EDISON INTERNATIONAL - 10-K Annual Report

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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, 2000
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2000

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 New York and Pacific

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. [ ]

The aggregate market value of registrant's voting stock held by non-affiliates
was approximately $3,860,862,791.10 on or about April 16, 2001, based upon
prices reported on the New York Stock Exchange. As of April 16, 2001, 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, 2000...................Parts I, II and IV
(2) Designated portions of the Joint Proxy Statement
relating to registrant's 2001 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............................................................. 1
Competitive Environment................................................................ 3
Significant Developments in California Electric Utility Restructuring.................. 4
Regulation of Edison International..................................................... 10
Environmental Matters.................................................................. 12
Business of SCE............................................................................. 15
Regulation of SCE...................................................................... 16
Changing Regulatory Environment........................................................ 16
Other Rate Matters..................................................................... 21
Fuel Supply and Purchased Power Costs.................................................. 26
Business of the Nonutility Companies........................................................ 28
2. Properties of SCE............................................................................... 38
Existing Utility Generating Facilities................................................. 38
SCE Construction Program and Capital Expenditures...................................... 40
Nuclear Power Matters.................................................................. 40
3. Legal Proceedings............................................................................... 43
Edison International........................................................................ 43
Geothermal Generators' Litigation...................................................... 43
Shareholder Litigation................................................................. 43
Power Generator Litigation............................................................. 44
Edison Mission Energy....................................................................... 44
PMNC Litigation........................................................................ 44
SCE ........................................................................................44
Geothermal Generators' Litigation...................................................... 44
San Onofre Personal Injury Litigation.................................................. 45
Navajo Nation Litigation............................................................... 46
Shareholder Litigation................................................................. 46
Power Generator Litigation............................................................. 47
PX Performance Bond Litigation......................................................... 53
4. Submission of Matters to a Vote of Security Holders............................................. 54
Executive Officers of the Registrant........................................................ 54

Part II

5. Market for Registrant's Common Equity and Related Stockholder Matters........................... 57
6. Selected Financial Data......................................................................... 57
7. Management's Discussion and Analysis of Results of Operations and Financial Condition........... 57
7A.Quantitative and Qualitative Disclosures About Market Risk...................................... 58
8. Financial Statements and Supplementary Data..................................................... 58
9. Changes in and Disagreements with Accountants on Accounting and Financial Disclosure............ 58

Part III

10.Directors and Executive Officers of the Registrant.............................................. 58
11.Executive Compensation.......................................................................... 58
12.Security Ownership of Certain Beneficial Owners and Management.................................. 58
13.Certain Relationships and Related Transactions.................................................. 58

TABLE OF CONTENTS

Item Page
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Part IV

14. Exhibits, Financial Statement Schedules, and Reports on Form 8-K............................... 59
Financial Statements....................................................................... 59
Report of Independent Public Accountants and Schedules Supplementing
Financial Statements.................................................................. 59
Exhibits................................................................................... 59
Reports on Form 8-K........................................................................ 59
Signatures................................................................................. 67

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, 2000, Edison International owned all of the
issued and outstanding common stock of SCE and of other subsidiaries engaged in
nonutility businesses (Nonutility Companies). These Nonutility Companies are:
Edison Mission Energy (EME), which is engaged in developing, acquiring, owning
or leasing, and operating electric power generation facilities worldwide; Edison
Capital, a provider of capital and financial services for energy and
infrastructure projects; and Edison Enterprises, which provides integrated
energy services, utility outsourcing, and consumer products and services.

Edison International is engaged in the business of holding, for investment, the
stock of its subsidiaries. At year-end 2000, Edison International had 25
full-time employees, SCE had 12,593 full-time employees, Edison Mission Energy
had 3,730 full-time employees, Edison Capital had 119 full-time employees, and
Edison Enterprises had 2,088 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

This annual report 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 herein or refers to or incorporates this
annual report may also contain forward-looking statements. In this annual report
and elsewhere, the words "expects," "believes," "anticipates," "estimates,"
"intends," "plans," "probable" and variations of such words and similar
expressions are intended to identify forward-looking statements. Such statements
necessarily involve risks and uncertainties that could cause actual results to
differ materially from those anticipated. Some of the risks, uncertainties and
other important factors that could cause results to differ are:

o Edison International's and SCE's financial condition, liquidity and credit
ratings have been adversely affected by California's electricity crisis.
Edison International and SCE have entered into a memorandum of
understanding (MOU), with the endorsement of the Governor of California,
which provides a plan for SCE's financial recovery by SCE selling its
transmission assets to an agency of the State of California and issuing
bonds to finance its undercollected power procurement costs, among other
steps. However, the MOU cannot be implemented unless the California
Legislature enacts necessary legislation, the California Public Utilities
Commission (CPUC) and Federal Energy Regulatory Commission (FERC) adopt
necessary orders, and various parties negotiate and execute definitive
agreements. Edison International and SCE cannot be certain that all the
required parties will take the necessary actions.

o Edison International and SCE are seeking to regain investment grade credit
ratings so they can re-enter the credit markets on reasonable terms. The
success of their efforts depends on the implementation of the MOU, which in
turn depends on actions of legislators, regulatory bodies and others.

o SCE is seeking to avoid bankruptcy. To conserve cash, SCE suspended certain
payments for debt service and purchased power. As a result numerous
creditors are suing SCE, and some have threatened the possible filing of an
involuntary bankruptcy petition against SCE. SCE's nonpayment

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of certain debt obligations also entitles debtholders to exercise remedies
against Edison International, including possibly accelerating the repayment
of principal.

o The CPUC recently adopted retroactive changes in regulatory accounting
mechanisms and implemented other measures that impair SCE's ability to
recover its costs and investments. As a result, SCE has taken a $2.5
billion ($4.2 billion on a pre-tax basis) fourth quarter write-off of
regulatory assets. The write-off eliminates SCE's retained earnings and
SCE's ability to pay dividends and issue additional first mortgage bonds.
If the MOU described above is implemented or a rate mechanism provided by
legislation or regulatory authority is established that makes recovery from
regulated rates probable as to all or a portion of the amounts that were
previously charged against earnings, current accounting standards provide
that a regulatory asset would be reinstated with a corresponding increase
in earnings. But to implement the MOU, SCE will need the cooperation of
legislators, regulators and other parties.

o Edison International and its subsidiaries may be 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. For example, regulatory actions in
California affect SCE's ability to recover its past investments in utility
plant and earn competitive returns; and regulatory actions in various
jurisdictions, including other countries, affect the business prospects of
EME and Edison Capital because of their investments in electric generating
and transmission assets and contracts with electric utility companies.

o Edison International and its subsidiaries may be affected by legislative
and regulatory measures adopted and being contemplated by federal and state
authorities to address the California electricity crisis or deregulation in
other states, 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 SCE may be affected by increased competition in the electric utility
business and other energy-related businesses, including among other things
the ability of customers to purchase energy and metering and billing
services from nonutility energy service providers.

o SCE and EME own and operate power generation facilities and, therefore, may
be affected by changes in the supply, demand and price for electric
capacity and energy in relevant markets and the cost and availability of
fuel and fuel transportation.

o SCE and EME, as owner-operators of power generation facilities, and Edison
Capital, as an investor in power generation facilities, also may be
affected by unpredictable weather conditions that may affect seasonal
patterns of revenue collection, cause changes in demand (and prices) for
electricity for heating and cooling purposes, and result in higher costs
for repair or maintenance of assets.

o Edison International and its subsidiaries may be affected by financial
market conditions such as inflation and changes in interest rates and
currency exchange rates, which could affect the availability and cost of
external financing, as well as the actions of securities rating agencies.

o EME and Edison Capital may be affected by risks of doing business in
foreign countries, including such things as political instability,
expropriation, currency devaluation, currency repatriation, and
uncertainties as to legal rights and remedies.

o EME is involved in developing, constructing and operating power plants and
is subject to risks such as cost overruns, strikes, equipment failures and
other issues.

o During 1999, EME acquired substantial generating assets which it is
operating as merchant plants. This involves significant financial and
operating risks because EME does not have long-term contracts for the sale
of power from those plants at fixed prices.

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o EME and Edison Capital may be adversely affected by the liquidity problems
of Edison International because historically they have received financial
support from Edison International in the form of equity investments, equity
infusion commitments, intercompany loans, and tax sharing arrangements.
Current constraints on such support may limit their ability to make new
investments.

o Edison International and its subsidiaries may be affected by changes in tax
laws or unfavorable interpretation and application of the laws by tax
authorities.

o The operation of power generation, transmission or distribution facilities
by SCE 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.

o Edison International and its subsidiaries are seeking to create and expand
new businesses, such as telecommunications and other energy-related
consumer products and services. Those businesses are subject to various
risks involved with start-up activities, such as developing products,
gaining customers, establishing management processes, hiring qualified
personnel, and so forth.

o Edison International and its subsidiaries may be subject to legal
proceedings arising out of financial reporting, commercial disputes,
property rights, personal injuries, and other circumstances.

Additional information about the risk factors listed above is contained
throughout this annual report. Readers are urged to read this entire report and
carefully consider the risks, uncertainties and other factors that affect Edison
International's business. The information contained in this report is subject to
change without notice. Readers should review future reports filed by Edison
International with the Securities and Exchange Commission (SEC).

Competitive Environment

SCE operates in a highly regulated environment in which it has an obligation to
deliver electric service to customers in return for an exclusive franchise
within its service territory and 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. In 1996, the
California Legislature enacted comprehensive restructuring legislation. SCE was
directed by the CPUC to divest the bulk of its gas-fired generation portfolio.
Furthermore, under the legislation and CPUC decisions, prices for wholesale
purchases of electricity from power suppliers are set by markets while the
retail prices paid by utility customers for electricity delivered to them
remained frozen at June 1996 levels. California's electric utilities, including
SCE, are currently facing a financial and liquidity crisis as a result of the
changes brought about by restructuring. (See Significant Developments in
California Electric Utility Restructuring below for a description of the most
recent developments.)

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. 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. Edison
Enterprises, through its various businesses, is engaged in a variety of
competitive retail products and services (See Business of the Nonutility
Companies). Each of these Nonutility Companies is adversely affected by the
financial constraints placed upon Edison International by the financial crisis
at SCE.

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Significant Developments in California Electric Utility Restructuring

Beginning in May 2000, SCE began experiencing adverse impacts from unusually
high prices for energy and ancillary services procured through the California
Power Exchange (PX) and the California Independent System Operator (ISO). These
high wholesale prices, coupled with the freeze on SCE's retail rates mandated by
the 1996 restructuring legislation, resulted in substantial increases in the
amount of undercollections in SCE's transition revenue account (TRA). SCE's TRA
is a regulatory asset account in which SCE records the difference between
revenues received from customers through the frozen rates and the costs of
providing service to customers, (which includes purchased power procurement
costs). 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
below), this undercollection, and SCE's coal and hydroelectric balancing account
overcollections (which amounted to $1.5 billion as of December 31, 2000), were
reclassified. In addition, SCE's transition cost balancing account (TCBA),
representing recovery of stranded costs net of a previously recorded credit for
market valuation of hydroelectric generation assets and the overcollections in
the balancing accounts for the coal and hydroelectric generating assets, was
recalculated to be a $2.9 billion undercollection.

On April 9, 2001, Edison International, SCE and the California Department of
Water Resources (CDWR) executed a Memorandum of Understanding (MOU) which sets
forth a comprehensive plan calling for legislation, regulatory action and
definitive agreements to resolve important aspects of the energy crisis, and
which, if implemented, is expected to help restore SCE's creditworthiness and
liquidity. The Governor of the State of California and his representatives
participated in the negotiation of the MOU, and the Governor endorsed
implementation of all the elements of the MOU. Edison International, SCE and the
CDWR committed in the MOU to proceed in good faith to sponsor and support the
required legislation and to negotiate in good faith the necessary definitive
agreements. If required legislation is not adopted and definitive agreements
executed by August 15, 2001, or if the CPUC does not adopt required implementing
decisions by June 8, 2001, the MOU may be terminated by Edison International,
SCE or the CDWR. Neither Edison International nor SCE can provide assurance that
all the required legislation will be enacted, regulatory actions taken and
definitive agreements executed before the applicable deadlines. Implementation
of the MOU, which is discussed in more detail below, will require numerous
actions by the parties and by other California state agencies and the FERC, and
would require significant changes in the regulatory decisions and other actions
discussed below.

The growing undercollections and the concerns of lenders and others that SCE
might not obtain regulatory approval of rate increases sufficient to cover
ongoing procurement costs and recover past costs materially and adversely
affected the liquidity of Edison International and SCE, becoming particularly
pronounced in January 2001. With its revenues providing substantially less cash
flow than needed for power purchases and other ongoing costs, SCE and its parent
company, Edison International, soon had no unused borrowing capacity under their
existing credit facilities and were unable to arrange any additional facilities.
Moreover, Edison International and SCE found themselves unable to issue
commercial paper or otherwise access the capital markets on reasonable terms. To
conserve cash and enable SCE to continue essential business operations, in
mid-January 2001, SCE temporarily suspended the payment of certain obligations
for principal and interest on outstanding debt and for purchased power.

As of March 31, 2001, SCE had $2.7 billion in obligations that were unpaid and
overdue including: (1) $626 million to the PX or the ISO; (2) $1.1 billion to
power producers that are qualifying facilities (QFs); (3) $229 million in PX
energy credits for energy service providers; (4) $506 million of matured
commercial paper; (5) $206 million of principal and interest on its 5-7/8%
notes; and (6) $7 million of other obligations. Unpaid obligations will continue
to accrue interest, as applicable. At March 31, 2001, SCE had estimated cash
reserves of approximately $2.0 billion, which is approximately $700 million less
than its outstanding obligations and preferred stock dividends in arrears. As of
March 31, 2001, the total preferred stock dividends in arrears was $6 million.
The amounts due to the ISO or PX in clause (1) above do not include $275 million
that has been charged back to SCE as a result of defaults in payments by Pacific
Gas and Electric Company (PG&E). SCE has disputed its obligation for such amount
in proceedings before the FERC and on April 6, 2001, the FERC ordered that such
charges be rescinded. As of March 31, 2001, SCE resumed payment of interest on
its debt obligations. Edison International has paid and expects to

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continue to pay its obligations, as they are due, subject to obtaining
financing. SCE has repurchased $549 million of pollution control bonds that
could not be remarketed in accordance with their terms. These bonds may be
remarketed in the future if SCE's credit status improves sufficiently.

On March 27, 2001, SCE announced that it will commence payments on deferred
indebtedness. These payments include (1) past due interest on first and
refunding mortgage bonds, Series 93C Due 2026 and Series 93H Due 2004 (which was
paid on March 30, 2001); (2) past due interest on senior unsecured notes, 5-7/8%
Series Due 2001 (which will be paid on April 19, 2001, to holders of record as
of April 9, 2001, in accordance with the applicable indenture); (3) interest on
matured commercial paper; and (4) interest on extendible commercial notes.
Payments on the commercial paper and extendible commercial notes were made on
April 6, 2001, and all interest was brought current to March 31, 2001, for the
commercial paper and March 28, 2001, for the extendible commercial notes.
Payments will also include interest on past due interest. Regular payments will
be resumed on all interest due going forward, including interest payments due
under SCE's bank credit facilities. Interest on commercial paper will be paid
monthly, and interest on the 5-7/8% Series notes will be paid semiannually.
Notices will be provided to holders of the securities about the timing and
amount of the interest payments they will receive. The aggregate amount required
to bring interest payments on outstanding indebtedness current as of March 31,
2001, is approximately $26 million.

On December 14, 2000, following an announcement from the ISO that electricity
generators were refusing to sell into the California market due to concerns
about the financial stability of SCE and Pacific Gas and Electric Company, the
U.S. Secretary of Energy issued an order requiring power generators to make
arrangements to generate and deliver electricity as required by the ISO after
the ISO certifies it has been unable to secure adequate electricity supplies in
the market. After being renewed multiple times, the order expired on February 6,
2001. However, on February 7, 2001, a federal court judge issued a temporary
restraining order requiring power suppliers to sell to the California grid. On
February 23, 2001, a federal court judge issued a stay of litigation in the case
of four power suppliers who agreed to extend their power sales pending a hearing
set for March 16, 2001. On March 16, 2001, a federal court judge put the case on
hold until March 20, 2001. On March 21, 2001, a federal court judge ordered one
of the power suppliers to continue to sell power to the California grid. The
three other power suppliers had signed an agreement with the judge voluntarily
agreeing to continue to sell power to the grid while awaiting a review of the
issue by the FERC. On April 6, 2001, the United States Ninth Circuit Court of
Appeals issued a stay order, suspending the lower court's March 21 order until a
final appeals ruling can be issued.

On January 17, 2001, following rolling blackouts in the northern California
service territory of Pacific Gas and Electric Company (PG&E), California
Governor Gray Davis signed an order declaring an emergency and authorizing the
CDWR to purchase power in order to prevent further blackouts.

Subsequently, on February 1, 2001, Governor Davis signed into law Assembly Bill
(AB) 1X, which was passed by the California Legislature as an urgency measure
during a special session. The new law 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 revenue bonds to
finance electricity purchases. The new law directed the CPUC to determine the
amount of a California Procurement Adjustment (CPA) and to determine further the
amount of the CPA allocable to the power sold by the CDWR which will be payable
to the CDWR when received by SCE. On March 7, 2001, the CPUC issued an interim
order in which it held that the CDWR's purchases are not subject to prudency
review by the CPUC, and that the CPUC must approve and impose, either as a part
of existing rates or as additional rates, rates sufficient to enable the CDWR to
recover its revenue requirements.

On March 27, 2001, the CPUC adopted an interim CPA-related order requiring SCE
to pay the CDWR a per-kWh price equal to the applicable generation-related
retail rate per kWh established in the order (based on rates in effect on
January 5, 2001), for each kWh the CDWR sells to SCE's customers. The CPUC
determined that the generation-related component of retail rates should be equal
to the total bundled electric rate (including the 1(cent) per kWh surcharge
adopted by the CPUC on January 4, 2001) less certain non-generation 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 cents per kWh. The CPUC
determined that the

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company-wide generation-related rate component is 7.277 cents per kWh (which
will increase to 10.277 cents per kWh for electricity delivered after March 27,
2001, due to the 3 cent surcharge discussed below) for each kWh delivered to
customers beginning February 1, 2001, until more specific rates are calculated.
The CPUC ordered SCE to pay the CDWR within 45 days after the CDWR supplies
power to retail customers. Using these rates, SCE has billed customers $196
million for energy sales made by CDWR during the period January 19 through March
31, 2001, and has forwarded $52 million to CDWR on behalf of these customers as
of March 31, 2001. In compliance with that same order, SCE is currently paying
the CDWR amounts approximating $2.5 million to $4 million daily.

In addition, this interim order proposed a method the CPUC will use to calculate
the CPA in accordance with AB 1X and applied the proposed method to propose a
company-wide average CPA rate. Using this rate, the order determined a proposed
CPA revenue amount, to be used by the CDWR to determine the amount of bonds it
may issue. All or a portion of the CPA may be allocated by the CPUC to reimburse
the CDWR for its power purchases on behalf of utility customers.

In an interim order on April 3, 2001, the CPUC adopted the method to calculate
the CPA and then applied that method to calculate a company-wide CPA rate for
each California utility. The CPUC used that rate to determine the CPA revenue
amount which can be used by the CDWR for issuing bonds. The CPUC stated that its
decision is narrowly focused to calculate the maximum amount of bonds that the
CDWR may issue and does not dedicate any particular revenue stream to the CDWR.
The CPUC determined that SCE's CPA rate is 1.120 cents per kWh, which generates
annual revenues of $856.43 million. According to the CPUC's methodology, the
aggregate annual revenues generated by the CPA rates determined for the three
California investor-owned utilities would allow the CDWR to issue up to $13.4
billion of bonds to pay for power purchases by the CDWR under the provisions of
AB 1X. In its calculation of the CPA, the CPUC disregarded all the adjustments
requested by SCE in its comments filed on March 29, 2001 (discussed below). As
to SCE's concerns that the CPA may be overstated and could cause deleterious
financial effects on SCE, the CPUC stated that the interim order does not
allocate the CPA, and SCE may comment on the allocation of the CPA at a later
time.

SCE believes that the intent of AB 1X was for the CDWR to assume full
responsibility for purchasing all power needed to serve the retail customers of
electric utilities, in excess of the output of generating plants owned by the
electric utilities and power delivered to the utilities under existing
contracts. However, the CDWR has stated that it is only purchasing power that it
considers to be reasonably priced, leaving the ISO to purchase in the short-term
market the additional power necessary to meet system requirements. The ISO, in
turn, takes the position that it will charge SCE for the costs of power it
purchases in this manner. If SCE is found responsible for any portion of the
ISO's purchases of power for resale to SCE's customers, SCE will continue to
incur purchased-power costs in addition to the unpaid costs described above. In
its March 27, 2001, interim order, the CPUC stated that it cannot assume that
the CDWR will pay for the ISO purchases and that it does not have the authority
to order the CDWR to do so. Litigation among certain power generators, the ISO
and the CDWR (to which SCE is not a party), and proceedings before the FERC (to
which SCE is a party), may result in rulings clarifying the CDWR's financial
responsibility for purchases of power. On April 6, 2001, the FERC issued an
order confirming that the ISO must have a creditworthy buyer for any
transactions, scheduled or not. In any event, SCE takes the position that it is
not responsible for purchases of power by the CDWR or the ISO from and after
January 18, 2001, the day after the Governor signed the order authorizing the
CDWR to begin purchasing power for utility customers. The MOU contemplates that
the CDWR will assume the entire responsibility for procuring the electricity
needs of SCE's customers through December 31, 2002, to the extent not met by
SCE's retained generation and power contracts. SCE cannot predict the outcome of
any of these proceedings or issues.

In addition to the CPA-related order discussed above, on March 27, 2001, the
CPUC adopted several other significant decisions regarding California's current
energy crisis. These March 27, 2001, decisions deal with complex matters and in
many respects are unclear or ambiguous. Edison International and SCE believe
that in some respects the CPUC's March 27, 2001, decisions are unlawful and
unconstitutional. Many elements of the decisions will be developed further in
ongoing proceedings, the timing of which is uncertain. Furthermore, key
components of the decisions would have to be modified, or the decisions

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rescinded, to implement the MOU that Edison International and SCE signed on
April 9, 2001, with the CDWR (discussed below).

In an interim order adopted on March 27, 2001, the CPUC granted SCE and other
California utilities a rate increase in the form of a three-cents per
kilowatt-hour (kWh) surcharge on electricity sold, effective immediately (rate
stabilization decision). However, the three-cent surcharge will not be collected
in rates until the CPUC establishes an appropriate rate design. The CPUC
proposed a tiered rate design in an assigned commissioner's ruling and asked for
comments. The assigned commissioner said the tiered rate design is intended to
encourage conservation by requiring customers to pay more for electricity above
a threshold usage level. The three-cent surcharge will not apply to residential
electricity usage below 130% of baseline rates or to certain low-income
customers. The CPUC will probably hold hearings on the rate design and may not
issue a decision until some time in May 2001. SCE has asked the CPUC to
immediately adopt an interim rate increase that would allow the rate change to
go into effect sooner.

The CPUC stated in its interim order that SCE is to use revenue generated by the
three-cent surcharge to pay power costs incurred after March 27, 2001. SCE must
refund the surcharge to ratepayers if SCE does not properly use it to pay power
costs. If any refunds of power costs are obtained from power generators and
sellers, those refunds will be used to reduce customer rates or to pay power
costs. SCE must also refund the three-cent surcharge to the extent that any
court or administrative body denies refunds from power generators or sellers in
a proceeding where recovery is hampered by lack of cooperation from SCE. The
CPUC also affirmed that an earlier one cent per kWh surcharge granted on January
4, 2001, is now permanent under California legislation adopted in February 2001,
known as AB 1X. The CPUC stated that revenues from the one-cent surcharge must
be used to pay for power purchases and not for any other costs. The CPUC ordered
that the three-cent surcharge must be added to the rate paid to the CDWR to
reimburse the CDWR for its costs of purchasing power for delivery to SCE's
customers (see above).

On March 27, 2001, the CPUC also ordered SCE to begin making payments to QFs for
power deliveries on a going forward basis, commencing with April 2001
deliveries. SCE must pay QFs within 15 days of the end of the QF's billing
period, and QFs are allowed to establish 15-day billing periods. The CPUC
provided two special payment options for the month of April only. Failure to
make a payment when due will result in a fine equal to the amount owed. 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 its March 27 decisions, the CPUC granted a petition previously filed by The
Utility Reform Network (TURN), a ratepayer advocacy group, that was opposed by
SCE and Pacific Gas and Electric Company. The CPUC directed that the balance in
SCE's TRA, whether positive or negative, be transferred on a monthly basis to
SCE's transition cost balancing account (TCBA), effective retroactively to
January 1, 1998. The TRA is a regulatory asset account in which SCE records the
difference between revenues received from customers through currently frozen
rates and the costs of providing service to customers, including power
procurement costs. The TCBA is a regulatory balancing account that tracks the
recovery of generation-related transition costs, including stranded investments.
The CPUC also ordered SCE to retroactively restate and record balances in its
generation memorandum accounts to the TRA on a monthly basis before any transfer
of generation revenues to the TCBA. SCE believes that this decision by the CPUC
is a fundamental departure from established regulatory accounting and ratemaking
procedures and is unlawful and unconstitutional. SCE believes the CPUC's intent
was to deny SCE lawful recovery of its costs and to artificially extend the end
of the current rate freeze. The CPUC characterized the changes as merely
reducing the prior revenues recorded in the TCBA, thereby affecting only the
amount of transition cost recovery achieved to date. Based upon the transfer of
balances into the TCBA, the CPUC stated that the current rate freeze has not
ended and will not end until the earlier of recovery of all specified transition
costs or March 31, 2002. The CPUC said that any undercollection in the TRA
cannot be recovered after the rate freeze ends. But the CPUC also said that it
will monitor the balances

7

remaining in the TCBA and consider how to address remaining balances in the
ongoing proceedings. If the CPUC does not modify this decision in a manner
consistent with the MOU, SCE intends to challenge this CPUC decision through all
appropriate avenues.

In response to the CPUC's request in the interim CPA-related order, SCE filed
comments on the proposed CPA calculation method on March 29, 2001, and April 2,
2001. In the limited time available to consider the impact of the CPUC's March
27 decisions, SCE estimated that its future revenues will not be sufficient to
cover its own costs of retained generation and power purchases. SCE provided a
forecast showing that the net effect of the rate increases described above, the
decision on QF payments described below, and the payments ordered to be made to
CDWR could result in a shortfall in the CPA calculation of $1.743 billion for
SCE during 2001. SCE further stated that the proposed calculation method does
not properly reflect all relevant generation costs, and that adoption of the
method and later allocation of a portion of the CPA to the CDWR would materially
exacerbate SCE's revenue shortfall. SCE commented that other flaws in the
calculation are that: (1) the proposed CPA is for an indefinite period with no
mechanism for adjustments based on changes in actual costs; (2) it ignores the
potential impact on SCE's costs if the CDWR is not responsible for the full
net-short position; (3) it assumes too low a cost for QF payments (as discussed
below); (4) it may improperly exclude authorized generation-related costs; (5)
it improperly excludes revenues from nuclear incentive pricing; and (6) the
methodology for calculating the CPA is flawed and based on unreasonable
assumptions.

In its comments on the CPUC's methodology for calculating the CPA, SCE also
discussed the QF pricing resulting from the CPUC's March 27 decision on QF
payments. SCE stated that the CPA calculation proposed by the CPUC is based on
an assumed QF price of $80 per MWh, which was a target price in earlier
negotiations with QFs seeking a settlement on lower prices. However, those
negotiations failed. SCE provided to the CPUC a forecast showing that QF prices
through the remainder of 2001, based on the revised formula adopted by the CPUC
and independently forecasted gas prices, will be substantially higher than $80
per MWh.

On April 9, 2001, Edison International and SCE signed a MOU with the CDWR
regarding the California energy crisis and its effects on SCE. California
Governor Gray Davis and his representatives participated in the negotiation of
the MOU, and Governor Davis endorsed implementation of all the elements of the
MOU. The MOU sets forth a comprehensive plan calling for legislation, regulatory
action and definitive agreements to resolve important aspects of the energy
crisis and which, if implemented, is expected to help restore SCE's
creditworthiness and liquidity. Key elements of the MOU include:

o SCE will sell its transmission assets to the CDWR, or another authorized
California state agency, at a price equal to 2.3 times their aggregate book
value, or approximately $2.76 billion. If a sale of the transmission assets
is not completed under certain circumstances, then if the State elects,
SCE's hydroelectric assets, and potentially additional rights to output
from other generating stations, may be sold to the State in their place.
SCE will use the proceeds of the sale in excess of book value to reduce its
undercollected costs and retire outstanding debt incurred in financing
those costs. SCE will agree to operate and maintain the transmission assets
for at least three years, for a fee to be negotiated.

o Two dedicated rate components will be established to assist SCE in
recovering the net undercollected amount of its power procurement costs
through January 31, 2001, estimated to be approximately $3.5 billion. The
first dedicated rate component will be used to securitize the excess of the
undercollected amount over the expected gain on sale of SCE's transmission
assets, as well as certain other costs. Such securitization will occur as
soon as reasonably practicable after passage of the necessary legislation
and satisfaction of other conditions of the MOU. The second dedicated rate
component would not be securitized and would not appear in rates unless the
transmission sale failed to close within a two-year period. The second
component is designed to allow SCE to obtain bridge financing of the
portion of the undercollection intended to be recovered through the gain on
the transmission sale.

8

o SCE will continue to own its generation assets, which will be subject to
cost-based ratemaking, through 2010. SCE will be entitled to collect
revenues sufficient to cover its costs from January 1, 2001, associated
with the retained generation assets and existing power contracts. The MOU
calls for the CPUC to adopt cost recovery mechanisms consistent with SCE
obtaining and maintaining an investment grade credit rating.

o The CDWR will assume the entire responsibility for procuring the
electricity needs of retail customers within SCE's service territory
through December 31, 2002, to the extent that those needs are not met by
generation sources owned by or under contract to SCE. (The unmet needs are
referred to as SCE's "net short position.") SCE will resume procurement of
its net short position after 2002. The MOU calls for the CPUC to adopt cost
recovery mechanisms to make it financially practicable for SCE to reassume
this responsibility.

o SCE's authorized return on equity will not be reduced below its current
level of 11.6% before December 31, 2010. Through the same date, a
ratemaking capital structure for SCE will not be established with different
proportions of common equity or preferred equity to debt than set forth in
current authorizations. These measures are intended to enable SCE to
achieve and maintain an investment grade credit rating.

o Edison International and SCE will commit to make capital investments in
SCE's regulated businesses of at least $3 billion through 2006, or a lesser
amount approved by the CPUC. The equity component of the investments will
be funded from SCE's retained earnings or, if necessary, from equity
investments by Edison International.

o EME will execute a contract with the CDWR or another state agency for the
provision of power to the state at cost-based rates for 10 years from a
power project currently under development. EME will use all commercially
reasonable efforts to place the first phase of the project into service
before the end of Summer 2001.

o SCE will grant perpetual conservation easements over approximately 21,000
acres of lands associated with SCE's Big Creek and Eastern Sierra
hydroelectric facilities. The easements initially will be held by a trust
for the benefit of the State of California, but ultimately may be assigned
to nonprofit entities or certain governmental agencies. SCE will be
permitted to continue utility uses on the subject lands.

o After the other elements of the MOU are implemented, SCE will enter into a
settlement of or dismiss its federal district court lawsuit against the
CPUC seeking recovery of past undercollected costs. The settlement or
dismissal will include related claims against the State of California or
any of its agencies, or against the federal government.

The parties agree in the MOU that each of its elements is part of an integrated
package, and effectuation of each element will depend upon effectuation of the
others. To implement the MOU, numerous actions must be taken by the parties and
by other agencies of the State of California and the FERC. The California
Legislature must enact legislation to authorize purchase of SCE's transmission
system or other assets, establish the dedicated rate components, authorize
and/or direct the CPUC to take certain actions, and authorize other agreements
and actions. The CPUC must also adopt the dedicated rate components and
financing orders, modify existing decisions, and take various ratemaking and
other actions. The CDWR and other state agencies must enter into definitive
agreements for the purchase of assets from SCE and to embody various other
elements of the MOU. The sale of SCE's transmission system and other elements of
the MOU must be approved by the FERC. Edison International, SCE, and the CDWR
committed in the MOU to proceed in good faith to sponsor and support the
required legislation and to negotiate in good faith the necessary definitive
agreements, and Governor Davis has endorsed the MOU and has agreed to work for
its complete implementation. The California Legislature, the CPUC, the FERC, and
other governmental entities on whose part action will be necessary to implement
the MOU are not parties to the MOU.

9

The MOU may be terminated by either SCE or CDWR if required legislation is not
adopted and definitive agreements executed by August 15, 2001, or if the CPUC
does not adopt required implementing decisions within 60 days after the MOU was
signed, or if certain other adverse changes occur. Edison International and SCE
cannot provide assurance that all the required legislation will be enacted,
regulatory actions taken, and definitive agreements executed before the
applicable deadlines.

Edison International and SCE believe that the MOU is an important step towards
an acceptable resolution of the major issues affecting Edison International and
SCE as a result of the California energy crisis, including restoring their
creditworthiness and creating a positive framework for future financial
stability, but achievement of those results is not assured. A California voter
initiative or referendum previously has been threatened against any measures
that would raise consumer rates or aid California's investor-owned utilities. In
addition, execution of the MOU does not eliminate the possibility that any of
SCE's creditors could take steps to force SCE into bankruptcy proceedings.

On April 6, 2001, Pacific Gas and Electric Company (PG&E) announced that it had
filed for reorganization under Chapter 11 of the United States Bankruptcy Code.
PG&E said that neither its parent holding company nor any of the parent's other
subsidiaries are affected by PG&E's filing. PG&E cited as reasons for its
bankruptcy filing the failure by the State of California to assume full
procurement responsibility for PG&E's net short position, the CPUC's actions on
March 27 and April 3, 2001, that created new payment obligations for PG&E, lack
of progress in negotiations with the State to provide recovery of power purchase
costs, the CPUC's adoption of an illegal and retroactive accounting change, and
the slow progress of discussions with representatives of Governor Davis (the
actions of the CPUC cited by PG&E are discussed above).

SCE is still working to avoid bankruptcy, despite PG&E's announcement that it is
filing for bankruptcy court protection. Edison International and SCE continue to
believe that a comprehensive solution to the current crisis through agreements,
legislation and regulatory actions, as contemplated by the MOU, is a preferable
course of action. Neither Edison International nor SCE can predict the impact of
PG&E's bankruptcy on implementation of the MOU and on Edison International's and
SCE's other efforts to resolve their current financial and liquidity problems.

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 (Holding
Company Act) 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. 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 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 California Public
Utilities Commission (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

10

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. The MOU calls for the CPUC to adopt a decision
clarifying that the "first priority" condition refers to equity investment, not
working capital for operating costs.

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 is expected before the end of the year 2001 at the earliest.

On January 29, 2001, independent auditors hired by the CPUC issued a report on
the financial condition and solvency of SCE and its affiliates. The report
confirmed what SCE had previously disclosed to the CPUC in public filings about
SCE's financial condition. The audit report covers, among other things, cash
needs, credit relationships, accounting mechanisms to track stranded cost
recovery, the flow of funds between SCE and Edison International, and earnings
of SCE's California affiliates. On March 15, 2001, the CPUC released a draft of
a proposed order instituting investigation.

At its March 27, 2000, meeting, the CPUC deferred action on a proposed order
instituting an investigation whether California's investor-owned utilities,
including SCE, have complied with past CPUC decisions authorizing the formation
of their holding companies and governing affiliate transactions, as well as
applicable statutes. On March 29, 2001, an assigned commissioner's ruling was
issued that requires Edison International and SCE to respond within 10 days to
document requests and questions that are identical to document requests and
questions included in the proposed order instituting investigation. At its
meeting on April 3, 2001, the CPUC adopted the proposed order. The order reopens
past CPUC decisions authorizing the utilities to form holding companies and
initiates an investigation into (1) whether the holding companies violated
requirements to give priority to the capital needs of their respective utility
subsidiaries; (2) whether "ring fencing" actions by Edison International and
PG&E Corporation and their respective nonutility affiliates also violated the
requirements to give priority to the capital needs of their utility
subsidiaries; (3) 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; (4) any additional suspected
violations of laws or CPUC rules and decisions; and (5) whether additional
rules, conditions, or other changes to the holding company decisions are
necessary. The MOU signed on April 9, 2001, with the CDWR calls for the CPUC to
adopt a decision clarifying that the "first priority" condition in SCE's holding
company decision refers to equity investment, not working capital for operating
costs. Neither Edison International nor SCE can provide assurance that the CPUC
will adopt such a decision, or predict what effects the investigation or any
subsequent actions by the CPUC may have on either of them.

Additional information about the applicability of certain regulatory
requirements to EME is provided below under Business of the Nonutility
Companies.

11

Environmental Matters

Legislative and regulatory activities by federal, state, and local authorities
in the United States and regulatory authorities with jurisdiction over Edison
International's projects located outside the United States continue to result in
the imposition of numerous restrictions on Edison International's operation of
existing facilities, on the timing, cost, location, design, construction, and
operation by Edison International of new facilities, and on 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 Edison International's existing facilities and operating procedures. Edison
International is unable to predict the extent to which additional regulations
may affect its operations and capital expenditure requirements.

The Clean Air Act provides the statutory framework to implement a program for
achieving national ambient air quality standards in areas exceeding such
standards and provides for maintenance of air quality in areas already meeting
such standards. Among other requirements, it also restricts the emission of
toxic air contaminants and provides for the reduction of sulfur dioxide
emissions to address acid deposition. In 1990, Congress passed amendments to the
Clean Air Act that greatly expanded the scope of federal regulations in several
significant respects. EME expects to spend approximately $67 million in 2001 to
install upgrades to the environmental controls at the Homer City plant in
Pennsylvania to control sulfur dioxide and nitrogen oxide emissions. Similarly,
EME anticipates upgrades to the environmental controls at its Illinois plants to
control nitrogen oxide emissions to result in expenditures of and expects to
spend approximately $61 million, $67 million, $130 million, $123 million and $57
million for 2001, 2001, 2003, 2004 and 2005, respectively. Provisions related to
nonattainment, air toxins, permitting of new and existing units, enforcement,
and acid rain may affect EME's domestic plants; however, final details of all
these programs have not been issued by the United States Environmental
Protection Agency (EPA) and state agencies. In addition, at the Ferrybridge and
Fiddler's Ferry plants in the United Kingdom, EME anticipates environmental
costs arising from plant modification, of approximately $52 million for the 2001
to 2005 period.

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 Generating Station (Mohave
Station) located in Laughlin, Nevada, which is subject to certain air quality
programs. In 1998, several environmental groups filed suit against the co-owners
of the Mohave Station regarding alleged violations of emissions limits. In order
to accelerate resolution of key environmental issues regarding the plant, the
parties filed, in concurrence with SCE and the other station owners, a consent
decree, which was approved by the Court in December 1999. The decree was
designed also to address concerns raised by two EPA programs regarding
visibility and regional haze. The EPA issued its final rulemaking regarding
regional haze regulations on July 1, 1999. The final rule is not expected to
impose any additional emissions control requirements on the Mohave Station
beyond meeting the provisions of the consent decree. The EPA and SCE also
participated in a study to determine the specific impact of air contaminant
emissions from the Mohave Station on visibility in Grand Canyon National Park.
The final report on this study, which was issued in March 1999, found negligible
correlation between measured Mohave Station tracer concentrations and visibility
impairment. The absence of any obvious relationship cannot rule out Mohave
Station contributions to haze in Grand Canyon National Park, but strongly
suggests that other sources were primarily responsible for the haze. Finally, in
June 1999, the EPA issued an advanced notice of proposed rulemaking regarding
assessment of visibility impairment at the Grand Canyon. SCE filed

12

comments on the proposed rulemaking in November 1999. In July 2000, EPA
published a proposed rule and on August 21, 2000, SCE provided comments to the
proposed rule. In a letter to SCE, the EPA has expressed its belief that the
controls provided in the consent decree will likely resolve the potential Clean
Air Act visibility concerns. The Agency is considering incorporating the decree
into the visibility provisions of its Federal Implementation Plan for Nevada.

The Clean Air Act also requires the EPA to carry out a three-year study of risk
to public health from the emissions of toxic air contaminants from electric
utility steam generating plants, and to regulate such emissions if the
Administrator makes certain findings. The study's final report to Congress
concluded that mercury from coal-fired utilities is the hazardous air pollutant
of greatest potential concern and merits additional research and monitoring to
better understand the risks of mercury exposure. Other pollutants that may
potentially need further study are dioxins and arsenic from coal-fired plants,
and nickel from oil- fired plants. The EPA concluded that the impacts from
emissions from gas-fired utilities are negligible and that there is no need for
further evaluation of the risks of hazardous air pollutants emitted from such
plants.

In 2000, the EPA issued a notice of violation and a compliance order alleging
violations of the Clean Air Act by EcoElectrica, a 540 MW liquefied natural gas
combined-cycle cogeneration facility in Penuelas, Puerto Rico, in which EME owns
an indirect 50% interest. Representatives of EcoElectrica have met with the EPA
to discuss the notice of violations 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. Several states have joined these lawsuits. In
addition, the EPA has also 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.

Prior to its purchase of the Homer City plant, 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 plant, no proceedings have been
initiated with respect to any of its facilities, EME has been in informal
voluntary discussions with the EPA relating to these facilities, and EME expects
it will reach a satisfactory agreement concerning future environmental
expenditures related to its domestic facilities, which may also include payment
of civil fines. However, there can be no assurance that EME 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.

13

On June 27, 2000, the EPA issued a Request For Information (RFI) for the Four
Corners plant. SCE owns a 48% share of Four Corners' Units 4 and 5 and on
September 1, 2000, replied to the RFI. To date, no further action has been taken
with respect to Four Corners.

In December 2000, the EPA announced its intention 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. EPA expects to finalize this rule
by December 15, 2004. Because neither EME nor SCE knows what the EPA may require
with respect to this issue, both companies are presently unable to evaluate the
impact of potential mercury regulations on the operation of their respective
facilities.

Regulations under the Clean Water Act require permits for the discharge of
certain pollutants into U.S. waters. Under this act, the EPA issues effluent
limitation guidelines, pretreatment standards, and new source performance
standards for the control of certain pollutants. Individual states may impose
more stringent limitations. SCE incurs additional expenses and capital
expenditures in order to comply with guidelines and standards applicable to
steam electric power plants. SCE presently has discharge permits for all
applicable facilities.

The Safe Drinking Water and Toxic Enforcement Act prohibits the exposure to
individuals of chemicals known to the State of California to cause cancer or
reproductive harm and the discharge of such listed chemicals into potential
sources of drinking water. Additional chemicals are continuously being put on
the State's list, requiring constant monitoring.

The Resource Conservation and Recovery Act provides the statutory authority for
the EPA to implement a regulatory program for the safe treatment, recycling,
storage, and disposal of solid and hazardous waste. An unresolved issue remains
regarding the degree to which coal waste should be regulated under the act.
Currently, coal waste has been determined to be non-hazardous. Increased
regulation may result in increased expenses relating to the operation of the
Mohave Station.

The Toxic Substances Control Act and accompanying regulations govern the
manufacturing, processing, distribution in commerce, use, and disposal of listed
compounds, such as polychlorinated biphenyls, a toxic substance used in certain
electrical equipment. Current costs for disposal of this substance are
immaterial.

Edison International records its environmental liabilities 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 discounted amounts).

Edison International's recorded estimated minimum liability to remediate its 44
currently identified sites is $114 million. All of these sites are related to
historic or current operations of SCE. The ultimate costs to clean up Edison
International's identified sites may vary from its recorded liability due to
numerous uncertainties inherent in the estimation process, such as: (1) the
extent and nature of contamination; (2) the scarcity of reliable data for
identified sites; (3) the varying costs of alternative cleanup methods; (4)
developments resulting from investigatory studies; (5) the possibility of
identifying additional sites; and (6) the time periods over which site
remediation is expected to occur. Edison International believes that, due to
these uncertainties, it is reasonably possible that cleanup costs could exceed
its recorded liability by up to $272 million. The upper limit of this range of
costs was estimated using assumptions least favorable to Edison International
among a range of reasonably possible outcomes. SCE has sold all of its

14

gas- and oil-fueled generation plants (except the Pebbly Beach Generating
Station) and has retained some liability associated with the divested
properties.

The CPUC allows SCE to recover environmental-cleanup costs at certain sites,
representing $45 million of its recorded liability, through an incentive
mechanism (SCE may request to include additional sites). Under this mechanism,
SCE will recover 90% of cleanup costs through customer rates; shareholders fund
the remaining 10%, with the opportunity to recover these costs from insurance
carriers and other third parties. SCE has successfully settled insurance claims
with all responsible carriers. Costs incurred at SCE's remaining sites are
expected to be recovered through customer rates. SCE has recorded a regulatory
asset of $75 million for its estimated minimum environmental-cleanup costs
expected to be recovered through customer rates.

Edison International'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 Edison International may be held
responsible for contributing to any costs incurred for remediating these sites.
Thus, no reasonable estimate of cleanup costs can be made for these sites.

Edison International expects to clean up its identified sites over a period of
up to 30 years. Remediation costs in each of the next several years are expected
to range from $5 million to $15 million. Recorded costs for 2000 were $13
million.

Based on currently available information, Edison International believes that it
is unlikely that it will incur amounts in excess of the upper limit of the
estimated range and, based upon the CPUC's regulatory treatment of
environmental-cleanup costs, Edison International believes that costs ultimately
recorded will not materially affect its results of operations or its financial
position. There is no assurance, however, that future developments, including
additional information about existing sites or the identification of new sites,
will not require material revisions to such estimates.

Edison International's projected environmental capital expenditures are $1.8
billion for the 2001-2005 period, mainly for undergrounding certain transmission
and distribution lines at SCE and upgrading environmental controls at EME.

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 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. Beginning in April 1998, pursuant to the restructuring of the
California electric utility industry mandated by a 1996 State law, other
entities have had the ability to sell electricity in SCE's service territory,
utilizing SCE's transmission and distribution lines at tariffed rates. As a part
of this utility industry restructuring, SCE sold some of its electric generating
plants in 1998. SCE currently retains other electric generating plants, however,
and it retains its transmission and distribution lines over which it transmits
and distributes the electricity generated by SCE and other generators to the
customers in SCE's service territory. The MOU calls for the sale of SCE's
transmission assets to an agency of the State of California. As a further part
of the industry restructuring, SCE had been required for an intended interim
transition period (ending no later than year-end 2001) to sell all SCE-generated
electricity to the California Power Exchange (PX) at prices determined by
periodic public auctions, and to buy any electricity needed to serve SCE's
retail customers from the PX at similarly determined prices. As part of a
December 15, 2000, order, the Federal Energy Regulatory Commission (FERC)
eliminated the requirement that SCE buy and sell power exclusively through the
PX and California ISO. In mid-January 2001, the PX suspended SCE's trading
privileges for failure to post collateral due to SCE's rating agency downgrades.
The PX suspended its day-ahead and day-of energy trading on January 30 and
January 31, 2001, respectively. On March 9, 2001, the PX filed for Chapter 11
bankruptcy protection. As discussed in Significant Developments in

15

California Electric Utility Restructuring above, 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
revenues for it on behalf of CDWR. In 2000, SCE's total operating revenue was
derived from: 38.2% residential customers, 38.3% commercial customers, 8.4%
industrial customers, 6.6% public authorities, 2.3% agricultural and other
customers, and 6.2% other electric revenue. SCE had 12,593 full-time employees
at year-end 2000. SCE comprises the largest portion of the assets and revenue of
its parent holding company, Edison International.

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 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 U.S. 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 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, in the summer of 2000, SCE applied for a coastal permit to
construct a dry cask spent fuel storage installation for Units 2 and 3. This
permit application was approved, with certain conditions, by the California
Coastal Commission at its meeting on March 13, 2001.

The U.S. 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 for further discussion of these rules and a recent 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

SCE currently operates in a highly regulated environment in which it has an
obligation to deliver electric service to customers in return for an exclusive
franchise within its service territory and certain obligations of the regulatory
authorities to provide just and reasonable rates. In 1994, state lawmakers and
the CPUC

16

initiated the electric industry restructuring process. In 1996, the California
Legislature enacted comprehensive restructuring legislation. SCE was directed by
the CPUC to divest the bulk of its generation portfolio. Today, those generating
plants are owned by independent power companies. Along with electric industry
restructuring, a mandated multi-year freeze on the rates that SCE could charge
its customers was mandated and transition cost recovery mechanisms allowing SCE
to recover its stranded costs associated with generation-related assets were
implemented.

As described above, skyrocketing wholesale energy pricing and resulting
liquidity pressures placed upon SCE and other investor-owned utilities has
caused the restructuring process to change significantly as California adopted
short-term measures, and works to develop longer-term solutions, to address the
energy crisis. SCE's remaining generation portfolio was impacted by California
state legislation enacted in January 2001 barring the sale of utility generating
facilities, including SCE's Mohave, Palo Verde and Four Corners generating
facilities, until 2006. Under the MOU, SCE would continue to own its share of
these generating assets, which would be subject to cost-based ratemaking,
through 2010. SCE's efforts to recover its transition and power procurement
costs associated with restructuring are described below under Recovery of
Transition and Power Procurement Costs.

Recovery of Transition and Power Procurement Costs

SCE's transition costs included power purchases from QF contracts (which are the
direct result of prior legislative and regulatory mandates), recovery of certain
generating assets and regulatory commitments consisting of recovery of costs
incurred to provide service to customers. Such commitments include the recovery
of income tax benefits previously flowed through to customers, postretirement
benefit transition costs, accelerated recovery of investment in San Onofre Units
2 and 3 and the Palo Verde units, and certain other costs. Transition costs
related to power-purchase contracts are being recovered through the terms of
each contract. The CPUC decisions provide that most of the remaining transition
costs are subject to recovery only through the end of the transition period (not
later than March 31, 2002). Although the MOU provides for, among other things,
SCE to be entitled to sufficient revenue to cover its costs from January 2001
associated with retaining generation and existing power contracts, the
implementation of the MOU requires the CPUC to modify various decisions. Because
of the CPUC's decisions on and after March 27, 2001, including the retroactive
transfer of balances from SCE's TRA to its TCBA and related changes and other
regulatory and legislative actions (see discussion in the Significant
Developments in California Electric Utility Restructuring above), SCE is not
able to conclude that the regulatory assets and liabilities related to
purchased-power settlements, the unamortized loss on SCE's generating plant
sales in 1998, and various other regulatory assets and liabilities (including
income taxes previously flowed through to customers) related to certain
generating assets are probable of recovery through the rate-making process. As a
result, these balances were written off as a charge to earnings as of December
31, 2000. If the MOU is implemented, or a rate mechanism provided by legislation
or regulatory authority is established that makes recovery from regulated rates
probable as to all or a portion of the amount that has been charged against
earnings, a regulatory asset would be correspondingly reinstated with a
corresponding increase in earnings.

During the rate freeze period, there are three sources of revenue available to
SCE for transition cost recovery: competition transition charge (CTC) revenue,
revenue from the sale or valuation of generation assets in excess of book
values, and net market revenue from the sale of SCE-controlled generation into
the ISO and PX markets. However, due to the events discussed above (see
Significant Developments in California Electric Utility Restructuring), revenue
from the sale of SCE generation into the ISO and PX markets and from the sale or
valuation of generation assets in excess of book values (prohibited by state
legislation enacted in January 2001) is no longer available to SCE. CTC revenue
is determined residually (i.e., CTC revenue is 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). The CTC applies to all customers who were using or began using utility
services on or after the CPUC's 1995 restructuring decision date. Residual CTC
revenue is calculated through the TRA mechanism.

17

Beginning in May 2000, SCE experienced adverse impacts from high prices for
energy and ancillary services procured through the PX and ISO. These high
wholesale prices, coupled with the current freeze on SCE's rates, resulted in
substantial increases in the amount of undercollections in SCE's TRA, reaching
$4.5 billion as of December 31, 2000. Additional information about the financial
impact of this undercollection and various ongoing and proposed legislative, and
regulatory efforts and current judicial proceedings designed to address or
otherwise relating to it, is provided in Management's Discussion and Analysis in
Edison International's Annual Report to Shareholders for the year ended December
31, 2000 (Annual Report), under SCE's Regulatory Environment - Status of
Transition and Power Procurement Costs Recovery section incorporated herein by
reference pursuant to General Instruction G(2).

Rate Reduction Notes

In December 1997, after receiving approval from the CPUC and the California
Infrastructure and Economic Development Bank, a limited liability company
created by SCE issued approximately $2.5 billion of rate reduction notes.
Residential and small commercial customers, whose 10% rate reduction began
January 1, 1998, are repaying the notes over the expected ten-year term through
non-bypassable charges based on electricity consumption. There were originally
seven classes of notes. The first class, in the amount of $246.3 million,
matured in December 1998, and the second class in the amount of $307.3 million
matured in March 2000. The remaining Notes consist of five classes with
scheduled maturities beginning in 2001 and ending in 2007, with interest rates
ranging from 6.17% to 6.42%.

Other Revenue and Cost-Recovery Mechanisms

Revenue is determined by various mechanisms depending on the utility operation:
distribution, transmission and generation. Moreover, in response to the
above-referenced skyrocketing wholesale energy pricing, SCE has initiated rate
stabilization proceedings at the CPUC. In addition, SCE jointly petitioned the
FERC to find that the California wholesale electricity market was not workably
competitive, to immediately impose a price cap for energy and ancillary
services, and to take other responsive measures.

Revenue related to distribution operations is being determined through a
performance-based rate-making mechanism (PBR) and the distribution assets have
the opportunity to earn a CPUC-authorized 9.49% return. The distribution PBR
will extend through December 2001. Key elements of the distribution PBR include:
distribution rates indexed for inflation based on the Consumer Price Index less
a productivity factor; adjustments for cost changes that are not within SCE's
control; a cost-of-capital trigger mechanism based on changes in a utility bond
index; standards for customer satisfaction; service reliability and safety; and
a net revenue-sharing mechanism that determines how customers and shareholders
will share gains and losses from distribution operations.

Transmission revenue is being determined through FERC-authorized rates that are
subject to refund. Since the initiation of the ISO in April 1998, transmission
cost recovery has been under FERC authority. In July 2000, FERC issued a final
decision in SCE's 1998 FERC 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 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 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 FERC to be included in transmission rates. A
CPUC decision is not expected until late in 2001. 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 FERC associated with
transmission will not be refunded to retail customers but will be credited
against the amount of accrued transition/procurement costs.

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 rate-making agreements. During
the rate freeze, revenue from generation-related operations has

18

been determined through the market and transition cost recovery mechanisms,
which included the nuclear rate-making agreements. The portion of revenue
related to coal generation plant costs (Mohave Generating Station and Four
Corners Generating Station) 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 have now been transferred to the TRA
on a monthly basis, retroactive to January 1, 1998. In addition, the TRA
balance, whether over- or undercollected, has now been transferred to the TCBA
on a monthly basis, retroactive to January 1, 1998. 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 and these two balancing accounts have become inactive. As a
key element of the MOU, SCE would continue to own its generation assets, which
would be subject to cost-based ratemaking, through 2010. The MOU calls for the
CPUC to adopt cost recovery mechanisms consistent with SCE obtaining and
maintaining an investment grade credit rating.

In 1999, SCE filed an application with the CPUC proposing for purposes of the
application a market value for its hydroelectric generation-related assets at
approximately $1.0 billion (almost twice the assets' book value) and proposing
to retain and operate the hydroelectric assets under a performance-based,
revenue-sharing mechanism. Under the MOU provides that SCE would withdraw this
application, and would continue to operate the hydroelectric assets under
cost-based ratemaking, through 2010.

In April 2000, SCE agreed to sell its 15.8% interest in Palo Verde and its 48%
interest in Four Corners Generating Station to Pinnacle West Energy (PWE) for
$550 million, subject to certain adjustments. The transaction remained subject
to the approval of the CPUC, the NRC, the FERC and other state and federal
entities, and to the receipt of a favorable ruling from the Internal Revenue
Service. In January 2001, California state legislation was enacted which bars
the sale of utility generating facilities, including SCE's Palo Verde and Four
Corners generating facilities, until 2006. Under the MOU, SCE would withdraw its
application to sell these generation interests and would continue to own its
generating assets, which would be subject to cost-based ratemaking, through
2010.

In January 2000, SCE filed an application with the CPUC proposing rates that
would go into effect when the current rate freeze ends on March 31, 2002, or
earlier, depending on the pace of transition cost recovery. In light of its
four-point market reform proposal of October 2000, on November 16, 2000, SCE
filed a rate stabilization plan with the CPUC seeking, among other things, a
9.9% rate increase for all customers (excluding low-income customers whose
increase would be 4.95%) for a two-year period beginning January 1, 2001.
Hearings were held in late December 2000 and on January 4, 2001, and 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. The revenue from the
surcharge is being tracked through a balancing account and applied to ongoing
power procurement costs. The surcharge resulted in rate increases, on average,
of approximately 7% to 25%, depending on the class of customer. As noted in the
decision, the 90-day period allowed independent auditors engaged by the CPUC to
perform a comprehensive review of SCE's financial position, as well as that of
Edison International and other affiliates.

In its interim rate stabilization order adopted on March 27, 2001, the CPUC
granted SCE a rate increase in the form of a 3(cent) per kWh surcharge applied
only to electric power costs, effective immediately, and affirmed that the
1(cent) interim surcharge granted on January 4, 2001, is now permanent. Also, in
the interim

19

order, the CPUC granted a petition previously filed by TURN and directed that
the balance in SCE's TRA, over- or undercollected, be transferred on a monthly
basis to the TCBA, retroactive to January 1, 1998, (see Significant Developments
in California Electric Utility Restructuring).

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 November 2000, SCE filed with the CPUC a request for approval to credit the
TCBA (and debit the Generation Asset Balancing Account) as soon as possible with
the aggregate net gain on the pending sales of the Mohave, Four Corners and Palo
Verde generation plants, which would have the effect of substantially
accelerating the end of SCE's statutory rate freeze. The CPUC dismissed the
request without full proceedings on the grounds that it was premature. Due to
events discussed above in Significant Developments in California Electric
Utility Restructuring (State legislation enacted in January 2001 bars the sale
or valuation of SCE's remaining generation assets until 2006), revenue from the
sale of generation assets in excess of book values is no longer available to
SCE. Additionally, as indicated above, under the MOU SCE would continue to own
its generating assets, which would be subject to cost-based ratemaking, through
2010.

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/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/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.

See SCE's Regulatory Environment - Generation and Power Procurement and SCE's
Regulatory Environment - Rate Stabilization Proceeding sections of the
Management's Discussion and Analysis in the Annual Report incorporated herein by
reference pursuant to General Instruction G(2), for more information about SCE's
revenue from its generation-related operations, recovery of its investment in
its nuclear facilities, market valuation of its hydroelectric generation-related
assets, the proposed sales of its interests in the Palo Verde and Four Corners
generating facilities, rate stabilization proceedings before the CPUC and its
FERC petition seeking specific regulatory responses to the wholesale energy
market dysfunction, and on accounting for generation-related assets and power
procurement costs.

Restructuring Implementation Costs

In May 1998, SCE filed an application with the CPUC to identify the categories
of restructuring implementation costs (including costs related to the start-up
and development of both the PX and ISO, and related to the implementation of
direct access) and to establish the reasonableness of those costs incurred in
1997. In September 1999, the CPUC approved a settlement agreement between SCE,
the Office of Ratepayer Advocates (ORA) and several other parties allowing SCE
to recover substantially all (approximately $300 million) of its restructuring
implementation costs (incurred and estimated) for the period 1997-2001. In
addition, the settlement provides that up to $210 million of generation-related
costs (transition costs) that are displaced by recovery of the restructuring
implementation costs during the rate freeze may be recovered after December 31,
2001, the date SCE would no longer be allowed to recover these transition costs
under restructuring legislation.

20

Market Risk Exposures

In 1997, SCE bought gas call options to mitigate its transition cost recovery
exposure to increases in energy costs. In October 2000, SCE sold its remaining
options; the gains were credited to the TCBA. In July 1999, SCE began
participating in forward purchases through a PX block forward market. Initially,
the only product available in the PX block forward market provided a monthly
block of energy delivered six days a week (excluding Sundays and holidays), 16
hours a day. The CPUC originally limited SCE's use of the PX block forward
market to a maximum of approximately 2,000 MW in any month. The PX requested and
was granted authority from the FERC to sell other forward products including a
peak product that specified power delivery six days a week, eight hours a day
(excluding holidays). In March 2000, the CPUC approved SCE's request for
rate-making treatment for its use of these additional products and for an
expansion of the limits from all forward PX products up to 5,200 MW in summer
months. In April 2000, the CPUC approved SCE's request to begin a demand
responsiveness program that would allow customers to be paid to curtail their
load during times of very high PX energy prices. In August 2000, the CPUC
approved SCE's request to enter into bilateral power contracts. The CPUC
approval limited the quantity of power that could be contracted for, required
pre-approval for contracts extending beyond 2002, and required that all
contracts expire on or before December 31, 2005. SCE entered into bilateral
power contracts in November 2000. On December 31, 2000, the "mark-to-market"
value of SCE's block-forward and bilateral forward contracts (market value of
the contracted power less the contract cost) was $424 million and $398 million,
respectively. During the last eight months of 2000, SCE experienced
significantly higher PX purchased-power expenses despite savings of $684 million
realized from its power hedging contracts over that period.

On February 2, 2001, the State of California seized SCE's block forward
contracts. Under law, the State must compensate SCE for the reasonable value of
the contracts. The PX has indicated that it will also seek to recover the monies
SCE owes to the PX from any proceeds from the contracts. On or about February
26, 2001, SCE filed a claim against the State Board of Control (now known as the
California Victim Compensation and Government Claims Board) seeking recovery of
damages incurred as a result of the State seizure of the block forward
contracts. SCE has also notified Governor Gray Davis of SCE's intention to
pursue a claim for damages. The Board has yet to respond to SCE's claim. The
MOU, if implemented, calls for settlement of SCE's claim relating to these block
forward contracts.

Other Rate Matters

CPUC Retail Ratemaking

The CPUC regulates the charges for services provided by SCE to its retail
customers. As discussed above in the section on Changing Regulatory Environment,
the way in which the CPUC regulates SCE is 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
them (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 which were implemented, replacing the Electric Revenue Adjustment
Mechanism, Energy Cost Adjustment Clause (ECAC) and base rates mechanism
(pre-restructuring 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 the CPUC's
interim rate stabilization order adopted on March 27, 2001 (see Other Revenue
and Cost Recovery Mechanisms). 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

21

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 non-generation rate components in October 1999. To maintain overall
frozen rate levels, to the extent non-generation rate components are authorized
to change, the generation rate component changes equal and opposite from the
non-generation rate component changes. The decision also instructed SCE to
include in the 1999 RAP Report a PX credit calculation that reflects the
long-run marginal costs of customer account managers, customer service
representatives, self-provision of ancillary services, and financing costs for
purchasing power from the PX.

In June 1999, the CPUC issued a decision regarding unbundling SCE's cost of
capital based on major utility functions. The decision was in response to SCE's
May 1998 application on this issue. The CPUC found no unbundling adjustment was
required in setting 1999 cost of capital for the California electric utilities.
Furthermore, the CPUC ruled that SCE's rate of return should continue to be
governed by the cost of capital trigger mechanism authorized as part of SCE's
performance-based ratemaking mechanism. (See discussion under Other Revenue and
Cost-Recovery Mechanisms.) As a result, SCE's return on equity for 1999 was
unchanged at 11.6%.

On August 9, 1999, SCE filed its 1999 RAP Report requesting CPUC approval of the
following: (1) consolidation of the 2000 non-generation revenue requirements;
(2) rate levels for 2000, including the residually determined generation rates;
(3) 2000 kWh sales forecast; (4) entries to the TRA for the period June 1, 1998,
through May 31, 1999; (5) proposed retention, elimination, and modification of
balancing and memorandum accounts; (6) implementation and costs of electric
vehicle programs during the record period; (7) administration of SCE's
self-generation deferral rate contracts during the record period; and (8) the
proposed additional .007/kWh (7 cents/MWh) credit to direct access customers
associated with SCE's procurement of PX energy for bundled service customers.
The most hotly contested issue was the computation of the PX Credit Adder
intended to reflect each utility's long-run marginal cost of power procurement.
On August 2, 2000, two proposed decisions (PDs) were issued - a PD of ALJ
Barnett and an Alternate PD of Commissioner Neeper. ALJ Barnett adopted for all
three investor-owned utilities a PX Credit Adder of .007 cents per kWh (7 cents
per MWh). This is the PX Credit Adder that SCE had proposed. ALJ Barnett adopted
all of SCE's arguments on long-run marginal cost and used SCE's formulation of
the PX credit as a model for the other utilities. Commissioner Neeper adopted,
and later through a revised PD modified, a different PX Credit Adder. A revised
Alternate PD by Commissioner Bilas proposing yet another PX Credit Adder was
issued on November 6, 2000. Like other Alternates, it relied on the "average
cost" methodology of the ORA. On January 4, 2001, the PD of ALJ Barnett was
adopted by the CPUC. The decision put SCE on notice that it will no longer be
able to prospectively recover 100% of its reliability must-run costs in the TRA.
The decision adopted all other RAP issues SCE requested.

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 (ATCP)

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

22

are justified. The purpose of the ATCP is to ensure the recovery of
generation-related transition costs through the TCBA that complies with the
guidelines established by the CPUC. The TCBA tracks the recovery of transition
costs, including the accelerated recovery of plant balances, QF and purchased
power costs, and regulatory assets and obligations.

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 March 31, 1999,
the ORA submitted its report and made the following recommendations adverse to
SCE: (1) $2.37 million in QF shareholder incentive amounts should be disallowed;
(2) $3.2 million in employee-related transition costs should be disallowed; and
(3) $9.67 million in post-retirement benefits other than pensions (PBOPs) and
$5.76 million in long-term disability regulatory assets should be rejected. On
June 14, 1999, the ALJ granted SCE's motion to strike the ORA's testimony and
recommendations on the third item. Prior to hearings, the ORA and SCE
recommended that the CPUC adopt a stipulation and joint recommendation whereby
SCE would not recover $895,000 in retention bonuses, and $1.19 million of the
total QF shareholder incentive amounts. On October 8, 1999, the matter was
submitted to the CPUC.

On January 6, 2000, an ALJ issued a proposed decision adopting the stipulation
and joint recommendation as specified above. In addition, the proposed decision
provided clarification on the following four accounting issues that impact the
operation of the TCBA: (1) It directs SCE and the other utilities to review
their estimates of market value for each divested generating plant and
recalculate the interest accrued on undercollections of the TCBA during the
record period. SCE believes it used the market value accounting directed by the
proposed decision; (2) It clarifies the accounting methodology used to estimate
the market value of retained generating assets. At this time, SCE believes there
will be no materially negative impact on earnings associated with this issue;
(3) It directs SCE to apply the TCBA overcollection of $350.7 million as of June
30, 1998, to further accelerate the depreciation of those transition cost assets
with the highest rate of return, and in a manner that provides the greater tax
benefits (i.e., to accelerate the recovery of nuclear sunk costs). It also
directs SCE to net a $238 million undercollection in the ISO/PX implementation
delay memorandum account against the TCBA overcollection in the calculation. SCE
estimates a $10 million impact over the entire transition period ending December
31, 2001, if this accounting change is adopted by the CPUC; and (4) It disallows
the recovery through the TCBA for the Record Period, of certain
telecommunications, training, mechanical service shop and warehouse equipment
that related to SCE's divested generating plants but was not purchased by the
new owners. The net book value of these retained assets is in the $8 million to
$10 million range. Comments to the proposed decision were filed in January and a
supplemental brief was filed on February 1, 2000.

On February 17, 2000, the ALJ prepared a revised proposed decision that
addressed these four matters and left intact other provisions of the proposed
decision. The revised proposed decision was approved by the CPUC on the same
day. The decision found that SCE's calculation of the TCBA for the Record Period
was correct and that SCE appropriately applied the overcollection as of June 30,
1998, to the subsequent undercollection. Therefore, the decision does not
require SCE to accelerate recovery of its nuclear assets. The decision changes
the accounting methodology used to estimate the market value of retained
generating assets and requires that SCE credit the TCBA for the aggregate net
book value of SCE's non-nuclear assets, including the land surrounding such
assets. SCE's shares of the Mohave Station and Four Corners Generating Station
(Four Corners) are excluded from this requirement. Ongoing depreciation, taxes,
and return will be recovered through market revenue. The decision disallows the
recovery through the TCBA for the record period of the retained assets but does
not preclude SCE from seeking recovery in future record periods. The
disallowance for the 1998 record period was $55,000.

23

On February 29, 2000, SCE made a request to the CPUC's Executive Director for an
extension of time to file the compliance advice letter so that the CPUC could
review SCE's soon-to-be filed petition for a stay of the decision, application
for rehearing and/or petition for modification of the decision. In a letter
dated March 3, 2000, the Executive Director granted SCE an extension of time
until May 31, 2000, to file its advice letter compliance filing.

Once SCE had the opportunity to fully review the decision adopted by the CPUC,
it discovered that the revisions by the CPUC in response to the parties'
comments 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 immediately informed the Assigned
Commissioner of the omission, and the Assigned Commissioner issued on March 2,
2000, an Assigned Commissioner's Ruling (ACR) proposing the CPUC establish a
generation asset memorandum account to record this debit. If no debit account
was established by the CPUC, any offsetting debit would be considered as a $300
million charge to earnings on an after tax basis.

In its comments to the ACR, SCE proposed that this account be established as a
balancing account, the Generation Asset Balancing Account, or GABA, 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.

On November 9, 2000, SCE filed a petition for modification of D.00-02-048
requesting the CPUC to allow SCE to credit its TCBA (and debit its GABA) with
the aggregate net above-book gain reflected in the pending sales of SCE's
interest in Mohave, Four Corners and Palo Verde generating plants. Crediting
these amounts to the TCBA would allow SCE to accelerate the end of its rate
freeze as requested in SCE's Rate Stabilization Application, A.00-11-038 (as
revised on December 20, 2000).

1999 ATCP

On September 1, 1999, SCE filed its 1999 ATCP setting forth entries made to the
TCBA and other generation-related accounts for the months of July 1998 through
June 1999. On February 23, 2000, the ORA issued its report and made the
following disallowance recommendations adverse to SCE: (1) approximately $5.5
million in post-record period adjustments booked after the date of divestiture
for capital additions made in 1996 to divested fossil generating plants that was
transferred to the TCBA; (2) $17.2 million related to the termination contract
with the Sacramento Municipal Utility District (SMUD); (3) $252,000 in
employee-related transition costs; and (4) a $136,000 adjustment to the QF sub
account of the TCBA. SCE served its rebuttal testimony on March 29, 2000, and
supplemental testimony on April 3, 2000. Prior to hearings, ORA and SCE executed
a Settlement Agreement that resolved all issues associated with SCE's filing.
The parties agreed that (1) SCE made the $5.5 million adjustment and a $136,000
adjustment to the TCBA as referred to above; (2) ORA no longer contests the
reasonableness of SCE's termination contracts with SMUD; and (3) $192,000 in
employee-related transition costs are to be disallowed. In the settlement, the
parties agree that the Union Worker Protection Benefit (WPB) Agreements were
reviewed for reasonableness by ORA in this proceeding and that the programs and
benefits in each of the WPB Agreements are reasonable and qualify for recovery
as transition costs through the TCBA. On October 19, 2000, the CPUC issued its
decision that approved the Settlement Agreement, closing this proceeding.

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 Commission: (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

24

(3) adjust the TCBA undercollection downward $4.35 million to reflect the
reasonableness of post record period adjustments. On March 15, 2001, in response
to SCE's First Set of Data Requests based on ORA's Report, ORA withdrew its
recommendation to defer its review of SCE's natural gas procurement and
management activities, including a $10,000,000 gas options post-record period
adjustment, until the 2001 ATCP. ORA found the $10,000,000 post-period
adjustment to be reasonable as well as SCE's natural gas procurement and
management activities during the record period with respect to the El Paso
contract. Since ORA no longer objects to the $10,000,000 gas options post-record
period adjustment, ORA no longer recommends that the TCBA needs to be further
adjusted and now agrees with SCE's June 30, 2000, TCBA balance. The only
contested issue that remains is the $882,000 in employee-related transition
costs. SCE's rebuttal testimony was mailed on March 27, 2001, and hearings are
scheduled for May 21 through May 25, 2001.

Annual Energy Cost Adjustment Clause (ECAC) Proceedings

Through 1998, SCE filed ECAC applications each year with the CPUC regarding its
fuel and purchased power expenses, seeking the CPUC's determination that SCE's
fuel and purchased power costs, including payments to QFs, were reasonable. The
last ECAC application filed in 1998 was closed in 1999. The ECAC reasonableness
revision of certain costs, including QF payments, is now reviewed in the ATCP
proceedings discussed above.

Palo Verde Nuclear Generating Station

In January 1997, the CPUC authorized a further acceleration of the recovery of
SCE's remaining investment of $1.2 billion in Palo Verde Units 1, 2, and 3. The
accelerated recovery will continue through December 2001, earning a 7.35% fixed
rate of return. The future operating costs, including nuclear fuel and nuclear
fuel financing costs, and incremental capital expenditures, are subject to
balancing account treatment through 2001. Beginning January 1, 1998, the
balancing account became part of the TCBA mechanism. The existing NUIP will
continue only for purposes of calculating a reward for performance of any unit
above an 80% capacity factor for a fuel cycle. These rate-making plans and the
TCBA mechanism will continue for rate-making purposes through the end of the
rate freeze period. However, due to the various unresolved regulatory and
legislative issues (see discussion in the Significant Developments in California
Electric Utility Restructuring above), SCE is not able to conclude that the
unamortized nuclear investment regulatory assets are probable of recovery
through the rate-making process. As a result, these balances were written off as
a charge to earnings as of December 31, 2000. Beginning in 2002, SCE will be
required to share the net benefits received from the operation of Palo Verde
equally with ratepayers. If the MOU is implemented, or a rate mechanism provided
by legislation or regulatory authority is established that makes recovery from
regulated rates probable as to all or a portion of the amount that has been
charged against earnings, a regulatory asset would be correspondingly reinstated
with a corresponding increase in earnings. In addition, if the MOU is
implemented, the requirement that SCE share the net benefits received from the
post-2001 operation of Palo Verde equally with ratepayers will be eliminated.

San Onofre Nuclear Generating Station Units 2 and 3

In April 1996, the CPUC authorized a further acceleration of the recovery of
SCE's remaining investment of $2.6 billion in San Onofre Units 2 and 3. The
accelerated recovery will continue through December 2001, earning a 7.35% fixed
rate of return. San Onofre's operating costs, including nuclear fuel, nuclear
fuel financing costs, and incremental capital expenditures, are recovered
through an incentive pricing plan which allows SCE to receive about 4(cent) per
kWh through December 31, 2003. Beginning January 1, 1998, the accelerated plant
recovery and incremental cost incentive pricing became part of the TCBA
mechanism. These rate-making plans and the TCBA mechanism will continue for
rate-making purposes through the end of the rate freeze period. However, due to
the various unresolved regulatory and legislative issues (as discussed in
Significant Developments in California Electric Utility Restructuring), SCE is
not able to conclude that the unamortized nuclear investment regulatory assets
are

25

probable of recovery through the rate-making process. As a result, these
balances were written off as a charge to earnings as of December 31, 2000. If
the MOU is implemented, or a rate mechanism provided by legislation or
regulatory authority is established that makes recovery from regulated rates
probable as to all or a portion of the amount that has been charged against
earnings, a regulatory asset would be correspondingly reinstated with a
corresponding increase in earnings. Beginning in 2004, SCE will be required to
share the benefits received from operation of San Onofre Units 2 and 3 equally
with ratepayers. In addition, if the MOU is implemented, the sharing of net
benefits received from the post-2003 operation of San Onofre Units 2 and 3
equally between shareholders and ratepayers would be eliminated, but these units
would continue to be subject to cost-based ratemaking through December 31, 2010.

New Accounting Rules

On January 1, 2001, Edison International adopted a new accounting standard for
derivative instruments and hedging activities. The new standard requires all
derivatives be recognized on the balance sheet at fair value. Gains or losses
from changes in fair value would be recognized in earnings in the period of
change unless the derivative is designated as a hedging instrument. Gains or
losses from hedges of a forecasted transaction or foreign currency exposure
would be recorded as a separate component of shareholders' equity under the
caption Accumulated Other Comprehensive Income. Gains or losses from hedges of a
recognized asset or liability or a firm commitment would be reflected in
earnings for the ineffective portion of the hedge. SCE's derivatives qualify for
hedge accounting under the new standard. On the implementation date, SCE
recorded its interest rate swap agreement (terminated January 5, 2001), and its
block forward power purchase contracts (seized by the State of California on
February 2, 2001) at fair value on its balance sheet. SCE does not anticipate
any earnings impact from its derivatives, since it expects that any market price
changes will be recovered in rates. As a result of the adoption of the new
standard, Edison International expects that the quarterly earnings from its EME
subsidiary will be more volatile than earnings reported under the prior
accounting policy. For Edison International's 2001 earnings, the cumulative
effect on prior years resulting from adoption of the new standard is expected to
be less than $10 million.

Effective January 1, 2000, EME changed its accounting method for major
maintenance to record such expenses as incurred. Previously EME recorded major
maintenance cost on an accrue-in-advance method. EME voluntarily made the change
in accounting due to recent guidance proved by the Securities and Exchange
Commission. The cumulative effect of the change in accounting method was an $18
million after-tax benefit.

On January 1, 1999, Edison International implemented a new accounting rule that
requires costs related to start-up activities to be expensed as incurred.
Although this new accounting rule did not materially affect Edison
International's results of operations or financial position, EME wrote off $14
million (after tax) of previously capitalized start-up costs in first quarter
1999.

Fuel Supply and Purchased Power Costs

Since April 1, 1998, SCE had been required to sell all of its generated and
purchased power through the PX and ISO, schedule delivery of the power through
the ISO, and acquire all of its power from the PX and ISO to distribute to its
retail customers. These PX and ISO transactions were reported net. As of
December 15, 2000, the FERC eliminated this buying and selling requirement. On
January 30, 2001, the PX suspended its day-ahead and day-of energy trading, and
it subsequently ceased operations and filed for bankruptcy. Furthermore,
beginning in January 2001, the CDWR began purchasing power for SCE's customers.
The MOU contemplates that the CDWR will assume the entire responsibility for
procuring the electricity needs of SCE's customers through December 31, 2002, to
the extent not met by SCE's retained generation and power contracts.

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,

26

as well as an increase in the market value of gas call options. Increases in the
options' market value decreased purchased-power expense. These gas call options
(which were sold in October 2000) mitigated SCE's transition cost recovery
exposure to increases in energy prices.

SCE's sources of energy during 2000 were as follows: 58.6% purchased power;
22.3% nuclear; 13.7% coal; and 5.4% 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
the assignee.

Nuclear Fuel Supply

SCE has contractual arrangements covering 100% of the projected nuclear fuel
requirements for San Onofre through the years indicated below:

Uranium concentrates(*)............................................. 2003
Conversion..................................................... 2003
Enrichment..................................................... 2003
Fabrication.................................................... 2005
---------------
(*) Assumes the San Onofre participants meet their supply obligations in a
timely manner.

Assuming normal operation and full utilization of existing on-site storage
capacity, San Onofre Units 2 and 3 will maintain full-core offload reserve
through 2005. The Nuclear Waste Policy Act of 1982 requires that the United
States Department of Energy provide for the disposal of utility spent nuclear
fuel beginning January 31, 1998. The Department of Energy has defaulted on its
obligation to begin acceptance of spent nuclear fuel from the commercial nuclear
industry by that date. Additional spent fuel storage either on-site or at
another location will be required to permit continued operations beyond 2005.

Participants at Palo Verde have contractual agreements for uranium concentrates
to meet projected requirements through 2002. Independent of arrangements made by
other participants, SCE will furnish its share of uranium concentrates
requirement through at least 2001 from existing contracts. Contracts covering
100% of requirements are in place for enrichment through 2003 and fabrication
through 2015. Contracts covering 75% of conversion requirements in 2001 are in
place with negotiations on-going for the remainder.

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.

27

Business of the Nonutility Companies

The activities of the Nonutility Companies are described below. For Edison
International's business segment information for each of the years ended
December 31, 2000,1999, and 1998, see Note 13 of Notes to Consolidated Financial
Statements contained in the Annual Report incorporated by reference, in part, in
this report.

Edison Mission Energy: EME is an independent power producer. EME also conducts
energy trading and price risk management activities in markets where power
generation facilities are open to competition. EME is engaged in the business of
developing, acquiring, owning or leasing and operating electric power generation
facilities worldwide. As of December 31, 2000, EME owns interests in 33 domestic
and 40 international operating power stations with an aggregate generating
capacity of 28,036 MW, of which its share is 22,759 MW. One domestic and one
international project totaling 603 MW of generating capacity, of which EME's
anticipated share is approximately 462 MW, are currently in the construction
stage. At December 31, 2000, EME had consolidated assets of $15.0 billion and
total shareholder's equity of $2.9 billion.

To isolate EME from the credit downgrades of Edison International and SCE, and
to facilitate EME's ability and the ability of its subsidiaries to maintain
their respective investment grade ratings, on January 17, 2001, EME amended its
articles of incorporation and its bylaws to include so-called "ring-fencing"
provisions. These ring-fencing provisions are intended to preserve EME as a
stand-alone investment grade rated entity in spite of the current difficulties
of Edison International and SCE. These provisions require the unanimous approval
of EME's board of directors, including at least one independent director, before
it can do any of the following:

o declare or pay dividends or distributions unless:

o EME has an investment grade rating and receives rating agency
confirmation that the dividend or distribution will not result in a
downgrade; or

o 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. EME currently meets this
interest coverage ratio.

o institute or consent to bankruptcy, insolvency or similar proceedings or
actions; or

o consolidate or merge with any entity or transfer substantially all of EME's
assets to any entity, except to an entity that is subject to similar
restrictions;

EME operates predominately in one line of business, electric power generation,
with reportable segments organized by geographic region: Americas, Asia Pacific
and Europe, Central Asia, Middle East and Africa. EME's plants are located in
different geographic areas, which mitigate the effects of regional markets,
economic downturns or unusual weather conditions.

In the past, Edison International has supported the investment activities of EME
through equity investments, equity infusion agreements, intercompany loans and
other arrangements. Due to its current liquidity problems, Edison International
is currently unable to provide such support. This situation may limit the
ability of EME to make new investments, to successfully obtain financing for its
projects, or to obtain sufficient additional equity capital project cash flow
for additional borrowings to enable it to fund the equity commitments required
for future projects.

Below is a brief discussion of the current strategy for each of the three
regions and a summary of EME's projects that are currently in the construction
or early operations stage and other significant operating projects in each of
the regions.

28

Americas - The strategy for the Americas region is (i) to manage EME's interest
in operating and construction phase projects located throughout the United
States, (ii) to expand EME's generation at existing sites (sometimes referred to
as "brownfield" development), (iii) to pursue the development of new power
projects throughout the region, sometimes referred to as "greenfield"
development, and (iv) to a lesser extent than EME had in the past, pursue the
acquisition and development of existing generating assets from utilities,
industrial companies and other independent power producers throughout the
region. EME currently has 33 operating projects in this region, all of which are
presently located in the United States and its territories.

In November 2000, EME completed a transaction with Texaco, Inc., to purchase a
proposed 560 MW gas-fired combined cycle project to be located in Kern County,
California, referred to as the Sunrise Project. The acquisition includes all
rights, title and interest held by Texaco in the Sunrise Project, except that
Texaco has an option to repurchase a 50% interest in the project prior to its
commercial operation. As part of this transaction, EME also: (i) acquired an
option to purchase two gas turbines which EME plans to utilize in the project,
(ii) provided Texaco an option to purchase two of the turbines available to EME
under the EME Master Turbine Lease, and (iii) granted Texaco an option to
acquire a 50% interest in 1,000 MW of future power plant projects designated by
EME. The Sunrise Project consists of two phases with Phase I, construction of a
single-cycle gas-fired facility (320 MW), currently scheduled to be completed in
August 2001, and Phase II, conversion to a combined-cycle gas-fired facility
(560 MW), currently scheduled to be completed in June 2003. In December 2000,
EME received the Energy Commission Certification and a permit to construct the
Sunrise plant, which allowed EME to commence construction of Phase I. EME is
negotiating with the California Department of Water Resources the detailed terms
and conditions of a long-term, cost-based-type rate power purchase agreement.
Edison International cannot predict whether EME will be successful in reaching a
final agreement. The MOU with the CDWR, to which Edison International is a
party, calls for a term of at least 10 years and specifies cost-of-service based
pricing, to be embodied in a definitive agreement by August 15, 2001. Under the
MOU, if the Sunrise Project is not placed in service on or before August 15,
2001, Edison International must credit the amount of $2 million against the
first $2 million in billings the CDWR would otherwise be required to pay EME
under the agreement.

In September 2000, EME completed a transaction with P&L Coal Holdings
Corporation and Gold Fields Mining Corporation (Peabody) to acquire the trading
operations of Citizens Power LLC and a minority interest in certain structured
transaction investments relating to long-term power purchase agreements. As a
result of this acquisition, EME has expanded its trading operations beyond the
traditional marketing of its electric power. By the end of the third quarter of
2000, the Citizens' trading operations were merged into EME's own marketing
operations, Edison Mission Marketing & Trading, Inc. (EMMT).

In December 1999, EME acquired the fossil-fuel generating plants of Commonwealth
Edison, a subsidiary of Exelon Corporation, which are collectively referred to
as the Illinois Plants, totaling 6,841 MW of generating capacity, for
approximately $4.1 billion. EME operates these plants, which provide access to
the Mid-America Interconnected Network and the East Central Area Reliability
Council. In connection with this transaction, EME entered into power purchase
agreements with Commonwealth Edison with a term of up to five years.
Subsequently, Commonwealth Edison assigned its rights and obligations under
these power purchase agreements to Exelon Generation Company, LLC.

Concurrently with this acquisition, EME assigned its right to purchase the
Collins Station, a 2,698 MW gas and oil-fired generating station located in
Illinois, to third party lessors. After this assignment, EME entered into a
lease of the Collins Station with a term of 33.75 years. The aggregate MW
purchased or leased as a result of these transactions is 9,539 MW.

In March 1999, EME acquired 100% of the 1,884 MW Homer City Electric Generating
Station for approximately $1.8 billion. This facility is a coal-fired plant in
the mid-Atlantic region of the United States and has 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 is commonly known as the NYISO and the Pennsylvania-New
Jersey-Maryland Power Pool, which is commonly known as the PJM. EME operates the
plant, which EME believes is one of the lowest-cost generation facilities in the
region.

29

Asia Pacific - The strategy for the Asia-Pacific region is (i) to pursue
projects in countries where there exist strong political commitment and the
structural framework necessary for private power, (ii) to seek opportunities to
employ indigenous fuels, and (iii) to seek strategic, complementary alliances
with partners who bring value to a project by providing fuel, equipment and
construction services.

In February 2001, EME completed the acquisition of a 50% interest in CBK Power
Co. Ltd. in exchange for $20 million. CBK Power has entered into a 25-year
build-rehabilitate-transfer-and-operate agreement with National Power
Corporation related to the 726 MW Caliraya-Botocan-Kalayaan (CBK) hydroelectric
project located in the Philippines. Financing for this $460 million project has
been completed with equity contributions of $117 million (EME's 50% share is
$58.5 million) required to be made upon completion of the rehabilitation and
expansion, currently scheduled in 2003, and debt financing has been arranged for
the remainder of the cost of this project.

In May 1999, EME completed a transaction with the government of New Zealand to
acquire 40% of the shares of Contact Energy Limited. The remaining 60% of
Contact Energy's shares were sold in an overseas public offering resulting in
widespread ownership among the citizens of New Zealand and offshore investors.
These shares are publicly traded on stock exchanges in New Zealand and
Australia. During 2000, EME increased its share of ownership of Contact Energy
to 42%. Contact Energy owns and operates hydroelectric, geothermal and natural
gas-fired power generating plants primarily in New Zealand with a total current
generating capacity of 2,449 MW, of which EME's share is 940 MW. In addition,
Contact Energy has expanded into the retail electricity and gas markets in New
Zealand since 1998 through acquisition of regional electricity supply and retail
gas supply businesses. See Recent Foreign Regulatory Matters.

The Paiton project is a 1,230 MW coal-fired power plant in operation in East
Java, Indonesia. A wholly-owned subsidiary of EME owns a 40% interest and had a
$490 million investment in the Paiton project at December 31, 2000. The
project's tariff under the power purchase agreement with PT PLN is higher in the
early years and steps down over time. The tariff for the Paiton project includes
costs relating to infrastructure to be used in common by other units at the
Paiton complex. The plant's output is fully contracted with the state-owned
electric company, PT PLN. Payments are in Indonesian Rupiah, with the portion of
the payments intended to cover non-Rupiah project costs, including returns to
investors, adjusted to account for exchange rate fluctuations between the
Indonesian Rupiah and the U.S. dollar. The project received substantial finance
and insurance support from the Export-Import Bank of the United States, the
Japan Bank for International Cooperation, the U.S. Overseas Private Investment
Corporation and the Ministry of Economy, Trade and Industry of Japan. PT PLN's
payment obligations are supported by the Government of Indonesia.

The projected rate of growth of the Indonesian economy and the exchange rate of
Indonesian Rupiah into U.S. dollars have deteriorated significantly since the
Paiton project was contracted, approved and financed. The Paiton project's
senior debt ratings have been reduced from investment grade to speculative grade
based on the rating agencies' determination that there is increased risk that PT
PLN might not be able to honor the power purchase agreement with P.T. Paiton
Energy, the project company. The Government of Indonesia has arranged to
reschedule sovereign debt owed to foreign governments and has entered into
discussions about rescheduling sovereign debt owed to private lenders.

In May 1999, Paiton Energy notified PT PLN that the first 615 MW unit of the
Paiton project had achieved commercial operation under terms of the power
purchase agreement and, in July 1999, that the second 615 MW unit of the plant
had similarly achieved commercial operation. Because of the economic downturn,
PT PLN is experiencing low electricity demand and PT PLN had, through February
2000, been dispatching the Paiton plant to zero. In addition, PT PLN filed a
lawsuit contesting the validity of its agreement to purchase electricity from
the project. The lawsuit was withdrawn by PT PLN on January 20, 2000, and in
connection with this withdrawal, the parties entered into an interim agreement
for the period through December 31, 2000, under which dispatch levels and fixed
and energy payment amounts were agreed. As of December 31, 2000, PT PLN had made
all fixed payments due under the interim agreement totaling $115 million and all
payments due for energy delivered by the plant to PT PLN. As part of the
continuing negotiations on a long-term restructuring of the tariff, Paiton
Energy and PT PLN agreed

30

in January 2001 on a Phase I Agreement for the period from January 1 through
June 30, 2001. This agreement provides for fixed monthly payments aggregating
$108 million over its six month duration and for the payment for energy
delivered to PLN from the plant during this period. Paiton Energy and PT PLN
intend to complete the negotiations of the further phases of a new long-term
tariff during the six month duration of the Phase I Agreement. To date, PT PLN
has made all fixed and energy payments due under the Phase I Agreement.

Events, including those discussed above, have occurred which may mature into
defaults of the project's debt agreements following the passage of time, notice
or lapse of waivers granted by the project's lenders. On October 15, 1999, the
project entered into an interim agreement with its lenders pursuant to which the
lenders waived defaults during the term of the agreement and effectively agreed
to defer payments of principal until July 31, 2000. In July, the lenders agreed
to extend the term of the lender interim agreement through December 31, 2000. In
December 2000, the lenders agreed to an additional extension of the lender
interim agreement through December 31, 2001. Paiton Energy has received lender
approval of the Phase I Agreement.

Under the terms of the power purchase agreement, PT PLN has been required to
continue to pay for capacity and fixed operating costs once each unit and the
plant achieve commercial operation. As of December 31, 2000, PT PLN has not paid
invoices amounting to $814 million for capacity charges and fixed operating
costs under the power purchase agreement. All arrears under the power purchase
agreement continue to accrue, minus the fixed monthly payments actually made
under the year 2000 interim agreement and under the recently agreed Phase I
Agreement, with the payment of these arrears to be dealt with in connection with
the overall long-term restructuring of the tariff. In this regard, under the
Phase I Agreement, Paiton Energy has agreed that, so long as the Phase I
Agreement is complied with, it will seek to recoup no more than $590 million of
the above arrears, with the payment to be dealt with in connection with the
overall tariff restructuring.

Any material modifications of the power purchase agreement could require a
renegotiation of the Paiton project's debt agreements. The impact of any
renegotiations with PT PLN, the Government of Indonesia, or the project's
creditors on EME's expected return on its investment in Paiton Energy is
uncertain at this time; however, EME believes that it will ultimately recover
its investment in the project.

Europe, Central Asia, Middle East and Africa - EME's strategy in the Europe and
Central Asia, Middle-East and Africa region is to pursue the development and
acquisition of medium to large scale power and cogeneration facilities with
diversified fuel sources and generation technology.

In March 2000, EME completed a transaction with UPC International Partnership CV
II to acquire Edison Mission Wind Power Italy B.V., formerly known as Italian
Vento Power Corporation Energy 5 B.V., which owns a 50% interest in a series of
power projects that are in operation or under development in Italy. All the
projects use wind to generate electricity from turbines. The electricity is sold
under fixed-price, long-term tariffs. Assuming all the projects under
development are completed, currently scheduled for 2002, the total capacity of
these projects will be 283 MW. The total purchase price was 90 billion Italian
Lira (approximately $44 million at December 31, 2000), with equity contribution
obligations of up to 33 billion Italian Lira (approximately $16 million at
December 31, 2000), depending on the number of projects that are ultimately
developed. As of December 31, 2000, payments included $27 million toward the
purchase price and $13 million in equity contributions.

In July 1999, EME acquired 100% of the Ferrybridge and Fiddler's Ferry
coal-fired power plants in the United Kingdom (the "U.K.") with a total
generating capacity of 3,984 MW from PowerGen UK plc for approximately $2.0
billion. Ferrybridge, located in West Yorkshire, and Fiddler's Ferry, located in
Warrington, are in the middle of the order in which plants are called upon to
dispatch electric power. The plants complement the pumped-storage hydroelectric
power plants EME already owns in the U.K.

The current electricity trading mechanism in the U.K. is in the process of being
abolished and replaced with trading arrangements using bilateral contracts. The
current system provides for the sale of energy to a pool. Under the new trading
arrangements, EME's U.K. subsidiary, Edison First Power Limited, is

31

required to contract with specific purchasers for the sales of energy produced
by its Ferrybridge and Fiddler's Ferry stations. Under the new system, a
generator must deliver, and a consumer take delivery, in accordance with their
contracted agreements or face the volatility of market prices. Edison First
Power believes that a consequence of this will be to increase greatly the
motivation of parties to contract in advance in order to lock in an agreed upon
price for, and quantity of, energy. The U.K. Utilities Act, which was approved
on July 28, 2000, allows for implementation of the new trading arrangements
which commenced on March 27, 2001. As a result of the introduction of the new
electricity trading arrangements, forecasts of future electricity prices in the
markets into which Edison First Power sells its power vary significantly. Recent
experience by Edison First Power has shown that this arrangement has placed
significant downward pressure on prices to be paid by purchasers of energy in
the future, although it is uncertain how the new trading arrangements will
affect prices in the long term.

The financial performance of the Fiddler's Ferry and Ferrybridge stations has
not matched EME's expectations, largely due to lower power prices resulting from
increased competition, warmer-than-average weather and uncertainties surrounding
the new electricity trading arrangement discussed above. As a result, Edison
First Power has decided to defer some environmental capital expenditures
originally planned to increase plant utilization and therefore, is currently in
breach of milestone requirements for the implementation of the capital
expenditures program set forth in the financing documents relating to the
acquisition of the plants. In addition, due to this reduced financial
performance, Edison First Power's debt service coverage ratio during 2000
declined below the threshold set forth in the financing documents.

Edison First Power is currently in discussions with the relevant financing
parties to revise the required capital expenditure program, to waive: (i) the
breach of the financial ratio covenant for 2000; (ii) a technical breach of
requirements for the provision of information that was delayed due to
uncertainty regarding capital expenditures; and (iii) other related technical
defaults. Edison First Power is in the process of requesting the necessary
waivers and consents to amendments from the financing parties. EME cannot assure
you that waivers and consents to amendments will be forthcoming. The financing
documents stipulate that a breach of the financial ratio covenant constitutes an
immediate event of default and, if the event of default is not waived, the
financing parties are entitled to enforce their security over Edison First
Power's assets, including the Fiddler's Ferry and Ferrybridge plants. Despite
the breaches under the financing documents, Edison First Power's debt service
coverage ratio for 2000 exceeded 1:1. Due to the timing of its cash flows and
debt service payments, Edison First Power utilized (pound)37 million from its
debt service reserve to meet its debt service requirements in 2000. EME's net
investment in its subsidiary that holds the Ferrybridge and Fiddler's Ferry
power plants and related debt was $918 million at December 31, 2000.

Another of EME's subsidiaries, EME Finance UK Limited, is the borrower under the
facility made available for the purposes of funding coal and capital
expenditures related to the Fiddler's Ferry and Ferrybridge power plants. At
December 31, 2000, (pound)58 million was outstanding for coal purchases and zero
was outstanding to fund capital expenditures under this facility. EME Finance UK
Limited on-lends any drawings under this facility to Edison First Power. The
financing parties of this facility have also issued letters of credit directly
to Edison First Power to support their obligations to lend to EME Finance UK
Limited. EME Finance UK Limited's obligations under this facility are separate
and apart from the obligations of Edison First Power under the financing
documents related to the acquisition of these plants. EME has guaranteed the
obligations of EME Finance UK Limited under this facility, including any letters
of credit issued to Edison First Power under the facility, for the amount of
(pound)359 million, and EME's guarantee remains in force notwithstanding any
breaches under Edison First Power's acquisition financing documents.

In addition, EME may provide guarantees in support of bilateral contracts
entered into by Edison First Power under the new electricity trading
arrangements. EME has provided guarantees totaling (pound)19 million relating to
these contracts at March 20, 2001.

During October 1999, EME completed the acquisition of the remaining 20% of the
220 MW natural gas-fired Roosecote project located in England. Consideration for
the remaining 20% consisted of a cash payment of approximately $16.0 million, or
(pound)9.6 million sterling.

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EME's Operating Power Generation Facilities

Domestic Overview - EME currently owns interests in 32 domestic operating
projects in eight states and one project in the Commonwealth of Puerto Rico.
These operating projects consist of 12 natural gas-fired cogeneration projects,
one coal-fired cogeneration project, seven coal-fired exempt wholesale generator
projects, one waste coal project, one liquefied natural gas combined-cycle
cogeneration project, and 11 gas-fired exempt wholesale generator projects. All
of EME domestic cogeneration projects, as well as the waste coal project, are
qualifying facilities under the Public Utility Regulatory Policies Act. EME's
domestic operating projects have total generating capacity of 15,257 MW, of
which EME's net ownership share is 13,231 MW.

The primary power sales contracts for four of EME's operating projects in 2000
and 1999 and five of EME's operating projects in 1998 are with SCE. Therefore,
the failure of SCE to fulfill its contractual obligations could have a negative
impact on a source of EME's revenues. Under the terms of an agreement between
SCE and the Office of Ratepayer Advocates (ORA), the consumer advocacy branch of
the CPUC, SCE is prohibited from entering into future power sales contracts with
EME or EME's affiliates without ORA's and CPUC's consent. The terms of the
agreement, however, do not affect the terms of the existing power sales
contracts between EME and SCE. Fuel supply for EME projects generally is
arranged through third-party suppliers and transporters.

In September 1998, the CPUC issued an order which approved an agreement entered
into between an operating cogeneration project in which EME has a 30%
partnership interest and SCE to terminate a power sales agreement. The
termination agreement became effective in February 1999.

Four Star - As of December 31, 2000, EME owned 36% of the stock of Four Star Oil
& Gas Company, a subsidiary of Texaco, Inc. The underlying value of Four Star is
attributable to the production of oil and gas from nine producing properties.
EME's proportionate interest in net quantities of proved reserves at December
31, 2000, totaled 180.6 billion cubic feet of natural gas and 10.4 million
barrels of oil.

Recent Foreign Regulatory Matters

United Kingdom - The U.K.'s new electricity trading arrangements are the direct
result of an October 1997 request by the Minister for Science, Energy and
Industry who asked the U.K. Director General of Electricity Supply to review the
operation of the pool pricing system. In July 1998, the Director General
proposed that the current structure of contracts for differences and compulsory
trading via the pool at half-hourly clearing prices bid a day ahead be
abolished. The U.K. Government accepted the proposals in October 1998 subject to
reservations. Following this, further proposals were published by the Government
and the Director General in July and October 1999. The proposals include, among
other things, the establishment of a spot market or voluntary short-term power
exchanges operating from 24 hours to three hours before a trading period; a
balancing mechanism to enable the system operator to balance generation and
demand and resolve any transmission constraints; a mandatory settlement process
for recovering imbalances between contracted and metered volumes with strong
incentives for being in balance; and a Balancing and Settlement Code Panel to
oversee governance of the balancing mechanism. Contracting over time periods
longer than the day-ahead market are not directly affected by the proposals.
Physical bilateral contracts will replace the current contracts for differences,
but will function in a similar manner. However, it remains difficult to evaluate
the future impact of the proposals. A key feature of the new electricity trading
arrangements is to require firm physical delivery, which means that a generator
must deliver, and a consumer must take delivery, against their contracted
positions or face assessment of energy imbalance penalty charges by the system
operator. A consequence of this should be to increase greatly the motivation of
parties to contract in advance and develop forwards and futures markets of
greater liquidity than at present. Recent experience has been that the new
electricity trading arrangements have placed a significant downward pressure on
forward contract prices. Furthermore, another consequence may be that
counterparties may require additional credit support, including parent company
guarantees or letters of credit. Legislation in the form of the Utilities Act,
which was approved July 28, 2000, allows for the implementation of new
electricity trading arrangements and the necessary amendments to generators'

33

licenses. Various key documents were designated by the Secretary of State and
signed by participants on August 14, 2000 (the Go-Active Date); however, due to
difficulties encountered during testing, implementation of the new electricity
trading arrangements has been delayed from November 21, 2000, until March 27,
2001.

A warmer-than-average winter (January to March 2000), the entry of new
operations into the generation market, the impending introduction of the new
electricity trading arrangements coupled with uncertainties surrounding the new
Utilities Act and action by the Director General to control abuse of market
power, discussed below, contributed to a drop in the energy component of pool
prices throughout the year (time weighted average System Marginal Price dropped
from (pound)22.39/MWh in 1999 to (pound)18.75/MWh in 2000) and depressed forward
prices for winter 2000/2001. EME entered into contracts for differences for the
majority of its forecasted generation through the winter 2000/2001, and
accordingly, mitigated the downside risks to further decreases in energy prices.
Despite improvement in capacity prices during August, September and early
October 2000, and a slight firming of forward prices, the short-term prices for
energy continue to be below prior years. As a result of the foregoing, EME
continues to expect lower revenues from its Ferrybridge and Fiddler's Ferry
plants.

The Utilities Act sets as a principal objective for the Government and the
Director General to "protect the interests of consumers ... where appropriate by
promoting competition ...". This represents a shift in emphasis toward the
consumer interest. But this is qualified by a recognition that license holders
should be able to finance their activities. The Act also contains new powers for
the Government to issue guidance to the Director General on social and
environmental matters, changes to the procedures for modifying licenses and a
new power for the Director General to impose financial penalties on companies
for breach of license conditions. EME will be monitoring the operation of these
new provisions.

New Zealand - The New Zealand Government has been undergoing a steady process of
electric industry deregulation since 1987. Reform in the distribution and retail
supply sector began in 1992 with legislation that deregulated electricity
distribution and provided for competition in the retail electric supply
function. The New Zealand Energy Market, established in 1996, is a voluntary
competitive wholesale market which allows for the trading of physical energy on
a half-hourly basis. The Electricity Industry Reform Act, which was passed in
July 1998, was designed to increase competition at the wholesale generation
level by splitting up Electricity Company of New Zealand Limited, the large
state-owned generator, into three separate generation companies. The Electricity
Industry Reform Act also prohibits the ownership of both generation and
distribution assets by the same entity.

The New Zealand Government commissioned an inquiry into the electricity industry
in February 2000. This Inquiry Board's report was presented to the government in
mid 2000. The main focus of the report was on the monopoly segments of the
industry, transmission and distribution, with substantial limitations being
recommended in the way in which these segments price their services in order to
limit their monopoly power. Recommendations were also made with respect to the
retail customer in order to reduce barriers to customers switching. In addition,
the Board made recommendations in relation to the wholesale market's governance
arrangements with the purpose of streamlining them. The recommended changes are
now being progressively implemented.

Sale of Power from Merchant Plants

During 1999, EME has acquired a number of merchant plants, which sell capacity,
energy and, in some cases, other services on a competitive basis under bilateral
arrangements or through centralized power pools that provide an institutional
framework for price setting, dispatch and settlement procedures.

Electric power generated at the Homer City plant is sold under bilateral
arrangements with domestic utilities and power marketers under short-term
contracts with terms of two years or less, or to the PJM or the NYISO. These
pools have short-term markets, which establish an hourly clearing price. The
Homer City plant is situated in the PJM control area and is physically connected
to high-voltage transmission lines serving both the PJM and NYISO markets. The
Homer City plant can also transmit power to the midwestern United States.

34

The majority of electric power generated at the Illinois Plants is sold under
power purchase agreements with Exelon Generation Company in which Exelon
Generation Company purchases capacity and has the right to purchase energy
generated by the Illinois Plants. The agreements, which began on December 15,
1999, and have a term of up to five years, provide for Exelon Generation Company
to make a capacity payment for the plants under contract and an energy payment
for the electricity produced by these plants. The capacity payments provide the
Illinois Plants revenue for fixed charges, and the energy payments compensate
the Illinois Plants for variable costs of production. If Exelon Generation
Company does not fully dispatch the plants under contract, the Illinois Plants
may sell, subject to specified conditions, the excess energy at market prices to
neighboring utilities, municipalities, third party electric retailers, large
consumers and power marketers on a spot basis. A bilateral trading
infrastructure already exists with access to the Mid-America Interconnected
Network and the East Central Area Reliability Council.

EME's plants in the U.K. currently sell their electrical energy and capacity
through a centralized electricity pool, which establishes a half-hourly clearing
price, also referred to as the pool price, for electrical energy. The pool price
is extremely volatile and can vary by as much as a factor of ten or more over
the course of a few hours, due to the large differentials in demand according to
the time of day. The pricing arrangements include provision for capacity
payments to be added to the basic pool price at times of capacity shortage. The
First Hydro, Ferrybridge and Fiddler's Ferry plants have the opportunity to
mitigate a portion of the market risk of the pool by entering into contracts for
differences, which are electricity rate swap agreements related to either the
selling or purchasing price of power. These contracts specify a price at which
the electricity will be traded, and the parties to the agreement make payments
calculated based on the difference between the price in the contract and the
pool price for the element of power under contract. These contracts are sold in
various structures and act to stabilize revenues or purchasing costs by removing
an element of net exposure to pool price volatility. See Recent Foreign
Regulatory Matters.

The Loy Yang B plant sells its electrical energy through 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 system marginal price each half-hour. To
mitigate exposure to price volatility of the electricity traded into the pool,
the Loy Yang B plant has entered into a number of financial hedges. From May 8,
1997, to December 31, 2000, approximately 53% to 64% of the plant output sold
was hedged under vesting contracts, with the remainder of the plant capacity
hedged under the State Hedge. The State Hedge agreement with the State
Electricity Commission of Victoria is a long-term contractual arrangement based
upon a fixed price commencing May 8, 1997, and terminating October 31, 2016. The
State Government of Victoria, Australia guarantees the State Electricity
Commission of Victoria's obligations under the State Hedge. From January 2001 to
July 2014, approximately 77% of the plant output is hedged under the State
Hedge. From August 2014 to October 2016, approximately 56% of the plant output
sold is hedged under the State Hedge. Additionally, the Loy Yang B plant has
entered into a number of fixed forward electricity contracts with terms of up to
two years, which will further mitigate against the price volatility of the
electricity pool.

Power Marketing and Trading Activities

When making sales under negotiated contracts, it is EME's policy to deal with
investment grade counterparties or counterparties that provide equivalent credit
support. Exceptions to the policy are granted only after thorough review and
scrutiny by EME's Risk Management Committee. 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 stabilize
and enhance the operating revenues from merchant plants. When appropriate, EME
manages the "spark spread," or margin, which is the spread between electric
prices and fuel prices and uses forward contracts, swaps, futures, or options
contracts to achieve those objectives.

EME's power marketing and trading organization, EMMT, is divided into front-,
middle-, and back-office segments, with specified duties segregated for control
purposes. The personnel of EMMT have a high

35

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.

EMMT markets and trades electric power and energy related commodity products,
including forwards, futures, options and swaps. It also provides services and
price risk management capabilities to the electric power industry. Price risk
management activities include the restructuring of power sales and power supply
agreements. EME generally balances forward sales and purchase contracts to
mitigate market risk and secure cash flow streams.

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 daily 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 industry "best practice"
techniques including the use of stress testing and worst-case scenario analysis,
as well as stop limits and counter party credit exposure limits.

Edison Capital: Edison Capital provides capital and financial services in energy
and infrastructure projects, including power generation, electric transmission
and distribution, transportation, telecommunications, and affordable housing. On
December 31, 2000, Edison Capital had total consolidated assets of $3.7 billion
and, for the year then ended, consolidated revenue of $274 million and net
income of $135 million. Edison Capital invested $570 million in energy and
infrastructure projects and $63 million in affordable housing in 2000.

Europe - 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 is 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 (FFF) in northern England.
This financing was committed in 1999 and closed in January 2000. In January
2001, Edison Capital redeemed its investment in FFF 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 $17
million in four 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.

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.

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 77% of Edison Capital's
original $80 million commitment. Through the fund, Edison Capital invested $56
million in 12 projects. Together with LAIF and AIG, Edison Capital invested $20
million in cable television systems in Mexico.

36

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 2000, Edison Capital closed
investments of $27 million in 10 projects. As of year end 2000, Edison Capital
has invested $57.5 million or 55% 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 28,200
housing units in 37 states. During 2000, the company closed $63 million in
investments, and committed $35 million. Edison Capital completed two
syndications of affordable housing properties during the year.

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 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
utilized by Edison International and Edison Capital is not currently receiving
cash for them. Without such cash, Edison Capital must meet its current
obligations out of its existing cash resources 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.

Edison Enterprises: Edison Enterprises was organized to own the stock and
coordinate the activities of Edison International's retail products and services
business. The current Edison Enterprises businesses include Edison Select and
Edison Source. 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. The financial effect of the sale
is not material to Edison International.

Edison Select: Edison Select is 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. In 1998, Edison Enterprises acquired Westec Residential Security, Inc.
and Valley Burglar and Fire Alarm Company, Inc., which significantly expanded
Edison Select's residential security business.

Edison Source: Edison Source is 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.

37

Item 2. Properties of SCE

The principal properties of SCE are described below. Properties of EME and
Edison Capital are discussed above under Business of the Nonutility Companies.

Existing Utility Generating Facilities

SCE owns and operates one diesel-fueled generating plant located on Santa
Catalina island, 37 hydroelectric plants, and an undivided 75.05% interest
(1,614 MW net) in San Onofre Units 2 and 3. These plants are located in Central
and Southern California.

SCE also owns a 15.8% (590 MW net) share of Palo Verde which is located near
Phoenix, Arizona. SCE owns a 48% undivided interest (754 MW net) in Units 4 and
5 at Four Corners, which is a coal-fueled steam electric generating plant
located in New Mexico. Palo Verde and Four Corners are operated by other
utilities. In April 2000, SCE agreed to sell its 15.8% interest in Palo Verde
and its 48% interest in Four Corners Generation Station to Pinacle West Energy
for $550 million, subject to certain adjustments. The transaction remained
subject to the approval of the CPUC, the Nuclear Regulatory Commission, the FERC
and other state and federal entities, and to the receipt of a favorable ruling
from the Internal Revenue Service. Under the sales agreement, competing offers
could be solicited by SCE, subject to certain conditions, and any superior
offers received were subject to certain matching rights by PWE. In late 2000,
SCE received a superior offer for its Four Corners Generating Station, which PWE
elected not to match. In January 2001, California state legislation was enacted
which bars the sale of utility generating facilities, including SCE's Palo Verde
and Four Corners generating facilities, until 2006. Under the MOU, SCE would
continue to own its share of these generating assets, which would be subject to
cost-based ratemaking, through 2010.

SCE operates and owns a 56% undivided interest (885 MW) in the Mohave Station,
which consists of two coal-fueled steam electric generating units in Clark
County, Nevada. In April 2000, the CPUC approved SCE's proposed auction process
to sell its 56% interest in Mohave Generating Station. In May 2000, SCE agreed
to sell its interest in Mohave to AES Corporation for approximately $533
million. The transaction was subject to final approval by the CPUC and various
federal regulatory agencies. In June 2000, SCE submitted a compliance filing
with the CPUC seeking approval of the auction results and the sale to AES. In
January 2001, California state legislation was enacted which bars the sale of
utility generating facilities, including SCE's Mohave plant, until 2006. Under
the MOU, SCE would continue to own its generating assets, which would be subject
to cost-based ratemaking, through 2010.

At year-end 2000, the existing SCE-owned generating capacity (summer effective
rating) was divided approximately as follows: 44.6% nuclear, 31.8% coal, 23.4%
hydroelectric, and 0.2% 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 U.S. or others under (with minor exceptions)
licenses, permits, easements or leases, or on public streets or highways
pursuant to franchises. Certain of such documents obligate SCE, under specified
circumstances and at its expense, to relocate transmission, distribution, and
communication facilities located on lands owned or controlled by federal, state,
or local governments.

The 37 hydroelectric plants (some with related reservoirs) have an effective
operating capacity of 1,156 MW, and are, with five exceptions, located in whole
or in part on lands of the U.S. pursuant to 30- to 50-year governmental licenses
that expire at various times between 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

38

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 1999, SCE filed an application with the
CPUC establishing for purposes of the application a market value for its
hydroelectric generation-related assets at approximately $1.0 billion (almost
twice the assets' book value) and proposing to retain and operate the
hydroelectric assets under a performance-based, revenue-sharing mechanism. The
application has broad-based support from labor, ratepayer and environmental
groups. If approved by the CPUC, SCE would be allowed to recover an authorized,
inflation-indexed operations and maintenance allowance, as well as a reasonable
return on capital investment. A revenue-sharing arrangement would be activated
if revenue from the sale of hydroelectricity exceeds or falls short of the
authorized revenue requirement. SCE would then refund 90% of the excess revenue
to ratepayers or recover 90% of any shortfalls from ratepayers. A final CPUC
decision is expected in 2001. Under the MOU, SCE would withdraw this
application, and would continue to own the hydroelectric assets, which would be
subject to cost-based ratemaking, through 2010. In June 2000, SCE credited the
TCBA with the proposed excess of market value over book value of its
hydroelectric generation assets and simultaneously recorded the same amount in
the GABA, pursuant to a CPUC decision. This balance was to remain in GABA until
final market valuation of the hydroelectric assets. If there were a difference
in the final market value, it would have been credited to or recovered from
customers through the TCBA. Due to the various unresolved regulatory and
legislative issues (as discussed in Significant Developments in California
Electric Utility Restructuring), 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.

The capacity factors in 2000 for SCE's principal generation resources were:
45.1% for SCE's hydroelectric plants (lower than average due to below-normal
water conditions); 96.4% for San Onofre; 77.9% for the Mohave Station; 79.2% for
Four Corners Units 4 and 5; and 93% for Palo Verde.

Substantially all of SCE's properties are subject to the lien of a trust
indenture securing First and Refunding Mortgage Bonds (Trust Indenture), of
which approximately $2 billion in principal amount was outstanding on December
31, 2000. 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 U.S. and a lease from The Navajo Nation, may
be subject to possible defects. These defects include possible conflicting
grants or encumbrances not ascertainable because of the absence of, or
inadequacies in, the applicable recording law and the record systems of the
Bureau of Indian Affairs and The Navajo Nation, the possible inability of SCE to
resort to legal process to enforce its rights against The Navajo Nation without
Congressional consent, possible impairment or termination under certain
circumstances of the easement and lease by The Navajo Nation, Congress, or the
Secretary of the Interior, and the possible invalidity of the Trust Indenture
lien against SCE's interest in the easement, lease, and improvements on Four
Corners.

As discussed above, the MOU between the CDWR and SCE calls for the State's
purchase of SCE's transmission lines for an estimated price of $2.76 billion
(2.3 times book value). The sale is subject to execution of a definitive sale
agreement and other conditions. If a sale of the transmission assets is not
completed under certain circumstances, the MOU calls for SCE's hydroelectric
assets, and potentially additional rights to output from its other generating
stations, to be sold to the State.

39

SCE Construction Program and Capital Expenditures

Cash required by SCE for its capital expenditures totaled $1.1 billion in 2000,
$986 million in 1999, and $861 million in 1998. Construction expenditures for
the 2001-2005 period are forecasted at $4.5 billion, but may have to be scaled
back unless regulatory or legislative changes make SCE creditworthy again.

In addition to cash required for construction expenditures for the next five
years as discussed above, $3.4 billion is needed to meet requirements for
long-term debt maturities and sinking fund redemption requirements.

SCE's estimates of cash available for operations for the five years through 2005
assume, among other things, satisfactory reimbursement of cos 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.
Because of its current liquidity and credit problems, SCE is unable to obtain
financing of any kind. Similarly, as a result of investor's concerns regarding
the California energy crisis' effect on SCE's liquidity and overall financial
condition, SCE has repurchased $849 million of pollution-control bonds that
could not be remarketed in accordance with their terms. These bonds may be
remarketed in the future if SCE's credit status improves sufficiently. In
January 2001, Fitch, Standard and Poor's, and Moody's Investors Service lowered
their credit ratings of SCE to substantially below investment grade. In
mid-April, Moody's removed SCE's credit ratings from review for possible
downgrade. The ratings remain under review for possible downgrade by the other
agencies.

Under the MOU among the CDWR, SCE and Edison International, Edison International
and SCE would commit to make capital investments in SCE's regulated businesses
of at least $3 billion through 2006, or a lesser amount approved by the CPUC.
The equity component of the investments would be funded from SCE's retained
earnings or, if necessary, from equity investments by Edison International.

Nuclear Power Matters

SCE's nuclear facilities have been reliable sources of inexpensive,
non-polluting power for SCE's customers for more than a decade. Throughout the
operating life of these facilities, SCE's customers have supported the revenue
requirements of SCE's capital investment in these facilities and for their
incremental costs through traditional cost-of-service ratemaking.

In 1996, the CPUC adopted SCE's San Onofre Unit 2 and 3 proposal under which SCE
would have recovered its remaining investment in the San Onofre Units at a
reduced rate of return of 7.35%, but on an accelerated basis during the
eight-year period from the effective date in 1996 through December 31, 2003.
California's restructuring legislation, however, requires the recovery of the
San Onofre investment to be completed by December 31, 2001. In addition, the
traditional cost-of-service ratemaking for San Onofre Units 2 and 3 was
superseded by an incentive pricing plan in which SCE's customers pay a preset
price for each kWh of energy generated at San Onofre during the eight-year
period. The restructuring legislation allows for the continuation of the
incentive pricing plan through December 31, 2003. SCE is compensated for the
incremental costs required for the continued operation of San Onofre Units 2 and
3 with revenue earned through the incentive pricing plan. SCE also retained the
ability to request recovery of the cost of replacement energy for periods in
which San Onofre will not generate power through ECAC filings and, beginning in
1998, as part of the TCBA mechanism. These rate-making plans and the TCBA
mechanism will continue for rate-making purposes through the end of the rate
freeze period. However, due to the various unresolved regulatory and legislative
issues (see discussion in the Significant Developments in

40

California Electric Utility Restructuring above), SCE is not able to conclude
that the unamortized nuclear investment regulatory assets are probable of
recovery through the rate-making process. As a result, these balances were
written off as a charge to earnings as of December 31, 2000. The restructuring
legislation also allows SCE to continue to collect funds for decommissioning
expenses through traditional ratemaking treatment. If the MOU is implemented, or
a rate mechanism provided by legislation or regulatory authority is established
that makes recovery from regulated rates probable as to all or a portion of the
amount that has been charged against earnings, a regulatory asset would be
correspondingly reinstated with a corresponding increase in earnings.

On July 16, 1997, the CPUC approved SCE's request to transfer the recorded net
investment in San Onofre Units 2 and 3 step-up transformers to San Onofre Units
2 and 3 sunk costs for recovery by December 31, 2001, at a reduced rate of
return of 7.35%.

On August 21, 1997, the CPUC approved San Diego Gas & Electric's (SDG&E) and
SCE's Joint Petition to Modify, requesting continued recovery of certain
corporate administrative and general costs allocable to San Onofre Units 2 and
3, at rates of 0.28(cent) and 0.21(cent) per kWh, respectively, for the period
January 1, 1998, through December 31, 2003.

In 1996, SCE filed its Palo Verde Proposal Application requesting adoption of a
new rate mechanism for Palo Verde consistent with that of San Onofre Units 2 and
3. On November 15, 1996, SCE, the ORA, and TURN entered into a settlement
agreement, which was approved by the CPUC on December 20, 1996. The agreement
allows SCE to recover its remaining investment in the Palo Verde units by
December 31, 2001, at a reduced rate of return of 7.35% consistent with the
restructuring legislation. The settling parties 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.

Beginning in 2002, the net benefits of future operation of Palo Verde Units 1,
2, and 3 will be shared equally between shareholders and customers. Likewise,
beginning in 2004, the benefits of future operation of San Onofre Units 2 and 3
will be shared equally between shareholders and customers. If the MOU is
implemented, the sharing of net benefits received from the post-2001 operation
of Palo Verde and post-2003 operation of San Onofre Units 2 and 3 equally
between shareholders and ratepayers would be eliminated, but these units would
continue to be subject to cost-based ratemaking through December 31, 2010.

San Onofre Nuclear Generating Station

In 1992, the CPUC approved a settlement agreement between SCE and the ORA to
discontinue operation of Unit 1 at the end of its then-current fuel cycle. In
November 1992, SCE discontinued operation of Unit 1. As part of the agreement,
SCE recovered its remaining investment over a four-year period ending August
1996. On December 21, 1998, SCE filed an application with the CPUC requesting
authorization to access its nuclear decommissioning trust funds for Unit 1 for
the purpose of commencing decommissioning of Unit 1 in 2000. On March 8, 1999,
SCE, SDG&E, the ORA and TURN entered into a settlement agreement that provided
for SCE to access its nuclear decommissioning trust funds for Unit 1
decommissioning. On June 3, 1999, the CPUC adopted the settlement agreement. On
December 6, 1999, SCE applied for a coastal permit to demolish and remove San
Onofre Unit 1 buildings and other structures and to construct a temporary used
fuel storage facility (also referred to as an independent spent fuel storage
installation) as part of the San Onofre Unit 1 decommissioning project. On
February 15, 2000, the California Coastal Commission approved SCE's application.
Decommissioning of Unit 1 is now underway and it is anticipated that
decommissioning will continue through 2008. At that time, San Onofre

41

Unit 1 will be completely dismantled and only the spent nuclear fuel will remain
on-site in an independent spent fuel storage installation. All of SCE's
reasonable San Onofre Unit 1 decommissioning costs will be paid from its nuclear
decommissioning trust funds.

San Onofre Unit 3 is 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 in the secondary side of the plant 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. SCE presently expects that repair costs
will be covered by applicable insurance except for an approximate $1.9 million
deductible. SCE loses about $800,000 per day of revenue for each day of the
outage under the currently effective San Onofre Units 2 and 3 Incremental Cost
Incentive Pricing plan. The unit is expected to return to service at the end of
June. It is estimated that the lost revenue due to this repair outage will be
approximately $110 million.

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 installation for Units 2 and 3. This
permit application was approved, with certain conditions, by the California
Coastal Commission at its meeting on March 13, 2001.

Palo Verde Nuclear Generating Station

In April 2000, SCE agreed to sell its 15.8% interest in Palo Verde and its 48%
interest in Four Corners Generation Station to Pinacle West Energy (PWE) for
$550 million, subject to certain adjustments. The transaction remained subject
to the approval of the CPUC, the Nuclear Regulatory Commission, the FERC and
other state and federal entities, and to the receipt of a favorable ruling from
the Internal Revenue Service. Under the sales agreement, competing offers could
be solicited by SCE, subject to certain conditions, and any superior offers
received were subject to certain matching rights by PWE. In late 2000, SCE
received a superior offer for its Four Corners Generating Station, which PWE
elected not to match. In January 2001, California state legislation was enacted
which bars the sale of utility generating facilities, including SCE's Palo Verde
and Four Corners generating facilities, until 2006. Under the MOU, SCE would
continue to own its generating assets, which would be subject to cost-based
ratemaking, through 2010.

Nuclear Facility Decommissioning

Decommissioning of San Onofre Unit 1 (shutdown in 1992 per CPUC agreement)
started in 1999 and will continue through 2008. All of SCE's San Onofre's Unit 1
decommissioning costs will be paid from its nuclear decommissioning funds. On
March 9, 2000, the NRC amended the operating licenses for San Onofre Units 2 and
3 so that the operating licenses for both units expire in 2022. Prior to that
amendment, the San Onofre Units 2 and 3 operating licenses expired in 2013. The
Palo Verde operating licenses currently expire in 2026 and 2028, respectively.
SCE plans to decommission San Onofre Units 2 and 3 as early as 2013 and Palo
Verde at the end of each unit's operating license by a removal method authorized
by the NRC.

Decommissioning is estimated to cost $2.1 billion in current-year dollars based
on site-specific studies performed in 1998 for San Onofre and Palo Verde. This
estimate considers the total cost of decommissioning and dismantling the plant,
including labor, material, burial, and other costs. The site-specific studies
are updated approximately every three years. Changes in the estimated costs,
timing of

42

decommissioning, or the assumptions underlying these estimates could cause
material revisions to the estimated total cost to decommission in the near term.
SCE estimates that it will spend approximately $8.6 billion through 2060 to
decommission its nuclear facilities.

Decommissioning expense was $106 million in 2000, $124 million in 1999, and $164
million in 1998. The accumulated provision for decommissioning excluding San
Onofre Unit 1 and unrealized holding gains was $1.4 billion at December 31,
2000, $1.3 billion at December 31, 1999, and $ 1.2 billion at December 31, 1998.
The estimated costs recorded as a liability to decommission San Onofre Unit 1
are approximately $342 million as of December 31, 2000.

Decommissioning funds collected in rates are placed in independent trusts which,
together with accumulated earnings, will be utilized solely for decommissioning.

Nuclear Insurance

Federal law limits public liability claims from a nuclear incident to $9.5
billion. SCE and other owners of San Onofre and Palo Verde have purchased the
maximum private primary insurance available ($200 million). The balance is
covered by the industry's retrospective rating plan that uses deferred premium
charges to every reactor licensee if a nuclear incident at any licensed reactor
in the U.S. results in claims and/or costs which exceed the primary insurance at
that plant site. Federal regulations require this secondary level of financial
protection. The NRC exempted San Onofre Unit 1 from this secondary level,
effective June 1994. The maximum deferred premium for each nuclear incident is
$88 million per reactor, but not more than $10 million per reactor may be
charged in any one year for each incident. Based on its ownership interests, SCE
could be required to pay a maximum of $175 million per nuclear incident. It
would have to pay, however, no more than $20 million per incident in any one
year. Such amounts include a 5% surcharge if additional funds are needed to
satisfy public liability claims and are subject to adjustment for inflation. If
the public liability limit above is insufficient, federal regulations may impose
further revenue-raising measures to pay claims, including a possible additional
assessment on all licensed reactor operators.

Property damage insurance covers losses up to $500 million, including
decontamination costs, at San Onofre and Palo Verde. Decontamination liability
and property damage coverage exceeding the primary $500 million has also been
purchased in amounts greater than federal requirements. Additional insurance
covers part of replacement power expenses during an accident-related nuclear
unit outage. These policies are issued by a mutual insurance company owned by
utilities with nuclear facilities. If losses at any nuclear facility covered by
the arrangement were to exceed the accumulated funds for these insurance
programs, SCE could be assessed retrospective premium adjustments of up to $19
million per year. Insurance premiums are charged to operating expense.

Item 3. Legal Proceedings

Edison International

Geothermal Generators' Litigation

Edison International and two of its nonutility subsidiaries, The Mission Group,
and Mission Power Engineering Company, have been named as defendants in a
lawsuit more fully described under Southern California Edison Company -
Geothermal Generators' Litigation.

Shareholder Litigation

Edison International has been named as a defendant along with SCE in two
lawsuits more fully described under Southern California Edison Company -
Shareholder Litigation.

43

Power Generator Litigation

Edison International along with SCE has been named as a defendant in a lawsuit
more fully described under Southern California Edison Company - Power Generator
Litigation.

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. EME has agreed to
indemnity Brooklyn Navy Yard and its partner in the venture from all claims and
costs arising from or in connection with the contractor litigation.

Southern California Edison Company

Geothermal Generators' Litigation

On June 9, 1997, SCE filed a complaint in Los Angeles County Superior Court
against an independent power producer of geothermal generation and six of its
affiliated entities (Coso parties). SCE alleges that in order to avoid power
production plant shutdowns caused by excessive noncondensable gas in the
geothermal field brine, the Coso parties routinely vented highly toxic hydrogen
sulfide gas from unmonitored release points beginning in 1990 and continuing
through at least 1994, in violation of applicable federal, state, and local
environmental law. According to SCE, these violations constituted material
breaches by the Coso parties of their obligations under their contracts with SCE
and applicable law. SCE seeks damages for excess power purchase payments made to
the Coso parties and other relief. The Coso parties' motion to transfer venue to
Inyo County Superior Court was granted on August 31, 1997.

The Coso parties filed a cross-complaint against SCE, The Mission Group, and
Mission Power Engineering Company (Mission parties), which contains claims for
breach of contract, unfair competition, interference with contract, defamation,
breach of an earlier settlement agreement between the Mission parties and the
Coso parties, and other claims. As against SCE, the cross-complaint seeks
restitution, compensatory damages in excess of $115 million, punitive damages in
an amount not less than $400 million, interest, attorney's fees, declaratory
relief, and injunctive relief. As against the Mission parties, the
cross-complaint seeks damages for breach of warranty of authority with respect
to the settlement agreement, and for equitable indemnity. Edison International
was named as a cross-

44

defendant, allegedly as an alter ego of SCE and the Mission parties. The Coso
parties voluntarily dismissed the claims against Edison International.

Three of the Coso Parties also filed a separate action in the Inyo County
Superior Court against SCE and Edison International, alleging claims for unfair
competition, false advertising and for violations of Public Utilities Code ss.
2106, and seeking injunctive relief, restitution, and punitive damages. The
Court ordered this action consolidated with the SCE action.

Effective February 8, 2000, the parties entered into confidential agreements
resolving all claims in the consolidated action and calling for dismissals with
prejudice and releases. The settlement is subject to the approval of the CPUC.
On February 10, 2000, the Court approved a stipulation staying all proceedings
during the period required to obtain CPUC approval. On April 26, 2000, SCE filed
an application to obtain such approval. The Commission approved the settlement
at its November 21, 2000, meeting, and issued it decision on November 22, 2000.
That decision became final (no longer subject to appeal) on December 22, 2000.
Performance of one of the Coso Parties' settlement obligations has not occurred,
delaying the filing and entry of the dismissals. The case has not yet been
dismissed pending completion of certain obligations under the settlement
agreements.

San Onofre Personal Injury Litigation

SCE is actively involved in three lawsuits claiming personal injuries allegedly
resulting from exposure to radiation at San Onofre. In addition, a fourth
lawsuit claiming personal injuries from exposure to radiation at San Onofre has
recently been filed but has not yet been served on SCE.

On August 31, 1995, the wife and daughter of a former San Onofre security
supervisor sued SCE and SDG&E in the U.S. District Court for the Southern
District of California. Plaintiffs also named Combustion Engineering and the
Institute of Nuclear Power Operations as defendants. All trial court proceedings
were stayed pending ruling of the Ninth Circuit Court of Appeal, on an appeal of
a lower court's judgment in favor of SCE in two earlier cases raising similar
allegations. On May 28, 1998, the Court of Appeal affirmed these judgments.
Pursuant to an agreement of the parties as described below, all proceedings in
this matter have been stayed.

On November 17, 1995, an SCE employee and his wife sued SCE in the U.S. District
Court for the Southern District of California. Plaintiffs also named Combustion
Engineering. The trial in this case resulted in a jury verdict for both
defendants. The plaintiffs' motion for a new trial was denied. Plaintiffs filed
an appeal of the trial court's judgment to the Ninth Circuit Court of Appeal.
Briefing on the appeal was 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 January 2, 2001, the Court granted SCE's rehearing petition as to
certain issues and ordered further briefing on those rehearing issues within 30
days. This further briefing was filed on February 1, 2001. On February 20, 2001,
the Court issued an order setting oral argument on the rehearing issues for
April 26, 2001. A decision on the rehearing is not expected for at least several
weeks.

On November 28, 1995, a former contract worker at San Onofre, her husband, and
her son, sued SCE in the U.S. District Court for the Southern District of
California. Plaintiffs also named Combustion Engineering. On August 12, 1996,
the Court dismissed the claims of the former worker and her husband with
prejudice, leaving only the son as plaintiff. Pursuant to an agreement of the
parties as described below, all proceedings in the matter have been stayed.

In March of 1999, SCE reached an agreement with the plaintiffs in both of the
cases at the U.S. District Court level to stay all proceedings including trial,
pending the results of the case currently before the Ninth Circuit Court of
Appeal. The parties agreed that if the plaintiffs do not receive a favorable
determination on appeal then the two cases at the District Court level will be
dismissed. If, however, those plaintiffs

45

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.

On March 1, 2001, a former contract worker at San Onofre and his wife sued SCE
in the U.S. District Court for the Southern District of California. Plaintiffs
also named Combustion Engineering and Bechtel Construction Company, the employer
of the former San Onofre worker. This lawsuit has not yet been served upon SCE
or, to SCE's knowledge, upon the other defendants.

SCE was previously involved, along with other defendants, in two earlier cases
raising allegations similar to those described above. Although SCE is no longer
actively involved in these actions, the impact on SCE, if any, from further
proceedings in those cases against the remaining defendants cannot be determined
at this time.

Navajo Nation Litigation

On June 18, 1999, SCE was served with a complaint filed by the Navajo Nation in
the United States District Court for the District of Columbia against Peabody
Holding Company and certain of its affiliates (Peabody), Salt River Project
Agricultural Improvement and Power District, and SCE. The complaint asserts
claims against the defendants for, among other things, violations of the federal
RICO statute, interference with fiduciary duties and contractual relations,
fraudulent misrepresentation by nondisclosure, and various contract-related
claims. Peabody supplies coal from mines on Navajo Nation lands to the Mohave
Station. The complaint claims that the defendants' actions prevented the Navajo
Nation from obtaining the full value in royalty rates for the coal. The
complaint seeks damages of not less than $600 million, trebling of that amount,
and punitive damages of not less than $1 billion, as well as a declaration that
Peabody's lease and contract rights to mine coal on Navajo Nation lands should
be terminated. SCE joined Peabody's motion to strike the Navajo Nation's
complaint. In addition, SCE and the other defendants have filed motions to
dismiss.

The Navajo Nation had previously filed suit in the Court of Claims against the
United States Department of Interior, alleging that the Government had breached
its fiduciary duty concerning the above-referenced contract negotiations. On
February 4, 2000, the Court of Claims issued a decision in the Government's
favor, finding that while there had been a breach, there was no available
redress from the Government. In its decision, the Court indicated that it was
making no statements regarding, or findings in, the above federal civil court
action. That decision is on appeal. On February 28, 2000, the Hopi Tribe filed a
motion to intervene in the pending litigation, alleging that the royalty
payments set for their interest in the coal leases with Peabody had been
impacted by the events at issue in the Navajo case. The defendants filed an
opposition to the motion, and the Court calendared all pending motions for
hearing on March 15, 2001.

On March 15, 2001, the District Court heard arguments, granted the Hopi Tribe's
motion to intervene and denied Peabody and SCE's motions to dismiss. The parties
are preparing a discovery plan and the Court set a scheduling conference for
June 15, 2001.

Shareholder Litigation

These purported class actions both involve securities fraud claims arising from
alleged improper accounting by Edison International and SCE of undercollections
in SCE's TRA.

On October 30, 2000, a purported class action lawsuit (the "Stubblefield
Action") was filed in federal district court in Los Angeles against SCE and
Edison International. On December 28, 2000, plaintiffs, without requiring a
response to the original complaint, filed a first amended complaint. In February
2001, the Court approved a stipulation of the parties providing that, in lieu of
a motion to dismiss directed to the first amended complaint, plaintiffs would
voluntarily file a second amended complaint. Pursuant to this stipulation, on
March 5, 2001, plaintiffs filed a second amended complaint. The second amended
complaint alleges that the

46

companies are engaging in securities fraud by over-reporting income and
improperly accounting for the TRA undercollections. The second amended complaint
purports 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 are recorded as a loss on SCE's income
statements. The second amended complaint seeks compensatory damages caused by
the alleged fraud as well as punitive damages. The response to the second
amended complaint was due April 2, 2001. As discussed below, plaintiff's counsel
has agreed with counsel for Edison International and SCE that the date for
Edison International and SCE to respond to the second amended complaint may be
deferred.

On March 15, 2001, a purported class action lawsuit (the "King Action") was
filed in federal district court in Los Angeles, California, against Edison
International and SCE and certain of their officers. The complaint alleges 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
purports to be filed on behalf of a class of persons who purchased all
publicly-traded securities of Edison International between May 12, 2000, and
December 22, 2000. Plaintiffs seek damages, in an unstated amount, in connection
with their purchase of securities during the class period.

Plaintiffs in the King Action have filed motions to consolidate this action with
the Stubblefield Action, to have the named plaintiffs in both cases be appointed
"lead plaintiffs' in the consolidated matter and for leave to file a
consolidated complaint. Plaintiffs' and defendants' counsel in the King and
Stubblefield Actions have agreed, subject to the approval of the Court, that
defendants' time for responding to the Stubblefield and King Action complaints
may be deferred pending resolution of motions for consolidation and to appoint
lead plaintiffs, and pending the filing of a consolidated complaint. The parties
have filed stipulations with the Court memorializing this agreement and seeking
the Court's approval.

Power Generator Litigation

SCE is involved in seventeen separate legal actions brought by various QFs
alleging SCE's failure to timely pay for power deliveries made beginning in
November 2000.

On February 9, 2001, SCE was served with a complaint that was filed against it,
Edison International and unnamed parties in the South (Long Beach) district of
the Los Angeles Superior Court. In this complaint, plaintiff City of Long Beach
alleges that SCE failed to pay the City's biomass project for power deliveries
made by the project in November and December 2000. The City states causes of
action for breach of contract, account stated and unjust enrichment and claims
damages in an amount not less than $4,933,489.78. The City also seeks an
accounting from SCE of the amounts due for power deliveries for November and
December 2000. On March 30, 2001, SCE responded to the complaint by asserting a
general denial and a number of affirmative defenses.

On February 20, 2001, eight geothermal generators that purport to be QFs and
which are each affiliated with CE Generation commenced an action against SCE and
unnamed additional defendants in the Imperial County Superior Court. In their
complaint, the generators allege that SCE has breached the power purchase
agreements applicable to the eight projects by failing to pay the projects for
energy and capacity delivered in November and December 2000. The generators
contend that their collective compensatory damages for these two months are in
the range of $45,000,000 and that they expect to be owed additional monies for
deliveries made in months following December 2000 for which payment is not
timely made by SCE. The generators also contend that SCE's alleged wrongful
failures to pay monies owed to the generators constitutes a willful violation of
one or more CPUC orders and/or other applicable laws, entitling them to
exemplary damages. The complaint also seeks a declaration from the Court that
SCE is obligated to make immediate payment for the November and December 2000
deliveries and that SCE is further obligated to reimburse the generators for all
incidental and other damages resulting from the alleged breaches of contract.
Finally, the generators seek declaratory and injunctive relief to restrain SCE
from preventing the generators from selling their energy and capacity to third
parties during such time as SCE remains noncurrent on its alleged payment
obligations.

47

On March 9, 2001, SCE filed an answer denying the material allegations of the
complaint and raising a number of affirmative defenses, including, among others,
that the Court lacks subject matter jurisdiction over the lawsuit because the
formula for determining the energy price to be paid to at least seven of the
eight projects for the months in question is the subject of a proceeding before
the CPUC, and, accordingly, SCE contends that the CPUC has exclusive
jurisdiction over the lawsuit. In addition, SCE contends that the generators are
barred from recovering the monies owed because of their own "unclean hands,"
arising from alleged unlawful price manipulation in the natural gas market by an
affiliate of the generators, which manipulation allegedly caused the price of
electricity to be improperly inflated. Furthermore, SCE filed a cross-complaint
alleging that four of the affected projects have operated in a manner contrary
to the terms of their contracts, by not having "stand alone" facilities for
processing geothermal brine (the resource powering the projects' generators) and
by wrongfully diverting electricity between the projects instead of delivering
that electricity directly to SCE. SCE alleges that it has sustained damages as a
result of these breaches of contract in an as-yet undetermined amount.

The generators obtained Court orders permitting them to file and to have heard
on an expedited basis motions for summary adjudication with respect to several
of the causes of action of their complaint. As a result of the first of such
motions, which was heard on March 22, 2001, the generators obtained an order
permitting them to sell energy and capacity to third parties during such time as
SCE remains noncurrent on its alleged payment obligations, and providing that
any such interim suspension of deliveries by the generators to SCE and resale to
third parties will not result in the termination or modification of the
generators' contracts with SCE. SCE has requested in a motion set for hearing on
April 16, 2001, that the order be lifted in light of the CPUC's March 27, 2001,
decision requiring SCE to resume payments to QFs. The second of the motions,
which was scheduled for hearing on April 2, 2001, seeks summary adjudication of
the generators' claims that SCE has breached each of the eight contracts by
failing to make payment for deliveries over the period from November 1, 2000, to
and including February 28, 2001, that SCE owes approximately $101 million for
such deliveries, and that the generators are entitled to recover all incidental
and other damages for the suspended deliveries and any future deliveries for
which payment is not paid and that the generators have the right to file and
prosecute additional breach of contract actions in response to any SCE
nonpayment for future deliveries. SCE filed opposition to this motion on March
23, 2001, contending, among other things, that SCE has defenses and/or
affirmative claims which constitute offsets to the generators' nonpayment
claims, including the defenses and cross-claims noted above. The hearing has
been continued to April 16, 2001, due to SCE's intention to seek coordination of
this case with other actions that QFs have commenced in various California
courts on the payment issue.

On March 2, 2001, SCE was served with a lawsuit filed against it in the United
States District Court, District of Nevada, by two related plaintiffs (Beowawe
Power, L.L.C. and Caithness Dixie Valley L.L.C.) that hold interests in two
power purchase contracts with SCE. The plaintiffs, each of which purports to be
a QF as defined under federal law, operate a geothermal generating facility in
Nevada. The complaint seeks damages in excess of $20,000,000, based upon SCE's
failure to make timely payment for energy deliveries made beginning in November
2000. Plaintiffs are also seeking a prejudgment attachment of SCE's undivided
56% interest in the Mohave generating facility, a coal-fired plant located in
Nevada. A hearing on an order to show cause why the attachment should not issue
took place on March 12, 2001. On March 14, 2001, the Court issued an order
granting the requested attachment subject to the plaintiffs posting required
security. On March 23, 2001, plaintiffs served an amended complaint which
repeats the allegations of the original complaint and which adds three new
claims for declaratory relief. Specifically, the amended complaint asks the
Court to declare: (1) that SCE is obligated to make immediate payments to
plaintiffs for deliveries in November and December 2000 and January 2001; (2)
that plaintiffs may sell the output of their projects to third parties while SCE
is not paying for deliveries; and (3) that plaintiffs are entitled to incidental
damages, as well as compensatory damages, arising out of SCE's alleged breach.
SCE has not yet responded to the amended complaint. Plaintiffs have also filed a
summary judgment motion. On April 11, 2001, SCE filed its opposition to
plaintiffs' motion. No hearing date has been set. SCE has requested oral
argument, but the request has not been granted.

48

On March 5, 2001, SCE was served with a lawsuit filed against it in Los Angeles
Superior Court by seven related plaintiffs that collectively hold interests in
twelve power purchase contracts with SCE. The plaintiffs each purport to be a QF
as defined under federal law. The complaint seeks "several million dollars" in
damages for breach of each of the twelve contracts based on SCE's alleged
failure to make timely payment for energy deliveries made beginning November
2000. It also seeks a declaration that SCE is obligated to pay for past and
future power deliveries under these contracts, including payments of several
million dollars for deliveries in November and December 2000 and January 2001.
Concurrently with serving their complaint, the plaintiffs also served
applications for writs of attachment against SCE's property within the State of
California. On March 28, 2001, the Court denied the applications. On April 4,
2001, SCE responded to the complaint by asserting a general denial and a number
of affirmative defenses.

On March 28, 2001, SCE was served with a complaint filed against it in the San
Bernardino Superior Court (Barstow District) by IMC Chemicals Inc., a QF
cogeneration project located in Trona, California. The complaint alleges that
SCE failed to pay plaintiff for power deliveries under the contract from
November 2000 through February 2001 and seeks damages of at least $2.8 million
for such alleged failure under four different causes of action: breach of the
power purchase contract between plaintiff and SCE, breach of the covenant of
good faith and fair dealing and two common counts (quantum meruit and quantum
valebant). The complaint also seeks declarations that: (1) SCE is obligated to
pay plaintiff all amounts owed for power deliveries under the contract; and (2)
plaintiff is entitled to suspend power deliveries and resell such power to third
parties so long as SCE is unable or unwilling to pay for such deliveries and
that such suspension does not terminate or modify the contract. Finally, the
complaint requests an injunction that would restrain SCE from demanding further
deliveries of energy from plaintiff and prohibiting plaintiff from selling power
to third parties. SCE has not yet responded to this complaint.

On March 28, 2001, SCE was served with a complaint filed in the Los Angeles
Superior Court by NP Cogen, a QF with which SCE has a power purchase contract.
The complaint alleges that SCE has failed to pay NP Cogen for power deliveries
made under the contract in November and December 2000 and January and February
2001 and, based on this alleged failure to pay, seeks damages for breach of
contract, breach of the covenant of good faith and fair dealing; quantum
valebant, open book account, under California Commercial Code section 2709,
indebitatus assumpsit and unjust enrichment. Although the prayer does not
specify the amount of damages sought, several of these causes of action allege
that the amount presently owing is approximately $8,000,000. The complaint also
seeks a declaration that SCE has effectively repudiated the contract and NP
Cogen is therefore excused from further performance thereunder. SCE has not yet
responded to this complaint.

On April 2, 2001, SCE was served with a complaint filed in Los Angeles County
superior court by Watson Cogeneration Company, a QF. In its complaint, Watson
alleges that SCE has failed to pay Watson for power deliveries between November
2000 and February 2001 under a power purchase contract between SCE and Watson.
Watson seeks at least $150,000,000 for the alleged failure to pay pursuant to
causes of action including breach of contract, breach of the implied covenant of
good faith and fair dealing and common counts (quantum meruit and quantum
valebant). In addition, Watson seeks declarations that (1) SCE must immediately
pay Watson all amounts due for power deliveries under the contract for each
month since November 2000; (2) Watson is entitled to suspend power deliveries
and resell such power to third parties so long as SCE does not pay for such
deliveries and that such suspension does not terminate or modify the contract;
and (3) Watson is entitled to recover all commercially reasonable costs incurred
in reselling power to third parties. Watson also seeks an injunction that
prohibits SCE from requiring Watson to continue power deliveries under the
contract; from interfering with Watson's right to suspend such deliveries and
resell such power to third parties; and from hindering Watson's use of
interconnection facilities and related services. Moreover, under Public
Utilities Code section 2106 Watson seeks exemplary damages and an injunction
that would restrain SCE and its parents and affiliates from converting to its
own use, and failing to pay Watson for power delivered from, amounts collected
from ratepayers. Finally, under California Business and Profession Code section
17200 et seq., Watson seeks an order that it is entitled to an injunction that
would prohibit SCE from continuing the unfair business

49

practices of unfairly interfering with the operating and continued success of
Watson's generating facility. Watson also claims attorneys' fees and costs under
this cause of action. SCE has not yet responded to this complaint.

On April 3, 2001, SCE was served with a lawsuit filed against it in the Los
Angeles County Superior Court by four plaintiffs, O.L.S. Energy - Chino, O.L.S.
Energy - Camarillo, Carson Cogeneration Company and Mojave Cogeneration Company,
L.P. Each plaintiff is a QF that holds a power purchase contract with SCE. The
complaint alleges that SCE has failed to pay for power deliveries under each of
the four contracts in November and December 2000 and January and February 2001.
The complaint seeks damages of at least $42,324,539.08 for breach of the four
contracts ($8,863,888.52 for the Chino contract; $9,770,153.86 for the Camarillo
contract; $12,465,578.58 for the Carson contract; and $11,216,918.12 for the
Mojave contract) and under common counts for quantum meruit and quantum
valebant. The complaint also seeks declarations that (1) SCE is obligated to pay
each plaintiff for power delivered from November 2000 through February 2001; (2)
plaintiffs are entitled to suspend power deliveries to SCE and sell to third
parties so long as SCE is unable or unwilling to pay for such deliveries and
this suspension shall not modify or terminate the contracts; (3) plaintiffs are
entitled to terminate the contracts; (4) plaintiffs are entitled to all
incidental and other damages incurred in suspending their power deliveries and
selling to third parties; and (5) plaintiffs have independently negotiated
contracts with SCE that are not subject to CPUC decision 01-03-067. Finally,
plaintiffs seek an injunction that would restrain SCE from demanding further
power deliveries and refusing to permit plaintiffs to sell to third parties.

On April 3, 2001, SCE was served with a complaint filed in the Ventura County
Superior Court by E.F. Oxnard, a QF with which SCE has a power purchase
contract. The complaint alleges that SCE has failed to pay Oxnard for deliveries
under the contract in November and December 2000 and January and February 2001.
It seeks unspecified damages for breach of contract, anticipatory breach of
contract and breach of the implied covenant of good faith and fair dealing and
damages of $13,561,773 for common counts (open book account, quantum meruit and
quantum valebant), all arising from the alleged nonpayment. SCE has not yet
responded to this complaint.

On April 5, 2001, Brea Power Partners, L.P. filed a complaint in the Los Angeles
County Superior Court against Southern California Edison Company. Brea Power
Partners L.P. is a QF that has a power purchase contract with SCE. The complaint
alleges that SCE has made reduced payments for power delivered under the
contract from June 2000 through October 2000 and has failed to make any payments
for power delivered under the contract from November 2000 through March 2001.
Based on these allegations, the complaint seeks damages under causes of action
for breach of contract ($1.65 million), anticipatory breach of contract and
breach of the covenant of good faith and fair dealing (each, $12 million). The
complaint also seeks a declaration that SCE has breached the contract and is not
entitled to demand further performance thereunder and that plaintiff may sell
its power to third parties. Finally, the complaint seeks an injunction
restraining SCE from unlawful and unfair conduct described in the complaint,
which allegedly includes not paying plaintiff and refusing to permit sales to
third parties. SCE has not yet been officially served with or responded to this
complaint.

On April 5, 2001, SCE submitted to the Chairperson of the California Judicial
Counsel a petition requesting the coordination before a single judge of each of
the foregoing Power Generator cases except the Beowawe Power case (due to the
fact it is in Nevada) and the Brea Power Partners case (due to the fact that SCE
was at that time unaware of this case). The petition requests an immediate stay
of the actions identified in the petition while the coordination issue is being
decided. On April 9, 2001, SCE filed an amended petition for the purpose of
adding the Brea Power Partners case to the petition. SCE is seeking coordination
of all of the QF-related lawsuits that have commenced in various California
courts. On April 13, 2001, the Chair of the Judicial Council of California
issued an order assigning the Supervising Judge of the Los Angeles County
Complex Civil Case Litigation Program to sit as coordination motion judge to
determine whether the actions SCE sought to coordinate are complex, and if so,
whether coordination of the included actions is appropriate. The hearing on the
motion is set for May 30, 2001.

50

On April 9, 2001, Inland Paperboard and Packaging, Inc. (Inland), filed a
lawsuit in the United States District Court, Central District of California, Los
Angeles Division, against SCE and the California ISO. Plaintiff is a QF that
sells power to SCE under a power purchase contract. In its complaint, plaintiff
alleges that SCE materially breached the contract by failing to pay for power
deliveries thereunder, beginning with deliveries made in November 2000. The
complaint also seeks declarations that plaintiff has terminated the contract by
reason of SCE's alleged material breach of same but that the interconnection
agreement between SCE and plaintiff remains in full force and effect. The
complaint also alleges the SCE and the ISO violated 16 U.S.C. ss.824d(b), and
SCE violated California Business & Professions Code ss.16720 et seq and
interfered with prospective economic advantage by refusing to deliver power from
plaintiff's project to the California energy market. Finally, plaintiff also
alleges a quantum meruit cause of action against SCE for power deliveries after
plaintiff allegedly terminated the contract. (The complaint also seeks a
declaration that the ISO is obligated to provide plaintiff with access to the
California energy market.) In addition to the declarations described in this
paragraph, plaintiff prays for actual damages not less than $5,300,000,
restitution, lost profits and actual and treble damages under the California
Business and Professions Code.

Also on April 9, 2001, Inland filed an application for a temporary restraining
order and preliminary injunction that would prevent SCE and the ISO from
refusing to deliver plaintiff's power for sale into the California energy
market. SCE filed opposition to this application on April 10, 2001. The matter
is under submission before Judge Stephen Wilson.

On April 10, 2001, Mammoth Pacific L.P. (Mammoth) filed a lawsuit against SCE in
the Mono County Superior Court. Mammoth has an interest in three QF projects
that sell power to SCE under three power purchase contracts. Mammoth seeks
damages of at least $16,700,000 for SCE's alleged breach of the power purchase
contracts by failing to pay for power deliveries beginning with deliveries made
in November 2000, under causes of action for breach of contract, quantum meruit
and quantum valebant. The complaint also alleges causes of action for breach of
the implied covenant of good faith and fair dealing and unfair competition under
California Business & Professions Code ss.17203. Mammoth seeks a temporary
restraining order and a preliminary and permanent injunction to prevent SCE from
taking power from Mammoth's projects without paying for it and accepting payment
from customers for sales of power generated by Mammoth's projects without using
such funds for any purpose other than paying Mammoth. Finally, Mammoth seeks
declarations that SCE is obligated to perform under Mammoth's contracts by
paying Mammoth for power delivered since November 2000; that Mammoth is entitled
to suspend deliveries until 90 days after SCE has paid all amounts due under the
contracts and has also demonstrated its ability and willingness to continue to
pay; and that this suspension does not modify or amend the contracts . Mammoth
also seeks attorneys' fees. SCE has not yet responded to this complaint.

On April 10, 2001, Heber Geothermal Company (Heber) and Second Imperial
Geothermal Company (Second Imperial) filed a lawsuit against SCE in the Imperial
County Superior Court. Both Heber and Second Imperial are QFs that sell power to
SCE under power purchase contracts. Plaintiffs seek damages of at least
$35,600,000 for SCE's alleged breach of their power purchase contracts by
failing to pay for power deliveries beginning with deliveries made in November
2000, under causes of action for breach of contract, quantum meruit and quantum
valebant. The complaint also alleges causes of action for breach of the implied
covenant of good faith and fair dealing and unfair competition under California
Business & Professions Code ss.17203. Plaintiffs seeks a temporary restraining
order and a preliminary and permanent injunction to prevent SCE from taking
power from plaintiffs without paying for it and accepting payment from customers
for sales of power generated by plaintiffs without using such funds for any
purpose other than paying plaintiffs. Finally, plaintiffs seek declarations that
SCE is obligated to perform under plaintiffs' contracts by paying plaintiffs for
power delivered since November 2000; that plaintiffs are entitled to suspend
deliveries until 90 days after SCE has paid all amounts due under the contracts
and has also demonstrated its ability and willingness to continue to pay; and
that this suspension does not modify or amend the contracts . Plaintiffs also
seek attorneys' fees. SCE has not yet responded to this complaint.

51

On April 10, 2001, SCE was served with a complaint filed against it by Southern
California Sunbelt Developers Inc. in the Riverside County Superior Court, Indio
District. This complaint alleges three causes of action for breach of the power
purchase agreement between Sunbelt and SCE. In the first cause of action,
Sunbelt alleges that SCE breached the contract by failing to pay for power
deliveries made in November 2000; in the second cause of action, Sunbelt alleges
that SCE breached the contract by failing to pay for power deliveries made in
December 2000; and in the third cause of action, Sunbelt alleges that SCE
breached the contract by failing to pay for power deliveries made in January
2001. Sunbelt prays for damages of at least $158,781.51. SCE has not yet
responded to this complaint.

On April 11, 2001, Corona Energy Partners, Ltd. served SCE with a complaint
filed against SCE in Riverside County Superior Court. Corona is a QF that holds
a power purchase contract with SCE. The complaint alleges that SCE breached the
contract by failing to pay for power deliveries from November 2000 through
February 2001. Based on this alleged failure, Corona states causes of action for
breach of contract, breach of the implied covenant of good faith and fair
dealing, quantum meruit, quantum valebant and action for the price, and seeks
damages of at least $13,361,096 thereunder. Under the breach of contract cause
of action, Corona also alleged entitlement to unspecified amounts allegedly
recoverable under Uniform Commercial Code sections 2701, 2702, 2703, 2706, 2709
and 2710. Corona also seeks declarations that it need not resume deliveries to
SCE until SCE pays all amounts due and "demonstrates an unequivocal commitment
and ability to pay for deliveries going forward," that Corona is entitled to
resell its energy to other purchasers during this time, and SCE cannot interfere
with such sales; and the suspension and reselling shall not modify or amend the
contract. Finally, Corona seeks an injunction that would restrain SCE from
requiring Corona to deliver to SCE while SCE is still allegedly in default of
the contract; from interfering with Corona's alleged right to resell its energy
to third parties; and from refusing to pay Corona while allegedly collecting
billions of dollars from ratepayers. SCE has not yet responded to this
complaint.

On April 11, 2001, SCE was served with a complaint filed against it by Kern
River Cogeneration Company ("KRCC") and Sycamore Cogeneration Company
("Sycamore") in the Kern County Superior Court. Each plaintiff is a QF that
holds a power purchase contract with SCE. Each plaintiff is also an affiliate of
SCE. In the complaint, each plaintiff alleges a cause of action against SCE for
breach of contract, arising from SCE's alleged failure to pay for energy
deliveries from November 2000 through March 2001 (the latter month is on
information and belief, since the March payment is not yet due). KRCC seeks at
least $112,033,000 in damages for the alleged breach, and Sycamore seeks at
least $120,407,000. Plaintiffs jointly allege a cause of action for breach of
the implied covenant of good faith and fair dealing, and seek compensatory and
exemplary damages therefor. Plaintiffs additionally allege violations of CPUC
Code section 2106 and unfair business practices for allegedly failing to pay
plaintiffs for power deliveries when SCE allegedly received tens of millions of
dollars from ratepayers and seek an injunction enjoining this alleged behavior
under both causes of action and reasonably attorneys fees under the unfair
business practices cause of action. Finally, plaintiffs seek a declaration that
each of them is entitled to suspend power deliveries until SCE makes cash
payments for all past due amounts and demonstrates that it is solvent,
creditworthy and able to make payments when due on an ongoing basis; that each
plaintiff is entitled to resell its power without hindrance from SCE; that SCE
is required to provide each plaintiff with interconnection service without
charge during the suspension; and that the suspension does not breach, modify or
terminate the contracts. These plaintiffs have also brought a motion for summary
adjudication of the cause of action for declaratory relief. It is scheduled for
hearing on May 2, 2001. SCE's opposition papers are due on April 24, 2001.

On April 12, 2001, the Proctor & Gamble Paper Products Company filed a lawsuit
against SCE in the Ventura County Superior Court. Plaintiff is a QF that holds a
power purchase contract with SCE. In its complaint, plaintiff alleges causes of
action for breach of contract, quantum meruit and quantum valebant, arising from
SCE's alleged failure to pay for power deliveries made from November 2000
through February 2001. Plaintiff seeks at least $19,770,202.97 in damages under
these causes of action. Plaintiff also seeks declarations that SCE must
immediately pay all sums allegedly owed for power deliveries; that SCE has
materially breached the contract; that plaintiff is entitled to suspend
deliveries under the contract and may use its present interconnection to SCE's
system, without charge, to sell power to solvent third

52

parties; that plaintiff is entitled to terminate the contract upon giving notice
of same; and that plaintiff is entitled to damages equal to the commercially
reasonable amount of suspending deliveries and reselling its power and that such
suspension and resale does not modify or terminate the contract. Finally,
plaintiff seeks an injunction that would restrain SCE from demanding further
deliveries of energy and capacity and preventing plaintiff from selling to third
parties. SCE has not yet responded to this complaint.

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, SCE has agreed to deposit $20,000,000, plus
a reasonable amount for interest and expenses, in an account in trust to be
available to satisfy any judgment, should there be one, against American Home
under the pool performance bond.

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.

53

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, 2000 Company Position
- -------------------------- -------------------------- -------------------------------------------------------

John E. Bryson 57 Chairman of the Board, President, Chief Executive
Officer and Director

Bryant C. Danner 63 Executive Vice President and General Counsel

Theodore F. Craver, Jr. 49 Senior Vice President, Chief Financial Officer and
Treasurer

Robert G. Foster 53 Senior Vice President, Public Affairs

Mahvash Yazdi 49 Senior Vice President and Chief Information Officer

Thomas M. Noonan 49 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, Edison Capital, and Edison Enterprises, all of whom
may be deemed significant policy makers of Edison International. None of
Edison International's elected executive officers are related to each other
by blood or marriage.

54

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. Each of the
above officers of Edison International has been actively engaged in the
business of Edison International and/or SCE for more than five years except
Theodore F. Craver, Jr., and Mahvash Yazdi. Those officers who have not
held their present position with Edison International and/or SCE 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, Chief Executive Officer, October 1990 to December 1999
and Director, Edison 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

Theodore F. Craver, Jr. Senior Vice President, Chief Financial Officer January 2000 to present
and Treasurer, Edison International
Senior Vice President and Treasurer, Edison February 1998 to January 2000
International
Chairman of the Board and Chief Executive September 1999 to present
Officer, Edison Enterprises
Senior Vice President and Treasurer, SCE February 1998 to September 1999
Vice President and Treasurer, Edison September 1996 to February 1998
International and SCE
Executive Vice President and Corporate September 1990 to April 1996
Treasurer, First Interstate Bancorp(1)

Robert G. Foster Senior Vice President, Public Affairs, Edison November 1996 to present
International and SCE
Vice President, Public Affairs, Edison January 1996 to October 1996
International
Vice President, Public Affairs, SCE November 1993 to October 1996

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

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)
- ------------------------------- ------------------------------------------------- ------------------------------------

(1) This entity is not a parent, subsidiary or other affiliate of SCE.

55

- --------------------------------------------------------------------------------------------------------------------
Southern California Edison Company
- --------------------------------- ---------------------------- ----------------------------------------------------
Age at
Executive Officer December 31, 2000 Company Position
- ---------------------------------- ---------------------------- ----------------------------------------------------

Stephen E. Frank 59 Chairman of the Board, President, Chief Executive
Officer and Director(1)

Harold B. Ray 60 Executive Vice President, Generation Business Unit

(1) Also a Director of Edison International from June 1995 to present.

As set forth in Article IV of SCE's Bylaws, the elected officers of SCE are
chosen annually by and serve at the pleasure of SCE's Board of Directors and
hold their respective offices until their resignation, removal, other
disqualification from service, or until their respective successors are elected.
All of the above officers have been actively engaged in the business of SCE for
more than five years. Those officers who have not held their present position
for the past five years had the following business experience:

Southern California Edison Company
- ------------------------------ ---------------------------------------------- --------------------------------------

Executive Officer Company Position Effective Dates
- ------------------------------ ---------------------------------------------- --------------------------------------

Stephen E. Frank Chairman of the Board, President, Chief January 2000 to present
Executive Officer and Director
President, Chief Operating Officer and June 1995 to December 1999
Director
- ------------------------------ ---------------------------------------------- --------------------------------------

The Nonutility Companies
- ---------------------------------- ---------------------------- ----------------------------------------------------
Age at
Executive Officer December 31, 2000 Company Position
- ---------------------------------- ---------------------------- ----------------------------------------------------

Alan J. Fohrer 50 President and Chief Executive Officer,
Edison Mission Energy

Thomas R. McDaniel 51 President and Chief Executive Officer,
Edison Capital

Theodore F. Craver, Jr.(1) 49 Chairman of the Board and Chief Executive Officer,
Edison Enterprises
- ---------------------------------- ---------------------------- ----------------------------------------------------

(1) Mr. Craver is also deemed an executive officer due to his positions at
Edison International. Information concerning their ages, Company position,
and business experience is set forth under Edison International. Edison
International is the parent holding company of the Nonutility Companies.

56

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 have been actively
engaged in the business of the respective Nonutility Companies, Edison
International, and/or SCE for more than five years except for Theodore F.
Craver, Jr. Those officers who have not held their present position for the past
five years had the following business experience:

The Nonutility Companies
- ----------------------------- ---------------------------------------------- ------------------------------------

Executive Officer Company Position Effective Dates
- ----------------------------- ---------------------------------------------- ------------------------------------

Alan J. Fohrer President and Chief Executive Officer, January 2000 to present
Edison Mission Energy
---------------------------------------------- ------------------------------------
Executive Vice President and Chief Financial September 1996 to January 2000
Officer, Edison International
---------------------------------------------- ------------------------------------
Chairman of the Board, Edison Enterprises January 1998 to September 1999
---------------------------------------------- ------------------------------------
Executive Vice President and Chief Financial September 1996 to December 1999
Officer, SCE
---------------------------------------------- ------------------------------------
Executive Vice President, Chief Financial February 1996 to August 1996
Officer and Treasurer, SCE
---------------------------------------------- ------------------------------------
Executive Vice President and Chief Financial May 1995 to January 1996
Officer, SCE
---------------------------------------------- ------------------------------------
Executive Vice President, Chief Financial May 1995 to August 1996
Officer and Treasurer, Edison 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, 2000, (Annual Report)
under Quarterly Financial Data on page 89 and under Shareholder Information on
page 93, and is incorporated by reference pursuant to General Instruction G(2).
The number of Common Stock shareholders of record was 80,070 on March 23, 2001.
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 - 2000 on page 90, 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 3 through 38 and is incorporated
herein by reference pursuant to General Instruction G(2).

57

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 18 through 23 incorporated herein by reference to General
Instruction G(2), and in Part I, Item 1 of this report on page 21 under Market
Risk Exposures.

Item 8. Financial Statements and Supplementary Data

Certain information responding to Item 8 is set forth after Item 14 in Part IV.
Other information responding to Item 8 is included in the Annual Report on pages
41 through 88 and is incorporated herein by reference pursuant to General
Instruction G(2).

Item 9. Changes in and Disagreements with Accountants on Accounting and
Financial Disclosure

None.

PART III

Item 10. Directors and Executive Officers of the Registrant

Information concerning executive officers of 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 Meeting to be held on May 14, 2001, under the heading
Election of Directors and Section 16(a) Beneficial Ownership Reporting
Compliance, and is incorporated herein by reference pursuant to General
Instruction G(3).

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, Option/SAR
Grants in 2000, Aggregated Option/SAR Exercises in 2000 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, and Compensation and Executive Personnel Committees' Interlocks
and Insider Participation, and is incorporated herein by reference pursuant to
General Instruction G(3).

Item 12. Security Ownership of Certain Beneficial Owners and Management

Information responding to Item 12 will be incorporated by reference from 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 Officers and Other
Management Transactions, and is incorporated herein by reference pursuant to
General Instruction G(3).

58

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 3 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, 2000,
1999, and 1998
Consolidated Statements of Comprehensive Income - Years Ended December 31, 2000,
1999, and 1998
Consolidated Balance Sheets - December 31, 2000, and 1999
Consolidated Statements of Cash Flows - Years Ended December 31, 2000, 1999,
and 1998
Consolidated Statements of Changes in Shareholders' Equity - Years Ended
December 31, 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 60
Schedule I - Condensed Financial Information of Parent 61
Schedule II - Valuation and Qualifying Accounts for the
Years Ended December 31, 2000, 1999 and 1998 64

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 68 of this report.

The Company will furnish a copy of any exhibit listed in the
accompanying Exhibit Index upon written request and upon payment to the Company
of its reasonable expenses of furnishing such exhibit, which shall be limited to
photocopying charges and, if mailed to the requesting party, the cost of
first-class postage.

(b) Reports on Form 8-K

October 17, 2000 TRA Undercollections
November 3, 2000 $350M Floating Rate Notes
December 22, 2000 TRA Undercollections and Other Events

59

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 2000 Annual
Report to Shareholders of Edison International incorporated by reference in this
Form 10-K, and have issued our report thereon dated April 12, 2001. 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
April 12, 2001

60

Edison International

SCHEDULE I - CONDENSED FINANCIAL INFORMATION OF PARENT

CONDENSED BALANCE SHEETS

December 31,
- ------------------------------------------------------------------------------------------------
2000 1999
- ------------------------------------------------------------------------------------------------
(In thousands)
Assets:

Cash and equivalents $ 255,323 $ 5,562
Other current assets 112,396 109,139
- ------------------------------------------------------------------------------------------------

Total current assets 367,719 114,701

Investments in subsidiaries 5,104,107 7,253,922
Other deferred debits 5,333 5,053
- ------------------------------------------------------------------------------------------------

Total assets $ 5,477,159 $ 7,373,676
- ------------------------------------------------------------------------------------------------

Liabilities and Shareholders' Equity:
Accounts payable $ 2,183 $ 1,849
Other current liabilities 1,278,265 606,036
- ------------------------------------------------------------------------------------------------

Total current liabilities 1,280,448 607,885

Long-term debt 745,702 744,556
Other long-term liabilities 866,285 850,519
Other deferred credits 25,060 1,616
Common shareholders' equity 2,559,664 5,169,103
- ------------------------------------------------------------------------------------------------

Total liabilities and shareholders' equity $ 5,477,159 $ 7,373,676
- ------------------------------------------------------------------------------------------------

61

Edison International

SCHEDULE I - CONDENSED FINANCIAL INFORMATION OF PARENT

CONDENSED STATEMENTS OF INCOME
For the Years Ended December 31, 2000, 1999, and 1998

2000 1999 1998
- -------------------------------------------------------------------------------------------------------------
(In thousands, except per-share amounts)

Operating revenue and other income $ 107,573 $ 73,892 $ 52,784
Operating expenses and interest expense 243,872 114,447 67,907
- ---------------------------------------------------------------------------------------------------------

Loss before equity in earnings of subsidiaries (136,299) (40,555) (15,123)

Equity in earnings of subsidiaries (1,806,498) 663,585 683,286
- ---------------------------------------------------------------------------------------------------------

Net income (Loss) $ (1,942,797) $ 623,030 $ 668,163
- ---------------------------------------------------------------------------------------------------------

Weighted-average shares of common stock outstanding 332,560 347,551 359,205
Basic earnings per share $ (5.84) $ 1.79 $ 1.86
Diluted earnings per share $ (5.84) $ 1.79 $ 1.84

62

Edison International

SCHEDULE I - CONDENSED FINANCIAL INFORMATION OF PARENT

CONDENSED STATEMENTS OF CASH FLOWS
For the Years Ended December 31, 2000, 1999, and 1998

2000 1999 1998
- -------------------------------------------------------------------------------------------------------------
(In thousands)

Cash Flows From Operating Activities $ (217,134) $ 137,336 $ (131,187)
- ---------------------------------------------------------------------------------------------------------

Cash Flows From Financing Activities 468,246 (113,581) (125,298)
- ---------------------------------------------------------------------------------------------------------

Cash Flows From Investing Activities (1,351) (25,294) (10,017)
- ---------------------------------------------------------------------------------------------------------

Increase (Decrease) in cash and equivalents 249,761 (1,539) (266,502)
Cash and equivalents at beginning of period 5,562 7,101 273,603
- ---------------------------------------------------------------------------------------------------------

Cash and Equivalents at the End of Period $ 255,323 $ 5,562 $ 7,101
- ---------------------------------------------------------------------------------------------------------

Cash dividends received from Southern California
Edison Company $ 372,268 $ 663,282 $1,103,574

63

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 232,901 44,244 24,101(e) 4,968(f) 296,278
Maintenance accrual 25,664 25,664(g) --
Insurance, casualty and
other 76,124 42,749 -- 47,571(h) 71,302
- ----------------------------------------------------------------------------------------------------------

Total $ 932,738 $ 104,181 $ 23,882 $ 197,069 $ 863,732
- ----------------------------------------------------------------------------------------------------------

(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.

64

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 48,894 21,674(e) 77,335(f) 232,901
Maintenance accrual 26,053 37,673 54 38,116 25,664
Insurance, casualty and other 80,493 37,674 -- 42,043(g) 76,124
- -----------------------------------------------------------------------------------------------------------------

Total $ 515,330 $ 590,284 $ 21,594 $ 194,470 $ 932,738
- -----------------------------------------------------------------------------------------------------------------

(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.

65

Edison International

SCHEDULE II - VALUATION AND QUALIFYING ACCOUNTS

For the Year Ended December 31, 1998

Additions
----------------------------
Balance at Charged to Charged to Balance
Beginning of Costs and Other at End
Description Period Expenses Accounts Deductions of Period
- -------------------------------------------------------------------------------------------------------------------

(In thousands)
Group A:
Uncollectible accounts

Customers $ 24,525 $ 21,570 $ -- $ 24,457 $ 21,638
All other 48,098 2,273 -- 47,737 2,634
- -------------------------------------------------------------------------------------------------------------------

Total $ 72,623 $ 23,843 $ -- $ 72,194(a) $ 24,272
- -------------------------------------------------------------------------------------------------------------------

Group B:
DOE Decontamination
and Decommissioning $ 44,336 $ -- $ (89)(b) $ 4,828(c) $ 39,419
Purchased-power settlements 145,640 -- -- 15,943(d) 129,697
Pension and benefits 211,200 170,743 18,988(e) 161,263(f) 239,668
Maintenance accrual 21,209 10,663 263 6,082 26,053
Insurance, casualty and other 84,253 70,727 -- 74,487(g) 80,493
- -------------------------------------------------------------------------------------------------------------------

Total $ 506,638 $ 252,133 $ 19,162 $ 262,603 $ 515,330
- -------------------------------------------------------------------------------------------------------------------

(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.

66

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: April 17, 2001

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, April 17, 2001
Chief Executive Officer and Director

Principal Financial Officer:
Theodore F. Craver, Jr.* Senior Vice President, Treasurer and
Chief Financial Officer April 17, 2001

Controller or Principal Accounting Officer:
Thomas M. Noonan* Vice President and Controller April 17, 2001

Board of Directors:

Warren Christopher* Director April 17, 2001
Stephen E. Frank* Director April 17, 2001
Joan C. Hanley* Director April 17, 2001
Carl F. Huntsinger* Director April 17, 2001
Charles D. Miller* Director April 17, 2001
Luis G. Nogales* Director April 17, 2001
Ronald L. Olson* Director April 17, 2001
James M. Rosser* Director April 17, 2001
Robert H. Smith* Director April 17, 2001
Thomas C. Sutton* Director April 17, 2001
Daniel M. Tellep* Director April 17, 2001
Edward Zapanta* Director April 17, 2001

*By:

Kenneth S. Stewart
-----------------------------
Kenneth S. Stewart
Assistant General Counsel

67

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 February 15, 2001

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)*

Edison Mission Energy (EME)

4.18 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)*

4.19 Indenture dated as of November 30, 1994 (File No. 1-13434, Form 10-K for
the year ended December 31, 1994)*

4.20 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)*

68

EXHIBIT INDEX

Exhibit
Number Description

4.21 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)*

4.22 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 Form 10-K for the year ended December 31, 1981)*

10.2 1985 Deferred Compensation Agreement for Executives (File No. 1-2313, filed
as Exhibit 10.3 to Form 10-K for the year ended December 31, 1985)*

10.3 1985 Deferred Compensation Agreement for Directors (File No. 1-2313, filed
as Exhibit 10.4 to Form 10-K for the year ended December 31, 1986)*

10.4 Director Deferred Compensation Plan (File No. 1-9936, filed as Exhibit 10.3
to 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)*

10.11 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)*

69

EXHIBIT INDEX

Exhibit
Number Description

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 awards filed as Exhibit
10.21.1 to Form 10-K for the year ended December 31, 1995, for 1996 awards
filed as Exhibit 10.16.2 to Form 10-K for the year ended December 31, 1996,
for 1997 awards filed as Exhibit 10.16.3 to Form 10-K for the year ended
December 31, 1997, for 1998 awards filed as Exhibit 10.4 to Form 10-Q for
the quarter ended June 30, 1998, for 1999 awards filed as Exhibit 10.1 to
Form 10-Q for the quarter ended March 31, 1999, for January 2000 awards
filed as Exhibit 10.1 to Form 10-Q for the quarter ended March 31, 2000,
and for May 2000 awards filed as Exhibit 10.2 to Form 10-Q for the quarter
ended June 30, 2000)*

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

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

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

10.21 Form of Agreement for 2000 Director Awards under the Equity Compensation
Plan (File No. 1-9936, filed as Exhibit 10.3 to Form 10-Q for the quarter
ended June 30, 2000)*

10.22 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 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)*

10.25 Option Gain Deferral Plan as restated September 15, 2000

10.26 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)*

10.27 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)*

10.28 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)*

10.29 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)*

10.30 Memorandum of Understanding with Governor Davis's Transmittal Letter dated
April 9, 2001

11. Computation of Primary 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, 2000

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

* Incorporated by reference pursuant to Rule 12b-32.

Exhibit 3.3
To Holders of the Company's Bylaws:

Effective February 15, 2001, Article II, Section 2 was
amended to change the date of the 2001 annual
shareholders' meeting, and
Article III, Sections 6 and 7 were amended
to change the regular Board meeting schedule.

BEVERLY P. RYDER
Corporate Secretary

BYLAWS

OF

EDISON INTERNATIONAL

AS AMENDED TO AND INCLUDING

FEBRUARY 15, 2001

INDEX

Page
ARTICLE I - PRINCIPAL OFFICE
Section 1. Principal Office..............................................1

ARTICLE II - SHAREHOLDERS
Section 1. Meeting Locations.............................................1
Section 2. Annual Meetings...............................................1
Section 3. Special Meetings..............................................2
Section 4. Notice of Annual or Special Meeting...........................2
Section 5. Quorum........................................................4
Section 6. Adjourned Meeting and Notice Thereof..........................4
Section 7. Voting........................................................4
Section 8. Record Date...................................................6
Section 9. Consent of Absentees..........................................7
Section 10. Action Without Meeting........................................7
Section 11. Proxies.......................................................8
Section 12. Inspectors of Election........................................8

ARTICLE III - DIRECTORS
Section 1. Powers........................................................9
Section 2. Number of Directors...........................................9
Section 3. Election and Term of Office..................................10
Section 4. Vacancies....................................................10
Section 5. Place of Meeting.............................................11
Section 6. Organization Meeting.........................................11
Section 7. Special Meetings and Other Regular Meetings..................11
Section 8. Quorum.......................................................12
Section 9. Participation in Meetings by Conference Telephone............12
Section 10. Waiver of Notice.............................................12
Section 11. Adjournment..................................................12

Section 12. Fees and Compensation........................................13
Section 13. Action Without Meeting.......................................13
Section 14. Rights of Inspection.........................................13
Section 15. Committees...................................................13

ARTICLE IV - OFFICERS
Section 1. Officers.....................................................14
Section 2. Election.....................................................14
Section 3. Eligibility of Chairman or President.........................15
Section 5. Appointment of Other Officers................................15
Section 6. Vacancies....................................................15
Section 7. Salaries.....................................................15
Section 8. Furnish Security for Faithfulness............................16
Section 9. Chairman's Duties; Succession to
Such Duties in Chairman's Absence or Disability...........16
Section 10. President's Duties...........................................16
Section 11. Chief Financial Officer......................................16
Section 12. Vice Presidents' Duties......................................17
Section 13. General Counsel's Duties.....................................17
Section 14. Associate General Counsel's and Assistant General
Counsel's Duties.........................................17
Section 15. Controller's Duties..........................................17
Section 16. Assistant Controllers' Duties................................17
Section 17. Treasurer's Duties...........................................17
Section 18. Assistant Treasurers' Duties.................................18
Section 19. Secretary's Duties...........................................18
Section 20. Assistant Secretaries' Duties................................19
Section 21. Secretary Pro Tempore........................................19
Section 22. Election of Acting Treasurer or Acting Secretary.............19
Section 23. Performance of Duties........................................19

ARTICLE V - OTHER PROVISIONS
Section 1. Inspection of Corporate Records..............................20
Section 2. Inspection of Bylaws.........................................21
Section 3. Contracts and Other Instruments, Loans, Notes
and Deposits of Funds....................................21
Section 4. Certificates of Stock........................................22
Section 5. Transfer Agent, Transfer Clerk and Registrar.................22
Section 6. Representation of Shares of Other Corporations...............22
Section 7. Stock Purchase Plans.........................................23
Section 8. Fiscal Year and Subdivisions.................................23
Section 9. Construction and Definitions.................................23

ARTICLE VI - INDEMNIFICATION
Section 1. Indemnification of Directors and Officers....................24
Section 2. Indemnification of Employees and Agents......................25
Section 3. Right of Directors and Officers to Bring Suit................26
Section 4. Successful Defense...........................................26
Section 5. Non-Exclusivity of Rights....................................26
Section 6. Insurance....................................................26
Section 7. Expenses as a Witness........................................27
Section 8. Indemnity Agreements.........................................27
Section 9. Separability.................................................27
Section 10. Effect of Repeal or Modification.............................27

ARTICLE VII - EMERGENCY PROVISIONS
Section 1. General......................................................27
Section 2. Unavailable Directors........................................28
Section 3. Authorized Number of Directors...............................28
Section 4. Quorum.......................................................28
Section 5. Creation of Emergency Committee..............................28
Section 6. Constitution of Emergency Committee..........................29

Section 7. Powers of Emergency Committee................................29
Section 8. Directors Becoming Available.................................29
Section 9. Election of Board of Directors...............................29
Section 10. Termination of Emergency Committee...........................30

ARTICLE VIII - AMENDMENTS
Section 1. Amendments...................................................30

BYLAWS

Bylaws for the regulation, except as otherwise provided
by statute or its Articles of Incorporation

of

EDISON INTERNATIONAL

AS AMENDED TO AND INCLUDING
FEBRUARY 15, 2001

ARTICLE I - PRINCIPAL OFFICE

Section 1. Principal Office.

The principal office of the Corporation is hereby fixed and located at 2244
Walnut Grove Avenue, in the City of Rosemead, County of Los Angeles, State of
California. The Board of Directors is hereby granted full power and authority to
change said principal office from one location to another.

ARTICLE II - SHAREHOLDERS

Section 1. Meeting Locations.

All meetings of shareholders shall be held at the principal office of the
corporation or at such other place or places within or without the State of
California as may be designated by the Board of Directors (the "Board"). In the
event such places shall prove inadequate in capacity for any meeting of
shareholders, an adjournment may be taken to and the meeting held at such other
place of adequate capacity as may be designated by the officer of the
corporation presiding at such meeting.

Section 2. Annual Meetings.

The 2001 annual meeting of shareholders shall be held on May 14, 2001, and
all annual meetings of shareholders thereafter shall be held on the third
Thursday of the month of April of each year at such time as the Chairman of the
Board shall designate on said day to elect directors to hold office for the year
next ensuing and until their successors shall be elected, and to consider and
act upon such other matters as may lawfully be presented to such meeting;
provided, however, that should said day fall upon a legal holiday, then any such
annual meeting of shareholders shall be held at such designated time and place
on the next day thereafter ensuing which is not a legal holiday.

1

ARTICLE II

Section 3. Special Meetings.

Special meetings of the shareholders may be called at any time by the
Board, the Chairman of the Board, the President, or upon written request of any
three members of the Board, or by the holders of shares entitled to cast not
less than ten percent of the votes at such meeting. Upon request in writing to
the Chairman of the Board, the President, any Vice President or the Secretary by
any person (other than the Board) entitled to call a special meeting of
shareholders, the officer forthwith shall cause notice to be given to the
shareholders entitled to vote that a meeting will be held at a time requested by
the person or persons calling the meeting, not less than thirty-five nor more
than sixty days after the receipt of the request. If the notice is not given
within twenty days after receipt of the request, the persons entitled to call
the meeting may give the notice.

Section 4. Notice of Annual or Special Meeting.

Written notice of each annual or special meeting of shareholders shall be
given not less than ten (or if sent by third-class mail, thirty) nor more than
sixty days before the date of the meeting to each shareholder entitled to vote
thereat. Such notice shall state the place, date, and hour of the meeting and
(i) in the case of a special meeting, the general nature of the business to be
transacted, and no other business may be transacted, or (ii) in the case of an
annual meeting, those matters which the Board, at the time of the mailing of the
notice, intends to present for action by the shareholders, but, subject to the
provisions of applicable law and these Bylaws, any proper matter may be
presented at an annual meeting for such action. The notice of any special or
annual meeting at which directors are to be elected shall include the names of
nominees intended at the time of the notice to be presented by the Board for
election. For any matter to be presented by a shareholder at an annual meeting
held after December 31, 1993, but on or before December 31, 1999, including the
nomination of any person (other than a person nominated by or at the direction
of the Board) for election to the Board, written notice must be received by the
Secretary of the corporation from the shareholder not less than sixty nor more
than one hundred twenty days prior to the date of the annual meeting specified
in these Bylaws and to which the shareholder's notice relates; provided however,
that in the event the annual meeting to which the shareholder's written notice
relates is to be held on a date which is more than thirty days earlier than the
date of the annual meeting specified in these Bylaws, the notice from a
shareholder must be received by the Secretary not later than the close of
business on the tenth day following the date on which public disclosure of the
date of the annual meeting was made or given to the shareholders. For any matter
to be presented by a shareholder at an annual meeting held after December 31,
1999, including the nomination of any person (other than a person nominated by
or at the direction of the Board) for election to the Board, written notice must
be received by the Secretary of the corporation from the shareholder not more
than one

2

hundred eighty days nor less than one hundred twenty days prior to the date
on which the proxy materials for the prior year's annual meeting were first
released to shareholders by the corporation; provided however, that in the event
the annual meeting to which the shareholder's written notice relates is to be
held on a date which is more than thirty days earlier or later than the date of
the annual meeting specified in these Bylaws, the notice from a shareholder must
be received by the Secretary not earlier than two hundred twenty days prior to
the date of the annual meeting to which the shareholder's notice relates nor
later than one hundred sixty days prior to the date of such annual meeting,
unless less than one hundred seventy days' prior public disclosure of the date
of the meeting is made by the earliest possible quarterly report on Form 10-Q,
or, if impracticable, any means reasonably calculated to inform shareholders
including without limitation a report on Form 8-K, a press release or
publication once in a newspaper of general circulation in the county in which
the principal office is located, in which event notice by the shareholder to be
timely must be received not later than the close of business on the tenth day
following the date of such public disclosure. The shareholder's notice to the
Secretary shall set forth (a) a brief description of each matter to be presented
at the annual meeting by the shareholder; (b) the name and address, as they
appear on the corporation's books, of the shareholder; (c) the class and number
of shares of the corporation which are beneficially owned by the shareholder;
and (d) any material interest of the shareholder in the matters to be presented.
Any shareholder who intends to nominate a candidate for election as a director
shall also set forth in such a notice (i) the name, age, business address and
residence address of each nominee that he or she intends to nominate at the
meeting, (ii) the principal occupation or employment of each nominee, (iii) the
class and number of shares of capital stock of the corporation beneficially
owned by each nominee, and (iv) any other information concerning the nominee
that would be required under the rules of the Securities and Exchange Commission
in a proxy statement soliciting proxies for the election of the nominee. The
notice shall also include a consent, signed by the shareholder's nominees, to
serve as a director of the corporation if elected. Notwithstanding anything in
these Bylaws to the contrary, and subject to the provisions of any applicable
law, no business shall be conducted at a special or annual meeting except in
accordance with the procedures set forth in this Section 4.

Notice of a shareholders' meeting shall be given either personally or by
first-class mail (or, if the outstanding shares of the corporation are held of
record by 500 or more persons on the record date for the meeting, by third-class
mail) or by other means of written communication, addressed to the shareholder
at the address of such shareholder appearing on the books of the corporation or
given by the shareholder to the corporation for the purpose of notice; or, if no
such address appears or is given, at the place where the principal office of the
corporation is located or by publication at least once in a newspaper of general
circulation in the county in which the principal office is located. Notice by
mail shall be deemed to have been given at the time a written notice is
deposited in

3

the United States mails, postage prepaid. Any other written notice shall be
deemed to have been given at the time it is personally delivered to the
recipient or is delivered to a common carrier for transmission, or actually
transmitted by the person giving the notice by electronic means, to the
recipient.

Section 5. Quorum.

A majority of the shares entitled to vote, represented in person or by
proxy, shall constitute a quorum at any meeting of shareholders. The affirmative
vote of a majority of the shares represented and voting at a duly held meeting
at which a quorum is present (which shares voting affirmatively also constitute
at least a majority of the required quorum) shall be the act of the
shareholders, unless the vote of a greater number or voting by classes is
required by law or the Articles; provided, however, that the shareholders
present at a duly called or held meeting at which a quorum is present may
continue to do business until adjournment, notwithstanding the withdrawal of
enough shareholders to have less than a quorum, if any action taken (other than
adjournment) is approved by at least a majority of the shares required to
constitute a quorum.

Section 6. Adjourned Meeting and Notice Thereof.

Any shareholders' meeting, whether or not a quorum is present, may be
adjourned from time to time by the vote of a majority of the shares, the holders
of which are either present in person or represented by proxy thereat, but in
the absence of a quorum (except as provided in Section 5 of this Article) no
other business may be transacted at such meeting.

It shall not be necessary to give any notice of the time and place of the
adjourned meeting or of the business to be transacted thereat, other than by
announcement at the meeting at which such adjournment is taken. At the adjourned
meeting, the corporation may transact any business which might have been
transacted at the original meeting. However, when any shareholders' meeting is
adjourned for more than forty-five days or, if after adjournment a new record
date is fixed for the adjourned meeting, notice of the adjourned meeting shall
be given as in the case of an original meeting.

Section 7. Voting.

The shareholders entitled to notice of any meeting or to vote at any such
meeting shall be only persons in whose name shares stand on the stock records of
the corporation on the record date determined in accordance with Section 8 of
this Article.

Voting shall in all cases be subject to the provisions of Chapter 7 of the
California General Corporation Law, and to the following provisions:

4

(a) Subject to clause (g), shares held by an administrator, executor,
guardian, conservator or custodian may be voted by such holder either in person
or by proxy, without a transfer of such shares into the holder's name; and
shares standing in the name of a trustee may be voted by the trustee, either in
person or by proxy, but no trustee shall be entitled to vote shares held by such
trustee without a transfer of such shares into the trustee's name.

(b) Shares standing in the name of a receiver may be voted by such
receiver; and shares held by or under the control of a receiver may be voted by
such receiver without the transfer thereof into the receiver's name if authority
to do so is contained in the order of the court by which such receiver was
appointed.

(c) Subject to the provisions of Section 705 of the California General
Corporation Law and except where otherwise agreed in writing between the
parties, a shareholder whose shares are pledged shall be entitled to vote such
shares until the shares have been transferred into the name of the pledgee, and
thereafter the pledgee shall be entitled to vote the shares so transferred.

(d) Shares standing in the name of a minor may be voted and the corporation
may treat all rights incident thereto as exercisable by the minor, in person or
by proxy, whether or not the corporation has notice, actual or constructive, of
the non-age unless a guardian of the minor's property has been appointed and
written notice of such appointment given to the corporation.

(e) Shares standing in the name of another corporation, domestic or
foreign, may be voted by such officer, agent or proxyholder as the bylaws of
such other corporation may prescribe or, in the absence of such provision, as
the Board of Directors of such other corporation may determine or, in the
absence of such determination, by the chairman of the board, president or any
vice president of such other corporation, or by any other person authorized to
do so by the chairman of the board, president or any vice president of such
other corporation. Shares which are purported to be voted or any proxy purported
to be executed in the name of a corporation (whether or not any title of the
person signing is indicated) shall be presumed to be voted or the proxy executed
in accordance with the provisions of this subdivision, unless the contrary is
shown.

(f) Shares of the corporation owned by any of its subsidiaries shall not be
entitled to vote on any matter.

(g) Shares of the corporation held by the corporation in a fiduciary
capacity, and shares of the corporation held in a fiduciary capacity by any of
its subsidiaries, shall not be entitled to vote on any matter, except to the
extent that

5

the settlor or beneficial owner possesses and exercises a right to vote or to
give the corporation binding instructions as to how to vote such shares.

(h) If shares stand of record in the names of two or more persons, whether
fiduciaries, members of a partnership, joint tenants, tenants in common, husband
and wife as community property, tenants by the entirety, voting trustees,
persons entitled to vote under a shareholder voting agreement or otherwise, or
if two or more persons (including proxyholders) have the same fiduciary
relationship respecting the same shares, unless the secretary of the corporation
is given written notice to the contrary and is furnished with a copy of the
instrument or order appointing them or creating the relationship wherein it is
so provided, their acts with respect to voting shall have the following effect:

(i) If only one votes, such act binds all;

(ii) If more than one vote, the act of the majority so voting binds all;

(iii)If more than one vote, but the vote is evenly split on any particular
matter, each faction may vote the securities in question
proportionately.

If the instrument so filed or the registration of the shares shows that any such
tenancy is held in unequal interests, a majority or even split for the purpose
of this section shall be a majority or even split in interest.

No shareholder of any class of stock of this corporation shall be entitled
to cumulate votes at any election of directors of this corporation.

Elections for directors need not be by ballot; provided, however, that all
elections for directors must be by ballot upon demand made by a shareholder at
the meeting and before the voting begins.

In any election of directors, the candidates receiving the highest number
of votes of the shares entitled to be voted for them up to the number of
directors to be elected by such shares are elected.

Section 8. Record Date.

The Board may fix, in advance, a record date for the determination of the
shareholders entitled to notice of any meeting or to vote or entitled to receive
payment of any dividend or other distribution, or any allotment of rights, or to
exercise rights in respect of any other lawful action. The record date so fixed
shall be not more than sixty days nor less than ten days prior to the date of
the meeting nor more than sixty days prior to any other action. When a record
date is so fixed, only shareholders of record at the close of business on that
date are

6

entitled to notice of and to vote at the meeting or to receive the dividend,
distribution, or allotment of rights, or to exercise the rights, as the case may
be, notwithstanding any transfer of shares on the books of the corporation after
the record date, except as otherwise provided by law or these Bylaws. A
determination of shareholders of record entitled to notice of or to vote at a
meeting of shareholders shall apply to any adjournment of the meeting unless the
Board fixes a new record date for the adjourned meeting. The Board shall fix a
new record date if the meeting is adjourned for more than forty-five days.

If no record date is fixed by the Board, the record date for determining
shareholders entitled to notice of or to vote at a meeting of shareholders shall
be at the close of business on the business day next preceding the day on which
notice is given or, if notice is waived, at the close of business on the
business day next preceding the day on which the meeting is held. The record
date for determining shareholders for any purpose other than as set forth in
this Section 8 or Section 10 of this Article shall be at the close of business
on the day on which the Board adopts the resolution relating thereto, or the
sixtieth day prior to the date of such other action, whichever is later.

Section 9. Consent of Absentees.

The transactions of any meeting of shareholders, however called and
noticed, and wherever held, are as valid as though had at a meeting duly held
after regular call and notice, if a quorum is present either in person or by
proxy, and if, either before or after the meeting, each of the persons entitled
to vote, not present in person or by proxy, signs a written waiver of notice or
a consent to the holding of the meeting or an approval of the minutes thereof.
All such waivers, consents or approvals shall be filed with the corporate
records or made a part of the minutes of the meeting. Neither the business to be
transacted at nor the purpose of any regular or special meeting of shareholders
need be specified in any written waiver of notice, consent to the holding of the
meeting or approval of the minutes thereof, except as provided in Section 601
(f) of the California General Corporation Law.

Section 10. Action Without Meeting.

Subject to Section 603 of the California General Corporation Law, any
action which, under any provision of the California General Corporation Law, may
be taken at any annual or special meeting of shareholders may be taken without a
meeting and without prior notice if a consent in writing, setting forth the
action so taken, shall be signed by the holders of outstanding shares having not
less than the minimum number of votes that would be necessary to authorize or
take such action at a meeting at which all shares entitled to vote thereon were
present and voted. Unless a record date for voting purposes be fixed as provided
in Section 8 of this Article, the record date for determining shareholders
entitled

7

to give consent pursuant to this Section 10, when no prior action by the
Board has been taken, shall be the day on which the first written consent is
given.

Section 11. Proxies.

Every person entitled to vote shares has the right to do so either in
person or by one or more persons, not to exceed three, designated by a proxy
authorized by such shareholder or the shareholder's attorney in fact and filed
with the corporation, in accordance with Cal. Corp. Code ss.178. Subject to the
following sentence, any proxy duly authorized continues in full force and effect
until revoked by the person authorizing it prior to the vote pursuant thereto by
a writing delivered to the corporation stating that the proxy is revoked or by a
subsequent proxy authorized by the person authorizing the prior proxy and
presented to the meeting, or by attendance at the meeting and voting in person
by the person authorizing the proxy; provided, however, that a proxy is not
revoked by the death or incapacity of the maker unless, before the vote is
counted, written notice of such death or incapacity is received by this
corporation. No proxy shall be valid after the expiration of eleven months from
the date of its authorization unless otherwise provided in the proxy.

Section 12. Inspectors of Election.

In advance of any meeting of shareholders, the Board may appoint any
persons other than nominees as inspectors of election to act at such meeting and
any adjournment thereof. If inspectors of election are not so appointed, or if
any persons so appointed fail to appear or refuse to act, the chairman of any
such meeting may, and on the request of any shareholder or shareholder's proxy
shall, make such appointments at the meeting. The number of inspectors shall be
either one or three. If appointed at a meeting on the request of one or more
shareholders or proxies, the majority of shares present shall determine whether
one or three inspectors are to be appointed.

The duties of such inspectors shall be as prescribed by Section 707 (b) of
the California General Corporation Law and shall include: determining the number
of shares outstanding and the voting power of each, the shares represented at
the meeting, the existence of a quorum, and the authenticity, validity and
effect of proxies; receiving votes, ballots or consents; hearing and determining
all challenges and questions in any way arising in connection with the right to
vote; counting and tabulating all votes or consents; determining when the polls
shall close; determining the result; and doing such acts as may be proper to
conduct the election or vote with fairness to all shareholders. If there are
three inspectors of election, the decision, act or certificate of a majority is
effective in all respects as the decision, act or certificate of all. Any report
or certificate made by the inspectors of election is prima facie evidence of the
facts stated therein.

8

ARTICLE III

ARTICLE III - DIRECTORS

Section 1. Powers.

Subject to limitations of the Articles, of these Bylaws and of the
California General Corporation Law relating to action required to be approved by
the shareholders or by the outstanding shares, the business and affairs of the
corporation shall be managed and all corporate powers shall be exercised by or
under the direction of the Board. The Board may delegate the management of the
day-to-day operation of the business of the corporation provided that the
business and affairs of the corporation shall be managed and all corporate
powers shall be exercised under the ultimate direction of the Board. Without
prejudice to such general powers, but subject to the same limitations, it is
hereby expressly declared that the Board shall have the following powers in
addition to the other powers enumerated in these Bylaws:

(a) To select and remove all the other officers, agents and employees of
the corporation, prescribe the powers and duties for them as may not be
inconsistent with law, with the Articles or these Bylaws, fix their compensation
and require from them security for faithful service.

(b) To conduct, manage and control the affairs and business of the
corporation and to make such rules and regulations therefor not inconsistent
with law, or with the Articles or these Bylaws, as they may deem best.

(c) To adopt, make and use a corporate seal, and to prescribe the forms of
certificates of stock, and to alter the form of such seal and of such
certificates from time to time as in their judgment they may deem best.

(d) To authorize the issuance of shares of stock of the corporation from
time to time, upon such terms and for such consideration as may be lawful.

(e) To borrow money and incur indebtedness for the purposes of the
corporation, and to cause to be executed and delivered therefor, in the
corporate name, promissory notes, bonds, debentures, deeds of trust, mortgages,
pledges, hypothecations or other evidences of debt and securities therefor.

Section 2. Number of Directors.

The authorized number of directors shall be not less than nine nor more
than seventeen until changed by amendment of the Articles or by a Bylaw duly
adopted by the shareholders. The exact number of directors shall be fixed,
within the limits specified, by the Board by adoption of a resolution or by the

9

shareholders in the same manner provided in these Bylaws for the amendment
thereof.

Section 3. Election and Term of Office.

The directors shall be elected at each annual meeting of the shareholders,
but if any such annual meeting is not held or the directors are not elected
thereat, the directors may be elected at any special meeting of shareholders
held for that purpose. Each director shall hold office until the next annual
meeting and until a successor has been elected and qualified.

Section 4. Vacancies.

Any director may resign effective upon giving written notice to the
Chairman of the Board, the President, the Secretary or the Board, unless the
notice specifies a later time for the effectiveness of such resignation. If the
resignation is effective at a future time, a successor may be elected to take
office when the resignation becomes effective.

Vacancies in the Board, except those existing as a result of a removal of a
director, may be filled by a majority of the remaining directors, though less
than a quorum, or by a sole remaining director, and each director so elected
shall hold office until the next annual meeting and until such director's
successor has been elected and qualified. Vacancies existing as a result of a
removal of a director may be filled by the shareholders as provided by law.

A vacancy or vacancies in the Board shall be deemed to exist in case of the
death, resignation or removal of any director, or if the authorized number of
directors be increased, or if the shareholders fail, at any annual or special
meeting of shareholders at which any director or directors are elected, to elect
the full authorized number of directors to be voted for at that meeting.

The Board may declare vacant the office of a director who has been declared
of unsound mind by an order of court or convicted of a felony.

The shareholders may elect a director or directors at any time to fill any
vacancy or vacancies not filled by the directors. Any such election by written
consent other than to fill a vacancy created by removal requires the consent of
a majority of the outstanding shares entitled to vote. If the Board accepts the
resignation of a director tendered to take effect at a future time, the Board or
the shareholders shall have power to elect a successor to take office when the
resignation is to become effective.

10

No reduction of the authorized number of directors shall have the effect of
removing any director prior to the expiration of the director's term of office.

Section 5. Place of Meeting.

Regular or special meetings of the Board shall be held at any place within
or without the State of California which has been designated from time to time
by the Board or as provided in these Bylaws. In the absence of such designation,
regular meetings shall be held at the principal office of the corporation.

Section 6. Organization Meeting.

Promptly following each annual meeting of shareholders the Board shall hold
a regular meeting for the purpose of organization, election of officers and the
transaction of other business.

Section 7. Special Meetings and Other Regular Meetings.

Special meetings and regular meetings other than organization meetings of
the Board for any purpose or purposes may be called at any time by the Chairman
of the Board, the President, any Vice President, the Secretary or by any two
directors.

Such meetings of the Board shall be held upon four days' notice by mail or
forty-eight hours' notice delivered personally or by telephone, including a
voice messaging system or other system or technology designed to record and
communicate messages, telegraph, telex, facsimile, electronic mail or other
similar means of communication. Any such notice shall be addressed or delivered
to each director at such director's address, telephone number, telex number,
facsimile number, E-mail address, or other designated location(s), as shown upon
the records of the corporation or as may have been given to the corporation by
the director for purposes of notice or, if such information is not shown on such
records or is not readily ascertainable, at the place in which the meetings of
the directors are regularly held. The notice need not specify the purpose of
such meeting.

Notice by mail shall be deemed to have been given at the time a written
notice is deposited in the United States mail, postage prepaid. Any other
written notice shall be deemed to have been given at the time it is personally
delivered to the recipient or is delivered to a common carrier for transmission,
or actually transmitted by the person giving the notice by electronic means to
the recipient. Oral notice shall be deemed to have been given at the time it is
communicated, in person or by telephone, wireless, or other similar means, to
the recipient or to a person at the office of the recipient who the person
giving the notice has reason to believe will promptly communicate it to the
recipient, or actually

11

transmitted to the recipient by the person giving the notice by a system or
technology designed to record and communicate messages.

Section 8. Quorum.

One-third of the number of authorized directors constitutes a quorum of the
Board for the transaction of business, except to adjourn as provided in Section
ll of this Article. Every act or decision done or made by a majority of the
directors present at a meeting duly held at which a quorum is present shall be
regarded as the act of the Board, unless a greater number is required by law or
by the Articles; provided, however, that a meeting at which a quorum is
initially present may continue to transact business notwithstanding the
withdrawal of directors, if any action taken is approved by at least a majority
of the required quorum for such meeting.

Section 9. Participation in Meetings by Conference Telephone.

Members of the Board may participate in a meeting through use of conference
telephone or similar communications equipment, so long as all members
participating in such meeting can hear one another. Such participation
constitutes presence in person at such meeting.

Section 10. Waiver of Notice.

The transactions of any meeting of the Board, however called and noticed or
wherever held, are as valid as though had at a meeting duly held after regular
call and notice if a quorum is present and if, either before or after the
meeting, each of the directors not present signs a written waiver of notice, a
consent to holding such meeting or an approval of the minutes thereof. All such
waivers, consents or approvals shall be filed with the corporate records or made
a part of the minutes of the meeting.

Section 11. Adjournment.

A majority of the directors present, whether or not a quorum is present,
may adjourn any directors' meeting to another time and place. Notice of the time
and place of holding an adjourned meeting need not be given to absent directors
if the time and place is fixed at the meeting adjourned. If the meeting is
adjourned for more than twenty-four hours, notice of any adjournment to another

12

time or place shall be given prior to the time of the adjourned meeting to the
directors who were not present at the time of the adjournment.

Section 12. Fees and Compensation.

Directors and members of committees may receive such compensation, if any,
for their services, and such reimbursement for expenses, as may be fixed or
determined by the Board.

Section 13. Action Without Meeting.

Any action required or permitted to be taken by the Board may be taken
without a meeting if all members of the Board shall individually or collectively
consent in writing to such action. Such written consent or consents shall have
the same force and effect as a unanimous vote of the Board and shall be filed
with the minutes of the proceedings of the Board.

Section 14. Rights of Inspection.

Every director shall have the absolute right at any reasonable time to
inspect and copy all books, records and documents of every kind and to inspect
the physical properties of the corporation and also of its subsidiary
corporations, domestic or foreign. Such inspection by a director may be made in
person or by agent or attorney and includes the right to copy and make extracts.

Section 15. Committees.

The Board may appoint one or more committees, each consisting of two or
more directors, to serve at the pleasure of the Board. The Board may delegate to
such committees any or all of the authority of the Board except with respect to:

(a) The approval of any action for which the California General Corporation
Law also requires shareholders' approval or approval of the outstanding shares;

(b) The filling of vacancies on the Board or in any committee;

(c) The fixing of compensation of the directors for serving on the Board or
on any committee;

(d) The amendment or repeal of Bylaws or the adoption of new Bylaws;

13

ARTICLE IV

(e) The amendment or repeal of any resolution of the Board which by its
express terms is not so amendable or repealable;

(f) A distribution to the shareholders of the corporation except at a rate
or in a periodic amount or within a price range determined by the Board; or

(g) The appointment of other committees of the Board or the members
thereof.

Any such committee, or any member or alternate member thereof, must be
appointed by resolution adopted by a majority of the exact number of authorized
directors as specified in Section 2 of this Article. The Board shall have the
power to prescribe the manner and timing of giving of notice of regular or
special meetings of any committee and the manner in which proceedings of any
committee shall be conducted. In the absence of any such prescription, such
committee shall have the power to prescribe the manner in which its proceedings
shall be conducted. Unless the Board or such committee shall otherwise provide,
the regular and special meetings and other actions of any such committee shall
be governed by the provisions of this Article applicable to meetings and actions
of the Board. Minutes shall be kept of each meeting of each committee.

ARTICLE IV - OFFICERS

Section 1. Officers.

The officers of the corporation shall be a Chairman of the Board, a
President, a Chief Financial Officer, one or more Vice Presidents, a General
Counsel and a Secretary. The corporation may also have, at the discretion of the
Board, one or more Associate General Counsel, one or more Assistant General
Counsel, a Controller, one or more Assistant Controllers, a Treasurer, one or
more Assistant Treasurers and one or more Assistant Secretaries, and such other
officers as may be elected or appointed in accordance with Section 5 of this
Article. The Board, the Chairman of the Board or the President may confer a
special title upon any Vice President not specified herein.

Section 2. Election.

The officers of the corporation, except such officers as may be elected or
appointed in accordance with the provisions of Section 5 or Section 6 of this
Article, shall be chosen annually by, and shall serve at the pleasure of the
Board, and shall hold their respective offices until their resignation, removal,
or other disqualification from service, or until their respective successors
shall be elected.

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Section 3. Eligibility of Chairman or President.

No person shall be eligible for the office of Chairman of the Board or
President unless such person is a member of the Board of the corporation; any
other officer may or may not be a director.

Section 4. Removal and Resignation.

Any officer may be removed, either with or without cause, by the Board at
any time or by any officer upon whom such power or removal may be conferred by
the Board. Any such removal shall be without prejudice to the rights, if any, of
the officer under any contract of employment of the officer.

Any officer may resign at any time by giving written notice to the
corporation, but without prejudice to the rights, if any, of the corporation
under any contract to which the officer is a party. Any such resignation shall
take effect at the date of the receipt of such notice or at any later time
specified therein and, unless otherwise specified therein, the acceptance of
such resignation shall not be necessary to make it effective.

Section 5. Appointment of Other Officers.

The Board may appoint such other officers as the business of the
corporation may require, each of whom shall hold office for such period, have
such authority, and perform such duties as are provided in the Bylaws or as the
Board may from time to time determine.

Section 6. Vacancies.

A vacancy in any office because of death, resignation, removal,
disqualification or any other cause shall be filled at any time deemed
appropriate by the Board in the manner prescribed in these Bylaws for regular
election or appointment to such office.

Section 7. Salaries.

The salaries of the Chairman of the Board, President, Chief Financial
Officer, Vice Presidents, General Counsel, Controller, Treasurer and Secretary
of the corporation shall be fixed by the Board. Salaries of all other officers
shall be as approved from time to time by the chief executive officer.

15

Section 8. Furnish Security for Faithfulness.

Any officer or employee shall, if required by the Board, furnish to the
corporation security for faithfulness to the extent and of the character that
may be required.

Section 9. Chairman's Duties; Succession to Such Duties in
Chairman's Absence or Disability.

The Chairman of the Board shall be the chief executive officer of the
corporation and shall preside at all meetings of the shareholders and of the
Board. Subject to the Board, the Chairman of the Board shall have charge of the
business of the corporation. The Chairman of the Board shall keep the Board
fully informed, and shall freely consult them concerning the business of the
corporation.

In the absence or disability of the Chairman of the Board, the President
shall act as the chief executive officer of the corporation; in the absence or
disability of the Chairman of the Board and the President, the next in order of
election by the Board of the Vice Presidents shall act as chief executive
officer of the corporation.

In the absence or disability of the Chairman of the Board, the President
shall act as Chairman of the Board at meetings of the Board; in the absence or
disability of the Chairman of the Board and the President, the next, in order of
election by the Board, of the Vice Presidents who is a member of the Board shall
act as Chairman of the Board at any such meeting of the Board; in the absence or
disability of the Chairman of the Board, the President, and such Vice Presidents
who are members of the Board, the Board shall designate a temporary Chairman to
preside at any such meeting of the Board.

Section 10. President's Duties.

The President shall perform such other duties as the Chairman of the Board
shall delegate or assign to such officer.

Section 11. Chief Financial Officer.

The Chief Financial Officer of the corporation shall be the chief
consulting officer in all matters of financial import and shall have control
over all financial matters concerning the corporation. If the corporation does
not have a currently elected and acting Controller, the Chief Financial Officer
shall also be the Chief Accounting Officer of the corporation.

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Section 12. Vice Presidents' Duties.

The Vice Presidents shall perform such other duties as the chief executive
officer shall designate.

Section 13. General Counsel's Duties.

The General Counsel shall be the chief consulting officer of the
corporation in all legal matters and, subject to the chief executive officer,
shall have control over all matters of legal import concerning the corporation.

Section 14. Associate General Counsel's and Assistant General
Counsel's Duties.

The Associate General Counsel shall perform such of the duties of the
General Counsel as the General Counsel shall designate, and in the absence or
disability of the General Counsel, the Associate General Counsel, in order of
election to that office by the Board at its latest organizational meeting, shall
perform the duties of the General Counsel. The Assistant General Counsel shall
perform such duties as the General Counsel shall designate.

Section 15. Controller's Duties.

The Controller shall be the chief accounting officer of the Corporation
and, subject to the Chief Financial Officer, shall have control over all
accounting matters concerning the Corporation and shall perform such other
duties as the Chief Executive Officer shall designate.

Section 16. Assistant Controllers' Duties.

The Assistant Controllers shall perform such of the duties of the
Controller as the Controller shall designate, and in the absence or disability
of the Controller, the Assistant Controllers, in order of election to that
office by the Board at its latest organizational meeting, shall perform the
duties of the Controller.

Section 17. Treasurer's Duties.

It shall be the duty of the Treasurer to keep in custody or control all
money, stocks, bonds, evidences of debt, securities and other items of value
that may belong to, or be in the possession or control of, the corporation, and
to dispose of the same in such manner as the Board or the chief executive
officer may direct, and to perform all acts incident to the position of
Treasurer.

17

Section 18. Assistant Treasurers' Duties.

The Assistant Treasurers shall perform such of the duties of the Treasurer
as the Treasurer shall designate, and in the absence or disability of the
Treasurer, the Assistant Treasurers, in order of election to that office by the
Board at its latest organizational meeting, shall perform the duties of the
Treasurer, unless action is taken by the Board as contemplated in Article IV,
Section 22.

Section 19. Secretary's Duties.

The Secretary shall keep or cause to be kept full and complete records of
the proceedings of shareholders, the Board and its committees at all meetings,
and shall affix the corporate seal and attest by signing copies of any part
thereof when required.

The Secretary shall keep, or cause to be kept, a copy of the Bylaws of the
corporation at the principal office in accordance with Section 213 of the
California General Corporation Law.

The Secretary shall be the custodian of the corporate seal and shall affix
it to such instruments as may be required.

The Secretary shall keep on hand a supply of blank stock certificates of
such forms as the Board may adopt.

The Secretary shall serve or cause to be served by publication or
otherwise, as may be required, all notices of meetings and of other corporate
acts that may by law or otherwise be required to be served, and shall make or
cause to be made and filed in the principal office of the corporation, the
necessary certificate or proofs thereof.

An affidavit of mailing of any notice of a shareholders' meeting or of any
report, in accordance with the provisions of Section 60l (b) of the California
General Corporation Law, executed by the Secretary shall be prima facie evidence
of the fact that such notice or report had been duly given.

The Secretary may, with the Chairman of the Board, the President, or a Vice
President, sign certificates of ownership of stock in the corporation, and shall
cause all certificates so signed to be delivered to those entitled thereto.

The Secretary shall keep all records required by the California General
Corporation Law.

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The Secretary shall generally perform the duties usual to the office of
secretary of corporations, and such other duties as the chief executive officer
shall designate.

Section 20. Assistant Secretaries' Duties.

Assistant Secretaries shall perform such of the duties of the Secretary as
the Secretary shall designate, and in the absence or disability of the
Secretary, the Assistant Secretaries, in the order of election to that office by
the Board at its latest organizational meeting, shall perform the duties of the
Secretary, unless action is taken by the Board as contemplated in Article IV,
Sections 21 and 22 of these Bylaws.

Section 21. Secretary Pro Tempore.

At any meeting of the Board or of the shareholders from which the Secretary
is absent, a Secretary pro tempore may be appointed and act.

Section 22. Election of Acting Treasurer or Acting Secretary.

The Board may elect an Acting Treasurer, who shall perform all the duties
of the Treasurer during the absence or disability of the Treasurer, and who
shall hold office only for such a term as shall be determined by the Board.

The Board may elect an Acting Secretary, who shall perform all the duties
of the Secretary during the absence or disability of the Secretary, and who
shall hold office only for such a term as shall be determined by the Board.

Whenever the Board shall elect either an Acting Treasurer or Acting
Secretary, or both, the officers of the corporation as set forth in Article IV,
Section 1 of these Bylaws, shall include as if therein specifically set out, an
Acting Treasurer or an Acting Secretary, or both.

Section 23. Performance of Duties.

Officers shall perform the duties of their respective offices as stated in
these Bylaws, and such additional duties as the Board shall designate.

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ARTICLE V

ARTICLE V - OTHER PROVISIONS

Section 1. Inspection of Corporate Records.

(a) A shareholder or shareholders holding at least five percent in the
aggregate of the outstanding voting shares of the corporation or who hold at
least one percent of such voting shares and have filed a Schedule 14B with the
United States Securities and Exchange Commission relating to the election of
directors of the corporation shall have an absolute right to do either or both
of the following:

(i) Inspect and copy the record of shareholders' names and addresses and
shareholdings during usual business hours upon five business days'
prior written demand upon the corporation; or

(ii) Obtain from the transfer agent, if any, for the corporation, upon five
business days' prior written demand and upon the tender of its usual
charges for such a list (the amount of which charges shall be stated
to the shareholder by the transfer agent upon request), a list of the
shareholders' names and addresses who are entitled to vote for the
election of directors and their shareholdings, as of the most recent
record date for which it has been compiled or as of a date specified
by the shareholder subsequent to the date of demand.

(b) The record of shareholders shall also be open to inspection and copying
by any shareholder or holder of a voting trust certificate at any time during
usual business hours upon written demand on the corporation, for a purpose
reasonably related to such holder's interest as a shareholder or holder of a
voting trust certificate.

(c) The accounting books and records and minutes of proceedings of the
shareholders and the Board and committees of the Board shall be open to
inspection upon written demand on the corporation of any shareholder or holder
of a voting trust certificate at any reasonable time during usual business
hours, for a purpose reasonably related to such holder's interests as a
shareholder or as a holder of such voting trust certificate.

(d) Any such inspection and copying under this Article may be made in
person or by agent or attorney.

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Section 2. Inspection of Bylaws.

The corporation shall keep in its principle office the original or a copy
of these Bylaws as amended to date, which shall be open to inspection by
shareholders at all reasonable times during office hours.

Section 3. Contracts and Other Instruments, Loans, Notes and Deposits
of Funds.

The Chairman of the Board, the President, or a Vice President, either alone
or with the Secretary or an Assistant Secretary, or the Secretary alone, shall
execute in the name of the corporation such written instruments as may be
authorized by the Board and, without special direction of the Board, such
instruments as transactions of the ordinary business of the corporation may
require and, such officers without the special direction of the Board may
authenticate, attest or countersign any such instruments when deemed
appropriate. The Board may authorize any person, persons, entity, entities,
attorney, attorneys, attorney-in-fact, attorneys-in-fact, agent or agents, to
enter into any contract or execute and deliver any instrument in the name of and
on behalf of the corporation, and such authority may be general or confined to
specific instances.

No loans shall be contracted on behalf of the corporation and no evidences
of such indebtedness shall be issued in its name unless authorized by the Board
as it may direct. Such authority may be general or confined to specific
instances.

All checks, drafts, or other similar orders for the payment of money,
notes, or other such evidences of indebtedness issued in the name of the
corporation shall be signed by such officer or officers, agent or agents of the
corporation and in such manner as the Board or chief executive officer may
direct.

Unless authorized by the Board or these Bylaws, no officer, agent, employee
or any other person or persons shall have any power or authority to bind the
corporation by any contract or engagement or to pledge its credit or to render
it liable for any purpose or amount.

All funds of the corporation not otherwise employed shall be deposited from
time to time to the credit of the corporation in such banks, trust companies, or
other depositories as the Board may direct.

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Section 4. Certificates of Stock.

Every holder of shares of the corporation shall be entitled to have a
certificate signed in the name of the corporation by the Chairman of the Board,
the President, or a Vice President and by the Treasurer or an Assistant
Treasurer or the Secretary or an Assistant Secretary, certifying the number of
shares and the class or series of shares owned by the shareholder. Any or all of
the signatures on the certificate may be facsimile. In case any officer,
transfer agent or registrar who has signed or whose facsimile signature has been
placed upon a certificate shall have ceased to be such officer, transfer agent
or registrar before such certificate is issued, it may be issued by the
corporation with the same effect as if such person were an officer, transfer
agent or registrar at the date of issue.

Certificates for shares may be used prior to full payment under such
restrictions and for such purposes as the Board may provide; provided, however,
that on any certificate issued to represent any partly paid shares, the total
amount of the consideration to be paid therefor and the amount paid thereon
shall be stated.

Except as provided in this Section, no new certificate for shares shall be
issued in lieu of an old one unless the latter is surrendered and canceled at
the same time. The Board may, however, if any certificate for shares is alleged
to have been lost, stolen or destroyed, authorize the issuance of a new
certificate in lieu thereof, and the corporation may require that the
corporation be given a bond or other adequate security sufficient to indemnify
it against any claim that may be made against it (including expense or
liability) on account of the alleged loss, theft or destruction of such
certificate or the issuance of such new certificate.

Section 5. Transfer Agent, Transfer Clerk and Registrar.

The Board may, from time to time, appoint transfer agents, transfer clerks,
and stock registrars to transfer and register the certificates of the capital
stock of the corporation, and may provide that no certificate of capital stock
shall be valid without the signature of the stock transfer agent or transfer
clerk, and stock registrar.

Section 6. Representation of Shares of Other Corporations.

The chief executive officer or any other officer or officers authorized by
the Board or the chief executive officer are each authorized to vote, represent
and exercise on behalf of the corporation all rights incident to any and all
shares of any other corporation or corporations standing in the name of the
corporation.

22

The authority herein granted may be exercised either by any such officer in
person or by any other person authorized so to do by proxy or power of attorney
duly executed by said officer.

Section 7. Stock Purchase Plans.

The corporation may adopt and carry out a stock purchase plan or agreement
or stock option plan or agreement providing for the issue and sale for such
consideration as may be fixed of its unissued shares, or of issued shares
acquired, to one or more of the employees or directors of the corporation or of
a subsidiary or to a trustee on their behalf and for the payment for such shares
in installments or at one time, and may provide for such shares in installments
or at one time, and may provide for aiding any such persons in paying for such
shares by compensation for services rendered, promissory notes or otherwise.

Any such stock purchase plan or agreement or stock option plan or agreement
may include, among other features, the fixing of eligibility for participation
therein, the class and price of shares to be issued or sold under the plan or
agreement, the number of shares which may be subscribed for, the method of
payment therefor, the reservation of title until full payment therefor, the
effect of the termination of employment and option or obligation on the part of
the corporation to repurchase the shares upon termination of employment,
restrictions upon transfer of the shares, the time limits of and termination of
the plan, and any other matters, not in violation of applicable law, as may be
included in the plan as approved or authorized by the Board or any committee of
the Board.

Section 8. Fiscal Year and Subdivisions.

The calendar year shall be the corporate fiscal year of the corporation.
For the purpose of paying dividends, for making reports and for the convenient
transaction of the business of the corporation, the Board may divide the fiscal
year into appropriate subdivisions.

Section 9. Construction and Definitions.

Unless the context otherwise requires, the general provisions, rules of
construction and definitions contained in the General Provisions of the
California Corporations Code and in the California General Corporation Law shall
govern the construction of these Bylaws.

23

ARTICLE VI

ARTICLE VI - INDEMNIFICATION

Section 1. Indemnification of Directors and Officers.

Each person who was or is a party or is threatened to be made a party to or
is involved in any threatened, pending or completed action, suit or proceeding,
formal or informal, whether brought in the name of the corporation or otherwise
and whether of a civil, criminal, administrative or investigative nature
(hereinafter a "proceeding"), by reason of the fact that he or she, or a person
of whom he or she is the legal representative, is or was a director or officer
of the corporation or is or was serving at the request of the corporation as a
director, officer, employee or agent of another corporation or of a partnership,
joint venture, trust or other enterprise, including service with respect to
employee benefit plans, whether the basis of such proceeding is an alleged
action or inaction in an official capacity or in any other capacity while
serving as a director or officer, shall, subject to the terms of any agreement
between the corporation and such person, be indemnified and held harmless by the
corporation to the fullest extent permissible under California law and the
corporation's Articles of Incorporation, against all costs, charges, expenses,
liabilities and losses (including attorneys' fees, judgments, fines, ERISA
excise taxes or penalties and amounts paid or to be paid in settlement)
reasonably incurred or suffered by such person in connection therewith, and such
indemnification shall continue as to a person who has ceased to be a director or
officer and shall inure to the benefit of his or her heirs, executors and
administrators; provided, however, that (A) the corporation shall indemnify any
such person seeking indemnification in connection with a proceeding (or part
thereof) initiated by such person only if such proceeding (or part thereof) was
authorized by the Board of the corporation; (B) the corporation shall indemnify
any such person seeking indemnification in connection with a proceeding (or part
thereof) other than a proceeding by or in the name of the corporation to procure
a judgment in its favor only if any settlement of such a proceeding is approved
in writing by the corporation; (C) that no such person shall be indemnified (i)
except to the extent that the aggregate of losses to be indemnified exceeds the
amount of such losses for which the director or officer is paid pursuant to any
directors' and officers' liability insurance policy maintained by the
corporation; (ii) on account of any suit in which judgment is rendered against
such person for an accounting of profits made from the purchase or sale by such
person of securities of the corporation pursuant to the provisions of Section
16(b) of the Securities Exchange Act of 1934 and amendments thereto or similar
provisions of any federal, state or local statutory law; (iii) if a court of
competent jurisdiction finally determines that any indemnification hereunder is
unlawful; and (iv) as to circumstances in which indemnity is expressly
prohibited by Section 317 of the General Corporation Law of California (the
"Law"); and (D) that no such person shall be indemnified with regard to any
action brought by or

24

in the right of the corporation for breach of duty to the corporation and
its shareholders (a) for acts or omissions involving intentional misconduct or
knowing and culpable violation of law; (b) for acts or omissions that the
director or officer believes to be contrary to the best interests of the
corporation or its shareholders or that involve the absence of good faith on the
part of the director or officer; (c) for any transaction from which the director
or officer derived an improper personal benefit; (d) for acts or omissions that
show a reckless disregard for the director's or officer's duty to the
corporation or its shareholders in circumstances in which the director or
officer was aware, or should have been aware, in the ordinary course of
performing his or her duties, of a risk of serious injury to the corporation or
its shareholders; (e) for acts or omissions that constitute an unexcused pattern
of inattention that amounts to an abdication of the director's or officer's
duties to the corporation or its shareholders; and (f) for costs, charges,
expenses, liabilities and losses arising under Section 310 or 316 of the Law.
The right to indemnification conferred in this Article shall include the right
to be paid by the corporation expenses incurred in defending any proceeding in
advance of its final disposition; provided, however, that if the Law permits the
payment of such expenses incurred by a director or officer in his or her
capacity as a director or officer (and not in any other capacity in which
service was or is rendered by such person while a director or officer,
including, without limitation, service to an employee benefit plan) in advance
of the final disposition of a proceeding, such advances shall be made only upon
delivery to the corporation of an undertaking, by or on behalf of such director
or officer, to repay all amounts to the corporation if it shall be ultimately
determined that such person is not entitled to be indemnified.

Section 2. Indemnification of Employees and Agents.

A person who was or is a party or is threatened to be made a party to or is
involved in any proceeding by reason of the fact that he or she is or was an
employee or agent of the corporation or is or was serving at the request of the
corporation as an employee or agent of another enterprise, including service
with respect to employee benefit plans, whether the basis of such action is an
alleged action or inaction in an official capacity or in any other capacity
while serving as an employee or agent, may, subject to the terms of any
agreement between the corporation and such person, be indemnified and held
harmless by the corporation to the fullest extent permitted by California law
and the corporation's Articles of Incorporation, against all costs, charges,
expenses, liabilities and losses, (including attorneys' fees, judgments, fines,
ERISA excise taxes or penalties and amounts paid or to be paid in settlement)
reasonably incurred or suffered by such person in connection therewith.

25

ARTICLE VI
Section 3. Right of Directors and Officers to Bring Suit.

If a claim under Section 1 of this Article is not paid in full by the
corporation within 30 days after a written claim has been received by the
corporation, the claimant may at any time thereafter bring suit against the
corporation to recover the unpaid amount of the claim and, if successful in
whole or in part, the claimant shall also be entitled to be paid the expense of
prosecuting such claim. Neither the failure of the corporation (including its
Board, independent legal counsel, or its shareholders) to have made a
determination prior to the commencement of such action that indemnification of
the claimant is permissible in the circumstances because he or she has met the
applicable standard of conduct, if any, nor an actual determination by the
corporation (including its Board, independent legal counsel, or its
shareholders) that the claimant has not met the applicable standard of conduct,
shall be a defense to the action or create a presumption for the purpose of an
action that the claimant has not met the applicable standard of conduct.

Section 4. Successful Defense.

Notwithstanding any other provision of this Article, to the extent that a
director or officer has been successful on the merits or otherwise (including
the dismissal of an action without prejudice or the settlement of a proceeding
or action without admission of liability) in defense of any proceeding referred
to in Section 1 or in defense of any claim, issue or matter therein, he or she
shall be indemnified against expenses (including attorneys' fees) actually and
reasonably incurred in connection therewith.

Section 5. Non-Exclusivity of Rights.

The right to indemnification provided by this Article shall not be
exclusive of any other right which any person may have or hereafter acquire
under any statute, bylaw, agreement, vote of shareholders or disinterested
directors or otherwise.

Section 6. Insurance.

The corporation may maintain insurance, at its expense, to protect itself
and any director, officer, employee or agent of the corporation or another
corporation, partnership, joint venture, trust or other enterprise against any
expense, liability or loss, whether or not the corporation would have the power
to indemnify such person against such expense, liability or loss under the Law.

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ARTICLE VII
ARTICLE VII
Section 7. Expenses as a Witness.

To the extent that any director, officer, employee or agent of the
corporation is by reason of such position, or a position with another entity at
the request of the corporation, a witness in any action, suit or proceeding, he
or she shall be indemnified against all costs and expenses actually and
reasonably incurred by him or her on his or her behalf in connection therewith.

Section 8. Indemnity Agreements.

The corporation may enter into agreements with any director, officer,
employee or agent of the corporation providing for indemnification to the
fullest extent permissible under the Law and the corporation's Articles of
Incorporation.

Section 9. Separability.

Each and every paragraph, sentence, term and provision of this Article is
separate and distinct so that if any paragraph, sentence, term or provision
hereof shall be held to be invalid or unenforceable for any reason, such
invalidity or unenforceability shall not affect the validity or enforceability
of any other paragraph, sentence, term or provision hereof. To the extent
required, any paragraph, sentence, term or provision of this Article may be
modified by a court of competent jurisdiction to preserve its validity and to
provide the claimant with, subject to the limitations set forth in this Article
and any agreement between the corporation and claimant, the broadest possible
indemnification permitted under applicable law.

Section 10. Effect of Repeal or Modification.

Any repeal or modification of this Article shall not adversely affect any
right of indemnification of a director or officer existing at the time of such
repeal or modification with respect to any action or omission occurring prior to
such repeal or modification.

ARTICLE VII - EMERGENCY PROVISIONS

Section 1. General.

The provisions of this Article shall be operative only during a national
emergency declared by the President of the United States or the person
performing the President's functions, or in the event of a nuclear, atomic or
other attack on the United States or a disaster making it impossible or
impracticable for the corporation to conduct its business without recourse to
the provisions of

27

ARTICLE VII

this Article. Said provisions in such event shall override all other Bylaws
of the corporation in conflict with any provisions of this Article, and shall
remain operative so long as it remains impossible or impracticable to continue
the business of the corporation otherwise, but thereafter shall be inoperative;
provided that all actions taken in good faith pursuant to such provisions shall
thereafter remain in full force and effect unless and until revoked by action
taken pursuant to the provisions of the Bylaws other than those contained in
this Article.

Section 2. Unavailable Directors.

All directors of the corporation who are not available to perform their
duties as directors by reason of physical or mental incapacity or for any other
reason or who are unwilling to perform their duties or whose whereabouts are
unknown shall automatically cease to be directors, with like effect as if such
persons had resigned as directors, so long as such unavailability continues.

Section 3. Authorized Number of Directors.

The authorized number of directors shall be the number of directors
remaining after eliminating those who have ceased to be directors pursuant to
Section 2, or the minimum number required by law, whichever number is greater.

Section 4. Quorum.

The number of directors necessary to constitute a quorum shall be one-third
of the authorized number of directors as specified in the foregoing Section, or
such other minimum number as, pursuant to the law or lawful decree then in
force, it is possible for the Bylaws of a corporation to specify.

Section 5. Creation of Emergency Committee.

In the event the number of directors remaining after eliminating those who
have ceased to be directors pursuant to Section 2 is less than the minimum
number of authorized directors required by law, then until the appointment of
additional directors to make up such required minimum, all the powers and
authorities which the Board could by law delegate, including all powers and
authorities which the Board could delegate to a committee, shall be
automatically vested in an emergency committee, and the emergency committee
shall thereafter manage the affairs of the corporation pursuant to such powers
and authorities and shall have all other powers and authorities as may by law or
lawful decree be conferred on any person or body of persons during a period of
emergency.

28

Section 6. Constitution of Emergency Committee.

The emergency committee shall consist of all the directors remaining after
eliminating those who have ceased to be directors pursuant to Section 2,
provided that such remaining directors are not less than three in number. In the
event such remaining directors are less than three in number the emergency
committee shall consist of three persons, who shall be the remaining director or
directors and either one or two officers or employees of the corporation, as the
remaining director or directors may in writing designate. If there is no
remaining director, the emergency committee shall consist of the three most
senior officers of the corporation who are available to serve, and if and to the
extent that officers are not available, the most senior employees of the
corporation. Seniority shall be determined in accordance with any designation of
seniority in the minutes of the proceedings of the Board, and in the absence of
such designation, shall be determined by rate of remuneration. In the event that
there are no remaining directors and no officers or employees of the corporation
available, the emergency committee shall consist of three persons designated in
writing by the shareholder owning the largest number of shares of record as of
the date of the last record date.

Section 7. Powers of Emergency Committee.

The emergency committee, once appointed, shall govern its own procedures
and shall have power to increase the number of members thereof beyond the
original number, and in the event of a vacancy or vacancies therein, arising at
any time, the remaining member or members of the emergency committee shall have
the power to fill such vacancy or vacancies. In the event at any time after its
appointment all members of the emergency committee shall die or resign or become
unavailable to act for any reason whatsoever, a new emergency committee shall be
appointed in accordance with the foregoing provisions of this Article.

Section 8. Directors Becoming Available.

Any person who has ceased to be a director pursuant to the provisions of
Section 2 and who thereafter becomes available to serve as a director shall
automatically become a member of the emergency committee.

Section 9. Election of Board of Directors.

The emergency committee shall, as soon after its appointment as is
practicable, take all requisite action to secure the election of a board of
directors,

29

ARTICLE VIII
ARTICLE VIII

and upon such election all the powers and authorities of the emergency
committee shall cease.

Section 10. Termination of Emergency Committee.

In the event, after the appointment of an emergency committee, a
sufficient number of persons who ceased to be directors pursuant to Section 2
become available to serve as directors, so that if they had not ceased to be
directors as aforesaid, there would be enough directors to constitute the
minimum number of directors required by law, then all such persons shall
automatically be deemed to be reappointed as directors and the powers and
authorities of the emergency committee shall be at an end.

ARTICLE VIII - AMENDMENTS

Section 1. Amendments.

These Bylaws may be amended or repealed either by approval of the
outstanding shares or by the approval of the Board; provided, however, that a
Bylaw specifying or changing a fixed number of directors or the maximum or
minimum number or changing from a fixed to a variable Board or vice versa may
only be adopted by approval of the outstanding shares. The exact number of
directors within the maximum and minimum number specified in these Bylaws may be
amended by the Board alone.

EXHIBIT 10.25

EDISON INTERNATIONAL

OPTION GAIN DEFERRAL PLAN

Reinstated
September 15, 2000

OPTION GAIN DEFERRAL PLAN
TABLE OF CONTENTS

Section Title Page
- ------- ----- ----

1. PURPOSE AND AUTHORIZED SHARES.............................................1

1.1 Purposes..............................................................1
1.2 Shares Available......................................................1
1.3 Relationship to Incentive Plans.......................................2

2. DEFINITIONS...............................................................2

3. PARTICIPATION.............................................................6

3.1 General Participation Requirements....................................6
3.2 Manner and Timing of Election.........................................6
3.3 Execution of Alternative Exercise Agreement by the Company............6

4. ALTERNATIVE EXERCISE OF OPTIONS...........................................6

4.1 Form of Agreement.....................................................6
4.2 Limited Ability to Exercise Option....................................6
4.3 Termination of Alternative Exercise Agreements........................7
4.4 Other Terms of Alternative Exercise Agreements........................7

5. STOCK UNIT ACCOUNTS.......................................................7

5.1 Crediting of Stock Units..............................................8
5.2 Dividend Equivalent Credits to Stock Unit Accounts....................8
5.3 Vesting.............................................................. 8
5.4 Distribution of Benefits..............................................8
5.5 Adjustments in Case of Changes in Common Stock.......................11
5.6 Company's Right to Withhold..........................................11

6. ADMINISTRATION...........................................................12

6.1 The Administrator....................................................12
6.2 Committee Action.....................................................12
6.3 Rights and Duties....................................................12
6.4 Indemnity and Liability..............................................13
6.5 Claims Procedure.....................................................13

OPTION GAIN DEFERRAL PLAN

TABLE OF CONTENTS

Section Title Page
- ------- ----- ----

7. PLAN CHANGES AND TERMINATION.............................................14

7.1 Amendments...........................................................14
7.2 Term.................................................................14

8. MISCELLANEOUS............................................................15

8.1 Limitation on Participant Rights.....................................15
8.2 Beneficiary Designation..............................................15
8.3 Payments to Minors or Persons Under Incapacity.......................16
8.4 Stock Units and Other Benefits Not Assignable;
Obligations Binding Upon Successors..................................16
8.5 Employment Taxes.....................................................16
8.6 Governing Law; Severability..........................................16
8.7 Compliance With Laws.................................................16
8.8 Plan Construction....................................................17
8.9 Headings Not Part of Plan............................................17

EDISON INTERNATIONAL
OPTION GAIN DEFERRAL PLAN

Restated September 15, 2000

1.
PURPOSE AND AUTHORIZED SHARES

1.1 Purposes

The purpose of this Plan is to promote the ownership and retention of Shares by
Eligible Persons and to enable Eligible Persons to defer compensation that would
otherwise be realized upon exercise of a Qualifying Option and ultimately
receive the deferred compensation in the form of Shares.

1.2 Shares Available

The number of Shares that may be issued under each of the Management Plan, the
Officer Plan, the 1998 Plan (except as provided below) and the 2000 Equity Plan
as part of this Plan is limited to the aggregate number of Shares that were the
subject of the Qualifying Options granted under such Plan that are exercised
pursuant to Article IV in exchange for the crediting of Stock Units under this
Plan. If the number of Shares payable under this Plan would exceed one or more
of the limits described in the preceding sentence because of the accumulation of
Stock Units in respect of Dividend Equivalents, such excess Shares shall be
issued and charged against the Share limits under the 1998 Plan or the 2000
Equity Plan. If insufficient Shares remain under the 1998 Plan or the 2000
Equity Plan for the accumulation of Dividend Equivalents under the Management
Plan, the Officer Plan, the 1998 Plan or the 2000 Equity Plan, such excess
Shares shall be issued under other authority of the Board, or, in absence of
such other authority, may be paid (in the sole discretion of the Committee) in
cash. Shares not exceeding the number of Already-Owned Shares used under this
Plan to exercise a Qualifying Stock Option granted under the Management Plan may
be used in respect of Dividend Equivalents on the Stock Units credited with
respect to Alternatively Exercised Qualifying Options granted under the
Management Plan, but may not be used for other awards under the Incentive Plans.
Shares not exceeding the number of Already-Owned Shares used under this Plan to
exercise a Qualifying Stock Option granted under the Officer Plan may be used in
respect of Dividend Equivalents on the Stock Units credited with respect to
Alternatively Exercised Qualifying Options granted under the Officer Plan, but
may not be used for other awards under the Incentive Plans. Shares not exceeding
the number of Already-Owned Shares used under this Plan to exercise a Qualifying
Stock Option granted under the 1998 Plan or the 2000 Equity Plan may be used in
respect of Dividend Equivalents on the Stock

1

Units credited with respect to an Alternatively Exercised Qualifying Option
granted under any one of the Incentive Plans, but may not be used for other
awards under the Incentive Plans.

1.3 Relationship to Incentive Plans

This Plan constitutes a deferred compensation plan providing alternative
settlements under and as contemplated by the Incentive Plans in respect of
nonqualified stock options granted thereunder. This Plan also contemplates the
grant of Stock Units under and as contemplated by the 1998 Plan. This Plan and
all rights under it are provided under and shall be subject to and construed
consistently with the other terms of the Management Plan, the Officer Plan, the
1998 Plan or the 2000 Equity Plan, as the case may be, except as the context
otherwise requires.
2.
DEFINITIONS

Whenever the following terms are used in this Plan, they shall have the meaning
specified below unless the context clearly indicates to the contrary:

"ALREADY-OWNED SHARES" shall mean Shares owned by an Eligible Person; provided,
however, that Shares acquired by an Eligible Person from the Company under an
option or other employee benefit plan maintained by the Company or otherwise
must be held by the Eligible Person for at least six months in order to qualify
as Already-Owned Shares and, if Shares are used to pay the exercise price of an
option or other award, such Shares may not be reused as payment of the exercise
price of another option or award within six months of such prior use.

"ALTERNATIVE EXERCISE" shall mean the exercise of all or a portion of a
Qualifying Stock Option using Already-Owned Shares in exchange for a combination
of Shares and Stock Units under this Plan.

"ALTERNATIVE EXERCISE AGREEMENT" shall mean an agreement entered into between
the Company and an Eligible Person in accordance with Article IV of this Plan
pursuant to which the Eligible Person elects to defer that portion of the
proceeds of the exercise of the Qualifying Option equal to the spread in the
form of Stock Units.

"BENEFICIARY" or "BENEFICIARIES" shall mean the person, persons, trust or trusts
(or similar entity), personal representative, or other fiduciary, last
designated in writing by a Participant in accordance with the provisions of
Section 8.2 to receive the benefits specified hereunder in the event of the
Participant's death. If there is no valid Beneficiary designation in effect that
complies with the provisions of Section 8.2, or if there is no surviving
designated Beneficiary, then the Participant's surviving spouse shall be the
Beneficiary. If there is no surviving spouse to receive any benefits payable in
accordance with the preceding sentence, the duly appointed and currently acting
personal representative of the Participant's estate (which shall include either
the Participant's probate estate or living trust) shall be the Beneficiary. In
any case where there is no such

2

personal representative of the Participant's estate duly appointed and acting in
that capacity within 90 days after the Participant's death (or such extended
period as the Committee determines is reasonably necessary to allow such
personal representative to be appointed, but not to exceed 180 days after the
Participant's death), then Beneficiary or Beneficiaries shall mean the person or
persons who can verify by affidavit or court order to the satisfaction of the
Committee that they are legally entitled to receive the benefits specified
hereunder.

"BOARD" shall mean the Board of Directors of the Company.

"CHANGE IN CONTROL EVENT" shall mean any of the following:

(a) The dissolution or liquidation of the Company;

(b) The reorganization, merger or consolidation of the Company with one or more
corporations as a result of which the Company is not the surviving corporation;

(c) The sale of all or substantially all of the property of the Company;

(d) A reorganization, merger, consolidation, or other corporate transaction
which is consummated following the related occurrence of a Distribution Date (as
such term is defined in the Rights Agreement approved by the Board on November
20, 1996) and as a result of which the Company is not the surviving corporation.

"CODE" shall mean the Internal Revenue Code of 1986, as amended.

"COMMITTEE" shall mean those members of the Compensation and Executive Personnel
Committee of the Board of the Company determined under Article VI. "COMMON
STOCK" shall mean the Common Stock of the Company, subject to adjustment
pursuant to Section 5.5 of this Plan, Section 16 of the Management Plan, Section
16 of the Officer Plan, and Section 3.4 of the 1998 Plan, as the case may be.
"COMPANY" shall mean Edison International, a California corporation, and its
successors and assigns.

"CONVERSION DATE" shall mean the date that the Eligible Person exercises all or
a portion of a Qualifying Option in accordance with the Alternative Exercise
procedures under this Plan.

"DISABILITY" shall mean the permanent and total disability of the Participant as
determined by the Committee.

"DISTRIBUTION SUBACCOUNT" shall mean any subaccount established and maintained
under a Participant's Stock Unit Account to separately account for Stock Units
which are subject to different distribution elections made by the Participant.

"DIVIDEND EQUIVALENT" shall mean the amount of cash dividends or other cash
distributions paid by the Company on that number of Shares equal to the number
of Stock Units credited to a Participant's Stock Unit Account as of the
applicable record date for the dividend or other distribution, which amount
shall be credited in the form of additional Stock

3

Units to the Stock Unit Account of the Participant, as provided in Section 5.2.

"EFFECTIVE DATE" shall mean January 1, 1998.

"ELIGIBLE PERSON" shall mean any employee of the Company, Southern California
Edison Company or any other Subsidiary who is eligible to defer compensation
under the terms of the Company Executive Deferred Compensation Plan.
"EXCHANGE ACT" shall mean the Securities Exchange Act of 1934, as amended from
time to time.

"FAIR MARKET VALUE" shall mean on any date the average of the highest and lowest
sale prices of the Common Stock on the Composite Tape, as published in the
Western Edition of The Wall Street Journal, of the principal securities exchange
or market on which the Common Stock is so listed, admitted to trade, or quoted
on such date, or, if there is no trading of (or no available highest and lowest
sale prices of) the Common Stock on such date, then the average of the highest
and lowest sale prices of the Common Stock as quoted on such Composite Tape on
the next preceding date on which there was trading in such shares. If the Common
Stock is not so listed, admitted or quoted, the Committee may designate such
other exchange, market or source of data as it deems appropriate for determining
such value for purposes of this Plan.

"FINANCIAL HARDSHIP" shall mean an unexpected and unforeseen financial
disruption arising from an illness, casualty loss, sudden financial reversal, or
other such unforeseeable occurrence as determined by the Committee. Needs
arising from foreseeable events such as the purchase of a residence or education
expenses for children shall not, alone, be considered a "financial hardship."

"INCENTIVE PLANS" shall mean the Management Plan, the Officer Plan, the 1998
Plan and the 2000 Equity Plan.

"INTEREST RATE" shall mean the rate (quoted as an annual rate) that is 120% of
the federal long-term rate for compounding on a quarterly basis, determined and
published by the Secretary of the United States Department of Treasury under
Section 1274(d) of the Code, for the month for which the interest is credited.

"MANAGEMENT PLAN" shall mean the Company's Management Long-Term Incentive
Compensation Plan.

"1998 PLAN" shall mean the Company's Equity Compensation Plan.

"OFFICER PLAN" shall mean the Company's Officer Long-Term Incentive Compensation
Plan.

"PARTICIPANT" shall mean any person who has Stock Units credited to a Stock Unit
Account under this Plan. "PLAN" shall mean this Edison International Option Gain
Deferral Plan, as it may be amended from time to time.

"QUALIFYING OPTION" or "QUALIFYING STOCK OPTION" shall mean a nonqualified
4

stock option granted under one of the Incentive Plans and evidenced in writing
that provides (or is amended to provide) that the option may be Alternatively
Exercised under this Plan; provided, however, that an option shall not be a
Qualifying Stock Option if it will expire, by its terms, before the end of the
six-month period commencing with the date that the Alternative Exercise
Agreement is submitted to and received by the Company.

"RETIREMENT" shall mean a separation from service under terms constituting a
retirement for purposes of the nonqualified executive retirement plan covering
the Participant.

"RULE 16b-3" shall mean Rule 16b-3 promulgated under the Exchange Act.

"SCHEDULED WITHDRAWAL" shall mean a distribution of all or a portion of the
Stock Units credited to the Participant as elected by the Participant pursuant
to the provisions of Section 5.4(g) of the Plan.

"SHARE" shall mean a share of Common Stock.

"STOCK UNIT" or "UNIT" shall mean a non-voting unit of measurement which is
deemed solely for bookkeeping purposes to be equivalent to one outstanding Share
(subject to Section 5.5) solely for purposes of this Plan.

"STOCK UNIT ACCOUNT" shall mean the bookkeeping account maintained by the
Company on behalf of each Participant which is credited with Stock Units in
accordance with Section 5.1(a) and Dividend Equivalents thereon in accordance
with Section 5.2.

"SUBSIDIARY" shall mean any company that is a "subsidiary company" as defined in
Section 424(f) of the Code.

"TERMINATION FOR CAUSE" shall mean the Termination of Employment of the
Participant upon willful failure by the Participant to substantially perform his
or her duties for the Company or one of its Subsidiaries or the willful engaging
by the Participant in conduct which is injurious to the Company or one of its
Subsidiaries, monetarily or otherwise.

"TERMINATION OF EMPLOYMENT" shall mean the voluntary or involuntary cessation of
the Participant's employment with the Company or a Subsidiary for any reason
other than death or Retirement. Termination of Employment shall not be deemed to
have occurred for purposes of this Plan if the Participant is re-employed by the
Company or a Subsidiary within thirty days of ceasing work with the Company or a
Subsidiary.

"UNSCHEDULED WITHDRAWAL" shall mean a distribution of all or a portion of the
Stock Units credited to the Participant under the Plan as requested by the
Participant pursuant to the provisions of Section 5.4(h) of the Plan.

5

3.
PARTICIPATION

3.1 General Participation Requirements.

An Eligible Person may elect to exercise all or a portion of a Qualifying Option
under and subject to the Alternative Exercise provisions set forth herein and to
receive a credit of Stock Units under this Plan.

3.2 Manner and Timing of Election

An election must be made by the Eligible Person by completing and executing a
form of Alternative Exercise Agreement which meets the requirements of Article
IV and submitting such form to the Company after the Effective Date. Such an
election shall be irrevocable.

3.3 Execution of Alternative Exercise Agreement by the Company.

The Company, acting through any of its officers, shall execute the Alternative
Exercise Agreement form submitted by such Eligible Person and deliver a copy of
such fully executed Alternative Exercise Agreement to him or her.

4.
ALTERNATIVE EXERCISE OF OPTIONS

4.1 Form of Agreement.

Each Alternative Exercise Agreement with respect to a Qualifying Stock Option
shall be in the form approved by the Committee. Each such Alternative Exercise
Agreement shall specify the portion of the Qualifying Stock Option or Qualifying
Stock Options that the Eligible Person elects to exercise under this Plan and
shall provide that (i) the Eligible Person will exercise all or the specified
portion of such Qualifying Stock Option(s) by paying the exercise price with
Already-Owned Shares having an aggregate Fair Market Value equal to the exercise
price for the number of Shares with respect to which the Qualifying Stock Option
is exercised and (ii), upon exercise, the Company will (A) deliver to the
Eligible Person the same number of Shares used by the Eligible Employee to pay
the exercise price of the Qualifying Stock Option and (B), in lieu of the
remainder of the Shares which would otherwise be delivered to the Eligible
Person (the "Gain Shares"), credit to a Stock Unit Account established for the
Eligible Person Stock Units equal in number to the number of Gain Shares.
Subject to applicable law and the intent of this Plan, the Committee may provide
for or permit an alternative method of delivering or tendering Already-Owned
Shares to pay the exercise price of a Qualifying Stock Option.

4.2 Limited Ability to Exercise Option.

Any Qualifying Option (or portion thereof) which is subject to an Alternative
Exercise Agreement may not be exercised at all during the six-month period
following the date the Company receives the Eligible Person's Alternative
Exercise election.

6

4.3 Termination of Alternative Exercise Agreements.

If, prior to the end of the six-month period described in Section 4.2, (a) an
Eligible Person's employment with the Company (including any Subsidiary) is
terminated or (b), unless the Committee otherwise provides, a Change in Control
Event occurs, the Eligible Person's Alternative Exercise Agreement shall
terminate and the related Qualifying Option may be exercised for actual Shares
in accordance with the terms of the Qualifying Option without regard to the
Alternative Exercise Agreement. If the Company unilaterally refuses to honor an
Alternative Exercise of a Qualifying Option pursuant to Section 8.7, the
Alternative Exercise Agreement with respect to such Qualifying Option shall
terminate and such Qualifying Option shall be exercisable for actual Shares in
accordance with its terms without regard to the Alternative Exercise Agreement
or the terms of the Qualifying Option regarding Alternative Exercise.

4.4 Other Terms of Alternative Exercise Agreements.

No Alternative Exercise Agreement shall have the effect of extending the term or
otherwise changing the terms of any Qualifying Option (except as expressly
contemplated hereby in respect of the consequences of exercise). No Alternative
Exercise Agreement may be amended or terminated except as specifically provided
herein.

5.
STOCK UNIT ACCOUNTS

5.1 Crediting of Stock Units.

(a) Crediting of Stock Units. As of the applicable Conversion Date of a
Qualifying Stock Option, an Eligible Person's Stock Unit Account shall be
credited with the number of Stock Units attributable to the Gain Shares, as
described in Section 4.1(a).

(b) Distribution Subaccounts. The Committee shall establish separate
Distribution Subaccounts under a Participant's Stock Unit Account as necessary
to separately account for Stock Units that are subject to different distribution
elections made by the Participant.

(c) Limitations on Rights Associated With Units. A Participant's Stock Unit
Account shall be a memorandum account on the books of the Company. The Units
credited to a Participant's Stock Unit Account shall be used solely as a device
for the determination of the number of Shares to be eventually distributed to
such Participant in accordance with this Plan. The Units shall not be treated as
property or as a trust fund of any kind. No Participant shall be entitled to any
voting or other stockholder rights with respect to Units granted or credited
under this Plan. The number of Units credited (and the Shares to which the
Participant is entitled under this Plan) shall be subject to adjustment in
accordance with Section 5.5 of this Plan, and Section 16 of the Management Plan
or Section 16 of the Officer Plan, Section 3.4 of the 1998 Plan or Section 3.4
of the 2000 Equity Plan, as the case may be.

7

5.2 Dividend Equivalent Credits to Stock Unit Accounts.

As of any applicable dividend or distribution payment date, a Participant's
Stock Unit Account shall be credited with additional Units in an amount equal to
the amount of the Dividend Equivalents divided by the Fair Market Value of a
Share as of the applicable dividend payment date. If the limit on the number of
Shares available under this Plan in respect of Dividend Equivalents is reached,
the Company may in its discretion credit or settle such amounts in cash.

5.3 Vesting.

All Units (including Stock Units credited as Dividend Equivalents) credited to a
Participant's Stock Unit Account shall be at all times fully vested.

5.4 Distribution of Benefits.

(a) Form of Distribution. Stock Units credited to a Participant's Stock Unit
Account shall be distributed in an equivalent whole number of Shares. Fractional
share interests shall be disregarded, but, in the Committee's discretion, may be
accumulated and paid in cash.

(b) Retirement Benefits. No later than sixty days following a Participant's
Retirement, the Committee shall distribute or begin to distribute Shares in
an amount equal to the number of Stock Units credited to the Participant's
Stock Unit Account pursuant to the election made by the Participant in his
or her Alternative Exercise Agreement. The Participant may elect in his or
her Alternative Exercise Agreement to have the Retirement Benefit paid in
one of the following forms:

(i) in a lump sum,

(ii) in installments paid annually over a period of five, ten or fifteen
years, or

(iii) in a lump sum of a portion of the Shares upon Retirement with the
balance in installments paid annually over a period of five, ten or
fifteen years.

If no valid election is made, the Committee shall distribute the Retirement
Benefits in a lump sum. Notwithstanding the foregoing or anything to the
contrary in Section 5.4(c) below, the Committee may, in its sole discretion:

(iv) distribute the benefits in a single lump sum if the sum of Shares to
be distributed to the Participant is less than or equal to 1,000, or

(v) reduce the number of installments elected by the Participant to
produce an annual distribution of at least 100 Shares.

(c) Termination Benefits. No later than 60 days after Termination of Employment,
the Committee shall distribute or commence to distribute Shares in an amount
equal to the number of Units credited to the Participant's Stock Unit Account.
The Shares shall be distributed in a single lump sum unless the Participant
elected three annual installments in his or her Alternative Exercise Agreement.
Notwithstanding the foregoing, if the Participant's Termination of Employment is
a Termination for Cause, the Committee shall distribute the shares in a lump
sum.

8

(d) Survivor Benefits. If the Participant dies while actively employed by the
Company or a Subsidiary, the Committee shall distribute or commence to
distribute to the Participant's Beneficiary the number of Shares equal to the
number of Units credited to the Participant's Stock Unit Account in accordance
with the Participant's election for Retirement Benefits within sixty days after
the Participant's death. If the Participant dies after Retirement, the Committee
shall distribute to the Participant's Beneficiary the remaining Shares
distributable to the Participant under the Plan over the same period that the
Shares would have been distributed to the Participant. If the Participant dies
following Termination of Employment, but prior to the distribution of all Shares
distributable to the Participant, the Committee shall deliver the remaining
Shares to the Participant's Beneficiary in a lump sum. Beneficiaries may
petition the Committee once, and only after the death of the Participant, for a
change in the form of survivor benefits. The Committee may, in its sole and
absolute discretion, choose to grant or deny such a petition. Notwithstanding
the foregoing, the Committee may, in its sole discretion:

(i) distribute the Shares in a single lump sum if the total number of the
Shares distributable to the Beneficiary is less than or equal to
1,000, or

(ii) reduce the number of installments elected by the Participant to ten or
five if necessary to produce an annual benefit of at least 100 Shares.

(e) Disability. In the event that a Participant has suffered a Disability, the
Committee shall distribute shares upon the Participant's Termination of
Employment, Retirement or death according to the Participant's prior election.

(f) Effect of Change in Control Event. Notwithstanding Section 5.4(a) and unless
the Committee provides in advance that no such acceleration shall occur in
connection with a specific Change in Control Event, then upon the occurrence of
a Change in Control Event, cash equal to the Fair Market Value, as of the date
immediately preceding the Change in Control Event, of the number of Shares equal
to the number of Stock Units then credited to the Participant's Stock Unit
Account shall be distributed immediately in a lump sum to the Participant.

(g) Scheduled Withdrawals. When completing an Alternative Exercise Agreement, a
Participant may elect to receive a distribution of a specific number of Shares
or a percentage of Shares deferred under such Alternative Exercise Agreement on
the first business day of the calendar year which is at least the second
calendar year following the calendar year in which the Qualifying Option is
Alternatively Exercised. Any Scheduled Withdrawal Election shall be superseded
by distributions due to the Retirement, Termination of Employment or death of
the Participant.

(h) Unscheduled Withdrawals. A Participant (or Beneficiary if
the Participant is deceased) may request in writing to the Committee a
distribution of Shares in an amount equal to all or a portion of the Units
credited to his or her Stock Unit Account, which shall be distributed in a lump
sum within thirty days; provided, that

(i) the minimum distribution shall be 25% of the Stock Unit Account,

9

(ii) an election to receive 75% or more of the Stock Unit Account shall be
deemed to be an election to receive the entire Stock Unit Account, and

(iii) such an election may be made only once in a Plan Year.

There shall be a penalty deducted from the Stock Unit Account prior to an
Unscheduled Withdrawal equal to 10% of the Shares to be delivered under the
Unscheduled Withdrawal. Notwithstanding the foregoing, if the number of Units
credited to the Stock Unit Account of the Participant or Beneficiary who has
requested an Unscheduled Withdrawal is less than or equal to 1,000, the
Committee may, in its sole discretion, elect to distribute Shares in an amount
equal to all of the Units credited, reduced by the 10% penalty, in a single lump
sum.

(i) Financial Hardship Distribution. A Participant or Beneficiary may submit a
hardship distribution request to the Committee in writing setting forth the
reasons for the request. The Committee shall have the sole authority to approve
or deny such requests. Upon a finding that the Participant or the Beneficiary
has suffered a Financial Hardship, the Committee may in its sole discretion,
accelerate distributions of Shares under the Plan in the amount reasonably
necessary to alleviate the Financial Hardship.

(j) Section 162(m) Limitation. Notwithstanding the foregoing, if the Committee
determines in good faith that there is a reasonable likelihood that any benefits
paid to a

Participant for a taxable year of the Company would not be deductible by the
Company or a Subsidiary solely by reason of the limitation under Code Section
162(m), then to the extent reasonably deemed necessary by the Committee to
ensure that the entire amount of any distribution to the Participant pursuant to
this Plan is deductible, the Committee may defer all or any portion of a
distribution under this Plan. The amounts so deferred shall be distributed to
the Participant or his or her Beneficiary (in the event of the Participant's
death) at the earliest possible date, as determined by the Committee in good
faith, on which the deductibility of compensation paid or payable to the
Participant for the taxable year of the Company during which the distribution is
made will not be limited by Code Section 162(m).

(k) Changes in Distribution Elections. Participants may change the form of
payout upon termination of employment due to Retirement, Termination of
Employment (other than Termination for Cause) or death by written election filed
with the Committee; provided, however, that if the Participant files the
election less than thirteen months prior to the date of such termination of
employment, the payout election in effect thirteen months prior to such
termination date shall govern.

10

5.5 Adjustments in Case of Changes in Common Stock.

(a) If the outstanding Shares are increased, decreased, or exchanged for a
different number or kind of securities, or if additional shares or new or
different shares or other securities are distributed with respect to such Shares
or other securities, through merger, consolidation, sale of all or substantially
all of the assets of the Company, reorganization, recapitalization, stock
dividend, stock split, reverse stock split or similar change in capitalization
or any other distribution with respect to such Shares or other securities,
proportionate and equitable adjustments consistent with the effect of such event
on stockholders generally (but without duplication of benefits if Dividend
Equivalents are credited) shall be made in the number and type of Shares or
other securities, property and/or rights contemplated hereunder and of rights in
respect of Units and Stock Unit Accounts credited under this Plan so as to
preserve the benefits intended. The provisions of Section 16 of the Management
Plan, Section 16 of the Officer Plan, Section 3.4 of the 1998 Plan and Section
3.4 of the 2000 Equity Plan shall also apply to the related Stock Units granted
under the Incentive Plans in accordance with this Plan.

(b) If the event results in any rights of stockholders to receive cash (other
than cash dividends and cash distributions), a corresponding amount of cash
shall be credited to each Participant's Stock Unit Account (or, if applicable,
the appropriate Distribution Subaccount of the Participant's Stock Unit Account)
as of the date that cash is paid in respect of outstanding Shares. As of the
last day of each calendar quarter, the Participant's Stock Unit Account shall be
credited with earnings on the cash balance credited to such Stock Unit Account
as of the last day of the preceding quarter or, if later, the date of such
event, at a rate (on an annualized basis) equal to the Interest Rate. The amount
of cash credited to a Participant's Stock Unit Account shall be distributed in
cash at such time (or times) and in such manner as otherwise provided under this
Plan and/or the applicable election made by the Participant in accordance with
the terms of this Plan.

5.6 Company's Right to Withhold.

The Company (including its Subsidiaries) may satisfy any state or federal tax
withholding obligation arising upon a distribution of Shares and any cash with
respect to a Participant's Stock Unit Account by reducing the number of Shares
or cash otherwise deliverable to the Participant. The appropriate number of
Shares required to satisfy such tax withholding obligation in the case of Stock
Units will be based on the Fair Market Value of a Share on the day prior to the
date of distribution. If the Company (including its Subsidiaries), for any
reason, elects not to (or cannot) satisfy the withholding obligation in
accordance with the preceding sentence, the Participant shall pay or provide for
payment in cash of the amount of any taxes which the Company (including its
Subsidiaries) may be required to withhold with respect to the benefits
hereunder, before any such benefits are paid.

11

6.
ADMINISTRATION

6.1 The Administrator.

The Committee hereunder shall consist of (i) the members of the Compensation and
Executive Personnel Committee of the Board who are Non-Employee Directors within
the meaning of Rule 16b-3 and "outside directors" for purposes of Section 162(m)
of the Code, or (ii) such other committee of the Board, each participating
member of which is a Non-Employee Director (as defined in Rule 16b-3) and each
member of which is an "outside director" for purposes of Section 162(m) of the
Code, as may hereafter be appointed by the Board to serve as administrator of
this Plan. Any member of the Committee may resign by delivering a written
resignation to the Board. Members of the Committee shall not receive any
additional compensation for administration of this Plan.

6.2 Committee Action.

Action of the Committee with respect to the administration of this Plan shall be
taken pursuant to a majority vote or by unanimous written consent of its
members. A member of the Committee shall not vote or act upon any matter which
relates solely to himself or herself as a Participant in this Plan.

6.3 Rights and Duties.

(a) Subject to the limitations of this Plan, the Committee shall be charged with
the general administration of this Plan and the responsibility for carrying out
its provisions, and shall have powers necessary to accomplish those purposes,
including, but not by way of limitation, the following:

(i) To construe and interpret this Plan;

(ii) To resolve any questions concerning the amount of benefits payable to
a Participant;

(iii)To make all other determinations required by this Plan, including
adjustments under Section 5.5.;

(iv) To maintain all the necessary records for the administration of this
Plan and provide statements of Stock Unit Accounts to Participants on
an annual or more frequent basis;

(v) To make and publish forms, rules and procedures for the administration
of this Plan; and

(vi) To administer the claims procedures set forth in Section 6.5 for
presentation of claims by Participants and Beneficiaries for benefits
under this Plan, including consideration of such claims, review of
claim denials and issuance of a decision on review.

12

(b) The Committee shall have full discretion to construe and interpret the terms
and provisions of this Plan (but not to increase amounts payable hereunder) and
to resolve any disputed question or controversy, which interpretation or
construction or resolution, including decisions with respect to adjustments
under Section 5.5, shall be final and binding on all parties, including but not
limited to the Company and any Eligible Person, Participant or Beneficiary,
except as otherwise required by law. The Committee shall administer such terms
and provisions in a nondiscriminatory manner and in full accordance with any and
all laws applicable to the Plan. In performing its duties, the Committee shall
be entitled to rely on information, opinions, reports or statements prepared or
presented by: (i) officers or employees of the Company whom the Committee
believes to be reliable and competent as to such matters; and (ii) counsel (who
may be employees of the Company), independent accountants and other persons as
to matters which the Committee believes to be within such persons' professional
or expert competence. The Committee shall be fully protected with respect to any
action taken or omitted by it in good faith pursuant to the advice of such
persons. The Committee may delegate ministerial, bookkeeping and other
non-discretionary functions to individuals who are officers or employees of the
Company.

6.4 Indemnity and Liability.

All expenses of the Committee shall be paid by the Company and the Company shall
furnish the Committee with such clerical and other assistance as is necessary in
the performance of its duties. No member of the Committee shall be liable for
any act or omission of any other member of the Committee nor for any act or
omission on his or her own part. To the extent permitted by law, the Company
shall indemnify and save harmless each member of the Committee against any and
all expenses and liabilities arising out of his or her membership on the
Committee.

6.5 Claims Procedure.

(a) The Committee shall notify Participants and, where appropriate,
Beneficiaries of their right to claim benefits under these claims procedures,
shall make forms available for filing of such claims, and shall provide the name
of the person or persons with whom such claims should be filed.

(b) The Committee shall act upon claims as required and communicate a decision
to the claimant promptly and, in any event, not later than 90 days after the
claim is received by the Committee, unless special circumstances require an
extension of time for processing the claim. If an extension is required, notice
of the extension shall be furnished to the claimant prior to the end of the
initial 90-day period, which notice shall indicate the reasons for the extension
and the expected decision date. The extension shall not exceed 90 days. The
claim may be deemed by the claimant to have been denied for purposes of further
review described below in the event a decision is not furnished to the claimant
within the period described in the preceding three sentences. Every claim for
benefits which is denied shall be denied by written notice setting forth in a
manner calculated to be understood by the claimant (i) the specific reason or
reasons for the denial, (ii) specific reference to any provisions of this Plan
on which denial is based, (iii) description of any additional material

13

or information necessary for the claimant to perfect his claim with an
explanation of why such material or information is necessary, and (iv) an
explanation of the procedure for further review of the denial of the claim under
the Plan.

(c) The claimant or his or her duly authorized representative shall have 60 days
after receipt of denial of his or her claim to request a review of such denial,
the right to review all pertinent documents and the right to submit issues and
comments in writing. Upon receipt of a request for a review of the denial of a
benefit claim, the Committee shall undertake a full and fair review of the
denial.

(d) The Committee shall issue a decision not later than 60 days after receipt of
a request for review from a claimant unless special circumstances, such as the
need to hold a hearing, require a longer period of time, in which case a
decision shall be rendered as soon as possible but not later than 120 days after
receipt of the claimant's request for review. The decision on review shall be in
writing and shall include specific reasons for the decision written in a manner
calculated to be understood by the claimant with specific reference to any
provisions of this Plan on which the decision is based.

7.
PLAN CHANGES AND TERMINATION

7.1 Amendments.

The Committee shall have the right to amend this Plan in whole or in part from
time to time or may at any time suspend or terminate this Plan; provided,
however, that no amendment or termination shall cancel or otherwise adversely
affect in any way, without his or her written consent, any Participant's rights
with respect to Stock Units and Dividend Equivalents (and any cash credited
pursuant to Section 5.5(b)) credited to his or her Stock Unit Account. Any
amendments authorized hereby shall be stated in an instrument in writing, and
all Eligible Persons shall be bound thereby upon receipt of notice thereof.
Adjustments pursuant to Section 5.5 hereof, Section 16 of the Management Plan,
Section 16 of the Officer Plan, Section 3.4 of the 1998 Plan or Section 3.4 of
the 2000 Equity Plan shall not be deemed amendments to this Plan, the Stock Unit
Accounts or the rights of Participants.

7.2 Term.

It is the current expectation of the Company that this Plan shall be continued
indefinitely, but continuance of this Plan is not assumed as a contractual
obligation of the Company. In the event that the Committee decides to
discontinue or terminate this Plan, it shall notify the Participants in this
Plan of its action in writing, and this Plan shall be terminated at the time
therein set forth. All Participants shall be bound thereby. In such event, the
then credited benefits of a Participant shall be immediately distributed in a
lump sum.

14

8.
MISCELLANEOUS

8.1 Limitation on Participant Rights.

Participation in this Plan shall not give any person the right to continued
employment or service or any rights or interests other than as herein provided.
No Participant shall have any right to any payment or benefit hereunder except
to the extent provided in this Plan. This Plan creates no fiduciary duty to
Participants and shall create only a contractual obligation on the part of the
Company as to such amounts; the Plan shall not be construed as creating a trust.
The Plan, in and of itself, has no assets. Participants shall have rights no
greater than the right to receive the Common Stock (and any cash as expressly
provided herein) or the value thereof as a general unsecured creditor in respect
of their Stock Unit Accounts.

8.2 Beneficiary Designation.

Upon forms provided by and subject to conditions imposed by the Company, each
Participant may designate in writing the Beneficiary or Beneficiaries whom such
Participant desires to receive any Shares or amounts payable under this Plan
after his or her death. A Participant may from time to time change his or her
designated Beneficiary or Beneficiaries without the consent of such Beneficiary
or Beneficiaries by filing a new designation with the Committee. However, if a
married Participant wishes to designate a person other than his or her spouse as
Beneficiary, such designation shall be consented to in writing by the spouse,
which consent shall acknowledge the effect of the designation. The Participant
may change any election designating a Beneficiary or Beneficiaries without any
requirement of further spousal consent if the spouse's consent so provides.
Notwithstanding the foregoing, spousal consent shall be unnecessary if it is
established (to the satisfaction of the Committee or a Committee representative)
that there is no spouse or that the required consent cannot be obtained because
the spouse cannot be located. The Company and the Committee may rely on the
Participant's designation of a Beneficiary or Beneficiaries last filed in
accordance with the terms of this Plan. Upon the dissolution of marriage of a
Participant, any designation of the Participant's former spouse as a Beneficiary
shall be treated as though the Participant's former spouse had predeceased the
Participant, unless (a) the Participant executes another Beneficiary designation
that complies with this Section 8.2 and that clearly names such former spouse as
a Beneficiary, or (b) a court order is presented to the Company that requires
the former spouse be maintained as the Beneficiary. In any case where the
Participant's former spouse is treated under the Participant's Beneficiary
designation as having predeceased the Participant, no heirs or other
beneficiaries of the former spouse shall receive benefits from the Plan as a
Beneficiary of the Participant except as provided otherwise in the Participant's
Beneficiary designation.

15

8.3 Payments to Minors or Persons Under Incapacity.

If any amount is payable under this Plan to a minor, payment shall not be made
to the minor, but instead shall be paid (i) to that person's then living
parent(s) to act as custodian, (ii) if that person's parents are then divorced,
and one parent is the sole custodial parent, to such custodial parent, or (iii)
if no parent of that person is living, to a custodian selected by the Committee
to hold the funds for the minor under the Uniform Transfers or Gifts to Minors
Act in effect in the jurisdiction in which the minor resides. If no parent is
living and the Committee decides not to select another custodian to hold the
funds for the minor, then payment shall be made to the duly appointed and
currently acting guardian of the estate for the minor or, if no guardian of the
estate for the minor is duly appointed and currently acting within 60 days after
the date the amount becomes payable, payment shall be deposited with the court
having jurisdiction over the estate of the minor.

8.4 Stock Units and Other Benefits Not Assignable; Obligations Binding Upon
Successors.

Stock Units and other benefits of a Participant under this Plan shall not be
assignable or transferable and any purported transfer, assignment, pledge or
other encumbrance or attachment of any payments or benefits under this Plan, or
any interest therein, other than by operation of law or pursuant to Section 8.2,
shall not be permitted or recognized. Obligations of the Company under this Plan
shall be binding upon successors of the Company.

8.5 Employment Taxes.

The Company (including its Subsidiaries) may satisfy any state or federal
employment tax withholding obligation arising from an Alternative Exercise of a
Qualifying Option under the Plan by deducting such amount from any amount of
compensation payable to the Participant. Alternatively, the Company (including
its Subsidiaries) may require the Participant to deliver to it the amount of any
such withholding obligation as a condition to the Alternative Exercise of the
Qualifying Option.

8.6 Governing Law; Severability.

The validity of this Plan or any of its provisions shall be construed,
administered and governed in all respects under and by the laws of the State of
California. If any provisions of this instrument shall be held by a court of
competent jurisdiction to be invalid or unenforceable, the remaining provisions
hereof shall continue to be fully effective.

8.7 Compliance With Laws.

This Plan, the Company's acceptance of the exercise price of a Qualifying Option
in the form of Shares, the Company's issuance of Stock Units, and the offer,
issuance and delivery of Shares and/or the payment in Shares through the
deferral of compensation under this Plan are subject to compliance with all
applicable federal and state laws, rules and regulations (including but not
limited to state and federal securities law) and to such

16

approvals by any listing, agency or any regulatory or governmental authority as
may, in the opinion of counsel for the Company, be necessary or advisable in
connection therewith. Any securities delivered under this Plan shall be subject
to such restrictions, and the person acquiring such securities shall, if
requested by the Company, provide such assurances and representations to the
Company as the Company may deem necessary or desirable to assure compliance with
all applicable legal requirements. If the Company in its sole discretion
determines that an Alternative Exercise of a Qualifying Option would violate any
law, rule or regulation, the Company may refuse to honor such Alternative
Exercise.

8.8 Plan Construction.

It is the intent of the Company that transactions pursuant to this Plan satisfy
and be interpreted in a manner that satisfies the applicable requirements of
Rule 16b-3 so that to the extent elections are timely made, the crediting of
Stock Units and the distribution of Shares with respect to Stock Units under
this Plan will be entitled to the benefits of Rule 16b-3 or other exemptive
rules under Section 16 of the Exchange Act and will not be subjected to
avoidable liability thereunder.

8.9 Headings Not Part of Plan

Headings and subheadings in this Plan are inserted for reference only and are
not to be considered in the construction of the provisions hereof.

IN WITNESS WHEREOF, the Company has caused its duly authorized officer to
execute this Plan on this 15th day of September, 2000.

EDISON INTERNATIONAL

/s/ John H. Kelly
- ------------------------------------
John H. Kelly, Senior Vice President

EXH 10.30
LOGO
GOVERNOR GRAY DAVIS

April 9, 2001

Mr. John E. Bryson
Southern California Edison Company
PO Box 800
Rosemead, CA 91770

Dear John:

I am pleased that Southern California Edison Company (SCE), Edison International
(EIX) and the California Department of Water Resources (CDWR) have negotiated a
final Memorandum of Understanding to implement our agreement in principle. I
know this has been a complex job, and that each and every term of the MOU is
interdependent and essential.

I firmly believe that the agreements contained in the MOU are in the best
interests of the people of California. I support them fully and will work for
the complete implementation of the MOU.

Your personal leadership and the tireless work of your team were critical to
this achievement. I hope you will convey to the Boards of Directors of SCE and
EIX my appreciation for their commitment to this effort and my assurances of
support for the MOU.

Sincerely,

/s/ Gray Davis
Gray Davis

MEMORANDUM OF UNDERSTANDING

THIS MEMORANDUM OF UNDERSTANDING ("MOU") is being entered into as of April
9, 2001, by and among the California Department of Water Resources ("CDWR")
separate and apart from its powers and responsibilities with respect to the
State Water Resources Development System, and Southern California Edison
Company, a California corporation ("SCE"), and, as to Sections 5, 8 and 12,
Edison International, a California corporation ("EIX"). 1. Purpose

The purposes of this MOU are to:

o Set forth the understandings reached by the parties above (the "Parties")
about a plan (the "Plan") to provide affordable and reliable electricity to
customers of SCE by, among other things, maintaining the output of SCE's
retained generation on a cost-of-service basis, providing for CDWR or
another authorized agency of the State of California (the "State") to
acquire SCE's transmission system (or certain other assets if the sale of
the transmission system is not consummated under certain circumstances)
(the "Transmission Sale"), dedicating a new generating facility owned by an
EIX company to cost-of-service based rates for at least 10 years, and
providing for easements and potential conveyances in fee of certain lands
described herein to ensure the long-term conservation of these lands for
their public interest value; and

o Provide a framework for the timely implementation of those understandings;
and

1

o As part of that implementation, provide for the resolution of certain
claims which SCE has asserted against the State of California and certain
agencies and subdivisions thereof.

It is expressly understood that the Parties will act in good faith to
implement all the elements of this MOU, and that the Governor of the State of
California has endorsed such implementation. Such implementation shall include
seeking to obtain the consents and authorizations contemplated herein. In
addition, it is expressly understood that there is no intention to change SCE's
continuing to be a public utility that is subject to the jurisdiction of the
California Public Utilities Commission (the "CPUC"). The Parties recognize, in
order for a number of the initiatives contemplated by this MOU to be fulfilled,
certain actions and approvals will need to be obtained by SCE from the CPUC in
an appropriate proceedings. Those actions and approvals are referred to herein
as the "CPUC Implementing Decisions." Inasmuch as the CPUC is an independent
regulatory agency which may within its discretion determine to adopt or not
adopt the actions and approvals that are described herein as "CPUC Implementing
Decisions," this MOU provides for certain rights on the part of SCE to terminate
the implementation of this MOU in the event that the CPUC does not adopt all of
the actions and approvals expressly characterized herein as "CPUC Implementing
Decisions" within the period of sixty (60) days after the date of the execution
of this MOU by all Parties.

Subject to legislation that may be adopted implementing this MOU and to the
CPUC Implementing Decisions, nothing herein shall prohibit the CPUC from
employing ratemaking and regulatory techniques, methods and standards that have
been historically used and may be used or implemented in the regulation of
public utilities.

Nothing herein is intended to provide SCE with actual recovery of a cost
more than once. In such instance, if any, the CPUC is authorized to adjust rates
to prevent multiple recovery of such cost.

2

2. General Overview

The Plan is comprised of the elements described in more detail in Sections
3 through 14 of this MOU. The Plan will be implemented through a combination of
the following:

o Legislative action, including, but not limited to, authorizing CDWR or
another State entity to acquire the SCE transmission assets and enter into
and implement the applicable contracts and activities contemplated herein,
and, as applicable or necessary, authorizing and/or directing the CPUC to
take certain actions called for hereby;

o Contracts directly between SCE and CDWR or other pertinent State agencies;

o Regulatory decisions, including actions by the Federal Energy Regulatory
Commission ("FERC") and the CPUC Implementing Decisions;

o Entry of a stipulated judgment in, or other form of mutually acceptable
disposition of, SCE's federal court lawsuit; and

o Releases or assignments of mutually agreed upon identified claims by SCE
against third parties subject to the conditions specified herein.

The Parties agree that the elements of the Plan are an integrated package,
and this MOU does not obligate any of the Parties to support any individual
element separate from the entire package. Further principles of implementation
are set forth in Section 15, and agreed upon next steps are provided in Section
16.

The proceeds from the transactions contemplated herein are intended to
eliminate SCE's net undercollected amount as of January 31, 2001, as described
herein. Accordingly, except as otherwise provided herein, proceeds received from
the securitizations

3

and Transmission Sale described herein will be applied to reduce payments
due for the procurement of power that are included in, and indebtedness (and
refinancings thereof) incurred by SCE to finance, the net undercollected amount.
In connection with the execution of the Purchase and Sale Agreement (as defined
in Section 4(b)), SCE will deliver to CDWR a schedule of sources and uses
setting forth SCE's uses of the proceeds being applied to the net undercollected
amount.

3. Utility Retained Generation

Subject to execution of the Definitive Agreements (as defined in Section
4(b)), adoption of the CPUC Implementing Decisions, and adoption of the
legislation contemplated hereby, SCE's generation assets, including all energy,
capacity, ancillary services, and any combination thereof, to which SCE has a
contractual right (collectively "URG"), will be committed to cost-based
ratemaking for SCE's bundled service customers, and SCE will not seek authority
to sell such assets, through December 31, 2010. In addition, SCE will operate
its URG in accordance with good utility practices, subject to the further terms
hereof. SCE's URG includes its interests in Units 2 and 3 of the San Onofre
Nuclear Generating Station ("SONGS"), the Palo Verde Nuclear Generating Station
("PVNGS"), the Mohave Generating Station ("Mohave"), the Four Corners Generating
Station ("Four Corners"), SCE's hydroelectric facilities ("Hydro Facilities"),
and the Pebbly Beach generating facility. URG also includes, for their
respective terms, power purchase contracts that SCE currently has, and other
contractual rights that SCE currently has, to purchase energy, capacity,
ancillary services and any combination thereof, from other utilities, power
suppliers or qualifying facilities. Consistent with the purposes of this
paragraph, SCE will withdraw its pending application with the CPUC to sell its
Mohave, PVNGS and Four Corners facilities.

This MOU does not address any aspects of the status and ratemaking
treatment of the URG or the ratemaking treatment therefore after December 31,
2010, and does not

4

bind any party to any obligation or exempt any party from any requirement
in respect thereof.

In return, subject to execution of the Definitive Agreements, the adoption
of the legislation contemplated hereby and the adoption or approval of the CPUC
Implementing Decisions, SCE will be entitled to collect revenues sufficient to
cover its costs from January 1, 2001, associated with its URG (and all costs for
ancillary services or other ISO costs associated with CDWR's procurement of the
net short allocated to SCE under Section 10) on a timely basis, in accordance
with the principles of cost-based ratemaking as applied in this State. In this
regard, one of the CPUC Implementing Decisions shall be the adoption by the CPUC
of procedures (which may include one or more balancing accounts and trigger
mechanisms) designed to ensure that any undercollection or overcollection of URG
costs (provided that actual costs of utility-owned generation shall equal
authorized costs, except for variable fuel costs) will be reconciled in a timely
manner and that any undercollection can be financed on reasonable terms
consistent with SCE being an investment grade credit (the "URG Cost Recovery
Mechanism"). The legislation necessary for the implementation of the Plan shall
include legislation overriding any applicable limits in A.B. 1890 which may be
inconsistent with the foregoing recovery principle. For the period from January
1 through 31, 2001, SCE will be deemed to have recovered its costs associated
with its URG through the operation of the Transition Cost Balancing Account
("TCBA"), except for depreciation and amortization that SCE shall recover as a
capital-related cost as described below.

Subject to the further provisions of this MOU respecting recovery of
investments, and the ratemaking principles set forth herein, a CPUC Implementing
Decision shall provide that SCE's costs associated with its URG will include,
through December 31, 2010:

o All customary categories of operating costs, including, but not limited to,
fuel costs (fixed and variable), operations and maintenance expenses, costs
of emissions credits (subject to the further provisions of Section 7),
direct, joint and common administrative and general (A&G) costs (excluding

5

non-site specific general plant, which shall be treated as a capital cost),
taxes, scheduling and dispatch costs, congestion costs, ancillary service
costs, and other transmission-related costs charged to generators.

o For SONGS 2 and 3, other than transmission-related costs, operating costs
will be recovered through 2003 through the existing Incremental Cost
Incentive Procedure ("ICIP") and will be recovered without regard to the
ICIP mechanism thereafter.

o All reasonably recorded capital-related costs, including a full return on
SCE's investment in used and useful URG (except as provided herein with
respect to SONGS 2 and 3). SCE's investment in URG will be set at the net
book value of such assets on December 31, 2000, including site specific and
non-site specific general plant and capital additions made after December
31, 1995, the costs of which have been reasonably and prudently incurred,
together with their associated income tax regulatory receivable or payable,
provided that the $129,783,000 of non-nuclear site-specific general plant
and capital additions made after December 31, 1995 and described on a
schedule that has been provided to CDWR and which have not to date been
disapproved by the CPUC shall be allowed in SCE's rate base temporarily
until the final approval or disapproval of such additions which shall be
accomplished by the CPUC as soon as practicable. Depreciation schedules
will be based on the expected remaining useful life of each plant, fixed
for this purpose for the period ending December 31, 2010 for SONGS 2 and 3
and PVNGS. For purposes of this Section 3, "net book value" means the
original cost recorded in SCE's books for a particular asset, less any
accumulated depreciation or amortization plus any deferred or flow through
taxes. Assets that have been expensed shall not have a book value.

6

o All reasonable and prudent incremental capital investments put into service
after December 31, 2000. Such investments, including income taxes and a
full return on investment, will be recovered in rates from the time they
are placed in service. Incremental investment which has not otherwise been
expensed will be depreciated over the expected remaining useful life of the
plant in question, which for purposes of SONGS 2 and 3 and PVNGS, will be
determined by the remaining term of the applicable license for each plant,
granted to SCE by the Nuclear Regulatory Commission ("NRC"), as such
licenses may be extended by the NRC. Notwithstanding anything to the
contrary in this Section 3, through 2003 incremental capital expenditures
for SONGS 2 and 3 will be recovered through the ICIP mechanism.

Operating decisions, including dispatch decisions, maintenance practices,
energy/capacity exchange decisions, and other operating practices shall be
performed by SCE in a reasonable and prudent manner.

Under current CPUC decisions, net revenues from PVNGS after 2001 and net
revenues from SONGS 2 and 3 after 2003 are subject to a sharing mechanism
whereby profits (as defined) are shared equally between shareholders and
customers. A CPUC Implementing Decision shall provide that such sharing
mechanism, and all associated provisions for transfer of post-ICIP cost
responsibility to SCE, will be eliminated through December 31, 2010. The
existing memorandum of understanding respecting SCE's Hydro Facilities will be
rendered moot, and SCE will withdraw its associated application under Public
Utilities Code section 377.

7

4. Transmission Sale

(a) Purchase of Assets and Assumed Liabilities

Subject to enabling legislation and the negotiation and execution of the
pertinent contracts, CDWR, or another authorized State agency (the "Purchaser"),
will purchase SCE's transmission system.

Subject to the further provisions of this MOU, the Transmission Sale
includes all of SCE's right, title, and interest to: (i) all transmission assets
under ISO control; (ii) any other assets not under ISO control that are used
exclusively in connection with transmission and included in SCE's FERC rates
charged to SCE's bundled service customers, or, in the case of any such assets
acquired after the date of such rates, includable in SCE's FERC rates charged to
SCE's bundled service customers; and (iii) related agreements and contracts. The
transmission assets shall also include rights to the real property associated
with or held for use in connection with the transmission system ("Real
Property") as well as other mutually agreed-upon assets and rights of SCE in
assets which are subject to joint interests of other parties, including shared
assets and rights, it being understood by the parties that the transmission
assets to be acquired by the Purchaser, whether through the acquisition of
assets to be exclusively owned by the Purchaser or through the acquisition of
rights in shared assets, shall be sufficient for the Purchaser to acquire a
functional transmission system capable of providing transmission services of the
type that it has in the past, with sufficient rights to repair and upgrade the
transmission system and to operate it efficiently and effectively. It is also
understood by the Parties that SCE's transmission system has been built and
operated on a fully integrated basis with SCE's distribution system and that the
Purchaser's operation of the transmission system and SCE's operation of the
distribution system will therefore necessarily involve mutually acceptable
arrangements for the sharing by SCE and the Purchaser of certain systems and
assets to avoid duplicative and potentially substantial costs to ratepayers and
taxpayers. To the extent the Purchaser desires physical separation of
transmission assets from distribution

8

assets, the costs of such separation, if feasible, will be borne by the
Purchaser. The Real Property and other assets included in the Transmission Sale
are collectively referred to herein as, the "Purchased Assets." Subject to the
further provisions of this MOU, title transferred to the Purchaser will be the
same as SCE's title, provided that the Purchased Assets will be transferred free
and clear of liens and encumbrances securing SCE's indebtedness for money
borrowed or other obligations of SCE not related to the transferred assets or
(unless the same has been adjusted for in the purchase price or in prorations)
not required to be assumed by the Purchaser hereunder; provided, that the
Definitive Agreements shall include provisions pursuant to which, if SCE is
unable, after using commercially reasonable efforts, to obtain the release of
any liens or encumbrances which it is responsible to release in connection with
the sale of the Purchased Assets (other than liens or encumbrances securing
indebtedness for borrowed money), then such failure shall not be a failure of
the foregoing condition or otherwise a default on the part of SCE if SCE is
diligently contesting such lien or encumbrance; SCE indemnifies the Purchaser
from and against any liability, damage, cost or expense incurred by it on
account thereof; and such lien or encumbrance has no material adverse effect on
Purchaser's ownership or operation of a functional transmission system capable
of providing transmission services of the type that it has in the past, with
sufficient rights to repair and upgrade the transmission system and to operate
it efficiently and effectively.

SCE will retain all of its right, title and interest in and to its
existing assets used exclusively in the operation of its non-transmission
business, such as generation assets (other than designated assets specified in
the Purchase and Sale Agreement, such as mutually agreed upon radial lines),
assets used in SCE's distribution business, communications facilities,
protection systems, control facilities and oil pipeline assets, and SCE will
retain rights in other assets necessary for such businesses to continue to
provide the services as they have in the past. The Purchase and Sale Agreement
will set forth the procedures and methods for transferring and retaining
interests in assets that are to be shared by the Parties after the closing
(because of the integrated nature of the transmission and distribution
businesses), provided that each Party will be entitled to the economic benefit

9

of its ownership or rights in a shared asset. The Parties will in any event
grant and reserve, as appropriate, such licenses, easements and reciprocal
easements as may be necessary or, in the reasonable judgment of the Parties,
desirable, to permit the Parties to own, operate and maintain their respective
assets and their interests therein. Such licenses, easements and reciprocal
easements shall, among other things, assure ingress, egress, access, utilities
and support; permit maintenance, relocation, construction and alteration; and
protect against encroachment, all as provided for in the Definitive Agreements
and subject to appropriate limitations and protections to be provided for
therein.

If, following the Transmission Sale, the Purchaser decides to explore
the possible offer for sale of all or substantially all of the Purchased Assets
(including all or substantially all of a larger transmission grid of which the
Purchased Assets may then form a part) through a competitive bidding process,
the Purchase and Sale Agreement will provide to SCE a non-exclusive opportunity
to bid for all, but not less than all, of the assets the Purchaser proposes to
sell, on the same terms and conditions as may be applicable to the other bidders
generally.

The Purchase and Sale Agreement will contain mutually agreed upon
representations and warranties, which will not include any representations and
warranties regarding or related to the physical condition of the Purchased
Assets, but will include covenants regarding operations in the ordinary course.
The assets will be sold to the Purchaser on an "AS IS, WHERE IS" and "WITH ALL
FAULTS" basis, and the Purchaser will assume all liabilities to the extent
related to the transferred assets, including all contractual obligations
(including obligations to provide transmission service and, without limiting the
parties' obligations under other provisions of this MOU, SCE's obligations under
the Transmission Control Agreement with the ISO, if such assumption is required
to transfer SCE's rights in the Purchased Assets or in order for SCE to be
relieved of its ongoing obligations under the Transmission Control Agreement),
environmental obligations, liabilities related to the operation of the assets
and decommissioning obligations, subject to the following:

10

o Recurring operating expenses will be subject to customary pro-ration as of
the closing;

o To the extent the cost of a liability has already been collected in rates
by SCE, SCE will indemnify the Purchaser against such liability;

o Liabilities for pending insured claims (including deductibles applicable
thereto) will be retained by SCE;

o SCE will assign its rights against insurers and third parties for
liabilities assumed by the Purchaser and each Party will cooperate and
assist the other in pursuing its rights against insurers and third parties
related to assumed and retained liabilities, provided that if consent to
such assignment is not received from insurers, then SCE will assign the
insurance proceeds arising from such claims; SCE and the Purchaser will
also negotiate provisions relating to the extension of claims periods under
insurance policies related to the Purchased Assets, including provisions
related to the cost thereof;

o SCE will indemnify the Purchaser for environmental liabilities which are
the "fault" of SCE, which term shall be as defined in the Purchase and Sale
Agreement (it being understood that liabilities related to EMF will be
assumed by the Purchaser, except for EMF-related liabilities for which SCE
would retain responsibility under the preceding bulleted provisions of this
Section and the last two bulleted provisions of this Section);

o SCE will indemnify the Purchaser for other liabilities caused by SCE's
gross negligence or willful misconduct prior to the Closing;

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o SCE will indemnify the Purchaser for pre-closing breaches of contract under
contracts not assigned to the Purchaser;

o Non-ordinary course operating contracts to be assumed by the Purchaser will
be disclosed in schedules to the Definitive Agreements which have been
approved by the Purchaser and SCE;

o Material liabilities (to be defined in the Definitive Agreements) actually
known to a responsible officer of SCE and to be assumed by the Purchaser
will be disclosed in schedules to the Definitive Agreements which have been
approved by the Purchaser and SCE;

o The Purchaser will not assume liabilities for pre-closing taxes,
pre-closing criminal violations, breaches of the Purchase and Sale
Agreement or similar liabilities customarily excluded from "AS IS"
transactions; and

o The Purchaser will not assume liabilities to the extent related to the
assets and interests retained by SCE.

The authorizing legislation will provide that from and after the sale of
the Purchased Assets, transmission costs will be charged to retail customers
within the SCE service area by the Purchaser, and if requested, SCE will, as
billing agent, bill such charges and remit to the Purchaser all amounts
collected, less prorated uncollectibles.

(b) Agreements; Form of Transaction

In addition to a purchase and sale agreement for the Transmission Sale
("Purchase and Sale Agreement"), the Purchaser and SCE would enter into certain
related agreements as part of the transaction ("Related Agreements"). These
would include the following:

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o O&M Agreement - Pursuant to which the Purchaser, as the owner, shall have
the right to make decisions commensurate with such interest, including the
decisions to make upgrades and to establish budgets. In addition, pursuant
to the O&M Agreement, SCE will provide operations and maintenance including
ordinary repairs and billing and collections services for a minimum term of
three (3) years with renewal options exercisable by the Purchaser. SCE
would be compensated through a fee to be negotiated. For work not included
in the fee, SCE's charges will be determined in accordance with the O&M
Agreement subject to audit by the Purchaser. The Purchaser will be
responsible for the costs of all capital improvements. It is the intention
of the Parties that the O&M Agreement be structured so that improvements
thereunder can be financed by tax-exempt bonds to the extent reasonably
practicable.

o Transmission Service Agreements - Pursuant to which the Purchaser will
agree to provide SCE with nondiscriminatory transmission service for its
URG and will further agree to provide nondiscriminatory transmission
service for other power being delivered to SCE's customers.

o Facilities Services and Coordinated Operations Agreements - Pursuant to
which the Parties will agree to the delineation of responsibilities and
costs (including the sharing of capital improvement costs) related to
certain interrelated or shared assets.

The Purchase and Sale Agreement together with the agreements contemplated
in Section 5 (power sale contract regarding Sunrise), Section 6 (grants of
conservation property), and 7 (agreements regarding claims of third parties) of
this MOU, and the agreement, if any, effectuating CDWR's obligations with
respect to the net short as provided for in Section 10 are collectively referred
to herein as the "Definitive Agreements." The Definitive Agreements shall
include all terms and conditions contained in this MOU that are to be
implemented contractually, except as the Parties may mutually agree. The

13

descriptions herein of the Definitive Agreements are intended as a summary, and
do not contain an exhaustive list of all provisions to be addressed in such
agreements; and provided, further, that any additional terms and conditions
shall not be inconsistent with the terms and conditions contained in this MOU,
except as the Parties may mutually agree.

The Definitive Agreements shall recognize that CDWR's actions as
contemplated in this MOU shall be separate and apart from its powers and
responsibilities with respect to the State Water Resources Development System
and that any and all obligations incurred and the funding for all such
obligations and activities arising from this MOU or the Definitive Agreements
shall be separate and distinct from the funds, monies, and obligations of the
State Water Resources Development System.

(c) Purchase Price

The purchase price will be 2.3 times SCE's net book value for the Purchased
Assets as of December 31, 2000, subject to verification of recorded amounts in
accordance with provisions to be negotiated in the Definitive Agreements and the
adjustments noted below, plus the sum of (i) approximately $63 million of
accelerated depreciation or similar tax benefits previously flowed through to
ratepayers (grossed up for taxes payable on the recovery of such benefits in
accordance with past ratemaking practices) and (ii) the transfer taxes payable
in connection with the sale of the Purchased Assets. For purposes of this
Section 4, "net book value" means the original cost recorded in SCE's books for
a particular asset, less any accumulated depreciation. Assets that have been
expensed shall not have a book value. The Parties currently estimate that the
unadjusted purchase price will be approximately $2.76 billion. The purchase
price will be subject to the following adjustments:

(1) To add the net book value at closing of reasonable and prudent capital
additions made to the Purchased Assets after December 31, 2000 to the
extent not recovered in transmission rates prior to the closing,
provided that capital additions approved by CDWR or the ISO and
capital additions that are in process or planned and that are

14

disclosed in a schedule to the Definitive Agreements shall be deemed
reasonable and prudent. Subject to the preceding sentence, capital
additions that are in process at the time of the closing of the
Transmission Sale will be valued at the investment made as of the
closing date.

(2) To add the net book value of any spare parts and similar current items
to the extent included in the Purchased Assets;

(3) To subtract the post-December 31, 2000 depreciation of the Purchased
Assets;

(4) To subtract the book value of any Purchased Assets existing as of
December 31, 2000 that are sold after that date, provided that if such
assets are not sold in the ordinary course of business and not
replaced by assets intended as equivalent replacements, the amount
subtracted shall be 2.3 times the book value of the sold assets; and

(5) To add or subtract for such additional items as the Parties may agree
upon.

Items such as rent, insurance, taxes and the like that are customarily pro-rated
for partial periods will be pro-rated at the closing. For purposes of this MOU,
references to the "gain on sale" of the Transmission Sale shall mean proceeds of
sale minus transaction costs paid or to be paid by SCE (other than those set
forth in Section 9), transfer taxes payable by SCE, net book value of the
Purchased Assets (including undepreciated capital additions as set forth above),
and the recapture or recovery by tax authorities of approximately $63 million of
accelerated depreciation or similar tax benefits previously flowed through to
ratepayers (grossed up for taxes payable on the recovery of such benefits in
accordance with past ratemaking practices).

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(d) Use of Proceeds

Proceeds from the Transmission Sale (including the back-up transaction
referred to in paragraph (f) below) representing the net book value of the
assets transferred at the closing (based on SCE's recorded amounts) will be used
to reduce debt and equity (including through dividends, to the extent permitted
by the California Corporations Code and consistent with SCE's authorized capital
structure). The proceeds representing the gain on sale will be applied to
recover SCE's "net undercollected amount," as described in Section 9 of this
MOU, and accordingly will be applied to payments due for the procurement of
power that are included in, and indebtedness (including interest thereon and
refinancings thereof) incurred by SCE to finance, the net undercollected amount,
including any securitization of such indebtedness.

(e) Closing Conditions

In addition to any other conditions described in this MOU, closing of the
Transmission Sale transaction will be subject to other mutually agreed upon
conditions, including receipt of all necessary approvals, without unreasonable
conditions materially adverse to either party, from FERC, the ISO and SCE's
Indenture Trustee, if required. It is contemplated that, regarding the sale of
the Purchased Assets to the Purchaser and the other actions to be implemented
contractually pursuant to this MOU, the legislative authorization will dispense
with CEQA compliance. It is also contemplated that, regarding the sale of the
Purchased Assets to the Purchaser, the legislation will dispense with approvals
by the CPUC. Such legislation will also authorize the CDWR (or such other
agency) and the Purchaser to enter into the transactions as contemplated hereby.
The closing will also be conditioned upon the absence of any injunction,
restraining order or other order restraining or prohibiting the consummation of
the transactions contemplated in this MOU, and the absence of any suit by the
Federal Government seeking to restrain or prohibit the consummation of the
transactions contemplated in this MOU.

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SCE will be required to deliver assets and rights sufficient for the
Purchaser to acquire a functional transmission system capable of providing
transmission services of the type that it has in the past, with sufficient
rights to repair and upgrade the transmission system and to operate it
efficiently and effectively. Subject to the foregoing, the Parties intend that a
failure to obtain a necessary consent or approval to transfer that relates to
only a portion of the Purchased Assets, after the Parties have used commercially
reasonable efforts to do so, or a third party's exercise of a right of first
refusal, will not result in a failure of closing conditions so long as the
Purchaser obtains substantially the same benefits of the contemplated bargain as
described below. In the event such a consent or approval is not received in a
timely manner, the Parties will work in good faith to provide substantially the
same benefits of the contemplated bargain to each of them through contractual
and other means not involving an actual transfer that is subject to such consent
or approval. Without limitation, the benefits of the contemplated bargain
include, in the case of the Purchaser, the ability of the Purchaser to have
upgrades and improvements made to the transmission system intended to be
purchased by the Purchaser hereunder, without any material limitation. If the
Parties are unable to provide substantially the same benefits of the
contemplated bargain through contractual and other means (but in all events
subject to the condition that the assets and rights to be acquired by the
Purchaser must be sufficient for the Purchaser to acquire a functional
transmission system capable of providing transmission services of the type that
it has in the past, with sufficient rights to repair and upgrade the
transmission system and to operate it efficiently and effectively), then the
portion of the Purchased Assets in question will not be transferred, and there
will be an equitable adjustment in the purchase price. In the event of any such
exclusion of assets and equitable adjustment of price, SCE shall nonetheless
cooperate with the Purchaser after the closing in order to enable upgrades and
improvements to be made to that portion of the Purchased Assets that are not
transferred.

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(f) Back-Up Transaction

If the Transmission Sale fails to close within 24 months (subject to
extension by one party if the failure to close is due to the breach of the other
party) of the execution of the Purchase and Sale Agreement for a "Qualified
Triggering Reason" (as defined below), then SCE shall offer to sell to CDWR or
its designated Purchaser (i) its hydroelectric assets and, if such assets do not
produce a gain on sale substantially equivalent to the gain expected from the
Transmission Sale, (ii) such rights, over a reasonable period of time, to the
output of SCE's interests in generating plants (including its interests in Four
Corners, SONGS, PVNGS and Mohave if then operated) after 2010 on terms and
conditions that result in a value to CDWR determined on a net present value
basis at the time of the consummation of the sale of the hydroelectric assets,
reasonably equal to the difference between the gain expected from the
Transmission Sale and the gain expected from the sale of the hydroelectric
assets. If CDWR or such Purchaser so elects to purchase such assets, then the
Parties will promptly negotiate in good faith a definitive sale agreement
respecting such assets that shall contain terms comparable to the terms of the
Transmission Sale. Upon execution of an agreement in respect of the alternative
assets, the Purchase and Sale Agreement for the Transmission Sale will be
cancelled and the references herein to the "Purchase and Sale Agreement" shall
mean the definitive sale agreement for such alternative assets, and to the
"Purchased Assets" shall mean the alternative assets purchased in such sale,
mutatis mutandis.

A Qualified Triggering Reason will be defined in the Purchase and Sale
Agreement for the Transmission Sale consistent with the following: Failure to
close for any reason other than (x) a breach or default by the Purchaser causing
the failure to close, or (y) other reasons mutually agreed upon in the
Definitive Agreements, it being understood that it is the intent of the Parties
that (i) breaches of the Purchase and Sale Agreement by either Party that are
compensable in damages or are immaterial will not provide a basis for the other
Party's failure to close (provided that, in the case of Purchaser, upon closing
Purchaser would obtain the benefits of the contemplated bargain as described
above) and (ii) the Purchaser's or SCE's failure to close because a regulatory

18

authority or the ISO reasonably conditions its approval of the Transmission Sale
shall not constitute a Qualified Triggering Reason.

5. Sunrise Project

An EIX company will commit by contract - for a term of not less than 10
years - the entire output of the Sunrise power project (the "Sunrise Project")
to CDWR or its designee under cost-of-service based rates on terms and
conditions to be set forth in a Definitive Agreement that incorporates the terms
hereof (the "Sunrise Agreement"). The EIX company will continue to use all
commercially reasonable efforts to place Phase I of the Sunrise Project in
service before the end of the Summer, 2001. Cost-of-service based rates shall be
determined on the basis of a 50/50 debt to equity leverage, permanent financing
at the Phase II commercial operations date, an assumed long-term interest rate
of 9.0%, an 11.6% return on equity, a useful life of the facility of 30 years
and a value at the end of the contract term equal to book value less
undepreciated acceleration costs to bring Phase I online by Summer 2001. The
fuel cost shall be passed through to CDWR, with a right of CDWR to supply its
own fuel, provided CDWR gives the notice to be specified in the Sunrise
Agreement. All other prices shall be fixed in the Sunrise Agreement. The
capacity price, based on capital cost estimates for the Sunrise Project as of
the signing of this MOU, would be $120/kW-yr for Phase I and $176/kW-yr for
Phase II. The final capacity price will be based upon final costs incurred for
the Project, which costs shall be subject to audit verification by CDWR. If the
actual costs would result in a lower capacity price, the final price to CDWR
shall be that lower capacity price. If the actual costs would result in a higher
capacity price, CDWR and the EIX company shall share the increased costs on a
50/50 basis and the capacity price on Phase II shall be increased accordingly.
The price for variable O&M, other than fuel costs, shall be fixed at $3.00/MW H
for the term of the Sunrise Agreement. In addition to the above variable O&M
payment, CDWR shall be responsible for start up payments per start for each
normal start up in excess of 100 normal start ups per contract year in
accordance with the following

19

schedule: 101-135 starts at a cost of $300/start, 136-150 starts at a cost
of $5,000/start, over 150 starts at a cost of $14,000/start. The Sunrise
Agreement shall provide CDWR with the standard rights of dispatch for this type
of arrangement. The Phase I capacity charge is based on a limitation of the
hours of operation as specified in the latest term sheet provided by the EIX
company to CDWR prior to the date of this MOU based upon emission credits which
the EIX company has obtained for the Project. Any increase in the hours of
operation that CDWR may request would reflect increased costs for additional
emission credits which would be reflected in an increase in the capacity charge
to be agreed to by the Parties. In the event that this MOU terminates, the
foregoing agreement for the Sunrise project would be withdrawn and subject to
new discussions between the parties. Notwithstanding the foregoing, the Sunrise
Agreement shall provide that if the Sunrise Project is not placed in service on
or before August 15, 2001 subject to extension for a force majeure event outside
of the control of the EIX company, the EIX company party thereto will credit the
amount of $2,000,000 against the first $2,000,000 in billings the CDWR would
otherwise be required to pay the EIX company under the Sunrise Agreement.

6. Conservation Property

Pursuant to the Definitive Agreements, SCE will convey perpetual protective
conservation easements to approximately 20,600 acres of its Big Creek
hydroelectric related lands and approximately 825 acres of its Eastern Sierra
hydroelectric related lands to a trust for the benefit of the State of
California, which trust will serve as the interim holder of these interests
while disposition and management plans therefore are developed as described
below. The easements will restrict public agency access over lands included in
FERC licensed areas to limited purposes consistent and that do not interfere
with utility uses over such property.

The purpose of these conveyances will be to ensure the long-term
conservation of these lands for their public interest value for the people of
the State of California, including fish, wildlife, and other ecological

20

purposes; human recreation; preservation of open space and cultural resources;
and for protection of water quality and watershed functions. Accordingly, the
trust conveyances will restrict future development over such lands in
perpetuity, subject to the following: (i) existing non-utility uses based on
current levels of activity shall be permitted for a period equal to the longer
of 5 years or the remaining term set forth in existing leases, licenses, permits
or other applicable agreements; (ii) existing utility uses (i.e., ownership and
operation of any existing hydroelectric plants located on said lands and related
improvements, including, in connection therewith, the maintenance, repair,
replacement and installation of public utility infrastructure, such as water and
sewer pipelines, and electric and telecommunications lines for existing utility
uses) based on current levels of activity shall in all events be permitted for
as long as the same continue; (iii) expansion of hydroelectric facilities
currently located on said lands shall be permitted, but only with the approval
of the state and federal agencies with jurisdiction over any such expansion;
(iv) SCE's current timber harvesting, logging or similar activities shall be
subject to modification based on the approved management and disposition plans
referred to below; and (v) the maintenance, repair, replacement and installation
of public utility infrastructure, such as water and sewer pipelines, and
electric and telecommunications lines for non-utility and other uses to the
extent permitted pursuant to the management and disposition plan. SCE will
indemnify the trust, the State and any successor-in-interest against
environmental liability associated with these lands, only to the extent
attributable to SCE's own negligent or willful acts.

The Definitive Agreements will provide that during the period the trust
holds these interests, the Wildlife Conservation Board or another state agency
whose primary mission includes the above purposes to be identified in the
Definitive Agreements will develop, with input from SCE, local governments,
federal agencies and other stakeholders, disposition and management plans for
each of the conservation easements conveyed by SCE, through a property-specific
process in which public input shall be obtained. All such disposition plans will
be subject to the reservations contained in the easement grant, as specified
above. The plans will analyze each property's natural resource, recreational,

21

and economic use value to the people of the State of California and to the local
community, subject to protection for existing uses and potential expansions of
hydroelectric activities as set forth above, and determine the appropriate
interests in the various lands to be transferred to the State or applicable
agencies thereof (or, where appropriate, the U.S. Forest Service, or other
applicable federal agencies, local governmental agencies or, after consultation
with and subject to the approval of SCE, non-governmental conservation
organizations or other third parties specified in Civil Code Section 815.3) to
preserve these values. As part of this process, the trust may request of SCE
that it convey a fee interest in specific properties, and SCE will consider any
such request in good faith on the basis of the specific justifications therefore
and the necessity thereof in light of the existence of the conservation
easement, provided that any such conveyance will be subject to an easement back
to SCE in form and substance reasonably satisfactory to it to protect its
interests, and no fee ownership request will relate to lands covering existing
hydroelectric facilities and related uses as well as reasonable expansions
thereof.

It is anticipated that these disposition and management plans will be
completed within 18 months after the conveyances of the easements to the trust
(subject to compliance with applicable laws), and dispositions of the property
or interests therein to the State or applicable agencies thereof, to the U.S.
Forest Service or other applicable federal agencies, to local governmental
agencies, or, after consultation with and subject to the approval of SCE,
non-governmental conservation organizations or other third parties specified in
Civil Code Section 815.3, will occur once such individual plans are finalized.

The formal terms of the trust arrangement will be negotiated between
the designated State agency and SCE as part of the Definitive Agreements on the
basis of the principles enumerated above. Except as provided in the Definitive
Agreements, SCE will continue to pay all expenses associated with the properties
over which it has fee title, including property taxes, and will receive all
income generated from these properties.

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7. BFMs; Emission Credits; Claims Against Third Parties

Upon execution of the Definitive Agreements, SCE will relinquish all claims
against the State for commandeering SCE's block forward market contracts
("BFMs") purchased through the California Power Exchange ("PX"), and in
connection therewith, CDWR will assume SCE's liabilities in respect of any
claims arising on or after February 2, 2001 or relating to the collateral value
of the BFMs after such date brought by the PX and/or PX Participants related to
the BFMs.

The Definitive Agreements shall obligate SCE, subject to pertinent
regulatory approvals, to sell certain mutually agreed upon emission credits
related to its previously sold generating stations, with the proceeds of such
sale to be for the benefit of ratepayers, or, alternatively, SCE shall, subject
to pertinent regulatory approvals, convey such credits to the State's Mitigation
Bank for no additional consideration.

In connection with the Definitive Agreements, the parties will negotiate
concerning their mutual cooperation and coordination with respect to pursuing
potential claims against third-party generators, and such Definitive Agreements
may contain provisions for the assignment of such claims from SCE to the State
or its agencies at times and upon terms to be mutually agreed upon. To the
extent SCE at any time after execution of this MOU realizes a discount or credit
in connection with the payment of any obligation included in the undercollection
amount described in Section 9 of this MOU, the amount of such discount or credit
shall be applied to the benefit of ratepayers in a manner to be more fully set
forth in the Definitive Agreements.

8. Tax Payments

To the extent not previously refunded by EIX after January 1, 2001, EIX
will, following its filing of a final federal income tax return for the year
2000, refund to SCE its year 2000 estimated quarterly tax payments
(approximately $293 million), and will fund an additional payment to SCE equal
to the federal loss carryback (currently estimated at approximately $127

23

million) that SCE would have had if it were not part of EIX's consolidated group
of taxpayers; provided that in no event will refunds from EIX to SCE
attributable to tax year 2000 aggregate less than $400 million.

9. Net Undercollected Amount

For the purposes of this MOU, the "net undercollected amount" shall be
computed as set forth in the remainder of this paragraph. For the purposes of
this calculation, SCE's TCBA and Transition Revenue Account ("TRA") as of
January 31, 2001 will not be combined. The balance in SCE's TCBA as of January
31, 2001 (adjusted (a) to exclude any amortization and depreciation for
presently owned generating facilities, together with their associated regulatory
receivable or payable for taxes that has occurred since December 31, 2000, which
shall be recovered as provided in Section 3 of this MOU, (b) to include the
associated Generation Memorandum Accounts, and (c) to exclude any entries with
corresponding entries in the Generation Asset Balancing Account) will be applied
to reduce the January 31, 2001 TRA balance (adjusted to remove amounts
representing potential payments to CDWR or the ISO for the period January 18 to
31, 2001 which are part of the procurement obligations which are being assumed
by CDWR pursuant to Section 10), resulting in a "net undercollected amount." The
net undercollected amount (i) will include retail generation revenues in respect
of power delivered in January 2001 received in February 2001 and thereafter
(until the end of the last full calendar month preceding the execution of the
Definitive Agreements), (ii) will exclude accrued QF costs as of January 31,
2001 not yet actually due and payable as of that date (it being acknowledged
that, notwithstanding the January 2001 cost recovery mechanism in Section 3, SCE
will be entitled to recover these accrued QF costs in a timely manner in rates
going forward), (iii) will exclude ISO charges (including imbalance energy
charges) assumed by the CDWR, as set forth in Section 10, and (iv) will include
CDWR charges on account of certain QF's not delivering power to SCE, set forth
in Section 10 of this MOU and SCE's cost obligations described in Section 15 of
this MOU. Subject to the foregoing, the size of the net undercollected amount as
computed under this paragraph will be subject to verification of recorded

24

amounts and any resulting adjustments by the CPUC, within 60 days of the passage
of the legislation referred to below. The net undercollected amount will be
deemed to equal the amount submitted by SCE if the CPUC does not complete the
verification process (and any adjustments resulting therefrom) within the 60-day
period. The net undercollected amount and the costs reflected therein will not
be subject to review by the CPUC or any other legislative, administrative or
judicial body for reasonableness. SCE estimates that the net undercollected
amount, as of January 31, 2001 was approximately $3.5 billion.

Legislation will direct the CPUC to establish an initial nonbypassable
dedicated rate component (including recovery of associated franchise fees and
uncollectibles) intended to be securitized, subject to the terms hereof, as soon
as practicable after the establishment thereof. Such dedicated rate component
will enable SCE to recover (i) the full net undercollected amount less the
expected gain on the Transmission Sale described in Sections 4(c) and 4(d)
above; (ii) the discounted net present value of interest on the expected gain on
the Transmission Sale for a period commencing on the date of the consummation of
the securitization of the Initial Dedicated Rate Component as described below
and ending two years after the date of the execution of the Purchase and Sale
Agreement; and (iii) interest on obligations included in the undercollection or
interim financing thereof during such period from January 31, 2001 until the
securitization transaction covering (i), (ii) and (iii) is consummated, based on
an effective interest rate to be mutually agreed to and set forth in the
Definitive Agreements, net of interest earned by SCE on its balances of cash,
cash equivalents and other liquid assets, if any, during such period in excess
of its normal cash balances. Such dedicated rate component is referred to herein
as the "First Dedicated Rate Component." SCE's actual borrowing costs are
referred to herein as "SCE's interest cost." As indicated above, the amount of
interest described in clause (ii) will be appropriately discounted to reflect
SCE's receipt of such amount in the securitization transaction before interest
on the expected gain on the Transmission Sale would actually accrue. SCE's
interest cost shall be addressed as provided in this paragraph and, subject to
the consummation of the financings and securitizations contemplated hereby,

25

shall not be recoverable in rates (other than through the dedicated rate
component described above), except that any difference between the amount of
interest securitized by SCE pursuant to clause (ii) above and the actual net
amount of interest incurred by SCE with respect to financing of a portion of the
undercollection equal to the expected gain on the Transmission Sale from the
date of the consummation of the securitization of the Initial Dedicated Rate
Component until the earlier of two years after the date of the execution of the
Purchase and Sale Agreement or the consummation of the Transmission Sale (based
on a rate to be mutually agreed to and set forth in the Definitive Agreements)
shall be recovered by or paid by SCE from or to its ratepayers.

Legislation will further direct the CPUC to establish a second
nonbypassable dedicated rate component (including recovery of associated
franchise fees and uncollectibles) that enables SCE to recover the expected gain
on the Transmission Sale as described in Section 4(c) and 4(d) above, subject to
the provisions set forth below. This dedicated rate component is referred to
herein as the "Second Dedicated Rate Component." The Second Dedicated Rate
Component is intended to provide a source to secure bridge financing of the
expected gain on the Transmission Sale. It shall not appear in rates for two
years after the execution of the Purchase and Sale Agreement and shall be made
subject to the Transmission Sale not closing before such time. The Second
Dedicated Rate Component would not be eligible to be securitized through a
public offering of debt securities by a special purpose entity until it is
eligible to appear in rates as provided above, but may be used to secure or
facilitate bridge financing prior to such time. However, the Second Dedicated
Rate Component will have the benefit of a financing order of the kind described
in Article 5.5 of the Public Utilities Code or order or action having equivalent
effect, and shall be effective no later than the effectiveness of the financing
order or its equivalent for the First Dedicated Rate Component. If the actual
gain on the Transmission Sale exceeds the estimated amount, then the difference
shall be refunded to SCE's customers; if the actual gain on the Transmission
Sale is less than the estimated amount, then the deficiency will be recovered

26

from SCE's customers in retail rates over the term of the securitization period.
Likewise, if there are other elements (other than interest, which is covered in
the preceding paragraph) included in the amount securitized which are based upon
contingencies related to the consummation of the Transmission Sale (such as, for
example, estimates of closing costs), there shall be adjustments (to be refunded
to or recovered from SCE's customers) if the actual amounts are less than or
greater than the estimated amounts. In addition, if any amount paid to SCE from
the proceeds of the initial securitization is intended to cover costs other than
procurement costs (such as interest or closing costs), SCE shall maintain such
amounts in one or more segregated accounts and use the amounts therein solely
for the purposes for which they were paid. Further, the Definitive Agreements
shall provide for appropriate adjustments upon the Transmission Sale in the
event that the Second Dedicated Rate Component has commenced but the
Transmission Sale has not yet occurred.

The dedicated rate components will be used solely to recover the net
undercollected amount, together with (a) reasonable costs incurred by SCE
associated with any financing of such amount (including any reasonable hedging
costs incurred by SCE in a reasonable hedging transaction approved by the
Department of Finance to hedge SCE's interest rate risk if the interest rate
provided for in the financing order or equivalent is a fixed or determined rate)
and (b) costs incurred or anticipated to be incurred by the State and the CDWR
in connection with this MOU, the Transmission Sale, or the securitization, as
more fully described in Section 15. The terms of any securitization transaction
will be subject to the approval of the Director of the State Department of
Finance, which approval shall not be unreasonably withheld or delayed. The net
undercollected amount will be amortized over a period of not less than 15 years
unless placement of securities with such a maturity is not reasonably practical,
in which case a shorter maturity shall be authorized by the Department of
Finance.

The legislation will further contain provisions that are the same as
Article 5.5 of the Public Utilities Code, mutatis mutandis, and that are
designed to facilitate the securitizing of the First and Second Dedicated Rate

27

Components, with such changes thereto as may be agreed upon by the Parties as
necessary to effectuate the foregoing provisions.

Amounts financed through such dedicated rate component(s) will not be
regarded as long-term debt for purposes of determining the utility's authorized
capital structure. Any tax benefits resulting from the timing difference between
the incurrence of procurement costs and the recovery thereof through the
financing contemplated in this Section 9 will be used to benefit retail
customers. The amount of benefit resulting from any such tax timing difference
during each applicable period will be determined by using a rate of return equal
to the weighted average yield applicable to the securities issued in such
financing.

10. Procurement Obligations

Either through legislation and/or through a contract between SCE and CDWR
(which, if in the form of a contract, shall be a Definitive Agreement), the
following will be effected:

o Through December 31, 2002, CDWR will assume the entire responsibility for
procuring the full net short needs of retail customers within the SCE
service area (i.e., the electricity needed to meet SCE's load that is not
met by the generation resources owned or under contract to SCE as of
January 18, 2001, plus any additions thereafter). CDWR shall also assume
responsibility for ancillary services (other than regulation, except to the
extent the parties agree pursuant to the next paragraph) associated with
CDWR import energy purchases and responsibility for the cost of Reliability
Must Run contracts from January 18, 2001. In addition, CDWR will also
assume responsibility for ISO charges to SCE for the energy cost component
of energy purchased by the ISO since January 18, 2001, to meet the net
short requirements in SCE's service area (such energy cost component shall
not include charges for underscheduling, capacity charges, ancillary

28

services or PX or similar chargebacks, except to the extent the parties
agree pursuant to the next paragraph).

o It is the intent of both SCE and CDWR that the overall costs to SCE's
retail customers be minimized, and accordingly SCE and CDWR agree that
SCE's operation of URG and CDWR's net short procurement should be
coordinated. SCE and CDWR will negotiate a mutually-agreeable operational
protocol which will address the use of URG for self-scheduling of ancillary
services, and will allocate responsibility for procurement and costs of
ancillary services. In addition, the operational protocol will allocate
cost responsibility for any ISO underscheduling penalties based upon SCE's
good faith forecast of the net-short and CDWR's activities to procure
sufficient quantities to meet SCE's forecast. SCE shall be entitled to
collect revenues through its retail rates sufficient to cover the costs of
any ancillary services it is responsible for on a timely basis.

o SCE will cooperate with CDWR to achieve operational efficiencies for
bundled service customers; and

o SCE power purchases, and, until it is creditworthy, utilization of URG, to
meet its obligations under interutility contracts will be allowed with an
offset for the net proceeds of any sale of power.

CDWR desires to be relieved of its obligation to provide for the net short
needs of SCE's retail customers, and SCE agrees to resume procurement of the
full net short needs and electric requirements for retail customers within the
SCE service area after 2002. In addition, after 2002, CDWR may at least assign
to SCE the administration of any of CDWR's outstanding procurement contracts.
The Parties will work together to minimize the burden on CDWR, without imposing
direct or indirect financial risks on SCE for those contracts. The Parties
recognize that legislation may be needed to achieve this result.

29

Given the magnitude of the net short and SCE's current financial condition,
the practical ability of SCE to resume such procurement responsibility after
2002, and to relieve CDWR of such burden, will depend in substantial part upon
prompt restoration of SCE's creditworthiness and its ability to recover such
procurement costs in rates on a timely basis. Accordingly, the CPUC Implementing
Decisions will include confirmation of SCE's entitlement to recover its
reasonable procurement costs on a timely basis and establish procedures (which
may include one or more balancing accounts and trigger mechanisms) designed to
ensure that any undercollection or overcollection of procurement costs will be
reconciled in a timely manner and any undercollection will be able to be
financed on reasonable terms consistent with SCE being an investment grade
credit, and mechanisms to mitigate the potential risks of retrospective
reasonableness review of procurement practices, including the development of a
framework and criteria for procurement practices, the submission of an annual
procurement plan, and the prompt approval or disapproval of contracts (the
"Procurement Cost Recovery Mechanism").

In addition, subject to execution of the Definitive Agreements and adoption
of legislation necessary to implement this MOU, SCE shall cooperate with CDWR in
the implementation of AB 1X, including provision by SCE of such information as
CDWR may reasonably require in connection with the financing of its power
purchase program. SCE and CDWR shall also execute a mutually approved servicing
agreement (which shall not be treated as a Definitive Agreement hereunder)
relating to the distribution, billing and collection of CDWR power for customers
in SCE's service area.

Upon the securitization of the First Dedicated Rate Component referred
to in Section 9 hereof, SCE shall pay CDWR an amount to be agreed upon
representing those costs incurred by CDWR in covering that portion of the net
short from January 18, 2001 through April 7, 2001 which is attributable to
certain QF's not delivering power to SCE, it being agreed that such payments to

30

CDWR shall be added to the net undercollected amount referred to herein and
shall not be construed as any admission by SCE.

The Parties agree to discuss in good faith the terms pursuant to which SCE,
as agent and not as principal, would be willing to assist CDWR in the management
of its power purchase contracts, on terms to be resolved in a subsequent
agreement. Such subsequent agreement shall not be considered a "Definitive
Agreement" as defined herein.

11. Investment Recovery

One of the goals of the Plan is for SCE to be an investment grade credit.
The Parties recognize that the creditworthiness and health of SCE, and the
ability of SCE to finance infrastructure improvements, require greater certainty
in respect of SCE's ability to earn a fair return on invested capital.
Accordingly, new legislation will provide that SCE's authorized return on equity
may not be reduced by the CPUC below its current 11.6% before December 31, 2010,
and that prior to such date, the CPUC will not establish a ratemaking capital
structure for SCE with different proportions of common equity or preferred
equity to debt than that set forth in current authorizations.

12. Capital Commitment by EIX; "First Priority" Condition

Pursuant to the Definitive Agreements, EIX and SCE shall commit to make
capital investments in SCE's regulated businesses of at least $3 billion through
2006, or such lesser amount as the CPUC may approve, with the equity component
thereof funded from utility retained earnings or, if insufficient, from EIX
equity investment, provided that SCE will receive a return of and on equity in
retail rates as provided in Section 11 hereof.

The CPUC Implementing Decisions will include a clarification that the
"first priority" condition in the decision authorizing the formation of a
holding company for SCE (D. 88-01-063, Condition 12) refers to equity
investment, not working capital for operating costs.

31

13. Additional CPUC Implementing Decisions

In addition to the URG Cost Recovery Mechanism, the Procurement Cost
Recovery Mechanism, and the other provisions of this MOU that are contemplated
to be implemented through CPUC Implementing Decisions, the CPUC Implementing
Decisions shall include:

o Orders resolving the responsibility of SCE to provide credits to direct
access customers in respect of electricity deliveries after December 31,
2000 in respects which do not result in any material financial detriment to
SCE; and

o A favorable determination by the CPUC in response to a request to be
submitted by SCE that SCE's 2002 Utility Distribution Company's GRC will be
deferred to test-year 2003.

14. Litigation Settlement

As part of the implementation steps, the Parties to the federal lawsuit
either will enter into a stipulated judgment resolving the federal lawsuit by
abandonment of SCE's claims and reflecting those terms of this MOU that have not
been secured either by entering into a Definitive Agreement, by CPUC action or
by legislation, or, if reasonably acceptable at the time to SCE, will enter into
a dismissal, with prejudice, of those claims. The claims to be abandoned or
dismissed by SCE as part of the settlement of the Federal litigation will
include, without limitation:

o any claim SCE may have or could have had against the State of California or
any agency, department or subdivision thereof, the Federal Government, or
the CPUC for takings or under the filed rate doctrine arising from or
related to the facts asserted in such litigation; and

32

o any claims challenging actions taken by the CPUC prior to execution of the
last executed Definitive Agreement to implement AB 1X and 6X, including,
without limitation, any determinations by the CPUC, State of California or
any agency, department or subdivision thereof of the California Procurement
Adjustment or the Fixed Department of Water Resources Set Aside.

In addition as part of the Definitive Agreements, the parties thereto will
negotiate in good faith releases of certain other claims. The judgment or
dismissal will be filed promptly following passage of all legislation, execution
of the Definitive Agreements and issuance of the financing order or equivalent
for the securitizations of the First and Second Dedicated Rate Components.

15. Implementation Principles

The MOU signifies the intention of the Parties to act in good faith to
sponsor and support legislation effecting elements of the Plan to be implemented
by legislation and to act in good faith to negotiate final agreements for those
elements of the Plan that are to be implemented by contract. As part of such
intention, each Party will allow for reasonable due diligence by the other
Party, and SCE will not seek to sell, encumber or otherwise dispose of the
transmission assets to any other person or entity or submit any application in
respect of the same to the CPUC or FERC. This MOU shall be terminable by either
Party upon written notice to the other in the event that such legislation is not
passed and the Definitive Agreements are not executed by August 15, 2001 unless
the Parties otherwise agree. This MOU shall also be terminable in the event that
any of the following (each, a "Material Adverse Change") occurs: (a) in the
event any law is passed, adopted or repealed or regulatory action taken which,
in the good faith judgment of such Party, would materially impede or frustrate
the ability of the Parties to effectuate all of the elements of the Plan as a
package; (b) as set forth above, in the event that all of the actions and
approvals expressly characterized herein as "CPUC Implementing Decisions" have

33

not been taken or adopted on or before sixty (60) days after the date this MOU
is signed by all Parties; (c) in the event of the adoption of or any change in
any applicable rule, regulation or order which would have a material adverse
effect on any Party or which, in the case of SCE, would include the failure on
the part of the CPUC, following a motion therefor filed on behalf of SCE (i) to
extend SCE's existing non-generation Performance Based Ratemaking and cost of
capital mechanisms until SCE's new GRC is implemented; (ii) to terminate the
Accelerated Cost Recovery and Reduced Cost Recovery ("ACRA/RCRA") mechanisms;
(iii) to permit the amortization of the RCRA reserve, in accordance with prior
CPUC decisions; (d) in the event that any material penalty is imposed by the
CPUC in respect of the relationship between SCE and EIX prior to the date
hereof, including without limitation any of the matters raised in Order
Instituting Investigation 01-04-002 or (e) in the event any bankruptcy
proceeding in respect of any Party is commenced. In the event of termination of
this MOU or any failure of the Definitive Agreements to be executed or become
effective, there shall be no liability for damages or otherwise on the part of a
Party to another under or by reason of this MOU or any discussions, negotiations
or conduct pertaining to this MOU or by reason of the failure of the
transactions contemplated hereby or thereby to be consummated.

Inasmuch as each element of the Plan is part of an integrated package, the
effectuation of each will depend upon effectuation of the others. In particular:

(i) Execution of the Definitive Agreements will be subject to final
passage and effectiveness of legislation implementing all elements of the
Plan that are required to be legislatively implemented and the adoption of
the CPUC Implementing Decisions. The Parties recognize that, as part of the
Definitive Agreements, mutually acceptable provisions shall be made with
respect to liabilities for PX chargebacks and ISO underscheduling charges.

(ii) Any financing order implementing the dedicated rate component(s)
will be subject to execution of the Definitive Agreements by the parties
thereto, and the consummation of the effectiveness of the Definitive

34

Agreements shall be conditioned upon the existence of financing orders or
their equivalent establishing irrevocable dedicated rate components for the
"net undercollected amount" referred to in Section 9.

(iii) Each Definitive Agreement will be subject to the Parties'
execution of the other Definitive Agreements; provided that: (A) the
Sunrise Agreement may be signed prior to the date the other agreements are
signed; (B) EIX may thereafter terminate the Sunrise Agreement if the other
Definitive Agreements are not executed when otherwise required by this MOU;
and (C) the EIX company shall be excused from performance under the Sunrise
Agreement in the event that, after the execution of the Definitive
Agreements, either (I) any legislation is enacted or any rule, regulation
or order is adopted by the CPUC which would have the effect of overturning,
in respects materially adverse to SCE, those CPUC Implementing Decisions
which were adopted prior to the execution of the Definitive Agreements or
(II) any Material Adverse Change referred to in clause (d) of the
definition thereof occurs.

(iv) Execution of each Definitive Agreement called for by the Plan and
dismissal or other resolution of the litigation referred to in Section 14
will be subject to there having been no Material Adverse Change and no
commencement of any bankruptcy or similar proceeding to which any party
hereto is subject.

Implementation of the Plan will be further subject to the following:

(a) Absence of any injunction, restraining order or other order restraining
or prohibiting the consummation of the transactions contemplated in this MOU,
and the absence of any suit by the Federal Government seeking to restrain or
prohibit the consummation of the transactions contemplated in this MOU.

(b) Receipt by each of the Parties upon or prior to execution of the
Definitive Agreements of such opinions of their financial advisors as they deem
reasonably necessary.

35

Provided the Definitive Agreements are entered into, SCE will pay all of
the reasonable costs and expenses incurred by the State directly in connection
with the negotiation or effectuation of this MOU and the Definitive Agreements,
including legal fees, fees of financial advisors and accountants and expenses of
its representatives, whether or not the transactions contemplated by this MOU
are consummated, subject to the following:

o SCE's obligations will only be for transaction costs identified to
transactions with SCE (not including, for example, costs associated with
State financing of its obligations or the conservation advertising
program);

o SCE's will not be obligated for State costs in excess of an amount to be
agreed upon based on an estimate provided by the State in connection with
the execution of the Definitive Agreements. All such costs shall be subject
to audit verification; and

o SCE recovers such expenses through the securitization of the First
Dedicated Rate Component described in Section 9 of this MOU (in addition to
the net undercollected amount) or if such securitization does not occur, in
retail rates.

16. Next Steps

Subject to the provisions of Section 15, the Parties will act in good faith
to implement this MOU and effectuate the Plan as quickly as reasonably
practicable. In this regard, the Governor will submit to the State Legislature,
after review and comment by SCE, a comprehensive legislative package setting
forth the legislative elements of the Plan. The Parties will then proceed
diligently and in good faith to attempt to have the necessary legislation
adopted, and will negotiate in good faith in an attempt to execute the
Definitive Agreements, by August 15, 2001.

36

While time is of the essence of this MOU, failure to satisfy the calendar
set forth in the preceding paragraph will not result in a termination of this
MOU, if the Parties are continuing to proceed diligently and in good faith to
achieve its implementation. Failure of all implementing legislation to be
adopted and effective and Definitive Agreements to be signed on or before
December 31, 2001, will entitle any Party thereafter to terminate this MOU upon
notice to the other Parties.

17. Signatures

This MOU may be executed in counterparts and via facsimile. The individuals
executing this MOU represent that they are authorized to sign on behalf of the
Parties they represent, it being understood, however, that the execution of this
MOU by representatives of SCE and EIX is following the approval of this MOU by
the Board of Directors of each such entity.

37

IN WITNESS WHEREOF, the undersigned have executed this Memorandum of
Understanding as of the day and year first above written.

SOUTHERN CALIFORNIA EDISON COMPANY,
a California corporation

By: /s/ Stephen E. Frank
Name: Stephen E. Frank
Title: Chairman of the Board, President and CEO

EDISON INTERNATIONAL, INC.,
a California corporation
By: /s/ John E. Bryson
Name: John E. Bryson
Title: Chairman of the Board, President and CEO

CALIFORNIA DEPARTMENT OF WATER RESOURCES
By: /s/ Thomas M. Hannigan
Name: Thomas M. Hannigan
Title: Director

EXHIBIT 10.18
2000 EQUITY PLAN

SPECIAL GRANT CERTIFICATE

AND AWARD AGREEMENT

This award is made by Edison International to John E. Bryson ("Employee"), as of
May 18, 2000, pursuant to the Equity Compensation Plan ("Plan"). Edison
International hereby grants to Employee, as a matter of separate arrangement and
not in lieu of any other compensation for services, the following:

----------------------------------------------------
The right and option to purchase 783,021 shares
of Edison International Common Stock at an exercise
price of $20.0625 per share.
-----------------------------------------------------

The award is made subject to the conditions contained in the document "Equity
Compensation Plan and 2000 Equity Plan Terms and Conditions for Special Grant of
Stock Options May 18, 2000" ("Terms and Conditions") which is incorporated
herein by reference.

The portion of this award giving Employee the right and option to purchase
235,821 shares is made in recognition of Employee's absolute and unconditional
relinquishment of any benefits under the "phantom stock options" in Edison
Mission Energy and Edison Capital on December 2, 1999. Notwithstanding the
provisions of Appendix B to the Terms and Conditions, the portion of this award
described in the preceding sentence shall be excluded from the allocation to
Tranche 2001 and Tranche 2002 described therein and shall become fully vested
if, during the vesting period, Employee terminates employment for a reason set
forth in Section 2(c) of the Terms and Conditions. Such portion of this award
will not, however, be exercisable prior to the 5th anniversary of the date of
grant unless the stock price appreciation requirement of Section 2(a)(ii) of the
Terms and Conditions has been satisfied prior to the exercise date. In all other
respects this award shall be subject to the Terms and Conditions.

The parties hereto agree to the terms of the award set forth herein and in the
Terms and Conditions and the Plan.

Edison International

By: John Kelly John E. Bryson
---------------------------- ---------------
John Kelly John E. Bryson

[GRAPHIC OMITTED]

EQUITY COMPENSATION PLAN

SPECIAL GRANT CERTIFICATE

AND AWARD AGREEMENT

This award is made by Edison International to John E. Bryson ("Employee"), as of
May 18, 2000, pursuant to the Equity Compensation Plan ("Plan"). Edison
International hereby grants to Employee, as a matter of separate arrangement and
not in lieu of any other compensation for services, the following:

---------------------------------------------------------
The right and option to purchase 216,979 shares of
Edison International Common Stock at an exercise
price of $20.0625 per share.
---------------------------------------------------------

The award is made subject to the conditions contained in the document "Equity
Compensation Plan and 2000 Equity Plan Terms and Conditions for Special Grant of
Stock Options May 18, 2000" ("Terms and Conditions") which is incorporated
herein by reference.

This award is made in recognition of Employee's absolute and unconditional
relinquishment of any benefits under the "phantom stock options" in Edison
Mission Energy and Edison Capital on December 2, 1999. Notwithstanding the
provisions of Appendix B to the Terms and Conditions, this award shall be
excluded from the allocation to Tranche 2001 and Tranche 2002 described therein
and shall become fully vested if, during the vesting period, Employee terminates
employment for a reason set forth in Section 2(c) of the Terms and Conditions.
This award will not, however, be exercisable prior to the 5th anniversary of the
date of grant unless the stock price appreciation requirement of Section
2(a)(ii) of the Terms and Conditions has been satisfied prior to the exercise
date. In all other respects this award shall be subject to the Terms and
Conditions.

The parties hereto agree to the terms of the award set forth herein and in the
Terms and Conditions and the Plan.

Edison International

By: John Kelly John E. Bryson
---------------------------- ---------------------------
John Kelly John E. Bryson

EXHIBIT 10.19

[GRAPHIC OMITTED]

EQUITY COMPENSATION PLAN

SPECIAL GRANT CERTIFICATE

AND AWARD AGREEMENT

This award is made by Edison International to Bryant C. Danner ("Employee"), as
of May 18, 2000, pursuant to the Equity Compensation Plan ("Plan"). Edison
International hereby grants to Employee, as a matter of separate arrangement and
not in lieu of any other compensation for services, the following:

------------------------------------------------------
The right and option to purchase 400,000 shares of
Edison International Common Stock at an exercise
price of $20.0625 per share.
------------------------------------------------------

The award is made subject to the conditions contained in the document "Equity
Compensation Plan and 2000 Equity Plan Terms and Conditions for Special Grant of
Stock Options May 18, 2000" ("Terms and Conditions") which is incorporated
herein by reference.

The portion of this award giving Employee the right and option to purchase
233,800 shares is made in recognition of Employee's absolute and unconditional
relinquishment of any benefits under the "phantom stock options" in Edison
Mission Energy and Edison Capital on December 2, 1999. Notwithstanding the
provisions of Appendix B to the Terms and Conditions, the portion of this award
described in the preceding sentence shall be excluded from the allocation to
Tranche 2001 and Tranche 2002 described therein and shall become fully vested
if, during the vesting period, Employee terminates employment for a reason set
forth in Section 2(c) of the Terms and Conditions. Such portion of this award
will not, however, be exercisable prior to the 5th anniversary of the date of
grant unless the stock price appreciation requirement of Section 2(a)(ii) of the
Terms and Conditions has been satisfied prior to the exercise date. In all other
respects this award shall be subject to the Terms and Conditions.

The parties hereto agree to the terms of the award set forth herein and in the
Terms and Conditions and the Plan.

Edison International

By: Beverly P. Ryder Bryant C. Danner
---------------------------- ---------------------
Beverly P. Ryder Bryant C. Danner

EXHIBIT 10.20

[GRAPHIC OMITTED]

EQUITY COMPENSATION PLAN

SPECIAL GRANT CERTIFICATE

AND AWARD AGREEMENT

This award is made by Edison International to Alan J. Fohrer ("Employee"), as of
May 18, 2000, pursuant to the Equity Compensation Plan ("Plan"). Edison
International hereby grants to Employee, as a matter of separate arrangement and
not in lieu of any other compensation for services, the following:

-----------------------------------------------------
The right and option to purchase 398,872 shares of
Edison International Common Stock at an exercise
price of $20.0625 per share.
-----------------------------------------------------

The award is made subject to the conditions contained in the document "Equity
Compensation Plan and 2000 Equity Plan Terms and Conditions for Special Grant of
Stock Options May 18, 2000" ("Terms and Conditions") which is incorporated
herein by reference.

The portion of this award giving Employee the right and option to purchase
204,400 shares is made in recognition of Employee's absolute and unconditional
relinquishment of any benefits under the "phantom stock options" in Edison
Mission Energy and Edison Capital on December 2, 1999. Notwithstanding the
provisions of Appendix B to the Terms and Conditions, the portion of this award
described in the preceding sentence shall be excluded from the allocation to
Tranche 2001 and Tranche 2002 described therein and shall become fully vested
if, during the vesting period, Employee terminates employment for a reason set
forth in Section 2(c) of the Terms and Conditions. Such portion of this award
will not, however, be exercisable prior to the 5th anniversary of the date of
grant unless the stock price appreciation requirement of Section 2(a)(ii) of the
Terms and Conditions has been satisfied prior to the exercise date. In all other
respects this award shall be subject to the Terms and Conditions.

The parties hereto agree to the terms of the award set forth herein and in the
Terms and Conditions and the Plan.

Edison International

By: John Kelly Alan J. Fohrer
---------------------------- ---------------------
John Kelly Alan J. Fohrer

Exhibit 11

Edison International

Computation of Primary and Fully Diluted Earnings per Share
(Unaudited)

Year Ended December 31,
----------------------------------------------------
2000 1999 1998
(in thousands, except per share amounts)

Consolidated net income $ (1,942,797) $ 623,030 $ 668,163
Primary weighted average shares 332,560 347,551 359,205
Fully diluted weighted average shares 332,560 348,529 363,685
Primary earnings per share $ (5.84) $ 1.79 $ 1.86
Fully diluted earnings per share $ (5.84) $ 1.79 $ 1.84

Exhibit 12

EDISON INTERNATIONAL

COMPUTATION OF RATIOS OF EARNINGS TO FIXED CHARGES AND PREFERRED
AND PREFERENCE STOCK

(Thousands of Dollars)

Year Ended December 31,
---------------------------------------------------------------------------------------
1995 1996 1997 1998 1999 2000
------------- ------------ ------------- -------------- ------------- ------------

EARNINGS BEFORE INCOME TAXES
AND FIXED CHARGES:

Income before interest expense (1) $1,346,636 $1,399,650 $1,450,957 $ 1,416,332 $ 1,586,819 $ (433,039)
Add:
Taxes on income (2) 491,477 505,785 498,729 461,711 294,081 (1,049,365)
Rentals (3) 5,188 5,159 4,649 4,278 5,015 39,520
Allocable portion of interest
on long-term contracts for
the purchase of power (4) 1,848 1,824 1,797 1,767 1,735 1,699
Dividends of <50% owned equity method
investments 60,251 72,787 82,576 49,208 80,891 121,463
Interest on partnership
indebtedness (5) 34,681 31,356 34,938 36,019 33,186 25,523
Amortization of previously capitalized
fixed charges 2,417 2,232 7,023 7,246 7,601 7,191
Less:
Earnings of <50% owned equity method 51,703 75,063 84,445 53,605 88,376 110,392
------------- ------------ ------------- -------------- ------------- ------------

Total earnings before income
taxes and fixed charges (A) $1,890,795 $1,943,730 $1,996,224 $ 1,922,956 $ 1,920,952 $(1,397,400)
============= ============ ============= ============== ============= ============

FIXED CHARGES:
Interest and amortization $ 560,641 $ 635,407 $ 708,446 $ 710,388 $ 893,613 $ 1,387,933
Rentals (3) 5,188 5,159 4,649 4,278 5,015 39,520
Capitalized interest (6) 59,885 57,803 14,937 19,219 28,682 15,819
Allocable portion of interest on
long-term contracts for
the purchase of power (4) 1,848 1,824 1,797 1,767 1,735 1,699
Interest on partnership
indebtedness (5) 34,681 31,356 34,938 36,019 33,186 25,523
Dividends on preferred securities 10,095 13,100 13,167 13,149 44,287 100,382
Subsidiary preferred and preference stock
dividend requirements - pre-tax basis 61,210 58,666 50,502 41,653 33,045 34,574
------------- ------------ ------------- -------------- ------------- ------------
Total fixed charges (B) $ 733,548 $ 803,315 $ 828,436 $ 826,473 $ 1,039,563 $ 1,605,450
============= ============ ============= ============== ============= ============

RATIO OF EARNINGS TO
FIXED CHARGES (A) / (B): 2.58 2.42 2.41 2.33 1.85 (0.87)
============= ============= ============= ============== ============= ===========

(1) Includes allowance for funds used during construction, accrual of unbilled
revenue and minority interest, net of income taxes.

(2) Includes allocation of federal income and state franchise taxes to other
income.

(3) Rentals include the interest factor relating to certain significant rentals
plus one-third of all remaining annual rentals.

(4) Allocable portion of interest included in annual minimum debt service
requirement of supplier.

(5) Includes the allocable portion of interest on project indebtedness of
fifty-percent partnership investments by other wholly-owned subsidiaries of
Edison International.

(6) Includes the fixed charges associated with Nuclear Fuel and capitalized
interest of fifty-percent owned partnerships.

- --------------------------------------------------------------------------------
Management's Discussion and Analysis of Results of Operations and Financial
Condition

California's investor-owned electric utilities, including Southern California
Edison Company (SCE), are currently facing a crisis resulting from deregulation
of the generation side of the electric industry through legislation enacted by
the California Legislature and decisions issued by the California Public
Utilities Commission (CPUC). Under the legislation and CPUC decisions, prices
for wholesale purchases of electricity from power suppliers are set by markets
while the retail prices paid by utility customers for electricity delivered to
them remain frozen at June 1996 levels. Since May 2000, SCE's costs to obtain
power (at wholesale electricity prices) for resale to its customers
substantially exceeded revenue from frozen rates. The shortfall has been
accumulated in the transition revenue account (TRA), a CPUC-authorized
regulatory asset. SCE has borrowed significant amounts of money to finance its
electricity purchases, creating a severe financial drain on SCE.

On April 9, 2001, Edison International, SCE and the California Department of
Water Resources (CDWR) executed a memorandum of understanding (MOU) which sets
forth a comprehensive plan calling for legislation, regulatory action and
definitive agreements to resolve important aspects of the energy crisis, and
which is expected to help restore SCE's creditworthiness and liquidity. The
Governor of the State of California and his representatives participated in the
negotiation of the MOU, and the Governor endorsed implementation of all the
elements of the MOU. The MOU is discussed in detail in the Memorandum of
Understanding with the CDWR section. Edison International, SCE and the CDWR
committed in the MOU to proceed in good faith to sponsor and support the
required legislation and to negotiate in good faith the necessary definitive
agreements. If required legislation is not adopted and definitive agreements
executed by August 15, 2001, or if the CPUC does not adopt required
implementing decisions by June 8, 2001, the MOU may be terminated by Edison
International, SCE or the CDWR. Neither Edison International nor SCE can
provide assurance that all the required legislation will be enacted, regulatory
actions taken and definitive agreements executed before the applicable
deadlines.

Accounting standards generally accepted in the United States permit SCE to
defer costs as regulatory assets if those costs are determined to be probable
of recovery in future rates. If SCE determines that regulatory assets, such as
the TRA and the transition cost balancing account (TCBA), are no longer
probable of recovery through future rates, they must be written off. The TCBA
is a regulatory balancing account that tracks the recovery of generation-
related transition costs, including stranded investments. SCE must assess the
probability of recovery of the undercollected costs that are now recorded in
the TCBA in light of the CPUC's March 27, 2001, and April 3, 2001, decisions,
including the retroactive transfer of balances from SCE's TRA to its TCBA and
related changes that are discussed in more detail in Rate Stabilization
Proceeding. These decisions and other regulatory and legislative actions did
not meet SCE's prior expectation that the CPUC would provide adequate cost
recovery mechanisms. Until legislative and regulatory actions contemplated by
the MOU occur, or other actions are taken, SCE is unable to conclude that its
undercollected costs that are recovered through the TCBA mechanism are probable
of recovery in future rates. As a result, Edison International's financial
results for the year ended 2000 include an after-tax charge at SCE of
approximately $2.5 billion ($4.2 billion on a pre-tax basis), reflecting a
write-off of the TCBA (as restated to reflect the CPUC's March 27, 2001,
decisions) and regulatory assets to be recovered through the TCBA mechanism, as
of December 31, 2000. In addition, SCE currently does not have regulatory
authority to recover any purchased-power costs it incurs during 2001 in excess
of revenue from retail rates. Those amounts will be charged against earnings in
2001 absent a regulatory or legislative solution, such as implementation of the
actions called for in the MOU that makes recovery of such costs probable. This
will result in further material declines in reported common shareholders'
equity, particularly in light of the CPUC's failure to provide SCE with
sufficient rate revenue to cover its ongoing costs and obligations through the
CPUC's March 27, 2001, decisions. The December 31, 2000, write-off also caused
SCE to be unable to meet an earnings test that must be met before SCE can issue
additional first mortgage bonds. If the MOU is implemented, or a rate mechanism
provided by legislation or regulatory authority is established that makes
recovery from regulated rates probable as to all or a portion of the amounts
that were previously charged against earnings, current accounting standards
provide that a regulatory asset would be reinstated with a corresponding
increase in earnings.

3

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Management's Discussion and Analysis of Results of Operations and Financial
Condition

The following pages include a discussion of the history of the TRA and TCBA and
related circumstances, the devastating effect on the financial condition of SCE
of undercollections recorded in the TRA and TCBA, the current status of the
undercollections, the impact of the CPUC's March 27, 2001, decisions and
related matters, and possible resolution of the current crisis through
implementation of the MOU.

Results of Operations

Earnings

In 2000, Edison International recorded a loss of $5.84 per share. The net loss
in 2000 included a write-off at SCE of regulatory assets and liabilities in the
amount of $2.5 billion (after tax), or $7.58 per share as of December 31, 2000.
Accounting principles generally accepted in the United States require SCE at
each financial statement date to assess the probability of recovering its
regulatory assets through a regulatory process. On March 27, 2001, the CPUC
issued a decision adopting a 3c-per-kilowatt-hour (kWh) surcharge on rates
effective immediately, with revenue generated by the surcharge to be applied to
electric power costs incurred after the date of the order. This rate
stabilization decision also stated that the rate freeze had not ended, and the
TCBA mechanism was to remain in place. However, the decision required SCE to
recalculate the TCBA retroactive to January 1, 1998, the beginning of the rate
freeze period. The new calculation required the coal and hydroelectric
balancing accounting overcollections (which amounted to $1.5 billion as of
December 31, 2000) to be closed monthly to the TRA, rather than annually to the
TCBA. In addition, it required the TRA to be transferred to the TCBA on a
monthly basis. Previous rules had called for TRA overcollections to be
transferred to the TCBA monthly, while undercollections were to remain in the
TRA until they were recovered from future overcollections or the end of the
rate freeze, whichever came first. Based on the new rules, the $4.5 billion TRA
undercollection as of December 31, 2000, and the coal and hydroelectric
balancing account overcollections were reclassified, and the TCBA balance was
recalculated to be a $2.9 billion undercollection (see further discussion of
the CPUC rate increase in the Rate Stabilization Proceeding section and the
components of the TCBA undercollection in the Status of Transition and Power
Procurement Costs Recovery section of SCE's Regulatory Environment).

On April 9, 2001, Edison International, SCE and the CDWR executed an MOU
providing for the sale of SCE's transmission assets, or other assets under
certain circumstances, recovery of SCE's net undercollected amount through the
application of proceeds of the asset sale and one or more securitization
financings, rate-making provisions for recovery of SCE's future power
procurement costs, settlement of SCE's legal actions against the CPUC, and
other elements of a comprehensive plan (see further discussion in Memorandum of
Understanding with the CDWR). The implementation of the MOU requires various
regulatory and legislative actions to be taken in the future. Until those
actions or actions in other proceedings are taken, which would include
modifying or reversing recent CPUC decisions that impair recovery of SCE's
power procurement and transition costs, SCE is not able to conclude that, under
applicable accounting principles, the $2.9 billion TCBA undercollection (as
recalculated above) and $1.3 billion (book value) of other regulatory assets
and liabilities, that were to be recovered through the TCBA mechanism by the
end of the rate freeze, are probable of recovery through the rate-making
process as of December 31, 2000.

4

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Edison International

As a result, accounting principles generally accepted in the United States
require that the net balance of these accounts be written off as a charge to
earnings as of December 31, 2000. This write-off consists of the following:

In millions
- -----------------------------------------------

TCBA (as recalculated) $ 2,878
Unamortized nuclear investment -- net 610
Purchased-power settlements 435
Unamortized loss on sale of plant 61
Other regulatory assets -- net 39
- -----------------------------------------------
Subtotal 4,023
Flow-through taxes 218
- -----------------------------------------------
Total regulatory assets -- net 4,241
Less income tax benefit (1,720)
- -----------------------------------------------
Net write-off $ 2,521
- -----------------------------------------------

This write-off is included in the income statement as a $4.0 billion charge to
provisions for regulatory adjustment clauses, and a $1.5 billion net reduction
in income tax expense.

As stated above, an MOU has been negotiated with representatives of the
Governor (see Memorandum of Understanding with the CDWR) to resolve the energy
crisis. The regulatory and legislative actions set forth in the MOU, if
implemented, are expected to result in a rate-making mechanism that would make
recovery of these regulatory assets probable. If and when those actions or
other actions that make such recovery probable are taken, and the necessary
rate-making mechanism is adopted, the regulatory assets would be restored to
the balance sheet, with a corresponding increase to earnings.

Excluding the write-off at SCE, Edison International's 2000 basic earnings per
share were $1.74, compared with $1.79 in 1999 and $1.86 in 1998. Excluding the
write-off, SCE earned $1.42 in 2000, compared with $1.39 in 1999 and $1.37 in
1998. Edison Mission Energy (EME) earned 38c in 2000, compared with 37c in
both 1999 and 1998. Edison Capital earned 41c in 2000, compared with 37c in
1999 and 29c in 1998. Edison Enterprises and Edison International (parent
company) incurred losses of 47c in 2000, compared with losses of 34c in 1999
and 17c in 1998. Edison International's 1999 earnings included a special
charge of 2c (a 6c charge at Edison Enterprises, partially offset by a 4c gain
at SCE).

Unless a rate-making mechanism is implemented in accordance with the MOU
described above or other necessary rate-making action is taken, future net
undercollections in the TCBA will be charged to earnings as the losses are
incurred. The losses (before tax) incurred in this balancing account (as
redefined) in January and February 2001 amount to approximately $800 million.
SCE anticipates that losses will continue unless a rate-making mechanism is
established. In addition to the losses from the TCBA undercollections, Edison
International expects its 2001 earnings to be negatively affected by the
recent fire and resulting damage at the San Onofre Nuclear Generating Station
Unit 3. See further discussion of the San Onofre fire in the San Onofre
Nuclear Generating Station section.

2000 vs. 1999

Excluding the $7.58 per share ($2.5 billion after tax) write-off in 2000 and
the 4c per share gain (discussed in 1999 vs. 1998 below) in 1999, SCE's 2000
earnings were $1.42 compared to $1.35 in 1999. The 7c per share increase was
mainly due to Edison International's share repurchase program referenced below
and discussed in Financial Condition.

EME's 2000 earnings of 38c per share increased 1c over 1999. The increase in
2000 was mainly due to Edison International's share repurchase program.

5

- --------------------------------------------------------------------------------
Management's Discussion and Analysis of Results of Operations and Financial
Condition

Edison Capital's 2000 earnings of 41c, up 4c over 1999, was primarily due to
increased earnings from new investments in infrastructure and leveraged leases,
partially offset by declining revenue from existing leveraged leases.

Edison Enterprises and the parent company showed a 47c loss in 2000, mostly the
result of higher interest expense at the parent company.

Excluding the write-off, the reduced number of outstanding shares (due to a
repurchase program discussed in Financial Condition) benefited Edison
International's earnings per share by 9c in 2000.

1999 vs. 1998

SCE's 1999 earnings of $1.39 included a $15 million, or 4c per share, tax
benefit due to a one-time adjustment that resulted from an Internal Revenue
Service ruling. Excluding the gain, SCE's 1999 earnings were $1.35 per share,
down 2c from 1998. The decrease was mainly due to the accelerated depreciation
of SCE's generation assets, partially offset by higher kWh sales in 1999.

EME's 1999 earnings of 37c were unchanged from 1998. Higher revenue from
existing projects and revenue from projects acquired in 1999 was offset by
affiliate stock option accruals. Edison Capital's 1999 earnings were 37c, up 8c
from 1998. The increase was mostly due to higher earnings from Edison Capital's
infrastructure investments and the sale of interests in affordable housing
projects, partially offset by affiliate stock option accruals.

Edison Enterprises and the parent company had a 1999 loss of 34c that included
a one-time adjustment of 6c per share ($23 million after tax) related to
actions taken at Edison Enterprises to close five businesses. Excluding the
one-time adjustment, Edison Enterprises and the parent company incurred a loss
of 28c in 1999, compared to a loss of 17c in 1998. Increased interest expense
at the parent company and continued investment in Edison Enterprises' ongoing
businesses contributed to most of the 1999 decrease.

The reduced number of outstanding shares as a result of the share repurchase
program benefited Edison International's earnings per share by 6c in 1999.

Operating Revenue

SCE's customers are able to choose to purchase power directly from an energy
service provider, thus becoming direct access customers, or continue to have
SCE purchase power on their behalf. Most direct access customers are billed by
SCE, but given a credit for the generation portion of their bills. Under
Assembly Bill 1 (First Extraordinary Session) (AB 1X), enacted on February 1,
2001, the CPUC was directed (on a schedule it determines) to suspend the
ability of retail customers to select alternative providers of electricity
until the CDWR stops buying power for retail customers.

During 2000, as a result of the power shortage in California, SCE's customers
on interruptible rate programs (which provide for a lower generation rate with
a provision that service can be interrupted if needed, with penalties for
noncompliance) were asked to curtail their electricity usage at various times.
As a result of noncompliance with SCE's requests, those customers were assessed
significant penalties. On January 26, 2001, the CPUC waived the penalties being
assessed to noncompliant customers until a reevaluation of the operation of the
interruptible programs can be completed.

Electric utility revenue increased in 2000 (as shown in the table below),
primarily due to: warmer weather in the second and third quarters of 2000 as
compared to the same periods in 1999; increased resale sales; and an increase
in revenue related to penalties customers incurred for not adhering to their
interruptible contracts. The increase in resale sales resulted from other
utilities and municipalities exercising their contractual option to buy more
power from SCE as the price of power purchased

6

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Edison International

through the California Power Exchange (PX) and Independent System Operator
(ISO) increased significantly in 2000. These increases were partially offset
by the credit given to customers who chose direct access. Electric utility
revenue increased by less than 1% in 1999, as increased kWh sales and revenue
resulting from maintenance work SCE was providing the new owners of generating
plants previously sold by SCE was almost completely offset by the credit given
to customers who chose direct access. On March 27, 2001, the CPUC affirmed
that the interim surcharge of 1c per kWh granted on January 4, 2001, is now
permanent. See further discussion in Rate Stabilization Proceeding.

In 2000, more than 92% of electric utility revenue was from retail sales.
Retail rates are regulated by the CPUC and wholesale rates are regulated by
the Federal Energy Regulatory Commission (FERC).

Due to warmer weather during the summer months, electric utility revenue
during the third quarter of each year is significantly higher than other
quarters.

The changes in electric utility revenue resulted from:

In millions Year Ended December 31, 2000 1999 1998
----------------------------------------------------------

Electric utility revenue --
Rate changes (including refunds) $ 120 $ (75) $(498)
Direct access credit (434) (213) (29)
Interruptible noncompliance penalty 102 6 --
Sales volume changes 520 195 (44)
Other 14 136 117
----------------------------------------------------------
Total $ 322 $ 49 $(454)
----------------------------------------------------------

Nonutility power generation revenue increased in both 2000 and 1999, primarily
due to revenue increases related to EME's Illinois, Ferrybridge and Fiddler's
Ferry, Homer City and Doga plants.

Due to warmer weather during the summer months, EME's nonutility power
generation revenue related to its Homer City plant and the Illinois plants is
usually higher during the third quarter of each year. Higher summer pricing
for EME's energy projects located on the western coast of the United States,
generally causes materially higher third quarter nonutility power generation
revenue than other quarters of the year. EME's First Hydro, Ferrybridge and
Fiddler's Ferry plants are expected to contribute more to nonutility power
generation revenue during the winter months.

Financial services and other revenue increased in 2000, mostly due to customer
growth at two of Edison International's subsidiaries (providers of energy
management and home security services). Financial services and other revenue
increased in 1999, mostly due to the closing of five affordable housing
syndications and additional lease transactions at Edison Capital.

Operating Expenses

Fuel expense increased in 2000 when compared to 1999. The increase was
primarily due to increased expenses at EME for its Illinois, Ferrybridge and
Fiddler's Ferry plants. Fuel expense increased in 1999 compared to 1998, also
due to an increase at EME for expenses at Homer City, the Ferrybridge and
Fiddler's Ferry plants, the Illinois plants, and the Doga plant in Turkey.
This increase was partially offset by a decrease at SCE resulting from the
sale of 12 generating plants in 1998.

Prior to April 1998, SCE was required under federal law and CPUC orders to
enter into contracts to purchase power from qualifying facilities (QFs) at
CPUC-mandated prices even though energy and capacity prices under many of
these contracts are generally higher than other sources. Purchased-power
expense related to contracts decreased in both 2000 and 1999. The decrease in
2000 was primarily due to a contract adjustment with a state agency, as well
as the terms in some of the

7

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Management's Discussion and Analysis of Results of Operations and Financial
Condition

remaining QF contracts reverting to lower prices. The decrease in 1999 was
primarily due to the terms in some of the remaining QF contracts reverting to
lower prices, as well as SCE's settlement agreements to terminate certain QF
contracts. SCE's settlement agreements with certain QFs decreased purchased-
power expense related to contracts by $47 million in 1999. SCE's purchased-
power settlement obligations were recorded as a liability. Because the
settlement payments were to be recovered through the TCBA mechanism as the
payments were made, a regulatory asset was also recorded. As of December 31,
2000, the purchased-power settlement regulatory asset was written off as a
charge to earnings. See further discussion of SCE's write-off in Earnings.

In 2000, PX/ISO purchased-power expense increased significantly due to
increased demand for electricity in California, dramatic price increases for
natural gas (a key input of electricity production), and structural problems
within the PX and ISO. The increased volume of higher priced PX purchases was
minimally offset by increases in PX sales revenue and ISO net revenue, as well
as the use of risk management instruments (gas call options and PX block
forward contracts). The gas call options (which were sold in October 2000) and
the PX block forward contracts mitigated SCE's transition cost recovery
exposure to increases in energy prices. SCE's use of gas call options reduced
PX/ISO purchased-power expense by $200 million in 2000 compared to 1999. SCE's
use of PX block forward contracts reduced PX/ISO purchased-power expense by
$688 million in 2000 compared to 1999. In 1999, PX/ISO purchased-power expense
increased compared to 1998, mainly due to three additional months of
PX transactions in 1999. However, when 1999 PX purchased-power expense was
compared on the same nine-month basis as 1998, the increase was less than 1%,
despite the fact that SCE experienced a significant decrease in the volume of
kWh sales through the PX. The lower volume of sales through the PX in 1999 was
the result of less generation at SCE (due to San Onofre refueling outages in
1999, divestiture of 12 generating plants in 1998 and reduced hydroelectric
generation) and fewer purchases from QFs. SCE's use of gas call options
decreased PX/ISO purchased-power expense by $8 million in 1999 compared to
1998. SCE's use of PX block forward contracts increased PX/ISO purchased-power
expense by $3 million in 1999 compared to 1998. For a further discussion of
SCE's hedging instruments and the recent significant increases in power prices,
see the SCE Issues section of Market Risk Exposures. As of December 15, 2000,
the FERC eliminated the requirement that SCE buy and sell its purchased and
generated power through the PX and ISO. See further discussion in Wholesale
Electricity Markets.

Due to SCE's noncompliance with the PX's tariff requirement for posting
collateral for all transactions in the day-ahead and day-of markets as a result
of the downgrade in its credit rating, the PX suspended SCE's market trading
privileges for the day-of market effective January 18, 2001, and, for the day-
ahead market effective January 19, 2001. See further discussion of SCE's
liquidity crisis in Financial Condition.

Provisions for regulatory adjustment clauses increased in 2000 and decreased in
1999. The 2000 increase was mainly due to SCE's write-off as of December 31,
2000, of $4.2 billion in regulatory assets and liabilities as a result of the
California energy crisis. See further discussion of SCE's write-off in the
Earnings section. In addition, the provision also increased in 2000 due to
adjustments to reflect potential regulatory refunds related to the outcome of
the CPUC's reevaluation of the operation of the interruptible rate programs.
The decrease in 1999 was mainly due to undercollections related to the TCBA and
the rate-making treatment of the rate reduction notes. These undercollections
were partially offset by overcollections related to the administration of
public purpose funds. The rate-making treatment associated with rate reduction
notes has allowed for the deferral of the recovery of a portion of the
transition-related costs, from a four-year period to a 10-year period. SCE's
use of gas call options increased the provisions by $200 million in 2000
compared to 1999, and decreased the provisions by $8 million in 1999 compared
to 1998.

Other operation and maintenance expense increased in 2000, primarily reflecting
increased plant operating expenses at EME's plants acquired in 1999, and
increases at two of Edison International's other nonutility subsidiaries
(providers of energy management and home security services). The

8

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Edison International

increases were partially offset by a $26 million decrease at Edison Capital,
associated with the syndication of affordable housing investments in 2000; a
$60 million decrease at EME in 2000, related to accrued compensation expense
reflecting lower valuation of the exchange offer for the affiliate stock
option plan; and decreases at SCE in 2000, related to lower expenses for
mandated transmission service (known as must-run reliability services); and
lower operating expenses at San Onofre. Mandated transmission service expense
decreased $120 million in 2000 compared to 1999. The $19 million decrease at
San Onofre in 2000 was primarily due to scheduled refueling outages at both
units in the first half of 1999. San Onofre had only one refueling outage in
2000. Other operation and maintenance expense increased in 1999, primarily due
to: accrued compensation expense incurred at EME and Edison Capital related to
affiliate stock options; increased plant operating expenses at EME's plants
acquired in 1999, as well as an increase at the Doga project; additional
reserves for five affordable housing syndications at Edison Capital; increases
at Edison Enterprises' security subsidiary; and the actions taken at Edison
Enterprises to close five businesses and refocus the ongoing businesses. In
addition, SCE had a net increase in other operation and maintenance expense
primarily related to its PX and ISO costs (including grid management costs),
partially offset by a decrease resulting from lower expenses incurred for its
distribution facilities. Lastly, a nonutility subsidiary incurred a decrease
in operating expenses in 1999 related to the sale of real estate in 1998.

Depreciation, decommissioning and amortization expense increased in both 2000
and 1999. The increase in both years is primarily due to EME's 1999
acquisitions of the Illinois, Ferrybridge and Fiddler's Ferry, and Homer City
plants.

Net gain on sale of utility plant in 2000 resulted from the sale of additional
property related to four of the generating stations SCE sold in 1998. The
gains were returned to the ratepayers through the TCBA mechanism.

Other Income and Deductions

Interest and dividend income increased in 2000, primarily due to increases in
interest earned on higher balancing account undercollections at SCE and
increases at EME related to higher cash balances and foreign exchange gains on
intercompany loans denominated in foreign currency. In 1999, interest and
dividend income decreased primarily due to lower cash balances at EME.

Other nonoperating income decreased in 2000, primarily due to the gains on
sales of equity investments in 1999 at SCE. This decrease was partially offset
by the gain on sale of an equity investment at Edison International's
insurance subsidiary in 2000. Other nonoperating income increased in 1999,
primarily due to the gains on sales of equity investments at SCE and a gain at
EME related to the sale of a partial interest in an oil and gas investment.

Interest expense -- net of amounts capitalized increased in both 2000 and
1999, reflecting additional long-term subsidiary debt at EME to finance its
acquisition of the Homer City, Ferrybridge and Fiddler's Ferry, and Illinois
generating plants. Increased long-term debt at the parent company and at
Edison Capital also contributed to the increased expense in both 2000 and
1999. Increased expense resulting from higher overall short-term debt balances
at both SCE and the parent company, and short-term debt utilized to fund a
portion of EME's 1999 acquisitions of the Illinois, the Ferrybridge and
Fiddler's Ferry, and the Homer City plants also contributed to the increases
in both 2000 and 1999. Interest expense resulting from balancing account
overcollections at SCE also contributed to the increase in 2000. Partially
offsetting the increase in 1999 was a decrease in SCE's interest on long-term
debt due to an adjustment of accrued interest in first quarter 1998 related to
the rate reduction notes issued in December 1997.

Other nonoperating deductions decreased in 2000 but increased in 1999. The
decrease in 2000 was mainly due to a write-off of start-up costs at EME (in
accordance with the implementation of a new accounting rule in first quarter
1999), as well as a decrease at Edison Capital related to syndications of

9

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Management's Discussion and Analysis of Results of Operations and Financial
Condition

affordable housing projects. The increase in other nonoperating deductions in
1999 compared to 1998 was primarily due to EME's 1999 write-off of start-up
costs, partially offset by a decrease at SCE in 1999. The 1999 decrease at SCE
resulted from expenses related to a ballot initiative in 1998 more than
offsetting additional accruals for regulatory matters in 1999.

Dividends on preferred securities increased in both 2000 and 1999. The increase
in 2000 reflects the issuance of quarterly income securities at the parent
company in July and October 1999. The 1999 increase in dividends on preferred
securities was primarily due to the additional issuance of preferred securities
at EME during 1999. Proceeds from the issuances were used primarily to finance
EME's 1999 plant acquisitions.

Income Taxes

Income taxes decreased in 2000, primarily due to the $1.5 billion income tax
benefit related to SCE's write-off as of December 31, 2000, of regulatory
assets and liabilities in the amount of $2.5 billion (after tax). Absent SCE's
write-off, Edison International's income tax expense increased in 2000, mainly
due to higher pre-tax income, as well as the income tax benefits EME and SCE
recorded in 1999. Income taxes decreased in 1999, primarily due to lower pre-
tax income, and income tax benefits EME recorded in 1999. In 1999, EME recorded
tax benefits associated with a partial sale of its interest in an oil and gas
joint venture and the refund of advanced corporation tax payments from the
United Kingdom (UK). Also in 1999, SCE recorded a $15 million tax benefit as
the result of an Internal Revenue Service ruling.

Financial Condition

Edison International's liquidity is primarily affected by debt maturities,
access to capital markets, dividend payments, capital expenditures, investments
in partnerships and unconsolidated subsidiaries, and SCE's power purchases.
Capital resources include cash from operations and external financings. As a
result of SCE's lack of creditworthiness (further discussed in Liquidity
Issues), at March 31, 2001, the fair market value of approximately $1.1 billion
of Edison International's short-term debt was approximately 80% of its carrying
value (as compared to 100% at December 31, 2000) and the fair market value of
its long-term debt was approximately 90% of its carrying value (as compared to
92% at December 31, 2000).

Beginning in 1995, Edison International's Board of Directors authorized the
repurchase of up to $2.8 billion of its outstanding shares of common stock.
Edison International repurchased more than 21 million shares (approximately
$400 million) of its common stock during the first six months of 2000. These
were the first repurchases since first quarter 1999. Between January 1, 1995,
and June 30, 2000, Edison International repurchased $2.8 billion (approximately
122 million shares) of its outstanding shares of common stock funded by
dividends from its subsidiaries (primarily from SCE).

Liquidity Issues

SCE

Sustained higher wholesale energy prices that began in May 2000 persisted
through Spring 2001. This resulted in an increasing undercollection in the TRA.
The increasing undercollection, coupled with SCE's anticipated near-term
capital requirements (included in the Projected Capital Requirements section of
Financial Condition) and the adverse reaction of the credit markets to
continued regulatory uncertainty regarding SCE's ability to recover its current
and future power procurement costs, have materially and adversely affected
SCE's liquidity. As a result of its liquidity crisis, SCE has taken and is
taking steps to conserve cash, so that it can continue to provide service to
its customers. As a part of this process, SCE has temporarily suspended
payments of certain obligations for principal and interest on outstanding debt
and for purchased power. As of March 31, 2001, SCE had $2.7 billion in

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obligations that were unpaid and overdue including: (1) $626 million to the PX
or ISO; (2) $1.1 billion to QFs; (3) $229 million in PX energy credits for
energy service providers; (4) $506 million of matured commercial paper;
(5) $206 million of principal and interest on its 5 7/8% notes; and (6) $7
million of other obligations. SCE's failure to pay when due the principal
amount of the 5 7/8% series of notes constitutes a default on the series,
entitling those noteholders to exercise their remedies. Such failure and the
failure to pay commercial paper when due could also constitute an event of
default on all the other series of notes (totaling $2.4 billion of outstanding
principal) if the trustee or holders of 25% in principal amount of the notes
give a notice demanding that the default be cured, and SCE does not cure the
default within 30 days. Such failures are also an event of default under SCE's
credit facilities, entitling those lenders to exercise their remedies
including potential acceleration of the outstanding borrowings of $1.6
billion. If a notice of default is received, SCE could cure the default only
by paying $700 million in overdue principal and interest to holders of
commercial paper and the 5 7/8% notes. Making such payment would further
impact SCE's liquidity. If a notice of default were received and not cured,
and the trustee or noteholders were to declare an acceleration of the
outstanding principal amount of the senior unsecured notes, SCE would not have
the cash to pay the obligation and could be forced to declare bankruptcy.

Subject to certain conditions, the bank lenders under SCE's credit facilities
agreed to forbear from exercising remedies, including acceleration of borrowed
amounts, against SCE with respect to the event of default arising from the
failure to pay the 5 7/8% notes and commercial paper when due.The initial
forbearance agreement expired on February 13, 2001, but it has been extended
twice and currently expires on April 28, 2001. At March 31, 2001, SCE had
estimated cash reserves of approximately $2.0 billion, which is approximately
$700 million less than its outstanding unpaid obligations (discussed above)
and overdue amounts of preferred stock dividends (see below). As of March 31,
2001, SCE resumed payment of interest on its debt obligations. If the MOU is
implemented, it is expected to allow SCE to recover its undercollected costs
and to restore SCE's creditworthiness, which would allow SCE to pay all of its
past due obligations.

The parent company has paid and expects to continue to pay its obligations, as
they are due, subject to obtaining financing as discussed below. SCE, Edison
Capital and the parent company have drawn on their entire lines of credit, and
only EME is able to obtain financing of any kind. To isolate EME from the
credit downgrades of Edison International and SCE and to help preserve the
value of EME, EME has adopted certain amendments to its articles of
incorporation and bylaws (see additional discussion in Cash Flows from
Financing Activities).

On March 27, 2001, the CPUC ordered SCE and the other California investor-
owned utilities to pay QFs for power deliveries on a going forward basis,
commencing with April 2001 deliveries. SCE must pay the QFs within 15 days of
the end of the QFs' billing period, and QFs are allowed to establish 15-day
billing periods. Failure to make a required payment within 15 days of delivery
would result in a fine equal to the amount owed to the QF. The CPUC decision
also modified the formula used in calculating payments to QFs by substituting
natural gas index prices based on deliveries at the Oregon border rather than
index prices at the Arizona border. The changes apply to all QFs, where
appropriate, whose payments are based on CPUC-approved short-run avoided costs
regardless of whether they use natural gas or other resources such as solar or
wind.

On March 27, 2001, the CPUC also issued decisions on the California
Procurement Adjustment (CPA) calculation (see CDWR Power Purchases discussion)
and the approval of a 3c per kWh rate increase (see Rate Stabilization
Proceeding discussion). Based on these two decisions, SCE estimates that
revenue going forward will not be sufficient to recover retained generation,
purchased-power and transition costs. In comments filed with the CPUC on March
29, 2001, and April 2, 2001, SCE provided a forecast showing that the net
effects of the rate increase, the payment ordered to be made to the CDWR, and
the QF decision discussed above could result in a shortfall to the CPA
calculation of

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Management's Discussion and Analysis of Results of Operations and Financial
Condition

$1.7 billion for SCE during 2001. To implement the MOU, it will be necessary
for the CPUC to modify or rescind these decisions.

In light of SCE's liquidity crisis, its Board of Directors did not declare
quarterly common stock dividends to SCE's parent, Edison International, in
either December 2000 or March 2001 and as a result, Edison International's
Board of Directors did not declare a common stock dividend to Edison
International's shareholders. Also, SCE's Board has not declared the regular
quarterly dividends for SCE's cumulative preferred stock, 4.08% Series, 4.24%
Series, 4.32% Series, 4.78% Series, 6.05% Series, 6.45% Series and 7.23% Series
in 2001. As of March 31, 2001, SCE's preferred stock dividends in arrears were
$6 million. As a result of SCE's $2.5 billion charge to earnings as of December
31, 2000, SCE's retained earnings are now in a deficit position and therefore
under California law, SCE will be unable to pay dividends as long as a deficit
remains. SCE does not meet other tests under which dividends can be paid from
sources other than retained earnings. As long as accumulated dividends on SCE's
preferred stock remain unpaid, SCE cannot pay any dividends on its common
stock.

SCE has begun immediate cost-cutting measures which, together with previously
announced actions, such as freezing new hires, postponing certain capital
expenditures and ceasing new charitable contributions, are aimed at reducing
general operating costs. These actions were expected to impact about 1,450 to
1,850 jobs, affect service levels for customers, and reduce near-term capital
expenditures to levels that will not sustain operations in the long term.
However, on March 15, 2001, the CPUC issued an order rescinding SCE's layoffs
of employees involved with service and reliability. SCE was also ordered to
restore specified service levels, make regular reports to the CPUC concerning
its cost-cutting measures, and track its cost savings pending future
adjustments to rates. The amount of the cost savings affected by the order is
not material. SCE's current actions, including the suspension of debt and
purchased-power obligations, are intended to allow it to continue to operate
while efforts to reach a regulatory solution, involving both state and federal
authorities, are underway. Additional actions by SCE may be necessary if the
energy and liquidity crisis is not resolved in the near future. See further
discussion in Status of Transition and Power Procurement Costs Recovery.

For additional discussion on the impact of California's energy crisis on SCE's
liquidity, see Cash Flows from Financing Activities. For a discussion on an
agreement to resolve SCE's crisis, see Memorandum of Understanding with the
CDWR.

SCE's future liquidity depends, in large part, on whether the MOU is
implemented, or other action by the California Legislature and the CPUC is
taken in a manner sufficient to resolve the energy crisis and the cash flow
deficit created by the current rate structure and the excessively high price of
energy. Without a change in circumstances, such as that contemplated by the
MOU, resolution of SCE's liquidity crisis and its ability to continue to
operate outside of bankruptcy is uncertain.

EME

EME has three corporate credit facilities that are scheduled to expire in May
2001 (total amount of $1 billion) and October 2001 ($500 million). From January
1, 2001, through March 31, 2001, EME has borrowed or issued additional letters
of credit of approximately $158 million under these credit facilities and has
an unused capacity of approximately $22 million at March 31, 2001. EME plans to
refinance its corporate credit facilities through modifications to its existing
credit facilities or by entering into new short-term facilities prior to their
expiration. EME's cash requirements in 2001 are expected to exceed its cash
distributions from its subsidiaries. EME's corporate cash requirements in 2001
include: debt service under its senior notes and intercompany notes resulting
from sale-leaseback transactions which total $149 million; capital requirements
for projects in development and under construction of $251 million; and
development costs, and general and administrative expenses. EME plans to
finance these activities through new short-term facilities and through the use
of project or subsidiary financings or capital markets debt, depending on
market conditions. However, there is no assurance that EME will be able to
enter into modifications to its existing credit facilities or obtain additional
debt to finance its

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needs or that the credit facilities can be modified or obtained under similar
terms and rates as its agreements. EME does believe that its corporate
financing plans will be successful in meeting its cash requirements in 2001.
In addition, to reduce debt and provide additional liquidity, EME may sell its
interest in individual projects in its project portfolio. Under one of EME's
credit facilities, EME is required to use 50% of the net proceeds from the
sale of assets and 75% of the net proceeds from the issuance of capital
markets debt to repay senior bank indebtedness, in each case in excess of $300
million in the aggregate. There is no assurance that EME will be able to sell
assets on favorable terms or that the sale of individual assets will not
result in a loss. On April 5, 2001, EME issued $600 million of 9.875% senior
notes, due in 2011. EME used the proceeds of the senior notes to repay and
permanently reduce portions of its corporate debt consisting of $105 million,
$45 million and $75 million of its $700 million, $300 million and $500 million
senior credit facilities, respectively. The remaining net proceeds will be
used for development costs and general corporate purposes.

The financial performance of the Ferrybridge and Fiddler's Ferry plants has
not matched EME's expectations, largely due to lower energy power prices
resulting from increased competition, climatic effects and uncertainties
surrounding the new electricity trading arrangements discussed in the EME
Issues section of Market Risk Exposures. (Also, see additional discussion of
the Ferrybridge and Fiddler's Ferry plants in Cash Flows from Financing
Activities.) In accordance with asset impairment accounting standards, EME has
evaluated the impairment of the Ferrybridge and Fiddler's Ferry power plants
and has determined that no impairment exists. As a result of the change in
power prices in the UK, EME is considering the sale of the Ferrybridge and
Fiddler's Ferry plants. A decision has not been made regarding whether or not
the sale of these plants will ultimately occur and, accordingly, these assets
are not classified as held for sale. However, if a decision to sell the
Ferrybridge and Fiddler's Ferry plants were made, it is likely that the fair
value of the assets would be substantially below their book value at December
31, 2000.

Edison Capital

Edison Capital historically received 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
consolidated tax return. However, these tax benefits and incentives are not
currently being utilized by Edison International and Edison Capital is not
currently receiving cash for them. Without such cash, Edison Capital must meet
its current obligations out of existing cash resources and/or by liquidating
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. Under the current circumstances, Edison Capital is not pursuing
any new investment opportunities.

Edison International

The parent company has fully drawn on the $618 million capacity of its
existing 364-day credit facility and has no other short-term borrowing
capacity. Because of the payment defaults by SCE on its notes and commercial
paper, the parent company is also technically in default under its credit
facility due to cross-default provisions. The administrative agent or a
majority in interest of the lenders under the credit

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Management's Discussion and Analysis of Results of Operations and Financial
Condition

facility may declare the outstanding loans to be immediately due and payable.
The lenders have agreed to forbear from exercising remedies until at least
April 28, 2001, subject to certain conditions. The credit facility is scheduled
to mature on May 14, 2001. In addition, the parent company has two series of
senior unsecured notes that mature on July 18, 2001 ($250 million) and November
1, 2001 ($350 million), respectively. The parent company is in discussions with
its bank lenders regarding a possible extension or refinancing of the existing
short-term credit facility. In addition, the parent company is seeking to
arrange interim financing arrangements that would enable the parent company to
pay the $600 million of maturing notes during 2001, and repay the $618 million
credit facility at maturity if necessary. The parent company's cash
requirements in 2001 are expected to exceed its cash distributions from its
subsidiaries. Therefore, the parent company is dependent on obtaining
additional financing to meet its cash requirements. The parent company believes
that, at a minimum, it will be able to obtain financing through borrowings
secured by a pledge of stock of EME. The terms of such borrowings may or may
not include a grant of options or warrants to purchase shares of stock of EME
in certain circumstances. Alternatively, the parent company may be able to
obtain capital market financing if it can obtain an upgrade in its credit
ratings. However, there is no assurance that the parent company will be able to
obtain the financing that it needs. The parent company does believe that its
corporate financing plans will be successful in meeting its cash requirements
in 2001. To reduce current cash requirements, the parent company may exercise
the right to defer interest payments pursuant to the terms of its outstanding
quarterly income debt securities. In addition, to provide additional liquidity,
the parent company may sell the stock or assets of certain nonutility
subsidiaries. There is no assurance that the parent company will be able to
sell assets on favorable terms or that the sale of individual assets will not
result in a loss.

Cash Flows from Operating Activities

Net cash provided by operating activities totaled $1.4 billion in 2000, $2.0
billion in 1999 and $1.4 billion in 1998. The decrease in cash flows provided
by operating activities in 2000 was primarily due to the extremely high prices
SCE paid for energy and ancillary services procured through the PX and ISO.
Cash flows provided by operations is expected to increase in the first half of
2001 as SCE conserves cash as result of the liquidity crisis (see Liquidity
Issues discussion).

Edison International's cash flow coverage of dividends was 3.8 times for 2000,
5.5 times for 1999 and 3.8 times for 1998. The decrease in 2000 reflects a
significant increase in SCE's balancing account undercollections related to the
unusually high prices SCE has been paying for energy and ancillary services
procured through the PX and ISO. The rate-making treatment of the gains on
sales of SCE's generating plants caused the increase in 1999. Beginning in
first quarter 2001, the cash flow coverage of dividends calculation will
reflect SCE's inability to pay dividends (discussed above in the Liquidity
Issues section).

SCE's estimates of cash available for operations in 2001 assume, among other
things, satisfactory reimbursement of costs incurred during California's energy
crisis, the receipt of adequate and timely rate relief, and the realization of
its assumptions regarding cost increases, including the cost of capital.

Cash Flows from Financing Activities

At December 31, 2000, Edison International and its subsidiaries had $400
million of borrowing capacity available under lines of credit totaling $3.6
billion. SCE had total lines of credit of $1.65 billion, with $125 million
available for the refinancing of certain variable-rate pollution-control bonds.
The parent company had drawn on all of its lines of credit at December 31,
2000. The nonutility subsidiaries had total lines of credit of $1.3 billion,
with $274 million available to finance general cash requirements. These
unsecured lines of credit have various expiration dates and can be drawn down
at negotiated or bank index rates. However, as of January 2, 2001, SCE had
drawn on its entire credit lines of $1.65 billion. As of January 31, 2001,
Edison Capital had borrowed an additional $130 million on its credit lines. The
proceeds were retained as a liquidity reserve. As a result, Edison Capital had
no additional credit lines as of January 31, 2001.

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Edison International

The parent company's short-term and long-term debt is used for general
corporate purposes, including investments in nonutility business activities.
EME uses its short-term and long-term debt to finance acquisitions and
development, as well as for general corporate purposes. Edison Capital's
short-term and long-term debt is used for general corporate purposes, as well
as investments. SCE's short-term debt is used to finance balancing account
undercollections, fuel inventories and general cash requirements, including
purchased-power payments. Long-term debt is used mainly to finance capital
expenditures. External financings are influenced by market conditions and
other factors. Because of the $2.5 billion charge to earnings, SCE does not
currently meet the interest coverage ratios that are required for SCE to issue
additional first mortgage bonds or preferred stock. In addition, because of
its current liquidity and credit problems, SCE is unable to obtain financing
of any kind.

As a result of investors' concerns regarding the California energy crisis and
its impact on SCE's liquidity and overall financial condition, SCE has
repurchased $549 million of pollution-control bonds that could not be
remarketed in accordance with their terms. These bonds may be remarketed in
the future if SCE's credit status improves sufficiently. In addition, the
parent company, SCE and Edison Capital have been unable to sell their
commercial paper and other short-term financial instruments.

In January 2001, Fitch IBCA, Standard & Poor's and Moody's Investors Service
lowered their credit ratings of Edison International, Edison Capital and SCE
to substantially below investment grade. In mid-April, Moody's removed the
companies' ratings from review for possible downgrade. The ratings remain
under review for possible downgrade by the other two agencies.

Subject to the outcome of regulatory, legislative and judicial proceedings,
including steps to implement the MOU, SCE intends to pay all of its
obligations.

California law prohibits SCE from incurring or guaranteeing debt for its
nonutility affiliates. Additionally, the CPUC regulates SCE's capital
structure, limiting the dividends it may pay Edison International.

In December 1997, $2.5 billion of rate reduction notes were issued on behalf
of SCE by SCE Funding LLC, a special purpose entity. These notes were issued
to finance the 10% rate reduction mandated by state law. The proceeds of the
rate reduction notes were used by SCE Funding LLC to purchase from SCE an
enforceable right known as transition property. Transition property is a
current property right created by the restructuring legislation and a
financing order of the CPUC and consists generally of the right to be paid a
specified amount from nonbypassable rates charged to residential and small
commercial customers. The rate reduction notes are being repaid over 10 years
through these non-bypassable residential and small commercial customer rates,
which constitute the transition property purchased by SCE Funding LLC. The
remaining series of outstanding rate reduction notes have scheduled maturities
beginning in 2001 and ending in 2007, with interest rates ranging from 6.17%
to 6.42%. The notes are secured by the transition property and are not secured
by, or payable from, assets of SCE or Edison International. SCE used the
proceeds from the sale of the transition property to retire debt and equity
securities. Although, as required by accounting principles generally accepted
in the United States, SCE Funding LLC is consolidated with SCE and the rate
reduction notes are shown as long-term debt in the consolidated financial
statements, SCE Funding LLC is legally separate from SCE. The assets of SCE
Funding LLC are not available to creditors of SCE or Edison International and
the transition property is legally not an asset of SCE or Edison
International. Due to its recent credit rating downgrade, in January 2001, SCE
began remitting its customer collections related to the rate reduction notes
on a daily basis.

To isolate EME from the credit downgrades of Edison International and SCE and
to help preserve the value of EME, EME has adopted certain amendments to its
articles of incorporation and bylaws. The provisions include the appointment
of an independent EME director whose consent is required for EME to:
consolidate or merge with any entity that does not have substantially similar
provisions in its organizational documents; institute or consent to
bankruptcy, insolvency or similar proceedings or actions; or declare or pay
dividends unless certain conditions exist. Such conditions are: EME has an

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Management's Discussion and Analysis of Results of Operations and Financial
Condition

investment grade rating and receives rating agency confirmation that the
dividend or distribution will not result in a downgrade, or such dividends do
not exceed $32.5 million in any quarter and EME meets a certain interest
coverage ratio for the immediately preceding four quarters. EME currently meets
this interest coverage ratio.

In July 2000, EME entered into a sale-leaseback transaction for certain
equipment, primarily Illinois peaker power units, with a third-party lessor for
$300 million. In connection with the sale-leaseback, EME purchased $255 million
of notes issued by the lessor that accrue interest at a variable rate depending
on EME's credit rating. The notes are due and payable in five years. The gain
recognized on the sale of the equipment has been deferred and is being
amortized over the term of the lease.

In August 2000, EME entered into a sale-leaseback transaction for power
facilities, located in Illinois, with third-party lessors for an aggregate
purchase price of $1.4 billion. Under the terms of the leases (between 30 years
and 33.75 years), EME will make semi-annual lease payments on each January 2
and July 2, beginning January 2, 2001. The lease costs will be levelized over
the terms of the respective leases. The gain recognized on the sale of the
power facilities has been deferred and is being amortized over the term of the
leases.

In December 2000, EME entered into agreements involving the construction of new
projects. Under the terms of one of the agreements, the lessor, as owner of the
projects, is responsible for the development and construction costs
(approximately $986 million) of the new projects using turbines procured by
EME. EME will supervise the development and construction of the projects as the
agent of the lessor and upon completion of construction of each project, EME
will lease the projects from the lessor. In connection with the lease, EME has
provided a residual value guarantee to the lessor at the end of the lease term.
EME is required to deposit treasury notes equal to 103% of the construction
costs as collateral for the lessor, which can only be used under certain
circumstances involving default of EME's performance obligations during
construction. The lease agreement provides a purchase option based on the lease
balance, which can be exercised at any time during the term. The lease term
ends in 2010.

One of the projects using turbines procured by EME may be used to meet the new
gas-fired generation commitment resulting from the acquisition of the Illinois
plants. As part of the purchase of the generating assets from Commonwealth
Edison (ComEd), EME's subsidiary committed to install one or more gas-fired
power plants having an additional gross dependable capacity of 500 megawatts
(MW) at existing or adjacent power plant sites in Chicago. Commercial
operations of this project must be completed by December 15, 2003. The
estimated cost to complete the construction of a 500-MW gas-fired power plant
is approximately $250 million.

EME has firm commitments related to the Italian wind projects of $3 million to
make equity contributions and $17 million for asset purchases. EME also has
contingent obligations to make additional contributions of $83 million,
primarily for equity support guarantees related to the Paiton project in
Indonesia and the ISAB project in Italy.

EME may incur additional obligations to make equity and other contributions to
projects in the future. As discussed above, due to its current liquidity
crisis, SCE has deferred payments to QFs, among others, due in January,
February and March 2001. EME has interests in eight partnerships who own power
plants (or QFs) in California and have power purchase agreements with Pacific
Gas and Electric Company (PG&E) and/or SCE. Some of the QFs owed by SCE, in
which EME has interests, have sought to minimize their exposure by reducing
deliveries under power purchase agreements. One of these partnerships has filed
a lawsuit against SCE (see further discussion in the Litigation section of
SCE's Regulatory Environment). On April 6, 2001, PG&E filed for Chapter 11
bankruptcy protection. As of March 31, 2001, EME's share of accounts receivable
due from PG&E was $29 million. It is unclear at this time what additional
actions, if any, the partnerships will take in regard to the utilities'
suspension of payments. As a result of the deferral of payments to these QFs,
the partnerships in which EME has interests, have called on the partners to
provide additional capital to fund operating costs of the power plants. Between
January 1, 2001, and March 31, 2001, EME subsidiaries have made equity

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Edison International

contributions of approximately $115 million to meet capital calls by the
partnerships. EME's subsidiaries and the other partners may be required to
make additional capital contributions to the partnerships.

EME's UK subsidiary has deferred certain required capital expenditures at the
Ferrybridge and Fiddler's Ferry power plants because the plants' financial
performance has not met expectations. As a result, the subsidiary is in breach
of technical requirements set forth in the plants' financing agreements
related to the acquisition of the plants. Also, due to the lower financial
performance, the subsidiary's debt service coverage ratio during 2000 declined
below the threshold specified in the financing documents. The subsidiary is
currently in discussions with financing parties to revise the required capital
expenditures program and to waive the breach of the financial ratio covenant
for 2000, and related technical defaults. There are no assurances that an
agreement can be met. The financing documents state that a breach of the
financial ratio covenant constitutes an immediate event of default and, if the
event of default is not waived, the financing parties are entitled to enforce
their security over the affiliate's assets, including the power plants. Due to
the timing of its cash flows and debt service payments, EME's UK subsidiary
utilized its debt service reserve to meet its debt service requirements in
2000.

Edison Capital has firm commitments of $228 million to fund affordable
housing, and energy and infrastructure investments.

Cash Flows from Investing Activities

Cash flows from investing activities are affected by additions to property and
plant, purchases and sales of assets including leasebacks, the nonutility
companies' investments in partnerships and unconsolidated subsidiaries, and
funding of nuclear decommissioning trusts. Decommissioning costs are recovered
in rates. These costs are expected to be funded from independent
decommissioning trusts that receive SCE contributions of approximately $25
million per year. In 1995, the CPUC determined the restrictions related to the
investments of these trusts. They are: not more than 50% of the fair market
value of the qualified trusts may be invested in equity securities; not more
than 20% of the fair market value of the trusts may be invested in
international equity securities; up to 100% of the fair market values of the
trusts may be invested in investment grade fixed-income securities including,
but not limited to, government, agency, municipal, corporate, mortgage-backed,
asset-backed, nondollar and cash equivalent securities; and derivatives of all
descriptions are prohibited. Contributions to the decommissioning trusts are
reviewed every three years by the CPUC. The contributions are determined from
an analysis of estimated decommissioning costs, the current value of trust
assets and long-term forecasts of cost escalation and after-tax return on
trust investments. Favorable or unfavorable investment performance in a period
will not change the amount of contributions for that period. However, trust
performance for the three years leading up to a review proceeding will provide
input into the contribution analysis for that proceeding's contribution
determination.

For 2000, cash flows from investing activities included the proceeds from
EME's sale-leaseback transactions with third parties and EME's purchase of
notes issued by one of the third-party lessors. For 1999, cash flows from
investing activities included EME's 1999 acquisitions of the Homer City,
Ferrybridge, Fiddler's Ferry and Illinois generating facilities, as well as an
ownership interest in Contact Energy. See further discussion of EME's
acquisitions in Note 14 to the Consolidated Financial Statements.

Cash used for the nonutility subsidiaries' investing activities was $1.2
billion in 2000, $9.0 billion in 1999 and $1.2 billion in 1998. The increase
in 1999 was primarily due to EME's 1999 acquisitions.

Projected Capital Requirements

Edison International's projected construction expenditures for 2001 are $1.1
billion. This projection reflects SCE's recently announced cost-cutting
measures discussed above in the Liquidity Issues section.

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Management's Discussion and Analysis of Results of Operations and Financial
Condition

Long-term debt maturities and sinking fund requirements for the next five years
are: 2001 -- $2.3 billion; 2002 -- $1.1 billion; 2003 -- $1.7 billion; 2004 --
$1.8 billion; and 2005 -- $499 million.

Estimated noncancelable lease payments for the next five years are: 2001 --
$196 million; 2002 -- $212 million; 2003 -- $210 million; 2004 -- $232 million;
and 2005 -- $269 million.

Preferred stock redemption requirements for the next five years are: 2001 --
zero; 2002 -- $105 million; 2003 -- $9 million; 2004 -- $9 million; and 2005 --
$9 million.

Market Risk Exposures

Edison International's primary market risk exposures arise from fluctuations in
energy prices, oil and gas prices, interest rates and foreign currency exchange
rates. Edison International's risk management policy allows the use of
derivative financial instruments to manage its financial exposures, but
prohibits the use of these instruments for speculative or trading purposes,
except at the new trading operation unit acquired by EME in September 2000 (see
EME Acquisitions). At December 31, 2000, a 10% change in market rates would
have had an immaterial effect on Edison International's financial instruments
not specifically addressed below.

SCE Issues

Changes in interest rates and in energy prices can have a significant impact on
SCE's results of operations.

SCE is exposed to changes in interest rates primarily as a result of its
borrowing and investing activities used for liquidity purposes and to fund
business operations, as well as to finance capital expenditures. The nature and
amount of SCE's long-term and short-term debt can be expected to vary as a
result of future business requirements, market conditions and other factors. As
a result of California's energy crisis, SCE has been exposed to significantly
higher interest rates, which has intensified its liquidity crisis (further
discussed in the Liquidity Issues section of Financial Condition).

At December 31, 2000, SCE did not believe that its short-term debt was subject
to interest rate risk, due to the fair market value being approximately equal
to the carrying value. SCE did believe that the fair market value of its fixed-
rate long-term debt was subject to interest rate risk. At December 31, 2000, a
10% increase in market interest rates would have resulted in a $222 million
decrease in the fair market value of SCE's long-term debt. A 10% decrease in
market interest rates would have resulted in a $244 million increase in the
fair market value of SCE's long-term debt. See further discussion in Financial
Condition of the impact of SCE's lack of creditworthiness on its short-term and
long-term debt.

SCE used an interest rate swap to reduce the potential impact of interest rate
fluctuations on floating-rate long-term debt. At December 31, 2000, a 10%
increase in market interest rates would have resulted in a $5 million increase
in the fair value of SCE's interest rate swap. A 10% decrease in market
interest rates would have resulted in an $8 million decrease in the fair value
of SCE's interest rate swap. As a result of the downgrade in SCE's credit
rating below the level allowed under the interest rate hedge agreement, on
January 5, 2001, the counterparty on this interest rate swap terminated the
agreement. As a result of the termination of the swap, SCE is paying a floating
rate on $196 million of its debt due 2008.

Since April 1998, the price SCE paid to acquire power on behalf of customers
was allowed to float, in accordance with the 1996 electric utility
restructuring law. Until May 2000, retail rates were sufficient to cover the
cost of power and other SCE costs. However, since May 2000, market power prices
have skyrocketed, creating a substantial gap between costs and retail rates. In
response to the dramatically higher prices, the ISO and the FERC have placed
certain caps on the price of power, but these caps are set at high levels and
are not entirely effective. For example, SCE paid an average of $248 per MW in
December 2000, versus an average of $32 per MW in December 1999.

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Edison International

SCE attempted to hedge a portion of its exposure to increases in power prices.
However, the CPUC has approved a very limited amount of hedging. In 1997, SCE
bought gas call options as a hedge against electricity price increases, since
gas is a primary component for much of SCE's power supply. These gas call
options were sold in October 2000, resulting in a $190 million gain (lowering
purchased-power expense) for 2000. In July 1999, SCE began forward purchases
of electricity through the PX block forward market. In November 2000, SCE
began purchases of energy through bilateral forward contracts. At December 31,
2000, the nominal value of SCE's block and bilateral forward contracts was
$234 million and $798 million, respectively. The block forward contracts
reduced purchased-power costs by $684 million in 2000.

At December 31, 2000, a 10% fluctuation in electricity prices would have
changed the fair market value of SCE's forward contracts by $187 million.

Because SCE has temporarily suspended payments for purchased power since
January 16, 2001, the PX sought to liquidate SCE's remaining block forward
contracts. Before the PX could do so, on February 2, 2001, the State of
California seized the contracts, but must pay SCE the reasonable value of the
contracts under the law. A valuation of the contracts is expected in mid-2001.
After other elements of the MOU are implemented, SCE would relinquish all
claims against the State for seizing these contracts.

Due to its speculative grade credit ratings, SCE has been unable to purchase
additional bilateral forward contracts, and some of the existing contracts
were terminated by the counterparties.

In January 2001, the CDWR began purchasing power for delivery to utility
customers. On March 27, 2001, the CPUC issued a decision directing SCE to,
among other things, immediately pay amounts owed to the CDWR for certain past
purchases of power for SCE's customers. See additional discussion of
regulatory proceedings related to CDWR activities in the Generation and Power
Procurement section of SCE's Regulatory Environment.

EME Issues

Changes in interest rates and in oil and gas prices, electricity pool pricing
and fluctuations in foreign currency exchange rates can have a significant
impact on EME's results of operations.

EME is exposed to changes in interest rates because it affects the cost of
capital needed to finance the construction and operation of EME's projects.
EME does not believe that its short-term debt is subject to interest rate
risk, due to the fair market value being approximately equal to the carrying
value. However, EME's long-term debt with fixed interest rates is subject to
interest rate risk. At December 31, 2000, a 10% increase in market interest
rates would have resulted in a $96 million decrease in the fair value of EME's
long-term debt. A 10% decrease in market interest rates would have resulted in
a $104 million increase in the fair value of EME's long-term debt.

EME has mitigated a portion of the risk of interest rate fluctuations by
arranging for fixed-rate or variable-rate financing with interest rate swaps
or other hedging mechanisms for a number of its project financings. Several of
EME's interest rate swap agreements mature prior to their underlying debt. At
December 31, 2000, a 10% fluctuation in market interest rates would have
changed the fair value of EME's interest rate hedge agreements by $17 million.

EME hedges a portion of the electric output of its plants in order to lock in
desirable outcomes. EME also manages the margin between electric prices and
fuel prices when deemed appropriate. EME uses forward contracts, swaps,
futures or option contracts to achieve these objectives.

Electric power generated at the Homer City plant is sold under bilateral
arrangements with domestic utilities and power marketers under short-term
contracts (two years or less) or to the Pennsylvania-

19

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Management's Discussion and Analysis of Results of Operations and Financial
Condition

New Jersey-Maryland Power Pool (PJM) or the New York Independent System
Operator (NYISO). These pools have short-term markets, which establish an
hourly clearing price. The Homer City plant is located in the PJM control area
and is physically connected to high-voltage transmission lines serving both the
PJM and NYISO markets. The Homer City plant can also transmit power to the
midwestern United States.

Electric power generated at the Illinois plants is sold under power purchase
agreements in which ComEd will purchase capacity and have the right to purchase
energy generated by EME's Illinois plants. The agreements, which began in
December 1999 and have a term of up to five years, provide for capacity and
energy payments. In January 2001, ComEd assigned its rights to Exelon
Generation Company LLC (ExGen). ExGen will be obligated to make a capacity
payment for the units under contract and an energy payment for the electricity
produced by these units and taken by ExGen. The capacity payments provide the
Illinois plants revenue for fixed charges, and the energy payments compensate
the Illinois plants for variable costs of production. If ExGen does not order
all the power from the units under contract, the Illinois plants may sell,
subject to specified conditions, the excess energy at market prices to
neighboring utilities, municipalities, third-party electric retailers, large
consumers and power marketers on a spot basis.

In September 2000, EME acquired the trading operations of Citizens Power LLC.
As a result of this acquisition, EME has expanded its trading operations beyond
the traditional marketing of electric power. EME's trading and price risk
management activities give rise to market risk, which represents the potential
loss that can be caused by a change in the market value of a particular
commitment. Market risks are actively monitored to ensure compliance with the
risk management policies of EME, which limit its total net exposure. EME
performs a value at risk analysis daily to monitor its overall market risk
exposure. 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 other techniques,
including the use of stress testing and worst-case scenario analysis, as well
as stop limits and counterparty credit exposure limits.

At December 31, 2000, a 10% fluctuation in fuel oil, natural gas and
electricity forward prices would have changed the fair market value of energy
contracts utilized by EME's domestic trading unit in energy trading and price
risk management activities by $16 million.

EME's projects in the UK currently sell their electric energy and capacity
through a centralized electricity pool, which establishes a half-hourly
clearing price, or pool price, for electric energy. This system had been in
place since 1989 but was replaced on March 27, 2001, with a bilateral physical
trading system, referred to as the new electricity trading arrangements.

The new electricity trading arrangements are the direct result of an October
1997 request by the Minister for Science, Energy and Industry who asked the UK
Director General of Electricity Supply to review the operation of the pool
pricing system. In July 1998 the Director General proposed that the current
structure of contracts for differences and compulsory trading via the pool at
half-hourly clearing prices bid a day ahead be abolished. The UK Government
accepted the proposals in October 1998 subject to reservations. Following this,
further proposals were published by the Government and the Director General in
July and October 1999. The proposals include, among other things, the
establishment of a spot market or voluntary short-term power exchanges
operating from 24 hours to three hours before a trading period; a balancing
mechanism to enable the system operator to balance generation and demand and
resolve any transmission constraints; a mandatory settlement process for
recovering imbalances between contracted and metered volumes with strong
incentives for being in balance; and a Balancing and Settlement Code Panel to
oversee governance of the balancing mechanism. Contracting over time periods
longer than the day-ahead market is not directly affected by the proposals.
Physical bilateral contracts will replace the current contracts for
differences, but will function in a similar manner. However, it remains
difficult to evaluate the future impact of the proposals.

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Edison International

A key feature of the new electricity trading arrangements is to require firm
physical delivery, which means that a generator must deliver, and a consumer
must take delivery, against their contracted positions or face assessment of
energy imbalance penalty charges by the system operator. A consequence of this
should be to increase greatly the motivation of parties to contract in advance
and develop forwards and futures markets of greater liquidity than at present.
Recent experience has been that the new electricity trading arrangements have
placed a significant downward pressure on forward contract prices.
Furthermore, another consequence may be that counterparties may require
additional credit support, including parent company guarantees or letters of
credit. Legislation in the form of the Utilities Act, which was approved in
July 2000, allows for the implementation of new electricity trading
arrangements and the necessary amendments to generators' licenses. Various key
documents were designated by the Secretary of State and signed by participants
in August 2000; however, due to difficulties encountered during testing,
implementation of the new trading arrangements was delayed from November 2000
until March 27, 2001.

The Utilities Act sets a principal objective for the UK Government and the
Director General to "protect the interests of consumers . . . where
appropriate by promoting competition . . ." This represents a shift in
emphasis toward consumer interest. But this is qualified by the recognition
that license holders should be able to finance their activities. The Act also
contains new powers for the Government to issue guidance to the Director
General on social and environmental matters, changes to the procedures for
modifying licenses, and a new power for the Director General to impose
financial penalties on companies for breach of license conditions. EME will be
monitoring the operation of these new provisions.

The Loy Yang B project in Australia sells its electrical energy through 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 system marginal
price each half-hour. To mitigate the exposure to price volatility of the
electricity traded in the pool, Loy Yang B has entered into a number of
financial hedges. From May 8, 1997, to December 31, 2000, 53% to 64% of the
plant output sold was hedged under vesting contracts, with the remainder of
the plant capacity hedged under the State hedge described below. Vesting
contracts were put into place by the State Government of Victoria, Australia,
between each generator and each distributor, prior to the privatization of
electric power distributors in order to provide more predictable pricing for
those electricity customers that were unable to choose their electricity
retailer. Vesting contracts set base strike prices at which the electricity
will be traded, and the parties to the agreement make payments, calculated
based on the difference between the price in the contract and the half-hourly
pool clearing price for the element of power under contract. Vesting contracts
were sold in various structures and accounted for as electricity rate swap
agreements. The State hedge with the State Electricity Commission of Victoria
is a long-term contractual arrangement based upon a fixed price commencing May
8, 1997, and terminating October 31, 2016. The State government guarantees the
State Electricity Commission of Victoria's obligations under the State hedge.
From January 2001 to July 2014, approximately 77% of the plant output sold is
hedged under the State hedge. From August 2014 to October 2016, approximately
56% of the plant output sold is hedged under the State hedge. Additionally,
Loy Yang B entered into a number of fixed forward electricity contracts
effective January 2001, which expire in either January 2002 or January 2003,
and which will further mitigate against the price volatility of the
electricity pool.

The New Zealand government has been undergoing a steady process of electric
industry deregulation since 1987. Reform in the distribution and retail supply
sector began in 1992 with legislation that deregulated electricity
distribution and provided for competition in the retail electric supply
function. The New Zealand Energy Market, established in 1996, is a voluntary
competitive wholesale market that allows for the trading of physical
electricity on a half-hourly basis. The Electricity Industry Reform Act, which
was passed in July 1998, was designed to increase competition at the wholesale
generation level by splitting up Electricity Company of New Zealand Limited,
the large state-owned generator, into three separate generation companies. The
Electricity Industry Reform Act also prohibits the ownership of both
generation and distribution assets by the same entity.

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Management's Discussion and Analysis of Results of Operations and Financial
Condition

The New Zealand government commissioned an inquiry into the electricity
industry in February 2000. This Inquiry Board's report was presented to the
government in mid-2000. The main focus of the report was on the monopoly
segments of the industry, transmission and distribution, with substantial
limitations being recommended in the way in which these segments price their
services in order to limit their monopoly power. Recommendations were also made
with respect to the retail customer in order to reduce barriers to customers
switching. In addition, the Board made recommendations in relation to the
wholesale market's governance arrangements with the purpose of streamlining
them. The recommended changes are now being progressively implemented.

At December 31, 2000, a 10% increase in pool prices would have resulted in a
$131 million decrease in the fair value of electricity rate swap agreements. A
10% decrease in pool prices would have resulted in a $130 million increase in
the fair value of electricity rate swap agreements.

At December 31, 2000, a 10% fluctuation in electricity prices would have
changed the fair value of forward contracts entered into by EME's Loy Yang B
project by $2 million.

Foreign currencies in the UK, Australia and New Zealand decreased in value
compared to the US dollar. The decrease in value of these currencies was the
primary reason for EME's foreign currency translation loss in 2000, included in
Edison International's Consolidated Statements of Changes in Common
Shareholders' Equity. At December 31, 2000, a 10% fluctuation in the value of
foreign currencies would have resulted in a foreign currency translation change
of $197 million.

In December 2000, EME entered into foreign currency forward exchange contracts,
in the ordinary course of business, to protect itself from adverse currency
rate fluctuations on anticipated foreign currency commitments with varying
maturities ranging from January 2001 to July 2002. The periods of the foreign
currency forward exchange contracts correspond to the periods of the hedged
transactions. At December 31, 2000, the outstanding notional amount of the
contracts was $91 million, consisting of contracts to exchange US dollars to
pound sterling.

At December 31, 2000, a 10% fluctuation in exchange rates would have changed
the fair value of EME's foreign currency exchange contracts by approximately $6
million.

Fluctuations in foreign currency exchange rates can affect the amount of EME's
equity contributions to, and distributions from its international projects. As
EME continues to expand into foreign markets, fluctuations in foreign currency
exchange rates can be expected to have a greater impact on EME's results of
operations in the future. At times, EME has hedged a portion of its current
exposure to fluctuations in foreign exchange rates through financial
derivatives, offsetting obligations denominated in foreign currencies, and
indexing underlying project agreements to US dollars or other indices
reasonably expected to correlate with foreign exchange movements. Statistical
forecasting techniques are used to help assess foreign exchange risk and the
probabilities of various outcomes. There can be no assurance, however, that
fluctuations in exchange rates will be fully offset by hedges or that currency
movements and the relationship between macro-economic variables will behave in
a manner that is consistent with historical or forecasted relationships.

Edison Capital Issues

Changes in interest rates and fluctuations in foreign currency exchange rates
can have a significant impact on Edison Capital's results of operations.

Edison Capital is exposed to changes in interest rates primarily as a result of
its borrowing and investing activities used for general corporate purposes, as
well as investments. The nature and amount of Edison Capital's long-term and
short-term debt can be expected to vary as a result of future business
requirements, market conditions and other factors.

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Edison International

At December 31, 2000, Edison Capital did not believe that its short-term debt
was subject to interest rate risk, due to the fair market value being
approximately equal to the carrying value. Edison Capital did believe that the
fair market value of its fixed-rate long-term debt was subject to interest
rate risk. At December 31, 2000, a 10% increase in market interest rates would
have resulted in an $11 million decrease in the fair market value of Edison
Capital's long-term debt. A 10% decrease in market interest rates would have
resulted in a $12 million increase in the fair market value of Edison
Capital's long-term debt.

Edison Capital has entered into interest rate swap agreements to reduce actual
or expected exposure to interest rate fluctuations. At December 31, 2000, a
10% fluctuation in market interest rates would have changed the fair value of
Edison Capital's swap agreements by approximately $5 million.

Edison Capital has entered into foreign currency contracts to reduce the
potential impact of changes in foreign exchange rates and future foreign
currency denominated cash flows. At December 31, 2000, the outstanding
notional amount of the contracts was approximately $13 million, consisting of
contracts to exchange US dollars to Great British Pounds.

At December 31, 2000, a 10% increase in exchange rates would have resulted in
an immaterial decrease in the fair value of Edison Capital's foreign currency
contracts. A 10% decrease in exchange rates would have resulted in a $2
million decrease in the fair value of Edison Capital's foreign currency
contracts.

Edison International Issues

The parent company is exposed to changes in interest rates primarily as a
result of its borrowing and investing activities used for general corporate
purposes, including investments in nonutility business activities. The nature
and amount of the parent company's long-term and short-term debt can be
expected to vary as a result of future business requirements, market
conditions and other factors.

At December 31, 2000, the parent company did not believe that its short-term
debt was subject to interest rate risk, due to the fair market value being
approximately equal to the carrying value. The parent company did believe that
the fair market value of its fixed-rate long-term debt was subject to interest
rate risk. At December 31, 2000, a 10% increase in market interest rates would
have resulted in a $23 million decrease in the fair market value of the parent
company's long-term debt. A 10% decrease in market interest rates would have
resulted in a $24 million increase in the fair market value of the parent
company's long-term debt.

At March 31, 2001, due to the liquidity issues it faces, the parent company
now believes that its short-term debt is subject to interest rate risk. A 10%
increase in market interest rates would have resulted in a $9 million decrease
in the fair market value of the parent company's short-term debt. A 10%
decrease in market interest rates would have resulted in a $10 million
increase in the fair market value of the parent company's short-term debt.

Paiton Project

A wholly owned subsidiary of EME owns a 40% interest and has a $490 million
investment (at December 31, 2000) in the Paiton project, a 1,230-MW coal-fired
power plant in Indonesia. The revenue schedule is higher in the early years
and decreases over time. The plant's output is fully contracted with the
state-owned electricity company for payment in Indonesian Rupiah, with the
portion of such payments intended to cover non-Rupiah project costs (including
returns to investors) adjusted to account for exchange rate fluctuations
between the Indonesian Rupiah and the US dollar. The project received
substantial finance and insurance support from the Export-Import Bank of the
United States and various other governmental agencies. The state-owned
electricity company's payment obligations are supported by the Indonesian
government.

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Management's Discussion and Analysis of Results of Operations and Financial
Condition

The projected rate of growth of the Indonesian economy and the exchange rate of
Indonesian Rupiah into US dollars have deteriorated significantly since the
Paiton project was contracted, approved and financed. The Paiton project's
senior debt ratings have been reduced from investment grade to speculative
grade based on the rating agencies' determination that there is increased risk
that the state-owned electricity company might not be able to honor the power
purchase agreement with Paiton. The Indonesian government has arranged to
reschedule senior debt owed to foreign governments and has entered into
discussions about rescheduling senior debt owed to private lenders.

One of the Paiton units began commercial operation in May 1999 and the other
unit in July 1999. Because of the economic downturn, the state-owned
electricity company was experiencing low electricity demand and, therefore
ordered no power from the Paiton plant through February 2000. The state-owned
electricity company filed a lawsuit contesting the validity of its agreement to
purchase electricity from the Paiton project. The lawsuit was withdrawn in
January 2000, and in connection with this withdrawal, the parties entered into
an interim agreement for the period through December 31, 2000, under which the
levels of power ordered, and the fixed and energy payment amounts were agreed.
As of December 31, 2000, the state-owned electricity company had made all fixed
payments due under the interim agreement totaling $115 million and all payments
due for energy delivered by the plant to the state-owned electricity company.
As part of the continuing negotiations on a long-term restructuring of the
revenue schedule, Paiton and the state-owned electricity company agreed in
January 2001 on a Phase I agreement for the period from January 1, 2001,
through June 30, 2001. This agreement provides for fixed monthly payments of
$108 million over its six-month duration and for the payment for energy
delivered to the state-owned electricity company from the plant during this
period. Paiton and the state-owned electricity company intend to complete the
negotiations of the future phases of a new long-term revenue schedule during
the six-month duration of the Phase I agreement. To date, the state-owned
electricity company has made all fixed and energy payments due under the Phase
I agreement.

In October 1999, the project entered into an interim agreement with its lenders
in which the lenders waived defaults during the term of the agreement and
effectively agreed to defer payments of principal until July 31, 2000. The
lenders had agreed to an extension of the agreement through December 31, 2000
(which has now been extended through December 31, 2001). Paiton has received
lender approval of the Phase I agreement.

Under the terms of the power purchase agreement, the state-owned electricity
company has been required to continue to pay for capacity and fixed operating
costs once each unit and the plant achieved commercial operation. As of
December 31, 2000, the state-owned electricity company had not paid invoices
totaling $814 million for capacity charges and fixed operating costs under the
power purchase agreement. All overdue amounts under the power purchase
agreement continue to accumulate, minus the fixed monthly payments made under
the year 2000 interim agreement and under the recently agreed Phase I
agreement, with the payment of these overdue amounts to be dealt with in
connection with the overall long-term restructuring of the revenue schedule. In
this regard, under the Phase I agreement, Paiton has agreed that, so long as
the Phase I agreement is complied with, it will seek to recoup no more than
$590 million of the above overdue amounts, the payment of which is to be dealt
with in connection with the overall revenue schedule restructuring.

Any material modifications of the power purchase agreement resulting from the
continuing negotiation of a new long-term revenue schedule could require a
renegotiation of the Paiton project's debt agreements. The impact of any such
renegotiations with the state-owned electricity company, the Indonesian
government or the project's creditors on EME's expected return on its
investment in Paiton is uncertain at this time; however, EME believes that it
will ultimately recover its investment in the project.

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Edison International

EME Acquisitions

In March 2000, EME completed its acquisition of Edison Mission Wind Power
Italy B.V., formerly known as Italian Vento Power Corp. Energy 5 B.V. Edison
Mission Wind owns a 50% interest in a series of wind-generated power projects
in operation or under development in Italy. When all of the projects under
development are completed, currently scheduled for 2002, the total capacity of
these projects will be 283 MW. The purchase price of the acquisition is $44
million with equity contribution obligations of up to $16 million, depending
on the number of projects that are ultimately developed. As of December 31,
2000, EME has paid $27 million toward the purchase price and $13 million in
equity contributions.

In September 2000, EME completed a transaction with P&L Coal Holdings
Corporation and Gold Fields Mining Corporation to acquire the trading
operations of Citizens Power LLC and a minority interest in certain structured
transaction investments relating to long-term power purchase agreements. The
purchase price of $45 million was based on $25 million plus the fair market
value of the trading portfolio and the structured transaction investments at
the date of acquisition. The acquisition was funded with cash. As a result of
this acquisition, EME has expanded its trading operations beyond the
traditional marketing of its electric power. By the end of the third quarter
of 2000, the Citizens' trading operations were merged into EME's marketing
operations.

In November 2000, EME completed a transaction with Texaco Inc. to purchase a
proposed 560-MW gas-fired combined cycle project (Sunrise project) in central
California. The acquisition includes all rights, title and interest held by
Texaco in the Sunrise project, except that Texaco has an option to repurchase
a 50% interest in the project prior to commercial operation. As part of this
transaction, EME also acquired an option to purchase two gas turbines that it
plans to utilize in the project, and provided Texaco options to purchase two
of the turbines under a lease agreement and to acquire 50% interests in 1,000
MW of future power plant projects EME designates. Phase I is scheduled for
completion in August 2001 and Phase II is scheduled for completion in June
2003. The total purchase price was $27 million. The acquisition was funded
with cash. The estimated construction costs are approximately $400 million. As
discussed in the California Governor's Proposal section of SCE's Regulatory
Environment, one of the elements of the Governor's proposal is the commitment
of the entire output of the Sunrise project being developed by EME, at cost-
based rates for 10 years. As a result, EME is negotiating with the CDWR
regarding detailed terms and conditions of a long-term, cost-based power
purchase agreement. No assurance can be provided that EME will be successful
in reaching a final agreement.

In February 2001, EME completed the acquisition of a 50% interest in CBK Power
Co. Ltd. in exchange for $20 million. CBK Power has entered into a 25-year
build-rehabilitate-transfer-and-operate agreement with National Power
Corporation related to the 726-MW Caliraya-Botocan-Kalayaan (CBK)
hydroelectric project located in the Philippines. Financing for this $460
million project has been completed with equity contributions of $117 million
(EME's share is $59 million) required to be made upon completion of the
rehabilitation and expansion, currently scheduled in 2003. Debt financing has
been arranged for the remainder of the cost for this project.

SCE's Regulatory Environment

SCE operates in a highly regulated environment in which it has an obligation
to deliver electric service to customers in return for an exclusive franchise
within its service territory and certain obligations of the regulatory
authorities to provide just and reasonable rates. In 1996, state lawmakers and
the CPUC initiated the electric industry restructuring process. SCE was
directed by the CPUC to divest the bulk of its gas-fired generation portfolio.
Today, independent power companies own those generating plants. Along with
electric industry restructuring, a multi-year freeze on the rates that SCE
could charge its customers was mandated and transition cost recovery
mechanisms (as described in Status of Transition and Power Procurement Costs
Recovery) allowing SCE to recover its stranded costs associated with

25

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Management's Discussion and Analysis of Results of Operations and Financial
Condition

generation-related assets were implemented. California's electric 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. However, since May 2000, the prices charged by sellers of power have
escalated far beyond what SCE can currently charge its customers. See further
discussion in Wholesale Electricity Markets.

Generation and Power Procurement

During the rate freeze, revenue from generation-related operations has been
determined through the market and transition cost recovery mechanisms, which
included the nuclear rate-making agreements. The portion of revenue related to
coal generation plant costs (Mohave Generating Station and Four Corners
Generating Station) that was 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 have now been transferred to the TRA on a monthly basis,
retroactive to January 1, 1998. In addition, the TRA balance, whether over- or
undercollected, has now been transferred to the TCBA on a monthly basis,
retroactive to January 1, 1998. 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 and
these two balancing accounts have become inactive. As a key element of the MOU,
SCE would continue to own its generation assets, which would be subject to
cost-based ratemaking, through 2010. The MOU calls for the CPUC to adopt cost
recovery mechanisms consistent with SCE obtaining and maintaining an investment
grade credit rating.

SCE has been recovering its investment in its nuclear facilities on an
accelerated basis in exchange for a lower authorized rate of return on
investment. SCE's nuclear assets are earning an annual rate of return on
investment of 7.35%. In addition, the San Onofre incentive pricing plan
authorizes a fixed rate of approximately 4c per kWh generated for operating
costs including incremental capital costs, nuclear fuel and nuclear fuel
financing costs. The San Onofre plan commenced in April 1996, and ends at the
earlier of December 2001 or the date when the statutory rate freeze ends for
the accelerated recovery portion, and in December 2003 for the incentive-
pricing portion. The Palo Verde Nuclear Generating Station's operating costs,
including incremental capital costs, and nuclear fuel and nuclear fuel
financing costs, are subject to balancing account treatment. The Palo Verde
plan commenced in January 1997 and ends in December 2001. The benefits of
operation of the San Onofre units and the Palo Verde units are required to be
shared equally with ratepayers beginning in 2004 and 2002, respectively.
Beginning January 1, 1998, both the San Onofre and Palo Verde rate-making plans
became part of the TCBA mechanism. These rate-making plans and the TCBA
mechanism will continue for rate-making purposes at least through the end of
the rate freeze period. Under the MOU, both nuclear facilities would be subject
to cost-based ratemaking upon completion of their respective rate-making plans
and the sharing mechanisms that were to begin in 2004 and 2002 would be
eliminated. However, due to the

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various unresolved regulatory and legislative issues (as discussed in Status
of Transition and Power Procurement Costs Recovery), SCE is no longer able to
conclude that the unamortized nuclear investment regulatory assets (as
discussed in Accounting for Generation-Related Assets and Power Procurement
Costs) are probable of recovery through the rate-making process. As a result,
these balances were written off as a charge to earnings as of December 31,
2000 (see further discussion in Earnings).

In 1999, SCE filed an application with the CPUC establishing a market value
for its hydroelectric generation-related assets at approximately $1.0 billion
(almost twice the assets' book value) and proposing to retain and operate the
hydroelectric assets under a performance-based, revenue-sharing mechanism. If
approved by the CPUC, SCE would be allowed to recover an authorized,
inflation-indexed operations and maintenance allowance, as well as a
reasonable return on capital investment. A revenue-sharing arrangement would
be activated if revenue from the sale of hydroelectricity exceeds or falls
short of the authorized revenue requirement. SCE would then refund 90% of the
excess revenue to ratepayers or recover 90% of any shortfalls from ratepayers.
If the MOU is implemented, SCE's hydroelectric assets will be retained through
2010 under cost-based rates, or they may be sold to the state if a sale of
SCE's transmission assets is not completed under certain circumstances. In
June 2000, SCE credited the TCBA with the estimated excess of market value
over book value of its hydroelectric generation assets and simultaneously
recorded the same amount in the generation asset balancing account (GABA),
pursuant to a CPUC decision. This balance was to remain in GABA until final
market valuation of the hydroelectric assets. If there were a difference in
the final market value, it would have been credited to or recovered from
customers through the TCBA. Due to the various unresolved regulatory and
legislative issues (as discussed in Status of Transition and Power Procurement
Costs Recovery), the GABA transaction was reclassified back to the TCBA, and
as discussed in the Earnings section, the TCBA balance (as recalculated based
on a March 27, 2001, CPUC interim decision discussed in Rate Stabilization
Proceeding) was written off as of December 31, 2000.

During 2000, SCE entered into agreements to sell the Mohave, Palo Verde and
Four Corners generation stations. The sales were pending various regulatory
approvals. Due to the shortage of electricity in California and the increasing
wholesale costs, state legislation was enacted in January 2001 barring the
sale of utility generation stations until 2006. Under the MOU, SCE would
continue to retain its generation assets through 2010.

CDWR Power Purchases

Pursuant to an emergency order signed by the Governor, the CDWR began making
emergency power purchases for SCE's customers on January 18, 2001. On February
1, 2001, AB 1X was enacted into law. The new law 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 revenue
bonds to finance electricity purchases. The new law directed the CPUC to
determine the amount of a CPA as a residual amount of SCE's generation-related
revenue, after deducting the cost of SCE-owned generation, QF contracts,
existing bilateral contracts and ancillary services. The new law also directed
the CPUC to determine the amount of the CPA that is allocable to the power
sold by the CDWR which will be payable to the CDWR when received by SCE. On
March 7, 2001, the CPUC issued an interim order in which it held that the
CDWR's purchases are not subject to prudency review by the CPUC, and that the
CPUC must approve and impose, either as a part of existing rates or as
additional rates, rates sufficient to enable the CDWR to recover its revenue
requirements.

On March 27, 2001, the CPUC issued an interim CDWR-related order requiring SCE
to pay the CDWR a per kWh price equal to the applicable generation-related
retail rate per kWh for electricity (based on rates in effect on January 5,
2001), 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 1c per kWh temporary surcharge adopted by the
CPUC on January 4, 2001) less certain

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Management's Discussion and Analysis of Results of Operations and Financial
Condition

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 6.277c per
kWh. The CPUC determined that the company-wide generation-related rate
component is 7.277c per kWh (which will increase to 10.277c per kWh for
electricity delivered after March 27, 2001, due to the 3c surcharge discussed
in Rate Stabilization Proceeding), for each kWh delivered to customers
beginning February 1, 2001, until more specific rates are calculated. The CPUC
ordered SCE to pay the CDWR within 45 days after the CDWR supplies power to
retail customers. Using these rates, SCE has billed customers $196 million for
energy sales made by the CDWR during the period January 19 through March 31,
2001, and has forwarded $52 million to the CDWR on behalf of these customers as
of March 31, 2001.

On April 3, 2001, the CPUC adopted the method (originally proposed in the March
27 CDWR-related order discussed above) it will use to calculate the CPA (which
was established by AB 1X) and then applied the method to calculate a company-
wide CPA rate for SCE. The CPUC used that rate to determine the CPA revenue
amount that can be used by the CDWR for issuing bonds. The CPUC stated that its
decision is narrowly focused to calculate the maximum amount of bonds that the
CDWR may issue and does not dedicate any particular revenue stream to the CDWR.
The CPUC determined that SCE's CPA rate is 1.120c per kWh, which generates
annual revenue of $856 million. In its calculation of the CPA, the CPUC
disregarded all of the adjustments requested by SCE in its comments filed on
March 29 and April 2, 2001. SCE's comments included, among other things, a
forecast showing that the net effect of the rate increases (discussed in Rate
Stabilization Proceeding), as well as the March 27 QF payment decision
(discussed in Liquidity Issues) and the payments ordered to be made to CDWR
(discussed above), could result in a shortfall in the CPA calculation of $1.7
billion for SCE during 2001. SCE estimates that its future revenue will not be
sufficient to cover its retained generation, purchased-power and transition
costs. To implement the MOU described in Memorandum of Understanding with the
CDWR, the CPUC will need to modify the calculation methods and provide
reasonable assurance that SCE will be able to recover its ongoing costs.

SCE believes that the intent of AB 1X was for the CDWR to assume full
responsibility for purchasing all power needed to serve the retail customers of
electric utilities, in excess of the output of generating plants owned by the
electric utilities and power delivered to the utilities under existing
contracts. However, the CDWR has stated that it is only purchasing power that
it considers to be reasonably priced, leaving the ISO to purchase in the short-
term market the additional power necessary to meet system requirements. The
ISO, in turn, takes the position that it will charge SCE for the costs of power
it purchases in this manner. If SCE is found responsible for any portion of the
ISO's purchases of power for resale to SCE's customers, SCE will continue to
incur purchased-power costs in addition to the unpaid costs described above. In
its March 27, 2001, interim order, the CPUC stated that it cannot assume that
the CDWR will pay for the ISO purchases and that it does not have the authority
to order the CDWR to do so. Litigation among certain power generators, the ISO
and the CDWR (to which SCE is not a party), and proceedings before the FERC (to
which SCE is a party), may result in rulings clarifying the CDWR's financial
responsibility for purchases of power. On April 6, 2001, the FERC issued an
order confirming that the ISO must have a creditworthy buyer for any
transactions. In any event, SCE takes the position that it is not responsible
for purchases of power by the CDWR or the ISO on or after January 18, 2001, the
day after the Governor signed the order authorizing the CDWR to begin
purchasing power for utility customers. SCE cannot predict the outcome of any
of these proceedings or issues. The recently executed MOU states that the CDWR
will assume the entire responsibility for procuring the electricity needs of
retail customers within SCE's service territory through December 31, 2002, to
the extent those needs are not met by generation sources owned by or under
contract to SCE (SCE's net short position). SCE will resume buying power for
its net short position after 2002. The MOU calls for the CPUC to adopt cost
recovery mechanisms to make it financially practicable for SCE to reassume this
responsibility.

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Status of Transition and Power Procurement Costs Recovery

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 regulatory commitments consisting of recovery of
costs incurred to provide service to customers. Such commitments include the
recovery of income tax benefits previously flowed through to customers,
postretirement benefit transition costs, accelerated recovery of investment in
San Onofre Units 2 and 3 and the Palo Verde units, and certain other costs.
Transition costs related to power-purchase contracts are being recovered
through the terms of each contract. Most of the remaining transition costs may
be recovered through the end of the transition period (not later than March
31, 2002). Although the MOU provides for, among other things, SCE to be
entitled to sufficient revenue to cover its costs from January 2001 associated
with retained generation and existing power contracts, the implementation of
the MOU requires the CPUC to modify various decisions (discussed in Rate
Stabilization Proceeding). Until the various regulatory and legislative
actions necessary to implement the MOU or other actions that make such
recovery probable, are taken, SCE is not able to conclude that the regulatory
assets and liabilities related to purchased-power settlements, the unamortized
loss on SCE's generating plant sales in 1998, and various other regulatory
assets and liabilities (including income taxes previously flowed through to
customers) related to certain generating assets are probable of recovery
through the rate-making process. As a result, these balances were written off
as a charge to earnings as of December 31, 2000 (see further discussion in
Earnings).

During the rate freeze period, there are three sources of revenue available to
SCE for transition cost recovery: 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. However, due to events discussed elsewhere in
this report, revenue from the sale or valuation of generation assets in excess
of book values (state legislation enacted in January 2001 bars the sale of
SCE's remaining generation assets until 2006) and from the sale of SCE-
controlled generation into the ISO and PX markets (see discussion in
Generation and Power Procurement) are no longer available to SCE. During 1998,
SCE sold all of its gas-fueled generation plants for $1.2 billion, over $500
million more than the combined book value. Net proceeds of the sales were used
to reduce transition costs, which otherwise were expected to be collected
through the TCBA mechanism.

Net market revenue from sales of power and capacity from SCE-controlled
generation sources was also applied to transition cost recovery. Increases in
market prices for electricity affected SCE in two fundamental ways prior to
the CPUC's March 27, 2001, rate stabilization decision. First, CTC revenue
decreased because there was less or no residual revenue from frozen rates due
to higher cost PX and ISO power purchases. Second, transition costs decreased
because there was increased net market revenue due to sales from SCE-
controlled generation sources to the PX at higher prices (accumulated as an
overcollection in the coal and hydroelectric balancing accounts). Although the
second effect mitigated the first to some extent, the overall impact on
transition cost recovery was negative because SCE purchased more power than it
sold to the PX. In addition, higher market prices for electricity adversely
affected SCE's ability to recover nontransition costs during the rate freeze
period. Since May 2000, market prices for electricity were extremely high and
there was insufficient revenue from customers under the frozen rates to cover
all costs of providing service during that period, and therefore there was no
positive residual CTC revenue transferred into the TCBA.

CTC revenue is determined residually (i.e., CTC revenue is 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). The CTC applies to all customers who are using
or begin using utility services on or after the CPUC's 1995 restructuring
decision date. Residual CTC revenue is calculated through the TRA mechanism.
Under CPUC decisions in existence prior to March 27, 2001, positive residual
CTC revenue (TRA overcollections) was transferred to the TCBA monthly; TRA

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Management's Discussion and Analysis of Results of Operations and Financial
Condition

undercollections were to remain in the TRA until they were offset by
overcollections, or the rate freeze ended, whichever came first. Pursuant to
the March 27, 2001, rate stabilization decision, both positive and negative
residual CTC revenue is transferred to the TCBA on a monthly basis, retroactive
to January 1, 1998 (see further discussion in Rate Stabilization Proceeding).

Upon recalculating the TCBA balance based on the new decision, SCE has received
positive residual CTC revenue (TRA overcollections) of $4.7 billion to recover
its transition costs from the beginning of the rate freeze (January 1, 1998)
through April 2000. As a result of sustained higher market prices, SCE
experienced the first month in which costs exceeded revenue in May 2000. Since
then, SCE's costs to provide power have continued to exceed revenue from frozen
rates and as a result, the cumulative positive residual CTC revenue flowing
into the TCBA mechanism has been reduced from $4.7 billion to $1.4 billion as
of December 31, 2000. The cumulative TCBA undercollection (as recalculated) is
$2.9 billion as of December 31, 2000. A summary of the components of this
cumulative undercollection is as follows:

In millions
- -----------------------------------------------------------

Transition costs recorded in the TCBA:
QF and interutility costs $ 3,561
Amortization of nuclear-related regulatory assets 3,090
Depreciation of plant assets 577
Other transition costs 634
- -----------------------------------------------------------
Total transition costs 7,862
Revenue available to recover transition costs (4,984)
- -----------------------------------------------------------
Unrecovered transition costs $ 2,878
- -----------------------------------------------------------

Unless the regulatory and legislative actions required to implement the MOU or
other actions that make such recovery probable, are taken, SCE is not able to
conclude that the recalculated TCBA net undercollection is probable of recovery
through the rate-making process. As a result, the $2.9 billion TCBA net
undercollection was written off as a charge to earnings as of December 31, 2000
(see further discussion in Earnings). In its interim rate stabilization
decision of March 27, 2001, the CPUC denied a December motion by SCE to end the
rate freeze, and stated that it will not end until recovery of all specified
transition costs (including TCBA undercollections as recalculated) or March 31,
2002. For more details on the matters discussed above, see Rate Stabilization
Proceeding.

Litigation

In November 2000, SCE filed a lawsuit against the CPUC in federal court in
California, seeking a ruling that SCE is entitled to full recovery of its past
electricity procurement costs in accordance with the tariffs filed with the
FERC. The effect of such a ruling would be to overturn the prior decisions of
the CPUC restricting recovery of TRA undercollections. In January 2001, the
court denied the CPUC's motion to dismiss the action and also denied SCE's
motion for summary judgment without prejudice. In February 2001, the court
denied SCE's motion for a preliminary injunction ordering the CPUC to institute
rates sufficient to enable SCE to recover its past procurement costs, subject
to refund. The court granted, in part, SCE's additional motion to specify
certain material facts without substantial controversy, but denied the
remainder of the motion and declined to declare at that time that SCE is
entitled to recover the amount of its undercollected procurement costs. In
March 2001, the court directed the parties to be prepared for trial on July 31,
2001. As discussed in the Memorandum of Understanding with the CDWR, after the
other elements of the MOU are implemented, SCE will enter into a settlement of
or dismiss its lawsuit against the CPUC seeking recovery of past undercollected
costs. The settlement or dismissal will include related claims against the
State of California or any of its agencies, or against the federal government.
SCE cannot predict whether or when a favorable final judgment or other
resolution would be obtained in this legal action, if it were to proceed to
trial.

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Edison International

In December 2000, a first amended complaint to a class action securities
lawsuit (originally filed in October 2000) was filed in federal district court
in Los Angeles against SCE and Edison International. On March 5, 2001, a
second amended complaint was filed that alleges that SCE and Edison
International are engaging in fraud by over-reporting and improperly
accounting for the TRA undercollections. The second amended complaint is
supposedly 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 are recorded as a loss on SCE's income
statement. The response to the second amended complaint was due April 2, 2001.
The response has been deferred pending resolution of motions to consolidate
this lawsuit with the March 15, 2001, lawsuit discussed below. SCE believes
that its current and past accounting for the TRA undercollections and related
items, as described above, is appropriate and in accordance with accounting
principles generally accepted in the United States.

On March 15, 2001, a purported class action lawsuit was filed in federal
district court in Los Angeles against Edison International and SCE and certain
of their officers. The complaint alleges 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 over-reported income and improperly accounted
for the TRA undercollections. The complaint is supposedly filed on behalf of a
class of persons who purchased all publicly traded securities of Edison
International between May 12, 2000, and December 22, 2000. Pursuant to an
agreement with Edison International and SCE, this lawsuit is expected to be
consolidated with the October 20, 2000, lawsuit discussed above, pending the
court's approval.

In addition to the two lawsuits filed against SCE and discussed above, as of
April 13, 2001, 17 additional lawsuits have been filed against SCE by QFs. The
lawsuits have been filed by various parties, including geothermal or wind
energy suppliers or owners of cogeneration projects. The lawsuits are seeking
payments of at least $420 million for energy and capacity supplied to SCE
under QF contracts, and in some cases for damages as well. Many of these QF
lawsuits also seek an order allowing the suppliers to stop providing power to
SCE and sell the power to other purchasers. SCE is seeking coordination of all
of the QF-related lawsuits that have commenced in various California courts.
On April 13, 2001, an order was issued assigning all pending cases to a
coordination motion judge and setting a hearing on SCE's coordination petition
by May 30, 2001. SCE cannot predict the outcome of any of these matters.

Rate Stabilization Proceeding

In January 2000, SCE filed an application with the CPUC proposing rates that
would go into effect when the current rate freeze ends on March 31, 2002, or
earlier, depending on the pace of transition cost recovery. On December 20,
2000, SCE filed an amended rate stabilization plan application, stating that
the CPUC must recognize that the statutory rate freeze is now over in
accordance with California law, and requesting the CPUC to approve an
immediate 30% increase to be effective, subject to refund, January 4, 2001.
SCE's plan included a trigger mechanism allowing for rate increases of 5%
every six months if SCE's TRA undercollection balance exceeds $1 billion.
Hearings were held in late December 2000.

On January 4, 2001, the CPUC issued an interim decision that authorized SCE to
establish an interim surcharge of 1c per kWh for 90 days, subject to refund.
The revenue from the surcharge is being tracked through a balancing account
and applied to ongoing power procurement costs. The surcharge resulted in rate
increases, on average, of approximately 7% to 25%, depending on the class of
customer. As noted in the decision, the 90-day period allowed independent
auditors engaged by the CPUC to perform a comprehensive review of SCE's
financial position, as well as that of Edison International and other
affiliates.

On January 29, 2001, independent auditors hired by the CPUC issued a report on
the financial condition and solvency of SCE and its affiliates. The report
confirmed what SCE had previously

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Management's Discussion and Analysis of Results of Operations and Financial
Condition

disclosed to the CPUC in public filings about SCE's financial condition. The
audit report covers, among other things, cash needs, credit relationships,
accounting mechanisms to track stranded cost recovery, the flow of funds
between SCE and Edison International, and earnings of SCE's California
affiliates. On April 3, 2001, the CPUC adopted an order instituting
investigation (originally proposed on March 15, 2001). The order reopens past
CPUC decisions authorizing the utilities to form holding companies and
initiates an investigation into: whether the holding companies violated
requirements to give priority to the capital needs of their respective utility
subsidiaries; whether ring-fencing actions by Edison International and PG&E
Corporation and their respective nonutility affiliates also violated the
requirements to give 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. An assigned
commissioner's ruling on March 29, 2001, required Edison International and SCE
to respond within 10 days to document requests and questions that are
substantially identical to those included in the March 15 proposed order
instituting investigation. The MOU calls for the CPUC to adopt a decision
clarifying that the first priority condition in SCE's holding company decision
refers to equity investment, not working capital for operating costs. Neither
Edison International nor SCE can provide assurance that the CPUC will adopt
such a decision, or predict what effects any investigation or any subsequent
actions by the CPUC may have on either of them.

In its interim rate stabilization order adopted on March 27, 2001, the CPUC
granted SCE a rate increase in the form of a 3c per kWh surcharge applied only
to electric power costs, effective immediately, and affirmed that the 1c
interim surcharge granted on January 4, 2001, is now permanent. Although the 3c
increase was authorized immediately, the surcharge will not be collected in
rates until the CPUC establishes an appropriate rate design, which is not
expected to occur until May 2001. SCE has asked the CPUC to immediately adopt
an interim rate increase that would allow the rate change to go into effect
sooner. The CPUC also ordered that the 3c surcharge be added to the rate paid
to the CDWR pursuant to the interim CDWR-related decision (see CDWR Power
Purchases).

Also, in the interim order, the CPUC granted a petition previously filed by The
Utility Reform Network and directed that the balance in SCE's TRA, whether
over- or undercollected, be transferred on a monthly basis to the TCBA,
retroactive to January 1, 1998. Previous rules called only for TRA
overcollections (residual CTC revenue) to be transferred to the TCBA. The CPUC
also ordered SCE to transfer the coal and hydroelectric balancing account
overcollections to the TRA on a monthly basis before any transfer of residual
CTC revenue to the TCBA, retroactive to January 1, 1998. Previous rules called
for overcollections in these two balancing accounts to be transferred directly
to the TCBA on an annual basis (see further discussion of the recalculation of
the TCBA in Status of Transition and Power Procurement Costs Recovery). SCE
believes this interim order attempts to retroactively transform power purchase
costs in the TRA into transition costs in the TCBA. However, the CPUC
characterized the accounting changes as merely reducing the prior residual CTC
revenue recorded in the TCBA, thus only affecting the amount of transition cost
recovery achieved to date. Based upon the transfer of balances into the TCBA,
the CPUC denied SCE's December 2000 filing to have the current rate freeze end,
and stated that it will not end until recovery of all specified transition
costs or March 31, 2002; and that balances in the TRA cannot be recovered after
the end of the rate freeze. The CPUC also said that it would monitor the
balances remaining in the TCBA and consider how to address remaining balances
in the ongoing proceeding. If the CPUC does not modify this decision in a
manner consistent with the MOU, SCE intends to challenge this decision through
all appropriate means.

Although the CPUC has authorized a substantial rate increase in its March 27,
2001, order, it has allocated the revenue from the increase entirely to future
purchased-power costs without addressing SCE's past undercollections for the
costs of purchased power. The CPUC's decisions do not assure that SCE will be
able to meet its ongoing obligations or repay past due obligations. By ordering
immediate payments to the CDWR and QFs, the CPUC aggravated SCE's cash flow and
liquidity problems. Additionally, the CPUC expressed the view that AB 1X
continues the utilities' obligations to

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serve their customers, and stated that it cannot assume that the CDWR will
purchase all the electricity needed above what the utilities either generate
or have under contract (the net short position) and cannot order the CDWR to
do so. This could result in additional purchased power costs with no allowed
means of recovery. To implement the MOU, it will be necessary for the CPUC to
modify or rescind these decisions. SCE cannot provide any assurance that the
CPUC will do so.

Accounting for Generation-Related Assets and Power Procurement Costs

In 1997, SCE discontinued application of accounting principles for rate-
regulated enterprises for its generation assets. At that time, SCE did not
write off any of its generation-related assets, including related regulatory
assets, because the electric utility industry restructuring plan made probable
their recovery through a nonbypassable charge to distribution customers.

During the second quarter of 1998, in accordance with asset impairment
accounting standards, SCE reduced its remaining nuclear plant investment by
$2.6 billion (as of June 30, 1998) and recorded a regulatory asset on its
balance sheet for the same amount. For this impairment assessment, the fair
value of the investment was calculated by discounting expected future net cash
flows. This reclassification had no effect on SCE's results of operations.

The implementation of the MOU requires various regulatory and legislative
actions to be taken in the future. Unless those actions or other actions that
make such recovery probable are taken which would include modifying or
reversing recent CPUC decisions that impair recovery of SCE's power
procurement and transition costs, SCE is not able to conclude that its $2.9
billion TCBA undercollection (as redefined in the March 27 decisions) and $1.3
billion (book value) of its generation-related regulatory assets and
liabilities to be amortized into the TCBA, are probable of recovery through
the rate-making process. As a result, accounting principles generally accepted
in the United States require that the balances in the accounts be written off
as a charge to earnings as of December 31, 2000 (see Earnings).

As discussed below, an MOU has been negotiated with representatives of the
Governor as a step to resolving the energy crisis. The regulatory and
legislative actions set forth in the MOU, if implemented, are expected to
result in a rate-making mechanism that would make recovery of these regulatory
assets probable. If and when those actions or other actions occur that make
such recovery probable are taken, and the necessary rate-making mechanism is
adopted, the regulatory assets would be restored to the balance sheet, with a
corresponding increase to earnings.

Memorandum of Understanding with the CDWR

On April 9, 2001, Edison International and SCE signed an MOU with the CDWR
regarding the California energy crisis and its effects on SCE. The Governor of
California and his representatives participated in the negotiation of the MOU,
and the Governor endorsed implementation of all the elements of the MOU. The
MOU sets forth a comprehensive plan calling for legislation, regulatory action
and definitive agreements to resolve important aspects of the energy crisis,
and which, if implemented, is expected to help restore SCE's creditworthiness
and liquidity. Key elements of the MOU include:

. SCE will sell its transmission assets to the CDWR, or another authorized
California state agency, at a price equal to 2.3 times their aggregate book
value, or approximately $2.76 billion. If a sale of the transmission assets
is not completed under certain circumstances, SCE's hydroelectric assets
and other rights may be sold to the state in their place. SCE will use the
proceeds of the sale in excess of book value to reduce its undercollected
costs and retire outstanding debt incurred in financing those costs. SCE
will agree to operate and maintain the transmission assets for at least
three years, for a fee to be negotiated.

. Two dedicated rate components will be established to assist SCE in
recovering the net undercollected amount of its power procurement costs
through January 31, 2001, estimated to be

33

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Management's Discussion and Analysis of Results of Operations and Financial
Condition

approximately $3.5 billion. The first dedicated rate component will be used
to securitize the excess of the undercollected amount over the expected
gain on sale of SCE's transmission assets, as well as certain other costs.
Such securitization will occur as soon as reasonably practicable after
passage of the necessary legislation and satisfaction of other conditions
of the MOU. The second dedicated rate component would not be securitized
and would not appear in rates unless the transmission sale failed to close
within a two-year period. The second component is designed to allow SCE to
obtain bridge financing of the portion of the undercollection intended to
be recovered through the gain on the transmission sale.

. SCE will continue to own its generation assets, which will be subject to
cost-based ratemaking, through 2010. SCE will be entitled to collect
revenue sufficient to cover its costs from January 1, 2001, associated with
the retained generation assets and existing power contracts. The MOU calls
for the CPUC to adopt cost recovery mechanisms consistent with SCE
obtaining and maintaining an investment grade credit rating.

. The CDWR will assume the entire responsibility for procuring the
electricity needs of retail customers within SCE's service territory
through December 31, 2002, to the extent that those needs are not met by
generation sources owned by or under contract to SCE. (The unmet needs are
referred to as SCE's net short position.) SCE will resume procurement of
its net short position after 2002. The MOU calls for the CPUC to adopt cost
recovery mechanisms to make it financially practicable for SCE to reassume
this responsibility.

. SCE's authorized return on equity will not be reduced below its current
level of 11.6% before December 31, 2010. Through the same date, a rate-
making capital structure for SCE will not be established with different
proportions of common equity or preferred equity to debt than set forth in
current authorizations. These measures are intended to enable SCE to
achieve and maintain an investment grade credit rating.

. Edison International and SCE will commit to make capital investments in
SCE's regulated businesses of at least $3 billion through 2006, or a lesser
amount approved by the CPUC. The equity component of the investments will
be funded from SCE's retained earnings or, if necessary, from equity
investments by Edison International.

. EME will execute a contract with the CDWR or another state agency for the
provision of power to the state at cost-based rates for 10 years from a
power project currently under development. EME will use all commercially
reasonable efforts to place the first phase of the project into service
before the end of summer 2001.

. SCE will grant perpetual conservation easements over approximately 21,000
acres of lands associated with SCE's Big Creek and Eastern Sierra
hydroelectric facilities. The easements initially will be held by a trust
for the benefit of the State of California, but ultimately may be assigned
to nonprofit entities or certain governmental agencies. SCE will be
permitted to continue utility uses of the subject lands.

. After the other elements of the MOU are implemented, SCE will enter into a
settlement of or dismiss its federal district court lawsuit against the
CPUC seeking recovery of past undercollected costs. The settlement or
dismissal will include related claims against the State of California or
any of its agencies, or against the federal government.

The sale of SCE's transmission system and other elements of the MOU must be
approved by the FERC. Edison International, SCE and the CDWR committed in the
MOU to proceed in good faith to sponsor and support the required legislation
and to negotiate in good faith the necessary definitive agreements. The MOU may
be terminated by either SCE or the CDWR if required legislation is not adopted
and definitive agreements executed by August 15, 2001, or if the CPUC does not
adopt

34

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Edison International

required implementing decisions within 60 days after the MOU was signed, or if
certain other adverse changes occur. Edison International and SCE cannot
provide assurance that all the required legislation will be enacted,
regulatory actions taken, and definitive agreements executed before the
applicable deadlines.

Distribution

Revenue related to distribution operations is determined through a
performance-based rate-making (PBR) mechanism and the distribution assets have
the opportunity to earn a CPUC-authorized 9.49% return on investment. The
distribution PBR will extend through December 2001. Key elements of the
distribution PBR include: distribution rates indexed for inflation based on
the Consumer Price Index less a productivity factor; adjustments for cost
changes that are not within SCE's control; a cost-of-capital trigger mechanism
based on changes in a utility bond index; standards for customer satisfaction;
service reliability and safety; and a net revenue-sharing mechanism that
determines how customers and shareholders will share gains and losses from
distribution operations.

Transmission

Transmission revenue is determined through FERC-authorized rates and is
subject to refund.

Wholesale Electricity Markets

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. The order, among other things, eliminated the requirement
for California utilities to buy and sell power exclusively through the ISO and
PX; created a benchmark price for wholesale bilateral power contracts; created
penalties for under-scheduling power loads; provided for an independent
governing board for the ISO; and established a breakpoint of $150/MWh so that
bids below $150 may clear at a single market-clearing price at or below
$150/MWh and bids above $150 will be paid as bid. On December 18, 2000, SCE
filed with the FERC an emergency request for rehearing and expedited action
seeking reconsideration of the December 15 order. On January 12, 2001, the
FERC issued an order granting rehearing for the purpose of further
consideration. The PX did not immediately implement the $150/MWh breakpoint
and on February 26, 2001, made a compliance filing with the FERC, which
requested the FERC's guidance on an acceptable recalculation methodology. On
April 6, 2001, the FERC issued an order providing guidance to the PX, which
should reduce SCE's energy costs owed to the PX for the month of January 2001.

On December 13, 2000, the ISO announced that generators of electricity were
refusing to sell into the California market due to concerns about the
financial stability of SCE and Pacific Gas and Electric Company. In response
to this announcement, on December 14, 2000, the United States Secretary of
Energy issued an order requiring power companies to make arrangements to
generate and deliver electricity as requested by the ISO after the ISO
certifies that it has been unable to acquire adequate supplies of electricity
in the market. After being renewed multiple times, the order expired on
February 6, 2001. However, on February 7, 2001, a federal court judge issued a
temporary restraining order requiring power suppliers to sell to the
California grid. On March 21, 2001, a federal court judge ordered one of the
power suppliers to continue to sell power to the California grid. Three other
power suppliers have signed an agreement with the judge voluntarily agreeing
to continue to sell power to the grid while awaiting a review of the issue by
the FERC. On April 6, 2001, the United States Court of Appeals issued a stay
order, suspending the lower court's March 21 order until a final appeals
ruling can be issued.

35

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Management's Discussion and Analysis of Results of Operations and Financial
Condition

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 controls that have allowed wholesale prices to climb to
current levels. SCE's petition for rehearing remains pending. SCE cannot
predict what action the FERC may take. SCE is considering the possibility of
judicial appeals and other actions.

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/MWh during ISO Stage 3 emergencies in January 2001. SCE will
oppose 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/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.

Environmental Protection

Edison International is subject to numerous environmental laws and regulations,
which require it to incur substantial costs to operate existing facilities,
construct and operate new facilities, and mitigate or remove the effect of past
operations on the environment.

As further discussed in Note 12 to the Consolidated Financial Statements,
Edison International records its environmental liabilities when site
assessments and/or remedial actions are probable and a range of reasonably
likely cleanup costs can be estimated. Edison International's recorded
estimated minimum liability to remediate its 44 identified sites is $114
million. Edison International believes that, due to uncertainties inherent in
the estimation process, it is reasonably possible that cleanup costs could
exceed its recorded liability by up to $272 million. In 1998, SCE sold all of
its gas-fueled power plants but has retained some liability associated with the
divested properties.

The CPUC allows SCE to recover environmental-cleanup costs at certain sites,
representing $45 million of its recorded liability, through an incentive
mechanism, which is discussed in Note 12. SCE has recorded a regulatory asset
of $75 million for its estimated minimum environmental-cleanup costs expected
to be recovered through customer rates.

Edison International's identified sites include several sites for which there
is a lack of currently available information. As a result, no reasonable
estimate of cleanup costs can be made for these sites. Edison International
expects to clean up its identified sites over a period of up to 30 years.
Remediation costs in each of the next several years are expected to range from
$5 million to $15 million. Recorded costs for 2000 were $13 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 not materially affect its results of operations or
financial position. There can be no assurance, however, that future
developments, including additional information about existing sites or the
identification of new sites, will not require material revisions to such
estimates.

The Clean Air Act requires power producers to have emissions allowances to emit
sulfur dioxide. Power companies receive emissions allowances from the federal
government and may bank or sell excess allowances. SCE expects to have excess
allowances under Phase II of the Clean Air Act (2000 and later). A study was
undertaken to determine the specific impact of air contaminant emissions from
the Mohave Generating Station on visibility in Grand Canyon National Park. The
final report on this study, which was issued in March 1999, found negligible
correlation between measured Mohave station tracer

36

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Edison International

concentrations and visibility impairment. The absence of any obvious
relationship cannot rule out Mohave station contributions to haze in Grand
Canyon National Park, but strongly suggests that other sources were primarily
responsible for the haze. In June 1999, the Environmental Protection Agency
(EPA) issued an advanced notice of proposed rulemaking regarding assessment of
visibility impairment at the Grand Canyon. SCE filed comments on the proposed
rulemaking in November 1999. In 1998, several environmental groups filed suit
against the co-owners of the Mohave station regarding alleged violations of
emissions limits. In order to accelerate resolution of key environmental
issues regarding the plant, the parties filed, in concurrence with SCE and the
other station owners, a consent decree, which was approved by the court in
December 1999. In a letter to SCE, the EPA has expressed its belief that the
controls provided in the consent decree will likely resolve the potential
Clean Air Act visibility concerns. The EPA is considering incorporating the
decree into the visibility provisions of its Federal Implementation Plan for
Nevada.

Edison International's projected environmental capital expenditures are $1.8
billion for the 2001-2005 period, mainly for undergrounding certain
transmission and distribution lines at SCE and upgrading environmental
controls at EME.

San Onofre Nuclear Generating Station

On February 3, 2001, SCE's San Onofre Unit 3 experienced a fire due to an
electrical fault in the non-nuclear portion of the plant. The turbine rotors,
bearings and other components of the turbine generator system were damaged
extensively. SCE expects that Unit 3 will return to service sometime in mid-
June 2001. SCE anticipates that its lost revenue under the currently effective
San Onofre recovery plan (discussed in the Generation and Power Procurement
section of SCE's Regulatory Environment) will be approximately $100 million.

The San Onofre Units 2 and 3 steam generators' 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.

Accounting Changes

On January 1, 2001, Edison International adopted a new accounting standard for
derivative instruments and hedging activities. The new standard requires all
derivatives be recognized on the balance sheet at fair value. Gains or losses
from changes in fair value would be recognized in earnings in the period of
change unless the derivative is designated as a hedging instrument. Gains or
losses from hedges of a forecasted transaction or foreign currency exposure
would be recorded as a separate component of shareholders' equity under the
caption "Accumulated other comprehensive income." Gains or losses from hedges
of a recognized asset or liability or a firm commitment would be reflected in
earnings for the ineffective portion of the hedge. SCE's derivatives qualify
for hedge accounting under the new standard. SCE does not anticipate any
earnings impact from its derivatives, since it expects that any market price
changes will be recovered in rates. As a result of the adoption of the new
standard, Edison International expects that the quarterly earnings from its
EME subsidiary will be more volatile than earnings reported under the prior
accounting policy. For Edison International's 2001 earnings, the cumulative
effect on prior years resulting from the adoption of the new standard is
expected to be less than $10 million (after tax).

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 an 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.

37

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Management's Discussion and Analysis of Results of Operations and Financial
Condition

On January 1, 1999, Edison International implemented a new accounting rule that
requires costs related to start-up activities to be expensed as incurred.
Although this new accounting rule did not materially affect Edison
International's results of operations or financial position, EME wrote off $14
million (after tax) of previously capitalized start-up costs in first quarter
1999.

Forward-Looking Information

In the preceding Management's Discussion and Analysis of Results of Operations
and Financial Condition and elsewhere in this annual report, the words
estimates, expects, anticipates, believes and other similar expressions are
intended to identify forward-looking information that involves risks and
uncertainties. Actual results or outcomes could differ materially as a result
of such important factors as implementation (or nonimplementation) of the MOU
as described above; the outcome of negotiations for solutions to SCE's
liquidity problems; further actions by state and federal regulatory bodies
setting rates, adopting or modifying cost recovery, accounting or rate-setting
mechanisms and implementing the restructuring of the electric utility industry;
actions by lenders, investors and creditors in response to SCE's suspension of
payments for debt service and purchased power, including the possible filing of
an involuntary bankruptcy petition against SCE; the effects, unfavorable
interpretations and applications of new or existing laws and regulations
relating to restructuring, taxes and other matters; the effects of increased
competition in energy-related businesses; changes in prices of electricity and
fuel costs; the actions of securities rating agencies; the availability of
credit, including Edison International's and SCE's ability to regain an
investment grade rating and re-enter the credit markets; changes in financial
market conditions; risks of doing business in foreign countries, such as
political changes and currency devaluations; power plant construction and
operation risks; new or increased environmental liabilities; the amount of
revenue available to recover both transition and nontransition costs; the
financial viability of new businesses, such as telecommunications; weather
conditions; and other unforeseen events.

38

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Responsibility for Financial Reporting Edison International

The management of Edison International is responsible for the integrity and
objectivity of the accompanying financial statements. The statements have been
prepared in accordance with accounting principles generally accepted in the
United States and are based, in part, on management estimates and judgment.

Edison International and its subsidiaries maintain systems of internal control
to provide reasonable, but not absolute, assurance that assets are
safeguarded, transactions are executed in accordance with management's
authorization and the accounting records may be relied upon for the
preparation of the financial statements. There are limits inherent in all
systems of internal control, the design of which involves management's
judgment and the recognition that the costs of such systems should not exceed
the benefits to be derived. Edison International believes its systems of
internal control achieve this appropriate balance. These systems are augmented
by internal audit programs through which the adequacy and effectiveness of
internal controls and policies and procedures are monitored, evaluated and
reported to management. Actions are taken to correct deficiencies as they are
identified.

Edison International's independent public accountants, Arthur Andersen LLP,
are engaged to audit the financial statements in accordance with auditing
standards generally accepted in the United States and to express an informed
opinion on the fairness, in all material respects, of Edison International's
reported results of operations, cash flows and financial position.

As a further measure to assure the ongoing objectivity of financial
information, the audit committee of the Board of Directors, which is composed
of outside directors, meets periodically, both jointly and separately, with
management, the independent public accountants and internal auditors, who have
unrestricted access to the committee. The committee recommends annually to the
Board of Directors the appointment of a firm of independent public accountants
to conduct audits of its financial statements; considers the independence of
such firm and the overall adequacy of the audit scope and Edison
International's systems of internal control; reviews financial reporting
issues and is advised of management's actions regarding financial reporting
and internal control matters.

Edison International and its subsidiaries maintain high standards in
selecting, training and developing personnel to assure that their operations
are conducted in conformity with applicable laws and are committed to
maintaining the highest standards of personal and corporate conduct.
Management maintains programs to encourage and assess compliance with these
standards.

[/s/ Thomas M. Noonan] [/s/ John E. Bryson]
Thomas M. Noonan John E. Bryson
Vice President Chairman of the Board, President
and Controller and Chief Executive Officer

April 12, 2001

39

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Report of Independent Public Accountants

To the Shareholders and the Board of Directors, Edison International:

We have audited the accompanying consolidated balance sheets of Edison
International (a California corporation) and its subsidiaries as of December
31, 2000, and 1999, and the related consolidated statements of income (loss),
comprehensive income (loss), cash flows and changes in common shareholders'
equity for each of the three years in the period ended December 31, 2000. These
financial statements are the responsibility of Edison International's
management. Our responsibility is to express an opinion on these financial
statements based on our audits.

We conducted our audits in accordance with auditing standards generally
accepted in the United States. Those standards require that we plan and perform
the audit to obtain reasonable assurance about whether the financial statements
are free of material misstatement. An audit includes examining, on a test
basis, evidence supporting the amounts and disclosures in the financial
statements. An audit also includes assessing the accounting principles used and
significant estimates made by management, as well as evaluating the overall
financial statement presentation. We believe that our audits provide a
reasonable basis for our opinion.

In our opinion, the financial statements referred to above present fairly, in
all material respects, the financial position of Edison International and its
subsidiaries as of December 31, 2000, and 1999, and the results of their
operations and their cash flows for each of the three years in the period ended
December 31, 2000, in conformity with accounting principles generally accepted
in the United States.

/S/ ARTHUR ANDERSEN LLP
ARTHUR ANDERSEN LLP

Los Angeles, California
April 12, 2001

40

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Consolidated Statements of Income (Loss) Edison International

In millions, except per share amounts Year ended
December 31, 2000 1999 1998
- -------------------------------------------------------------------------------

Electric utility $ 7,870 $7,548 $7,499
Nonutility power generation 3,253 1,642 894
Financial services and other 594 506 467
- -------------------------------------------------------------------------------
Total operating revenue 11,717 9,696 8,860
- -------------------------------------------------------------------------------
Fuel 1,277 664 501
Purchased power -- contracts 2,357 2,419 2,626
Purchased power -- PX/ISO -- net 2,329 771 636
Provisions for regulatory adjustment clauses -- net 2,301 (763) (473)
Other operation and maintenance 3,145 2,935 2,533
Depreciation, decommissioning and amortization 1,933 1,795 1,662
Property and other taxes 129 124 133
Net gain on sale of utility plant (25) (3) (542)
- -------------------------------------------------------------------------------
Total operating expenses 13,446 7,942 7,076
- -------------------------------------------------------------------------------
Operating income (loss) (1,729) 1,754 1,784
Interest and dividend income 227 96 108
Other nonoperating income 165 195 140
Interest expense -- net of amounts capitalized (1,388) (894) (710)
Other nonoperating deductions (146) (164) (154)
Dividends on preferred securities (100) (44) (13)
Dividends on utility preferred stock (21) (26) (25)
- -------------------------------------------------------------------------------
Income (loss) before taxes (2,992) 917 1,130
Income taxes (1,049) 294 462
- -------------------------------------------------------------------------------
Net income (loss) $(1,943) $ 623 $ 668
- -------------------------------------------------------------------------------
Weighted average shares of common stock outstanding 333 348 359
Basic earnings (loss) per share $ (5.84) $ 1.79 $ 1.86
Weighted average shares, including effect of dilutive
securities 333 349 364
Diluted earnings (loss) per share $ (5.84) $ 1.79 $ 1.84
Dividends declared per common share $ 0.84 $ 1.08 $ 1.04

Consolidated Statements of Comprehensive Income
(Loss)

In millions Year ended December 31, 2000 1999 1998
- -------------------------------------------------------------------------------
Net income (loss) $(1,943) $ 623 $ 668
Cumulative translation adjustments -- net (150) (19) --
Unrealized gain (loss) on securities -- net (7) 23 12
Reclassification adjustment for gains included in net
income (24) (46) (18)
- -------------------------------------------------------------------------------
Comprehensive income (loss) $(2,124) $ 581 $ 662
- -------------------------------------------------------------------------------

The accompanying notes are an integral part of these financial statements.

41

- --------------------------------------------------------------------------------
Consolidated Balance Sheets

In millions December 31, 2000 1999
- --------------------------------------------------------------------------------

Assets
- --------------------------------------------------------------------------------
Cash and equivalents $ 1,973 $ 508
Receivables, less allowances of $40 and $34 for uncollectible
accounts at respective dates 1,099 944
Accrued unbilled revenue 377 434
Fuel inventory 220 241
Materials and supplies, at average cost 210 199
Accumulated deferred income taxes -- net 1,350 191
Trading and price risk management assets 252 --
Prepayments and other current assets 185 153
- --------------------------------------------------------------------------------
Total current assets 5,666 2,670
- --------------------------------------------------------------------------------
Nonutility property -- less accumulated provision for
depreciation of $774 and $446 at respective dates 10,084 12,352
Nuclear decommissioning trusts 2,505 2,509
Investments in partnerships and unconsolidated subsidiaries 2,700 2,505
Investments in leveraged leases 2,345 1,885
Other investments 92 180
- --------------------------------------------------------------------------------
Total investments and other assets 17,726 19,431
- --------------------------------------------------------------------------------
Utility plant, at original cost:
Transmission and distribution 13,129 12,439
Generation 1,745 1,718
Accumulated provision for depreciation and decommissioning (7,834) (7,520)
Construction work in progress 636 562
Nuclear fuel, at amortized cost 143 132
- --------------------------------------------------------------------------------
Total utility plant 7,819 7,331
- --------------------------------------------------------------------------------
Regulatory assets -- net 2,390 5,555
Other deferred charges 1,499 1,242
- --------------------------------------------------------------------------------
Total deferred charges 3,889 6,797
- --------------------------------------------------------------------------------

Total assets $35,100 $36,229
- --------------------------------------------------------------------------------

The accompanying notes are an integral part of these financial statements.

42

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Consolidated Balance Sheets Edison International

In millions, except share amounts December 31, 2000 1999
- ------------------------------------------------------------------------------

Liabilities and Shareholders' Equity
- ------------------------------------------------------------------------------
Short-term debt $ 3,920 $ 2,553
Current portion of long-term debt 2,260 962
Accounts payable 1,228 625
Accrued taxes 593 407
Accrued interest 232 189
Dividends payable 12 101
Regulatory liabilities -- net 195 101
Trading and price risk management liabilities 282 --
Deferred unbilled revenue 250 300
Other current liabilities 1,828 1,604
- ------------------------------------------------------------------------------
Total current liabilities 10,800 6,842
- ------------------------------------------------------------------------------
Long-term debt 12,150 13,391
- ------------------------------------------------------------------------------
Accumulated deferred income taxes -- net 5,328 5,757
Accumulated deferred investment tax credits 183 225
Customer advances and other deferred credits 1,692 2,094
Power purchase contracts 466 563
Accumulated provision for pensions and benefits 439 374
Other long-term liabilities 94 104
- ------------------------------------------------------------------------------
Total deferred credits and other liabilities 8,202 9,117
- ------------------------------------------------------------------------------
Commitments and contingencies (Notes 2, 3, 11 and 12)
Minority interest 18 9
- ------------------------------------------------------------------------------
Preferred stock of utility:
Not subject to mandatory redemption 129 129
Subject to mandatory redemption 256 256
Company-obligated mandatorily redeemable securities of
subsidiaries holding solely parent company debentures 949 948
Other preferred securities 176 326
- ------------------------------------------------------------------------------
Total preferred securities of subsidiaries 1,510 1,659
- ------------------------------------------------------------------------------
Common stock (325,811,206 and 347,207,106 shares outstanding
at respective dates) 1,960 2,090
Accumulated other comprehensive income:
Cumulative translation adjustments -- net (139) 11
Unrealized gain in equity securities -- net -- 31
Retained earnings 599 3,079
- ------------------------------------------------------------------------------
Total common shareholders' equity 2,420 5,211
- ------------------------------------------------------------------------------

Total liabilities and shareholders' equity $35,100 $36,229
- ------------------------------------------------------------------------------

The accompanying notes are an integral part of these financial statements.

43

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Consolidated Statements of Cash Flows

In millions Year ended December 31, 2000 1999 1998
- -----------------------------------------------------------------------------
Cash flows from operating activities:
Net income (loss) $(1,943) $ 623 $ 668
Adjustments to reconcile net income to net cash
provided by operating activities:
Depreciation, decommissioning and amortization 1,933 1,795 1,662
Other amortization 168 112 96
Deferred income taxes and investment tax credits (1,086) 525 348
Equity in income from partnerships and
unconsolidated subsidiaries (267) (244) (190)
Income from leveraged leases (192) (214) (213)
Regulatory balancing accounts -- long-term 1,758 (1,354) (361)
Net gain on sale of utility generating plants (14) (1) (565)
Net gain on sale of marketable securities (57) (77) (30)
Other assets 54 (58) (244)
Other liabilities (132) 134 49
Changes in working capital:
Receivables (140) (75) (235)
Regulatory balancing accounts -- short-term 97 363 (94)
Fuel inventory, materials and supplies 30 (5) 24
Prepayments and other current assets 12 (75) (19)
Accrued interest and taxes 204 (151) 68
Accounts payable and other current liabilities 757 526 283
Distributions and dividends from unconsolidated
entities 227 213 185
- -----------------------------------------------------------------------------
Net cash provided by operating activities 1,409 2,037 1,432
- -----------------------------------------------------------------------------
Cash flows from financing activities:
Long-term debt issued 5,600 6,685 981
Long-term debt repaid (4,608) (1,071) (1,544)
Bonds repurchased and funds held in trust (440) -- --
Common stock repurchased (386) (92) (714)
Preferred securities issued -- 1,124 --
Preferred stocks redeemed (125) -- (74)
Rate reduction notes repaid (246) (246) (252)
Short-term debt financing -- net 1,324 1,931 236
Dividends paid (371) (373) (374)
Nuclear fuel financing -- net 9 (37) 17
- -----------------------------------------------------------------------------
Net cash provided (used) by financing activities 757 7,921 (1,724)
- -----------------------------------------------------------------------------
Cash flows from investing activities:
Additions to property and plant (1,488) (1,232) (963)
Acquisition of nonutility property (47) (7,958) (258)
Proceeds from sale of nonutility property 1,727 115 1,215
Funding of nuclear decommissioning trusts (69) (116) (163)
Investments in partnerships and unconsolidated
subsidiaries (289) (853) (401)
Investments in leveraged leases (255) (99) (458)
Proceeds from sales of marketable securities 58 84 32
Investments in other assets (302) 28 (32)
- -----------------------------------------------------------------------------
Net cash used by investing activities (665) (10,031) (1,028)
- -----------------------------------------------------------------------------
Effect of exchange rate changes on cash (36) (3) (3)
Net increase (decrease) in cash and equivalents 1,465 (76) (1,323)
Cash and equivalents, beginning of year 508 584 1,907
- -----------------------------------------------------------------------------
Cash and equivalents, end of year $ 1,973 $ 508 $ 584
- -----------------------------------------------------------------------------

The accompanying notes are an integral part of these financial statements.

44

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Consolidated Statements of Changes in Edison International
Common Shareholders' Equity

Accumulated
Other Total Common
Common Comprehensive Retained Shareholders'
In millions, except share amounts Stock Income Earnings Equity
- --------------------------------------------------------------------------------

Balance at December 31, 1997 $2,261 $ 90 $ 3,176 $ 5,527
- --------------------------------------------------------------------------------
Net income 668 668
Stock repurchase and retirement
(25,211,232 shares) (152) (562) (714)
Dividends declared on common
stock (371) (371)
Unrealized gain on securities 18 18
Tax effect (6) (6)
Reclassified adjustment for gain
included in net income (30) (30)
Tax effect 12 12
Stock option appreciation (5) (5)
- --------------------------------------------------------------------------------
Balance at December 31, 1998 2,109 84 2,906 5,099
- --------------------------------------------------------------------------------
Net income 623 623
Stock repurchase and retirement
(3,350,500 shares) (20) (72) (92)
Dividends declared on common
stock (375) (375)
Unrealized gain on securities 39 39
Tax effect (16) (16)
Reclassified adjustment for gain
included in net income (77) (77)
Tax effect 31 31
Cumulative translation adjustment (21) (21)
Tax effect 2 2
Capital stock expense 1 1
Stock option appreciation (3) (3)
- --------------------------------------------------------------------------------
Balance at December 31, 1999 2,090 42 3,079 5,211
- --------------------------------------------------------------------------------
Net income (loss) (1,943) (1,943)
Stock repurchase and retirement
(21,402,700 shares) (130) (257) (387)
Dividends declared on common
stock (277) (277)
Unrealized gain on securities (11) (11)
Tax effect 4 4
Reclassified adjustment for gain
included in net income (41) (41)
Tax effect 17 17
Cumulative translation adjustment (148) (148)
Tax effect (2) (2)
Stock option appreciation (3) (3)
- --------------------------------------------------------------------------------
Balance at December 31, 2000 $1,960 $(139) $ 599 $ 2,420
- --------------------------------------------------------------------------------

Authorized common stock is 800 million shares with no par value.

The accompanying notes are an integral part of these financial statements.

45

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Notes to Consolidated Financial Statements

Note 1. Summary of Significant Accounting Policies

Nature of Operations

Edison International's wholly owned subsidiaries include: Southern California
Edison Company (SCE), a rate-regulated electric utility which supplies electric
energy for its 4.3 million customers in central, coastal and Southern
California; Edison Mission Energy (EME), a producer of electricity engaged in
the development, acquisition, ownership or leasing and operation of electric
power generation facilities worldwide; Edison Capital, a provider of capital
and financial services; and Edison Enterprises, the retail business arm of
Edison International. EME and Edison Capital have domestic and foreign
projects, primarily in Europe, Asia, Australia and Africa.

EME's plants are located in different geographic areas, mitigating the effects
of regional markets, economic downturns or unusual weather conditions. EME's
domestic projects (other than Homer City and the Illinois plants) generally
sell power to a limited number of electric utilities under long-term (15 years
to 30 years) contracts. Projects in both the United Kingdom and Australia sell
their energy and capacity through a centralized electricity pool. A project in
New Zealand sells its power through a voluntary pool system. Other electric
power generated overseas is sold primarily through long-term contracts to
electric utilities in the country where the power is generated. EME also
conducts energy trading and price risk management activities in power markets
open to competition.

SCE operates in a highly regulated environment in which it has an obligation to
deliver electric service to customers in return for an exclusive franchise
within its service territory. In 1996, state lawmakers and the California
Public Utilities Commission (CPUC) initiated the electric industry
restructuring process. SCE was directed by the CPUC to divest the bulk of its
generation portfolio. Today, those generating plants are owned by independent
power companies. Along with electric industry restructuring, a multi-year
freeze on the rates that SCE could charge its customers was mandated and
transition cost recovery mechanisms allowing SCE to recover its stranded costs
associated with generation-related assets were implemented. California's
electric 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 are
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 are
recovered. However, since the summer of 2000, the prices charged by generators
and other sellers have escalated far beyond what SCE can currently charge its
customers. See Note 3 for a further discussion.

SCE also produces electricity. On April 1, 1998, SCE began selling all of its
electric generation through the California Power Exchange (PX) and Independent
System Operator (ISO) and scheduling delivery through the ISO, as mandated by
the CPUC's 1995 restructuring decision. By purchasing wholesale electricity
through the PX and ISO, SCE satisfied the electric energy needs for customers
who did not choose an alternative energy provider. The Federal Energy
Regulatory Commission (FERC) issued an order on December 15, 2000, which, among
other things, eliminated the requirement for California utilities to buy and
sell power exclusively through the ISO and PX. On January 19, 2001, the PX
announced that it will permanently cease operations by April 2001; on March 9,
2001, the PX filed for Chapter 11 bankruptcy protection.

The CPUC regulates SCE's capital structure, limiting the dividends it may pay
Edison International. In light of SCE's liquidity crisis, its Board of
Directors did not declare quarterly common stock dividends to its parent,
Edison International in either December 2000 or March 2001. Edison
International's Board of Directors also did not declare common stock dividends
that would have been paid to its shareholders. See Note 2 for a further
discussion.

46

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Edison International

Basis of Presentation

The consolidated financial statements include Edison International and its
wholly owned subsidiaries. Edison International's subsidiaries use the equity
method to account for significant investments in partnerships and subsidiaries
in which they own 50% or less. Intercompany transactions have been eliminated,
except EME's profits from energy sales to SCE, which are allowed in utility
rates. Certain prior-year amounts were reclassified to conform to the December
31, 2000, financial statement presentation.

SCE's accounting policies conform with accounting principles generally
accepted in the United States, including the accounting principles for rate-
regulated enterprises, which reflect the rate-making policies of the CPUC and
the FERC. Since 1997, SCE has used accounting principles applicable to
enterprises in general for its investment in generation facilities, as a
result of industry restructuring legislation enacted by the State of
California and related changes in the rate-recovery of generation-related
assets. Application of such accounting principles to SCE's generation assets
did not result in any adjustment of their carrying value.

Earnings (Loss) Per Share (EPS)

Basic EPS is computed by dividing net income (loss) by the weighted-average
number of common shares outstanding. In arriving at net income (loss),
dividends on preferred securities and preferred stock have been deducted. For
the diluted EPS calculation, dilutive securities (employee stock options) are
added to the weighted-average shares. In 2000, the dilutive securities were
excluded from the diluted EPS calculation due to their antidilutive effect.

Estimates

Financial statements prepared in compliance with accounting principles
generally accepted in the United States require management to make estimates
and assumptions that affect the amounts reported in the financial statements
and disclosure of contingencies. Actual results could differ from those
estimates. Certain significant estimates related to liquidity, electric
utility regulatory matters, decommissioning and contingencies are further
discussed in Notes 2, 3, 11 and 12 to the Consolidated Financial Statements,
respectively.

Regulatory Balancing Accounts

During the rate freeze period, the difference between certain generation-
related revenue and generation-related costs are being accumulated in the
transition cost balancing account (TCBA). The gains resulting from the sale of
12 of SCE's generating plants during 1998 have been credited to the TCBA; the
losses are being amortized over the remaining transition period and
accumulated in the TCBA.

In June 2000, SCE credited the TCBA for the estimated excess of the market
value over book value of its hydroelectric generation assets and
simultaneously recorded the same amount in the generation asset balancing
account (GABA), pursuant to a CPUC decision. This balance was to remain in
GABA until final market valuation of the hydroelectric generation assets. If
there was a difference in the final market valuation, it would have been
credited to or recovered from customers through the TCBA mechanism. Due to the
various unresolved regulatory and legislative issues (as discussed in Note 3),
the GABA transaction was reclassified back into the TCBA as of December 31,
2000.

The coal and hydroelectric generation balancing accounts tracked the
differences between market revenue from coal and hydroelectric generation and
the plants' operating costs after April 1, 1998. Overcollections were credited
to the TCBA in 1998 and 1999, pursuant to a 1997 CPUC decision. Due to a
January 4, 2001, interim CPUC decision, the balance at year-end 2000 was not
credited to the TCBA, pending further testimony and evidence on the
implications of crediting the overcollections to the transition revenue
account (TRA) rather than the TCBA. The TRA is a CPUC-authorized regulatory

47

- --------------------------------------------------------------------------------
Notes to Consolidated Financial Statements

asset in which SCE recorded the difference between revenue received from
customers through currently frozen rates and the costs of providing service to
customers, including power procurement costs.

On March 27, 2001, the CPUC issued a decision stating, among other things, that
the rate freeze had not ended, and the TCBA mechanism was to remain in place.
However, the decision required SCE to recalculate the TCBA retroactive to
January 1, 1998, the beginning of the rate freeze period. The new calculation
required the coal and hydroelectric balancing accounting overcollections (which
amounted to $1.5 billion as of December 31, 2000) to be closed monthly to the
TRA, rather than annually to the TCBA. In addition, it required the TRA to be
transferred to the TCBA on a monthly basis. Previous rules had called only for
overcollections to be transferred to the TCBA monthly, while undercollections
were to remain in the TRA until they were recovered from future overcollections
or the end of the rate freeze, whichever came first. Based on the new rules,
the $4.5 billion TRA undercollection as of December 31, 2000, and the coal and
hydroelectric balancing account overcollections, were reclassified to the TCBA,
and the TCBA balance was recalculated to be a $2.9 billion undercollection.

Due to the various unresolved regulatory and legislative issues (as discussed
in Note 3), the TCBA undercollection was charged to earnings at December 31,
2000.

Balancing account undercollections and overcollections accrue interest. Income
tax effects on all balancing account changes are deferred.

Regulatory Assets and Liabilities

In accordance with accounting principles for rate-regulated enterprises, SCE
records regulatory assets, which represent probable future revenue associated
with certain costs that will be recovered from customers through the rate-
making process, and regulatory liabilities, which represent probable future
reductions in revenue associated with amounts that are to be credited to
customers through the rate-making process. SCE's discontinuance of the
application of accounting principles for rate-regulated enterprises to its
generation assets in 1997 did not result in a write-off of its generation-
related regulatory assets at that time since the CPUC had approved recovery of
these assets through the TCBA mechanism.

There are many factors that affect SCE's ability to recover its regulatory
assets. SCE must assess the probability of recovery of its generation-related
regulatory assets in light of the CPUC's March 27, 2001, and April 3, 2001,
decisions (discussed in Note 3), including the retroactive transfer of balances
from SCE's TRA to its TCBA and related changes. These decisions and other
regulatory and legislative actions did not meet SCE's prior expectation that
the CPUC would provide adequate cost recovery mechanisms. Until legislative and
regulatory actions contemplated by the memorandum of understanding (MOU, as
discussed in Note 3) occur, or other actions are taken, SCE is unable to
conclude that its generation-related regulatory assets are probable of recovery
through the rate-making process. Therefore, in accordance with accounting
rules, SCE recorded a $2.5 billion after-tax charge to earnings as of December
31, 2000, to write off the TCBA and other regulatory assets (see below).

In addition to the TCBA, generation-related regulatory assets totaling $1.3
billion (including unamortized nuclear investment, flow-through taxes,
unamortized loss on sale of plant, purchased-power settlements and other
regulatory assets) were written off as of December 31, 2000. Unless the MOU is
implemented or a rate-making mechanism is in place that would make recovery of
SCE's TCBA-related regulatory assets probable, future net undercollections in
the TCBA will be charged to earnings as losses are incurred.

48

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Edison International

Regulatory assets and liabilities included in the consolidated balance sheets
are:

In millions December 31, 2000 1999
------------------------------------------------------------------

Generation-related:
Unamortized nuclear investment -- net $ -- $1,366
Flow-through taxes -- 414
Unamortized loss on sale of plant -- 122
Purchased-power settlements -- 531
TCBA -- 1,044
Other -- net -- 47
------------------------------------------------------------------
Subtotal -- 3,524
------------------------------------------------------------------
Rate reduction notes -- transition cost deferral 1,090 707
------------------------------------------------------------------
Other:
Flow-through taxes 874 859
Unamortized loss on reacquired debt 273 295
Environmental remediation 52 111
Regulatory balancing accounts and other (94) (42)
------------------------------------------------------------------
Subtotal 1,105 1,223
------------------------------------------------------------------
Total $2,195 $5,454
------------------------------------------------------------------

The regulatory asset related to the rate reduction notes will be recovered
over the terms of the rate reduction notes. The other regulatory assets and
liabilities are being recovered through other components of the unbundled
rates.

The unamortized nuclear investment regulatory asset was created during the
second quarter of 1998. SCE reduced its remaining nuclear plant investment by
$2.6 billion (as of June 30, 1998) and recorded a regulatory asset on its
balance sheet for the same amount in accordance with asset impairment
accounting standards. For this impairment assessment, the fair value of the
investment was calculated by discounting expected future net cash flows. This
reclassification had no effect on SCE's results of operations.

Nuclear

SCE has been recovering its investments in San Onofre Nuclear Generating
Station Units 2 and 3 and Palo Verde Nuclear Generating Station on an
accelerated basis, as authorized by the CPUC. The accelerated recovery was to
continue through December 2001, earning a 7.35% fixed rate of return on
investment. San Onofre's operating costs, including nuclear fuel and nuclear
fuel financing costs, and incremental capital expenditures, are recovered
through an incentive pricing plan which allows SCE to receive about 4c per
kilowatt-hour through 2003. Any differences between these costs and the
incentive price will flow through to the shareholders. Palo Verde's
accelerated plant recovery, as well as operating costs, including nuclear fuel
and nuclear fuel financing costs, and incremental capital expenditures, are
subject to balancing account treatment through December 31, 2001. The San
Onofre and Palo Verde rate recovery plans and the Palo Verde balancing account
are part of the TCBA.

The nuclear rate-making plans and the TCBA mechanism will continue for rate-
making purposes at least through the end of the rate freeze period and through
2001 for Palo Verde operating costs and through 2003 for the San Onofre
incentive pricing plan. However, due to the various unresolved regulatory and
legislative issues (as discussed in Note 3), SCE is no longer able to conclude
that the unamortized nuclear investment is probable of recovery through the
rate-making process. As a result, the balance was written off as a charge to
earnings as of December 31, 2000.

49

- --------------------------------------------------------------------------------
Notes to Consolidated Financial Statements

The benefits of operation of the San Onofre units and the Palo Verde units are
required to be shared equally with ratepayers beginning in 2004 and 2002,
respectively. Palo Verde's existing nuclear unit incentive procedure will
continue through 2001 only for purposes of calculating a reward for performance
of any unit above an 80% capacity factor for a fuel cycle.

Under the MOU (discussed in Note 3), both nuclear facilities would be subject
to cost-based ratemaking upon completion of their respective rate-making plans
and the sharing mechanisms that were to begin in 2004 and 2002 would be
eliminated.

Cash Equivalents

Cash equivalents include tax-exempt investments, time deposits and other
investments with original maturities of three months or less.

Planned Major Maintenance

Certain plant facilities require major maintenance on a periodic basis. All
such costs are expensed as incurred. Prior to January 1, 2000, EME recorded
major maintenance costs on an accrue-in-advance method. EME voluntarily changed
its accounting method for major maintenance to record such expenses as incurred
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.

Fuel Inventory

SCE's inventory is valued under the last-in, first-out method for fuel oil and
under the first-in, first-out method for coal. EME's fuel inventory is stated
at the lower of weighted-average cost or market value.

Revenue

Electric utility revenue includes amounts for services rendered but unbilled at
the end of each year. Some nonutility power generation revenue from power sales
contracts is deferred and amortized to income over the life of the contracts.

Translation of Foreign Financial Statements

Assets and liabilities of most foreign operations are translated at end of
period rates of exchange and the income statements are translated at the
average rates of exchange for the year. Gains or losses from translation of
foreign currency financial statements are included in comprehensive income in
shareholders' equity. Gains or losses resulting from foreign currency
transactions are included in other nonoperating income or deductions.

Investments

Net unrealized gains (losses) on equity investments are recorded as a separate
component of shareholders' equity under the caption "Accumulated other
comprehensive income." Unrealized gains and losses on decommissioning trust
funds are recorded in the accumulated provision for decommissioning.

All investments are classified as available-for-sale.

Property and Plant

Utility plant additions, including replacements and betterments, are
capitalized. Such costs include direct material and labor, construction
overhead and an allowance for funds used during construction (AFUDC). AFUDC
represents the estimated cost of debt and equity funds that finance utility-
plant

50

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Edison International

construction. AFUDC is capitalized during plant construction and reported in
current earnings in other nonoperating income. AFUDC is recovered in rates
through depreciation expense over the useful life of the related asset.
Depreciation of utility plant is computed on a straight-line, remaining-life
basis.

AFUDC -- equity was $11 million in 2000, $13 million in 1999 and $12 million
in 1998. AFUDC -- debt was $10 million in 2000, $11 million in 1999 and $8
million in 1998.

Replaced or retired property and removal costs less salvage are charged to the
accumulated provision for depreciation. Depreciation expense stated as a
percent of average original cost of depreciable utility plant was 3.6% for
both 2000 and 1999, and 4.2% for 1998.

SCE's net investment in generation-related utility plant was $1.0 billion at
both December 31, 2000, and December 31, 1999.

Nonutility property is capitalized at cost, including interest incurred on
borrowed funds that finance construction. Depreciation of nonutility
properties is primarily computed on a straight-line basis over their estimated
useful lives. Depreciation expense stated as a percent of average original
cost of depreciable nonutility property was, on a composite basis, 2.9% for
2000, 2.2% for 1999 and 3.6% for 1998.

Supplemental Cash Flows Information

Edison International's supplemental cash flows information was:

In millions Year ended December 31, 2000 1999 1998
---------------------------------------------------------------------

Cash payments for interest and taxes:
Interest -- net of amounts capitalized $1,128 $689 $474
Taxes 3 27 87
Non-cash investing and financing activities:
Obligation to fund investments in partnerships and
unconsolidated subsidiaries 42 278 7
Liabilities assumed (of companies acquired) 397 539 --

-----------------------------------------------------------------------

Related Party Transactions

Certain EME subsidiaries have ownership in partnerships that sell electricity
generated by their project facilities to SCE under long-term power purchase
agreements. Such sales to SCE were $716 million in 2000, $513 million in 1999
and $535 million in 1998. As a result of SCE's liquidity crisis, SCE has
deferred payment for power purchases from some of these facilities.

Purchased Power -- PX/ISO

Transactions through the PX and ISO (reported net) were:

In millions Year ended December 31, 2000 1999 1998
----------------------------------------------------------
Purchases $8,449 $2,490 $1,984
Generation sales 6,120 1,719 1,348
----------------------------------------------------------
Purchased power -- PX/ISO -- net $2,329 $ 771 $ 636
----------------------------------------------------------

51

- --------------------------------------------------------------------------------
Notes to Consolidated Financial Statements

Other Nonoperating Income and Deductions

Other nonoperating income and deductions was comprised of:

In millions Year ended December 31, 2000 1999 1998
-----------------------------------------------------

Nonutility nonoperating income $ 47 $ 33 $ 11
Utility nonoperating income 118 162 129
-----------------------------------------------------
Total other nonoperating income $165 $195 $140
-----------------------------------------------------
Nonutility nonoperating deductions $ 36 $ 57 $ 37
Utility nonoperating deductions 110 107 117
-----------------------------------------------------
Total other nonoperating deductions $146 $164 $154
-----------------------------------------------------

Derivative Financial Instruments

Edison International uses the hedge accounting method to record its nontrading
derivative financial instruments. Hedge accounting requires an assessment that
the transaction reduces risk, that the derivative be designated as a hedge at
the inception of the derivative contract, and that the changes in the market
value of a hedge move in an inverse direction to the item being hedged. Under
hedge accounting, the derivative itself is not recorded on Edison
International's balance sheet. Mark-to-market accounting would be used if the
hedge accounting criteria were not met. Interest rate differentials and
amortization of premiums for interest rate caps are recorded as adjustments to
interest expense. If the derivatives were terminated before the maturity of the
corresponding debt issuance, the realized gain or loss on the transaction would
be amortized over the remaining term of the debt.

Edison International uses the fair value method for its trading and price risk
management activities. Under this method, forwards, futures, options, swaps and
other financial instruments with third parties are reflected at market value
and are included in the balance sheet as assets or liabilities from trading and
price risk management activities. In the absence of quoted values, financial
instruments are valued at fair value, considering time value, volatility of the
underlying commodity, and other factors as determined by Edison International.
The resulting gains and losses are recognized in the profit and loss account in
the period of change. Assets from trading and price risk management activities
include the fair value of open financial positions related to trading
activities and the present value of net amounts receivable from structured
transactions. Liabilities from trading and price risk management activities
include the fair value of open financial positions related to trading
activities and the present value of net amounts payable from structured
transactions.

Note 2. Liquidity Crisis

Edison International's liquidity is primarily affected by debt maturities,
dividend payments, capital expenditures, investments in partnerships and
unconsolidated subsidiaries, and SCE's power purchases. Capital resources
include cash from operations and external financings.

The increasing undercollection in the TRA, coupled with SCE's anticipated near-
term capital requirements and the adverse reaction of the credit markets to
continued regulatory uncertainty regarding SCE's ability to recover its current
and future power procurement costs, have materially and adversely affected
SCE's and Edison International's liquidity. As a result of the liquidity
crisis, SCE has taken and is taking steps to conserve cash, so that it can
continue to provide service to its customers. As a part of this process, SCE
has temporarily suspended payments of certain obligations for principal and
interest on outstanding debt and for purchased power. As of March 31, 2001, SCE
had $2.7 billion in obligations that were unpaid and overdue including: (1)
$626 million to the PX or the ISO; (2) $1.1 billion to power producers that are
qualifying facilities (QFs); (3) $229 million in PX energy credits for energy
service providers; (4) $506 million of matured commercial paper; (5) $206
million of principal and interest on its 5 7/8% notes; and (6) $7 million of
other obligations. Unpaid obligations will

52

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Edison International

continue to accrue interest, as applicable. At March 31, 2001, SCE has
estimated cash reserves of approximately $2.0 billion, which is approximately
$700 million less than its outstanding unpaid obligations and preferred stock
dividends in arrears (see below).

SCE, Edison Capital and the parent company have drawn on their entire lines of
credit, and only EME is able to obtain financing of any kind. To protect EME
from the credit downgrade of Edison International and SCE and to help preserve
the value of EME, EME has adopted certain amendments to its articles of
incorporation and bylaws. As a result of investors' concerns regarding the
California energy crisis and its impact on SCE's liquidity and overall
financial condition, SCE has repurchased $549 million of pollution-control
bonds that could not be remarketed in accordance with their terms. These bonds
may be remarketed in the future if SCE's credit status improves sufficiently.
In addition, Edison International, Edison Capital and SCE have been unable to
market their commercial paper and other short-term financial instruments. As
of March 31, 2001, SCE resumed payment of interest on its debt obligations. If
the MOU is implemented, it is expected to allow SCE to recover its
undercollected costs and to restore SCE's creditworthiness which would allow
SCE to pay all of its past-due obligations.

On March 27, 2001, the CPUC ordered SCE to pay QFs for power deliveries on a
going forward basis, commencing with April 2001 deliveries. SCE must pay QFs
within 15 days of the end of the QF's billing period, and QFs are allowed to
establish 15-day billing periods. Failure to make a payment when due will
result in a fine equal to the amount owed. The CPUC also modified the formula
used in calculating payments to QFs by substituting natural gas index prices
based on deliveries at the Oregon border rather than the Arizona border. The
CPUC stated that the changes will probably result in lower QF power prices.
The changes apply to all QFs where appropriate, regardless of whether they use
natural gas or other resources such as solar or wind.

On March 27, 2001, the CPUC also issued decisions on the California
Procurement Adjustment (CPA) calculation and the approval of a 3c per kWh rate
increase (see Note 3). Based on these two decisions, SCE estimates that
revenue going forward will not be sufficient to recover retained generation,
purchased-power and transition costs. In comments filed with the CPUC on March
29, 2001, and April 2, 2001, SCE provided a forecast showing that the net
effects of the rate increase, the payment ordered to be made to the California
Department of Water Resources (CDWR), and the QF decision discussed above
could result in a shortfall to the CPA calculation of $1.7 billion for SCE
during 2001. To implement the MOU, it will be necessary for the CPUC to modify
or rescind these decisions.

In light of SCE's liquidity crisis, its Board of Directors did not declare
quarterly common stock dividends to its parent, Edison International, in
either December 2000 or March 2001. In addition, Edison International's Board
of Directors did not declare a common stock dividend to its shareholders.
Also, SCE's Board has not declared the regular quarterly dividends for SCE's
cumulative preferred stock, 4.08% Series, 4.24% Series, 4.32% Series, 4.78%
Series, 6.05% Series, 6.45% Series and 7.23% Series in 2001. The total
preferred stock dividends in arrears is $6 million as of March 31, 2001. As a
result of the $2.5 billion charge to earnings as of December 31, 2000, SCE's
retained earnings are now in a deficit position and therefore, under
California law, SCE will be unable to pay dividends as long as a deficit
remains. SCE does not meet other tests under which dividends can be paid from
sources other than retained earnings. As long as dividends in arrears on SCE's
cumulative preferred stock remain unpaid, SCE cannot pay any dividends on its
common stock.

In addition to the above, SCE has begun immediate cost-cutting measures which,
together with previously announced actions, such as freezing new hires,
postponing certain capital expenditures and ceasing new charitable
contributions, are aimed at reducing general operating costs. SCE's current
cost-cutting measures are intended to allow it to continue to operate while
efforts to reach a regulatory solution, involving both state and federal
authorities, are underway. Additional actions by SCE may be necessary if the
energy and liquidity crisis is not resolved in the near future.

On April 9, 2001, SCE and the CDWR signed an MOU that, if approved by the
legislature, would allow SCE to restore its financial health.

53

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Notes to Consolidated Financial Statements

For a more detailed discussion on the matters discussed above, see Notes 3
through 7.

SCE's future liquidity depends, in large part, on whether the MOU is
implemented, or other action by the California Legislature and the CPUC is
taken in a manner sufficient to resolve the energy crisis and the cash flow
deficit created by the current rate structure and the excessively high price of
energy. Without a change in circumstances, such as that contemplated by the
MOU, resolution of SCE's liquidity crisis and its ability to continue to
operate outside of bankruptcy is uncertain.

The parent company and the nonutility affiliates believe that their corporate
financing plans will be successful in meeting cash requirements in 2001.

Note 3. Electric Utility Regulatory Matters

Status of Transition and Power-Procurement Cost Recovery

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 regulatory commitments consisting of recovery of
costs incurred to provide service to customers. Such commitments include the
recovery of income tax benefits previously flowed through to customers,
postretirement benefit transition costs, accelerated recovery of investment in
San Onofre Units 2 and 3 and the Palo Verde units, and certain other costs.
Transition costs related to power-purchase contracts are being recovered
through the terms of each contract. Most of the remaining transition costs may
be recovered through the end of the transition period (not later than March 31,
2002). Although the MOU provides for, among other things, SCE to be entitled to
sufficient revenue to cover its costs from January 2001 associated with
retained generation and existing power contracts, the implementation of the MOU
requires the CPUC to modify various decisions. Until the various regulatory and
legislative actions to implement the MOU are taken, or other actions occur that
make such recovery probable, SCE is not able to conclude that the regulatory
assets and liabilities related to purchased-power settlements, the unamortized
loss on SCE's generating plant sales in 1998, and various other regulatory
assets and liabilities (including income taxes previously flowed through to
customers) related to certain generating assets are probable of recovery
through the rate-making process. As a result, these balances were written off
as a charge to earnings as of December 31, 2000.

During the rate freeze period, there are three sources of revenue available to
SCE for transition cost recovery: 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. However, due to events discussed elsewhere in
this report, revenue from the sale or valuation of generation assets in excess
of book values (state legislation enacted in January 2001 prohibits the sale of
SCE's remaining generation assets until 2006) and from the sale of SCE-
controlled generation into the ISO and PX markets is no longer available to
SCE. During 1998, SCE sold all of its gas-fueled generation plants for
$1.2 billion, over $500 million more than the combined book value. Net proceeds
of the sales were used to reduce transition costs, which otherwise were
expected to be collected through the TCBA mechanism.

Net market revenue from sales of power and capacity from SCE-controlled
generation sources was also applied to transition cost recovery. Increases in
market prices for electricity affected SCE in two fundamental ways prior to the
CPUC's March 27, 2001, rate stabilization decision. First, CTC revenue
decreased because there was less or no residual revenue from frozen rates due
to higher cost PX and ISO power purchases. Second, transition costs decreased
because there was increased net market revenue due to sales from SCE-controlled
generation sources to the PX at higher prices (accumulated as an overcollection
in the coal and hydroelectric balancing accounts). Although the second effect
mitigated the first to some extent, the overall impact on transition cost
recovery was negative because SCE purchased more power than it sold to the PX.
In addition, higher market prices for electricity adversely affected SCE's
ability to recover non-transition costs during the rate freeze period. Since
May 2000, market prices for electricity were extremely high and there was
insufficient revenue from

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customers under the frozen rates to cover all costs of providing service
during that period, and therefore there was no positive residual CTC revenue
transferred into the TCBA.

CTC revenue is determined residually (i.e., CTC revenue is 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). The CTC applies to all customers who are using
or begin using utility services on or after the CPUC's 1995 restructuring
decision date. Residual CTC revenue is calculated through the TRA mechanism.
Under CPUC decisions in existence prior to March 27, 2001, positive residual
CTC revenue (TRA overcollections) was transferred to the TCBA monthly; TRA
undercollections were to remain in the TRA until they were offset by
overcollections, or the rate freeze ended, whichever came first. Pursuant to
the March 27, 2001, rate stabilization decision, both positive and negative
residual CTC revenue is transferred to the TCBA on a monthly basis,
retroactive to January 1, 1998.

Upon recalculating the TCBA balance based on the new decision, SCE has
received positive residual CTC revenue (TRA overcollections) of $4.7 billion
to recover its transition costs from the beginning of the rate freeze (January
1, 1998) through April 2000. As a result of sustained higher market prices,
SCE experienced the first month in which costs exceeded revenue in May 2000.
Since then, SCE's costs to provide power have continued to exceed revenue from
frozen rates and as a result, the cumulative positive residual CTC revenue
flowing into the TCBA mechanism has been reduced from $4.7 billion to $1.4
billion as of December 31, 2000. The cumulative TCBA undercollection (as
recalculated) is $2.9 billion as of December 31, 2000. A summary of the
components of this cumulative undercollection is as follows:

In millions
------------------------------------------------------------

Transition costs recorded in the TCBA:
QF and interutility costs $3,561
Amortization of nuclear-related regulatory assets 3,090
Depreciation of plant assets 577
Other transition costs 634
------------------------------------------------------------
Total transition costs 7,862
Revenue available to recover transition costs (4,984)
------------------------------------------------------------
Unrecovered transition costs $2,878
------------------------------------------------------------

Unless the regulatory and legislative actions required to implement the MOU,
or other actions that make recovery probable are taken, SCE is not able to
conclude that the recalculated TCBA net undercollection is probable of
recovery through the rate-making process. As a result, the $2.9 billion TCBA
net undercollection was written off as a charge to earnings as of December 31,
2000. In its interim rate stabilization decision of March 27, 2001, the CPUC
denied a December motion by SCE to end the rate freeze, and stated that it
will not end until recovery of all specified transition costs (including TCBA
undercollections as recalculated) or March 31, 2002.

Rate Stabilization Proceeding

In January 2000, SCE filed an application with the CPUC proposing rates that
would go into effect when the current rate freeze ends on March 31, 2002, or
earlier, depending on the pace of transition cost recovery. On December 20,
2000, SCE filed an amended rate stabilization plan application, stating that
the CPUC must recognize that the statutory rate freeze is now over in
accordance with California law, and requesting the CPUC to approve an
immediate 30% increase to be effective, subject to refund, January 4, 2001.
SCE's plan included a trigger mechanism allowing for rate increases of 5%
every six months if SCE's TRA undercollection balance exceeds $1 billion.
Hearings were held in late December 2000.

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Notes to Consolidated Financial Statements

On January 4, 2001, the CPUC issued an interim decision that authorized SCE to
establish an interim surcharge of 1c per kWh for 90 days, subject to refund.
The revenue from the surcharge is being tracked through a balancing account and
applied to ongoing power procurement costs. The surcharge resulted in rate
increases, on average, of approximately 7% to 25%, depending on the class of
customer. As noted in the decision, the 90-day period allowed independent
auditors engaged by the CPUC to perform a comprehensive review of SCE's
financial position, as well as that of Edison International and other
affiliates.

On January 29, 2001, independent auditors hired by the CPUC issued a report on
the financial condition and solvency of SCE and its affiliates. The report
confirmed what SCE had previously disclosed to the CPUC in public filings about
SCE's financial condition. The audit report covers, among other things, cash
needs, credit relationships, accounting mechanisms to track stranded cost
recovery, the flow of funds between SCE and Edison International, and earnings
of SCE's California affiliates. On April 3, 2001, the CPUC adopted an order
instituting investigation (originally proposed on March 15, 2001). The order
reopens the past CPUC decisions authorizing the utilities to form holding
companies and initiates an investigation into: whether the holding companies
violated company requirements to give priority to the capital needs of their
respective utility subsidiaries; whether ring-fencing actions by Edison
International and PG&E Corporation and their respective nonutility affiliates
also violated the requirements to give 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. An
assigned commissioner's ruling on March 29, 2001, required Edison International
and SCE to respond within 10 days to document requests and questions that are
substantially identical to those included in the March 15 proposed order
instituting investigation. The MOU calls for the CPUC to adopt a decision
clarifying that the first priority condition in SCE's holding company decision
refers to equity investment, not working capital for operating costs. Neither
Edison International nor SCE can provide assurance that the CPUC will adopt
such a decision, or predict what effects this investigation or any subsequent
actions by the CPUC may have on either of them.

In its interim order adopted on March 27, 2001, the CPUC granted SCE a rate
increase in the form of a 3c per kWh surcharge applied only to electric power
costs, effective immediately, and affirmed that the 1c interim surcharge
granted on January 4, 2001, is now permanent. Although the 3c increase was
authorized immediately, the surcharge will not be collected in rates until the
CPUC establishes an appropriate rate design, which is not expected to occur
until May 2001. SCE has asked the CPUC to immediately adopt an interim rate
increase that would allow the rate change to go into effect sooner. The CPUC
also ordered that the 3c surcharge be added to the rate paid to the CDWR
pursuant to the interim CDWR-related decision.

Also, in the interim order, the CPUC granted a petition previously filed by The
Utility Reform Network and directed that the balance in SCE's TRA account,
whether over- or undercollected, be transferred on a monthly basis to the TCBA
account, retroactive to January 1, 1998. Previous rules called only for TRA
overcollections (residual CTC revenue) to be transferred to the TCBA. The CPUC
also ordered SCE to transfer the coal and hydroelectric balancing account
overcollections to the TRA on a monthly basis before any transfer of residual
CTC revenue to the TCBA, retroactive to January 1, 1998. Previous rules called
for overcollections in these two balancing accounts to be transferred directly
to the TCBA on an annual basis. SCE believes this interim order attempts to
retroactively transform power purchase costs in the TRA into transition costs
in the TCBA. However, the CPUC characterized the accounting changes as merely
reducing the prior residual CTC revenue recorded in the TCBA, thereby only
affecting the amount of transition cost recovery achieved to date. Based upon
the transfer of balances into the TCBA, the CPUC denied SCE's December 2000
filing to have the current rate freeze end, and stated that it will not end
until recovery of all specified transition costs or March 31, 2002; and that
balances in the TRA cannot be recovered after the end of the rate freeze. The
CPUC also said that it will monitor the balances remaining in the TCBA and
consider how to address remaining balances in the ongoing

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proceedings. If the CPUC does not modify this decision in a manner consistent
with the MOU, SCE intends to challenge this decision through all appropriate
means.

Although the CPUC has authorized a substantial rate increase in its March 27,
2001, order, it has allocated the revenue from the increase entirely to future
purchased-power costs without addressing SCE's past undercollections for the
costs of purchased power. The CPUC's decisions do not assure that SCE will be
able to meet its ongoing obligations or repay past due obligations. By
ordering immediate payments to the CDWR and QFs, the CPUC aggravated SCE's
cash flow and liquidity problems. Additionally, the CPUC expressed the view
that AB 1X (see CDWR Power Purchases) continues the utilities' obligations to
serve their customers, and stated that it cannot assume that the CDWR will
purchase all the electricity needed above what the utilities either generate
or have under contract (the net short position) and cannot order the CDWR to
do so. This could result in additional purchased power costs with no allowed
means of recovery. To implement the MOU, it will be necessary for the CPUC to
modify or rescind these decisions. SCE cannot provide any assurance that the
CPUC will do so.

Wholesale Electricity Markets

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. The order, among other things, eliminated the requirement
for California utilities to buy and sell power exclusively through the ISO and
PX; created a benchmark price for wholesale bilateral power contracts; created
penalties for under-scheduling power loads; provided for an independent
governing board for the ISO; and established a breakpoint of $150/MWh so that
bids below $150 may clear at a single market-clearing price at or below
$150/MWh and bids above $150 will be paid as bid. On December 18, 2000, SCE
filed with the FERC an emergency request for rehearing and expedited action
seeking reconsideration of the December 15 order. On January 12, 2001, the
FERC issued an order granting rehearing for the purpose of further
consideration. The PX did not immediately implement the $150/MWh breakpoint
and on February 26, 2001, made a compliance filing with the FERC, which
requested the FERC's guidance on an acceptable recalculation methodology. On
April 6, 2001, the FERC issued an order providing guidance to the PX, which
should reduce SCE's energy costs owed to the PX for the month of January 2001.

On December 13, 2000, the ISO announced that generators of electricity were
refusing to sell into the California market due to concerns about the
financial stability of SCE and Pacific Gas and Electric Company. In response
to this announcement, on December 14, 2000, the United States Secretary of
Energy issued an order requiring power companies to make arrangements to
generate and deliver electricity as requested by the ISO after the ISO
certifies that it has been unable to acquire adequate supplies of electricity
in the market. After being renewed multiple times, the order expired on
February 6, 2001. However, on February 7, 2001, a federal court judge issued a
temporary restraining order requiring power suppliers to sell to the
California grid. On March 21, 2001, a federal court judge ordered one of the
power suppliers to continue to sell power to the California grid. The three
other power suppliers have signed an agreement with the judge voluntarily
agreeing to continue to sell power to the grid while awaiting a review of the
issue by the FERC. On April 6, 2001, the United States Court of Appeals issued
a stay order, suspending the lower court's March 21 order until a final
appeals ruling can be issued.

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 controls that have allowed wholesale prices to climb
to current levels. SCE's petition for rehearing remains pending. SCE cannot
predict what action the FERC may take. SCE is considering the possibility of
judicial appeals and other actions.

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Notes to Consolidated Financial Statements

On March 9, 2001, FERC directed 13 wholesale sellers of energy to refund $69
million or submit cost-of-service information to FERC to justify their prices
above $273/MWh during ISO Stage 3 emergencies in January 2001. SCE will oppose
the order as inadequate, particularly because the FERC is unwilling to exercise
any control over 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/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.

Memorandum of Understanding with the CDWR

On April 9, 2001, Edison International and SCE signed an MOU with the CDWR
regarding the California energy crisis and its effects on SCE. The Governor of
California and his representatives participated in the negotiation of the MOU,
and the Governor endorsed implementation of all the elements of the MOU. The
MOU sets forth a comprehensive plan calling for legislation, regulatory action
and definitive agreements to resolve important aspects of the energy crisis,
and which, if implemented, is expected to help restore SCE's creditworthiness
and liquidity. Key elements of the MOU include:

. SCE will sell its transmission assets to the CDWR, or another authorized
California state agency, at a price equal to 2.3 times their aggregate
book value, or approximately $2.76 billion. If a sale of the transmission
assets is not completed under certain circumstances, SCE's hydroelectric
assets and other rights may be sold to the state in their place. SCE will
use the proceeds of the sale in excess of book value to reduce its
undercollected costs and retire outstanding debt incurred in financing
those costs. SCE will agree to operate and maintain the transmission
assets for at least three years, for a fee to be negotiated.

. Two dedicated rate components will be established to assist SCE in
recovering the net undercollected amount of its power procurement costs
through January 31, 2001, estimated to be approximately $3.5 billion. The
first dedicated rate component will be used to securitize the excess of
the undercollected amount over the expected gain on sale of SCE's
transmission assets, as well as certain other costs. Such securitization
will occur as soon as reasonably practicable after passage of the
necessary legislation and satisfaction of other conditions of the MOU.
The second dedicated rate component would not be securitized and would
not appear in rates unless the transmission sale failed to close within a
two-year period. The second component is designed to allow SCE to obtain
bridge financing of the portion of the undercollection intended to be
recovered through the gain on the transmission sale.

. SCE will continue to own its generation assets, which will be subject to
cost-based ratemaking, through 2010. SCE will be entitled to collect
revenue sufficient to cover its costs from January 1, 2001, associated
with the retained generation assets and existing power contracts. The MOU
calls for the CPUC to adopt cost recovery mechanisms consistent with SCE
obtaining and maintaining an investment grade credit rating.

. The CDWR will assume the entire responsibility for procuring the
electricity needs of retail customers within SCE's service territory
through December 31, 2002, to the extent that those needs are not met by
generation sources owned by or under contract to SCE. (The unmet needs
are referred to as SCE's net short position.) SCE will resume procurement
of its net short position after 2002. The MOU calls for the CPUC to adopt
cost recovery mechanisms to make it financially practicable for SCE to
reassume this responsibility.

. SCE's authorized return on equity will not be reduced below its current
level of 11.6% before December 31, 2010. Through the same date, a rate-
making capital structure for SCE will not be established with different
proportions of common equity or preferred equity to debt than set forth
in current authorizations. These measures are intended to enable SCE to
achieve and maintain an investment-grade credit rating.

. Edison International and SCE will commit to make capital investments in
SCE's regulated businesses of at least $3 billion through 2006, or a
lesser amount approved by the CPUC. The

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equity component of the investments will be funded from SCE's retained
earnings or, if necessary, from equity investments by Edison
International.

. EME will execute a contract with the CDWR or another state agency for the
provision of power to the state at cost-based rates for ten years from a
power project currently under development. EME will use all commercially
reasonable efforts to place the first phase of the project into service
before the end of summer 2001.

. SCE will grant perpetual conservation easements over approximately 21,000
acres of lands associated with SCE's Big Creek and Eastern Sierra
hydroelectric facilities. The easements initially will be held by a trust
for the benefit of the State of California, but ultimately may be
assigned to nonprofit entities or certain governmental agencies. SCE will
be permitted to continue utility uses of the subject lands.

. After the other elements of the MOU are implemented, SCE will enter into
a settlement of or dismiss its federal district court lawsuit against the
CPUC seeking recovery of past undercollected costs. The settlement or
dismissal will include related claims against the State of California or
any of its agencies, or against the federal government.

The sale of SCE's transmission system and other elements of the MOU must be
approved by the FERC. Edison International, SCE and the CDWR committed in the
MOU to proceed in good faith to sponsor and support the required legislation
and to negotiate in good faith the necessary definitive agreements. The MOU
may be terminated by either SCE or the CDWR if required legislation is not
adopted and definitive agreements executed by August 15, 2001, or if the CPUC
does not adopt required implementing decisions within 60 days after the MOU
was signed, or if certain other adverse changes occur. Edison International
and SCE cannot provide assurance that all the required legislation will be
enacted, regulatory actions taken, and definitive agreements executed before
the applicable deadlines.

CDWR Power Purchases

Pursuant to an emergency order signed by the Governor, the CDWR began making
emergency power purchases for SCE's customers on January 18, 2001. On February
1, 2001, Assembly Bill 1 (First Extraordinary Session) (AB 1X) was enacted
into law. The new law 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 revenue bonds to finance
electricity purchases. The new law directed the CPUC to determine the amount
of the CPA as a residual amount of SCE's generation-related revenue, after
deducting the cost of SCE-owned generation, QF contracts, existing bilateral
contracts and ancillary services. The new law also directed the CPUC to
determine the amount of the CPA that is allocable to the power sold by the
CDWR, which will be payable to the CDWR when received by SCE. On March 7,
2001, the CPUC issued an interim order in which it held that the CDWR's
purchases are not subject to prudency review by the CPUC, and that the CPUC
must approve and impose, either as a part of existing rates or as additional
rates, rates sufficient to enable the CDWR to recover its revenue
requirements.

On March 27, 2001, the CPUC issued an interim CDWR-related order requiring SCE
to pay the CDWR a per-kWh price equal to the applicable generation-related
retail rate per kWh for electricity (based on rates in effect on January 5,
2001), 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 1c per kWh temporary surcharge adopted by the
CPUC on January 4, 2001) 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 6.277c per kWh for power delivered on an interim
basis to SCE's customers. The CPUC determined that the applicable rate
component is 7.277c per kWh (which will increase to 10.277c per kWh for
electricity delivered after March 27, 2001, due to the 3c surcharge discussed
in Rate Stabilization Proceeding), for electricity delivered by the CDWR to
SCE's retail customers after February 1, 2001, until more specific rates are
calculated. The CPUC ordered SCE to

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Notes to Consolidated Financial Statements

pay the CDWR within 45 days after the CDWR supplies power to retail customers,
subject to penalties for each day the payment is late. Using these rates, SCE
has billed customers $196 million for energy sales made by the CDWR during the
period January 19 through March 31, 2001, and has forwarded $52 million to the
CDWR on behalf of these customers as of March 31, 2001.

On April 3, 2001, the CPUC adopted the method (originally proposed in the March
27 CDWR-related order discussed above) it will use to calculate the CPA (which
was established by AB 1X) and then applied the method to calculate a company-
wide CPA rate for SCE. The CPUC used that rate to determine the CPA revenue
amount that can be used by the CDWR for issuing bonds. The CPUC stated that its
decision is narrowly focused to calculate the maximum amount of bonds that the
CDWR may issue and does not dedicate any particular revenue stream to the CDWR.
The CPUC determined that SCE's CPA rate is 1.120c per kWh, which generates
annual revenue of $856 million. In its calculation of the CPA, the CPUC
disregarded all of the adjustments requested by SCE in its comments filed on
March 29 and April 2, 2001. SCE's comments included, among other things, a
forecast showing that the net effect of the rate increases (discussed in Rate
Stabilization Proceeding), as well as the March 27 QF payment decision
(discussed in Note 2) and the payments ordered to be made to CDWR, could result
in a shortfall in the CPA calculation of $1.7 billion for SCE during 2001. SCE
estimates that its future revenue will not be sufficient to cover its retained
generation, purchased-power and transition costs. To implement the MOU, the
CPUC will need to modify the calculation methods and provide reasonable
assurance that SCE will be able to recover its ongoing costs.

SCE believes that the intent of AB 1X was for the CDWR to assume full
responsibility for purchasing all power needed to serve the retail customers of
electric utilities, in excess of the output of generating plants owned by the
electric utilities and power delivered to the utilities under existing
contracts. However, the CDWR has stated that it is only purchasing power that
it considers to be reasonably priced, leaving the ISO to purchase in the short-
term market the additional power necessary to meet system requirements. The
ISO, in turn, takes the position that it will charge SCE for the costs of power
it purchases in this manner. If SCE is found responsible for any portion of the
ISO's purchases of power for resale to SCE's customers, SCE will continue to
incur purchased-power costs in addition to the unpaid costs described above. In
its March 27, 2001, interim order, the CPUC stated that it cannot assume that
the CDWR will pay for the ISO purchases and that it does not have the authority
to order the CDWR to do so. Litigation among certain power generators, the ISO
and the CDWR (to which SCE is not a party), and proceedings before the FERC (to
which SCE is a party), may result in rulings clarifying the CDWR's financial
responsibility for purchases of power. On April 6, 2001, the FERC issued an
order confirming that the ISO must have a creditworthy buyer for any
transaction. In any event, SCE takes the position that it is not responsible
for purchases of power by the CDWR or the ISO on or after January 18, 2001, the
day after the Governor signed the order authorizing the CDWR to begin
purchasing power for utility customers. SCE cannot predict the outcome of any
of these proceedings or issues. The recently executed MOU states that the CDWR
will assume the entire responsibility for procuring the electricity needs of
retail customers within SCE's service territory through December 31, 2002, to
the extent those needs are not met by generation sources owned by or under
contract to SCE (SCE's net short position). SCE will resume buying power for
its net short position after 2002. The MOU calls for the CPUC to adopt
cost-recovery mechanisms to make it financially practicable for SCE to reassume
this responsibility.

Hydroelectric Market Value Filing

In 1999, SCE filed an application with the CPUC establishing a market value for
its hydroelectric generation-related assets at approximately $1.0 billion
(almost twice the assets' book value) and proposing to retain and operate the
hydroelectric assets under a performance-based, revenue-sharing mechanism. If
approved by the CPUC, SCE would be allowed to recover an authorized, inflation-
indexed operations and maintenance allowance, as well as a reasonable return on
capital investment. A revenue-sharing arrangement would be activated if revenue
from the sale of hydroelectricity exceeds or falls short of the authorized
revenue requirement. SCE would then refund 90% of the excess revenue to
ratepayers or recover 90% of any shortfall from ratepayers. If the MOU is
implemented, SCE's

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hydroelectric assets will be retained through 2010 under cost-based rates, or
they may be sold to the state if a sale of SCE's transmission assets is not
completed under certain circumstances.

Note 4. Financial Instruments

Edison International's risk management policy allows the use of derivative
financial instruments to manage financial exposure on its investments and
fluctuations in interest rates, foreign currency exchange rates and oil, gas
and energy prices but prohibits the use of these instruments for speculative
or trading purposes, except at EME's trading operations unit (acquired in
September 2000).

SCE used the mark-to-market accounting method for its gas call options, which
were used to mitigate SCE's transition cost recovery exposure to increases in
energy prices. Gains and losses from monthly changes in market prices were
recorded as income or expense. In addition, the options' costs and market
price changes were included in the TCBA. As a result, the mark-to-market gains
or losses had no effect on earnings. In October 2000, SCE sold its gas call
options resulting in a $190 million gain. The options covered various periods
through 2001. The gains were credited to the TCBA.

The PX block forward market allowed SCE to purchase monthly blocks of energy
and ancillary services for six days a week (excluding Sundays and holidays)
for 8 hours to 16 hours a day, up to 12 months in advance of the delivery
date.

SCE purchased block forward energy contracts through the PX, with various
terms and prices, to hedge its exposure to fluctuations in energy prices. Due
to downgrades in SCE's credit ratings and SCE's failure to pay its obligations
to the PX, the PX suspended SCE's market trading privileges and sought to
liquidate SCE's block forward contracts. On February 2, 2001, SCE's motion for
a preliminary injunction was denied, freeing the PX to liquidate the contracts
and apply the proceeds to amounts owed by SCE to the PX. On the same day, the
State seized the contracts for the benefit of the State before they could be
sold by the PX. The State must compensate SCE for the reasonable value of the
contracts. The PX has indicated that it will also seek to recover the monies
that SCE owes to the PX from any proceeds realized from those contracts. After
other elements of the MOU are implemented, SCE would relinquish all claims
against the State for seizing these contracts. At December 31, 2000, these
contracts had a nominal value of $234 million.

SCE also has bilateral forward contracts, which are considered normal
purchases under accounting rules. At December 31, 2000, these contracts had a
nominal value of $798 million. Due to its deteriorating credit ratings, SCE
has been unable to purchase additional bilateral forward contracts, and $379
million (nominal value) of its existing contracts were terminated by the
counterparties in early 2001. SCE is exposed to credit loss in the event of
nonperformance by the counterparties to its bilateral forward contracts, but
does not expect the counterparties to fail to meet their obligations. The
counterparties are required to post collateral depending on the
creditworthiness of each counterparty. SCE is exposed to market risk resulting
from changes in the spot market price for power. Changes in the value of
bilateral forward contracts affects purchased power expense in the period when
the power is delivered.

SCE used an interest rate swap to reduce the potential impact of interest rate
fluctuations on floating-rate long-term debt. At December 31, 2000, and
December 31, 1999, SCE had an interest rate swap agreement which fixed the
interest rate at 5.585% for $196 million of debt due 2008; the receive rate on
the swap averaged 3.839% in 2000. As a result of the downgrade in SCE's credit
rating below the level allowed under the interest rate hedge agreement, on
January 5, 2001, the counterparty on this interest rate swap terminated the
agreement. As a result of the termination of the swap, SCE is paying a
floating rate on $196 million of its debt due 2008. The realized loss of
$26 million will be amortized over a period ending in 2008.

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Notes to Consolidated Financial Statements

EME uses foreign currency forward exchange contracts and interest rate swaps to
mitigate the risk of fluctuations in foreign currency exchange rates and
interest rates. The maturity date of the swaps generally occur prior to the
final maturity of the underlying debt. Under the fixed to variable swap
agreements, the fixed interest rate payments are at a weighted-average rate of
5.65% at December 31, 2000, and 1999. Variable rate payments are based on six-
month LIBOR capped at 9%. The weighted- average LIBOR rate applicable to these
agreements was 5.605% and 6.22% at December 31, 2000, and 1999, respectively.
Under the variable to fixed swap agreements, EME paid counterparties interest
at a weighted-average fixed rate of 7.59% and 7.6% at December 31, 2000, and
1999, respectively. Counterparties paid EME interest at a weighted-average
variable rate of 6.43% and 5.03% at December 31, 2000, and 1999, respectively.
The weighted-average variable interest rates are based on LIBOR or equivalent
interest rate benchmarks for foreign-denominated interest rate swap agreements.

EME enters into electricity rate swap agreements to manage its exposure to the
United Kingdom and Australia market (pool) price volatilities. The related
price differentials to be paid or received are currently recorded as
adjustments to electric revenue or fuel expense. Projects in the United Kingdom
currently sell their electrical energy and capacity through a centralized
electricity pool, which establishes a half-hourly clearing price, or pool
price, for electrical energy. The pool price is extremely volatile and can vary
by a factor of 10 or more over the course of a few hours due to large
differentials in demand according to the time of day. The pricing arrangements
include provision for capacity payments to be added to the basic pool price at
time of capacity shortage. First Hydro, Ferrybridge and Fiddler's Ferry
mitigate a significant portion of the market risk of the pool by entering into
electricity rate swap agreements, related to either the selling or purchasing
price of power. These contracts are sold in various structures and act as a
means of stabilizing production revenue or purchasing costs by removing an
element of net exposure to pool price volatility.

Electric power at EME's Homer City plant is sold under bilateral arrangements
with domestic utilities and power marketers under short-term contracts (two
years or less) or to the Pennsylvania-New Jersey-Maryland Power Pool (PJM) or
the New York Independent System Operator (NYISO). These pools
have short-term markets which establish an hourly clearing price. Homer City is
located in the PJM control area and is physically connected to high-voltage
transmission lines serving both the PJM and the NYISO markets. Power can also
be transmitted to the mid-western United States. EME has developed risk
management policies and procedures which, among other matters, address credit
risk. It is EME's policy to sell to investment grade counterparties or
counterparties that provide equivalent credit support. Exception to the policy
is granted only after thorough review and scrutiny by EME's Risk Management
Committee. Entities which have received exceptions are organized power pools
and quasi-governmental agencies. EME intends on hedging a portion of the
electric output of its merchant plants in order to lock in desirable outcomes.
EME plans to manage the margin that is spread between electric prices and fuel
prices when deemed appropriate. EME plans to use forward contracts, swaps,
futures or option contracts to achieve those objectives.

Loy Yang B (EME's energy project in Australia) sells its electrical energy
through a centralized electricity pool, which provides for a system of
generator bidding, central dispatch and a settlement system based on a clearing
market for each half-hour of every day. To mitigate the exposure to price
volatility of the electricity traded in the pool, Loy Yang B has entered into a
number of financial hedges. Between May 1997 and December 2000, 53% to 64% of
the plant output sold was hedged under vesting contracts, with the remainder of
the plant capacity hedged under the State hedge described below. Vesting
contracts were put into place by the State Government of Victoria, Australia,
between each generator and each distributor, prior to the privatization of
electric power distributors in order to provide more predictable pricing for
those electricity customers that were unable to choose their electricity
retailer. Vesting contracts set base strike prices at which the electricity
will be traded, and the parties to the agreement make payments, calculated
based on the difference between the price in the contract and the half-hourly
pool clearing price for the element of power under the contract. Vesting
contracts were sold in various structures and accounted for as electricity rate
swap agreements. The State hedge with the State Electricity Commission of
Victoria is a long-term contractual agreement based upon a fixed price

62

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Edison International

commencing in May 1997 and terminating in October 2016. The State government
guarantees the State Electricity Commission of Victoria's obligations under
the State hedge. From January 2001 to July 2014, approximately 77% of the
plant output sold is hedged under the State hedge. From August 2014 to October
2016, approximately 56% of the plant output is hedged under the State hedge.
Additionally, Loy Yang B entered into a number of fixed forward electricity
contracts effective January 2001, which will expire either January 1, 2002, or
January 1, 2003, and which will further mitigate against the price volatility
of the electricity pool.

Edison International is subject to concentrations of credit risk as the result
of elements involved in EME's financial instruments and power-sales contracts.
Credit risk relates to the risk of loss that EME would incur as a result of
nonperformance by counterparties (major financial institutions and domestic
foreign utilities) under their contractual obligations. One of EME's
customers, Exelon Generation, accounted for 33% of EME's revenue during 2000.
Any failure by Exelon Generation to make payments under the power purchase
agreements could adversely affect EME's results of operations. EME attempts to
mitigate credit risk by contracting with counterparties that have a strong
capacity to meet their contractual obligations and by monitoring their credit
quality. In addition, EME seeks to secure long-term power-sales contracts for
its investments in domestic operating projects that are expected to result in
adequate cash flow under a wide range of economic and operating circumstances.
To accomplish this, EME attempts to structure its long-term contracts so that
fluctuations in fuel costs will produce similar fluctuations in electric
and/or steam revenue by entering into long-term fuel supply and transportation
agreements. Accordingly, EME does not anticipate a material effect on its
results of operations or financial condition as a result of counterparty
nonperformance.

Edison Capital has entered into foreign currency contracts to reduce the
potential impact of changes in foreign exchange rates and future foreign
currency denominated cash flows, and into interest rate swaps to reduce the
potential impact of changes in interest rates. In 2000, Edison Capital made
payments and received payments on its swap agreements. The net effective
interest rate of these transactions results in Edison Capital paying a
weighted average fixed rate of 6.156% and receiving a weighted average fixed
rate of 6.719%. In 1999, Edison Capital made payments on its swap agreements
on which the net effective weighted average interest rate was 5.520%. There
were no payments received on the swap agreements in 1999.

Edison International had the following interest rate, foreign currency and
commodity hedges:

In millions December 31, 2000 1999
-----------------------------------------------------------------------
Notional Contract Notional Contract
Amount Expires Amount Expires
-----------------------------------------------------------------------

Interest rate swaps:
Fixed to variable $ 100 2002 $ 100 2002
Variable to fixed 1,246 2001-2009 2,148 2000-2009
Interest rate caps 584 2005-2010 626 2005
Foreign currency contracts 111 2001-2002 9 2001
Derivative commodity contracts:
Forwards 489 2001-2003 -- --
Futures (70) 2001 -- --
Options 4 2001 47 2001
Swaps 1,748 2001-2016 1,803 2000-2016
-----------------------------------------------------------------------

On January 1, 2001, Edison International adopted a new accounting standard for
derivative instruments and hedging activities. The new standard requires all
derivatives to be recognized on the balance sheet at fair value. Gains or
losses from changes in fair value would be recognized in earnings in the
period of change unless the derivative is designated as a hedging instrument.
Gains or losses from hedges of a forecasted transaction or foreign currency
exposure would be recorded as a separate component of

63

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Notes to Consolidated Financial Statements

shareholders' equity under the caption "Accumulated other comprehensive
income." Gains or losses from hedges of a recognized asset or liability or a
firm commitment would be reflected in earnings for the ineffective portion of
the hedge. SCE's derivatives qualify for hedge accounting under the new
standard. SCE does not anticipate any earnings impact from its derivatives,
since it expects that any market price changes will be recovered in rates. As a
result of the adoption of the new standard, Edison International expects that
the quarterly earnings from its EME subsidiary will be more volatile than
earnings reported under the prior accounting policy. For Edison International's
2001 earnings, the cumulative effect on prior years resulting from adoption of
the new standard is expected to be less than $10 million.

Fair values of financial instruments were:

In millions December 31, 2000 1999
------------------------------------------------------------------------------
Cost Fair Cost Fair
Basis Value Basis Value
------------------------------------------------------------------------------

Financial assets:
Decommissioning trusts $ 1,720 $ 2,505 $ 1,650 $ 2,509
Equity investments -- -- -- 33
Gas call options -- -- 28 20
Electricity rate swaps -- 555 -- 71
Power options 2 2 4 4
Forward power contracts/futures -- 27 -- --
Gas swaps -- 7 -- --

Financial liabilities:
DOE decommissioning and decontamination fees $ 36 $ 31 $ 40 $ 35
Interest rate hedges -- 63 -- 44
Long-term debt 12,150 11,197 13,391 13,281
Utility preferred stock subject to mandatory
redemption 256 157 256 259
Other preferred securities subject
to mandatory redemption 327 327 359 360
Forward power contracts/futures -- 143 -- --
Gas swaps/futures 50 56 -- --
Power swaps -- 1 -- --
Emission options 2 -- -- --
------------------------------------------------------------------------------

Financial assets are carried at their fair value based on quoted market prices
for decommissioning trusts, equity investments and gas call options and on
financial models for electricity rate swaps. The fair value of the commodity
contracts considers quoted market prices, time value, volatility of the
underlying commodities and other factors.

Financial liabilities are recorded at cost. Financial liabilities' fair values
are based on: discounted future cash flows for U.S. Department of Energy (DOE)
decommissioning and decontamination fees; quoted market prices for the interest
rate hedges; and brokers' quotes for long-term debt and preferred stock. Due to
their short maturities, amounts reported for cash equivalents and short-term
debt approximated fair value at December 31, 2000, and 1999.

As a result of investors' concerns regarding SCE and Edison International's
liquidity difficulties, Edison International's short-term debt and long-term
debt fair values have decreased approximately $250 million and $540 million,
respectively, from amounts reported at year-end.

64

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Gross unrealized holding gains on debt and equity securities were:

In millions December 31, 2000 1999
--------------------------------------------------

Decommissioning trusts:
Municipal bonds $193 $239
Stocks 384 454
U.S. government issues 136 119
Short-term and other 72 47
--------------------------------------------------
785 859
Equity investments -- 33
--------------------------------------------------
Total $785 $892
--------------------------------------------------

There were no unrealized holding losses on debt and equity securities for the
years presented.

Commodity Derivatives -- Trading

In September 2000, EME acquired the trading operations of Citizens Power LLC,
expanding EME's trading operations beyond the traditional marketing of
electric power. Energy trading and price risk management activities give rise
to market risk (potential loss that can be caused by a change in the market
value of a particular commitment). Market risks are actively monitored to
ensure compliance with EME's risk management policies. EME performs a value at
risk analysis daily to monitor its overall market risk exposure. This analysis
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 other techniques, including the use of stress
testing and worst-case scenario analysis, as well as stop limits and
counterparty credit exposure limits.

The fair value of the financial instruments, including forwards, options and
swaps, related to trading and price risk management activities as of December
31, 2000, which include energy commodities, and the average fair value of
those instruments held during the period from inception (September 1, 2000) to
December 31, 2000, were:

Average Fair Value
for the Period
Fair Value at Ended December 31,
In millions December 31, 2000 2000
---------------------------------------------------------
Assets Liabilities Assets Liabilities
---------------------------------------------------------

Forward contracts $302 $282 $154 $147
Option contracts 1 4 3 2
Swap agreements 3 4 2 2
---------------------------------------------------------
Total $306 $290 $159 $151
---------------------------------------------------------

A portion of these assets and liabilities are classified as long-term in the
balance sheet.

The approximate gross contract or notional amounts of the financial
instruments as of December 31, 2000, were as follows:

In millions December 31, 2000 Assets Liabilities
---------------------------------------------------

Forward contracts $433 $420
Option contracts 2 --
Swap agreements 40 64
---------------------------------------------------

65

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Notes to Consolidated Financial Statements

The net realized and change in unrealized gains or losses arising from trading
and activities for the period from inception to December 31, 2000, are as
follows:

In millions Period Ended December 31, 2000
---------------------------------------------------------------------------

Forward contracts $68
Option contracts (1)
Swap agreements (5)
---------------------------------------------------------------------------
Total $62
---------------------------------------------------------------------------

The change in unrealized gains from trading and price risk management
activities included in the above amounts was $12 million for the period ended
December 31, 2000.

Note 5. Long-Term Debt

California law prohibits SCE from incurring or guaranteeing debt for its
nonutility affiliates.

Almost all SCE properties are subject to a trust indenture lien. SCE has
pledged first and refunding mortgage bonds as security for borrowed funds
obtained from pollution-control bonds issued by government agencies. SCE uses
these proceeds to finance construction of pollution-control facilities.
Bondholders have limited discretion in redeeming certain pollution-control
bonds, and SCE has arrangements with securities dealers to remarket or purchase
them if necessary. As a result of investors' concerns regarding SCE's liquidity
difficulties and overall financial condition, SCE had to repurchase $549
million of pollution control bonds in December 2000 and early 2001 that could
not be remarketed in accordance with their terms.

Debt premium, discount and issuance expenses are amortized over the life of
each issue. Under CPUC rate-making procedures, debt reacquisition expenses are
amortized over the remaining life of the reacquired debt or, if refinanced, the
life of the new debt.

Commercial paper intended to be refinanced for a period exceeding one year and
used to finance nuclear fuel scheduled for use more than one year after the
balance sheet date is classified as long-term debt.

In December 1997, $2.5 billion of rate reduction notes were issued on behalf of
SCE by SCE Funding LLC, a special purpose entity. These notes were issued to
finance the 10% rate reduction mandated by state law. The proceeds of the rate
reduction notes were used by SCE Funding LLC to purchase from SCE an
enforceable right known as transition property. Transition property is a
current property right created by the restructuring legislation and a financing
order of the CPUC and consists generally of the right to be paid a specified
amount from nonbypassable rates charged to residential and small commercial
customers. The rate reduction notes are being repaid over 10 years through
these non-bypassable residential and small commercial customer rates which
constitute the transition property purchased by SCE Funding LLC. The notes are
secured by the transition property and are not secured by, or payable from,
assets of SCE or Edison International. SCE used the proceeds from the sale of
the transition property to retire debt and equity securities. Although, as
required by accounting principles generally accepted in the United States, SCE
Funding LLC is consolidated with SCE and the rate reduction notes are shown as
long-term debt in the consolidated financial statements, SCE Funding LLC is
legally separate from SCE. The assets of SCE Funding LLC are not available to
creditors of SCE or Edison International and the transition property is legally
not an asset of SCE or Edison International. Due to SCE's recent credit
downgrade, in January 2001, SCE began remitting its customer collections
related to the rate-reduction notes on a daily basis.

66

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Edison International

Long-term debt consisted of:

In millions December 31, 2000 1999
----------------------------------------------------------------
First and refunding mortgage bonds:
2002-2026 (5.625% to 7.25%) $ 1,175 $ 1,400
Rate reduction notes:
2001-2007 (6.17% to 6.42%) 1,724 1,970
Pollution-control bonds:
2008-2040 (5.125% to 7.2% and variable) 1,216 1,196
Bonds repurchased (420) --
Funds held by trustees (20) (2)
Debentures and notes:
2001-2029 (5.875% to 11.2% and variable) 10,594 9,633
Subordinated debentures:
2044 (8.375%) 100 100
Commercial paper for nuclear fuel 79 71
Capital lease obligation 1 23
Current portion of capital lease obligation (1) (22)
Long-term debt due within one year (2,259) (940)
Unamortized debt discount -- net (39) (38)
----------------------------------------------------------------
Total $12,150 $13,391
----------------------------------------------------------------

Long-term debt maturities and sinking-fund requirements for the next five
years are: 2001 -- $2.3 billion; 2002 -- $1.1 billion; 2003 -- $1.7 billion;
2004 -- $1.8 billion; and 2005 -- $499 million.

As a result of its liquidity crisis, SCE has taken steps to conserve cash, and
has been forced to consider further alternatives for conserving cash, so that
it can continue to provide service to its customers. As a part of this
process, SCE has temporarily suspended payments of certain obligations. As of
March 31, 2001, SCE has failed to pay $206 million of maturing principal and
accrued interest on its 5 7/8% notes. Under the indenture for SCE's senior
unsecured notes, the failure to pay principal was an immediate event of
default as to the one series of notes on which the principal was due. If an
event of default occurs as to any series of senior unsecured notes, the
trustee or the holders of 25% in principal amount of the notes of such series
may declare the principal of the notes of that series to be immediately due
and payable. In addition, SCE's failure to pay any obligation for borrowed
money in an aggregate amount in excess of $10 million would constitute an
event of default with respect to all of the senior unsecured notes and SCE's
outstanding quarterly income preferred securities if not cured within 30 days
after notice from the trustee or the holders of the securities. No such notice
has been received by SCE.

If a notice of default is received, SCE could cure the default only by paying
$700 million in overdue principal and interest to holders of commercial paper
and the 5 7/8% notes. (SCE has also deferred payment of maturing commercial
paper. See Note 6 for a further discussion). Making such payment would further
impact SCE's liquidity. If a notice of default were received and not cured,
and the trustee or noteholders were to declare an acceleration of the
outstanding principal amount of the senior unsecured notes, SCE would not have
the cash to pay the obligation and could be forced to declare bankruptcy.

In January 2001, three rating agencies lowered their credit ratings of Edison
International, Edison Capital and SCE to substantially below investment grade.
In mid-April, one agency removed the ratings from review for possible
downgrade. The ratings remain under review for possible downgrade by the other
two agencies.

To isolate EME from the credit downgrades of Edison International and SCE and
to help preserve the value of EME, EME has adopted certain provisions (ring-
fencing) in the form of amendments to its articles of incorporation and
bylaws. The provisions include the appointment of an independent EME

67

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Notes to Consolidated Financial Statements

director whose consent is required for EME to: consolidate or merge with any
entity; institute or consent to bankruptcy, insolvency or similar proceedings
or actions; or declare or pay dividends unless certain conditions exist. Such
conditions are: EME has an investment grade rating and receives rating agency
confirmation that the dividend or distribution will not result in a downgrade,
or such dividends do not exceed $32.5 million in any quarter and EME meets a
certain interest coverage ratio for the immediately preceding four quarters.
EME currently meets this interest coverage ratio.

A subsidiary of EME has deferred certain required capital expenditures at EME's
Fiddler's Ferry and Ferrybridge power plants in the United Kingdom because the
plants' financial performance has not met expectations. As a result, the EME
subsidiary is in breach of technical requirements set forth in the plants'
financing agreements related to the acquisition of the plants. Also, due to the
lower financial performance, the subsidiary's debt service coverage ratio
declined in 2000 below the threshold set in its financing documents. The
subsidiary is currently in discussions with financing parties to revise the
required capital expenditures program and to waive the breach of the financial
ratio covenant for 2000, and related technical defaults. There are no
assurances that an agreement can be met. The financing documents state that a
breach of the financial ratio covenant constitutes an immediate event of
default and, if the default is not waived, the financing parties are entitled
to enforce their security over the subsidiary's assets, including the power
plants. Due to the timing of its cash flows and debt service payments, EME's
subsidiary utilized its debt service reserve to meet its debt service
requirements in 2000.

The financial performance of the Ferrybridge and Fiddler's Ferry plants has not
matched EME's expectations, largely due to lower energy power prices resulting
from increased competition, climatic effects and uncertainties surrounding the
new electricity trading arrangements. In accordance with asset impairment
accounting standards, EME has evaluated the impairment of the Ferrybridge and
Fiddler's Ferry power plants and has determined that no impairment exists. As a
result of the change in power prices in the United Kingdom, EME is considering
the sale of the Ferrybridge and Fiddler's Ferry plants. A decision has not been
made regarding whether or not the sale of these plants will ultimately occur
and, accordingly, these assets are not classified as held for sale. However, if
a decision to sell the Ferrybridge and Fiddler's Ferry plants were made, it is
likely that the fair value of the assets would be substantially below their
book value at December 31, 2000.

On April 5, 2001, EME issued $600 million of 9.875% senior notes. The notes are
due in April 2011.

Note 6. Short-Term Debt

Short-term debt is used to finance fuel inventories, balancing account
undercollections and general cash requirements, including PX and ISO payments.
Commercial paper intended to finance nuclear fuel scheduled to be used more
than one year after the balance sheet date is classified as long-term debt in
connection with refinancing terms under five-year term lines of credit with
commercial banks.

Short-term debt consisted of:

In millions December 31, 2000 1999
--------------------------------------------------

Commercial paper $1,586 $2,413
Bank loans 1,355 --
Floating rate notes 600 --
Amount reclassified as long-term (79) (71)
Unamortized discount (14) (14)
Other short-term debt 472 225
--------------------------------------------------
Total $3,920 $2,553
--------------------------------------------------
Weighted-average interest rate 7.2% 6.5%

68

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Edison International

At December 31, 2000, Edison International and its subsidiaries had lines of
credit totaling $3.6 billion, with approximately $400 million available.
Credit lines are used to support commercial paper borrowings and bank loans.
SCE had lines of credit totaling $1.65 billion with $125 million available for
the long-term refinancing of certain variable-rate pollution-control debt. The
nonutility subsidiaries had lines of credit of $274 million available to
finance general cash requirements. Edison International's unsecured revolving
lines of credit can be drawn at negotiated or bank index rates and have
various expiration dates.

As of January 2001, SCE had borrowed the entire $1.65 billion in funds
available under its credit lines. The proceeds were used in part to repurchase
$420 million of pollution control bonds; the balance was retained as a
liquidity reserve.

As of January 2001, Edison Capital had borrowed the entire $300 million in
funds available under its credit lines. The proceeds were retained as a
liquidity reserve. As a result, Edison Capital had no remaining credit lines
available as of January 2001.

In late 2000, SCE was unable to complete the syndication of a $1 billion
revolving credit agreement that was intended to finance current and expected
balancing account undercollections and other operating requirements. In
addition, SCE, Edison International and Edison Capital have been unable to
market their commercial paper and other short-term financial instruments. And,
in SCE's efforts to conserve cash, SCE has deferred payment of approximately
$506 million of maturing commercial paper as of March 31, 2001.

Note 7. Preferred Securities

Preferred Stock of Utility

SCE's authorized shares of preferred and preference stocks are: $25 cumulative
preferred -- 24 million; $100 cumulative preferred -- 12 million; and
preference -- 50 million. All cumulative preferred stocks are redeemable.

Mandatorily redeemable preferred stocks are subject to sinking-fund
provisions. When preferred shares are redeemed, the premiums paid are charged
to common equity.

Preferred stock redemption requirements for the next five years are: 2001 --
zero; 2002 -- $105 million; 2003 -- $9 million; 2004 -- $9 million; and
2005 -- $9 million.

69

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Notes to Consolidated Financial Statements

SCE's cumulative preferred stocks consisted of:

Dollars in millions, except per share amounts December
31, 2000 1999
-------------------------------------------------------------------

December 31, 2000
----------------------
Shares Redemption
Outstanding Price
----------- ----------
Not subject to mandatory redemption:
$25 par value:
4.08% Series 1,000,000 $ 25.50 $ 25 $ 25
4.24 1,200,000 25.80 30 30
4.32 1,653,429 28.75 41 41
4.78 1,296,769 25.80 33 33
-------------------------------------------------------------------
Total $129 $129
-------------------------------------------------------------------

Subject to mandatory redemption:
$100 par value:
6.05% Series 750,000 $ 100.00 $ 75 $ 75
6.45 1,000,000 100.00 100 100
7.23 807,000 100.00 81 81
-------------------------------------------------------------------
Total $256 $256
-------------------------------------------------------------------

In 1998, SCE redeemed 2.2 million shares of Series 5.8% and 193,000 shares of
Series 7.23% preferred stock. SCE did not issue any preferred stock in the last
three years.

SCE's Board of Directors did not declare the regular quarterly dividends for
SCE's cumulative preferred stock in 2001. As long as these dividends remain
unpaid, SCE cannot declare or pay future cash dividends on any series of
preferred stock or on its common stock, and SCE cannot repurchase any shares of
its common stock. As a result of the $2.5 billion charge to earnings during the
fourth quarter 2000, SCE's retained earnings are now in a deficit position and
therefore under California law, SCE will be unable to pay dividends as long as
a deficit remains.

Company-Obligated Mandatorily Redeemable Securities of Subsidiary

EME issued, through a limited partnership, 3.5 million of 9.875% cumulative
monthly income preferred securities in 1994, at a price of $25 per security.
These securities are redeemable at the option of the partnership, in whole or
in part, beginning November 1999 with mandatory redemption in 2024 at a
redemption price of $25 per security plus accrued and unpaid distributions.

EME also issued, through a limited partnership, 2.5 million of 8.5% cumulative
monthly income preferred securities in 1995, at a price of $25 per security.
These securities are redeemable at the option of the partnership, in whole or
in part, beginning August 2000 with mandatory redemption in 2025 at a
redemption price of $25 per security plus accrued and unpaid distributions.

In 1999, Edison International issued, through affiliates, $500 million of
7.875% cumulative quarterly income preferred securities and $325 million of
8.6% cumulative quarterly income preferred securities at a price of $25 per
security. The 7.875% securities have a stated maturity of July 2029 but are
redeemable at the option of Edison International, in whole or in part,
beginning July 2004. The 8.6% securities, which are guaranteed by Edison
International, have a stated maturity of October 2029 but are redeemable at the
option of Edison International, in whole or in part, beginning October 2004.

Other Preferred Securities

During 1999, EME issued, through an indirect, wholly owned affiliate, $120
million of flexible money market cumulative preferred stock. The stock issuance
consisted of 600 Series A shares and

70

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Edison International

600 Series B shares, with a dividend rate of 5.74%. These securities were
redeemable, in whole or in part, at the option of EME's affiliate, beginning
May 2004, at $100,000 per share, plus accrued and unpaid dividends. On
December 20, 2000, all Series A and Series B shares were redeemed at their
liquidation preference of $100,000 per share, plus an additional premium of
$3,785 per share and all unpaid dividends.

During 1999, EME issued through an indirect, wholly owned affiliate, $84
million of Class A redeemable preferred shares (16,000 shares priced at 10,000
New Zealand dollars per share with dividend rates between 6.19% and 6.86%).
The shares are redeemable at their issuance price in June 2003.

During 1999, EME issued through an indirect, wholly owned affiliate, $125
million of retail redeemable preference shares (240 million shares priced at
one New Zealand dollar per share with dividend rates between 5.0% and 6.37%).
The shares are redeemable at their issuance price, according to the following
schedule: June 2001 (64 million shares); June 2002 (43 million shares); and
June 2003 (133 million shares).

Note 8. Income Taxes

Edison International's subsidiaries are included in Edison International's
consolidated federal income tax and combined state franchise tax returns.
Under income tax allocation agreements, each subsidiary calculates its own tax
liability.

Income tax expense includes the current tax liability from operations and the
change in deferred income taxes during the year. Investment tax credits are
amortized over the lives of the related properties.

The components of the net accumulated deferred income tax liability were:

In millions December 31, 2000 1999
--------------------------------------------------------------------

Deferred tax assets:
Property-related $ 277 $ 184
Unrealized gains or losses 420 453
Investment tax credits 81 113
Regulatory balancing accounts 1,763 68
Decommissioning 98 127
Unbilled revenue 101 122
Deferred income 183 185
Accrued charges 548 461
Loss carryforwards 902 69
Other 133 137
--------------------------------------------------------------------
Total $4,506 $1,919
--------------------------------------------------------------------
Deferred tax liabilities:
Property-related $4,239 $4,562
Leveraged leases 1,665 1,280
Capitalized software costs 264 225
Regulatory balancing accounts 1,632 448
Decommissioning 28 23
Unrealized gains and losses 317 357
Other 339 590
--------------------------------------------------------------------
Total $8,484 $7,485
--------------------------------------------------------------------
Accumulated deferred income taxes -- net $3,978 $5,566
--------------------------------------------------------------------
Classification of accumulated deferred income taxes:
Included in deferred credits $5,328 $5,757
Included in current assets 1,350 191

71

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Notes to Consolidated Financial Statements

The current and deferred components of income tax expense were:

In millions Year ended December 31, 2000 1999 1998
----------------------------------------------------------------

Current:
Federal $(61) $(111) $121
State -- 3 18
Foreign 61 (34) 15
----------------------------------------------------------------
-- (142) 154
----------------------------------------------------------------
Deferred -- federal and state:
Accrued charges (98) (147) (43)
Depreciation and basis differences (5) (57) (14)
Investment and energy tax credits -- net (41) (46) (80)
Leveraged leases 387 315 346
Loss carryforwards (846) -- (33)
Regulatory balancing accounts (740) 371 177
CTC amortization 251 7 63
Price risk management (38) -- --
State tax -- privilege year 30 4 (1)
Other 51 (11) (107)
----------------------------------------------------------------
(1,049) 436 308
----------------------------------------------------------------
Total $(1,049) $ 294 $462
----------------------------------------------------------------

The composite federal and state statutory income tax rate was 40.551% for all
years presented.

The federal statutory income tax rate is reconciled to the effective tax rate
below:

Year ended December 31, 2000 1999 1998
---------------------------------------------------------

Federal statutory rate 35.0% 35.0% 35.0%
Foreign earnings reinvestment 0.4 (4.4) --
Housing credits 2.0 (6.9) (5.7)
Capital loss utilization -- (4.7) --
Capitalized software 0.4 (2.5) (0.6)
Property-related and other (7.1) 9.7 10.0
Investment and energy tax credits 1.4 (4.7) (5.7)
State tax -- net of federal deduction 3.0 10.4 7.5
---------------------------------------------------------
Effective tax rate 35.1% 31.9% 40.5%
---------------------------------------------------------

Note 9. Employee Compensation and Benefit Plans

Employee Savings Plan

Edison International has a 401(k) defined-contribution savings plan designed to
supplement employees' retirement income. The plan received employer
contributions of $41 million in 2000, $31 million in 1999 and $18 million in
1998.

Pension Plan and Postretirement Benefits Other Than Pensions

Edison International has a noncontributory, defined-benefit pension plan that
covers employees meeting minimum service requirements. Edison International's
utility operations recognize pension expense as calculated by the actuarial
method used for ratemaking. In April 1999, Edison International adopted a cash
balance feature for its pension plan.

72

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Edison International

Most employees retiring at or after age 55 with at least 10 years of service
are eligible for postretirement health and dental care, life insurance and
other benefits.

Information on plan assets and benefit obligations is shown below:

Other
Pension Postretirement
Benefits Benefits
In millions Year ended December 31, 2000 1999 2000 1999
- -----------------------------------------------------------------------------

Change in benefit obligation
Benefit obligation at beginning of year $2,121 $ 2,281 $ 1,547 $ 1,563
Service cost 74 70 45 49
Interest cost 159 149 129 111
Plan amendment -- (26) -- (5)
Acquisition -- 10 -- 81
Actuarial loss (gain) 92 (221) 231 (198)
Benefits paid (185) (142) (62) (54)
- -----------------------------------------------------------------------------
Benefit obligation at end of year $2,261 $ 2,121 $ 1,890 $ 1,547
- -----------------------------------------------------------------------------
Change in plan assets
Fair value of plan assets at beginning of
year $3,112 $ 2,576 $ 1,283 $ 1,029
Actual return on plan assets 143 627 (41) 186
Employer contributions 39 51 20 122
Benefits paid (185) (142) (62) (54)
- -----------------------------------------------------------------------------
Fair value of plan assets at end of year $3,109 $ 3,112 $ 1,200 $ 1,283
- -----------------------------------------------------------------------------
Funded status $ 848 $ 991 $ (690) $ (264)
Unrecognized net loss (gain) (741) (1,019) 160 (218)
Unrecognized transition obligation 23 29 323 350
Unrecognized prior service cost 115 128 (3) (3)
- -----------------------------------------------------------------------------
Recorded asset (liability) $ 245 $ 129 $ (210) $ (135)
- -----------------------------------------------------------------------------
Discount rate 7.25% 7.75% 7.5% 8.0%
Rate of compensation increase 5.0% 5.0% -- --
Expected return on plan assets 8.5% 7.5% 8.2% 7.5%

Expense components were:

Other Postretirement
In millions Year ended Pension Benefits Benefits
December 31, 2000 1999 1998 2000 1999 1998
- -----------------------------------------------------------------------------

Service cost $ 74 $ 70 $ 63 $ 45 $ 49 $ 43
Interest cost 159 149 143 129 111 100
Expected return on plan assets (270) (190) (172) (106) (80) (62)
Net amortization and deferral (40) 12 14 27 27 28
- -----------------------------------------------------------------------------
Expense under accounting
standards (77) 41 48 95 107 109
Regulatory adjustment --
deferred 88 14 11 -- -- --
- -----------------------------------------------------------------------------
Total expense recognized $ 11 $ 55 $ 59 $ 95 $ 107 $ 109
- -----------------------------------------------------------------------------

The assumed rate of future increases in the per-capita cost of health care
benefits is 11.0% for 2001, gradually decreasing to 5.0% for 2008 and beyond.
Increasing the health care cost trend rate by one percentage point would
increase the accumulated obligation as of December 31, 2000, by $311 million
and annual aggregate service and interest costs by $34 million. Decreasing the
health care cost trend rate by one percentage point would decrease the
accumulated obligation as of December 31, 2000, by $264 million and annual
aggregate service and interest costs by $28 million.

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Notes to Consolidated Financial Statements

Phantom Stock Options

Phantom stock option performance awards (also known as affiliate options) were
developed for two affiliate companies, EME and Edison Capital, as part of the
Edison International long-term incentive compensation program for senior
management. Each phantom option could be exercised to realize any appreciation
in the deemed value of one hypothetical share of EME or Edison Capital stock
over exercise prices. Exercise prices for EME and Edison Capital phantom
options were escalated on an annually compounded basis over the grant price by
a factor linked to each affiliate's cost of capital. The deemed values of the
phantom stock were recalculated annually as determined by a formula linked to
the value of its portfolio of investments, less general and administrative
costs. The options had a 10-year term with one-third of the total award vesting
in each of the first three years of the award term. For options awarded in 1998
and 1999, one-fourth of the total award vested in each of the first four years
of the award term.

Compensation expense recorded with respect to the phantom stock options was $13
million in 2000 (before the $60 million adjustment referred to below), $157
million in 1999 and $53 million in 1998.

Edison International elected to not issue additional phantom options after
1999. In January 2000, the Board of Directors preliminarily approved an
exchange offer to the holders of outstanding phantom options. A revised
exchange offer was subsequently approved and all holders of phantom stock
options accepted the revised offer. The exchange offer was completed in August
2000. The exchange offer was principally for cash, with a portion exchanged for
stock equivalent units relating to Edison International common stock. The
vested cash payment occurred in March 2001, and accrued interest from August
2000. The number of stock equivalent units was determined on the basis of
$20.50 per share, and the stock equivalent units will receive dividend
equivalents to the extent dividends are declared on Edison International common
stock. Participants could elect to cash their vested stock equivalent units on
either the first or third anniversary of the exchange offer date (August 2000)
for an amount equal to the daily average of Edison International common stock
(for 20 trading days preceding the elected payment date). Some participants
have elected to defer payment of their cash and stock equivalent units. Since
all of the outstanding phantom options have been terminated, there will be no
future exercises of the phantom options.

Due to the lower valuation of the exchange offer, the liability for accrued
incentive compensation was reduced by approximately $60 million in the third
quarter of 2000.

Stock Option Plans

In 1998, Edison International shareholders approved the Edison International
Equity Compensation Plan, replacing the Long-Term Incentive Compensation
Program (prior program), which had been adopted by shareholders in 1992. Under
the prior program, options on 2.9 million of Edison International common stock
remain outstanding to officers and senior managers. The 1998 plan authorizes a
limited annual award of Edison International common shares and options on
shares. The annual authorization is cumulative, allowing subsequent issuance of
previously unutilized awards. In May 2000, Edison International adopted an
additional plan, the 2000 Equity Plan, which did not require shareholder
approval.

Under the 1998 and 2000 plans, options on 17.1 million shares of Edison
International common stock are currently outstanding to officers and senior
managers.

Each option may be exercised to purchase one share of Edison International
common stock, and is exercisable at a price equivalent to the fair market value
of the underlying stock at the date of grant. Options expire 10 years after the
date of grant, and vest over a period of up to five years. A portion of the
executive long-term incentives for 2000 was awarded in the form of performance
shares. The performance shares were restructured as retention incentives in
December 2000, which will pay as a combination of Edison International common
stock and cash if the executive remains employed at the

74

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Edison International

end of the performance period. Performance shares may still be awarded in 2001
and 2002. No special stock options may be exercised before five years have
passed unless the stock price appreciates to $25 (based on the average of 20
consecutive trading day closing prices). Edison International stock options
awarded between 1994 and 1999 included a dividend equivalent feature. Dividend
equivalents are accrued to the extent dividends are declared on Edison
International common stock, and are subject to reduction unless certain
performance criteria are met. Only a portion of the 1999 Edison International
stock option awards included a dividend equivalent feature. The 2000 stock
option awards did not include dividend equivalents. Future stock option awards
are not expected to include dividend equivalents.

All stock options have a 10-year term. Options issued after 1997 generally
vest in 25 percent annual installments over a four-year period, although the
vesting period for the May 2000 grants does not begin until May 2001. Stock
options issued prior to 1998 had a three-year vesting period with one-third of
the total award vesting after each of the first three years of the award term.
If an option holder retires, dies or is permanently and totally disabled
(qualifying event) during the vesting period, the unvested options will vest
on a pro rata basis.

Unvested options of any person who has served in the past on the SCE
Management Committee (which was dissolved in 1993) will vest and be
exercisable upon a qualifying event. If a qualifying event occurs, the vested
options may continue to be exercised within their original terms by the
recipient or beneficiary. If an option holder is terminated other than by a
qualifying event, options which had vested as of the prior anniversary date of
the grant are forfeited unless exercised within 180 days of the date of
termination. All unvested options are forfeited on the date of termination.

The performance shares values are accrued ratably over a three-year
performance period. Edison International measures compensation expense related
to stock-based compensation by the intrinsic value method. Compensation
expense recorded under the stock-compensation program was $5 million in 2000,
$5 million in 1999 and $9 million in 1998.

Stock-based compensation expense under the fair value method of accounting
would have resulted in pro forma earnings (loss) of $(1.954) billion for 2000,
$621 million for 1999 and $668 million for 1998, and in pro forma basic
earnings (loss) per share of $(5.87) for 2000, $1.79 for 1999 and $1.86 for
1998.

The fair value for each option granted, reflecting the basis for the above pro
forma disclosures, was determined on the date of grant using the Black-Scholes
option-pricing model. The following assumptions were used in determining fair
value through the model:

December 31, 2000 1999
----------------------------------------------------

Expected life 7 years-10 years 7 years
Risk-free interest rate 4.7%-6.0% 5.0%-5.5%
Expected volatility 17%-46% 18%
----------------------------------------------------

The application of fair-value accounting to calculate the pro forma
disclosures above is not an indication of future income statement effects. The
pro forma disclosures do not reflect the effect of fair-value accounting on
stock-based compensation awards granted prior to 1995.

75

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Notes to Consolidated Financial Statements

A summary of the status of Edison International's stock options is as follows:

Weighted Average
-----------------------------
Share Exercise Exercise Fair Value Remaining
Options Price Price At Grant Life
- ----------------------------------------------------------------------------------------

Outstanding, December 31, 1997 4,411,666 $14.56--$25.19 $18.76 7 years
Granted 1,639,300 $26.78--$29.34 $27.25 $6.42
Expired -- -- --
Forfeited (46,171) $17.63--$29.88 $26.07
Exercised (573,527) $14.56--$29.88 $17.33
- ----------------------------------------------------------------------------------------
Outstanding, December 31, 1998 5,431,268 $14.56--$29.34 $21.52 7 years
Granted 3,045,949 $24.81--$28.13 $28.10 $6.45
Expired -- -- --
Forfeited (6,805) $28.13--$28.80 $28.65
Exercised (368,264) $14.56--$25.75 $18.72
- ----------------------------------------------------------------------------------------
Outstanding, December 31, 1999 8,102,148 $14.56--$29.34 $24.04 7 years
Granted 13,373,680 $15.88--$28.13 $21.02 $5.63
Expired -- -- --
Forfeited (1,183,760) $15.94--$28.94 $23.19
Exercised (517,396) $14.56--$28.13 $19.35
- ----------------------------------------------------------------------------------------
Outstanding, December 31, 2000 19,774,672 $14.56--$29.34 $22.24 8 years
- ----------------------------------------------------------------------------------------

The number of options exercisable and their weighted average exercise prices at
December 31, 2000, 1999 and 1998 were 6,782,209 at $23.27, 5,018,556 at $21.63,
and 3,805,755 at $19.72, respectively.

Note 10. Jointly Owned Utility Projects

SCE owns interests in several generating stations and transmission systems for
which each participant provides its own financing. SCE's share of expenses for
each project is included in the consolidated statements of income.

The investment in each project as of December 31, 2000, was:

Accumulated
Original Depreciation
Cost of and Under Ownership
In millions Facility Amortization Construction Interest
- -------------------------------------------------------------------------------

Transmission systems:
Eldorado $ 41 $ 11 $ 1 60%
Pacific Intertie 230 80 6 50
Generating stations:
Four Corners Units 4 and 5 (coal) 463 351 3 48
Mohave (coal) 327 240 3 56
Palo Verde (nuclear)(/1/) 1,624 1,399 15 16
San Onofre (nuclear)(/1/) 4,268 3,874 22 75
- -------------------------------------------------------------------------------
Total $6,953 $5,955 $50
- -------------------------------------------------------------------------------

(/1/)Regulatory assets, which were written off as a charge to earnings as of
December 31, 2000, as discussed in Notes 1 and 3.

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Edison International

Note 11. Commitments

Leases

Leveraged Leases

Edison Capital is the lessor in several leveraged-lease agreements with terms
of 24 years to 38 years. All operating, maintenance, insurance and
decommissioning costs are the responsibility of the lessees. The total cost of
these facilities was $7.5 billion and $5.5 billion at December 31, 2000, and
1999, respectively.

The equity investment in these facilities is 19% of the purchase price. The
remainder is nonrecourse debt secured by first liens on the leased property.
The lenders have accepted their security interests as their only remedy if the
lessee defaults.

The net investment in leveraged leases consisted of:

In millions December 31, 2000 1999
- -----------------------------------------------------------------------

Rentals receivable (net of principal and interest on
nonrecourse debt) $ 3,827 $ 2,990
Unearned income (1,531) (1,145)
- -----------------------------------------------------------------------
Investment in leveraged leases 2,296 1,845
Estimated residual value 57 58
Deferred income taxes (1,665) (1,280)
- -----------------------------------------------------------------------
Net investment in leveraged leases $ 688 $ 623
- -----------------------------------------------------------------------

Operating Leases

Edison International has operating leases for office space, vehicles, property
and other equipment (with varying terms, provisions and expiration dates).

During 2000, EME entered into a sale-leaseback transaction for certain
equipment, primarily Illinois peaker power units, with a third-party lessor
for $300 million. In connection with the sale-leaseback, EME purchased $255
million of notes issued by the lessor that accrue interest at a variable rate
depending on EME's credit rating. The notes are due and payable in five years.
Also during 2000, EME entered into a sale-leaseback transaction for power
facilities, located in Illinois, with third-party lessors for an aggregate
purchase price of $1.4 billion. The lease costs for the power facilities will
be levelized over the terms of the power facilities' respective leases. The
gain recognized on the sale of the power plants and equipment has been
deferred and is being amortized over the terms of the respective leases. Lease
payments are included in the table below.

Estimated remaining commitments for noncancelable leases at December 31, 2000,
were:

Year ended December 31, In millions
--------------------------------------

2001 $ 196
2002 212
2003 210
2004 232
2005 269
Thereafter 3,838
--------------------------------------
Total $4,957
--------------------------------------

77

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Notes to Consolidated Financial Statements

In December 2000, EME entered into agreements involving the construction of new
projects. Under the terms of one of the agreements, the lessor, as owner of the
projects, is responsible for the development and construction costs
(approximately $986 million) of the new projects using turbines procured by
EME. EME will supervise the development and construction of the projects as the
agent of the lessor and upon completion of construction of each project, EME
will lease the projects from the lessor. In connection with the lease, EME has
provided a residual value guarantee to the lessor at the end of the lease term.
EME is required to deposit treasury notes equal to 103% of the construction
costs as collateral for the lessor which can only be used under certain
circumstances involving default of EME's performance obligations during
construction. Minimum lease payments under this agreement (included in the
table above) are $3 million in 2003, $28 million in 2004 and $50 million in
2005. The lease agreement provides a purchase option based on the lease balance
which can be exercised at any time during the term. The lease term ends in
2010.

Nuclear Decommissioning

Decommissioning is estimated to cost $2.1 billion in current-year dollars,
based on site-specific studies performed in 1998 for San Onofre and Palo Verde.
Changes in the estimated costs, timing of decommissioning, or the assumptions
underlying these estimates could cause material revisions to the estimated
total cost to decommission in the near term. SCE estimates that it will spend
approximately $8.6 billion through 2060 to decommission its nuclear facilities.
This estimate is based on SCE's current dollar decommissioning costs, escalated
at rates ranging from 0.3% to 10.0% (depending on the cost element) annually.
These costs are expected to be funded from independent decommissioning trusts,
which, effective June 1999, receive contributions of approximately $25 million
per year. SCE estimates annual after-tax earnings on the decommissioning funds
of 3.9% to 4.9%.

SCE plans to decommission its nuclear generating facilities by a prompt removal
method authorized by the Nuclear Regulatory Commission. The operating licenses
expire in 2022 for San Onofre Units 2 and 3, and in 2026 and 2028 for the Palo
Verde units. SCE could decommission San Onofre Units 2 and 3 as early as 2013.
Palo Verde is planned to be decommissioned at the end of its operating license.
Decommissioning costs, which are recovered through non-bypassable customer
rates over the term of each nuclear facility's operating license, are recorded
as a component of depreciation expense.

Decommissioning of San Onofre Unit 1 (shut down in 1992 per CPUC agreement)
started in 1999 and will continue through 2008. All of SCE's San Onofre's Unit
1 decommissioning costs will be paid from its nuclear decommissioning trust
funds.

Decommissioning expense was $106 million in 2000, $124 million in 1999 and $164
million in 1998. The accumulated provision for decommissioning, excluding San
Onofre Unit 1 and unrealized holding gains, was $1.4 billion at December 31,
2000, and $1.3 billion at December 31, 1999. The estimated cost (recorded as a
liability) to decommission San Onofre Unit 1 is approximately $342 million as
of December 31, 2000.

Decommissioning funds collected in rates are placed in independent trusts,
which, together with accumulated earnings, will be utilized solely for
decommissioning.

Trust investments (cost basis) include:

In millions Maturity Dates December 31, 2000 1999
- -----------------------------------------------------------------

Municipal bonds 2001-2034 $ 548 $ 684
Stocks -- 531 482
U.S. government issues 2001-2029 421 351
Short-term and other 2001 220 133
- -----------------------------------------------------------------
Total $1,720 $1,650
- -----------------------------------------------------------------

78

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Edison International

Trust fund earnings (based on specific identification) increase the trust fund
balance and the accumulated provision for decommissioning. Net earnings were
$38 million in 2000, $58 million in 1999 and $63 million in 1998. Proceeds
from sales of securities (which are reinvested) were $4.7 billion in 2000,
$2.6 billion in 1999 and $1.2 billion in 1998. Approximately 90% of the trust
fund contributions were tax deductible.

Other Commitments

SCE and EME have fuel supply contracts which require payment only if the fuel
is made available for purchase. Certain SCE gas and coal fuel contracts
require payment of certain fixed charges whether or not gas or coal is
delivered.

SCE has power-purchase contracts with certain qualifying facilities
(cogenerators and small power producers) and other utilities. These contracts
provide for capacity payments if a facility meets certain performance
obligations and energy payments based on actual power supplied to SCE. There
are no requirements to make debt-service payments. As a result of the utility
industry restructuring, SCE has entered into purchased-power settlements to
end its contract obligations with certain qualifying facilities. The
settlements are reported as power purchase contracts on the balance sheets.

SCE has unconditional purchase obligations for part of a power plant's
generating output, as well as firm transmission service from another utility.
Minimum payments are based, in part, on the debt-service requirements of the
provider, whether or not the plant or transmission line is operable. SCE's
minimum commitment under both contracts is approximately $159 million through
2017. The purchased-power contract is expected to provide approximately 5% of
current or estimated future operating capacity, and is reported as power
purchase contracts (approximately $31 million). The transmission service
contract requires a minimum payment of approximately $6 million a year.

Certain commitments for the years 2001 through 2005 are estimated below:

In millions 2001 2002 2003 2004 2005
------------------------------------------------------------

Fuel supply contracts $989 $760 $501 $405 $338
Purchased-power capacity payments 647 644 637 635 632
------------------------------------------------------------

SCE and EME's projected construction expenditures for 2001 total approximately
$1.1 billion. The construction programs are subject to periodic review and
revision, and actual construction costs may vary from estimates because of
numerous factors.

EME has firm commitments related to its Italian wind projects to make equity
contributions of $3 million, and $17 million for asset purchases. EME also has
contingent obligations to make additional contributions of $83 million,
primarily for equity support guarantees related to the Paiton project in
Indonesia and the ISAB project in Italy.

SCE has deferred payment to certain QFs for power purchases (as discussed in
Notes 2 and 3). Four of these QFs are owned by partnerships in which EME has
interests. Some of these QFs, have sought to minimize their exposure by
reducing deliveries under power purchase agreements. As a result of the
payment deferrals, certain partnerships have called on the partners to provide
additional capital to fund operating costs of the power plants. From January
2001 through March 31, 2001, EME subsidiaries have made equity contributions
of approximately $115 million to meet capital calls by these partnerships.
EME's subsidiaries may be required to make additional capital contributions to
the partnerships.

Edison Capital has commitments of $228 million to fund affordable housing, and
energy and infrastructure investments.

79

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Notes to Consolidated Financial Statements

Note 12. Contingencies

In addition to the matters disclosed in these notes, Edison International is
involved in other legal, tax and regulatory proceedings before various courts
and governmental agencies regarding matters arising in the ordinary course of
business. SCE believes the outcome of these other proceedings will not
materially affect its results of operations or liquidity.

Energy Crisis Issues

In December 2000, a first amended complaint to a class action securities
lawsuit (originally filed in October 2000) was filed in federal district court
in Los Angeles against SCE and Edison International. On March 5, 2001, a second
amended complaint was filed that alleges that SCE and Edison International are
engaging in fraud by over-reporting and improperly accounting for the TRA
undercollections. The second amended complaint is supposedly 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
are recorded as a loss on SCE's income statement. The response to the second
amended complaint was due April 2, 2001. The response has been deferred pending
resolution of motions to consolidate this lawsuit with another lawsuit filed on
March 15, 2001. SCE believes that its current and past accounting for the TRA
undercollections and related items is appropriate and in accordance with
accounting principles generally accepted in the United States.

As of April 13, 2001, 17 additional lawsuits have been filed against SCE by
QFs. The lawsuits have been filed by various parties, including geothermal or
wind energy suppliers or owners of cogeneration projects. The lawsuits are
seeking payments of at least $420 million for energy and capacity supplied to
SCE under QF contracts, and in some cases for damages as well. Many of these QF
lawsuits also seek an order allowing the suppliers to stop providing power to
SCE and sell the power to other purchasers. SCE is seeking coordination of all
of the QF-related lawsuits that have commenced in various California courts. On
April 13, 2001, an order was issued assigning all pending cases to a
coordination motion judge and setting a hearing on SCE's coordination petition
by May 30, 2001. SCE cannot predict the outcome of any of these matters.

Environmental Protection

Edison International is subject to numerous environmental laws and regulations,
which require it to incur substantial costs to operate existing facilities,
construct and operate new facilities, and mitigate or remove the effect of past
operations on the environment.

Edison International records its environmental liabilities 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 recorded estimated minimum liability to remediate its 44
identified sites is $114 million. The ultimate costs to clean up Edison
International'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. Edison
International believes that, due to these uncertainties, it is reasonably
possible that cleanup

80

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Edison International

costs could exceed its recorded liability by up to $272 million. The upper
limit of this range of costs was estimated using assumptions least favorable
to Edison International 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.

The CPUC allows SCE to recover environmental-cleanup costs at certain sites,
representing $45 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. 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 $75 million for its
estimated minimum environmental-cleanup costs expected to be recovered through
customer rates.

Edison International'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 Edison International
may be held responsible for contributing to any costs incurred for remediating
these sites. Thus, no reasonable estimate of cleanup costs can now be made for
these sites.

Edison International 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 $5 million to $15 million. Recorded expenditures for
2000 were $13 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 not materially affect its results of operations or
financial position. There can be no assurance, however, that future
developments, including additional information about existing sites or the
identification of new sites, will not require material revisions to such
estimates.

Nuclear Insurance

Federal law limits public liability claims from a nuclear incident to $9.5
billion. SCE and other owners of San Onofre and Palo Verde have purchased the
maximum private primary insurance available ($200 million). The balance is
covered by the industry's retrospective rating plan that uses deferred premium
charges to every reactor licensee if a nuclear incident at any licensed
reactor in the U.S. results in claims and/or costs which exceed the primary
insurance at that plant site. Federal regulations require this secondary level
of financial protection. The Nuclear Regulatory Commission exempted San Onofre
Unit 1 from this secondary level, effective June 1994. The maximum deferred
premium for each nuclear incident is $88 million per reactor, but not more
than $10 million per reactor may be charged in any one year for each incident.
Based on its ownership interests, SCE could be required to pay a maximum of
$175 million per nuclear incident. However, it would have to pay no more than
$20 million per incident in any one year. Such amounts include a 5% surcharge
if additional funds are needed to satisfy public liability claims and are
subject to adjustment for inflation. If the public liability limit above is
insufficient, federal regulations may impose further revenue-raising measures
to pay claims, including a possible additional assessment on all licensed
reactor operators.

Property damage insurance covers losses up to $500 million, including
decontamination costs, at San Onofre and Palo Verde. Decontamination liability
and property damage coverage exceeding the primary $500 million also has been
purchased in amounts greater than federal requirements. Additional insurance
covers part of replacement power expenses during an accident-related nuclear
unit outage. These policies are issued primarily by mutual insurance companies
owned by utilities with nuclear facilities. If losses at any nuclear facility
covered by the arrangement were to exceed the accumulated funds for these
insurance programs, SCE could be assessed retrospective premium adjustments of
up to $19 million per year. Insurance premiums are charged to operating
expense.

81

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Notes to Consolidated Financial Statements

Paiton Project

A wholly owned subsidiary of EME owns a 40% interest and has a $490 million
investment (at December 31, 2000) in the Paiton project, a 1,230-MW coal-fired
power plant in Indonesia. The revenue schedule is higher in the early years and
decreases over time. The plant's output is fully contracted with the state-
owned electricity company for payment in Indonesian Rupiah, with the portion of
such payments intended to cover non-Rupiah project costs (including returns to
investors) adjusted to account for exchange rate fluctuation between the
Indonesian Rupiah and the U.S. dollar. The project received substantial finance
and insurance support from the Export-Import Bank of the United States and
various other governmental agencies. The state-owned electricity company's
payment obligations are supported by the Indonesian government.

The projected rate of growth of the Indonesian economy and the exchange rate of
Indonesian Rupiah into U.S. dollars have deteriorated significantly since the
Paiton project was contracted, approved and financed. The Paiton project's
senior debt ratings have been reduced from investment grade to speculative
grade based on the rating agencies' determination that there is increased risk
that the state-owned electricity company might not be able to honor the power
purchase agreement with Paiton. The Indonesian government has arranged to
reschedule senior debt owed to foreign governments and has entered into
discussions about rescheduling senior debt owed to private lenders.

One of the Paiton units began commercial operation in May 1999 and the other
unit in July 1999. Because of the economic downturn, the state-owned
electricity company has experienced low electricity demand and has therefore
ordered no power from the Paiton plant through February 2000. The state-owned
electricity company filed a lawsuit contesting the validity of its agreement to
purchase electricity from the Paiton project. The lawsuit was withdrawn in
January 2000, and in connection with this withdrawal, the parties entered into
an interim agreement for the period through December 31, 2000, under which the
levels of power ordered, and the fixed and energy payment amounts were agreed.
As of December 31, 2000, the state-owned electricity company has made all fixed
payments due under the interim agreement totalling $115 million and all
payments due for energy delivered by the plant to the state-owned electricity
company. As part of the continuing negotiations on a long-term restructuring of
the revenue schedule, Paiton and the state-owned electricity company agreed in
January 2001 on a Phase I agreement for the period from January 1, 2001,
through June 30, 2001. This agreement provides for fixed monthly payments of
$108 million over its six-month duration and for the payment for energy
delivered to the state-owned electricity company from the plant during this
period. Paiton and the state-owned electricity company intend to complete the
negotiations of the future phases of a new long-term revenue schedule during
the six-month duration of the Phase I agreement. To date, the state-owned
electricity company has made all fixed and energy payments due under the Phase
I agreement.

In October 1999, the project entered into an interim agreement with its lenders
in which the lenders waived defaults during the term of the agreement and
effectively agreed to defer payments of principal until July 31, 2000. The
lenders had agreed to an extension of the agreement through December 31, 2000
(which has now been extended through December 31, 2001). Paiton has received
lender approval of the Phase I agreement.

Under the terms of the power purchase agreement, the state-owned electricity
company has been required to continue to pay for capacity and fixed operating
costs once each unit and the plant achieved commercial operation. As of
December 31, 2000, the state-owned electricity company had not paid invoices
totaling $814 million for capacity charges and fixed operating costs under the
power purchase agreement. All overdue amounts under the power purchase
agreement continue to accumulate, minus the fixed monthly payments made under
the year 2000 interim agreement and under the recently agreed Phase I
agreement, with the payment of these overdue amounts to be dealt with in
connection with the overall long-term restructuring of the revenue schedule. In
this regard, under the Phase I agreement, Paiton has agreed that, so long as
the Phase I agreement is complied with, it will seek to recoup no more than
$590 million of the above overdue amounts, the payment of which is to be dealt
with in connection with the overall revenue schedule restructuring.

82

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Edison International

Any material modifications of the power purchase agreement resulting from the
continuing negotiation of a new long-term revenue schedule could require a
renegotiation of the Paiton project's debt agreements. The impact of any such
renegotiations with the state-owned electricity company, the Indonesian
government or the project's creditors on EME's expected return on its
investment in Paiton is uncertain at this time; however, EME believes that it
will ultimately recover its investment in the project.

Spent Nuclear Fuel

Under federal law, the DOE is responsible for the selection and development of
a facility for disposal of spent nuclear fuel and high-level radioactive
waste. Such a facility was to be in operation by January 1998. However, the
DOE did not meet its obligation. It is not certain when the DOE will begin
accepting spent nuclear fuel from San Onofre or from other nuclear power
plants.

SCE, as operating agent, has primary responsibility for the interim storage of
its spent nuclear fuel at San Onofre. Current capability to store spent fuel
is estimated to be adequate through 2005. SCE has not determined the costs for
spent-fuel storage beyond that period which would require new and separate
interim storage facilities. Extended delays by the DOE could lead to
consideration of costly alternatives involving siting and environmental
issues. SCE has paid the DOE the required one-time fee applicable to nuclear
generation at San Onofre through April 6, 1983 (approximately $24 million,
plus interest). SCE is also paying the required quarterly fee equal to one
mill per kWh of nuclear-generated electricity sold after April 6, 1983.

Palo Verde on-site spent fuel storage capacity will accommodate needs until
2003 for Unit 2, and until 2004 for Units 1 and 3. Arizona Public Service
Company, operating agent for Palo Verde, is constructing an interim fuel
storage facility that is expected to be completed in 2002.

Note 13. Investments in Partnerships and Unconsolidated Subsidiaries

Edison International's nonutility subsidiaries have equity interests in energy
projects, oil and gas and real estate investment partnerships. The difference
between the carrying value of energy project investments and oil and gas and
the underlying equity in the net assets was $490 million at December 31, 2000.
The difference related to the energy projects is being amortized over the life
of the projects; the difference related to oil and gas investment is amortized
on a unit of production basis over the life of the reserves.

Summarized financial information of these investments was:

In millions Year
ended December 31, 2000 1999 1998
-----------------------------------------------------

Revenue $ 2,844 $ 2,338 $1,848
Expenses 2,266 1,872 1,525
-----------------------------------------------------
Net income $ 578 $ 466 $ 323
-----------------------------------------------------

In millions December 31, 2000 1999
-----------------------------------------------------

Current assets $ 1,907 $ 854
Other assets 8,272 9,487
-----------------------------------------------------
Total assets $10,179 $10,341
-----------------------------------------------------
Current liabilities $ 1,299 $ 1,644
Other liabilities 6,192 6,029
Equity 2,688 2,668
-----------------------------------------------------
Total liabilities and equity $10,179 $10,341
-----------------------------------------------------

83

- --------------------------------------------------------------------------------
Notes to Consolidated Financial Statements

The undistributed earnings of investments accounted for by the equity method
were $271 million in 2000 and $224 million in 1999.

Note 14. Business Segments

Edison International's reportable business segments include its electric
utility operation segment (SCE), a nonutility power generation segment (EME),
and a capital and financial services provider segment (Edison Capital). Its
segments are based on Edison International's internal organization. They are
separate business units and are managed separately. Edison International
evaluates performance based on net income.

SCE is a rate-regulated electric utility which produces and supplies electric
energy in central, coastal and Southern California. EME is a producer of
electricity engaged in the development, ownership or leasing and operation of
electric power generation facilities worldwide. EME also conducts energy
trading and price risk management activities in markets where power generation
facilities are open to competition. Edison Capital is a provider of capital and
financial services with investments worldwide.

The accounting policies of the segments are the same as those described in the
summary of significant accounting policies.

A significant source of revenue from EME's sale of energy and capacity is
derived from sales to Commonwealth Edsion under power purchase agreements
terminating in December 2004. Revenue from such sales was $1.1 billion in 2000.
In January 2001, Commonwealth Edison assigned its rights to Exelon Generation
Company. Exelon Generation will be obligated to make a capacity payment for the
units under contract and an energy payment for the electricity produced by
these units.

84

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Edison International

Edison International's business segment information was:

Nonutility Capital & Consolidated
Electric Power Financial Corporate Edison
In millions Utility Generation Services & Other(/1/) International
- -----------------------------------------------------------------------------------------------

2000
Operating revenue $ 7,870 $ 3,253(/2/) $ 274 $ 320 $11,717
Depreciation,
decommissioning and
amortization 1,473 382 28 50 1,933
Interest and dividend
income 173 45 10 (1) 227
Interest expense -- net
of amounts capitalized 572 689 57 70 1,388
Income tax expense
(benefit) (1,022) 82 (10) (99) (1,049)
Net income (loss) (2,050)(/3/) 125 135 (153) (1,943)
Total assets 15,966 15,017 3,713 404 35,100
Additions to and
acquisition of property 1,096 399 1 39 1,535
- -----------------------------------------------------------------------------------------------
1999
Operating revenue $ 7,548 $ 1,642(/2/) $ 282 $ 224 $ 9,696
Depreciation,
decommissioning and
amortization 1,548 190 22 35 1,795
Interest and dividend
income 69 42 4 (19) 96
Interest expense -- net
of amounts capitalized 483 353 41 17 894
Income tax expense
(benefit) 438 (40) (25) (79) 294
Net income 484 130 129 (120) 623
Total assets 17,657(/3/) 15,534 2,712 326 36,229
Additions to and
acquisition of property 986 8,309 -- (105)(/4/) 9,190
- -----------------------------------------------------------------------------------------------
1998
Operating revenue $ 7,499 $ 894(/2/) $ 235 $ 232 $ 8,860
Depreciation,
decommissioning and
amortization 1,546 87 20 9 1,662
Interest and dividend
income 67 50 4 (13) 108
Interest expense -- net
of amounts capitalized 485 183 49 (7) 710
Income tax expense
(benefit) 442 70 (15) (35) 462
Net income 490 132 105 (59) 668
Total assets 16,947(/3/) 5,158 2,276 317 24,698
Additions to and
acquisition of property 861 331 -- 29 1,221
- -----------------------------------------------------------------------------------------------

(/1/)Includes amounts from nonutility subsidiaries not significant as a
reportable segment.
(/2/)Includes equity in income from investments of $267 million in 2000, $244
million in 1999 and $189 million in 1998.
(/3/)Net income (loss) available for common stock.
(/4/)Includes liabilities assumed and deferred credits of projects acquired in
1999.

Geographic Information

Electric power and steam generated domestically by EME is sold primarily under
long-term contracts to electric utilities, through a centralized power pool,
or under a power-purchase agreement with a term of

85

- --------------------------------------------------------------------------------
Notes to Consolidated Financial Statements

up to five years. Projects in the United Kingdom and a project in Australia
sell their energy through a centralized power pool (in the respective
countries). Other electric power generated overseas is sold primarily under
long-term contracts to electric utilities located in the country where the
power is generated. All electric power generated by SCE was sold through the PX
and ISO, as mandated by the CPUC. Effective December 15, 2000, the requirement
for California utilities to buy and sell exclusively through the PX and ISO was
eliminated.

Edison International's foreign and domestic revenue and assets information was:

In millions Year ended December 31, 2000 1999 1998
------------------------------------------------------------

Revenue
United States $10,262 $8,657 $8,154
Foreign Countries:
United Kingdom 1,140 748 449
Australia 178 209 199
Other 137 82 58
------------------------------------------------------------
$11,717 $9,696 $8,860
------------------------------------------------------------

In millions December 31, 2000 1999
-------------------------------------------

Assets
United States $26,930 $28,122
Foreign Countries:
United Kingdom 5,212 5,032
Australia 1,217 1,398
Other 1,741 1,677
-------------------------------------------
$35,100 $36,229
-------------------------------------------

Note 15. Acquisitions

Italian Wind Projects

In March 2000, EME completed its acquisition of Edison Mission Wind Power Italy
B.V., formerly known as Italian Vento Power Corp. Energy 5 B.V. Edison Mission
Wind owns a 50% interest in a series of wind-generated power projects in
operation or under development in Italy. When all of the projects under
development are completed, currently scheduled for 2002, the total capacity of
these projects will be 283 MW. The purchase price of the acquisition is $44
million with equity contribution obligations of up to $16 million, depending on
the number of projects that are ultimately developed. As of December 31, 2000,
EME has paid $27 million toward the purchase price and $13 million in equity
contributions.

Citizens Power

In September 2000, EME completed a transaction with P&L Coal Holdings
Corporation and Gold Fields Mining Corporation to acquire the trading
operations of Citizens Power LLC and a minority interest in certain structured
transaction investments relating to long-term power purchase agreements. The
purchase price of $45 million (funded from cash) was based on the sum of the
fair market value of the trading portfolio and the structured transaction
investments at the date of acquisition, plus $25 million. As a result of this
acquisition, EME has expanded its trading operations beyond the traditional
marketing of electric power. By the end of the third quarter of 2000, the
Citizens' trading operations were merged into EME's marketing operations.

86

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Edison International

Sunrise Project

In November 2000, EME completed a transaction with Texaco Inc. to purchase a
proposed 560-MW gas-fired combined cycle project (Sunrise Project) to be
located in central California. The acquisition includes all rights, title and
interest held by Texaco in the Sunrise Project, except that Texaco has an
option to repurchase a 50% interest in the project prior to commercial
operation. Phase I (construction of a single-cycle gas-fired facility) is
scheduled to be completed in August 2001; Phase II (conversion to a combined-
cycle gas-fired facility) is scheduled to be completed by June 2003. In
December 2000, EME received the Energy Commission Certification and a permit
to construct Phase I. The purchase price was $27 million. The acquisition was
funded with cash. The project's estimated construction cost is approximately
$400 million. As a part of this transaction, EME also acquired an option to
purchase two gas turbines which it plans to utilize in the project, and
provided Texaco with options to purchase two of the turbines under a lease
agreement and to acquire 50% interests in 1,000 MW of future plant projects
EME designates.

As discussed in Note 3, one of the elements of the Governor's proposal is the
commitment of the entire output of this project to the State at cost-based
rates for 10 years. As a result, EME is negotiating with the CDWR the detailed
terms and conditions of a long-term, cost-based power purchase agreement. No
assurance can be provided that EME will be successful in reaching a final
agreement.

Homer City Electric Generating Station

In 1999, EME paid approximately $1.8 billion for Homer City. The purchase was
partially financed by $1.5 billion of new loans, combined with corporate
revolver borrowings and existing cash.

Contact Energy Ltd.

In 1999, EME completed a transaction with the New Zealand government to
acquire 40% of the shares of Contact Energy Ltd (which owns and operates
hydroelectric, geothermal and natural gas-fired generating plants, primarily
in New Zealand). The remaining 60% of Contact Energy's shares were sold in an
overseas public offering resulting in widespread ownership among the citizens
of New Zealand and offshore investors. EME paid $635 million (1.2 billion New
Zealand dollars), which was financed by a $120 million preferred securities of
a wholly owned affiliate of EME, a $214 million EME credit facility, a $300
million equity contribution from Edison International and existing cash.
During 2000, EME increased its share of ownership in Contact Energy to 42%.

Ferrybridge and Fiddler's Ferry

In 1999, EME paid approximately $2.0 billion (1.3 billion pounds Sterling) for
the two plants. The coal-fired electric generating plants are located in the
United Kingdom. Each plant has generating capacity of approximately 2,000 MW.
The acquisition was funded primarily with a combination of net proceeds from
an EME bond issuance, cash and an equity contribution from Edison
International. The bonds were issued to a special purpose entity, which sold
the variable rate coupons portion of the bonds to a special purpose entity
that borrowed $1.3 billion under a Term Loan Facility to finance the purchase.

Roosecote Project

In 1999, EME paid approximately $16 million (9.6 million pounds Sterling) for
the remaining 20% of the 220-MW natural gas-fired Roosecote project located in
England.

Illinois Plants

In December 1999, EME through its wholly owned subsidiary, Midwest Generation
LLC, completed the acquisition of Commonwealth Edison's fossil-fueled
generating plants in Illinois. The $4.9 billion

87

- --------------------------------------------------------------------------------
Notes to Consolidated Financial Statements

transaction was funded primarily with a combination of debt secured by a pledge
of the stock of certain subsidiaries, EME corporate debt, equity contributions
from Edison International and amounts paid by third-party lessors in connection
with a lease transaction.

These acquisitions were accounted for utilizing the purchase method. Edison
International's 2000 consolidated income statements reflect the operations of
the Italian wind projects as of April 1, 2000, and Citizens Power as of
September 1, 2000. Edison International's 1999 consolidated income statements
reflect the operations of Homer City, Contact Energy, Ferrybridge and Fiddler's
Ferry, Roosecote and the Illinois plants as of the date of their respective
acquisitions.

In February 2001, EME completed the acquisition of a 50% interest in CBK Power
Co. Ltd. in exchange for $20 million. CBK Power has entered into a 25-year
build-rehabilitate-transfer-and-operate agreement with National Power
Corporation related to a hydroelectric project located in the Philippines.
Financing for this $460 million project has been completed with equity
contributions of $117 million (EME's share is $59 million) required to be made
upon completion of the rehabilitation and expansion, currently scheduled in
2003. Debt financing has been arranged for the remainder of the cost for this
project.

88

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Quarterly Financial Data (Unaudited) Edison International

2000
---------------------------------------------
In millions, except per
share amounts Total Fourth Third Second First
- ----------------------------------------------------------------------

Operating revenue $11,717 $ 2,591 $ 3,653 $ 2,749 $ 2,724
Operating income (loss) (1,729) (3,777) 962 557 529
Net income (loss) (1,943) (2,550) 360 137 110
Per share:
Basic earnings (loss) (5.84) (7.83) 1.11 0.41 0.32
Diluted earnings (loss) (5.84) (7.83) 1.10 0.41 0.32
Dividends declared 0.84 -- 0.28 0.28 0.28
Common stock prices:
High 30 24 7/16 26 5/8 21 15/16 30
Low 14 1/8 14 1/8 19 16 5/16 15 1/4
Close 15 5/8 15 5/8 19 21/64 20 1/2 16 9/16

1999
---------------------------------------------
In millions, except per
share amounts Total Fourth Third Second First
- ----------------------------------------------------------------------

Operating revenue $ 9,696 $ 2,516 $ 2,963 $ 2,121 $ 2,096
Operating income 1,754 327 643 379 405
Net income 623 96 255 129 143
Per share:
Basic earnings 1.79 0.28 0.74 0.37 0.41
Diluted earnings 1.79 0.28 0.73 0.37 0.41
Dividends declared 1.08 0.27 0.27 0.27 0.27
Common stock prices:
High 29 5/8 29 5/8 27 3/8 29 1/4 28 15/16
Low 21 5/8 23 13/16 22 7/8 22 3/8 21 5/8
Close 26 3/16 26 3/16 24 5/16 26 3/4 22 1/4
- ----------------------------------------------------------------------

89

- --------------------------------------------------------------------------------
Selected Financial and Operating Data: 1996-2000

Dollars in millions, except
per share amounts 2000 1999 1998 1997 1996
- ------------------------------------------------------------------------------

Edison International and
Subsidiaries
Operating revenue $ 11,717 $ 9,696 $ 8,860 $ 9,235 $ 8,545
Operating expenses $ 13,446 $ 7,942 $ 7,076 $ 7,200 $ 6,503
Net income (loss) $ (1,943) $ 623 $ 668 $ 700 $ 717
Weighted-average shares of
common stock outstanding (in
millions) 333 348 359 400 437
Per share data:
Basic earnings (loss) $ (5.84) $ 1.79 $ 1.86 $ 1.75 $ 1.64
Diluted earnings (loss) $ (5.84) $ 1.79 $ 1.84 $ 1.73 $ 1.63
Dividends paid $ 1.11 $ 1.07 $ 1.03 $ 1.00 $ 1.00
Dividends declared $ 0.84 $ 1.08 $ 1.04 $ 1.00 $ 1.00
Book value at year-end $ 7.43 $ 15.01 $ 14.55 $ 14.71 $ 15.07
Market value at year-end $ 15 5/8 $ 26 3/16 $ 27 7/8 $ 27 3/16 $ 19 7/8
Dividend payout ratio (paid) N/A 59.8% 55.4% 57.1% 61.0%
Rate of return on common
equity (41.0)% 12.2% 12.8% 11.7% 11.1%
Price/earnings ratio (2.7) 14.6 15.0 15.5 12.1
Ratio of earnings to fixed
charges (.87) 1.85 2.33 2.41 2.42
Assets $ 35,100 $ 36,229 $ 24,698 $ 25,101 $ 24,559
Long-term debt $ 12,150 $ 13,391 $ 8,008 $ 8,871 $ 7,475
Common shareholders' equity $ 2,420 $ 5,211 $ 5,099 $ 5,527 $ 6,397
Preferred stock subject to
mandatory redemption $ 256 $ 256 $ 256 $ 275 $ 275
Company-obligated mandatorily
redeemable securities of
subsidiaries holding solely
parent company debentures $ 949 $ 948 $ 150 $ 150 $ 150
Retained earnings $ 599 $ 3,079 $ 2,906 $ 3,176 $ 3,753

- ------------------------------------------------------------------------------

Southern California Edison
Company
Operating revenue $ 7,870 $ 7,548 $ 7,499 $ 7,953 $ 7,583
Net income (loss) available
for common stock $ (2,050) $ 484 $ 490 $ 576 $ 621
Basic earnings (loss) per
Edison International
common share $ (6.16) $ 1.39 $ 1.37 $ 1.44 $ 1.42
Rate of return on common
equity (67.6)% 15.2% 13.3% 11.6% 12.1%
Peak demand in megawatts (MW) 19,757 19,122 19,935 19,118 18,207
Generation capacity at peak
(MW) 10,191 10,474 10,546 21,511 21,602
Kilowatt-hour sales (in
millions) 83,436 78,602 76,595 77,234 75,572
Customers (in millions) 4.29 4.36 4.27 4.25 4.22
Full-time employees 12,593 13,040 13,177 12,642 12,057

- ------------------------------------------------------------------------------

Edison Mission Energy
Revenue $ 3,253 $ 1,642 $ 894 $ 975 $ 844
Net income $ 125 $ 130 $ 132 $ 115 $ 92
Assets $ 15,017 $ 15,534 $ 5,158 $ 4,985 $ 5,153
Rate of return on common
equity 4.3% 8.1% 14.8% 12.2% 8.8%
Ownership in operating
projects (MW) 22,759 22,037 5,153 5,180 4,706
Full-time employees 3,391 3,245 1,180 1,140 940

- ------------------------------------------------------------------------------

Edison Capital
Revenue $ 274 $ 282 $ 235 $ 138 $ 49
Net income $ 135 $ 129 $ 105 $ 61 $ 41
Assets $ 3,713 $ 2,712 $ 2,276 $ 1,783 $ 1,423
Rate of return on common
equity 22.9% 27.0% 30.2% 23.2% 17.7%
Full-time employees 119 115 85 85 70

90

- --------------------------------------------------------------------------------
Board of Directors* Edison International

John E. Bryson /1/**
Chairman of the Board, President and Chief Executive Officer, Edison
International
A director since 1990

Warren Christopher /1/,/4/
Senior Partner,
O'Melveny & Myers,
Los Angeles, California
A director since 1971+

Stephen E. Frank /1/***
Chairman of the Board,
President and Chief Executive Officer, Southern California Edison Company
A director since 1995

Joan C. Hanley /2/,/4/
The Former General Partner and Manager, Miramonte Vineyards,
Rancho Palos Verdes, California
A director since 1980

Carl F. Huntsinger /1/,/4/,/5/
General Partner, DAE Limited Partnership, Ltd.,
Ojai, California
A director since 1983

Charles D. Miller /3/,/4/,/5/
Retired Chairman of the Board,
Avery Dennison Corporation,
Pasadena, California
A director since 1987

Luis G. Nogales /2/,/3/
President, Nogales Partners,
Los Angeles, California
A director since 1993

Ronald L. Olson /1/,/2/,/4/
Senior Partner,
Munger, Tolles and Olson,
Los Angeles, California
A director since 1995

James M. Rosser /1/,/2/,/3/
President, California State University, Los Angeles,
Los Angeles, California
A director since 1985

Robert H. Smith /3/,/5/
Managing Director,
Smith and Crowley Incorporated,
Pasadena, California
A director since 1987

Thomas C. Sutton /2/,/3/,/5/
Chairman of the Board and
Chief Executive Officer,
Pacific Life Insurance Company,
Newport Beach, California
A director since 1995

Daniel M. Tellep /2/,/5/
Retired Chairman of the Board,
Lockheed Martin Corporation,
Bethesda, Maryland
A director since 1992

Edward Zapanta, M.D. /1/,/3/,/5/
Physician and Neurosurgeon,
Torrance, California
A director since 1984
/1/Executive Committee
/2/Finance Committee
/3/Compensation and Executive Personnel Committee
/4/Nominating Committee
/5/Audit Committee

* Service includes combined Edison International and Southern California
Edison Company Board memberships
** Edison International Board and Executive Committee only
*** Southern California Edison Company Executive Committee only

+ 8/19/71 to 1/20/77
6/18/81 to 1/19/93
5/15/97 to present

91

- -------------------------------------------------------------------------------
Management Team Edison International

EDISON INTERNATIONAL

John E. Bryson
Chairman of the Board, President and Chief Executive Officer

Bryant C. Danner
Executive Vice President and
General Counsel

Theodore F. Craver, Jr.
Senior Vice President,
Chief Financial Officer and
Treasurer

Robert G. Foster
Senior Vice President,
External Affairs

Mahvash Yazdi
Senior Vice President and
Chief Information Officer

Jo Ann Goddard
Vice President, Investor Relations

Thomas M. Noonan
Vice President and Controller

Pedro J. Pizarro
Vice President,
Technology Business Development

Joseph P. Ruiz
Vice President and General Auditor

Beverly P. Ryder
Vice President, Community Involvement, and Secretary

Andrea L. Simpson
Vice President,
Corporate Communications

Anthony L. Smith
Vice President, Tax

SOUTHERN CALIFORNIA EDISON COMPANY

Stephen E. Frank
Chairman of the Board, President and Chief Executive Officer

Harold B. Ray
Executive Vice President,
Generation Business Unit

Pamela A. Bass
Senior Vice President,
Customer Service Business Unit

John R. Fielder
Senior Vice President,
Regulatory Policy and Affairs

Robert G. Foster
Senior Vice President, External Affairs

Richard M. Rosenblum
Senior Vice President, Transmission
and Distribution Business Unit

Mahvash Yazdi
Senior Vice President and
Chief Information Officer

Emiko Banfield
Vice President, Shared Services

Robert C. Boada
Vice President and Treasurer

Clarence Brown
Vice President, Corporate Communications

Bruce C. Foster
Vice President, San Francisco Regulatory Operations

A.L. Grant
Vice President, Engineering and Technical Services

Lawrence D. Hamlin
Vice President, Power Production

Harry B. Hutchison
Vice President, Mass Customers

James A. Kelly
Vice President,
Regulatory Compliance

Russell W. Krieger
Vice President,
Nuclear Generation

J. Michael Mendez
Vice President, Labor Relations

Thomas M. Noonan
Vice President and Controller

Dwight E. Nunn
Vice President,
Nuclear Engineering and
Technical Services

Stephen E. Pickett
Vice President and
General Counsel

Frank J. Quevedo
Vice President,
Equal Opportunity

Joseph P. Ruiz
Vice President and General Auditor

W. James Scilacci
Vice President and
Chief Financial Officer

Dale E. Shull, Jr.
Vice President, Power Delivery

Anthony L. Smith
Vice President, Tax

David Ned Smith
Vice President,
Major Customers

Joseph J. Wambold
Vice President, Nuclear Business and Support Services

Beverly P. Ryder
Secretary

EDISON MISSION ENERGY

John E. Bryson
Chairman of the Board

Alan J. Fohrer
President and
Chief Executive Officer

Robert M. Edgell
Executive Vice President

William J. Heller
Senior Vice President

Ronald L. Litzinger
Senior Vice President

Georgia R. Nelson
Senior Vice President

Kevin M. Smith
Senior Vice President and
Chief Financial Officer

Raymond W. Vickers
Senior Vice President and
General Counsel

Paul D. Jacob
President, Edison Mission
Marketing and Trading

EDISON CAPITAL

John E. Bryson
Chairman of the Board

Thomas R. McDaniel
President and
Chief Executive Officer

Ashraf T. Dajani
Senior Vice President

Richard E. Lucey
Senior Vice President and
Chief Financial Officer

Larry C. Mount
Senior Vice President,
General Counsel and Secretary

EDISON ENTERPRISES

Theodore F. Craver, Jr.
Chairman of the Board and
Chief Executive Officer

92

Shareholder Information
- --------------------------------------------------------------------------------
Annual Meeting

The annual meeting of shareholders will be held on Monday, May 14, 2001, at
1:30 p.m., at the DoubleTree Hotel, 222 N. Vineyard Avenue, Ontario,
California.
- --------------------------------------------------------------------------------
Stock Listing and Trading Information

Edison International Common Stock
The New York and Pacific stock exchanges use the ticker symbol EIX; daily
newspapers list the stock as EdisonInt.

Preferred Securities and Preferred Stock
Edison International's preferred securities are listed on the New York Stock
Exchange under the ticker symbols EIX prA for 7.875% QUIPS Series A and EIX prB
for the 8.60% Series B. Previous day's closing prices, when traded, are listed
in the daily newspapers in the New York Stock Exchange composite table. Southern
California Edison Company's series of preferred stocks -- 4.08%, 4.24%, 4.32%
and 4.78% -- are listed on the American and Pacific stock exchanges under the
ticker symbol SCE. Previous day's closing prices, when traded, are listed in the
daily newspapers in the American Stock Exchange composite table. The 6.05%,
6.45% and 7.23% series are not listed; however, the 6.45% and 7.23% series are
traded over-the-counter. The preferred securities of Mission Capital, an
affiliate of Edison Mission Energy, are listed on the New York Stock Exchange
under the ticker symbol MEPrA for the 9.875% series and MEPrB for the 8.50%
series.
- --------------------------------------------------------------------------------
Transfer Agent and Registrar

Wells Fargo Bank Minnesota, N.A., maintains shareholder records and is the
transfer agent and registrar for Edison International common stock and Southern
California Edison Company's preferred stocks. Shareholders may call Wells Fargo
Shareowner Services (800) 347-8625, between 7 a.m. and 7 p.m. (Central Time),
Monday through Friday, regarding:

o stock transfer and name-change requirements;

o address changes, including dividend addresses;

o electronic deposit of dividends;

o taxpayer identification number submission or changes;

o duplicate 1099 and W-9 forms;

o notices of, and replacement of, lost or destroyed stock certificates and
dividend checks;

o direct debit of optional cash for dividend reinvestment;

o Edison International's Dividend Reinvestment and Stock Purchase Plan,
including enrollments, withdrawals, terminations, transfers, sales,
duplicate statements; and

o requests for access to online account information.

Inquiries may also be directed to:

Mail E-mail
Wells Fargo Bank Minnesota, N.A. stocktransfer@wellsfargo.com
Shareowner Services Department
161 North Concord Exchange Street Web Address
South St. Paul, MN 55075-1139 www.edisoninvestor.com

Fax
(651) 450-4033

- --------------------------------------------------------------------------------
Dividend Reinvestment and Electronic Transfer

Shareholders can purchase additional common shares by reinvesting their
quarterly dividends when paid. A prospectus for Edison International's Dividend
Reinvestment and Stock Purchase Plan is available from Wells Fargo Shareowner
Services.

Dividend checks can be electronically deposited directly to your financial
institution. Enrollment forms are available upon request.

EXHIBIT 21

EDISON INTERNATIONAL TIER LIST

[Numbers on left are Dun & Bradstreet tier level indicators]

HOLDING COMPANY

00 EDISON INTERNATIONAL is a corporation organized under the laws of the
State of California and having its principal place of business at 2244
Walnut Grove Avenue (P.O. Box 999), Rosemead, California 91770. It was
organized principally to acquire and hold securities of other
corporations for investment purposes. Edison International has the
following subsidiaries:

UTILITY SUBSIDIARIES

01 SOUTHERN CALIFORNIA EDISON COMPANY ("SCE") is a California corporation
having its principal place of business at 2244 Walnut Grove Avenue (P.O.
Box 800), Rosemead, California 91770. SCE is a public utility primarily
engaged in the business of supplying electric energy to portions of
central and southern California, excluding the City of Los Angeles and
certain other cities. Unless otherwise indicated, its subsidiaries have
the same principal place of business as Southern California Edison
Company:

02 CALIFORNIA ELECTRIC POWER COMPANY is an inactive California
corporation that remains from a 1964 merger with SCE.

02 CONSERVATION FINANCING CORPORATION is a California
corporation engaged in the remediation and mitigation of
environmental liabilities.

02 EDISON ESI is a California corporation engaged in the business of
marketing services, products, information, and copyrighted materials
to third parties on behalf of SCE.

02 EDISON MATERIAL SUPPLY LLC is a Delaware limited liability company
that provides procurement, inventory and warehousing services.

02 MONO POWER COMPANY is an inactive California corporation that has been
engaged in the business of exploring for and developing fuel
resources.

03 The Bear Creek Uranium Company is an inactive California
partnership between Mono Power Company (50%) and Union Pacific
Resources (50%) that has been engaged in reclamation of an
integrated uranium mining and milling complex in Wyoming.

02 SCE CAPITAL COMPANY is an inactive Delaware corporation
that acted as a financing vehicle for SCE.

02 SCE FUNDING LLC is a Delaware limited liability company that acts as a
financing vehicle for rate reduction bonds.

02 SCE TRUST I is a Delaware business trust organized to act
as a financing vehicle.

02 SCE TRUST II is a Delaware business trust organized to act
as a financing vehicle.

1

02 SCE UK SERVICES LTD is a United Kingdom private limited company having
its registered office at Lansdowne House, Berkeley Square, London,
England W1X 5DH, which provides auditing services for affiliated
companies.

02 SOUTHERN STATES REALTY is a California corporation engaged
in holding real estate assets for SCE.

NONUTILITY SUBSIDIARIES

01 EDISON DRIVES ELECTRIC is a California corporation having its principal
place of business at 2244 Walnut Grove Avenue, Rosemead, California
91770, which is engaged in administering a vehicle lease program for
Edison International employees.

01 EDISON INSURANCE SERVICES, INC., is a Hawaii corporation having its
principal executive office at 1099 Alakea Street, 22nd Floor, Honolulu,
Hawaii 96813, which provides domestic and foreign property damage and
business interruption insurance to Edison International and its
subsidiaries.

01 EDISON VENTURES is a California corporation having its principal place of
business at 2244 Walnut Grove Avenue, Rosemead, California 91770, which
owns the stock and coordinates the activities of its nonutility
subsidiaries. The subsidiaries of Edison Ventures are as follows:

02 EDISON TRANSENERGY is a California corporation having its principal
place of business at 2244 Walnut Grove Avenue, Rosemead, California
91770, which is engaged in pipeline development activities to
transport crude oil.

01 EIX TRUST I is a Delaware business trust that acts as a
financing vehicle.

01 EIX TRUST II is a Delaware business trust that acts as a
financing vehicle.

01 EIX TRUST III is a Delaware business trust organized to
act as a financing vehicle.

01 THE MISSION GROUP is a California corporation having its principal place
of business at 2244 Walnut Grove Avenue, Rosemead, California 91770,
which owns the stock and coordinates the activities of nonutility
companies. The subsidiaries of The Mission Group are as follows:

02 EDISON O&M SERVICES is a California corporation having its principal
place of business at 955 Overland Court, San Dimas, CA 91772, that
provides generation operation and maintenance services.

02 EDISON TECHNOLOGY SOLUTIONS ("ETS") is a California corporation having
its principal place of business at 2244 Walnut Grove Avenue, Rosemead,
California 91770, which was organized to engage in technology
development and commercialization, and which is currently inactive.
The subsidiaries of Edison Technology Solutions are as follows:

03 EDISON EV is a California corporation having its
principal place of business at 2244 Walnut Grove Avenue,
Rosemead, California 91770, which was engaged in the
business of providing electric vehicle charging
infrastructure, and which is currently inactive.

2

03 FACILICHEM, INC., is a California corporation having
its principal place of business at 333 Ravenswood Avenue,
Menlo Park, California 94025, which was organized to
engage in the research, development and commercialization
of liquid membrane technologies for application in
specific industrial and chemical processes. ETS has a
10% ownership interest with an option to increase that
interest to 16.66%

02 EDISON ENVIRONMENTAL SERVICES is a California corporation having its
principal place of business at 2244 Walnut Grove Avenue, Rosemead,
California 91770, which was organized to provide nuclear
decommissioning services, and which is currently inactive.

02 EDISON ENTERPRISES is a California corporation having its principal
place of business at 955 Overland Court, San Dimas, California 91773,
which owns the stock and coordinates the activities of its nonutility
subsidiaries. The subsidiaries of Edison Enterprises are as follows:

03 EDISON SOURCE is a California corporation having its
principal place of business at 800 East Orangethorpe
Avenue, Anaheim, California 92801. It is engaged in the
business of integrated energy services.

04 EDISON SOURCE NORVIK COMPANY is a Canadian company having its
principal place of business at 1959 Upper Water Street, Suite
800, Halifax, NS B3J 2X2. It is engaged in the business of
providing rapid battery charging technology for the electric
fork lift market.

04 G.H.V. REFRIGERATION, INC. is a California corporation
having its principal place of business at 800 East
Orangethorpe Avenue, Anaheim, California 92801. It is
engaged in the business of providing refrigeration/HVAC
operations, maintenance and installations throughout
Southern California and Arizona.

03 EDISON SELECT is a California corporation having its
principal place of business at 955 Overland Court, San
Dimas, Califonia 91773. It is engaged in the business of
providing consumer products and services.

04 EDISON HOME PROTECTION COMPANY (Inactive)

04 SELECT HOME WARRANTY COMPANY (Inactive)

04 EDISON SECURITY CORP. [formerly WESTEC RESIDENTIAL
SECURITY, INC.] is a Delaware corporation having its
principal place of business at 955 Overland Court, San
Dimas, California 91773. It is engaged in the business
of providing home security services.

04 VALLEY BURGLAR & FIRE ALARM CO., INC. is a California
corporation having its principal place of business
at 955 Overland Court, San Dimas, California 91773.
It is engaged in the business of providing home security
services.

03 EDISON UTILITY SERVICES is a California corporation having its
principal place of business at 955 Overland Court, San Dimas,
California 91773. It is engaged in the business of providing
services including billing and transmission and distribution
outsourcing.

3

02 EDISON CAPITAL is a California corporation having its principal place
of business at 18101 Von Karman Avenue, Suite 1700, Irvine, California
92612-1046. It is engaged in the business of leveraged-leasing
transactions and other project financings, either directly or through
subsidiaries. Edison Capital owns a group of subsidiaries and has
interests in various partnerships through its subsidiaries. The
subsidiaries and partnerships of Edison Capital are listed below.
Unless otherwise indicated, all entities are corporations, are
organized under the laws of the State of California, and have the same
principal place of business as Edison Capital.

03 BURLINGTON APARTMENTS, INC.
03 EDISON CAPITAL EUROPE LIMITED (UK corporation)
Address: Lansdowne House, Berkeley Square, London, England
W1X 5DH
03 EDISON CAPITAL VENTURES
03 EDISON FUNDING COMPANY
[directly owns 0.08% of Edison Funding Omicron Incorporated;
see listing under Edison Housing Consolidation Company)
04 EDISON CAPITAL HOUSING INVESTMENTS
[directly owns 0.35% of Edison Housing Consolidation Co.;
see listing under MHICAL 95 Company.]
[directly owns 35.52% of Edison Funding Omicron Incorporated;
see listing under Edison Housing Consolidation Co.]
05 1st Time Homebuyer Opportunities LP (Chester County
Homes) 99%
05 1732 Champa LP (Buerger Brothers Lofts) 99%
05 18303 Kittridge Associates LP 99%
05 210 Washington Avenue Associates (Renaissance Plaza)
(Connecticut partnership) 99%
05 2400 Locust Associates LP (Locust on the Park) 99%
05 Aaron Michael Associates LP 99.9%
05 Abajo Del Sol LP 99.9%
05 Argyle Redevelopment Partnership, Ltd. (Colorado
partnership) 99%
05 Auburn Manor L.L.C. 50%
05 Baldwin Village LP 99.9%
05 Bartlett Hill Associates LP 99%
05 Bouquet Canyon Seniors LP 99%
05 CCS/Bellingham LP (Washington Grocery Building) 99%
05 CCS/Mount Vernon Housing LP (La Venture) 99%
05 Cincinatti Ravenwood Apartments LP 99%
05 Conejo Valley Community Housing Associates (Community
House Apartments) 99%
05 Diamond Creek Apartments LP 99.9%
05 EAST COAST CAPITAL, INC. (Massachusetts corporation)
Address: 240 Commercial Street, Boston, MA 02109-1336
05 EC ASSET SERVICES, INC. (Massachusetts corporation)
Address: 240 Commercial Street, Boston, MA 02109-1336
05 EC PROPERTIES, INC. (Massachusetts corporation)
Address: 240 Commercial Street, Boston, MA 02109-1336
06 Corporations for Affordable Housing LP 1%GP
07 Arbor Lane Associates Phase II LP (Timberwood) 99%
07 Arroyo Vista Associates LP 99%
07 Artloft Associates LP 35.6%
07 Caleb Affordable Housing Associates LP
(Ledges/Pinebrook) 99%
07 The Carlin LP 99%
07 Diamond Phase III Venture LP 99%
07 Fairmont Hotel Urban Renewal Associates LP 99%
07 Mackenzie Park Associates LP 99%
07 Parkside Associates LP (Parkside Garden) 99%

4

07 Pines Housing LP 99%
07 Pines Housing II, LP 99%
07 Smyrna Gardens Associates LP 99%
07 Tioga Gardens LP 99%
07 Walden Pond, LP (Hamlet) 99%
06 Corporations for Affordable Housing LP II 1%GP
07 2601 North Broad Street Associates LP (Station
House) 99%
07 Artloft Associates LP 53.39%
07 Brookline Housing Associates LLC (Bridgewater) 99%
07 EDA LP (Eagle's Nest) 99%
07 Edgewood Manor Associates II LP 99%
07 Gateway Housing LP (Gateway Townhomes) 99%
07 Homestead Village Associates LP 99%
07 Junction City Apartments LP (Green Park) 99%
07 Liberty House Associates LP 99%
07 Maple Ridge Development Associates LP 99%
07 Parsonage Cottage Senior Residence LP 99%
07 Rittenhouse School LP 99%
07 Silver City Housing LP 99%
07 South 55th Street, LP 99%
07 W. M. Housing Associates LP (Williamsport Manor) 99%
07 Winnsboro Apartments LP (Deer Wood) 99%
05 EC PROPERTIES III, INC. (Massachusetts corporation)
Address: 240 Commercial Street, Boston, MA 02109-1336
06 Corporations for Affordable Housing LP III 1%GP
07 Piedmont Housing Associates 99%
07 Pines Housing III 99%
07 Salem Lafayette Urban Renewal Associates, LP 99%
07 Spring Valley Commons LP 99%
07 Stevenson Housing Associates (Park Vista) 99%
05 EC-SLP, INC. (Massachusetts corporation)
Address: 240 Commercial Street, Boston, MA 02109-1336
05 ECHI-A COMPANY
05 ECHI-B COMPANY
05 ECHI Wyvernwood, Inc. [dead project]
05 ECH/HFC GP Partnership No. 1 34.9%GP
06 Edison Capital Housing Partners VII LP 19.4%GP
07 C-Court LP (Cawelti Court) 99%
07 Cottonwood Affordable Housing LP 99%
07 Fifth & Wilshire Apartments LP 99%
07 Flagstaff Affordable Housing II, LP (Forest View
Apts.) 99%
07 Huff Avenue Associates LP 99%
07 Mountain View Townhomes Associates LP 99%
07 Oak Forest Associates LP 99%
07 Paradise Road Partners LP (Gateway Village) 99%
07 Woodland Arms Apartments, Ltd. 99%
05 ECH/HFC GP Partnership No. 2 56.7%GP
06 Edison Capital Housing Partners VIII LP 18.54%GP
07 Catalonia Associates LP 99%
07 Ohlone Housing Associates LP 99%
05 EDISON CAPITAL AFFORDABLE HOUSING 97 V
05 EDISON CAPITAL AFFORDABLE HOUSING 97 VI
05 EDISON CAPITAL AFFORDABLE HOUSING 97 VII
05 EDISON CAPITAL AFFORDABLE HOUSING 97 VIII
05 EDISON CAPITAL AFFORDABLE HOUSING 99A COMPANY
05 Edison Capital Affordable Housing 99A G.P. 27.69%GP
06 Edison Capital Housing Partners IX LP 13.5533%GP
07 1010 SVN Associates LP 99.9%
07 2814 Fifth Street Associates LP (Land Park
Woods) 99%
07 Alma Place Associates LP 99%
07 Knolls Community Associates LP 99.9%
07 Monterra Village Associates LP 99%
07 Pacific Terrace Associates LP 99.9%

5

07 PVA LP (Park Victoria) 99%
07 Sherman Glen, L.L.C. 99%
07 Strobridge Housing Associates LP 99%
07 Trolley Terrace Townhomes LP 99.9%
07 Walnut Avenue Partnership LP 99%
05 EDISON CAPITAL AFFORDABLE HOUSING 99B COMPANY 99.99%
05 Edison Capital Affordable Housing 99B G.P. 99.99%GP
06 Edison Capital Housing Partners X LP 19.3952%GP
07 Beacon Manor Associates LP 99.9%
07 Boulder Creek Apartments LP 99.9%
07 Burlington Senior Housing LLC 99.9%
07 CCS/Renton Housing LP (Renton) 99.9%
07 Coolidge Station Apartments L.L.C. 99%
07 Lark Ellen LP 99%
07 Mercy Housing California IX LP (Sycamore) 99.9%
07 Morgan Hill Ranch Housing LP 99%
07 Pacifica Community Associates LP (Villa
Pacifica) 99.9%
07 Persimmon Associates LP 99%
07 Providence-Brown Street Housing LP (Brown
Street) 99.9%
07 San Juan Commons 1996 LP 99.9%
07 Timber Sound, Ltd. 99%
07 Timber Sound II, Ltd. 99%
07 Trinity Park Apartments LP 99.9%
07 Venbury Trail LP 99.9%
06 Edison Capital Housing Partners XI LP 18.62486%GP
07 1475 167th Avenue Associates LP (Bermuda Gardens)
99.9%
07 Auburn Manor Apartments LP 99.9%
07 Barnsdall Court LP (Villa Mariposa) 99%
07 Borregas Court LP 99%
07 Bryson Family Apartments LP 99.9%
07 Carson Housing LP 98%
07 Casa Rampart LP (Rampart Apartments) 98.9%
07 Davis MHA Twin Pines Community Associates LP
(Northstar Apartments) 99%
07 Eastwood Homes LP 99%
07 Electra Arms Senior Associates LP 99%
07 Grace Housing LP 99%
07 Stony Point Apartment Investors LP (Panas Place)
99.9%
07 Wall Street Palmer House LP 99%
07 Wilmington Housing Associates LP (New Harbor
Vista) 99.9%
06 Edison Capital Housing Partners XII LP 13.73759%GP
07 Cedarshores Limited Dividend Housing Association
LP 98.99%
07 Heritage Partners LP 99%
07 Osage Terrace LP 99.89%
07 West Oaks Apartments LP 99.9%
07 Yale Street LP 99.9%
06 Edison Capital Housing Partners XIII LP 17.03513%GP
07 Alhambra Apartments LP 99.9%
07 Chamber Apartments LP 99%
07 Park Land Senior Apartments Investors LP (Banducci)
99.9%
07 President John Adams Manor Apartments LP 99.9%
07 Riverwalk Apartments, Ltd. (Colorado) 99%
07 Rosecreek Senior Living LP 99.9%
07 Twin Ponds Apartments LP 99.9%
07 Woodleaf Village LP 98.99%
07 Women's Westlake LP (Dorothy Day) 99%

7

06 Edison Capital Housing Partners XIV LP 7.61%GP
07 Apollo Development Associates LP (Apollo Hotel) 99.9%
07 Carson Terrace LP 99.9%
07 Don Avante Association II LP (Village Avante) 99.9%
07 Preservation Properties I 99.9%
07 Preservation Properties II 99.9%
07 Preservation Properties III 99.9%
07 Preservation Properties IV 99.9%
07 Preservation Properties V 99.9%
07 Rowland Heights Preservation LP 99.9%
07 Springdale Preservation LP (Springdale West) 99.9%
06 Edison Capital Housing Partners XV LP 9.567%GP
07 708 Pico LP (Wavecrest Apartments) 99.9%
07 Benton Green LP 99.9%
07 Don Avante Association I LP (Don de Dios) 99.9%
07 Emmanuel Grant Company LLC (Capitol Heights) 99.9%
07 Highland Village Partners LP 99.9%
07 I.G. Partners LP (Islands Gardens) 99.9%
07 Karen Partners LP 99.9%
07 Lilac Estates LP 99.9%
07 Mountainlands Housing Partners LP (Holiday
Village Apartments) 99.9%
07 NAHF Brockton LP (Southfield Gardens) 99.9%
07 Northern Senior Housing LP (St. Johnsbury) 99.9%
07 Park Place 1998, LLC 99.9%
07 Park Williams Partners LP 99.9%
07 Patriots Pointe at Colonial Hills LP 99.9%
07 PlumTree Preservation LP 99.9%
07 Poinsettia Housing Associates 99.9%
07 Project Home I LLC 99.99%
07 Saratoga Vacaville LP (Saratoga Senior) 99.9%
07 Serena Sunbow LP (Villa Serena) 99.9%
07 St. Regis Park LP (Pear Tree) 99.9%
07 Vista Sonoma Senior Living LP 99.9%
07 Westfair LLC (Cedar Ridge) 99.9%
07 Windrush Apartments of Statesville LP 99.9%
07 Wingate LLC (Regency Park) 99.9%
05 Edison Capital Contributions VI Partners 91.77%GP
06 ECH Investor Partners VI-A LP 15.39%GP
07 Edison Capital Housing Partners VI LP 61.82%GP
08 Admiralty Heights Associates II 1995 LP (Kent
Manor) 99%
08 Affordable/Citrus Glenn Phase II, Ltd. (Citrus
Glenn Apts. Phase II) 99%
08 Altamont Hotel Associates LP 99%
08 Bradley Manor Senior Apartments LP 99%
08 Double X Associates 1995 LP (Terrace Manor) 99%
08 Hamilton Place Apartments LP (Larkin Place) 99%
08 Hamilton Place Senior Living LP 99%

8

08 Hearthstone Group 3 LP (Evergreen Court) 99%
08 KDF Malabar LP 99%
08 LINC-Bristol Associates I, LP (City Gardens) 99%
08 MAS-WT, LP (Washington Terrace) 99%
08 Northwood Manor Associates LP 99%
08 Silver Lake Properties LP 99%
08 University Park Properties LP 99%
08 Upland Senior Housing LP (Coy D. Estes) 99%
08 Vista Properties LLC (Vista View) 99%
08 Vista Verde Townhomes II LLC 99%
06 ECH Investor Partners VI-B LP 15.39%GP
07 Edison Capital Housing Partners VI LP 37.18%GP
08 Admiralty Heights Associates II 1995 LP (Kent
Manor) 99%
08 Affordable/Citrus Glenn Phase II, Ltd. (Citrus
Glenn Apts. Phase II) 99%
08 Altamont Hotel Associates LP 99%
08 Bradley Manor Senior Apartments LP 99%
08 Double X Associates 1995 LP (Terrace Manor) 99%
08 Hamilton Place Apartments LP (Larkin Place) 99%
08 Hamilton Place Senior Living LP 99%
08 Hearthstone Group 3 LP (Evergreen Court) 99%
08 KDF Malabar LP 99%
08 LINC-Bristol Associates I, LP (City Gardens) 99%
08 MAS-WT, LP (Washington Terrace) 99%
08 Northwood Manor Associates LP 99%
08 Silver Lake Properties LP 99%
08 University Park Properties LP 99%
08 Upland Senior Housing LP (Coy D. Estes) 99%
08 Vista Properties LLC (Vista View) 99%
08 Vista Verde Townhomes II LLC 99%
05 EDISON CAPITAL HOUSING DELAWARE, INC.
06 B.A.I. Edison Ravenwood LP (Ravenwood) 90%GP
07 Cincinatti Ravenwood Apartments LP 0.95%GP
05 Edison Capital Housing Partners V LP 16.38%GP
06 AMCAL Santa Barbara Fund XXXVI LP (Positano) 99%
06 Bodega Hills Investors LP 99%
06 Mercy Housing California IV LP (Vista Grande) 99%
06 Park Place Terrace LP 99%
06 River Walk Apartments Homes LP 99%
06 San Diego Golden Villa Partners LP (Golden Villa) 99%
06 Santa Alicia Gardens Townhomes LP (The Gardens) 99%
06 St. Hedwig's Gardens LP 99%
06 Sunshine Terrace LP 99%
06 Union Meadows Associates LLC 99%
05 EDISON CAPITAL HOUSING FLORIDA
05 EDISON CAPITAL HOUSING MANAGEMENT
06 JOHN STEWART COMPANY
Address: 1388 Sutter Street, 11th Floor, San
Francisco, CA 94109
07 2814 Fifth Street Associates LP (Land Park
Woods) 0.5%GP
07 381 Turk Street LP 1%GP
07 Community Investment LP (Oak Village Apartments)
1%GP
07 Crescent Manor Associates LP 2.85%GP
07 Del Norte Place LP 18%GP
07 Jackie Robinson Apartments LP 1.67%GP
07 Larkspur Isle LP 0.5%GP
07 Las Casitas LP 0.5%GP
07 Mason Street Enterprises LP 1%GP
07 Mountain View Apartments LP 0.26%GP
07 Piper Court G.P. 50%GP
07 Shiloh Arms LP 1%GP/9.8%LP
07 St. John's LP 1%GP/19.6%LP
07 The IBEX Group 10%GP
07 Village East Apartments LP 3%GP
07 Woodhaven Senior Residences LP 1%GP
05 EDISON CAPITAL HOUSING NEW JERSEY
[owns 6.16% of Edison Housing Consolidation Co.; see
listing under MHICAL 95 Company.]
05 EDISON CAPITAL HOUSING NEW YORK
06 WPA/Edison LLC (Pier A) 99%
05 EDISON CAPITAL HOUSING PENNSYLVANIA
[owns 5.26% of Edison Housing Consolidation Co.; see
listing under MHICAL 95 Company.]
05 EDISON HOUSING NORTH CAROLINA
06 Edison Capital Contributions VI Partners 4.03%
07 ECH Investor Partners VI-A LP 15.39%GP
08 Edison Capital Housing Partners VI LP 61.82%GP
09 Admiralty Heights Associates II 1995 LP (Kent
Manor) 99%
09 Affordable/Citrus Glenn Phase II, Ltd. (Citrus
Glenn Apts. Phase II) 99%

9

09 Altamont Hotel Associates LP 99%
09 Bradley Manor Senior Apartments LP 99%
09 Double X Associates 1995 LP (Terrace Manor) 99%
09 Hamilton Place Apartments LP (Larkin Place) 99%
09 Hamilton Place Senior Living LP 99%
09 Hearthstone Group 3 LP (Evergreen Court) 99%
09 KDF Malabar LP 99%
09 LINC-Bristol Associates I, LP (City Gardens) 99%
09 MAS-WT, LP (Washington Terrace) 99%
09 Northwood Manor Associates LP 99%
09 Silver Lake Properties LP 99%
09 University Park Properties LP 99%
09 Upland Senior Housing LP (Coy D. Estes) 99%
09 Vista Properties LLC (Vista View) 99%
09 Vista Verde Townhomes II LLC 99%
07 ECH Investor Partners VI-B LP 15.39%GP
08 Edison Capital Housing Partners VI LP 37.18%GP
09 Admiralty Heights Associates II 1995 LP (Kent
Manor) 99%
09 Affordable/Citrus Glenn Phase II, Ltd. (Citrus
Glenn Apts. Phase II) 99%
09 Altamont Hotel Associates LP 99%
09 Bradley Manor Senior Apartments LP 99%
09 Double X Associates 1995 LP (Terrace Manor) 99%
09 Hamilton Place Apartments LP (Larkin Place) 99%
09 Hamilton Place Senior Living LP 99%
09 Hearthstone Group 3 LP (Evergreen Court) 99%
09 KDF Malabar LP 99%
09 LINC-Bristol Associates I, LP (City Gardens) 99%
09 MAS-WT, LP (Washington Terrace) 99%
09 Northwood Manor Associates LP 99%
09 Silver Lake Properties LP 99%
09 University Park Properties LP 99%
09 Upland Senior Housing LP (Coy D. Estes) 99%
09 Vista Properties LLC (Vista View) 99%
09 Vista Verde Townhomes II LLC 99%
05 EDISON HOUSING OREGON, INC.
05 EDISON HOUSING SOUTH CAROLINA
06 Edison Capital Contributions VI Partners 4.20%
07 ECH Investor Partners VI-A LP 15.39%GP
08 Edison Capital Housing Partners VI LP 61.82%GP
09 Admiralty Heights Associates II 1995 LP (Kent
Manor) 99%
09 Affordable/Citrus Glenn Phase II, Ltd. (Citrus
Glenn Apts. Phase II) 99%
09 Altamont Hotel Associates LP 99%
09 Bradley Manor Senior Apartments LP 99%
09 Double X Associates 1995 LP (Terrace Manor) 99%
09 Hamilton Place Apartments LP (Larkin Place) 99%
09 Hamilton Place Senior Living LP 99%
09 Hearthstone Group 3 LP (Evergreen Court) 99%
09 KDF Malabar LP 99%
09 LINC-Bristol Associates I, LP (City Gardens) 99%
09 MAS-WT, LP (Washington Terrace) 99%
09 Northwood Manor Associates LP 99%
09 Silver Lake Properties LP 99%
09 University Park Properties LP 99%
09 Upland Senior Housing LP (Coy D. Estes) 99%
09 Vista Properties LLC (Vista View) 99%
09 Vista Verde Townhomes II LLC 99%
07 ECH Investor Partners VI-B LP 15.39%GP
08 Edison Capital Housing Partners VI LP 37.18%GP
09 Admiralty Heights Associates II 1995 LP (Kent
Manor) 99%
09 Affordable/Citrus Glenn Phase II, Ltd. (Citrus
Glenn Apts. Phase II) 99%
09 Altamont Hotel Associates LP 99%
09 Bradley Manor Senior Apartments LP 99%
09 Double X Associates 1995 LP (Terrace Manor) 99%

10

09 Hamilton Place Apartments LP (Larkin Place) 99%
09 Hamilton Place Senior Living LP 99%
09 Hearthstone Group 3 LP (Evergreen Court) 99%
09 KDF Malabar LP 99%
09 LINC-Bristol Associates I, LP (City Gardens) 99%
09 MAS-WT, LP (Washington Terrace) 99%
09 Northwood Manor Associates LP 99%
09 Silver Lake Properties LP 99%
09 University Park Properties LP 99%
09 Upland Senior Housing LP (Coy D. Estes) 99%
09 Vista Properties LLC (Vista View) 99%
09 Vista Verde Townhomes II LLC 99%
05 EHI DEVELOPMENT COMPANY
05 EHI DEVELOPMENT FUND
05 Eugene Hotel LP 99.9%
05 Florence Apartments LLC 99%
05 Harry Clark Jr. Residential Center LLC 99%
05 Hercules Senior Housing Associates 99.9%
05 Hilltop Farms LP 99.9%
05 Hotel Elkhart L.L.C. (The Cornerstone) 99%
05 Josephinum Associates LP, The (Washington ptnrshp) 99%
05 KDF Park Glenn LP (Park Glenn) 99%
05 KDF Park Glenn Seniors LP (Park Glenn II) 99.9%
05 KDF Santa Paula LP (Santa Paula) 99%
05 Kennedy Lofts Associates LP (Massachusetts ptnrshp) 99%
05 King Road Associates LP 99.9%
05 LL Housing LP (Maryland partnership) (Laurel Lakes) 99%
05 LL Housing L.L.C. 24.5%
05 Lovejoy Station LP 99.9%
05 Madison/Mollison LP (Park Mollison) 99%
05 Maplewood Housing Associates LP 99.9%
05 MH I LP 1%GP
06 California Park Apartments LP 99%
05 MH II LP 1%GP
06 5363 Dent Avenue Associates LP 99%
05 MH III LP 1%GP
06 DeRose Housing Associates LP 99%
05 MH IV LP 1%GP
06 MPT Apartments LP (MacArthur Park) 99%
05 MH V LP 1%GP
06 Centennial Place LP 99%
05 MHICAL 94 COMPANY
[owns 19.32% of Edison Housing Consolidation Co.; see
listing under MHICAL 95 Company.]
05 MHICAL 94 LP (Delaware partnership) 1%GP
06 Mayacamas Village Associates LP 99%
06 Rincon De Los Esteros Associates LP 99%
06 West Capital Courtyard LP 99%
06 Winfield Hill Associates LP 99%
05 MHICAL 95 LP (Delaware partnership) 1%GP
06 Abby Associates LP (Windmere) 99%
06 Antelope Associates LP 99%
06 Baker Park Associates LP 99%
06 Bracher Associates LP 99%
06 Colina Vista LP 99%
06 Florin Woods Associates LP 99%
06 Mercy Housing California VI LP (205 Jones) 99%
06 Pinmore Associates LP 99%
06 Sunset Creek Partners LP 99%
05 MHICAL 96 LP (Delaware partnership) 1%GP
06 Greenway Village Associates LP 99%
06 Kennedy Court Partners LP 99%
06 Klamath Associates LP 99%
06 Sky Parkway Housing Associates LP 99%
06 Westgate Townhomes Associates LP 99%
05 MHICAL 95 COMPANY
06 ECH/HFC GP Partnership No. 2 43.3%

11

07 Edison Capital Housing Partners VIII LP 18.54%GP
08 Catalonia Associates LP 99%
08 Ohlone Housing Associates LP 99%
06 EDISON HOUSING CONSOLIDATION CO. (formerly Edison
Housing Georgia) 29.90%
07 EDISON FUNDING OMICRON INCORPORATED (Delaware corporation)
(formerly Edison Funding Omicron GP) 44.40% [also owned
0.08% by Edison Funding Company, 35.52% by Edison Capital
Housing Investments and 20.00% by The Connell Company, an
outside entity]
08 16th & Church Street Associates LP 99%
08 1856 Wells Court Partners, LP (Wells Court) 99%
08 AE Associates LP (Avenida Espana) 99%
08 Agape Housing LP 99%
08 Anglo Edison LLC No. 1 (Las Brisas) 99%
08 Anglo Edison Ravenwood L.L.C. 99%
08 Brantwood II Associates LP 99%
08 Brooks School Associates LP 99%
08 Bryn Mawr - Belle Shore LP (The) 99%
08 Bush Hotel LP 99%
08 Centertown Associates LP (Ravenwood) 99%
08 Centro Partners LP (El Centro) 99%
08 Cochrane Village Apartments LP 99%
08 Coyote Springs Apartments Associates LP 99%
08 Cypress Cove Associates 99%
08 Del Carlo Court Associates LP 99%
08 Delta Plaza Apartments LP 99%
08 EAH Larkspur Creekside Associates LP 99%
08 East Cotati Avenue Partners LP 99%
08 EDISON FUNDING OLIVE COURT 100%
09 Olive Court Housing Associates LP 0.6%
08 Edmundson Associates LP (Willows) 99%
08 El Barrio Academy Urban Renewal Associates, LP
(Academy Street) 99%
08 Elizabeth West & East LP 99%
08 Farm (The) Associates LP 99%
08 Fremont Building LP (Crescent Arms) 99%
08 Gilroy Redwood Associates LP (Redwoods) 99%
08 Ginzton Associates LP 99%
08 Grossman Apartments Investors LP 99%
08 Heartland-Wisconsin Rapids Timber Trails LLC
(Timber Trails) 99%
08 Heather Glen Associates LP 99%
08 HMB-Atlanta I LP (Spring Branch) 99%
08 Holy Family Associates LP 99%
08 Lackawana Housing Associates LLC (Goodwill
Neighborhood Residences) 99%
08 Maplewood School Apartments LP 99%
08 Mar Associates LP (Frank Mar) 99%
08 McFarland Press Associates LP 99%
08 Mercantile Housing LLC (Mercantile Square) 99%
08 Merrill Road Associates LP 99%
08 MH I LP 99%
09 California Park Apartments LP 99%
08 MHICAL 94 LP (Delaware partnership) 99%LP
09 Mayacamas Village Associates LP 99%
09 Rincon De Los Esteros Associates LP 99%
09 West Capital Courtyard LP 99%
09 Winfield Hill Associates LP 99%
08 MHICAL 95 LP (Delaware partnership) 99%LP
09 Abby Associates LP (Windmere) 99%
09 Antelope Associates LP 99%
09 Baker Park Associates LP 99%
09 Bracher Associates LP 99%

12

09 Colina Vista LP 99%
09 Florin Woods Associates LP 99%
09 Mercy Housing California VI LP (205 Jones) 99%
09 Pinmore Associates LP 99%
09 Sunset Creek Partners LP 99%
08 MHICAL 96 LP (Delaware partnership) 99%LP
09 Greenway Village Associates LP 99%
09 Kennedy Court Partners LP 99%
09 Klamath Associates LP 99%
09 Sky Parkway Housing Associates LP 99%
09 Westgate Townhomes Associates LP 99%
08 Mid-Peninsula Century Village Associates LP
(Century Village) 99%
08 Mission Capp LP 99%
08 Mission Housing Partnership 1996 LP (Delaware
partnership) 99%LP
09 La Terraza Associates LP (Carlsbad Villas at
Camino Real) 99%
08 Neary Lagoon Partners LP 99%
08 North Park Village LLC 99%
08 Oceanside Gardens LP 99%
08 Omaha Amber Ridge LP (Amber Ridge) 99%
08 Open Door Associates LP (West Valley) 99%
08 Palmer House LP 99%
08 Pellettieri Homes Urban Renewal Associates, LP 99%
08 Richmond City Center Associates LP 99%
08 Riverside/Liebrandt Partners LP (La Playa) 99%
08 Roebling Village Inn Urban Renewal LP 99%
08 Rosebloom Associates LP (Oakshade) 99%
08 San Pablo Senior Housing Associates LP 99%
08 San Pedro Gardens Associates LP 99%
08 Santa Paulan Senior Apartments Associates LP
(The Paulan) 99%
08 South Beach Housing Associates LP (Steamboat)
99%
08 South Winery Associates LP (The Winery
Apartments) 99%
08 Stoney Creek Associates LP 99%
08 Studebaker Building LP 99%
08 Sultana Acres Associates LP 99%
08 Thomson Rental Housing, LP (Washington Place) 99%
08 Tuscany Associates LP (Tuscany Villa) 99%
08 Villa Maria Housing LP 99%
08 Washington Creek Associates LP 99%
08 Westport Village Homes Associates LP 99%
08 Wheeler Manor Associates LP 99%
08 YWCA Villa Nueva Partners LP 99%
05 MHICAL 96 COMPANY
[owns 8.96% of Edison Housing Consolidation Co.; see
listing under MHICAL 95 Company.]
06 ECH/HFC GP Partnership No. 1 50.4%
07 Edison Capital Housing Partners VII LP 19.4%GP
08 C-Court LP (Cawelti Court) 99%
08 Cottonwood Affordable Housing LP 99%
08 Fifth & Wilshire Apartments LP 99%
08 Flagstaff Affordable Housing II, LP (Forest
View Apts.) 99%
08 Huff Avenue Associates LP 99%
08 Mountain View Townhomes Associates LP 99%
08 Oak Forest Associates LP 99%
08 Paradise Road Partners LP (Gateway Village) 99%
08 Woodland Arms Apartments, Ltd. 99%
06 Edison Capital Affordable Housing 99A G.P. 36.47%
07 Edison Capital Housing Partners IX LP 13.5533%GP
08 1010 SVN Associates LP 99.9%
08 2814 Fifth Street Associates LP (Land Park
Woods) 99%

13

08 Alma Place Associates LP 99%
08 Knolls Community Associates LP 99.9%
08 Monterra Village Associates LP 99%
08 Pacific Terrace Associates LP 99.9%
08 PVA LP (Park Victoria) 99%
08 Sherman Glen, L.L.C. 99%
08 Strobridge Housing Associates LP 99%
08 Trolley Terrace Townhomes LP 99.9%
08 Walnut Avenue Partnership LP 99%
05 MHICAL 97 COMPANY
06 ECH/HFC GP Partnership No. 1 14.7%
07 Edison Capital Housing Partners VII LP 19.4%GP
08 C-Court LP (Cawelti Court) 99%
08 Cottonwood Affordable Housing LP 99%
08 Fifth & Wilshire Apartments LP 99%
08 Flagstaff Affordable Housing II, LP (Forest
View Apts.) 99%
08 Huff Avenue Associates LP 99%
08 Mountain View Townhomes Associates LP 99%
08 Oak Forest Associates LP 99%
08 Paradise Road Partners LP (Gateway Village) 99%
08 Woodland Arms Apartments, Ltd. 99%
06 Edison Capital Affordable Housing 99A G.P. 33.05%
07 Edison Capital Housing Partners IX LP 13.5533%GP
08 1010 SVN Associates LP 99.9%
08 2814 Fifth Street Associates LP (Land Park
Woods) 99%
08 Alma Place Associates LP 99%
08 Knolls Community Associates LP 99.9%
08 Monterra Village Associates LP 99%
08 Pacific Terrace Associates LP 99.9%
08 PVA LP (Park Victoria) 99%
08 Sherman Glen, L.L.C. 99%
08 Strobridge Housing Associates LP 99%
08 Trolley Terrace Townhomes LP 99.9%
08 Walnut Avenue Partnership LP 99%
06 MHICAL 97 LP 99%LP
07 Garnet Housing Associates LP 99%
05 MHICAL 97 LP 1%GP
06 Garnet Housing Associates LP 99%
05 MHIFED 94 COMPANY
05 MHIFED 94 LP (Delaware partnership) 1%GP; 99%LP to
Bell Atlantic
06 Berry Avenue Associates LP 99%
06 Carlton Way Apartments LP 99%
06 CDR Senior Housing Associates (Casa del Rio) 99%
06 Corona Ely/Ranch Associates LP 99%
06 Fairview Village Associates LP 99%
06 Fell Street Housing Associates LP 99%
06 Hope West Apartments LP 99%
06 Morrone Gardens Associates LP 99%
06 Pajaro Court Associates LP 99%
06 Tierra Linda Associates LP 99%
06 Tlaquepaque Housing Associates LP 99%
05 MHIFED 95 COMPANY
05 MHIFED 95 LP (Delaware partnership) 1%GP; 99%LP to
Bell Atlantic
06 1101 Howard Street Associates LP 99%
06 Avalon Courtyard LP (Carson Senior Housing) 99%
06 Hollywood El Centro LP 99%
06 La Brea/Franklin LP 99%
06 Larkin Pine LP 99%
06 Mercy Housing California III LP (3rd & Reed) 99%
06 Pinole Grove Associates LP 99%
06 Second Street Center LP (Santa Monica) 99%
06 Solinas Village Partners LP 99%
06 Three Oaks Housing LP 99%
05 MHIFED 96 COMPANY
05 MHIFED 96 LP (Delaware partnership) 5%GP; 95%LP to
Cargill

14

06 Lavell Village Associates LP 99%
06 North Town Housing Partners LP (Villa del Norte
Village) 99%
06 Poco Way Associates LP 99%
06 Seasons Affordable Senior Housing LP 99%
05 MHIFED 96A COMPANY
05 MHIFED 96A LP (Delaware partnership) 1%GP; 99%LP to
Bell Atlantic
06 Good Samaritan Associates LP 99%
06 Metro Senior Associates LP 99%
06 Oxnard Housing Associates LP 99%
06 Reseda Village LP 99%
06 Round Walk Village Apartments LP 99%
06 Santa Alicia Family Housing Associates 99%
06 Vine Street Court LP 99%
06 Vine Street Court LP II 99%
05 MHIFED 97 COMPANY
06 MHIFED 97 LP 99%LP
05 MHIFED 97 LP 1%GP
05 Mid-Peninsula Sharmon Palms Associates LP (Sharmon
Palms) 99%
05 MISSION HOUSING ALPHA
06 Lee Park Investors LP (Pennsylvania partnership) 99%
06 Quebec Arms Apartments LP 0.05% GP
06 University Manor Apartment LP 0.05% GP
05 MISSION HOUSING BETA
[owns 2.58% of Edison Housing Consolidation Co.; see
listing under MHICAL 95 Company.]
05 MISSION HOUSING DELTA
[owns 1.07% of Edison Housing Consolidation Co.; see
listing under MHICAL 95 Company.]
06 MH II LP 99%
07 5363 Dent Avenue Associates LP 99%
06 MH III LP 99%
07 DeRose Housing Associates LP 99%
06 MH IV LP 99%
07 MPT Apartments LP (MacArthur Park) 99%
06 MH V LP 99%
07 Centennial Place LP 99%
05 MISSION HOUSING DENVER
[owns 5.67% of Edison Housing Consolidation Co.; see
listing under MHICAL 95 Company.]
05 MISSION HOUSING EPSILON
[owns 0.54% of Edison Housing Consolidation Co.; see
listing under MHICAL 95 Company.]
06 Edison Capital Affordable Housing 99A G.P. 2.78%
07 Edison Capital Housing Partners IX LP 13.5533%GP
08 1010 SVN Associates LP 99.9%
08 2814 Fifth Street Associates LP (Land Park
Woods) 99%
08 Alma Place Associates LP 99%
08 Knolls Community Associates LP 99.9%
08 Monterra Village Associates LP 99%
08 Pacific Terrace Associates LP 99.9%
08 PVA LP (Park Victoria) 99%
08 Sherman Glen, L.L.C. 99%
08 Strobridge Housing Associates LP 99%
08 Trolley Terrace Townhomes LP 99.9%
08 Walnut Avenue Partnership LP 99%
05 MISSION HOUSING GAMMA
[owns 1.73% of Edison Housing Consolidation Co.; see
listing under MHICAL 95 Company.]

15

05 MISSION HOUSING HOLDINGS
[owns 13.10% of Edison Housing Consolidation Co.; see
listing under MHICAL 95 Company.]
05 Mission Housing Partnership 1996 LP (Delaware
partnership) 1%GP
06 La Terraza Associates LP (Carlsbad Villas at Camino
Real) 99%
05 MISSION HOUSING THETA
06 MISSION FUNDING THETA
[owns 0.01% of Edison Housing Consolidation Co.; see
listing under MHICAL 95 Company.]
07 Cedarshores Limited Dividend Housing Association
LP 0.01%
07 Edison Capital Affordable Housing 99A G.P. 0.01%
08 Edison Capital Housing Partners IX LP 13.5533%GP
09 1010 SVN Associates LP 99.9%
09 2814 Fifth Street Associates LP (Land Park
Woods) 99%
09 Alma Place Associates LP 99%
09 Knolls Community Associates LP 99.9%
09 Monterra Village Associates LP 99%
09 Pacific Terrace Associates LP 99.9%
09 PVA LP (Park Victoria) 99%
09 Sherman Glen, L.L.C. 99%
09 Strobridge Housing Associates LP 99%
09 Trolley Terrace Townhomes LP 99.9%
09 Walnut Avenue Partnership LP 99%
07 Edison Capital Affordable Housing 99B G.P. 0.01%
08 Edison Capital Housing Partners X LP 19.3952%GP
09 Beacon Manor Associates LP 99.9%
09 Boulder Creek Apartments LP 99.9%
09 Burlington Senior Housing LLC 99.9%
09 CCS/Renton Housing LP (Renton) 99.9%
09 Coolidge Station Apartments L.L.C. 99%
09 Lark Ellen LP 99%
09 Mercy Housing California IX LP (Sycamore) 99.9%
09 Morgan Hill Ranch Housing LP 99%
09 Pacifica Community Associates LP (Villa
Pacifica) 99.9%
09 Persimmon Associates LP 99%
09 Providence-Brown Street Housing LP (Brown
Street) 99.9%
09 San Juan Commons 1996 LP 99.9%
09 Timber Sound, Ltd. 99%
09 Timber Sound II, Ltd. 99%
09 Trinity Park Apartments LP 99.9%
09 Venbury Trail LP 99.9%
07 Oakdale Terrace Leased Housing Associates LP 0.01%
07 Westfield Condominium Investment LP 0.01%
07 Woodleaf Village LP 0.01%
06 Mission Housing Investors Partnership 5%GP; 95%LP
to GECC
07 1028 Howard Street Associates LP 99%
07 Forest Winds Associates LP 99%
07 Glen Eden Associates LP (A Street) 99%
07 Gray's Meadows Investors LP 99%
07 Prince Bozzuto LP (Fairground Commons) (Maryland
partnership) 99%
07 Rancho Park Associates LP 99%
07 Rustic Gardens Associates LP 99%
07 Sea Ranch Apartments LP 99%
07 Springdale Kresson Associates LP (Jewish Federation)
(New Jersey partnership) 99%
05 MISSION HOUSING ZETA
[owns 5.35% of Edison Housing Consolidation Co.; see
listing under MHICAL 95 Company.]
05 MISSION SA COMPANY

16

05 National Boston Lofts Associates LLLP (Boston Lofts) 99%
05 Oakdale Terrace Leased Housing Associates LP 98.99%
05 OL Hope LP (Olympic Hope) 99.9%
05 Olive Court Apartments LP 98.9%
05 Ontario Senior Housing LP (Ontario Plaza) 99%
05 Parkview Apartments Associates LP (Parkview/Sunburst)
99.9%
05 Pecan Court Associates LP 99%
05 Pilot Grove LP (Massachusetts partnership) 99%
05 Pinewood on Wisconsin Apartments 99%
05 Post Office Plaza LP (Ohio partnership) 99%
05 Quebec Arms Apartments LP 99.9%
05 Red Lake LP #1 99%
05 San Martin de Porres LP 99.9%
05 Schoolhouse Court Housing Associates LP 99%
05 SD Regency Centre LP 99.9%
05 Southern Hotel LP 99.9%
05 Tabor Grand LP (Colorado partnership) 99%
05 Terra Cotta Housing Associates LP 99.9%
05 University Manor Apartments LP 99.9%
05 Virginia Lane LP 99.9%
05 Vista Verde Housing Associates LP 99.9%
05 WGA INVESTORS COMPANY [dead project]
05 West Valley Hart LP (Hart & Alabama) 99.9%
05 Westfield Condominium Investment LP 98.99%
05 White Mountain Apache LP 99%
04 EDISON INTEGRATED ENERGY SERVICES
04 MISSION FIRST ASSET INVESTMENT
04 MISSION FUNDING BETA
04 MISSION FUNDING EPSILON
05 EDISON CAPITAL (BERMUDA) INVESTMENTS, LTD. (Bermuda
corporation)
Address: Clarendon House, 2 Church Street, Hamilton
HM CX, Bermuda
06 Edison Capital LAI (Bermuda) Ltd. (Bermuda corporation)
Address: Clarendon House, 2 Church Street, P.O. Box
HM666, Hamilton HM CX, Bermuda
07 Trinidad and Tobago Methanol Company Limited
(equity) 1.0%
06 Edison Capital Latin American Investments (Bermuda)
Ltd. (Bermuda corporation) 33.3%
Address: Clarendon House, 2 Church Street, P.O. Box
HM666, Hamilton HM CX, Bermuda
07 AIG Asian Infrastructure Fund II LP 5.8%
07 AIG-GE Capital Latin American Infrastructure
Fund LP 8%
07 AIG Emerging Europe Infrastructure Fund LP 18.05%
07 AIG Emerging Europe Infrastructure Management LP
23.6%GP
05 EDISON CAPITAL INTERNATIONAL (BERMUDA) LTD.
Address: Clarendon House, 2 Church Street, P.O. Box
HM666, Hamilton HM CX, Bermuda
06 EDISON CAPITAL INTERNATIONAL TRANSMISSION (BERMUDA)
LTD. (Bermuda corporation) 100%
06 Edison Capital Latin American Investments (Bermuda)
Ltd. (Bermuda corporation) 33.3%
07 AIG Asian Infrastructure Fund II LP 5.8%
07 AIG-GE Capital Latin American Infrastructure Fund
LP 7.89%
08 Andes Energy XII Ltd. 100%
09 Paz Holdings Ltd. 43.22%
10 Compania Adminstradora de Empresas Bolivia
S.A. (Cade) 12.55% (Bolivian service company)
Address: Edificio Electropaz SA, subsuelo
Plaza Venezuela No. 1401 esq. Loayza,
La Paz, Bolivia

17

10 Electricidad de La Paz S.A. (Electropaz)
(equity) 10% (Bolivian foreign utility
company) [See 4.EC01]
Address: Avenida Illimani l973, Casilla
10511, La Paz, Bolivia
10 Empresa de Luz y Fuerza Electrica de Oruro
S.A. (Elfeo) 12.55% (Bolivian foreign
utility company) [See 4.EC02]
Address: Junin No. 710, Casilla No. 53,
Oruro, Bolivia
10 Empresa de Servicios Edeser S.A. (Edeser)
12.55% (Bolivian service company)
Address: Iturralde No. 1309, Miraflores,
La Paz, Bolivia
07 AIG Emerging Europe Infrastructure Fund LP 18.05%
07 AIG Emerging Europe Infrastructure Management LP
23.6%GP
06 Lyonnaise Latin America Water Corporation Ltd.
(equity) 25.8%
06 Olmeca Cable Investments Ltd. (Mandeville Mexico,
S.A.) 21.7%
06 Paz Holdings Ltd. 30.42%
07 Compania Adminstradora de Empresas Bolivia S.A.
(Cade) 12.55% (Bolivian service company)
Address: Edificio Electropaz SA, subsuelo Plaza
Venezuela No. 1401 esq. Loayza, La Paz, Bolivia
07 Electricidad de La Paz S.A. (Electropaz)
(equity) 10% (Bolivian foreign utility company)
[See 4.EC01]
Address: Avenida Illimani l973, Casilla 10511,
La Paz, Bolivia
07 Empresa de Luz y Fuerza Electrica de Oruro S.A.
(Elfeo) 12.55% (Bolivian foreign utility company)
[See 4.EC02]
Address: Calle Junin No. 71, Casilla No. 53,
Oruro, Bolivia
07 Empresa de Servicios Edeser S.A. (Edeser) 12.55%
(Bolivian service company)
Address: Iturralde No. 1309, Miraflores, La Paz,
Bolivia
05 Edison Capital Latin American Investments Holding
Company (Delaware corporation)
06 Edison Capital Latin American Investments (Bermuda)
Ltd. (Bermuda corporation) 33.3%
07 AIG Asian Infrastructure Fund II LP 5.8%
07 AIG-GE Capital Latin American Infrastructure Fund
LP 7.89%
07 AIG Emerging Europe Infrastructure Fund LP 18.05%
07 AIG Emerging Europe Infrastructure Management LP
23.6%GP
05 EDISON CAPITAL (NETHERLANDS) HOLDINGS B.V.
Address: Aert van Nesstraat 45, 3012 CA Rotterdm, The
Netherlands
06 EDISON CAPITAL (NETHERLANDS) INVESTMENTS B.V.
Address: Aert van Nesstraat 45, 3012 CA Rotterdm,
The Netherlands
07 Adams Campus Limited (Clarendon College) 25%
07 Barr Castlehill Holdings Limited 22.05%
07 Catchment Highland Limited (Highland Project) 16.67%
07 Covesea Limited (Lossiemouth Project) 16.67%
07 Dumfries and Galloway Royal Infirmary 19.9%
07 Fiddler's Ferry and Ferrybridge Power Plants 33%
07 GH Bodmin (Holdco) Limited 9.8%
07 HpC King's College Hospital (Holdings) Limited 20%
07 Kinnoul House Limited (Perth Project) 25%
07 Morrison Edison Investments Limited 50%
07 Newham Community Healthcare Services NHS Trust 9.8%
07 Road Link (A69) Limited 9.12%
07 St. George's Hospital 80%
07 St. Mary's Wing of Luton and Dunstable Hospital 20.8%

18

07 Summit Holdings (Law) Limited (Law Hospital) 20%
07 Wansbeck General Hospital for the Northumbria
Health Care NHS Trust 19.2%
05 GEM Energy Company (New York partnership) 50%GP
05 MISSION FUNDING ALPHA
06 MISSION FUNDING MU
07 EPZ Mission Funding Mu Trust (equity interest in
foreign utility company) [See 4.EC03]
Address: c/o Wilmington Trust Company, Rodney
Square North, 111 North Market Square, Wilmington,
Delaware 19890-0004
05 MISSION FUNDING DELTA
06 MISSION FUNDING NU
07 EPZ Mission Funding Nu Trust (equity interest in
foreign utility company) [See 4.EC04]
Address: c/o Wilmington Trust Company, Rodney
Square North, 111 North Market Square, Wilmington,
Delaware 19890-0004
05 MISSION INVESTMENTS, INC. (U.S. Virgin Islands corp.)
Address: ABN Trustcompany, Guardian Building,
Havensight, 2nd Floor, St. Thomas, U.S. Virgin Islands
05 MISSION (BERMUDA) INVESTMENTS, LTD. (Bermuda corp.)
Address: Clarendon House, 2 Church Street,
Hamilton HM CX, Bermuda
04 MISSION FUNDING GAMMA
04 MISSION FUNDING KAPPA
05 ABB Funding Partners, LP 14.27%
04 MISSION FUNDING ZETA
05 Huntington LP (New York partnership) 50%
05 Lakota Ridge LLC 75% [See 4.EC05]
Address: c/o Northern Alternative Energy, Inc., 333
Washington Ave North, Suite 402, Minneapolis, MN 55401
05 Shaokatan Hills LLC 75% [See 4.EC06]
Address: c/o Northern Alternative Energy, Inc., 333
Washington Ave North, Suite 402, Minneapolis, MN 55401
05 Woodstock Hills LLC 75% [See 4.EC07]
Address: 191 West Fifth Street, Cottonwood, MN 56229
04 MISSION IOWA WIND COMPANY
05 Storm Lake Power Partners I LLC (99%) [See 4.EC08]
Address: 13000 Jameson Road, Tehachapi, CA 93561
03 EDISON MORTGAGE COMPANY
03 MISSION BARTLETT HILL COMPANY
03 MISSION INTERNATIONAL CAPITAL, INC.
03 RENEWABLE ENERGY CAPITAL COMPANY

02 MISSION LAND COMPANY is a California corporation having its principal
place of business at 18101 Von Karman Avenue, Suite 1700, Irvine,
California 92612-1046. It is engaged, directly and through its
subsidiaries, in the business of owning, managing and selling
industrial parks and other real property investments. The subsidiaries
and partnerships of Mission Land Company are listed below. Unless
otherwise indicated, all entities are corporations, are organized
under the laws of the State of California, and have the same principal
place of business as Mission Land Company.

03 ASSOCIATED SOUTHERN INVESTMENT COMPANY
03 CALABASAS PALATINO, INC. (Inactive)
03 Carol Stream Developers G.P. (Illinois partnership) 60%GP
03 Centrelake Partners, LP (limited partnership) 98%GP
03 IRWINDALE LAND COMPANY (Inactive)
03 MISSION AIRPORT PARK DEVELOPMENT CO.
04 Carol Stream Developers G.P. (Illinois partnership) 40%GP
04 Centrelake Partners, LP (limited partnership) 2%LP
04 Mission Vacaville LP (limited partnership) 1%GP

19

03 MISSION INDUSTRIAL CONSTRUCTORS, INC. (Inactive)
03 Mission-Oceangate 75%GP
03 MISSION/ONTARIO, INC. (Inactive)
03 MISSION SOUTH BAY COMPANY (Inactive)
04 Mission-Oceangate 25%GP
03 MISSION TEXAS PROPERTY HOLDINGS, INC. (Inactive)
03 Mission Vacaville LP (limited partnership) 99%LP

02 MISSION POWER ENGINEERING COMPANY is a California corporation having
its principal place of business at 18101 Von Karman Avenue, Suite
1700, Irvine, California 92612- 1046. It is currently an inactive
company. The subsidiaries of Mission Power Engineering Company are
listed below. Unless otherwise indicated, all entities are
corporations, are organized under the laws of the State of California,
and have the same principal place of business as Mission Power
Engineering Company.

03 ASSOCIATED SOUTHERN ENGINEERING COMPANY (Inactive)

02 EDISON MISSION ENERGY is a California corporation having its principal
place of business at 18101 Von Karman Avenue, Suite 1700, Irvine,
California 92612-1046. Edison Mission Energy owns the stock of a group
of corporations which, primarily through partnerships with
non-affiliated entities, are engaged in the business of developing,
owning, leasing and/or operating cogeneration, geothermal and other
energy or energy-related projects pursuant to the Public Utility
Regulatory Policies Act of 1978. Edison Mission Energy, through wholly
owned subsidiaries, also has ownership interests in a number of
independent power projects in operation or under development that
either have been reviewed by the Commission's staff for compliance
with the Act or are or will be exempt wholesale generators or foreign
utility companies under the Energy Policy Act of 1992. In addition,
some Edison Mission Energy subsidiaries have made fuel-related
investments and a limited number of non-energy related investments.
The subsidiaries and partnerships of Edison Mission Energy are listed
below. Unless otherwise indicated, all entities are corporations, are
organized under the laws of the State of California and have the same
principal place of business as Edison Mission Energy.

EDISON MISSION ENERGY DOMESTIC COMPANIES:
03 AGUILA ENERGY COMPANY (LP)
04 American Bituminous Power Partners, LP (Delaware limited
partnership) 49.5%; 50% with Pleasant Valley
05 American Kiln Partners, LP (Delaware limited partnership)
49.5% of 53%
03 ANACAPA ENERGY COMPANY (GP)
04 Salinas River Cogeneration Company 50%
03 ARROWHEAD ENERGY COMPANY (Inactive)
03 BALBOA ENERGY COMPANY (GP)
04 Smithtown Cogeneration, LP (Delaware partnership) 50%; 100%
w/Kingspark
03 BERGEN POINT ENERGY COMPANY (GP) Company and interests
sold December 2000
04 TEVCO/Mission Bayonne Partnership (Delaware G.P.) 50%
05 Cogen Technologies NJ Ventures (Delaware G.P.) 0.75%
03 BLUE RIDGE ENERGY COMPANY (GP)
04 Bretton Woods Cogeneration, LP (Delaware limited partnership)
50%; 100% w/Bretton Woods

20

03 BRETTON WOODS ENERGY COMPANY (GP & LP)
04 Bretton Woods Cogeneration, LP (Delaware LP) 50%; 100%
w/Blue Ridge
03 CAMINO ENERGY COMPANY (GP)
04 Watson Cogeneration Company (general partnership) 49%
04 CPC Cogeneration LLC (Delaware LLC) 49%
03 CAPISTRANO COGENERATION COMPANY (GP)
04 James River Cogeneration Company (North Carolina
partnership) 50%
03 CENTERPORT ENERGY COMPANY (GP & LP)
04 Riverhead Cogeneration I, LP (Delaware partnership) 50%;
100% w/ Ridgecrest
03 CHESAPEAKE BAY ENERGY COMPANY (GP)
04 Delaware Clean Energy Project (Delaware general
partnership) 50%
03 CHESTER ENERGY COMPANY (no partners; option Chesapeake,VA)
03 CLAYVILLE ENERGY COMPANY
04 Oconee Energy, LP (Delaware LP) 50%; 100% w/Coronado
03 COLONIAL ENERGY COMPANY (Inactive)
03 CORONADO ENERGY COMPANY
04 Oconee Energy, LP (Delaware LP) 50%; 100% w/Clayville
03 CRESCENT VALLEY ENERGY COMPANY (Inactive)
03 DEL MAR ENERGY COMPANY (GP)
04 Mid-Set Cogeneration Company 50%
03 DELAWARE ENERGY CONSERVERS, INC. (Delaware corporation)
(Inactive)
03 DESERT SUNRISE ENERGY COMPANY (Nevada corporation) (Inactive)
03 DEVEREAUX ENERGY COMPANY (LP)
04 Auburndale Power Partners, LP (Delaware LP) 49%LP; 50%
w/ El Dorado [See 4.EME01] [07/06/2000 Calpine acquired the
remaining 50% from EME]
03 EASTERN SIERRA ENERGY COMPANY (GP & LP)
04 Saguaro Power Company, LP 50%
03 EAST MAINE ENERGY COMPANY (Inactive) [dissolving]
03 EDISON ALABAMA GENERATING COMPANY
03 EDISON MISSION DEVELOPMENT, INC. (Delaware corporation) 100%
03 EDISON MISSION ENERGY FUEL
04 EDISON MISSION ENERGY OIL & GAS
05 Four Star Oil & Gas Company 35.84%
04 EDISON MISSION ENERGY PETROLEUM
04 POCONO FUELS COMPANY (Inactive)
04 SOUTHERN SIERRA GAS COMPANY
05 TM Star Fuel Company (general partnership) 50%
03 EDISON MISSION ENERGY FUNDING CORP. (Delaware corporation) 1%
03 EDISON MISSION ENERGY GLOBAL MANAGEMENT, INC. (Delaware
corporation) [Corporation dissolved 12/21/2000]
04 MAJESTIC ENERGY LIMITED (UK private limited company)
Address: Lansdowne House, Berkeley Square, London
W1X 5DH England [owned directly by EME--Tier 3]
05 EME ROYALE (New Zealand private limited company)
Address: Lansdowne House, Berkeley Square, London
W1X 5DH England [Tier 4]
06 EDISON MISSION ENERGY TAUPO LIMITED (New Zealand
company) 100% [Tier 5]
Address: Southgate Complex, Level 20, HWT Tower, 40
City Road, South Melbourne, 3205 Victoria, Australia
03 Edison Mission Energy Interface Ltd. (British Columbia Co.)
Address: 2 Sheppard Ave. E. #200, North York, Ontario, Canada
04 The Mission Interface Partnership (Province of Ontario
G.P.) 50%
03 EDISON MISSION ENERGY SERVICES, INC. [formerly EDISON MISSION
ENERGY FUEL SERVICES, INC.] [PowerGen project]
03 EDISON MISSION FUEL RESOURCES, INC. [Com Ed Project
03 EDISON MISSION FUEL TRANSPORTATION, INC. [Com Ed Project]
03 EDISON MISSION MARKETING & TRADING, INC. [Com Ed Project]

21

04 CP POWER SALES FIVE, L.L.C.
04 CP POWER SALES THIRTEEN, L.L.C.
04 CP POWER SALES FOURTEEN, L.L.C.
04 CP POWER SALES FIFTEEN, L.L.C.
04 CP POWER SALES SEVENTEEN, L.L.C.
04 CP POWER SALES EIGHTEEN, L.L.C.
04 CP POWER SALES NINETEEN, L.L.C.
04 CP POWER SALES TWENTY, L.L.C.
03 EDISON MISSION HOLDINGS CO. (formerly EME Homer City
Holdings Co.)
04 CHESTNUT RIDGE ENERGY COMPANY 100%
05 EME HOMER CITY GENERATION LP (Pennsylvania) 99%LP
[See 4.EME06]
Address: 1750 Power Plant Road, Homer City,
PA 15748-8009
04 EDISON MISSION FINANCE CO. 100%
04 HOMER CITY PROPERTY HOLDINGS, INC. 100%
04 MISSION ENERGY WESTSIDE, INC. 100%
05 EME HOMER CITY GENERATION LP (Pennsylvania) 1%GP
[See 4.EME06]
Address: 1750 Power Plant Road, Homer City,
PA 15748-8009
03 EDISON MISSION OPERATION & MAINTENANCE, INC.
04 Mission Operations de Mexico, S.A. de C.V. 99%
Address: Bosques de Ciruelos No. 304 2 Piso, Colonia
Bosques de las Lomas, 11700 Mexico Distrito Federal
03 EDISON MISSION PROJECT CO. (formerly EME UK
International, Inc.) (Delaware corp) 100% [holds 100% of
the issued and outstanding Class D shares of MEC International
B.V. (0.01%)--see INTERNATIONAL section]
03 EL DORADO ENERGY COMPANY (GP)
04 Auburndale Power Partners, LP (Delaware LP) 1%GP; 50% w/ Devereaux
[See 4.EME01] [07/06/2000 Calpine acquired the remaining 50% from EME]
03 EME EASTERN HOLDINGS CO.
ATHENS FUNDING, L.L.C.
04 CITIZENS POWER HOLDINGS ONE, LLC
05 CL POWER SALES ONE, L.L.C. 25%
05 CL POWER SALES TWO, L.L.C. 25%
05 CL POWER SALES SIX, L.L.C. 25%
05 CL POWER SALES SEVEN, L.L.C. 25%
05 CL POWER SALES EIGHT, L.L.C. 25%
05 CL POWER SALES NINE, L.L.C. 25%
05 CL POWER SALES TEN, L.L.C. 25%
04 CP POWER SALES TWELVE, L.L.C.
03 EMP, INC. (Oregon corporation) (GP & LP) (Inactive)
03 FOUR COUNTIES GAS COMPANY (Inactive)
03 GLOBAL POWER INVESTORS, INC.
03 HANOVER ENERGY COMPANY
04 CHICKAHOMINY RIVER ENERGY CORPORATION (Virginia
corporation) (GP & LP)
05 Commonwealth Atlantic LP (Delaware partnership)
50% [See 4.EME03]
Address: 2837 South Military Highway, Chesapeake,
VA 23323-0286
03 HOLTSVILLE ENERGY COMPANY (GP & LP)
04 Brookhaven Cogeneration, LP (Delaware partnership) 50%;
100% w/ Madera
03 INDIAN BAY ENERGY COMPANY (GP & LP)
04 Riverhead Cogeneration III, LP (Delaware partnership) 50%;
100% w/ Santa Ana
03 JEFFERSON ENERGY COMPANY (GP & LP) (Inactive)
03 KINGS CANYON ENERGY COMPANY (Inactive)
03 KINGSPARK ENERGY COMPANY (GP & LP)
04 Smithtown Cogeneration, LP (Delaware partnership) 50%;
100% w/ Balboa

22

03 LAGUNA ENERGY COMPANY (Inactive) (former interest in Ambit)
03 LA JOLLAN ENERGY COMPANY (Inactive) (used for Belridge)
03 LAKEVIEW ENERGY COMPANY
04 Georgia Peaker, LP (Delaware LP) 50%; 100% w/Silver Springs
03 LEHIGH RIVER ENERGY COMPANY (Inactive)
03 LONGVIEW COGENERATION COMPANY (held for Weyerhauser)
03 MADERA ENERGY COMPANY (GP)
04 Brookhaven Cogeneration, LP (Delaware partnership) 50%;
100% w/ Holtsville
03 MADISON ENERGY COMPANY (LP)
04 Gordonsville Energy, LP (Delaware partnership) 49%;
50% w/ Rapidan [See 4.EME04]
Address: 115 Red Hill Road, Gordonsville, VA 22942
03 MIDWEST GENERATION EME, LLC (Delaware LLC) 100%
Address: One Financial Place, 400 South LaSalle Street,
Suite 3410, Chicago, Illinois 60605
04 COLLINS HOLDINGS EME, LLC
Address: One Financial Place, 400 South LaSalle Street,
Suite 3410, Chicago, Illinois 60605
04 EDISON MISSION MIDWEST HOLDINGS CO. 100%
Address: One Financial Place, 400 South LaSalle Street,
Suite 3410, Chicago, Illinois 60605
05 EDISON MISSION ENERGY FUEL SERVICES, LLC
Address: One Financial Place, 440 South LaSalle Street,
Suite 3500, Chicago, Illinois 60605
05 EDISON MISSION OVERSEAS CO. (Com Ed project) 100%
Address: One Financial Place, 400 South LaSalle Street,
Suite 3410, Chicago, Illinois 60605
06 EDISON MISSION OVERSEAS LTD. (Com Ed project) 100%
Address: One Financial Place, 400 South LaSalle
Street, Suite 3410, Chicago, Illinois 60605
05 MIDWEST GENERATION, LLC (Com Ed project) 100% [See 4.EME07]
Address: One Financial Place, 400 South LaSalle Street,
Suite 3410, Chicago, Illinois 60605
03 MIDWEST PEAKER HOLDINGS, INC. (Delaware corporation) 100%
03 Mission Capital, LP (Delaware LP) 3%; MIPS partnership
03 MISSION DEL CIELO, INC. 100%
04 Mission Del Sol, LLC (Delaware LLC) 100%
05 Sunrise Power Company 100% [EWG]
03 MISSION/EAGLE ENERGY COMPANY (Inactive)
03 MISSION ENERGY CONSTRUCTION SERVICES, INC. (Provided services for
construction Paiton Project)
03 MISSION ENERGY GENERATION, INC. (Inactive)
03 MISSION ENERGY HOLDINGS, INC.
04 Mission Capital, LP (Delaware LP) 97%; MIPS partnership
03 MISSION ENERGY HOLDINGS INTERNATIONAL, INC. [holds 100% of the
issued and outstanding Class A shares of MEC International B.V.
(99.97%)--see INTERNATIONAL section]
04 EME INVESTMENTS, LLC (Delaware LLC) 100% [Contact Energy Acq.]
04 EME SOUTHWEST POWER CORPORATION (Delaware corp) 100% [holds 100%
of the issued and outstanding Class C shares of MEC International
B.V. (0.01%)--see INTERNATIONAL section]
04 EME UK INTERNATIONAL LLC (Delaware LLC) 100% [holds 100% of
the issued and outstanding Class B stock of MEC International
B.V. (0.01%)--see INTERNATIONAL section]
03 MISSION ENERGY INDONESIA (Inactive)
03 MISSION ENERGY MEXICO (Inactive) formerly the branch office in
Mexico (no partnership)
03 MISSION ENERGY NEW YORK, INC. (GP & LP)
04 Brooklyn Navy Yard Cogeneration Partners, LP (Delaware
partnership) 50% [See 4.EME02]
Address: Flushing Avenue, Cumberland Street, Building 41,
Brooklyn, NY 11205

23

03 MISSION ENERGY WALES COMPANY
04 Mission Hydro Limited Partnership 30%
Address: Lansdowne House, Berkeley Square, London W1X 5DH
England
05 EME Generation Holdings Limited (UK company) 100%
Address: Lansdowne House, Berkeley Square, London W1X 5DH
England
06 Loyvic Pty Ltd. (Australia company) 100%
Address: Southgate Complex, Level 20, HWT Tower, 40
City Road, South Melbourne, 3205 Victoria, Australia
07 Energy Capital Partnership (Australia partnership) 1%
Address: Southgate Complex, Level 20, HWT Tower, 40
City Road, South Melbourne, 3205 Victoria, Australia
08 Enerloy Pty Ltd. (Australia company) 100%
Address: Southgate Complex, Level 20, HWT Tower, 40
City Road, South Melbourne, 3205 Victoria, Australia
06 EME Victoria Generation Limited (UK company) 100%
Address: Lansdowne House, Berkeley Square, London
W1X 5DH England
07 Energy Capital Partnership (Australia partnership 98%
08 Enerloy Pty Ltd. (Australia company) 100%
07 Mission Energy Development Australia Pty Ltd. 100%
Address: Southgate Complex, Level 20, HWT Tower, 40
City Road, South Melbourne, 3205 Victoria, Australia
08 Gippsland Power Pty Ltd 100%
Address: Southgate Complex, Level 20, HWT Tower, 40
City Road, South Melbourne, 3205 Victoria, Australia
09 Loy Yang B Joint Venture 49% [See 4.EME12]
Address: Bartons Lane, Loy Yang, Victoria,
Australia 3844
06 Energy Capital Partnership (Australia partnership) 1%LP
07 Enerloy Pty Ltd. (Australia company) 100%
06 First Hydro Holdings Company (Australia partnership) 99%
Address: Lansdowne House, Berkeley Square, London
W1X 5DH England
07 First Hydro Company 99% [See 4.EME16]
Address: Bala House, St. David's Park, Ewloe,
Dlwyd, Wales CH5 3XJ
07 First Hydro Finance plc 100%
Address: Lansdowne House, Berkeley Square,
London W1X 5DH England
08 First Hydro Company 1% [See 4.EME16]
Address: Bala House, St. David's Park
Ewloe, Dlwyd, Wales CH5 3XJ
03 Mission Operations de Mexico, S.A. de C.V. 1%
Address: Bosques de Ciruelos No. 304 2 Piso, Colonia
Bosques de las Lomas, 11700 Mexico Distrito Federal
03 MISSION TRIPLE CYCLE SYSTEMS COMPANY (GP)
04 Triple Cycle Partnership (Texas G.P.) 50%
03 NORTH JACKSON ENERGY COMPANY (Inactive)
03 NORTHERN SIERRA ENERGY COMPANY (GP)
04 Sobel Cogeneration Company (general partnership) 50%
03 ORTEGA ENERGY COMPANY
03 PANTHER TIMBER COMPANY (GP)
04 American Kiln Partners, LP (Delaware limited partnership) 2%
03 PARADISE ENERGY COMPANY (Inactive)
03 PLEASANT VALLEY ENERGY COMPANY (GP)
04 American Bituminous Power Partners, LP (Delaware limited
partnership) 0.5%; 50% w/Aguila
05 American Kiln Partners, LP (Delaware Limited
Partnership) 0.5% of 53%
03 PRINCE GEORGE ENERGY COMPANY (LP)
04 Hopewell Cogeneration Limited Partnership (Delaware
limited partnership) 24.75%
04 Hopewell Cogeneration Inc. (Delaware corporation) 25%
05 Hopewell Cogeneration Limited Partnership (Delaware
limited partnership) 1%

24

03 QUARTZ PEAK ENERGY COMPANY (LP)
04 Nevada Sun-Peak LP (Nevada partnership) 50% [See 4.EME08]
Address: 200 South Virginia Street, Reno, NV 89501
03 RAPIDAN ENERGY COMPANY (GP)
04 Gordonsville Energy, LP (Delaware partnership) 1%;
50% w/ Madison [See 4.EME04]
Address: 115 Red Hill Road, Gordonsville, VA 22942
03 REEVES BAY ENERGY COMPANY (GP & LP)
04 North Shore Energy LP (Delaware partnership) 50%; 100%
w/ Santa Clara
05 Northville Energy Corporation (New York corp.) 100%
03 RIDGECREST ENERGY COMPANY (GP)
04 Riverhead Cogeneration I, LP (Delaware partnership) 50%;
100% w/ Centerport
03 RIO ESCONDIDO ENERGY COMPANY
03 RIVERPORT ENERGY COMPANY (GP & LP)
04 Riverhead Cogeneration II, LP (Delaware partnership) 50%;
100% w/ San Pedro
03 SAN GABRIEL ENERGY COMPANY (Inactive)
03 SAN JOAQUIN ENERGY COMPANY (GP)
04 Midway-Sunset Cogeneration Company, LP 50%
03 SAN JUAN ENERGY COMPANY (GP)
04 March Point Cogeneration Company 50%
03 SAN PEDRO ENERGY COMPANY (GP)
04 Riverhead Cogeneration II, LP (Delaware partnership) 50%;
100% w/ Riverport
03 SANTA ANA ENERGY COMPANY (GP)
04 Riverhead Cogeneration III, LP (Delaware partnership) 50%;
100% w/ Indian Bay
03 SANTA CLARA ENERGY COMPANY (GP)
04 North Shore Energy, LP (Delaware partnership) 50%; 100%
w/ Reeves Bay
05 Northville Energy Corporation (New York corp.) 100%
03 SILVERADO ENERGY COMPANY (GP)
04 Coalinga Cogeneration Company 50%
03 SILVER SPRINGS ENERGY COMPANY
04 Georgia Peaker, LP (Delaware limited partnership) 50%;
100% w/ Lakeview
03 SONOMA GEOTHERMAL COMPANY (Inactive)
03 SOUTH COAST ENERGY COMPANY (GP)
04 Harbor Cogeneration Company 30% [See 4.EME05]
Address: 420 Henry Ford Avenue, Wilmington, CA 93210
03 SOUTHERN SIERRA ENERGY COMPANY (GP)
04 Kern River Cogeneration Company (general partnership) 50%
03 THOROFARE ENERGY COMPANY (Inactive)
03 VIEJO ENERGY COMPANY (GP)
04 Sargent Canyon Cogeneration Company 50%
03 VISTA ENERGY COMPANY (New Jersey corporation) (Inactive)
03 WESTERN SIERRA ENERGY COMPANY (GP)
04 Sycamore Cogeneration Company (general partnership) 50%

EDISON MISSION ENERGY INTERNATIONAL COMPANIES:
04 MEC International B.V. (Netherlands corporation) (Holding
Company 99.99% owned by Mission Energy Holdings
International, Inc., a California corp. (owns 100% of
Class A Shares) and 0.01% by EME UK International LLC,
a Delaware LLC (owns 100% of Class B shares)
Address: Apollolaan 15, 1077 AB Amsterdam, The Netherlands
05 Adelaide Ventures Ltd. (Cayman Island company) 100%
Address: Walker House, Mary Street, P.O. Box 265GT,
George Town, Grand Cayman, Cayman Islands
05 Beheer-en Beleggingsmaatschappij Botara B.V. (LYB
Peakers Project) 100%
Address: Croeselaan 18, 3500 GT Utrecht, The Netherlands

25

06 Valley Power Pty Ltd. (proprietary limited Australia
company; LYB Peakers Project)
Address: Southgate Complex, Level 20, HWT Tower, 40
City Road, South Melbourne, 3205 Victoria, Australia
05 Beheer-en Beleggingsmaatschappij Jydeno B.V. (Inactive)
100%
Address: Croeselaan 18, 3500 GT Utrecht, The Netherlands
05 Edison Mission Advantage B.V. 100% (Inactive)
Address: Croeselaan 18, 3500 GT Utrecht, The Netherlands
05 Edison Mission Energy Asia Pte Ltd. (Singapore private
company limited by shares) 100% (EME's Regional Asia
Pacific Headquarters)
Address: 391-B Orchard Road, Ngee Ann City, Tower B,
14th Floor, #14-08/10, Singapore 238874
06 Edison Mission Energy Asia Pacific Pte Ltd. (Singapore
corporation) 100%
Address: 391-B Orchard Road, Ngee Ann City, Tower B,
14th Floor, #14-08/10, Singapore 238874
06 Edison Mission Energy Fuel Company Pte Ltd. (Singapore
corporation) 100%
Address: 391-B Orchard Road, Ngee Ann City, Tower B,
14th Floor, #14-08/10, Singapore 238874
06 Edison Mission Operation & Maintenance Services Pte
Ltd 100%
Address: 391-B Orchard Road, Ngee Ann City, Tower B,
14th Floor, #14-08/10, Singapore 238874
06 P.T. Edison Mission Operation and Maintenance
Indonesia (Indonesian company) 99%
Address: Jl. Gen. A Yani No. 54
Probolinggo, East Java, Indonesia
05 Edison Mission Energy International B.V. (Netherlands
company) 99%
Address: Croeselaan 18, 3500 GT Utrecht, The Netherlands
05 Edison Mission Energy Services B.V. (Netherlands co.) 100%
Address: Croeselaan 18, 3500 GT Utrecht, The Netherlands
05 Edison Mission Millennium B.V. (Netherlands company) 100%
Address: Croeselaan 18, 3500 GT Utrecht, The Netherlands
06 EME Caliraya B.V. (formerly Beheer-en Beleggingsmaatschappij
Trepo B.V. 75%
Address: Apollolaan 15, 1077 AB Amsterdam, The Netherlands
07 CBK Power Company Ltd. (Philippine LP) 49%
[not officially a partner yet]
Address: 1701 One Magnificent Mile Building, San Miguel
Avenue, Ortigas Center, Pasig City, Philippines
06 EME Kayalaan B.V. (formerly Beheer-en Beleggingsmaatschappij
Hagra B.V. 100%
Address: Apollolaan 15, 1077 AB Amsterdam, The Netherlands
07 CBK Power Company Ltd. (Philippine LP) 1%
[not officially a partner yet]
Address: 1701 One Magnificent Mile Building, San Miguel
Avenue, Ortigas Center, Pasig City, Philippines
05 Edison Mission Operation & Maintenance Services B.V.
(Netherlands company) 100%
Address: Croeselaan 18, 3500 GT Utrecht, The Netherlands
06 Edison Mission Operation & Maintenance (Thailand)
Company Limited 100%
Address: 7th Fl. Bubhajit Bldg., 20 North Sathorn
Road, Kwaeng Silom, Khet Bangrak, Bangkok
06 EME Philippines O&M Corporation (Philippines co.) 100%
Address: Unit 1105, Tower One, Ayala Triangle, Ayala
Avenue, Makati City, Philippines
05 Edison Mission Wind Power Italy B.V. (formerly IVPC Energy
5 B.V.) 100%
Address: Apollolaan 15, 1077 AB Amsterdam, The Netherlands
06 Italian Vento Power Corporation 4 S.r.l. (joint venture) 50%
[See 4.EME22]
Address: Via Circumvallazione, 54/h, 83100 Avellino, Italy

26

05 EME Atlantic Holdings Limited (UK company) 100%
Address: Lansdowne House, Berkeley Square, London
W1X 5DH England
06 EME Ascot Limited (UK company) 100% [Contact Energy
Project, 2nd Stage]
Address: Lansdowne House, Berkeley Square, London
W1X 5DH England
07 EME Buckingham Limited (UK company) 100% [Contact
Energy Project, 2nd Stage]
Address: Lansdowne House, Berkeley Square, London
W1X 5DH England
08 EME Precision B.V. (Netherlands company) (formerly
Beheer-en-Beleggingsmaatschappij Pylamo B.V.) 100%
[Contact Energy Project, 2nd Stage]
Address: Croeselaan 18, 3500 GT Utrecht,
The Netherlands
09 EME Universal Holdings (New Zealand company) 100%
[Contact Energy Project, 2nd Stage]
Address: Lansdowne House, Berkeley Square,
London W1X 5DH England
10 EME Pacific Holdings (New Zealand company) 100%
[Contact Energy Project, 2nd Stage]
Address: IBM Centre, 171 Featherston Street,
Wellington, New Zealand
11 Contact Energy Limited (New Zealand company)
(equity) 42.26% [See 4.EME10]
Address: Level 1, Harbor City Tower,
29 Brandon Street, Box 10-742, Wellington,
New Zealand
05 EME Tri Gen B.V. 100%
Address: Croeselaan 18, 3500 GT Utrecht, The Netherlands
06 Tri Energy Company Limited (Thai limited liability
company) (Tri Energy Project) (equity) 25% [See 4.EME14]
Address: Grand, Amarin Tower, 16th Floor, New
Petchburi Road, Ratchathewi, Bangkok 10320 Thailand
05 EME Victoria B.V. 100% (Inactive)
Address: Croeselaan 18, 3500 GT Utrecht, The Netherlands
05 Global Generation B.V. 100%
Address: Apollolaan 15, 1077 AB Amsterdam, The Netherlands
06 Caresale Services Limited (UK LLC) 49%
Address: Lansdowne House, Berkeley Square, London
W1X 5DH England
06 Edison First Power Holdings I (UK LLC) 100% [PowerGen
project]
Address: Lansdowne House, Berkeley Square, London
W1X 5DH England
07 Caresale Services Limited (UK LLC) 51%
Address: Lansdowne House, Berkeley Square, London
W1X 5DH England
07 Edison Mission Marketing and Services Limited (UK
company) 100%
Address: Lansdowne House, Berkeley Square, London
W1X 5DH England
07 EME Finance UK Limited (UK LLC) 100%
Address: Lansdowne House, Berkeley Square, London
W1X 5DH England
07 South Australian Holdings Ltd. 100%
Address: Lansdowne House, Berkeley Square, London
W1X 5DH England
08 Edison Mission Retail Pty Ltd. (Australian co.) 100%
Address: Southgate Complex, Level 20, HWT Tower, 40
City Road, South Melbourne, 3205 Victoria, Australia
08 Edison Mission Utilities Pty. Ltd. (Australian
company) 100%
Address: Southgate Complex, Level 20, HWT Tower, 40
City Road, South Melbourne, 3205 Victoria, Australia

27

08 EME International Dragon Limited (UK) 100%
Address: Lansdowne House, Berkeley Square, London
W1X 5DH England
09 Edison Mission Ausone Pty Ltd. (Australian co.) 100%
Address: Southgate Complex, Level 20, HWT Tower, 40
City Road, South Melbourne, 3205 Victoria, Australia
09 EME Adelaide Energy Ltd. (UK company) 100%
Address: Lansdowne House, Berkeley Square, London
W1X 5DH England
09 EME Monet Ltd. (UK company) 100%
Address: Lansdowne House, Berkeley Square, London
W1X 5DH England
10 Edison Mission De Laide Pty Ltd. (Australian
company) 100%
Address: Southgate Complex, Level 20, HWT Tower,
40 City Road, South Melbourne, 3205 Victoria,
Australia
10 Edison Mission Vendesi Pty Ltd. (Australian
company) 100%
Address: Southgate Complex, Level 20, HWT Tower,
40 City Road, South Melbourne, 3205 Victoria,
Australia
07 Energy Generation Finance PLC (UK) 100%
Address: Lansdowne House, Berkeley Square, London
W1X 5DH England
07 Maplekey Holdings Limited (UK LLC) 100%
Address: Lansdowne House, Berkeley Square, London
W1X 5DH England
08 Maplekey UK Finance Limited (UK company) 100%
Address: Lansdowne House, Berkeley Square, London
W1X 5DH England
09 Maplekey UK Limited (UK LLC) 100%
Address: Lansdowne House, Berkeley Square,
London W1X 5DH England
10 Edison First Power Limited (Guernsey LLC)
100% [See 4.EME17]
Address: Lansdowne House, Berkeley Square,
London W1X 5DH England
06 Redbill Contracts Limited (UK LLC) 100%
Address: Lansdowne House, Berkeley Square, London
W1X 5DH England
05 Hydro Energy B.V. (Netherlands LLC) 10%
Address: Croeselaan 18, 3500 GT Utrecht, The Netherlands
06 Iberica de Energias, S.L. (Spain corp) 96.65%
[See 4.EME18]
Address: Paseo de Gracia 18, Planta 4, 08007,
Barcelona, Spain
07 Electrometalurgica del Ebro, S.L. ("EMESA")
(Spain corporation) 91.32% [See 4.EME19]
Address: Paseo de Gracia 18, Planta 4, 08007,
Barcelona, Spain
08 Monasterio de Rueda, S.L. (Spain) 100%
Address: Paseo de Gracia 18, Planta 4, 08007,
Barcelona, Spain
05 Iberian Hy-Power Amsterdam B.V. (Netherlands LLC) 100%
Address: Strawinskylaan 1725, Amsterdam, NOORD-HOLL
1077 XX
06 EME Desarrello Espana S.L. 100%
Address: Paseo de Gracia 18, 4o. Piso, 08007
Barcelona, Spain
06 Hydro Energy B.V. (Netherlands company) 90%
07 Iberica de Energias, S.L. (Spain corporation)
96.65% [See 4.EME18]
08 Electrometalurgica del Ebro, S.L. ("EMESA")
(Spain corporation) 91.32% [See 4.EME19]
09 Monasterio de Rueda, S.L. (Spain) 100%

28

06 Iberica de Energias, S.L. (Spain corporation) 3.35%
[See 4.EME18]
07 Electrometalurgica del Ebro, S.L. ("EMESA")
(Spain corporation) 91.32% [See 4.EME19]
08 Monasterio de Rueda, S.L. (Spain) 100%
06 Saltos del Porma S.A.
Address: Paseo de Gracia 18, 4o. Piso, 08007
Barcelona, Spain
05 Latrobe Power Pty. Ltd. (Australian corporation) 99%
Address: Southgate Complex, Level 20, HWT Tower, 40
City Road, South Melbourne, 3205 Victoria, Australia
06 Mission Victoria Partnership (Australian partnership)
52.31% (100% w/ Traralgon PPL 46.69% and MEVALP 1%)
07 Latrobe Power Partnership (Australian partnership) 99%
08 Loy Yang B Joint Venture 51% [See 4.EME12]
Address: Bartons Lane, Loy Yang, Victoria,
Australia 3844
05 Loy Yang Holdings Pty Ltd (Australia corporation) 100%
Address: Southgate Complex, Level 20, HWT Tower, 40
City Road, South Melbourne, 3205 Victoria, Australia
06 Edison Mission Energy Holdings Pty Ltd (Australian
corporation) 100%
Address: Southgate Complex, Level 20, HWT Tower, 40
City Road, South Melbourne, 3205 Victoria, Australia
07 Edison Mission Energy Australia Ltd. (Australian
public company) 100%
Address: Southgate Complex, Level 20, HWT Tower, 40
City Road, South Melbourne, 3205 Victoria, Australia
08 Latrobe Power Partnership (Australian ptnrshp) 1%
Address: Southgate Complex, Level 20, HWT Tower,
40 City Road, South Melbourne, 3205 Victoria,
Australia
09 Loy Yang B Joint Venture 51% [See 4.EME12]
07 Edison Mission Energy Australia Pilbara Power Ltd.
(Australia company) 100%
Address: Southgate Complex, Level 20, HWT Tower, 40
City Road, South Melbourne, 3205 Victoria, Australia
07 Edison Mission Operation & Maintenance Kwinana Pty
Ltd. (Australia) 100% (Operator of Kwinana Project)
Address: Southgate Complex, Level 20, HWT Tower, 40
City Road, South Melbourne, 3205 Victoria, Australia
07 Edison Mission Operation & Maintenance Loy Yang Pty
Ltd. (Australian corporation) 100%
Address: P.O. Box 1792, Traralgon, Victoria 3844,
Australia
07 Mission Energy Holdings Superannuation Fund Pty
Ltd. (retirement fund required by Australia law) 100%
07 Mission Energy (Kwinana) Pty Ltd. (Australia) 100%
Address: Southgate Complex, Level 20, HWT Tower, 40
City Road, South Melbourne, 3205 Victoria, Australia
08 Kwinana Power Partnership (Australian G.P.) 1%
Address: Level 23, St. Martins Tower
44 St George's Terrace, Perth WA 6000
09 Perth Power Partnership 70% (Kwinana Project)
[See 4.EME11]
Address: James Court, Kwinana Beach 6167,
Western Australia
06 Latrobe Power Pty. Ltd. (Australian corporation) 1%
07 Mission Victoria Partnership (Australian
partnership) 52.31%
08 Latrobe Power Partnership (Australian ptnrshp) 99%
09 Loy Yang B Joint Venture 51% [See 4.EME12]
06 Mission Energy Ventures Australia Pty. Ltd. (Australian
company) 100%
Address: Southgate Complex, Level 20, HWT Tower, 40
City Road, South Melbourne, 3205 Victoria, Australia

29

07 Mission Victoria Partnership (Australian ptnrshp) 1%
08 Latrobe Power Partnership (Australian ptnrshp) 99%
09 Loy Yang B Joint Venture 51% [See 4.EME12]
06 Traralgon Power Pty. Ltd. (Australian corporation) 1%
Address: Southgate Complex, Level 20, HWT Tower,
40 City Road, South Melbourne, 3205 Victoria, Australia
07 Mission Victoria Partnership (Australian partnership)
46.69%
08 Latrobe Power Partnership (Australian ptnrshp) 99%
09 Loy Yang B Joint Venture 51% [See 4.EME12]
05 MEC Esenyurt B.V. (Netherlands company) (Doga Project) 99%
Address: Croeselaan 18, 3500 GT Utrecht, The Netherlands
06 Doga Enerji Uretim Sanayi ve Ticaret L.S.
(Turkish corp.) (Project company) 80% [See 4.EME23]
Address: Merkez Mahallesi, Birlik Caddesi 11/8,
Esenyurt, Istanbul, Turkey
06 Doga Isi Satis Hizmetleri ve Ticaret L.S. (Turkish
corporation) (Heat company) 80%
Address: Merkez Mahallesi, Birlik Caddesi 11/8,
Esenyurt, Istanbul, Turkey
06 Doga Isletme ve Bakim Ticaret L.S. (Turkish corporation)
(O&M company) 80%
Address: Merkez Mahallesi, Birlik Caddesi 11/8,
Esenyurt, Istanbul, Turkey
05 MEC IES B.V. (Netherlands company) (ISAB Project) 99%
Address: Croeselaan 18, 3500 GT Utrecht, The Netherlands
06 ISAB Energy Services s.r.l. 49% (services co ISAB
Project)
Address: Ex S.S. 114km 146, 96100 Priolo G (SR),
Sicily, Italy
05 MEC India B.V. (Netherlands company) (Jojobera Project) 99%
Address: Croeselaan 18, 3500 GT Utrecht, The Netherlands
06 Edison Mission Energy Power (Mauritius corporation)
(Branch office in India)
Address: Louis Leconte Street, Curepipe, Mauritius
05 MEC Indo Coal B.V. (Netherlands co.) (Adaro Project) 99%
Address: Croeselaan 18, 3500 GT Utrecht, The Netherlands
06 P. T. Adaro Indonesia (equity) 10%
Address: Suite 704, World Trade Centre, Jl. Jend.
Sudirman Kav. 31, Jakarta 12920 Indonesia
05 MEC Indonesia B.V. (Netherlands company) 99%
Address: Croeselaan 18, 3500 GT Utrecht, The Netherlands
06 P. T. Paiton Energy (Indonesia company) (equity)
(Paiton Project) 40% [See 4.EME13]
Address: Jl. Raya Surabaya Situbondo KM 141,
Paiton 67291, Probolinggo, East Java, Indonesia
05 MEC International Holdings B.V. (Netherlands corp) 100%
Address: Croeselaan 18, 3500 GT Utrecht, The Netherlands
06 Edison Mission Energy International B.V. (Netherlands
company) 1%
06 MEC Esenyurt B.V. (Netherlands co.) (Doga Project) 1%
07 Doga Enerji Uretim Sanayi ve Ticaret L.S.
(Turkish corp.) (Project company) 80% [See 4.EME23]
07 Doga Isi Satis Hizmetleri ve Ticaret L.S. (Turkish
corporation) (Heat company) 80%
07 Doga Isletme ve Bakim Ticaret L.S. (Turkish corporation)
(O&M company) 80%
06 MEC IES B.V. (Netherlands company) (ISAB Project) 1%
07 ISAB Energy Services s.r.l. 49%
06 MEC India B.V. (Netherlands company) 1%
07 Edison Mission Energy Power (Mauritius corporation)

30

06 MEC Indo Coal B.V. (Netherlands co.) (Adaro Project) 1%
07 P. T. Adaro Indonesia (equity) 10%
06 MEC Indonesia B.V. (Netherlands company) 1%
07 P. T. Paiton Energy (Indonesia company) (equity)
(Paiton Project) 40% [See 4.EME13]
06 MEC Laguna Power B.V. (Netherlands company) (Thailand
Project) 1%
07 Gulf Power Generation Co. Ltd. (Bangkok corp.) 40%
06 MEC Perth B.V. (Netherlands company) (Kwinana Project) 1%
07 Kwinana Power Partnership (Australian G.P.) 99%
08 Perth Power Partnership 70% (Kwinana Project)
[See 4.EME11]
06 MEC Priolo B.V. (Netherlands company) (ISAB Project) 1%
07 ISAB Energy, s.r.l. (Italian J.V. company) (equity)
1% of 49% (quota, not shares) [See 4.EME21]
06 MEC San Pascual B.V. (Netherlands company) 1%
07 San Pascual Cogeneration Company International B.V. 50%
08 San Pascual Cogeneration Company (Philippines)
Ltd. (San Pascual Project) (equity) 1%GP and 74%LP
07 Morningstar Holdings B.V. (formerly Beheer-en
Beleggingsmaatschappij Vestra B.V.) 50%
06 MEC Sidi Krir B.V. (Netherlands company) 1%
06 MEC Sumatra B.V. (Netherlands company) 1%
06 MEC Wales B.V. (Netherlands Company) 1%
07 Mission Hydro Limited Partnership (UK LP)
08 EME Generation Holdings Limited (UK Co.) 100%
09 Loyvic Pty Ltd. (Australia company) 100%
10 Energy Capital Partnership (Australia
partnership) 1%
11 Enerloy Pty Ltd. (Australia co.) 100%
09 EME Victoria Generation Limited (UK co.) 100%
10 Energy Capital Partnership (Australia
partnership 98%
11 Enerloy Pty Ltd. (Australia company) 100%
10 Mission Energy Development Australia Pty Ltd.
11 Gippsland Power Pty Ltd 100%
12 Loy Yang B Joint Venture 49% [See 4.EME12]
09 Energy Capital Partnership (Australia
partnership) 1%LP
10 Enerloy Pty Ltd. (Australia company) 100%
09 First Hydro Holdings Company (Australia
partnership) 99%
10 First Hydro Company 99% [See 4.EME16]
10 First Hydro Finance plc
11 First Hydro Company 1% [See 4.EME16]
06 Mission Energy Italia s.r.l. 10% (Office in Italy)
Address: via Mar della Cina, 304, 00144 Rome, Italy
06 P.T. Edison Mission Operation and Maintenance
Indonesia (Indonesian company) 1%
Address: Jl. Raya Surabaya Situbondo Km 141, P.O. Box
78, Paiton 67291, Probolinggo, East Java, Indonesia
05 MEC Laguna Power B.V. (Netherlands co) (Malaya Proj) 99%
Address: Croeselaan 18, 3500 GT Utrecht, The Netherlands
06 Gulf Power Generation Co. Ltd. (Bangkok corporation) 40%
Address: 888/101 Mahatun Plaza Tower, 10th Floor,
Ploenchit, Lumphini, Patumwan, Bangkok 10330
05 MEC Perth B.V. (Netherlands co.) (Kwinana Project) 99%
06 Kwinana Power Partnership (Australian G.P.) 99%
Address: Level 23, St. Martins Tower
44 St George's Terrace, Perth WA 6000
07 Perth Power Partnership 70% (Kwinana Project)
[See 4.EME11]
Address: James Court, Kwinana Beach 6167,
Western Australia

31

05 MEC Priolo B.V. (Netherlands co.) (ISAB Project) 99%
Address: Croeselaan 18, 3500 GT Utrecht, The Netherlands
06 ISAB Energy, s.r.l. (Italian J.V. company) (equity)
99% of 49% (quota, not shares) [See 4.EME21]
Address: Corso Gelone No. 103, Siracusa, Sicily, Italy
05 MEC San Pascual B.V. (Netherlands company) 99%
Address: Croeselaan 18, 3521 CB Utrecht, The Netherlands
06 San Pascual Cogeneration Company International B.V. 50%
Address: Croeselaan 18, 3521 CB Utrecht, The Netherlands
07 San Pascual Cogeneration Company (Philippines) Ltd
(San Pascual Project) (equity) 1%GP and 74%LP
Address: Unit 1610/1611, Tower One, Ayala Triangle,
Ayala Ave, 1200 Makati City, Metro Manila, Philippines
06 Morningstar Holdings B.V. (formerly Beheer-en
Beleggingsmaatschappij Vestra B.V.) 50%
Address: Croeselaan 18, 3521 CB Utrecht, The Netherlands
05 MEC Sidi Krir B.V. (Netherlands company) 99%
Address: Croeselaan 18, 3500 GT Utrecht, The Netherlands
05 MEC Sumatra B.V. (Netherlands company) 99%
Address: Croeselaan 18, 3500 GT Utrecht, The Netherlands
05 MEC Wales B.V. (Netherlands company) 99%
Address: Croeselaan 18, 3500 GT Utrecht, The Netherlands
06 Mission Hydro Limited Partnership 69%
Address: Lansdowne House, Berkeley Square,
London, England W1X 5DH
07 EME Generation Holdings Limited (UK company) 100%
Address: Lansdowne House, Berkeley Square, London
W1X 5DH England
08 Loyvic Pty Ltd. (Australia company) 100%
Address: Southgate Complex, Level 20, HWT Tower, 40
City Road, South Melbourne, 3205 Victoria, Australia
09 Energy Capital Partnership (Australia ptnrshp) 1%
Address: Southgate Complex, Level 20, HWT Tower,
40 City Road, South Melbourne, 3205 Victoria,
Australia
10 Enerloy Pty Ltd. (Australia company) 100%
Address: Southgate Complex, Level 20, HWT
Tower, 40 City Road, South Melbourne, 3205
Victoria, Australia
08 EME Victoria Generation Limited (UK company) 100%
Address: Lansdowne House, Berkeley Square, London
W1X 5DH England
09 Energy Capital Partnership (Australia ptnrshp 98%
10 Enerloy Pty Ltd. (Australia company) 100%
09 Mission Energy Development Australia Pty Ltd. 100%
Address: Southgate Complex, Level 20, HWT Tower,
40 City Road, South Melbourne, 3205 Victoria,
Australia
10 Gippsland Power Pty Ltd 100%
Address: Southgate Complex, Level 20, HWT
Tower, 40 City Road, South Melbourne, 3205
Victoria, Australia
11 Loy Yang B Joint Venture 49% [See 4.EME12]
Address: Bartons Lane, Loy Yang, Victoria,
Australia 3844
08 Energy Capital Partnership (Australia ptnrshp) 1%LP
09 Enerloy Pty Ltd. (Australia company) 100%

32

08 First Hydro Holdings Company (Australia ptnrshp) 99%
Address: Lansdowne House, Berkeley Square,
London W1X 5DH England
09 First Hydro Company 99% [See 4.EME16]
Address: Bala House, St. David's Park
Ewloe, Dlwyd, Wales CH5 3XJ
09 First Hydro Finance plc 100%
Address: Lansdowne House, Berkeley Square,
London W1X 5DH England
10 First Hydro Company 1% [See 4.EME16]
Address: Bala House, St. David's Park
Ewloe, Dlwyd, Wales CH5 3XJ
05 Mission Energy Company (UK) Limited (United Kingdom
private limited company) 100%
Address: Lansdowne House, Berkeley Square,
London W1X 5DH England
06 Derwent Cogeneration Limited (United Kingdom private
limited liability company) (equity) 33% [See 4.EME15]
Address: Lansdowne House, Berkeley Square,
London W1X 5DH England
06 Edison Mission Energy Limited (UK private limited
company) 100%
Address: Lansdowne House, Berkeley Square,
London W1X 5DH England
06 Edison Mission Operation & Maintenance Limited (a
United Kingdom corporation) 100%
Address: Lansdowne House, Berkeley Square,
London W1X 5DH England
06 Edison Mission Services Limited (UK private limited
company) 100%
Address: Lansdowne House, Berkeley Square,
London W1X 5DH England
06 Mission Hydro (UK) Limited 100%
Address: Lansdowne House, Berkeley Square,
London W1X 5DH England
07 First Hydro Holdings Company 1%
08 First Hydro Company 99% [See 4.EME16]
08 First Hydro Finance plc 100%
09 First Hydro Company 1% [See 4.EME16]
07 Mission Hydro Limited Partnership 1%GP
08 EME Generation Holdings Limited (UK co.) 100%
09 Loyvic Pty Ltd. (Australia company) 100%
10 Energy Capital Partnership (Australia
partnership) 1%
11 Enerloy Pty Ltd. (Australia co.) 100%
09 EME Victoria Generation Limited (UK co.) 100%
10 Energy Capital Partnership (Australia
partnership 98%
11 Enerloy Pty Ltd. (Australia co.) 100%
10 Mission Energy Development Australia
Pty Ltd.
11 Gippsland Power Pty Ltd 100%
12 Loy Yang B Joint Venture 49%
[See 4.EME12]
09 Energy Capital Partnership (Australia
partnership) 1%LP
10 Enerloy Pty Ltd. (Australia company) 100%
09 First Hydro Holdings Company (Australia
partnership) 99%
10 First Hydro Company 99% [See 4.EME16]
10 First Hydro Finance plc 99%
11 First Hydro Company 1% [See 4.EME16]
06 Pride Hold Limited (United Kingdom corp.) 99%
Address: Lansdowne House, Berkeley Square,
London W1X 5DH England
07 Lakeland Power Ltd. (United Kingdom private
limited liability company) 100% [See 4.EME20]
Address: Roosecote Power Station, Barrow-In-
Furness, Cumbria, England LA13 OPX
07 Lakeland Power Development Company (UK corp.) 100%
Address: Lansdowne House, Berkeley Square,
London W1X 5DH England

33

06 Rapid Energy Limited
Address: Lansdowne House, Berkeley Square, London
W1X 5DH England
05 Mission Energy Italia s.r.l. 90% Rep Office in Italy
Address: Villa Brasini, Via Flaminia 497, 00191 Rome Italy
05 Mission NZ Operations B.V. 100% (Inactive)
Address: Croeselaan 18, 3500 GT Utrecht, The Netherlands
05 Pride Hold Limited (United Kingdom corporation) 1%
Address: Lansdowne House, Berkeley Square,
London W1X 5DH England
06 Lakeland Power Ltd. (United Kingdom private limited
liability company) 100% [See 4.EME20]
Address: Roosecote Power Station, Barrow-In-Furness,
Cumbria, England LA13 OPX
06 Lakeland Power Development Company (UK corp.) 100%
Address: Lansdowne House, Berkeley Square,
London W1X 5DH England
05 EcoElectrica S.a.r.l. (Luxemburg)
Address: 10, rue Antoine Jans, L-1820 Luxembourg
06 EME del Caribe Holding GmbH (Austria)
Address: 4020 Linz, Landstrasse 12, Austria
07 EME del Caribe (Cayman Islands)
Address: First Floor, Caledonian House, Mary St,
George Town, Grand Cayman, Cayman Islands
08 EcoElectrica Holdings, Ltd. (Cayman Islands) 50%
Address: 1350 GT, The Huntlaw Building, Fort
Street, Grand Cayman, Cayman Islands
09 EcoElectrica Ltd. (Cayman Islands) 100%
Address: 1350 GT, The Huntlaw Building, Fort
Street, Grand Cayman, Cayman Islands
10 EcoElectrica LP (Bermuda partnership)
(equity) 1% [See 4.EME09]
Address: Plaza Scotiabank, 273 Ponce de Leon
Avenue, Suite 902, Hato Rey, Puerto Rico 00918
09 EcoElectrica LP (Bermuda ptnrshp) (equity) 99%
[See 4.EME09]
Address: Plaza Scotiabank, Suite 902, Avenida
Ponce de Leon 273, Hato Rey, Puerto Rico 00918
05 Southwestern Generation B.V. 100%
Address: Croeselaan 18, 3521 CB Utrecht, The Netherlands
05 Traralgon Power Pty. Ltd. (Australian corporation) 99%
Address: Southgate Complex, Level 20, HWT Tower,
40 City Road, South Melbourne, 3205 Victoria, Australia
06 Mission Victoria Partnership (Australian partnership)
46.69% (100% w/ Latrobe PPL 52.31% and MEVALP 1%)
07 Latrobe Power Partnership (Australian ptnrshp) 99%
08 Loy Yang B Joint Venture 51% [See 4.EME12]