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UNITED STATESSECURITIES AND EXCHANGE COMMISSIONWashington, D.C. 20549

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FORM 10-K

ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d)
OF THE SECURITIES EXCHANGE ACT OF 1934

For the fiscal year ended December 31, 2002

Commission File Number 333-68632

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Mission Energy Holding Company(Exact name of registrant as specified in its charter)

|Delaware                                                       |  | 95-4867576                          
|-------------------------------------------------------------- |  | ------------------------------------
|(State or other jurisdiction of incorporation
or organization) |  | (I.R.S. Employer Identification No.)
|2600 Michelson Drive, Suite 1700
Irvine, California            |  | 92612                               
|(Address of principal executive offices)                       |  | (Zip Code)                          

Registrant's telephone number, including area code:(949) 852-3576

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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 ý NO o

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. ý

Indicate
by check mark whether the registrant is an accelerated filer (as defined in Rule 12b-2 of the
Act). YES o NO ý

Aggregate
market value of the registrant's Common Stock held by non-affiliates of the registrant as of June 28, 2002: $0. Number of shares outstanding of the
registrant's Common Stock as of March 27, 2003: 1,000 shares (all shares held by an affiliate of the registrant).

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 Edison Mission Energy's Form 10-K for the year ended December 31, 2002                           |  | Part III
|--- |  | ----------------------------------------------------------------------------------------------------------------------- |  | --------
|(2) |  | Designated portions of the Joint Proxy Statement relating to Edison International's 2003 Annual Meeting of Shareholders |  | Part III

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TABLE OF CONTENTS

|         |  |                                                                                       |  | Page
|-------- |  | ------------------------------------------------------------------------------------- |  | ----
|         |  | PART I                                                                                |  |     
|Item 1.  |  | Business                                                                              |  | 1   
|Item 2.  |  | Properties                                                                            |  | 28  
|Item 3.  |  | Legal Proceedings                                                                     |  | 29  
|Item 4.  |  | Submission of Matters to a Vote of Security Holders                                   |  | 31  
|         |  | PART II                                                                               |  |     
|Item 5.  |  | Market for Registrant's Common Equity and Related Stockholder Matters                 |  | 32  
|Item 6.  |  | Selected Financial Data                                                               |  | 33  
|Item 7.  |  | Management's Discussion and Analysis of Results of Operations and Financial Condition |  | 34  
|Item 7a. |  | Quantitative and Qualitative Disclosures about Market Risk                            |  | 116 
|Item 8.  |  | Financial Statements and Supplementary Data                                           |  | 117 
|Item 9.  |  | Changes in and Disagreements with Accountants on Accounting and Financial Disclosure  |  | 117 
|         |  | PART III                                                                              |  |     
|Item 10. |  | Directors and Executive Officers of the Registrant                                    |  | 195 
|Item 11. |  | Executive Compensation                                                                |  | 196 
|Item 12. |  | Security Ownership of Certain Beneficial Owners and Management                        |  | 197 
|Item 13. |  | Certain Relationships and Related Transactions                                        |  | 197 
|Item 14. |  | Controls and Procedures                                                               |  | 197 
|         |  | PART IV                                                                               |  |     
|Item 15. |  | Exhibits, Financial Statement Schedules and Reports on Form 8-K                       |  | 199 
|         |  | Signatures                                                                            |  | 366 
|         |  | Certifications                                                                        |  | 367 

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PART I

Mission Energy Holding Company, which is referred to as MEHC in this annual report, did not conduct any business prior to its formation on
June 8, 2001. All MEHC's substantive operations are currently conducted by Edison Mission Energy, which is referred to as EME in this annual report, and its subsidiaries and
investments.

The presentation of information below pertaining to EME and its consolidated subsidiaries should not be understood to mean that EME has agreed to pay or become
liable for any debt of MEHC. EME and MEHC are separate entities with separate obligations. MEHC is the sole obligor on the $800 million of 13.50% senior secured notes due 2008 and the
$385 million term loan due 2006, and neither EME nor any of its subsidiaries or other investments has any obligation with respect to the notes.

ITEM 1. BUSINESS

The Company

MEHC was formed as a wholly owned subsidiary of The Mission Group, which is a wholly owned subsidiary of Edison International. MEHC was formed to:



On
July 2, 2001, The Mission Group contributed to MEHC all the outstanding common stock of EME. The contribution of EME's common stock to MEHC has been accounted for as a transfer
of ownership of companies under common control, which is similar to a pooling of interest. This means that MEHC's historical financial results of operations and financial position will include the
historical financial results and results of operations of EME and its subsidiaries as though MEHC had such ownership throughout the periods presented. MEHC's only substantive liabilities are its
obligations under the senior secured notes, the term loan and corporate overhead, including fees of its legal counsel, auditors and other advisors. MEHC does not have any substantive operations other
than through EME and its subsidiaries and other investments. At December 31, 2002, MEHC had consolidated assets of $11.4 billion and total shareholder's equity of $736 million.

As
of December 31, 2002, consolidated debt of MEHC was $7.2 billion, including $911 million of debt maturing in December 2003 which is owed by EME's largest
subsidiary, Edison Mission Midwest Holdings Co. The $911 million of debt of Edison Mission Midwest Holdings maturing in December 2003 will need to be repaid, extended or refinanced.
Edison Mission Midwest Holdings is not expected to have sufficient cash to repay the $911 million debt due in December 2003, and there is no assurance that it will be able to extend or
refinance this debt obligation on similar terms and rates as the existing debt, on commercially reasonable terms, on the terms permitted under the financing documents entered into by MEHC in
July 2001 or at all. MEHC's independent accountants' audit opinion for the year ended December 31, 2002 contains an explanatory paragraph that indicates the consolidated financial
statements included in Part II of this annual report have been prepared on the basis that MEHC will continue as a going concern and that the uncertainty about Edison Mission Midwest Holdings'
ability to repay, extend or refinance this obligation raises substantial doubt about MEHC's ability to continue as a going concern. Accordingly, the consolidated financial statements do not include
any adjustments that might result from the resolution of this uncertainty. See "Item 7. Management's Discussion and Analysis of Results of Operations and Financial ConditionLiquidity and
Capital ResourcesRisk Factors."

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MEHC
is incorporated under the laws of the State of Delaware. MEHC's headquarters and principal executive offices are located at 2600 Michelson Drive, Suite 1700, Irvine, California
92612, and its telephone number is (949) 852-3576.

Forward-Looking Statements

This annual report on Form 10-K contains forward-looking statements that reflect MEHC's current expectations and projections about future
events based on MEHC's knowledge of present facts and
circumstances and assumptions about future events. Other information distributed by MEHC that is incorporated in this annual report, or that refers to or incorporates this annual report, may also
contain forward-looking statements. In this annual report and elsewhere, the words "expects," "believes," "anticipates," "estimates," "intends," "plans," "probable" and variations of such words and
similar expressions are intended to identify forward-looking statements. Such statements necessarily involve risks and uncertainties that could cause actual results to differ materially from those
anticipated. Some of the risks, uncertainties and other important factors that could cause results to differ, or that otherwise could impact MEHC or its subsidiaries, are:



Additional
information about the risk factors listed above and other risks and uncertainties is contained throughout this annual report and in the Notes to Consolidated Financial
Statements and Management's Discussion and Analysis of Results of Operations and Financial Condition that appear in Part II of this annual report. Readers are urged to read this entire annual
report, including the

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information incorporated by reference, and carefully consider the risks, uncertainties and other factors that affect MEHC's business. The information contained in this annual report is subject to
change without notice, and MEHC is not obligated to publicly update or revise forward-looking statements. Readers should review future reports filed by MEHC with the Securities and Exchange
Commission.

Description of Business

Electric Power Industry

Until the enactment of the Public Utility Regulatory Policies Act of 1978, utilities and government-owned power agencies were the only producers of bulk electric
power intended for sale to third parties in the United States. The Public Utility Regulatory Policies Act encouraged the development of independent power by removing regulatory constraints relating to
the production and sale of electric energy by certain non-utilities and requiring electric utilities to buy electricity from certain types of non-utility power producers, known
as qualifying facilities, under certain conditions. The passage of the Energy Policy Act of 1992 further encouraged the development of independent power by significantly expanding the options
available to independent power producers with respect to their regulatory status and by liberalizing transmission access. As a result, a significant market for electric power produced by independent
power producers, such as EME, developed in the United States. Beginning in the mid-1990s, industry restructuring and opening of retail markets to competition in several states led some
utilities to divest generating assets, which created new opportunities for growth of independent power
in the United States. In those jurisdictions that have deregulated retail markets, industry trends and regulatory initiatives resulted in a new set of market relationships in which independent
generators and marketers compete with incumbent distribution utilities for sales to end-users, on the basis of price, reliability and other factors. As a result of the
2000-2001 California power crisis and related volatility in wholesale markets, some states have either discontinued or delayed implementation of initiatives involving deregulation and some
utilities have delayed or cancelled plans to divest their generating assets. These developments have generally not affected the progress of industry restructuring in Illinois and Pennsylvania, where
many of EME's power plants are located. However, as discussed further below, competition, regulatory uncertainty and lower wholesale energy prices have adversely affected independent power producers,
including several of EME's subsidiaries. See "Item 7. Management's Discussion and Analysis of Results of Operations and Financial ConditionCurrent Developments."

The
movement toward privatization of existing power generation capacity in many foreign countries and the growing need for new capacity has also led to the development of significant new
markets for independent power producers outside the United States. EME has developed or acquired power plants in the Asia Pacific region and in the Europe region as a result of these developments.
However, as discussed below, the recent volatility in global energy markets has introduced considerable uncertainty as to the future rates of growth in the global independent power producers sector.

Competition and Market Condition Generally

EME and its subsidiaries are subject to intense competition in the United States and overseas from energy marketers, utilities, industrial companies and other
independent power producers. Over the past several years, the restructuring of energy markets has led to the sale of utility-owned assets to EME and its competitors. More recently, in response to
market conditions, EME has changed its focus from acquisition and growth to operating, maintaining, and maximizing the value of its current asset base. Accordingly, EME has engaged in asset sales, has
canceled or deferred new development, and has taken a number of actions to decrease capital expenditures, including cancellations of orders for new turbines, reductions in operating costs, and
suspension of operations at several power plants. This trend reflects lower prices for electric generating capacity in wholesale energy markets both in the United States and United Kingdom,
significant declines in the credit ratings of most major market participants, and the decline of liquidity in the energy markets as a result of credit concerns.

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Where
EME sells power from plants from which the output is not committed to be sold under long-term contracts, commonly referred to as merchant plants, EME is subject to the
market fluctuations in prices based on a number of factors including the amount of capacity available to meet demand, the price of fuel, particularly gas, and the presence of transmission constraints.
EME's customers include large electric utilities or regional distribution companies. In some cases, the electric utilities and distribution companies have their own generation capacity, including
nuclear generation, that affects the amount of generation available to meet demand and may affect the price of electricity in a particular market.

Amendments
to the Public Utility Holding Company Act of 1935 made by the Energy Policy Act have increased the number of competitors in the domestic independent power industry by reducing
restrictions applicable to projects that are not qualifying facilities under the Public Utility Regulatory Policies Act. The introduction of a new standard market design structure mandated by the
Federal Energy Regulatory Commission in those regions not currently organized into centralized power markets and the continued expansion by utilities of unbundled retail distribution services could
also lead to increased competition in the independent power market. See "Regulatory MattersRetail Competition."

Segment Information

EME operates predominantly in one line of business, electric power generation, with reportable segments organized by geographic region: Americas, Asia Pacific and
Europe. EME's plants are located in different geographic areas, which mitigates somewhat the effects of regional markets, regional economic downturns or unusual weather conditions. These regions take
advantage of the increasing globalization of the independent power market. See "Mission Energy Holding Company and Subsidiaries Notes to Consolidated Financial StatementsNote 20.
Business Segments."

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Regional Overview of Business Segments

As of December 31, 2002, EME had ownership or leasehold interests in the following domestic operating power plants:

|Power Plants                   |                | Location      |  | Primary Electric Purchaser(2) |  | Type of
Facility(3) |  | Ownership Interest |   | Electric Capacity (in MW) |        | Net Electric Capacity (in MW)
|------------------------------ | -------------- | ------------- |  | ----------------------------- |  | ------------------- |  | ------------------ | - | ------------------------- | ------ | -----------------------------
|American Bituminous(1)         |                | West Virginia |  | MPC                           |  | Waste Coal          |  | 50                 | % | 80                        |        | 40                           
|Brooklyn Navy Yard             |                | New York      |  | CE                            |  | Cogeneration/EWG    |  | 50                 | % | 286                       |        | 143                          
|Coalinga(1)                    |                | California    |  | PG&E                          |  | Cogeneration        |  | 50                 | % | 38                        |        | 19                           
|EcoEléctrica(1)                |                | Puerto Rico   |  | PREPA                         |  | Cogeneration        |  | 50                 | % | 540                       |        | 270                          
|Gordonsville(1)                |                | Virginia      |  | VEPCO                         |  | Cogeneration/EWG    |  | 50                 | % | 240                       |        | 120                          
|Homer City(1)                  |                | Pennsylvania  |  | Pool                          |  | EWG                 |  | 100                | % | 1,884                     |        | 1,884                        
|Illinois Plants (12 plants)(1) |                | Illinois      |  | EG                            |  | EWG                 |  | 100                | % | 9,287                     |        | 9,287                        
|Kern River(1)                  |                | California    |  | SCE                           |  | Cogeneration        |  | 50                 | % | 300                       |        | 150                          
|March Point I                  |                | Washington    |  | PSE                           |  | Cogeneration        |  | 50                 | % | 80                        |        | 40                           
|March Point II                 |                | Washington    |  | PSE                           |  | Cogeneration        |  | 50                 | % | 60                        |        | 30                           
|Mid-Set(1)                     |                | California    |  | PG&E                          |  | Cogeneration        |  | 50                 | % | 38                        |        | 19                           
|Midway-Sunset(1)               |                | California    |  | SCE                           |  | Cogeneration        |  | 50                 | % | 225                       |        | 112                          
|Salinas River(1)               |                | California    |  | PG&E                          |  | Cogeneration        |  | 50                 | % | 38                        |        | 19                           
|Sargent Canyon(1)              |                | California    |  | PG&E                          |  | Cogeneration        |  | 50                 | % | 38                        |        | 19                           
|SunrisePhase 1(1)             |                | California    |  | CDWR                          |  | EWG                 |  | 50                 | % | 320                       |        | 160                          
|Sycamore(1)                    |                | California    |  | SCE                           |  | Cogeneration        |  | 50                 | % | 300                       |        | 150                          
|Watson                         |                | California    |  | SCE                           |  | Cogeneration        |  | 49                 | % | 385                       |        | 189                          
|                               |                |               |  |                               |  |                     |  |                    |   |                           |        |                              
|                               | Total Americas |               |  |                               |  |                     |  |                    |   |                           | 14,139 |                              
|                               |                |               |  |                               |  |                     |  |                    |   |                           |        |                              

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|CDWR |  | California Department of Water Resources      |  | PREPA |  | Puerto Rico Electric Power Authority
|---- |  | --------------------------------------------- |  | ----- |  | ------------------------------------
|CE   |  | Consolidated Edison Company of New York, Inc. |  | PSE   |  | Puget Sound Energy, Inc.            
|EG   |  | Exelon Generation Company                     |  | SCE   |  | Southern California Edison Company  
|MPC  |  | Monongahela Power Company                     |  | VEPCO |  | Virginia Electric & Power Company   
|PG&E |  | Pacific Gas & Electric Company                |  |       |  |                                     
|Pool |  | Regional electricity trading market           |  |       |  |                                     

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As
of December 31, 2002, EME had ownership or leasehold interests in the following international operating power plants:

|Power Plants                       |                     | Location    |  | Primary
Electric
Purchaser(2) |  | Ownership
Interest |      | Electric
Capacity (in MW) |       | Net Electric
Capacity (in MW)
|---------------------------------- | ------------------- | ----------- |  | ----------------------------- |  | ------------------ | ---- | ------------------------- | ----- | -----------------------------
|Europe:                            |                     |             |  |                               |  |                    |      |                           |       |                              
|Derwent(1)                         |                     | England     |  | SSE                           |  | 33                 | %    | 214                       |       | 71                           
|Doga(1)                            |                     | Turkey      |  | TEAS                          |  | 80                 | %    | 180                       |       | 144                          
|First Hydro (2 plants)(1)          |                     | Wales       |  | Various                       |  | 100                | %    | 2,088                     |       | 2,088                        
|Iberian Hy-Power I (5 plants)(1)   |                     | Spain       |  | FECSA                         |  | 100                | %(4) | 43                        | (6)   | 39                           
|Iberian Hy-Power II (13 plants)(1) |                     | Spain       |  | FECSA                         |  | 100                | %    | 43                        | (6)   | 43                           
|ISAB                               |                     | Italy       |  | GRTN                          |  | 49                 | %    | 518                       |       | 254                          
|Italian Wind (13 plants)           |                     | Italy       |  | GRTN                          |  | 50                 | %    | 303                       |       | 152                          
|                                   |                     |             |  |                               |  |                    |      |                           |       |                              
|                                   | Total Europe        |             |  |                               |  |                    |      |                           | 3,389 |                              
|                                   |                     |             |  |                               |  |                    |      |                           |       |                              
|Asia Pacific:                      |                     |             |  |                               |  |                    |      |                           |       |                              
|Contact Energy (10 plants)         |                     | New Zealand |  | Pool                          |  | 51%                | (5)  | 2,302                     |       | 1,064                        
|Caliraya(1)                        |                     | Philippines |  | NPC                           |  | 50                 | %    | 22                        |       | 11                           
|Kalayaan I(1)                      |                     | Philippines |  | NPC                           |  | 50                 | %    | 363                       |       | 182                          
|Kwinana(1)                         |                     | Australia   |  | WP                            |  | 70                 | %    | 116                       |       | 81                           
|Loy Yang B(1)                      |                     | Australia   |  | Pool(3)                       |  | 100                | %    | 1,000                     |       | 1,000                        
|Paiton(1)                          |                     | Indonesia   |  | PLN                           |  | 40                 | %    | 1,230                     |       | 492                          
|Tri Energy                         |                     | Thailand    |  | EGAT                          |  | 25                 | %    | 700                       |       | 175                          
|Valley Power Peaker(1)             |                     | Australia   |  | Pool                          |  | 80                 | %    | 300                       |       | 241                          
|                                   |                     |             |  |                               |  |                    |      |                           |       |                              
|                                   | Total Asia Pacific  |             |  |                               |  |                    |      |                           | 6,033 |                              
|                                   |                     |             |  |                               |  |                    |      |                           |       |                              
|                                   | Total International |             |  |                               |  |                    |      |                           | 9,422 |                              
|                                   |                     |             |  |                               |  |                    |      |                           |       |                              

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|      |  |                                              |  |      |  |                                                         
|----- |  | -------------------------------------------- |  | ---- |  | --------------------------------------------------------
|EGAT  |  | Electricity Generating Authority of Thailand |  | Pool |  | Electricity trading market for Australia and New Zealand
|FECSA |  | Fuerzas Electricas de Cataluma, S.A.         |  | SSE  |  | Scottish and Southern Electric plc.                     
|GRTN  |  | Gestore Rete Transmissione Nazionale         |  | TEAS |  | Turkiye Elektrik Urehm A.S.                             
|NPC   |  | National Power Corp.                         |  | WP   |  | Western Power                                           
|PLN   |  | PT PLN                                       |  |      |  |                                                         

Americas

As of December 31, 2002, EME had 28 operating power plants in this region, all of which are presently located in the United States and its territories.
EME's Americas region is headquartered in Chicago, Illinois with additional offices located in Irvine, California, and Boston, Massachusetts. A description of EME's larger power plants and major
investments in energy projects in the Americas region is set forth below.

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Illinois Plants

On December 15, 1999, a wholly owned indirect subsidiary of EME, Midwest Generation, LLC (Midwest Generation), completed a transaction with Commonwealth
Edison, now a subsidiary of Exelon Corporation, to acquire Commonwealth Edison's fossil-fuel power plants located in Illinois, which are collectively referred to as the Illinois Plants.
These power plants are located in the Mid-America Interconnected Network, which has transmission connections to the East Central Area Reliability Council and other regional markets.

The
Illinois Plants include the following:

|Plant or Site                  |  | Location                  |  | Leased/
Owned |  | Type    |  | Megawatts
|------------------------------ |  | ------------------------- |  | ------------- |  | ------- |  | ---------
|Electric Generating Facilities |  |                           |  |               |  |         |  |          
|Collins Station(1)             |  | Grundy County, Illinois   |  | leased        |  | oil/gas |  | 2,698    
|Crawford Station               |  | Chicago, Illinois         |  | owned         |  | coal    |  | 542      
|Fisk Station                   |  | Chicago, Illinois         |  | owned         |  | coal    |  | 326      
|Joliet Unit 6                  |  | Joliet, Illinois          |  | owned         |  | coal    |  | 314      
|Joliet Units 7 and 8           |  | Joliet, Illinois          |  | leased        |  | coal    |  | 1,044    
|Powerton Station               |  | Pekin, Illinois           |  | leased        |  | coal    |  | 1,538    
|Waukegan Station               |  | Waukegan, Illinois        |  | owned         |  | coal    |  | 789      
|Will County Station(1)         |  | Romeoville, Illinois      |  | owned         |  | coal    |  | 1,092    
|Peaking Units                  |  |                           |  |               |  |         |  |          
|Crawford                       |  | Chicago, Illinois         |  | owned         |  | oil/gas |  | 121      
|Fisk                           |  | Chicago, Illinois         |  | owned         |  | oil/gas |  | 163      
|Joliet                         |  | Joliet, Illinois          |  | owned         |  | oil/gas |  | 101      
|Waukegan                       |  | Waukegan, Illinois        |  | owned         |  | oil/gas |  | 92       
|Calumet                        |  | Chicago, Illinois         |  | owned         |  | oil/gas |  | 129      
|Bloom                          |  | Chicago Heights, Illinois |  | owned         |  | oil/gas |  | 45       
|Electric Junction              |  | Aurora, Illinois          |  | owned         |  | oil/gas |  | 159      
|Lombard                        |  | Lombard, Illinois         |  | owned         |  | oil/gas |  | 64       
|Sabrooke                       |  | Rockford, Illinois        |  | owned         |  | oil/gas |  | 70       
|                               |  |                           |  |               |  |         |  |          
|                               |  |                           |  | Total         |  | 9,287  
|                               |  |                           |  |               |  |         |  |          

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As
part of the purchase of the Illinois Plants, EME assigned its right to purchase the Collins Station to third-party entities and Midwest Generation simultaneously entered into a
long-term lease arrangement of the Collins Station with these third-party entities. EME also completed sale-leaseback transactions involving its Powerton and Joliet power
facilities in August 2000. EME sold these assets to third parties and entered into long-term leases of the facilities from these third parties to provide capital to finance its
acquisition, in the case of the Collins Station, or to repay corporate debt while maintaining control of the use of the power plants during the terms of the leases. For more information on these
transactions, see "Item 7. Management's Discussion and Analysis of Results of Operation and Financial ConditionOff-Balance Sheet Transactions."

Power Purchase Agreements

On December 15, 1999, Midwest Generation entered into three separate five-year power purchase agreements with Commonwealth Edison that expire
on December 31, 2004. In January 2001,

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Commonwealth Edison assigned these agreements to Exelon Generation. Under these agreements, Midwest Generation has agreed to make the capacity of the power generation stations it purchased from
Commonwealth Edison available to Exelon Generation. These agreements allow Midwest Generation to sell any excess electric energy, including energy not dispatched by Exelon Generation, to other
purchasers under specified conditions. The power purchase agreements with Exelon Generation accounted for 41%, 43% and 49% of EME's consolidated operating revenues for 2002, 2001 and 2000,
respectively. As discussed in detail below, Exelon Generation has released 4,548 MW of Midwest Generation's generating capacity from the power purchase agreements for 2003. 4,739 MW of Midwest
Generation's generating capacity remains subject to power purchase agreements with Exelon Generation.



Under this agreement, Exelon Generation purchases capacity and thus has the right to take from Midwest Generation energy generated by the coal-fired
stations. The agreement provides for capacity payments for the units under contract, whether or not energy is generated, and for energy payments for energy generated by Midwest Generation and taken by
Exelon Generation. The capacity payments provide Midwest Generation revenue for fixed charges such as debt service, labor and insurance, and the energy payment compensates Midwest Generation for
variable costs of actual electricity production. Exelon Generation also compensates Midwest Generation for the cost of startups, shutdowns and some low-load operations, which are not
covered by the normal energy charge rate. Midwest Generation, for its part, supplies ancillary services with respect to such units. If Exelon Generation does not request all available energy from the
units under contract, Midwest Generation may sell the excess energy to third parties, subject to several conditions.

The
agreement identifies the units that are contracted to Exelon Generation and for each contract year denominates them either as committed units or option units for that contract year.
Committed units for each contract year remain subject to the agreement for that contract year, but Exelon Generation has the option to retain, subject to the agreement, all or part of the capacity of
those units denominated as option units for a contract year. Any capacity of the option units which Exelon Generation does not elect to retain for a contract year is released from the terms of the
agreement for that and subsequent contract years. The capacity of the committed units for both of 2003 and 2004 is 1,696 MW. For 2003, Exelon Generation has elected to retain 1,265 MW of the capacity
of those units that were denominated as option units for that contract year. For contract year 2004, Exelon Generation has the option to terminate one or more option units by giving Midwest Generation
notice of its exercise of its option by July 3, 2003.

The
following table lists the committed coal units, the option units for which Exelon Generation has exercised its call option for 2003 but which may be released for 2004, and the units
which, as of January 1, 2003, were released from the terms of the power purchase agreement, along with related pricing information set forth in the power purchase agreement.

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Coal-Fired Units

|                  |                       |       |     | Summer(1)
Capacity Charge
($ per MW Month) |        | Non-Summer(1)
Capacity Charge
($ per MW Month) |        | Energy Prices
($/MWhr)
|----------------- | --------------------- | ----- | --- | ------------------------------------------ | ------ | ---------------------------------------------- | ------ | ----------------------
|
|
|Committed Units   |                       |       |     |                                            |        |                                                |        |                       
|                  | Waukegan Unit 7       |       | 328 |                                            | 11,000 |                                                | 11,000 |                       
|                  | Crawford Unit 8       |       | 326 |                                            | 11,000 |                                                | 11,000 |                       
|                  | Will County Unit 4    |       | 520 |                                            | 11,000 |                                                | 11,000 |                       
|                  | Joliet Unit 8         |       | 522 |                                            | 11,000 |                                                | 11,000 |                       
|                  |                       |       |     |                                            |        |                                                |        |                       
|                  |                       | 1,696 |     |                                            |        |                                                |        |                       
|Option Units(2)   |                       |       |     |                                            |        |                                                |        |                       
|                  | Waukegan Unit 6       |       | 100 |                                            | 21,300 |                                                | 21,300 |                       
|                  | Waukegan Unit 8       |       | 361 |                                            | 21,300 |                                                | 21,300 |                       
|                  | Fisk Unit 19          |       | 326 |                                            | 21,300 |                                                | 21,300 |                       
|                  | Crawford Unit 7       |       | 216 |                                            | 21,300 |                                                | 21,300 |                       
|                  | Will County Unit 3    |       | 262 |                                            | 21,300 |                                                | 21,300 |                       
|                  |                       |       |     |                                            |        |                                                |        |                       
|                  |                       | 1,265 |     |                                            |        |                                                |        |                       
|Released Units(3) |                       |       |     |                                            |        |                                                |        |                       
|                  | Will County Unit 1(4) |       | 156 |                                            |        |                                                |        |                       
|                  | Will County Unit 2(4) |       | 154 |                                            |        |                                                |        |                       
|                  | Joliet Unit 6         |       | 314 |                                            |        |                                                |        |                       
|                  | Joliet Unit 7         |       | 522 |                                            |        |                                                |        |                       
|                  | Powerton Unit 5       |       | 769 |                                            |        |                                                |        |                       
|                  | Powerton Unit 6       |       | 769 |                                            |        |                                                |        |                       
|                  |                       |       |     |                                            |        |                                                |        |                       
|                  |                       | 2,684 |     |                                            |        |                                                |        |                       
|                  |                       |       |     |                                            |        |                                                |        |                       
|                  |                       | 5,645 |     |                                            |        |                                                |        |                       
|                  |                       |       |     |                                            |        |                                                |        |                       

---

The
coal-fired units power purchase agreement sets forth different capacity charges for the summer months and the non-summer months. The capacity payments are
based on the contracted amounts identified in the power purchase agreement and are adjusted by a factor that is in part based on the group equivalent availability factor. If the group equivalent
availability factor is higher than a specified threshold, then the adjustment factor calculation provides Midwest Generation with the opportunity to increase the normal monthly capacity payment, but
if the group equivalent availability factor is lower than the minimum, then Midwest Generation is penalized by a loss in the monthly

9

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capacity payment. The monthly capacity payment adjustment factor provides Midwest Generation with an incentive to maintain the individual units at high equivalent availabilities. The group equivalent
availability factor required in the calculation for potentially achieving the full monthly capacity payment for the coal-fired units is 65% for the summer months and 55% for the
non-summer months.



Under the Collins Station power purchase agreement, Exelon Generation purchases capacity and thus has the right to take from Midwest Generation electric energy
generated by the units at the Collins Station. The agreement provides for capacity payments for the units under contract, whether or not energy is generated, and for energy payments for energy
generated by Midwest Generation and taken by Exelon Generation. The capacity payments provide Midwest Generation revenue for fixed charges such as debt service, labor and insurance, and the energy
payment compensates Midwest Generation for variable costs of actual electricity production. The agreement also includes the requirement that Midwest Generation supply ancillary services with respect
to units under contract. Exelon Generation is obligated to dispatch and purchase a specified minimum amount of electric energy or pay an additional payment calculated under the agreement to meet this
minimum purchase requirement. If Exelon Generation does not request all available energy from the units under contract, Midwest Generation may sell the excess energy to third parties, subject to
several conditions.

Pursuant
to the provisions of the agreement, Exelon Generation has elected to retain, for contract year 2003, 1,084 MW of capacity of the units at the Collins Station, thus releasing
from the contract 1,614 MW of capacity. For contract year 2004, Exelon Generation has the option to terminate one or more option units by giving Midwest Generation notice of its exercise of its option
by October 3, 2003.

10

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The following table lists the generating units at the Collins Station for which Exelon Generation has not exercised its option to terminate for 2003 but which may be released for 2004,
and the generating units which, as of January 1, 2003, were, as a result of the exercise by Exelon Generation of its option to terminate, released from the terms of the power purchase
agreement, along with related pricing information set forth in the power purchase agreement.

Collins Station

|                  |                   |       |     | Summer(1)
Capacity Charge
($ per MW Month) |       | Non-Summer(1)
Capacity Charge
($ per MW Month) |       | Energy Prices
($/MWhr)
|----------------- | ----------------- | ----- | --- | ------------------------------------------ | ----- | ---------------------------------------------- | ----- | ----------------------
|
|
|Option Units(2)   |                   |       |     |                                            |       |                                                |       |                       
|                  | Collins Unit 1    |       | 554 |                                            | 8,333 |                                                | 8,333 |                       
|                  | Collins Unit 3    |       | 530 |                                            | 8,333 |                                                | 8,333 |                       
|                  |                   |       |     |                                            |       |                                                |       |                       
|                  |                   | 1,084 |     |                                            |       |                                                |       |                       
|Released Units(3) |                   |       |     |                                            |       |                                                |       |                       
|                  | Collins Unit 2    |       | 554 |                                            |       |                                                |       |                       
|                  | Collins Unit 4(4) |       | 530 |                                            |       |                                                |       |                       
|                  | Collins Unit 5(4) |       | 530 |                                            |       |                                                |       |                       
|                  |                   |       |     |                                            |       |                                                |       |                       
|                  |                   | 1,614 |     |                                            |       |                                                |       |                       
|                  |                   |       |     |                                            |       |                                                |       |                       
|                  |                   | 2,698 |     |                                            |       |                                                |       |                       
|                  |                   |       |     |                                            |       |                                                |       |                       

---

The
Collins Station power purchase agreement divides the capacity charges into summer months and non-summer months. The capacity payments are based on the contracted amounts
identified in the agreement and are adjusted by a factor that is in part based on the group equivalent availability factor. With respect to all electricity purchased under the agreement, Exelon
Generation is obligated to pay: a monthly capacity charge for the reserved units which varies according to the time of year; a per megawatt-hour energy charge; various charges for
start-up of the reserved units; low load charges that apply at any hour in which Exelon Generation schedules a reserved unit to operate at an output below
a level specified in the agreement; and an annual settlement amount to the extent natural gas prices exceed a specified amount and Exelon Generation dispatches a minimum amount of electric energy.



Under the peaking units power purchase agreement, Exelon Generation purchases capacity and thus has the right to take from Midwest Generation electric energy
generated by the peaking units. The

11

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agreement provides for capacity payments for the units under contract, whether or not energy is generated, and for energy payments for energy generated by Midwest Generation and taken by Exelon
Generation. If Exelon Generation does not request all available energy from the units under contract, Midwest Generation may sell the excess energy to third parties, subject to several conditions.

Pursuant
to the provisions of the agreement, Exelon Generation has elected to retain, for contract year 2003, 694 MW of capacity of the peaking units, thus releasing from the contract
250 MW of capacity. For contract year 2004, Exelon Generation has the option to terminate one or more option units by giving Midwest Generation notice of its exercise of its option by
October 3, 2003.

The
following table shows the peaking units as to which Exelon Generation has not exercised its option to terminate for 2003 but which may be released for 2004, and the peaking units
which were, as a result of the exercise by Exelon Generation of its option to terminate, released from the terms of the power purchase agreement, along with related pricing information set forth in
the power purchase agreement.

Peaking Units

|                  |  |     |  | Summer(1)
Capacity Charge
($ per MW Month) |  | Non-Summer(1)
Capacity Charge
($ per MW Month) |  | Energy Prices
($/MWhr)
|----------------- |  | --- |  | ------------------------------------------ |  | ---------------------------------------------- |  | ----------------------
|
|
|Option Units(2)   |  | 694 |  | 9,500                                      |  | 9,500                                          |  | 1,500                 
|Released Units(3) |  | 250 |  |                                            |  |                                                |  |                       
|                  |  |     |  |                                            |  |                                                |  |                       
|                  |  | 944 |  |                                            |  |                                                |  |                       
|                  |  |     |  |                                            |  |                                                |  |                       

---



For the past three years, Midwest Generation has derived substantially all of its revenue from the sale of energy and capacity to Exelon Generation under power
purchase agreements. Midwest Generation's energy and capacity that are not purchased under power purchase agreements are generally sold at market prices to neighboring utilities, third-party
electricity retailers and power marketers through a marketing affiliate.

While
an independent system operator does not yet oversee operations of the Commonwealth Edison control area, a number of other utilities in the region participate in the Midwest
Independent System Operator, a Regional Transmission Organization authorized pursuant to FERC Order No. 2000, and a bilateral market is already present. The regional market is supported by open
access transmission under various utility company transmission tariffs, the Midwest Independent System Operator Tariff, as well as retail access electricity tariffs currently available to end use
customers in many states, including Illinois and Ohio. Open Access Transmission Tariffs and retail access tariffs allow companies which do

12

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not own transmission and distribution systems to utilize the transmission and distribution systems of others to sell power at wholesale and retail on a non-discriminatory basis relative
to the system owners. Such tariffs are vital to allow companies, such as Midwest Generation, which own or control generation but not transmission and distribution systems, to compete in the
deregulated electricity markets. These documents provide a uniform set of standards that have been approved by regulatory agencies and are publicly available. Both Commonwealth Edison and American
Electric Power are seeking to have their control areas placed under the operation of PJM Interconnection, LCC, which is commonly known as PJM, and, if they are successful, will be subject to the PJM
Tariff and Market Rules. PJM is a prominent independent system operator providing system operations and market settlement throughout the Mid-Atlantic States. Consequently, Midwest
Generation's plant operations and future power sales may conform to future PJM requirements. Some of Midwest Generation's coal units may have a portion of their revenue derived from forward sales to
regional utilities and power marketers. The remainder of the available coal-fired generation output, together with available output from the Collins Station and the peaking units, may be
sold on a spot basis.

During
2003, the primary markets available to Midwest Generation for wholesale sales of electricity are expected to be "wholesale customer" and
"over-the-counter." Wholesale customer transactions are bilateral sales for resale to regional buyers, including investor-owned utilities, municipal utilities, rural electric
cooperatives and retail energy suppliers. Wholesale customer transactions include real-time, daily and longer term structured sales; they are not arranged through brokers and may be
tailored to meet the specific requirements of wholesale electricity consumers. Over-the-counter markets are generally accessed through third-party brokers and electronic
exchanges, and include forward sales of electricity. The most liquid over-the-counter markets in the Midwest region are "Into Cinergy," and, to a lesser extent, "Into ComEd."
Liquidity in the over-the-counter markets is lower than it has been in prior years as a consequence of the decision by many trading entities to discontinue operations and the
financial problems of others resulting in far fewer creditworthy participants in these electricity markets.

"Into
Cinergy" and "Into ComEd" are bilateral markets for the sale or purchase of electrical energy for future delivery. The emergence of "Into Cinergy," and "Into ComEd" as commercial
hubs for the trading of physical power has not only facilitated transparency of wholesale power prices in these markets, but also provides liquidity required to support risk management strategies
utilized to mitigate exposure to electricity price volatility. Energy is traded in the form of physically delivered megawatt-hours. Delivery is either made (1) into the receiving control area's
transmission system (i.e., Cinergy's or ComEd's transmission system) by the seller's daily election of control area interface, or (2) by procuring energy generated from a source within the
receiving control area. Almost all of Midwest Generation's plants are capable of meeting the current "Into ComEd" delivery criteria. Performance of transactions in these markets is subject to
contracts that generally provide for liquidated damages supported by a variety of credit requirements, which may include independent credit assessment, parental guarantees, letters of credit and cash
margining arrangements. As noted, however, liquidity in all of these markets has been adversely affected by recent financial problems among trading and marketing entities.

On
December 11, 2002, Commonwealth Edison, American Electric Power and others filed with the Federal Energy Regulatory Commission seeking permission to include their transmission
systems within the Regional Transmission Organization proposed by PJM. The effect of the filing would be to transfer functional control of such systems to PJM and to eliminate so-called
rate pancaking for transmission and ancillary services over a region that would extend significantly beyond the current western boundaries of PJM and into electricity markets in the Midwest. Rate
pancaking occurs when energy must move through multiple, separately priced transmission systems to travel from its point of production to its point of delivery, and each transmission owner along the
line charges separately for the use of its system. The Federal Energy Regulatory Commission was requested by the parties to act on such filing by mid-February 2003. However, such
action has now been delayed by the unanticipated

13

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enactment of emergency legislation by the Virginia legislature that purports to prevent any Virginia utility (including American Electric Power's subsidiary, Appalachian Power Company) from
transferring control of its transmission assets to PJM until July 2004. The effect of such enactment is to create uncertainty regarding the timing, and possibly the ultimate feasibility, of
American Electric Power's and Commonwealth Edison's moving forward with their applications to place their transmission systems under the control of PJM. On March 14, 2003, the states of
Pennsylvania, Ohio and Michigan filed a motion with the Federal Energy Regulatory Commission seeking an order granting immediate approval of the pending applications of Commonwealth Edison and
American Electric Power to join PJM, or in the alternative for temporary control of such parties' transmission assets by PJM. On March 17, 2003, Commonwealth Edison filed a motion requesting
immediate approval of such applications, and opposing any temporary measures of the sort suggested by Pennsylvania, Ohio and Michigan. The outcome of such efforts is uncertain.

For
a discussion of the risks related to Midwest Generation's sale of electricity, see "Item 7. Management's Discussion and Analysis of Results of Operations and Financial
ConditionMarket Risk Exposures."

Homer City Facilities

On March 18, 1999, EME completed a transaction with GPU, Inc., New York State Electric & Gas Corporation and their respective affiliates to
acquire the 1,884 MW Homer City Electric Generating Station. These facilities consist of three coal-fired boilers and steam turbine-generator units, one coal preparation facility, an
1,800-acre site and associated support facilities in the mid-Atlantic region of the United States and have direct, high voltage interconnections to both PJM and 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. For a discussion of the risks related to the
sale of electricity from the Homer City facilities, see "Item 7. Management's Discussion and Analysis of Results of Operations and Financial ConditionMarket Risk Exposures."

On
December 7, 2001, EME's subsidiary completed a sale-leaseback of the Homer City facilities to third-party lessors. EME sold the Homer City facilities to provide
capital to repay corporate debt and entered into long-term leases to continue to operate the facilities during the terms of the leases. See "Item 7. Management's Discussion and Analysis of
Results of Operations and Financial ConditionOff-Balance Sheet Transactions."

Major Investments in California Cogeneration Plants

EME owns partnership investments in the Kern River Cogeneration Company, Midway Sunset Cogeneration Company, Sycamore Cogeneration Company
and Watson Cogeneration Company, as described below. These projects have similar economic characteristics and have been used, collectively, to obtain bond financing by Edison Mission Energy Funding
Corp., a special purpose entity that EME includes in its consolidated financial statements. Due to similar economic characteristics and the bond financing related to its equity investments, EME views
these projects collectively and refers to them as the Big 4 projects.

Kern River Cogeneration PlantEME owns a 50% partnership interest in Kern River Cogeneration Company, which owns a 300 MW
natural gas-fired cogeneration facility located near Bakersfield, California, which EME refers to as the Kern River project. Kern River Cogeneration sells electricity to Southern
California Edison Company under a power purchase agreement that expires in 2005 and sells steam to Texaco Exploration and Production Inc. under a steam supply agreement that also expires in
2005.

Midway-Sunset Cogeneration PlantEME owns a 50% partnership interest in Midway Sunset Cogeneration Company, which owns a 225
MW natural gas-fired cogeneration facility located near Taft,

14

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California, which EME refers to as the Midway-Sunset project. Midway-Sunset sells electricity to Southern California Edison, Aera Energy LLC and Pacific Gas & Electric Company under power
purchase agreements that expire in 2009 and sells steam to Aera under a steam supply agreement that also expires in 2009.

Sycamore Cogeneration PlantEME owns a 50% partnership interest in Sycamore Cogeneration Company, which owns and operates a
300 MW natural gas-fired cogeneration facility located near Bakersfield, California, which EME refers to as the Sycamore project. Sycamore Cogeneration sells electricity to Southern
California Edison under a power purchase agreement that expires in 2007 and sells steam to Texaco Exploration and Production Inc. under a steam supply agreement that also expires in 2007.

Watson Cogeneration PlantEME owns a 49% partnership interest in Watson Cogeneration Company, which owns a 385 MW natural
gas-fired cogeneration facility located in Carson, California, which EME refers to as the Watson project. Watson Cogeneration sells electricity to Southern California Edison and to the
adjacent BP refinery under power purchase agreements that expire in 2008 and sells steam to ARCO Products Company under a steam supply agreement that also expires in 2008. From January 2000
through December 2002, Watson Cogeneration sold electricity to CPC Cogeneration LLC, which in turn sold electricity to the BP refinery. EME owned a 49% interest in CPC Cogeneration. CPC
Cogeneration was dissolved in December 2002 and its contract with the BP refinery was assigned back to Watson Cogeneration.

Other Americas Power Plants

Sunrise Power PlantEME owns a 50% interest in Sunrise Power Company, LLC, which owns a natural
gas-fired facility currently under construction in Kern County, California, which EME refers to as the Sunrise project. The Sunrise project consists of two phases. Phase 1, a simple-cycle
gas-fired facility (320 MW), was completed on June 27, 2001. Phase 2, conversion to a combined-cycle gas-fired facility (bringing the capacity to a total of 560 MW), is
currently scheduled to be completed in July 2003. Sunrise Power entered into a long-term power purchase agreement with the California Department of Water Resources on
June 25, 2001. For further discussion related to this agreement, see "Item 3. Legal ProceedingsRegulatory Developments Affecting Sunrise Power Company."

Brooklyn Navy Yard Cogeneration PlantEME owns a 50% partnership interest in Brooklyn Navy Yard Cogeneration Partners L.P.,
which owns a 286 MW natural gas and oil-fired cogeneration facility located near Brooklyn, New York, which EME refers to as the Brooklyn Navy Yard project. Brooklyn Navy Yard sells
electricity and steam to Consolidated Edison Company of New York, Inc. under a power purchase agreement that expires in 2039.

Gordonsville Cogeneration PlantEME owns a 50% partnership interest in Gordonsville Energy, L.P., which owns a 240 MW natural
gas-fired cogeneration facility located in Gordonsville, Virginia, which EME refers to as the Gordonsville project. Gordonsville Energy sells electricity to Virginia Electric &
Power Company under a power purchase agreement that expires in 2024 and sells steam to Rapidan Service Authority under a steam supply agreement that also expires in 2024.

EcoEléctrica Power PlantEME owns a 50% partnership interest in EcoEléctrica L.P., which owns a
540 MW power plant located Peñuelas, Puerto Rico, which EME refers to as the EcoEléctrica project. EcoEléctrica sells electricity to Puerto Rico Electric
Power Authority under a power purchase agreement that expires in 2022 and sells water to Puerto Rico Water & Sewer Authority under a water supply agreement that also expires in 2022. See "Item
3. Legal ProceedingsEcoEléctrica Potential Environmental Proceeding" for more information regarding environmental matters.

15

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Other Small Investments in Energy Projects

EME also owns 50% investments in seven other small energy projects (less than 200 MW of net electric capacity) that are located in the United States. Each project
sells electricity under a long-term power purchase agreement with the local electric utility.

Investment in Four Star Oil & Gas Company

EME owns a 37.2% direct and indirect interest, with 36.05% voting stock, in Four Star Oil & Gas Company, with majority control held by affiliates of
ChevronTexaco Corp. Four Star Oil & Gas owns oil and gas reserves in the San Juan Basin, the Hugoton Basin, the Permian Basin and offshore Gulf Coast and Alabama. Under a long-term
service contract, the majority of Four Star Oil & Gas's properties are operated through ChevronTexaco Exploration & Production Inc. See "Mission Energy Holding Company and
Subsidiaries Notes to Consolidated Financial StatementsNote 8. Investments in Unconsolidated Affiliates" for financial information on EME's oil and gas investments.

Asia Pacific

As of December 31, 2002, EME had 17 operating power plants in this region that are located in Australia, Indonesia, the Philippines, Thailand and New
Zealand. EME's Asia Pacific region is headquartered in Singapore, with an additional office located in Australia. A description of EME's power plants, its investment in Contact Energy and investments
in energy projects in the Asia Pacific region is set forth below.

Australia

Loy Yang B Power PlantEME owns a 1,000 MW coal-fired power station located in Traralgon,
Victoria, Australia, which EME refers to as the Loy Yang B project. The project sells electricity to a centralized electricity pool, which provides for a system of generator bidding, central dispatch
and a settlements system based on a clearing market for each half-hour of every day. The National Electricity Market Management Company, operator and administrator of the pool, determines
a system marginal price each half-hour. EME has entered into an agreement with the State Electricity Commission of Victoria, which agreement EME refers to as the State Hedge, that provides
through October 31, 2016 for the project to receive a fixed price for a portion of its electricity in exchange for payment to the State of the system marginal price applicable to such portion.
For further discussion of risks related to the sale of electricity from the Loy Yang B project, see "Item 7. Management's Discussion and Analysis of Results of Operations and Financial
ConditionMarket Risk Exposures."

Valley Power Peaker Power PlantDuring 2002, EME completed construction of a 300 MW gas-fired peaker plant located
adjacent to the Loy Yang B coal-fired power plant site, which EME refers to as the Valley Power Peaker project. The peaker units service peaking demand within the National Energy Market of
Eastern Australia and, specifically, within the State of Victoria by selling the output of the peakers directly into the pool and by entering into financial contracts related to pool prices with a
variety of generation and retail businesses. EME owns a 60% interest in the Valley Power Peaker project, with the remaining interest held by its 51.2%-owned affiliate, Contact Energy Limited.

Kwinana Cogeneration PlantEME owns a 70% interest in a 116 MW gas-fired cogeneration plant in Perth, Australia,
which EME refers to as the Kwinana project. EME sells electricity to Western Power under a power purchase agreement that expires in 2021 and sells steam to the British Petroleum Kwinana refinery under
a steam supply agreement which also expires in 2021.

16

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New Zealand

Contact EnergyEME owns a 51.2% majority interest in Contact Energy Limited. The remaining shares of
Contact Energy are publicly held and traded on the New Zealand stock exchange. Contact Energy is the largest wholesaler and retailer of natural gas in New Zealand and generates about
one-quarter of New Zealand's electricity. For further discussion of risks related to the sale of electricity from Contact Energy, see "Item 7. Management's Discussion and Analysis of
Results of Operations and Financial ConditionMarket Risk Exposures." Contact Energy owns the following power plants:

Plant

Type

MegawattsNew Plymouth

Gas thermal

464Clyde

Hydro

432Otahuhu B

Natural gas

372Roxbugh

Hydro

320Oakey(1)

Natural gas

300Wairakei

Geothermal

165Ohaaki

Geothermal

104Poihipi

Geothermal

55Otahuhu A

Natural gas

45Te Rapa

Natural gas

452,302


---

Contact
Energy also owns a 40% interest in the Valley Power Peaker project in Australia with the remaining interest held by an EME wholly owned subsidiary.

Indonesia

The Paiton Power PlantEME owns a 40% interest in PT Paiton Energy (Paiton Energy), which owns a 1,230
MW coal-fired power plant in operation in East Java, Indonesia, which EME refers to as the Paiton project. Paiton Energy sells electricity to PT PLN, the state-owned electric utility
company, under a power purchase agreement. On December 23, 2002, an amendment to the original power purchase agreement became effective, bringing to a close and resolving a series of disputes
between Paiton Energy and PT PLN which began in 1999 and were caused, in large part, by the effects of the regional financial crisis in Asia and Indonesia. The amended power purchase agreement
includes changes in the price for power and energy charged under the power purchase agreement, provides for payment over time of amounts unpaid prior to January 2002 and extends the expiration
date of the power purchase agreement from 2029 to 2040. These terms have been in effect since January 2002 under a previously agreed Binding Term Sheet which was replaced by the power purchase
agreement amendment. For a further discussion of the Paiton project and the restructuring of its financing arrangements, see "Item 7. Management's Discussion and Analysis of Results of Operations and
Financial ConditionContingencies."

Philippines

CBK Power PlantsIn February 2001, EME purchased a 50% interest in CBK Power Co. Ltd.
CBK Power has entered into a 25-year build-rehabilitate-operate-transfer agreement with National Power Corporation related to the 760 MW Caliraya-Botocan-Kalayaan hydroelectric project
located in the Philippines, which EME refers to as the CBK project. CBK Power is paid capital recovery fees and

17

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operations and maintenance fees for generating electricity and providing other services under the agreement. At December 31, 2002, 385 MW had been commissioned and were operational.

Thailand

Tri Energy Cogeneration PlantEME owns a 25% interest in Tri Energy Company Limited, which owns a 700
MW gas-fired cogeneration plant located west of Bangkok, Thailand, which EME refers to as the Tri Energy project. Tri Energy sells electricity to Electricity Generating Authority of
Thailand under a power purchase agreement that expires in 2020.

Europe

As of December 31, 2002, EME had 36 operating power plants in this region that are located in the U.K., Turkey, Spain and Italy. EME's Europe region is
headquartered in London, England, with additional offices located in Italy and Spain. The London office was established in 1989. A description of EME's power plants and investments in energy projects
in the Europe region is set forth below.

United Kingdom

First Hydro Power PlantsEME's wholly owned subsidiary, First Hydro, owns two pumped storage stations
in North Wales at Dinorwig and Ffestiniog which have a combined capacity of 2,088 MW, which EME refers to as the First Hydro project. Pumped storage stations consume electricity when it is
comparatively less expensive in order to pump water for storage in an upper reservoir. Water is then allowed to flow back through turbines in order to generate electricity when its market value is
higher. First Hydro sells electricity to electricity suppliers, other generators and into short-term markets. Additionally, it sells ancillary services to the system operator. For further
discussion of issues related to the First Hydro project, see "Item 7. Management's Discussion and Analysis of Results of Operations and Financial ConditionMarket Risk Exposures" and
"Historical Distributions Received by Edison Mission Energy," as well as "Edison Mission Energy and Subsidiaries Notes to Consolidated Financial StatementsNote 10.
Financial Instruments."

Derwent Cogeneration PlantEME owns a 33% interest in Derwent Cogeneration Limited, which owns a 214 MW gas-fired
cogeneration plant in Derby, England, which EME refers to as the Derwent project. Derwent sells electricity to Southern Electric plc under a power purchase agreement that expires in 2010 and sells
steam to Courtaulds Chemicals (Holdings) Limited under a steam supply contract that also expires in 2010.

Italy

ISAB Power PlantEME owns a 49% interest in ISAB Energy S.r.l. which owns a 518 MW integrated
gasification combined cycle power plant in Sicily, Italy, which EME refers to as the ISAB project. ISAB sells electricity to Gestore Rete Transmissione Nazionale, Italy's state transmission company,
under a power purchase agreement that expires in 2020. The ISAB project is located by an oil refinery owned by ERG Petroli SpA.

Italian Wind Power PlantsIn 2000, EME's wholly owned subsidiary, Edison Mission Wind Power Italy B.V., acquired a 50%
interest in 13 power projects that are in operation in Italy by UPC International Partnership CV II, which EME collectively refers to as the Italian Wind project. The projects use wind to generate
electricity from turbines, which is sold under fixed-price, long-term tariffs to Gestore Rete Transmissione Nazionale (GRTN). At December 31, 2002, the entire planned 303 MW had
been
commissioned and are operational. The project, however, is restricted to 283 MW as the project is awaiting 20 MW of transmission capacity to be interconnected to one of the sites. GRTN expects to
complete the interconnection in the second quarter of 2003.

18

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Spain

Spanish Hydro Power PlantsEME's wholly owned subsidiary, Iberica de Energias, S.L., owns 18 small,
run-of-the-river hydroelectric plants regionally dispersed in Spain totaling 86 MW, which EME refers to as the Spanish Hydro project. Iberica de Energias, S.L.
sells electricity to Fuerzas Electricas de Cataluma, S.A. under concessions that have various expiration dates ranging from 2030 to 2065.

Turkey

Doga Cogeneration PlantEME owns an 80% interest in Doga Enerji, which owns a 180 MW
gas-fired cogeneration plant near Istanbul, Turkey, which EME refers to as the Doga project. Doga Enerji sells electricity to Turkiye Elektrik Ticaret ve Taahhut, A.S., commonly known as
TETAS, under a power purchase agreement that expires in 2018. See "Item 7. Management's Discussion and Analysis of Results of Operations and Financial ConditionContingencies" for
information regarding regulatory developments affecting the Doga project.

In
addition to the facilities and power plants that EME owns, EME uses the term "its" in regard to facilities and power plants that EME or an EME subsidiary operates under
sale-leaseback arrangements.

Discontinued Operations

Lakeland Project

EME's Lakeland project operated a 220 MW combined cycle, natural gas-fired power plant located in the United Kingdom. The assets of the project are
owned by EME's indirect subsidiary, Lakeland Power Ltd., which sold power generated from the plant pursuant to a power sales agreement with
Norweb Energi Ltd., a subsidiary of TXU (UK) Holdings Limited (TXU UK) and an indirect subsidiary of TXU Europe Group plc (TXU Europe).

On
November 19, 2002, TXU UK and TXU Europe, together with a related entity, TXU Europe Energy Trading Limited (TXU Energy), entered into formal administration proceedings in the
United Kingdom (similar to bankruptcy proceedings in the United States). As a result of these actions and their effect upon Norweb Energi Ltd. and EME's contractual arrangements with other
parties, the Lakeland power plant suspended operations.

In
December 2002, the directors of Norweb Energi Ltd. appointed a liquidator to wind up its contractual rights and obligations. On December 4, 2002, Norweb
Energi Ltd. provided a notice of disclaimer of the power sales agreement under Section 178 of the Insolvency Act 1986. The disclaimer effectively terminated the power sales agreement.

On
December 19, 2002, the lenders to the Lakeland project accelerated the debt owing under the bank agreement that governs the project's indebtedness, and on December 20,
2002, the Lakeland project lenders appointed Michael Thomas Seery and Michael Vincent McLoughlin, partners with KPMG LLP, as administrative receiver over the assets of Lakeland Power Ltd. The
administrative receiver is appointed to take control of the affairs of Lakeland Power Ltd. and has a wide range of powers (specified in the Insolvency Act), including authorizing the sale of
the power plant. The appointment of the administrative receiver requires the treatment of the Lakeland power plant as an asset held for sale under Statement of Financial Accounting Standards
No. 144, "Accounting for the Impairment or Disposal of Long-Lived Assets" (SFAS No. 144). See "Mission Energy Holding Company and Subsidiaries Notes to Consolidated Financial
StatementsNote 7. Discontinued Operations."

The
bank loans of Lakeland Power Ltd. are non-recourse to EME. Furthermore, neither the defaults on these loans nor the institution of administrative proceedings
cross-default to any other indebtedness of EME or its affiliates.

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Ferrybridge and Fiddler's Ferry Plants

On December 21, 2001, EME completed the sale of the Ferrybridge and Fiddler's Ferry coal-fired power plants located in the United Kingdom to
two wholly owned subsidiaries of American Electric Power. In addition, as part of the transactions, the purchasers acquired other assets and assumed specified liabilities associated with the plants.
EME acquired the plants in 1999 from PowerGen UK plc. In accordance with SFAS No. 144, the results of Ferrybridge and Fiddler's Ferry have been reflected as discontinued operations in EME's
consolidated financial statements. See "Mission Energy Holding Company and Subsidiaries Notes to Consolidated Financial StatementsNote 7. Discontinued Operations."

Price Risk Management and Trading Activities

EME's domestic power marketing and trading organization, Edison Mission Marketing & Trading, Inc., markets the energy and capacity of EME's merchant
generating fleet and, in connection with this activity, trades electric power and energy and related commodity and financial products, including forwards, futures, options and swaps. Edison Mission
Marketing & Trading also provides services and price risk management capabilities to the electric power industry. Almost all of this trading activity is related either to realizing value from
the sale of energy and capacity from EME's merchant plants or to risk management activities related to preserving the value of this marketing activity. EME segregates its marketing and trading
activities into two categories:



Edison
Mission Marketing & Trading is divided into front-, middle-, and back-office segments, with specified duties segregated for control purposes. Edison Mission
Marketing & Trading has systems in place which monitor real time spot and forward pricing and perform option valuations. Edison Mission Marketing & Trading also has a wholesale power
scheduling group that operates on a 24-hour basis.

Internationally,
EME also conducts price risk management activities through subsidiaries that are primarily focused on marketing and fuel management activities in the same manner
described above.

In
conducting EME's price risk management and trading activities, EME contracts with a number of utilities, energy companies and financial institutions. Due to factors beyond EME's
control, market liquidity has decreased significantly since the beginning of 2002, and a number of formerly significant

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trading parties have completely withdrawn from the market or substantially reduced their trading activities. The reduction in the credit quality of traditional trading parties increases EME's credit
risk. In addition, the decrease in market liquidity may require EME to rely more heavily on wholesale electricity sales to wholesale customer markets, which may also increase EME's credit risk. While
various industry groups and regulatory agencies have taken steps to address market liquidity, transparency and credit issues, there is no assurance as to when, or how effectively, such efforts will
restore market confidence. In the event a counterparty were to default on its trade obligation, EME would be exposed to the risk of possible loss associated with reselling the contracted product at a
lower price if the non-performing counterparty were unable to pay the resulting liquidated damages owed to EME. Further, EME would be exposed to the risk of non-payment of
accounts receivable accrued for products delivered prior to the time such counterparty defaulted.

To
manage credit risk, EME looks at the risk of a potential default by its counterparties. Credit risk is measured by the loss EME would record if its counterparties failed to perform
pursuant to the terms of their contractual obligations. EME has established controls to determine and monitor the creditworthiness of counterparties and uses master netting agreements whenever
possible to mitigate its exposure to counterparty risk. EME may require counterparties to pledge collateral when deemed necessary. EME tries to manage the credit in its portfolio based on credit
ratings using published ratings of counterparties and other publicly disclosed information, such as financial statements, regulatory filings, and press releases, to guide it in the process of setting
credit levels, risk limits and contractual arrangements including master netting agreements. The credit quality of EME's counterparties is reviewed regularly by EME's risk management committee. In
addition to continuously monitoring its credit exposure to its counterparties, EME also takes appropriate steps to limit or lower
credit exposure. Despite this, there can be no assurance that EME's actions to mitigate risk will be wholly successful or that collateral pledged will be adequate.

EME's
merchant power plants and energy trading activities expose EME to commodity price risks. 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 regular reviews by a risk management committee. 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 commodity risk, compare risk on a consistent basis and identify the drivers of the risk. Value at risk measures the possible 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 the use of stress testing and worst-case scenario analysis, as well as stop loss limits and counterparty credit exposure limits. Despite this, there can be no assurance that all risks
have been accurately identified, measured and/or mitigated.

In
executing agreements with counterparties to conduct price risk management or trading activities, EME generally provides credit support in the form of guarantees or letters of credit
or enters into margining arrangements (agreements to provide or receive collateral based on changes in the market price of the underlying contract under specific terms). To manage its liquidity, EME
assesses the potential impact of future price changes in determining the amount of collateral requirements under existing or anticipated forward contracts. There is no assurance that EME's liquidity
will be adequate to meet margin calls from counterparties in the case of extreme market changes or that the failure to meet such cash requirements would not have a material adverse effect on its
liquidity. See "Item 7. Management's Discussion and Analysis of Results of Operations and Financial ConditionLiquidity and Capital ResourcesRisk Factors."

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Seasonality

EME's third quarter income from continuing operations from its domestic energy projects are materially higher than income from continuing operations related to
other quarters of the year because warmer weather during the summer months results in higher electric revenues being generated from the Homer City facilities and the Illinois Plants, and because a
number of EME's domestic energy projects, located on the west coast, have power sales contracts that provide for higher payments during the summer months. By contrast, the First Hydro plants and
Contact Energy have higher electric revenues during their winter months.

Regulatory Matters

General

EME's operations are subject to extensive regulation by governmental agencies in each of the countries in which EME conducts operations. EME's domestic operating
projects are subject to energy, environmental and other governmental laws and regulations at the federal, state and local levels in connection with the ownership and operation of its projects, and the
use of electric energy, capacity and related products, including ancillary services from its projects. Federal laws and regulations govern, among other things, transactions by and with purchasers of
power, including utility companies, the operation of a project and the ownership of a project. Under limited circumstances where exclusive federal jurisdiction is not applicable or specific exemptions
or waivers from state or federal laws or regulations are otherwise unavailable, federal and/or state utility regulatory commissions may have broad jurisdiction over non-utility owned
electric power plants. Energy producing projects are also subject to federal, state and local laws and regulations that govern the geographical location, zoning, land use and operation of a project.
Federal, state and local environmental requirements generally require that a wide variety of permits and other approvals be obtained before the commencement of construction or operation of an energy
producing facility and that the facility then operate in compliance with these permits and approvals. Furthermore, each of EME's international projects is subject to the energy and environmental laws
and regulations of the foreign country in which the project is located. The degree of regulation varies by country and may be materially different from the regulatory regime in the United States.

EME
is subject to a varied and complex body of laws and regulations that are in a state of flux and which both public officials and private parties may seek to enforce. Intricate and
changing environmental and other regulatory requirements may necessitate substantial expenditures and may create a significant risk of expensive delays or significant loss of value in a project if it
is unable to function as planned due to changing requirements or local opposition.

U.S. Federal Energy Regulation

The Federal Energy Regulatory Commission has ratemaking jurisdiction and other authority with respect to interstate wholesale sales and transmission of electric
energy under the Federal Power Act and with respect to certain interstate sales, transportation and storage of natural gas under the Natural Gas Act of 1938. The Securities and Exchange Commission has
regulatory powers with respect to upstream owners of electric and natural gas utilities under the Public Utility Holding Company Act of 1935. The enactment of the Public Utility Regulatory Policies
Act of 1978 and the adoption of regulations thereunder by the Federal Energy Regulatory Commission provided incentives for the development of cogeneration facilities and small power production
facilities using alternative or renewable fuels by establishing certain exemptions from the Federal Power Act and the Public Utility Holding Company Act for the owners of qualifying facilities. The
passage of the Energy Policy Act in
1992 further encouraged independent power production by providing additional exemptions from the Public Utility Holding Company Act for exempt wholesale generators and foreign utility companies.

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A"qualifying facility"under the Public Utility Regulatory Policies Act is a cogeneration facility or a small power production facility
that satisfies criteria adopted by the Federal Energy Regulatory Commission. In order to be a qualifying facility, a cogeneration facility must (i) sequentially produce both useful thermal
energy, such as steam, and electric energy, (ii) meet specified operating standards, and energy efficiency standards when oil or natural gas is used as a fuel source and (iii) not be
controlled, or more than 50% owned by one or more electric utilities (where "electric utility" is interpreted with reference to the Public Utility Holding Company Act definition of an "electric
utility company"), electric utility holding companies (defined by reference to the Public Utility Holding Company Act definitions of "electric utility company" and "holding company") or affiliates of
such entities.

An "exempt wholesale generator"under the Public Utility Holding Company Act is an entity determined by the Federal Energy Regulatory
Commission to be exclusively engaged, directly or indirectly, in the business of owning and/or operating specified eligible facilities and selling electric energy at wholesale or, if located in a
foreign country, at wholesale or retail.

A"foreign utility company"under the Public Utility Holding Company Act is, in general, an entity located outside the United States that
owns or operates facilities used for the generation, distribution or transmission of electric energy for sale or the distribution at retail of natural or manufactured gas, but that derives none of its
income, directly or indirectly, from such activities within the United States.

Federal Power ActThe Federal Power Act grants the Federal Energy Regulatory Commission exclusive jurisdiction over the rates,
terms and conditions of wholesale sales of electricity and transmission services in interstate commerce, including ongoing, as well as initial, rate jurisdiction. This jurisdiction allows the Federal
Energy Regulatory Commission to revoke or modify previously approved rates after notice and opportunity for hearing. These rates may be based on a cost-of-service approach or,
in geographic and product markets determined by Federal Energy Regulatory Commission to be workably competitive, may be market-based. As noted, most qualifying facilities are exempt from the
ratemaking and several other provisions of the Federal Power Act. Exempt wholesale generators and other non-qualifying facility independent power projects are subject to the Federal Power
Act and to the ratemaking jurisdiction of the Federal Energy Regulatory Commission thereunder, but the Federal Energy Regulatory Commission typically grants exempt wholesale generators the authority
to charge market-based rates to purchasers which are not affiliated electric utility companies as long as the absence of market power is shown. In addition, the Federal Power Act grants the Federal
Energy Regulatory Commission jurisdiction over the sale or transfer of jurisdictional facilities, including wholesale power sales contracts, and in some cases, jurisdiction over the issuance of
securities or the assumption of specified liabilities and some interlocking directorates. In granting authority to make sales at market-based rates, the Federal Energy Regulatory Commission typically
also grants blanket approval for the issuance of securities and partial waiver of the restrictions on interlocking directorates.
The Federal Energy Regulatory Commission has indicated its intention to review some of the waivers of financial reporting rules currently granted to some entities with market rate authority.

Currently,
in addition to the facilities owned or operated by EME, a number of its operating projects, including the Homer City facilities, the Illinois Plants, and Brooklyn Navy Yard
facilities, are subject to the Federal Energy Regulatory Commission ratemaking regulation under the Federal Power Act. EME's future domestic non-qualifying facility independent power
projects will also be subject to Federal Energy Regulatory Commission jurisdiction on rates.

The Public Utility Holding Company ActUnless exempt or found not to be a holding company by the Securities and Exchange
Commission, a company that falls within the definition of a holding company must register with the Securities and Exchange Commission and become subject to Securities and Exchange Commission
regulation as a registered holding company under the Public Utility Holding Company Act."Holding company"is defined in Section 2(a)(7) of the
Public Utility Holding Company

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Act to include, among other things, any company that owns 10% or more of the voting securities of an electric utility company."Electric utility
company"is defined in Section 2(a)(3) of the Public Utility Holding Company Act to include any company that owns or operates facilities used for generation,
transmission or distribution of electric energy for sale. Exempt wholesale generators and foreign utility companies are not deemed to be electric utility companies, and ownership or operation of
qualifying facilities does not cause a company to become an electric utility company. Securities and Exchange Commission precedent also indicates that it does not consider "paper facilities," such as
contracts and tariffs used to make power sales, to be facilities used for the generation, transmission or distribution of electric energy for sale, and power marketing activities will not, therefore,
result in an entity being deemed to be an electric utility company.

A
registered holding company is required to limit its utility operations to a single integrated utility system and to divest any other operations not functionally related to the
operation of that utility system. In addition, a registered holding company will require Securities and Exchange Commission approval for the issuance of securities, other major financial or business
transactions (such as mergers) and transactions between and among the holding company and holding company subsidiaries.

Edison
International, EME's ultimate parent company, is a holding company because it owns Southern California Edison, an electric utility company. However, Edison International is exempt
from registration pursuant to Section 3(a)(1) of the Public Utility Holding Company Act, because the public utility operations of the holding company system are predominantly intrastate in
character. Consequently, EME is not a subsidiary of a registered holding company, so long as Edison International continues to be exempt from registration pursuant to Section 3(a)(1) or another
of the exemptions enumerated in Section 3(a). EME is not a holding company under the Public Utility Holding Company Act, because its interests in power generation facilities are exclusively in
qualifying facilities, facilities owned by exempt wholesale generators and facilities owned by foreign utility companies. All international projects and specified U.S. projects that EME might develop
or acquire will be non-qualifying facility independent power projects. EME intends for each project to qualify as an exempt wholesale generator or as a foreign utility company. Loss of
exempt wholesale generator,
qualifying facility or foreign utility company status for one or more projects could result in EME's becoming a holding company subject to registration and regulation under the Public Utility Holding
Company Act and could trigger defaults under the covenants in EME's project agreements. Becoming a holding company could, on a retroactive basis, lead to, among other things, fines and penalties and
could cause certain of EME's project agreements and other contracts to be voidable.

Public Utility Regulatory Policies Act of 1978The Public Utility Regulatory Policies Act provides two primary benefits to
qualifying facilities. First, as discussed above, ownership of qualifying facilities will not cause a company to be deemed an electric utility company for purposes of the Public Utility Holding
Company Act. In addition, all cogeneration facilities that are qualifying facilities are exempt from most provisions of the Federal Power Act and regulations of the Federal Energy Regulatory
Commission thereunder. Second, the Federal Energy Regulatory Commission regulations promulgated under the Public Utility Regulatory Policies Act require that electric utilities purchase electricity
generated by qualifying facilities at a price based on the purchasing utility's avoided cost, and that the utilities sell back up power to the qualifying facility on a nondiscriminatory basis. The
Federal Energy Regulatory Commission's regulations define "avoided cost" as the incremental cost to an electric utility of electric energy or capacity, or both, which, but for the purchase from the
qualifying facility or qualifying facilities, the utility would generate itself or purchase from another source. The Federal Energy Regulatory Commission's regulations also permit qualifying
facilities and utilities to negotiate agreements for utility purchases of power at prices different from the utility's avoided costs. While it has been common for utilities to enter into
long-term contracts with qualifying facilities in order, among other things, to facilitate project financing of independent power facilities and to reflect the deferral by the utility of
capital costs for new plant additions, increasing competition and the

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development of new power markets have resulted in a trend toward shorter term power contracts that would place greater risk on the project owner.

If
one of the projects in which EME has an interest were to lose its status as a qualifying facility, the project would no longer be entitled to the qualifying facility-related
exemptions from regulation under the Public Utility Holding Company Act and the Federal Power Act. As a result, the project could become subject to rate regulation by the Federal Energy Regulatory
Commission under the Federal Power Act, and EME could inadvertently become a holding company under the Public Utility Holding Company Act. Under Section 26(b) of the Public Utility Holding
Company Act, any project contracts that are entered into in violation of the Public Utility Holding Company Act, including contracts entered into during any period of non-compliance with
the registration requirement, could be determined by the courts or the Securities and Exchange Commission to be void. If a project were to lose its qualifying facility status, EME could attempt to
avoid holding company status on a prospective basis by qualifying the project owner as an exempt wholesale generator. However, assuming this changed status would be permissible under the terms of the
applicable power sales agreement, rate approval from the Federal Energy Regulatory Commission would be required. In addition, the project would be required to cease selling electricity to any retail
customers, in order to qualify for exempt wholesale generator status, and could become subject to additional state regulation. Loss of qualifying facility status by one project could also potentially
cause other projects with the same partners to lose their qualifying facility status to the extent those partners became electric utilities, electric utility holding companies or affiliates of such
companies for purposes of the ownership criteria applicable to qualifying facilities. Loss of qualifying facility status could also trigger defaults under covenants to maintain qualifying facility
status in the project's power sales agreements, steam sales agreements and financing agreements and result in termination, penalties or acceleration of indebtedness under such
agreements. If a power purchaser were to cease taking and paying for electricity or were to seek to obtain refunds of past amounts paid because of the loss of qualifying facility status, EME cannot
provide assurance that the costs incurred in connection with the project could be recovered through sales to other purchasers. Moreover, EME's business and financial condition could be adversely
affected if regulations or legislation were modified or enacted that changed the standards for maintaining qualifying facility status or that eliminated or reduced the benefits, such as the mandatory
purchase provisions of the Public Utility Regulatory Policies Act and exemptions currently enjoyed by qualifying facilities. Loss of qualifying facility status on a retroactive basis could lead to,
among other things, fines and penalties being levied against EME, or claims by a utility customer for the refund of payments previously made.

EME
endeavors to develop its qualifying facility projects, monitor regulatory compliance by these projects and choose its customers in a manner that minimizes the risks of losing these
projects' qualifying facility status. However, some factors necessary to maintain qualifying facility status are subject to risks of events outside EME's control. For example, loss of a thermal energy
customer or failure of a thermal energy customer to take required amounts of thermal energy from a cogeneration facility that is a qualifying facility could cause a facility to fail to meet the
requirements regarding the minimum level of useful thermal energy output. Upon the occurrence of this type of event, EME would seek to replace the thermal energy customer or find another use for the
thermal energy that meets the requirements of the Public Utility Regulatory Policies Act.

Natural Gas ActMany of the domestic operating facilities that EME owns, operates or has investments in use natural gas as
their primary fuel. Under the Natural Gas Act, the Federal Energy Regulatory Commission has jurisdiction over certain sales of natural gas and over transportation and storage of natural gas in
interstate commerce. The Federal Energy Regulatory Commission has granted blanket authority to all persons to make sales of natural gas without restriction but continues to exercise significant
oversight with respect to transportation and storage of natural gas services in interstate commerce.

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Recent Foreign Regulatory Matters

See the discussion on recent foreign regulatory matters in "Item 7. Management's Discussion and Analysis of Results of Operations and Financial
ConditionMarket Risk Exposures."

Transmission of Wholesale Power

Generally, projects that sell power to wholesale purchasers other than the local utility to which the project is interconnected require the transmission of
electricity over power lines owned by others. This
transmission service over the lines of intervening transmission owners is also known as wheeling. The prices and other terms and conditions of transmission contracts are regulated by the Federal
Energy Regulatory Commission when the entity providing the wheeling service is a jurisdictional public utility under the Federal Power Act.

Until
1992, the Federal Energy Regulatory Commission's ability to compel wheeling was very limited, and the availability of voluntary wheeling service could be a significant factor in
determining whether a site was viable for project development. The Federal Energy Regulatory Commission's authority under the Federal Power Act to require electric utilities to provide transmission
service on a case-by-case basis to qualifying facilities, exempt wholesale generators, and other power generators was expanded substantially by the Energy Policy Act.
Furthermore, in 1996 the Federal Energy Regulatory Commission issued Order No. 888, in which the Commission asserted the power, under its authority to eliminate undue discrimination in
transmission, to compel all jurisdictional public utilities under the Federal Power Act to file open access transmission tariffs consistent with a pro forma tariff drafted by the Federal Energy
Regulatory Commission. The Federal Energy Regulatory Commission subsequently issued Order Nos. 888-A, 888-B and 888-C to clarify the terms that jurisdictional
transmitting utilities are required to include in their open access transmission tariffs. The Federal Energy Regulatory Commission also issued Order No. 889, which required those transmitting
utilities to abide by specified standards of conduct when using their own transmission systems to make wholesale sales of power, and to post specified transmission information, including information
about transmission requests and availability, on a publicly available computer bulletin board.

In
issuing Order No. 888et al., the Federal Energy Regulatory Commission determined that the open-access rules set
forth in the order would apply to transmission with respect to wholesale sales and also with respect to retail transactions where the transmission component had been unbundled from the retail sale by
state regulatory action or voluntarily by the utility making the retail sale. The Commission declined to assert jurisdiction over retail transmission service whose costs were included in the delivered
price of energy to the end user (i.e., costs that remained "bundled" into the retail sale). Subsequent court appeals of Order No. 888 were brought by parties challenging the order on the basis
that the Commission had no authority to regulate the transmission of unbundled retail sales and by parties challenging the Commission's failure to include the transmission of bundled retail sales in
the order. On June 30, 2000, the U.S. Court of Appeals for the District of Columbia Circuit upheld the decision by the Federal Energy Regulatory Commission in both respects, finding that the
Commission did have jurisdiction to regulate transmission of unbundled retail transactions, and that it was not required to assert jurisdiction over transmission embedded in bundled retail sales. In
an opinion issued on March 4, 2002, the Supreme Court affirmed the decision of the U.S. Court of Appeals.

While
Order No. 888 was pending judicial review, it became apparent to the Federal Energy Regulatory Commission that relying exclusively on the Order No. 888 requirement to
file open access tariffs was not having the desired effects of eliminating discriminatory behavior by transmission-owning utilities and promoting the development of competitive wholesale electricity
markets. Accordingly, in an effort to remedy the shortcomings it perceived, the Commission, on December 20, 1999, issued Order No. 2000, which required all jurisdictional
transmission-owning utilities to file by December 15, 2000, a statement of their plans with respect to placing functional control over their transmission assets under a

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Regional Transmission Organization, or RTO, meeting certain criteria set forth in the order. Although Order No. 2000 did not mandate that a utility join an RTO, it set forth various incentives
for voluntary action by utilities to take such action and required them to explain in detail their reasons for deviating from the objectives set forth in the order. RTOs meeting the Commission's
criteria in Order No. 2000 were required to be operationally independent of the transmission-owning utilities whose assets they controlled and to possess other essential attributes, such as
regional scope and configuration, the authority to receive and rule upon requests for service, a separate tariff governing all transactions of the RTO, a market monitoring capability, and other
features. In subsequent orders, the Commission has progressively tightened its policies in favor of RTO formation, by such means as an explicit proposal that approvals of market-based rate authority
for affiliates of utilities owning transmission should be tied to such utilities' placing functional control over their transmission assets in an RTO meeting the criteria of Order No. 2000.

On
July 31, 2002, the Federal Energy Regulatory Commission issued a Notice of Proposed Rulemaking having the stated purpose of remedying the remaining opportunities for undue
discrimination in transmission and establishing a standardized transmission service and wholesale market design (SMD) that would provide a "level playing field" for all entities that seek to
participate in wholesale electric markets. The SMD proposal includes a number of features that, taken together, should provide a flexible transmission service and an open and transparent spot market
design that convey the right pricing signals for investment in transmission and generation facilities, and for other purposes. Comments on certain features of the SMD proposal were filed by interested
parties in October 2002 and during the first quarter of 2003. The SMD proposal has also engendered considerable comment, and in some cases opposition, including in Congress, and the anticipated
timetable for issuance of a final rule is now unclear. The Federal Energy Regulatory Commission recently indicated its intention to publish a "White Paper" in April 2003 setting forth its plans
for SMD implementation. Whether adopted in its current or a modified form, it may take several years before the SMD model becomes fully operational in all regions of the country. These and other
regulatory initiatives by the Federal Energy Regulatory Commission are ongoing, and it is not possible to predict the extent of future developments or how they might affect the wholesale power
business.

Retail Competition

In response to pressure from retail electric customers, particularly large industrial users, the state commissions or state legislatures of many states have
considered whether to open the retail electric power market to competition. Retail competition is possible when a customer's local utility agrees, or is required, to unbundle its distribution service
(for example, the delivery of electric power through its local distribution lines) from its transmission and generation service (for example, the provision of electric power from the utility's
generating facilities or wholesale power purchases). Several state commissions and legislatures have issued orders or passed legislation requiring utilities to offer unbundled retail distribution
service, which is called retail wheeling, and phasing in retail wheeling over the next several years.

The
competitive pricing environment that will result from retail competition may cause utilities to experience revenue shortfalls and deteriorating creditworthiness. However, EME expects
that most, if not all, state plans will insure that utilities receive sufficient revenues, through a distribution surcharge if necessary, to pay their obligations under existing long-term
power purchase contracts with qualifying
facilities and exempt wholesale generators. On the other hand, qualifying facilities and exempt wholesale generators may be subject to pressure to lower their contract prices in an effort to reduce
the stranded investment costs of their utility customers. Recent volatility in California and other regional power markets has resulted in several states slowing, and in some cases reversing, their
plans to allow retail competition.

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Environmental Matters and Regulations

See the discussion on environmental matters and regulations in "Item 7. Management's Discussion and Analysis of Results of Operations and Financial
ConditionEnvironmental Matters and Regulations."

Employees

MEHC has no full-time employees. At December 31, 2002, EME and its subsidiaries employed 2,662 people, all of whom were full-time
employees and 180, 148 and 1,022 of whom were covered by collective bargaining agreements in the United Kingdom, Australia and the United States, respectively.

MEHC's and EME's Relationship with Certain Affiliated Companies

Both MEHC and EME are indirect subsidiaries of Edison International. Edison International is a holding company. Edison International is also the corporate parent
of Southern California Edison, an electric utility that serves customers in California.

ITEM 2. PROPERTIES

MEHC's principal office is in Irvine, California.

EME
leases its principal office in Irvine, California. This lease covers approximately 147,000 square feet. The term of the lease for approximately 65,500 square feet expires on
December 31, 2004 with two five-year options to extend. The term of the lease for the balance of approximately 81,500 square feet expires on December 31, 2004 with no options
to extend. EME also leases office space in Chicago, Illinois; Chantilly, Virginia and Boston, Massachusetts. The Chicago lease is for approximately 51,000
square feet and expires on December 31, 2009. The Chantilly lease is for approximately 30,000 square feet and expires on March 31, 2010. The Boston lease is for approximately 42,000
square feet and expires on July 31, 2007. At December 31, 2002, approximately 30% of the above space was either available for sublease or subleased.

The
following table shows the material properties owned or leased by EME's subsidiaries and affiliates. Each property represents at least five percent of EME's income before tax or is
one in which EME has an investment balance greater than $50 million. Most of these properties are subject to mortgages or other liens or encumbrances granted to the lenders providing financing
for the plant or project.

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Description of Properties

|Plant              |  | Business
Segment |  | Location                         |  | Interest
In Land |  | Plant Description                          
|------------------ |  | ---------------- |  | -------------------------------- |  | ---------------- |  | -------------------------------------------
|Brooklyn Navy Yard |  | Americas         |  | Brooklyn, New York               |  | Leased           |  | Natural gas-turbine cogeneration facility  
|CBK                |  | Asia             |  | Ratchaburi Province, Philippines |  | Leased           |  | Hydro generation facility                  
|Coalinga           |  | Americas         |  | Coalinga, California             |  | Leased           |  | Natural gas-turbine cogeneration facility  
|Contact Energy     |  | Asia Pacific     |  | Wellington, New Zealand          |  | Owned/Leased     |  | Various                                    
|Derwent            |  | Europe           |  | Derby, England                   |  | Leased           |  | Natural gas-turbine cogeneration facility  
|Doga               |  | Europe           |  | Esenyurt, Turkey                 |  | Owned            |  | Combined cycle generation facility         
|EcoEléctrica       |  | Americas         |  | Peñuelas, Puerto Rico            |  | Owned            |  | Liquefied natural gas cogeneration facility
|First Hydro        |  | Europe           |  | Dinorwig, Wales                  |  | Owned            |  | Pumped-storage electric power facility     
|First Hydro        |  | Europe           |  | Ffestiniog, Wales                |  | Owned            |  | Pumped-storage electric power facility     
|Gordonsville       |  | Americas         |  | Gordonsville, Virginia           |  | Leased           |  | Natural gas-turbine cogeneration facility  
|Homer City         |  | Americas         |  | Pittsburgh, Pennsylvania         |  | Owned            |  | Coal fired generation facility             
|Illinois Plants    |  | Americas         |  | Northeast Illinois               |  | Owned            |  | Coal, oil/gas fired generation facilities  
|ISAB               |  | Europe           |  | Sicily, Italy                    |  | Owned            |  | Integrated gasification combined cycle     
|IVPC4              |  | Europe           |  | Italy                            |  | Leased           |  | Wind generation facilities                 
|Kern River         |  | Americas         |  | Oildale, California              |  | Leased           |  | Natural gas-turbine cogeneration facility  
|Kwinana            |  | Asia             |  | Perth, Australia                 |  | Leased           |  | Gas-fired cogeneration facility            
|Loy Yang B         |  | Asia Pacific     |  | Victoria, Australia              |  | Owned            |  | Coal fired generation facility             
|March Point        |  | Americas         |  | Anacortes, Washington            |  | Leased           |  | Natural gas turbine cogeneration facility  
|Mid-Set            |  | Americas         |  | Fellows, California              |  | Leased           |  | Natural gas-turbine cogeneration facility  
|Midway-Sunset      |  | Americas         |  | Fellows, California              |  | Leased           |  | Natural gas-turbine cogeneration facility  
|Paiton             |  | Asia Pacific     |  | East Java, Indonesia             |  | Leased           |  | Coal fired generation facility             
|Salinas River      |  | Americas         |  | San Ardo, California             |  | Leased           |  | Natural gas-turbine cogeneration facility  
|Sargent Canyon     |  | Americas         |  | San Ardo, California             |  | Leased           |  | Natural gas-turbine cogeneration facility  
|Sunrise            |  | Americas         |  | Fellows, California              |  | Leased           |  | Simple cycle generation facility           
|Sycamore           |  | Americas         |  | Oildale, California              |  | Leased           |  | Natural gas-turbine cogeneration facility  
|Tri Energy         |  | Asia             |  | Laguna Province, Thailand        |  | Owned            |  | Natural gas-turbine cogeneration facility  
|Watson             |  | Americas         |  | Carson, California               |  | Leased           |  | Natural gas-turbine cogeneration facility  

ITEM 3. LEGAL PROCEEDINGS

Brooklyn Navy Yard Project

Brooklyn Navy Yard is a 286 MW gas-fired cogeneration power plant in Brooklyn, New York. A wholly owned subsidiary of EME owns 50% of the project. In
February 1997, the construction contractor asserted general monetary claims under the turnkey agreement against Brooklyn Navy Yard Cogeneration Partners, L.P. for damages in the amount of
$137 million. Brooklyn Navy Yard has also filed an action 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, in the Supreme Court of the State of New York, Kings County, Index No. 5966/97 asserting general monetary claims in excess
of $13 million under the construction turnkey agreement. Trial was scheduled for October 21, 2002, and rescheduled for January 2003. In December 2002, the parties held
mediation
sessions and settled the litigation. A settlement agreement was executed on January 17, 2003, which was followed by the dismissal of both the New York and the California litigation and release
of the writs of attachment.

EcoEléctrica Potential Environmental Proceeding

EME owns an indirect 50% interest in EcoEléctrica, L.P., a limited partnership which owns and operates a liquefied natural gas import terminal and
cogeneration project at Peñuelas, Puerto Rico. In 2000, the U.S. Environmental Protection Agency issued to EcoEléctrica a notice of violation and a compliance order
alleging violations of the Federal Clean Air Act primarily related to start-up activities. Representatives of EcoEléctrica have met with the Environmental Protection Agency
to discuss the notice of violations and compliance order. On August 15, 2002, the U.S. Department of

29

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Justice notified EcoEléctrica that it was preparing to bring a federal court action for violations of the Clean Air Act and regulations promulgated thereunder, and requested a meeting
with EcoEléctrica to discuss and possibly settle the matter. The initial meeting with the Department of Justice took place on January 15, 2003. Settlement discussions have
continued in 2003.

Regulatory Developments Affecting Sunrise Power Company

Sunrise Power Company, in which a wholly owned subsidiary of EME owns a 50% interest, sells all its output to the California Department of Water Resources under a
power purchase agreement entered into on June 25, 2001. On February 25, 2002, the California Public Utilities Commission and the California Electricity Oversight Board filed complaints
with the Federal Energy Regulatory Commission against all sellers of power under long-term contracts to the California Department of Water Resources, including Sunrise Power Company. The
California Public Utilities Commission complaint alleged that the contracts were "unjust and unreasonable" on price and other terms, and requested that the contracts be abrogated. The California
Electricity Oversight Board complaint made a similar allegation and requested that the contracts be deemed voidable at the request of the California Department of Water Resources or, in the
alternative, abrogated as of a future date to allow for the possibility of renegotiation. In January 2003, the California Public Utilities Commission and the California Electricity Oversight
Board dismissed their complaints against Sunrise Power Company pursuant to a global settlement that also involved a restructuring of Sunrise Power Company's long-term contract with the
California Department of Water Resources. On December 31, 2002, Sunrise Power Company restructured its contract with the California Department of Water Resources. The restructured agreement
reduced by 5% the capacity payments to be made to Sunrise Power Company as compensation for having power available when needed. In addition, Sunrise Power Company's option to extend the agreement for
one year beyond December 31, 2011 was terminated; however, the term of the restructured agreement was extended until June 30, 2012.

On
May 2, 2002, the United States Justice Foundation announced that it had filed a complaint in the Superior Court of the State of California, Los Angeles County, against the
California Department of
Water Resources, all sellers of power under long-term energy contracts entered into in 2001, including Sunrise Power Company, and Vikram Budhraja, one of the consultants involved in the
negotiation of energy contracts on behalf of the California Department of Water Resources. The lawsuit asks the Superior Court to void all the contracts entered into in 2001, as well as all the
contracts renegotiated in 2002, as a result of a purported conflict of interest by Mr. Budhraja. Sunrise Power Company has not yet been served with the complaint.

On
May 15, 2002, Sunrise Power Company was served with a complaint filed in the Superior Court of the State of California, City and County of San Francisco, by James M. Millar,
"individually, and on behalf of the general public and as a representative taxpayer suit" against sellers of long-term power to the California Department of Water Resources, including
Sunrise Power Company. The lawsuit alleges that the defendants, including Sunrise Power Company, engaged in unfair and fraudulent business practices by knowingly taking advantage of a manipulated
power market to obtain unfair contract terms. The lawsuit seeks to enjoin enforcement of the "unfair and oppressive terms and conditions" in the contracts, as well as restitution by the defendants of
excessive monies obtained by the defendants. Plaintiffs in several other class action lawsuits pending in Northern California have filed petitions seeking to have the Millar lawsuit consolidated with
those lawsuits. The defendants in the Millar lawsuit and other class action suits removed all the lawsuits to the U.S. District Court, Northern District of California, and filed a motion to stay all
proceedings pending final resolution of the jurisdictional issue. Various plaintiffs have filed pleadings opposing the removal and requesting that the matters be remanded to state court. The motions
are still pending.

30

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Paiton Labor Suit

In April 2001, Paiton Energy was sued in the Central Jakarta District Court by the PLN Labor Union. PT PLN, the Indonesian Minister of Mines and Energy and
the former President Director of PT PLN are also named as defendants in the suit. The union seeks to set aside the power purchase agreement between Paiton Energy and PT PLN and the interim agreement
then in effect between Paiton Energy and its lenders, as well as damages and other relief. On April 16, 2002 the Central Jakarta District Court dismissed the lawsuit against Paiton Energy and
the other defendants on the basis that the PLN Labor Union was not authorized under the law to bring such an action. The PLN Labor Union filed an appeal on April 23, 2002. In order for the
Appeals Court to hear any appeal on the matter, the District Court must have certified its judgment and forwarded it to the Appeals Court.

While
Paiton Energy has not, to date, received notice of any change in jurisdiction, it now appears that jurisdiction has passed to the appellate court. The appellate court has not
indicated when, or if, it will move on the PLN Labor Union's appeal. Paiton Energy continues to believe that the District Court's decision was grounded on the applicable legal bases and should
withstand any appellate scrutiny.

ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS

Inapplicable.

31

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PART II

ITEM 5. MARKET FOR REGISTRANT'S COMMON EQUITY AND RELATED STOCKHOLDER MATTERS

All the outstanding common stock of Mission Energy Holding Company (MEHC) is, as of the date hereof, owned by MEHC's direct parent, The Mission Group, a wholly
owned subsidiary of Edison International. There is no market for the common stock. Dividends on the common stock will be paid when declared by MEHC's board of directors. MEHC's wholly owned
subsidiary, Edison Mission Energy (EME), made cash dividend payments to MEHC's parent, The Mission Group, totaling $65 million and $88 million during 2001 and 2000, respectively. MEHC
paid two dividends to The Mission Group: (i) $811.2 million from the proceeds of the issuance of 13.5% senior secured notes and the term loan, and (ii) $31.5 million from
dividends received from EME after July 2, 2001. EME did not pay or declare any dividends to MEHC during 2002.

During
the first two years of MEHC's operations, when debt interest payments will be funded with restricted cash, MEHC is permitted to distribute to its direct parent, The Mission Group
dividends MEHC receives from EME, less MEHC's overhead costs subject to compliance with limitations contained in the senior secured notes indenture and in the term loan. Limitations on MEHC's ability
to pay dividends and make other distributions to its parent after July 15, 2003 are significantly more restrictive than the restrictions applicable during the first two years of its operations.
Dividends from EME may be limited based on its earnings and cash flow, terms of restrictions contained in EME's contractual obligations (including its corporate credit facility), charter documents,
business and tax considerations, and restrictions imposed by applicable law.

EME's
certificate of incorporation and bylaws require the unanimous approval of EME's board of directors, including at least one independent director, before EME can declare or pay
dividends or distributions, unless either of the following is true:



EME's
interest coverage ratio for the four quarters ended December 31, 2002 was 2.36 to 1. For more information on these restrictions, see "Item 7. Management's Discussion and
Analysis of Results of Operations and Financial ConditionEdison Mission Energy's Interest Coverage Ratio."

32

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ITEM 6. SELECTED FINANCIAL DATA

|                                                                                                                                    |  | Years Ended December 31, |      
|----------------------------------------------------------------------------------------------------------------------------------- |  | ------------------------ | -----
|
|
|INCOME STATEMENT DATA                                                                                                               |  |                          |      
|Operating revenues                                                                                                                  |  | $                        | 2,750
|Operating expenses                                                                                                                  |  |                          | 2,421
|                                                                                                                                    |  |                          |      
|Operating income                                                                                                                    |  |                          | 329  
|Equity in income from unconsolidated affiliates                                                                                     |  |                          | 283  
|Interest expense                                                                                                                    |  |                          | (633 
|Interest and other income                                                                                                           |  |                          | 31   
|                                                                                                                                    |  |                          |      
|Income from continuing operations before income taxes and minority interest                                                         |  |                          | 10   
|Provision (benefit) for income taxes                                                                                                |  |                          | (20  
|Minority interest                                                                                                                   |  |                          | (27  
|                                                                                                                                    |  |                          |      
|Income from continuing operations                                                                                                   |  |                          | 3    
|Income (loss) from operations of discontinued foreign subsidiaries (including loss on disposal of $1.1 billion in 2001), net of tax |  |                          | (57  
|                                                                                                                                    |  |                          |      
|Income (loss) before accounting change                                                                                              |  |                          | (54  
|Cumulative effect of change in accounting, net of tax                                                                               |  |                          | (14  
|                                                                                                                                    |  |                          |      
|Net income (loss)                                                                                                                   |  | $                        | (68  
|                                                                                                                                    |  |                          |      

---

|                                     |  | As of December 31,
|------------------------------------ |  | ------------------
|
|
|BALANCE SHEET DATA                   |  |                   
|Assets                               |  | $                 
|Current liabilities                  |  |                   
|Long-term obligations                |  |                   
|Preferred securities of subsidiaries |  |                   
|Shareholder's equity                 |  |                   

33

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ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF RESULTS OF OPERATIONS AND FINANCIAL CONDITION

The following discussion contains forward-looking statements. These statements are based on Mission Energy Holding Company's (MEHC's)
knowledge of present facts, current expectations about future events and assumptions about future developments. Forward-looking statements are not guarantees of performance; they are subject to risks,
uncertainties and assumptions that could cause actual future activities and results of operations to be materially different from those set forth in this discussion. Important factors that could cause
actual results to differ include risks set forth in "Market Risk ExposuresRisk Factors."

The presentation of information below pertaining to Edison Mission Energy (EME) and its consolidated subsidiaries should not be understood to mean that EME has
agreed to pay or become liable for any debt of MEHC. EME and MEHC are separate entities with separate obligations. MEHC is the sole obligor on the 13.50% senior secured notes due 2008 and the
$385 million term loan due 2006, and neither EME nor any of its subsidiaries or other investments has any obligation with respect to the notes or the term loan.

GENERAL

MEHC was formed as a wholly owned subsidiary of The Mission Group, which is a wholly owned subsidiary of Edison International. MEHC was formed to:



On
July 2, 2001, The Mission Group contributed to MEHC all the outstanding common stock of EME. The contribution of EME's common stock to MEHC has been accounted for as a transfer
of ownership of companies under common control, which is similar to a pooling of interest. This means that MEHC's historical financial results of operations and financial position will include the
historical financial results and results of operations of EME and its subsidiaries as though MEHC had such ownership throughout the periods presented. MEHC's only substantive liabilities are its
obligations under the senior secured notes, the term loan and corporate overhead, including fees of its legal counsel, auditors and other advisors. MEHC does not have any substantive operations other
than through EME and its subsidiaries and other investments.

EME
is an independent power producer engaged in the business of owning or leasing and operating electric power generation facilities worldwide. EME also conducts price risk management
and energy trading activities in power markets open to competition. Edison International is EME's ultimate parent company. Edison International also owns Southern California Edison Company, one of the
largest electric utilities in the United States.

As
of December 31, 2002, EME owned or leased interests in 28 domestic and 53 international operating power plants with an aggregate generating capacity of 23,561 megawatts (MW),
of which EME's share was 18,688 MW. At that date, one domestic and two international power plants, totaling 615 MW of generating capacity, of which EME's anticipated share will be approximately 308
MW, were in construction.

Current Developments

A number of significant developments during late 2001 and 2002 have adversely affected independent power producers and subsidiaries of major integrated energy
companies that sell a sizable

34

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portion of their generation into the wholesale energy market (sometimes referred to as merchant generators), including several of EME's subsidiaries, as discussed below. These developments included
lower market prices in wholesale energy markets both in the United States and United Kingdom, significant declines in the credit ratings of most major market participants, decreased availability of
debt financing or refinancing, and a resulting decline of liquidity in the energy markets due to growing concern about the ability of counterparties to perform their obligations. In response to these
developments, many merchant generators and power trading firms have announced plans to improve their financial position through asset sales, the cancellation or deferral of substantial new
development, significant reduction in or elimination of trading activities, decreases in capital expenditures, including cancellations of orders for new turbines, and reductions in operating costs. In
early 2003, wholesale energy prices have increased primarily due to colder-than-normal weather and increases in the prices for natural gas. However, the recent changes in
wholesale energy prices may or may not continue throughout 2003. See "Market Risk Exposures" for more information regarding forward market prices.

EME's Situation

Because of the 2000-2001 California power crisis and its indirect effect on EME and its subsidiaries, EME de-emphasized the development
and acquisition of projects and focused primarily on enhancing the performance of its existing projects and on maintaining credit quality. As a result, during 2001 and early 2002, EME completed the
sale of several non-strategic project investments. During 2002, EME undertook a further effort to reduce corporate overhead and other expenditures across the organization and to reduce
debt.

In
2002, EME was affected by lower wholesale prices of energy and capacity, particularly at its Homer City facilities in Pennsylvania, and by the diminished ability to enter into forward
contracts for the sale of power primarily from these facilities because of the credit constraints affecting EME and many of its counterparties. See "Market Risk
ExposuresAmericasHomer City Facilities."

EME's
Illinois Plants were largely unaffected by these developments in 2002, because Exelon Generation was under contract to buy substantially all of the capacity from these units during
the entire year. However, as permitted by the power purchase agreements, Exelon Generation advised EME that it will not purchase under contract 2,684 MW of capacity from EME's coal-fired
units and 1,864 MW of capacity from EME's Collins Station and small peaking units during 2003 and 2004. Exelon Generation has the further right to release 1,265 MW of capacity from EME's
coal-fired units and 1,778 MW of capacity from EME's Collins Station and small peaking units for 2004. As a result, beginning in 2003, the portion of EME's generation that will be sold
into the wholesale markets has significantly increased, thereby increasing EME's merchant risk. See "Market Risk ExposuresAmericasIllinois Plants."

As
a result of these and other factors, both Moody's Investors Service and Standard & Poor's Rating Service downgraded MEHC's credit rating, EME's credit rating and the credit
rating of its largest subsidiary, Edison Mission Midwest Holdings, to below investment grade. See "Liquidity and Capital ResourcesEdison Mission Energy's Credit Ratings."
Furthermore, MEHC's independent accountants' audit opinion for the year ended December 31, 2002, contains an explanatory paragraph that indicates the consolidated financial statements have been
prepared on the basis that MEHC will continue as a going concern and that the uncertainty about Edison Mission Midwest Holdings' ability to repay, extend or refinance Edison Mission Midwest Holdings'
$911 million of debt due in December 2003 raises substantial doubt about MEHC's ability to continue as a going concern. Accordingly, the consolidated financial statements do not include
any adjustments that might result from the resolution of this uncertainty. Within Item 8, see "Report of Independent Accountants" and "Mission Energy Holding Company and Subsidiaries Notes to
Consolidated Financial StatementsNote 10. Financial Instruments."

35

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Against
this background, EME has undertaken a number of actions to reduce its commitments and expenditures, thereby improving its cash flow. These actions include:



In
addition, EME continues to review the possibility of asset sales, but believes that current market conditions may inhibit its ability to obtain prices commensurate with its valuation
of those investments which EME might offer for sale. For a discussion of risk factors that affect EME's business, see "Risk Factors." For a discussion of EME's current financial
condition, see "Liquidity and Capital Resources."

Disposition of Investments in Energy Plants

During the first quarter of 2002, EME completed the sales of its 50% interests in the Commonwealth Atlantic and James River plants and its 30% interest in the
Harbor plant. Proceeds received from the sales were $44 million. During the second half of 2001, EME recorded asset impairment charges of $32 million related to these plants based on the
expected sales proceeds. No gain or loss was recorded from the sale of its interests in these plants during the first quarter of 2002.

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RESULTS OF OPERATIONS

CONSOLIDATED OPERATING RESULTS

Net Income Summary

Net income is comprised of the following components:

Years Ended December 31,2002

2001

2000(in millions)Mission Energy Holding Company:Loss from continuing operations

$
(93
)
$
(49
)
$
Edison Mission Energy and its Consolidated Subsidiaries:Income from continuing operations


96


83


65Income (loss) from discontinued operations


(57
)

(1,219
)

38Cumulative changes in accounting


(14
)

15


22Net Income (loss)

$
(68
)
$
(1,170
)
$
125


MEHC's
loss from continuing operations in 2002 was $93 million compared to $49 million in 2001. The 2002 increase in loss from continuing operations from 2001 was due to a
full year of interest expense in 2002 compared to a half year of interest expense in 2001, related to MEHC's $800 million senior secured notes and borrowings of $385 million under a term
loan, both entered into on July 2, 2001. MEHC had no comparable results in 2000.

EME's
income from continuing operations in 2002 was $96 million compared to $83 million in 2001 and $65 million in 2000. The 2002 increase in income from continuing
operations from 2001 was primarily due to improved operating results at EME's Illinois Plants and the Loy Yang B plants, income from the Paiton project in Indonesia, and lower state income taxes,
partially offset by lower west coast energy prices, unplanned outages at the Homer City facilities, 2001 gains related to gas swaps from EME's oil and gas activities and net after-tax
charges and credits during 2002 totaling $50 million. These after-tax charges and credits include a $66 million after-tax write-down of assets related
to the cancellation of turbine orders, the suspension of the SCR major capital improvements project at the Powerton Station, an impairment of goodwill, and a $27 million after-tax
loss from a settlement agreement that terminates the obligation to build additional generation in Chicago, partially offset by a gain of $43 million, after tax, from the settlement of a
postretirement employee benefit liability.

The
2001 increase in income from continuing operations from 2000 reflects higher energy prices for the Big 4 projects and increased earnings from oil and gas activities, partially offset
by lower energy prices and capacity payments in the United Kingdom, after-tax charges of $38 million related to the phantom stock option plan in 2000, and $15 million, after
tax, related to a loss on the termination of a portion of EME's Master Turbine Lease in 2001.

EME's
loss from discontinued operations in 2002 was $57 million compared to $1.2 billion in 2001 and income of $38 million in 2000. The 2002 loss from discontinued
operations primarily represents an after-tax asset impairment charge of $77 million related to the Lakeland project in the United Kingdom. The 2001 loss includes an
after-tax asset impairment charge of $1.2 billion related to the Ferrybridge and Fiddler's Ferry project in the United Kingdom. The 2000 income from discontinued operations is
related to the operations of Lakeland and Ferrybridge and Fiddler's Ferry projects in the United Kingdom.

37

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Operating Revenues

Operating revenues increased 11% in 2002 from 2001 and increased 14% in 2001 from 2000. Operating revenues in 2002 increased from 2001 primarily due to
consolidating Contact Energy operating revenue for a full year in 2002 as compared to a partial year in 2001 (EME's ownership interest increased to 51%, effective June 1, 2001), increased
revenues from the Illinois Plants and the First Hydro plant, partially offset by decreased revenues from Homer City. Operating revenues in 2001 increased from 2000 primarily due to consolidating
Contact Energy operating revenue for the first five months of 2001, as compared to the equity method of accounting in 2000, and higher revenues at Homer City, partially offset by lower revenues from
First Hydro.

Operating
revenues includes net gains (losses) from risk management and energy trading activities of $27 million in 2002, $36 million in 2001, and $(17) million in 2000.
Net gains and (losses) from price risk management activities result from recording derivatives at fair value under Statement of Financial Accounting Standards No. 133, "Accounting for
Derivative Instruments and Hedging Activities" (SFAS No. 133) or applicable generally accepted accounting principles prior to adoption of SFAS No. 133. Included in net gains (losses)
from price risk management were:



Net
gains from energy trading activities were $42 million in 2002, $10 million in 2001, and $62 million in 2000.The increase in net gains from energy trading
activities in 2002 from 2001 was primarily due to
completing the restructuring of a power sales agreement with an unaffiliated electric utility during the first quarter of 2002. As part of the transaction, an EME subsidiary purchased the power sales
agreement held by a third party, modified its terms and conditions, and entered into a long-term power supply agreement with another party. Although the sale and purchase of power arising
from these contracts will occur over their term, net gains of $22 million were recorded in 2002 attributable to the fair value of the contracts (generally referred to as
mark-to-market accounting). Net gains in 2002 also increased from 2001 as a result of realized gains from transmission congestion contracts. Net gains in 2001 decreased from
2000 primarily due to a reduction in trading activity in 2001 resulting from the adverse impact of the California power crisis on EME's credit, as well as higher gains in 2000 due to the volatility of
power prices in the west coast trading markets during the fourth quarter of 2000.

EME's
third quarter electric revenues are materially higher than revenues related to other quarters of the year because warmer weather during the summer months results in higher electric
revenues being generated from the Homer City facilities and the Illinois Plants. By contrast, the First Hydro plants and Contact Energy have higher electric revenues during their winter months.

38

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Operating Expenses

Fuel costs increased $129 million in 2002 from 2001, and increased $47 million in 2001 from 2000. Fuel costs in 2002 increased from 2001 primarily
due to consolidating Contact Energy fuel costs for a full year in 2002 as compared to a partial year in 2001 (EME's ownership interest increased to 51%, effective June 1, 2001), increased
pumping power costs from the First Hydro plant and increased fuel costs from the Illinois Plants, partially offset by decreased fuel costs from Homer City. Fuel costs in 2001 increased from 2000
primarily due to consolidating Contact Energy operating revenue for a partial year in 2001 as compared to the equity method of accounting in 2000 (EME's ownership interest increased to 51%, effective
June 1, 2001), partially offset by lower fuel costs at the Illinois Plants.

Plant
operations and transmission costs increased $58 million in 2002 from 2001, and increased $184 million in 2001 from 2000. Transmission costs were $186 million
in 2002, $99 million in 2001 and $33 million in 2000. The increases in transmission costs were primarily due to consolidating Contact Energy, effective June 1, 2001.

Plant
operating leases increased $73 million in 2002 from 2001, and increased $46 million in 2001 from 2000. The 2002 and 2001 increases were due to the
sale-leaseback transactions for the Homer City and Powerton-Joliet power facilities. There were no comparable lease costs for the Homer City facilities through the period ended
December 2001 and the Powerton-Joliet power facilities through the period ended August 2000. See "Off-Balance Sheet
TransactionsSale-Leaseback Transactions," for discussion of the financial impact of sale-leaseback transactions.

Depreciation
and amortization expense decreased $16 million in 2002 from 2001, and decreased $9 million in 2001 from 2000. The 2002 and 2001 decreases are primarily due to
lower depreciation expense from Homer City and the Illinois Plants related to the sale-leaseback transaction from Homer City in December 2001 and the Powerton-Joliet power
facilities in August 2000.

Long-term
incentive compensation expense consists of charges related to EME's terminated phantom option plan. Long-term incentive compensation expense increased
$62 million in 2001 compared to 2000. The 2001 increase was due to a reduction in the liability for previously accrued incentive compensation by approximately $60 million recorded during
2000 and additional 2002 and 2001 compensation expense related to deferred payments and annual vesting of benefits. The 2000 reduction resulted from the lower valuation implicit in the
August 2000 exchange offer pursuant to which the phantom option plan was terminated compared to the value previously accrued.

The
settlement of postretirement employee benefit liability relates to a retirement health care and other benefits plan for represented employees at the Illinois Plants that expired on
June 15, 2002. In October 2002, Midwest Generation reached an agreement with its union-represented employees on new benefits plans, which extend from January 1, 2003 through
June 30, 2005. Midwest Generation continued to provide benefits at the same level as those in the expired agreement until December 31, 2002. The accounting for postretirement benefits
liabilities has been determined on the basis of a substantive plan under Statement of Financial Accounting Standards No. 106, "Employers' Accounting for Postretirement Benefits Other Than
Pensions." A substantive plan means that Midwest Generation assumed, for accounting purposes, that it would provide for postretirement health care benefits to union-represented employees following
conclusion of negotiations to replace the current benefits agreement, even though Midwest Generation had no legal obligation to do so. Under the new agreement, postretirement health care benefits will
not be provided. Accordingly, Midwest Generation treated this as a plan termination under SFAS No. 106 and recorded a pre-tax gain of $71 million during the fourth quarter of
2002.

Asset
impairment and other charges were $131 million in 2002 and $59 million in 2001. Asset impairment and other charges in 2002 consisted of $61 million related to
the write-off of capitalized costs associated with the termination of the turbines from Siemens Westinghouse, $45 million in

39

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settlement of the In-City Obligation (refer to "Contractual Obligations, Commitments and ContingenciesChicago In-City Obligation," for further
discussion), and $25 million related to the write-off of capitalized costs associated with the suspension of the Powerton Station SCR major capital environmental improvements
project at the Illinois Plants. Asset impairment and other charges in 2001 consisted of $34 million to write down to the estimated net proceeds from the planned sale of the Commonwealth
Atlantic, Gordonsville, Harbor and James River projects and $25 million related to a loss on the termination of a portion of EME's Master Turbine Lease. There were no comparable asset
impairment and other charges in 2000.

Administrative
and general expenses decreased $7 million in 2002 from 2001 and increased $13 million in 2001 from 2000. The 2002 decrease was primarily due to lower
business development costs. There were no material changes in 2001 administrative and general expenses from 2000. EME recorded a pre-tax
charge of approximately $13 million in 2002 and $9 million in 2001 against earnings for severance and other related costs, which resulted from a series of actions undertaken to reduce
administrative and general operating costs, including reductions in management and administrative personnel.

Other Income (Expense)

Equity in income from unconsolidated affiliates decreased 24% in 2002 from 2001 and increased 40% in 2001 from 2000. The 2002 decrease was primarily due to a
decrease in EME's share of income from the Big 4 projects and Four Star Oil & Gas, partially offset by an increase in EME's share of income from the Paiton Energy and ISAB projects. The 2001
increase was primarily due to an increase in EME's share of income from the Big 4 projects and the ISAB project. EME's third quarter equity in income from its domestic energy projects is materially
higher than equity in income related to other quarters of the year due to warmer weather during the summer months and because a number of EME's domestic energy projects, located on the west coast,
have power sales contracts that provide for higher payments during the summer months.

Interest
and other income decreased $14 million in 2002 from 2001, and increased $10 million in 2001 from 2000. The 2002 decrease was primarily due to lower interest income
and foreign exchange losses from EME's intercompany loans. The 2001 increase was primarily due to higher interest income from interest earned on funds placed into an escrow account from the sale of
the senior secured notes and the term loan.

Gains
on sale of assets were $5 million, $41 million and $26 million in 2002, 2001 and 2000, respectively. The gain on sale of assets in 2002 represents the sale of
a development project in the United Kingdom during December 2002. Proceeds from the sale were $6 million. Gains on sale of assets for 2001 and 2000 included:

Project

Gross Proceeds

EME's Partnership
Interest Sold

DateNevada Sun-Peak

$
11

50
%
December 5, 2001Saguaro


67

50

September 20, 2001Hopewell


27

25

June 29, 2001Kwinana


12

30

August 16, 2000Auburndale


22

50

June 30, 2000


Gain
on early extinguishment of debt of $10 million in 2001 is attributable to the extinguishment of debt that was assumed by third-party lessors in the Homer City
sale-leaseback transaction on December 7, 2001. EME reclassified this amount in the fourth quarter of 2002 due to the early adoption of SFAS No. 145, "Rescission of FASB
Statements No. 4, 44 and 64, Amendment of FASB Statement No. 13, and Technical Corrections."

40

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Interest
expense decreased $13 million in 2002 compared to 2001 and increased $73 million in 2001 compared to 2000. The 2002 decrease was due to a combination of the
following: a reduction of $830 million in bonds assumed by the lessor in the sale-leaseback transaction of the Homer City facilities in December 2001, a reduction of
$350 million in EME's corporate debt from the proceeds of such transaction and lower borrowings by EME combined with lower interest rates on variable rate debt generally tied to LIBOR,
partially offset by higher interest margins as a result of EME's and Edison Mission Midwest Holdings' credit downgrades. See "Liquidity and Capital ResourcesEdison Mission
Energy's Credit Ratings." In addition, the 2002 decrease in interest expense at EME was almost entirely offset by a full year of interest expense related to MEHC's $800 million senior secured
notes
and borrowings of $385 million under a term loan, both entered into on July 2, 2001. MEHC had no comparable interest expense for the first six months of 2001. The 2001 increase primarily
reflects the issuance of MEHC's $800 million senior secured notes on July 2, 2001 and MEHC's borrowings of $385 million under a term loan entered into on July 2, 2001.

Dividends
on mandatorily redeemable preferred securities decreased $10 million in 2001 compared to 2000. The 2001 decrease reflects the redemption of the NZ$400 million EME
Taupo preferred securities in July 2001.

Income Taxes

MEHC had effective tax provision (benefit) rates of (200)% in 2002, 54% in 2001, and 53% in 2000. The effective income tax benefit rate in 2002 is due to
additional state tax benefits recorded by EME, net of federal income taxes, of $32 million resulting from changes in estimates of the 2001 and 2002 tax-allocation calculation
completed by Edison International. Under the tax-allocation agreement, EME's current state tax benefit is generally determined by using Edison International's combined state tax liability
and calculating the difference between including and excluding EME's taxable income or losses and state apportionment factors. During the third quarter of 2002, Edison International substantially
completed preparation of its 2001 combined state income tax returns and changed its 2002 estimated state income tax projection. EME expects that approximately $9 million of this benefit will
not be paid until 2005. There was no significant change in the effective income tax rate in 2001 from 2000.

Minority Interest

Minority interest expense increased $5 million in 2002 from 2001 and increased $19 million in 2001 from 2000. Minority interest primarily relates to
49% ownership of Contact Energy by the public in New Zealand. The 2002 and 2001 increase was due to accounting for Contact Energy on a consolidated basis, effective June 1, 2001, due to the
purchase of additional shares of Contact Energy that increased EME's ownership interest from 43% to 51%.

Discontinued Operations

Lakeland Project

EME's Lakeland project operated a 220 MW combined cycle, natural gas-fired power plant located in the United Kingdom. The assets of the project are
owned by EME's indirect subsidiary, Lakeland Power Ltd., which sold power generated from the plant pursuant to a power sales agreement with Norweb Energi Ltd., a subsidiary of TXU (UK)
Holdings Limited (TXU UK) and an indirect subsidiary of TXU Europe Group plc (TXU Europe).

On
November 19, 2002, TXU UK and TXU Europe, together with a related entity, TXU Europe Energy Trading Limited (TXU Energy), entered into formal administration proceedings in the
United Kingdom (similar to bankruptcy proceedings in the United States). As a result of these actions and

41

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their effect upon Norweb Energi Ltd. and EME's contractual arrangements with other parties, the Lakeland power plant suspended operations.

In
December 2002, the directors of Norweb Energi Ltd. appointed a liquidator to wind up its contractual rights and obligations. On December 4, 2002, Norweb
Energi Ltd. provided a notice of disclaimer of the power sales agreement under Section 178 of the Insolvency Act 1986. The disclaimer effectively terminated the power sales agreement.

On
December 19, 2002, the lenders to the Lakeland project accelerated the debt owing under the bank agreement that governs the project's indebtedness, and on December 20,
2002, the Lakeland project lenders appointed Michael Thomas Seery and Michael Vincent McLoughlin, partners with KPMG LLP, as administrative receiver over the assets of Lakeland Power Ltd. The
administrative receiver is appointed to take control of the affairs of Lakeland Power Ltd. and has a wide range of powers (specified in the Insolvency Act), including authorizing the sale of
the power plant. The appointment of the administrative receiver requires the treatment of the Lakeland power plant as an asset held for sale under Statement of Financial Accounting Standards
No. 144, "Accounting for the Impairment or Disposal of Long-Lived Assets" (SFAS No. 144). See "Mission Energy Holding Company and Subsidiaries Notes to Consolidated Financial
StatementsNote 7. Discontinued Operations."

The
bank loans of Lakeland Power Ltd. are non-recourse to EME. Furthermore, neither the defaults on these loans nor the institution of administrative proceedings
cross-default to any other indebtedness of EME or its affiliates.

The
events related to the Lakeland project resulted in an impairment charge of $92 million ($77 million after tax) and a provision for bad debts of $1 million, after
tax, in the fourth quarter of 2002 arising from the write-down of the Lakeland power plant and related claims under the power sales agreement (an asset group under SFAS No. 144) to
their fair market value. Due to EME's loss of control arising
from the appointment of the administrative receiver, EME no longer consolidates the activities of Lakeland Power Ltd.

The
following table is a condensed income statement of the Lakeland project for the three years ended December 31, 2002.

|                                     |  | Years Ended December 31, |    
|------------------------------------ |  | ------------------------ | ---
|
|
|Operating revenues                   |  | $                        | 74 
|Operating expenses(1)                |  |                          | 145
|                                     |  |                          |    
|Operating income (loss)              |  |                          | (71
|Interest expense                     |  |                          | (3 
|Interest and other income            |  |                          | 1  
|                                     |  |                          |    
|Income (loss) before income taxes    |  |                          | (73
|Provision (benefit) for income taxes |  |                          | (17
|                                     |  |                          |    
|Income (loss) from operations        |  | $                        | (56
|                                     |  |                          |    

---

Ferrybridge and Fiddler's Ferry Project

On December 21, 2001, EME completed the sale of the Ferrybridge and Fiddler's Ferry coal-fired power plants located in the United Kingdom to
two wholly owned subsidiaries of American Electric Power. In addition, as part of the transactions, the purchasers acquired other assets and assumed

42

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specified liabilities associated with the plants. The sale was the result of a competitive bidding process. EME acquired the plants in 1999 from PowerGen UK plc for £1.3 billion.
Net proceeds from the sales of £643 million were used to repay borrowings outstanding under the existing debt facility related to the acquisition of the power plants. The early
repayment of the projects' existing debt facility of £682 million at December 21, 2001 resulted in a loss of $28 million, after tax, attributable to the
write-off of unamortized debt issue costs. EME recorded an after-tax loss during 2001 of $1.1 billion related to the loss on disposal of these assets. In accordance with
SFAS No. 144, the results of Ferrybridge and Fiddler's Ferry have been reflected as discontinued operations in the consolidated financial statements.

During
2002, EME recorded a loss of $2 million from discontinued operations primarily due to a $7 million loss on settlement of the pension plan related to previous
employees of the Ferrybridge and Fiddler's Ferry project, partially offset by an insurance recovery from claims filed prior to the sale of the power plants. The loss on settlement of the pension plan
arose from the election by former employees in March 2002 to transfer to American Electric Power's new pension plan and the subsequent transfer of pension assets and liabilities in
December 2002 in accordance with the terms of the sale agreement.

Effective
January 1, 2001, EME recorded a $6 million, after tax, increase to income (loss) from discontinued operations, as the cumulative effect of change in accounting
for derivatives. The majority of EME's activities related to the Ferrybridge and Fiddler's Ferry power plants did not qualify for either the normal purchases and sales exception or as cash flow hedges
under SFAS No. 133. EME could not conclude that the timing of generation from these power plants met the probable requirement for a specific forecasted transaction under SFAS No. 133.
Accordingly, the majority of Ferrybridge and Fiddler's Ferry's energy contracts were recorded at fair value with subsequent changes in fair value recorded through the income statement.

Effective
January 1, 2000, EME recorded a $4 million, after tax, decrease to income (loss) from discontinued operations, as the cumulative effect of change in accounting
for major maintenance costs. Through December 31, 1999, EME accrued for major maintenance costs incurred during the period at the Ferrybridge and Fiddler's Ferry power plants between overhauls
(referred to as "accrue in advance"
accounting method). In March 2000, EME voluntarily decided to change its accounting policy to record major maintenance costs as an expense as incurred.

Cumulative Effect of Change in Accounting Principle

Discussion of Initial Adoption of SFAS No. 142

During the third quarter of 2002, EME completed the steps necessary for the adoption of Statement of Financial Accounting Standards No. 142, "Goodwill and
Other Intangible Assets." EME concluded that the goodwill related to the Citizens Power LLC acquisition was impaired as discussed under "New Accounting Standards." Retroactive to
January 1, 2002, EME recorded a $14 million, after tax, decrease to net income as the cumulative effect of the adoption of SFAS No. 142.

Accounting for Derivatives and SFAS No. 133

EME's primary market risk exposures arise from fluctuations in electricity and fuel prices, emission and transmission rights, interest rates and foreign currency
exchange rates. EME manages these risks in part by using derivative financial instruments in accordance with established policies and procedures. Effective January 1, 2001, MEHC adopted
Statement of Financial Accounting Standards No. 133, "Accounting for Derivative Instruments and Hedging Activities." SFAS No. 133 establishes accounting and reporting standards requiring
that derivative instruments be recorded in the balance sheet as either assets or liabilities measured at their fair value unless they meet an exception. SFAS No. 133 also requires that changes
in the derivative's fair value be recognized currently in earnings unless specific

43

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hedge accounting criteria are met. For derivatives that qualify for hedge accounting, depending on the nature of the hedge, changes in fair value are either offset by changes in the fair value of the
hedged assets, liabilities or firm commitments through earnings, or recognized in other comprehensive income until the hedged item is recognized in earnings.

Effective
January 1, 2001, MEHC recorded all derivatives at fair value unless the derivatives qualified for the normal sales and purchases exception. This exception applies to
physical sales and purchases of power or fuel where it is probable that physical delivery will occur, the pricing provisions are clearly and closely related to the contracted prices and the
documentation requirements of SFAS No. 133 are met.

On
January 1, 2001, EME recorded a $250 thousand, after tax, increase to income from continuing operations and a $230 million, after tax, decrease to other
comprehensive income as the cumulative effect of the adoption of SFAS No. 133. Effective July 1, 2001, the Derivative Implementation Group of the Financial Accounting Standards Board
under Statement No. 133 Implementation Issue Number C15 modified the normal sales and purchases exception to include electricity contracts which include terms that require physical delivery by
the seller in quantities that are expected to be sold in the normal course of business. This modification had two significant impacts:



Under
SFAS No. 133, the portion of a cash flow hedge that does not offset the change in value of the transaction being hedged, which is commonly referred to as the ineffective
portion, is immediately recognized in earnings. EME recorded a net loss of approximately $2 million and $1 million in 2002 and 2001, respectively, representing the amount of cash flow
hedges' ineffectiveness, reflected in net gains (losses) from price risk management and energy trading in its consolidated income statement.

Accounting for Major Maintenance Costs

Through December 31, 1999, EME accrued for major maintenance costs incurred during the period between overhauls (referred to as "accrue in advance"
accounting method). In March 2000, EME voluntarily decided to change its accounting policy to record major maintenance costs as an expense as incurred. This change in accounting policy is
considered preferable based on guidance provided by the Securities and Exchange Commission. In accordance with Accounting Principles Board Opinion No. 20, "Accounting Changes," EME recorded a
$22 million, after tax, increase to income from continuing operations, as the cumulative effect of change in accounting for major maintenance costs during the quarter ended March 31,
2000.

44

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REGIONAL OPERATING RESULTS

EME operates predominantly in one line of business, electric power generation, organized by three geographic regions: Americas, Asia Pacific, and Europe.

Operating
revenues are derived from EME's majority-owned domestic and international entities. Intercompany interest expense and income between EME and its consolidated subsidiaries have
been eliminated in the following project results, except as described below with respect to loans provided to EME from a wholly owned subsidiary, Midwest Generation.

Equity
in income from unconsolidated affiliates relates to energy projects where EME's ownership interest is 50% or less in the projects. The equity method of accounting is generally
used to account for the operating results of entities over which EME has a significant influence but in which it does not have a controlling interest. With respect to entities accounted for under the
equity method, EME recognizes its proportional share of the income or loss of such entities.

MEHC uses the word "earnings" in this section to describe EME's income from continuing operations before income taxes and minority
interest.

Americas

|                                                            |                                                          | Years Ended December 31, |      
|----------------------------------------------------------- | -------------------------------------------------------- | ------------------------ | -----
|
|
|Operating Revenues from Consolidated Subsidiaries           |                                                          |                          |      
|                                                            | Illinois Plants                                          |                          | $    
|                                                            | Homer City                                               |                          |      
|                                                            | Other                                                    |                          |      
|                                                            |                                                          |                          |      
|                                                            |                                                          | $                        | 1,564
|                                                            |                                                          |                          |      
|Income (Loss) before Taxes and Minority Interest (Earnings) |                                                          |                          |      
|                                                            | Consolidated operations                                  |                          |      
|                                                            | Illinois Plants                                          |                          |      
|                                                            | Homer City                                               |                          |      
|                                                            | Charges related to cancellation of turbine orders/leases |                          |      
|                                                            | Other                                                    |                          |      
|                                                            | Unconsolidated affiliates                                |                          |      
|                                                            | Big 4 projects                                           |                          |      
|                                                            | Four Star Oil & Gas                                      |                          |      
|                                                            | Sunrise                                                  |                          |      
|                                                            | March Point                                              |                          |      
|                                                            | Other                                                    |                          |      
|                                                            | Regional overhead                                        |                          |      
|                                                            |                                                          |                          |      
|                                                            |                                                          | $                        | 379  
|                                                            |                                                          |                          |      

45

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Illinois Plants

|                                 |                                   | Years Ended December 31, |  
|-------------------------------- | --------------------------------- | ------------------------ | -
|
|StatisticsCoal-Fired Generation |                                   |                          |  
|                                 | Generation (in GWhr)              |                          |  
|                                 | Availability                      |                          |  
|                                 | Forced outage rate                |                          |  
|                                 | Average realized energy price/MWh |                          | $
|                                 | Capacity revenues (in millions)   |                          | $

Operating
revenues from the Illinois Plants increased $60 million in 2002 compared to 2001, and decreased $29 million in 2001 from 2000. Operating revenues were primarily
derived from power purchase agreements with Exelon Generation Company. Significantly less capacity will be subject to these agreements in 2003, and they terminate in their entirety in 2004. See "Item
1. BusinessAmericasIllinois Plants." Under these agreements, Exelon Generation is obligated to make capacity payments for the plants under contract and energy payment for
electricity produced by these plants. Revenues under these power purchase agreements were $1.1 billion for each 2002, 2001 and 2000. This represents 41%, 43% and 49% of EME's consolidated
operating revenues in 2002, 2001, and 2000, respectively. For more information on these power purchase agreements, see "Market Risk ExposuresIllinois Plants" and
"Risk Factors." The increase in operating revenues in 2002 compared to 2001 is primarily due to scheduled price increases in the power purchase agreements along with improved availability
and higher generation. The decrease in operating revenues in 2001 compared to 2000 is primarily due to lower generation.

Earnings
from the Illinois Plants increased $129 million in 2002 from 2001, and increased $56 million in 2001 from 2000. Discrete items affecting the earnings of the
Illinois Plants include:



Income
(losses) from price risk management activities were $(1) million in 2002, $(21) million in 2001 and $6 million in 2000. The income (losses) primarily resulted primarily
from the change in market value of future contracts with respect to a portion of anticipated fuel purchases that did not qualify for hedge accounting under SFAS No. 133.

The
earnings of the Illinois Plants included interest income of $119 million in 2002, $130 million in 2001, and $51 million in 2000 related to loans to EME. In
July 2000, Midwest Generation, which owns and leases the Illinois Plants, entered into a sale-leaseback transaction of the Powerton-Joliet facilities. The proceeds from the sale of
these facilities were loaned to EME, which also provided a guaranty of the lease obligations of Midwest Generation. The Powerton-Joliet sale-leaseback is recorded as an operating lease for
accounting purposes. See "Critical Accounting Policies and EstimatesOff-Balance Sheet Financing" for further discussion of these leases.

46

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Earnings
from the Illinois Plants, excluding the above discrete items, for 2002 improved over 2001 due to the following factors:



Earnings
from the Illinois Plants for 2001 improved over 2000 due to:



Homer City

Years Ended December 31,2002

2001

2000StatisticsGeneration (in GWhr)


12,111


12,922


11,796Availability


76.8
%

87.4
%

80.2
%Forced outage rate


16.0
%

4.5
%

6.1
%Average realized energy price/MWh

$
28.70

$
33.07

$
31.63Capacity revenues (in millions)

$
41

$
67

$
49


Operating
revenues from Homer City decreased $105 million in 2002 from 2001 and increased $72 million in 2001 from 2000. The 2002 decrease primarily resulted from lower
electric revenues from the Homer City facilities due to decreased generation and lower energy and capacity prices. On February 10, 2002, Homer City experienced a major unplanned outage due to a
collapse of the SCR ductwork of one of the units, known as Unit 3. The unit was restored to operation on April 4, 2002 and is operating with the SCR bypassed. As a result of the Unit 3 SCR
ductwork collapse, Homer City reviewed the similar structures on Units 1 and 2 and determined that, as a precaution, it would be appropriate to install additional reinforcement in these structures.
The additional reinforcement extended the duration of planned outages for these units, which had been scheduled to end on June 2, 2002. Unit 1 returned to service on June 28, 2002, and
Unit 2 returned to service on June 26, 2002. The increase in operating revenues in 2001 from 2000 is primarily due to higher availability and, to a lesser extent, higher energy prices.

Earnings
from Homer City decreased $89 million in 2002 compared to 2001, and increased $66 million in 2001 compared to 2000. The 2002 decrease in earnings is due to the
outages described above and lower wholesale energy and capacity prices. See "Market Risk ExposuresHomer City Facilities." In addition, 2002 earnings reflect the treatment of
the Homer City facilities as an operating lease in 2002 compared
to ownership of the plant with debt financing in 2001 and 2000. The operating lease treatment in 2002 resulted from the sale-leaseback of Homer City completed in December 2001.
SeeOff-Balance Sheet TransactionsSale-Leaseback Transactions" for discussion of the financial impact of sale-leaseback transactions.

47

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Charges Related to Cancellation of Turbine Orders/Leases

In December 2000, EME entered into a master lease and related agreements which together initially provided for the construction of new projects using a
total of nine turbines on order from Siemens Westinghouse. Due to unfavorable market conditions, EME decided to terminate its obligation to cause the completion of three of the four projects (for
which EME planned to use six of the turbines) and recorded a loss of $25 million during the year ended December 31, 2001. In March 2002, EME purchased the remaining three turbines
under the master lease for $61 million. The amount paid to purchase the turbines was capitalized as EME planned to use the turbines for a new gas-fired project. In light of lower
wholesale energy prices during 2002 (see "GeneralCurrent Developments"), EME notified Siemens Westinghouse in September 2002 of its election to terminate all of the
equipment purchase contracts for the nine turbines effective October 25, 2002. Accordingly, EME recorded approximately $61 million to write-off capitalized costs associated
with the turbines during the year ended December 31, 2002.

Big 4 Projects

EME owns partnership investments (50% ownership or less) in Kern River Cogeneration Company, Midwest Sunset Cogeneration Company, Sycamore Cogeneration Company
and Watson Cogeneration Company. These projects have similar economic characteristics and have been used, collectively, to secure bond financing by Edison Mission Energy Funding Corp., a special
purpose entity that EME includes in its consolidated financial statements. Due to similar economic characteristics and the bond financing related to EME's equity investments in these projects, EME
evaluates them collectively and refers to them as the Big 4 projects.

Earnings
from the Big 4 projects decreased $112 million in 2002 from 2001 and increased $85 million in 2001 from 2000. The change in earnings in these periods was largely
due to higher energy prices in 2001. The earnings from the Big 4 projects included interest expense from Edison Mission Energy Funding LLC of $19 million, $22 million and
$25 million in 2002, 2001 and 2000, respectively.

Four Star Oil & Gas

EME owns a 37.2% direct and indirect interest, with 36.05% voting stock, in Four Star Oil & Gas Company, with majority control held by affiliates of
ChevronTexaco Corporation. Four Star Oil & Gas owns oil and gas reserves in the San Juan Basin, the Hugoton Basin, the Permian Basin and offshore Gulf Coast and Alabama. EME's share of earnings
from Four Star Oil & Gas Company was $21 million in 2002, $41 million in 2001, and $43 million in 2000. The 2002 decrease in earnings was primarily due to lower production
volumes and lower natural gas prices.

Also
reflected in earnings from this project are the results of EME's hedging activities. Net gains (losses) from hedging were $(1) million in 2002, $45 million in 2001 and $(87)
million in 2000 related to hedging a portion of EME's gas price risk related to its share of gas production. Although EME believes that these financial instruments hedge its gas price risk, hedge
accounting is not permitted for transactions or investments accounted for on the equity method, and, thus EME is required to record changes in fair value of these positions through the income
statement.

Sunrise

Earnings from the Sunrise project increased $2 million in 2002 from 2001 and increased $14 million in 2001 from 2000. The 2002 increase in earnings
resulted from inclusion of a full year of earnings in 2002, compared to a partial year in 2001. The Sunrise project commenced commercial operation in June 2001. The 2001 increase in earnings
reflects income from initial commercial operation of the Sunrise project. EME had no comparable results for the Sunrise project in 2000.

48

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March Point

Earnings from March Point increased $10 million in 2002 from 2001 and decreased $2 million in 2001 from 2000. The 2002 increase in earnings was
primarily due to the ineffective portion of fuel contracts entered into by March Point, which are derivatives that qualified as cash flow hedges under SFAS No. 133.

Other

Earnings from other projects in the Americas region (consolidated subsidiaries and unconsolidated affiliates) included net gains from energy trading activities of
$42 million in 2002, $10 million in 2001, and $62 million in 2000. In addition, other projects included $10 million in 2001 and $17 million in 2000 related to asset
impairment and other charges or gains on sale of assets. See "Consolidated Operating ResultsOperating Revenues" and "Consolidated Operating
ResultsOperating Expenses" for further discussion of these items.

Regional G&A

Americas Regional G&A decreased $2 million in 2002 from 2001 and increased $19 million in 2001 from 2000. There was no significant change in
Regional G&A in 2002 from 2001. The increase in Regional G&A in 2001 from 2000 was due to the acquisition of Citizens Power in 2000 and the subsequent establishment of the Boston office and an
increase in general and administrative costs related to the Illinois Plants.

Asia Pacific

|                                                            |                           | Years Ended December 31, |    
|----------------------------------------------------------- | ------------------------- | ------------------------ | ---
|
|
|Operating Revenues from Consolidated Subsidiaries           |                           |                          |    
|                                                            | Contact Energy            |                          | $  
|                                                            | Loy Yang B                |                          |    
|                                                            | Other                     |                          |    
|                                                            |                           |                          |    
|                                                            |                           | $                        | 707
|                                                            |                           |                          |    
|Income (Loss) before Taxes and Minority Interest (Earnings) |                           |                          |    
|                                                            | Consolidated operations   |                          |    
|                                                            | Contact Energy(1)         |                          |    
|                                                            | Loy Yang B                |                          |    
|                                                            | Other                     |                          |    
|                                                            | Unconsolidated affiliates |                          |    
|                                                            | Paiton                    |                          |    
|                                                            | Other                     |                          |    
|                                                            | Regional overhead         |                          |    
|                                                            |                           |                          |    
|                                                            |                           | $                        | 141
|                                                            |                           |                          |    

---

49

---

Contact Energy

Operating revenues increased $197 million in 2002 from 2001, and increased $297 million in 2001 from 2000. The 2002 and 2001 increases were
primarily due to consolidating Contact Energy operating revenues as a result of EME acquiring a controlling interest in the company, effective June 1, 2001. Operating revenues generated by
Contact Energy were higher in 2002 from 2001 due to successful expansion of Contact Energy's retail customer base. During 2001, Contact Energy benefited from higher energy prices in New Zealand caused
by dry and cold weather conditions during the third quarter of 2001.

Earnings
from Contact Energy, included in the consolidated statements of income of EME as described above, increased $16 million in 2002 from 2001, and increased
$60 million in 2001 from 2000. The increase in earnings in 2002 is primarily due to increased retail sales from the successful expansion of Contact Energy retail customer base and an 11.8%
increase in the average exchange rate of the New Zealand dollar compared to the U.S. dollar during 2002, compared to 2001, partially offset by a decrease in wholesale energy prices. The increase in
earnings in 2001 is primarily due to higher wholesale prices in the summer of 2001 due to dry and cold weather conditions.

Loy Yang B

Operating revenues increased $28 million in 2002 from 2001, and decreased $15 million in 2001 from 2000. The increase in operating revenues in 2002
is due to higher generation and pool prices for the power sold into the wholesale energy market. The decrease in operating revenues in 2001 was primarily due to an 11.1% decrease in the average
exchange rate of the Australian dollar compared to the U.S. dollar during 2001, compared to 2000.

Earnings
from Loy Yang B increased $41 million in 2002 from 2001, and decreased $11 million in 2001 from 2000. The increase in earnings from 2002 is due to higher electric
revenues discussed above.

Paiton Energy

Earnings from Paiton Energy increased $28 million in 2002 from 2001 and had no significant change between 2001 and 2000. Beginning January 1, 2002,
Paiton Energy recorded revenue in accordance with the Binding Term Sheet, as described in more detail under "Contractual Obligations, Commitments and ContingenciesPaiton
Project." Revenue recognized under the Binding Term Sheet is comprised of capacity payments (based on the availability of the power plant) and energy payments (based on electricity generated). Prior
to the execution of the Binding Term Sheet, EME assumed the lower end of a range of expected outcomes of negotiations of a revised power purchase agreement, which resulted in no equity in income from
Paiton Energy during 2001 and 2000.

Other

Operating revenues from other consolidated subsidiaries in the Asia Pacific Region increased $18 million in 2002 from 2001 and had no significant change
between 2001 and 2000. Earnings from other projects in the Asia Pacific Region (consolidated subsidiaries and unconsolidated affiliates) increased $5 million in 2002 from 2001, and decreased
$7 million in 2001 from 2000. The increase in both operating revenues and earnings in 2002 is primarily due to higher electric revenues from the Valley Power Peaker project in Australia. EME
had no comparable results for the Valley Power Peaker project in 2001. Commercial operation of the Valley Power Peaker project commenced during the second quarter of 2002. During 2000, EME's
subsidiary sold its 30% interest in the Kwinana project and recognized a gain of $8 million. No comparable gain was recorded in 2002 or 2001.

50

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Regional G&A

Asia Pacific's Regional G&A increased $2 million in 2002 from 2001 and decreased $5 million in 2001 from 2000. The increase in Regional G&A in 2002
from 2001 is primarily due to changes in foreign currency exchange rates. The decrease in Regional G&A in 2001 is largely due to consolidation efforts of EME's Asia Pacific operations which reduced
overhead costs in EME's Singapore office.

Europe(1)

|                                                            |                           | Years Ended December 31, |    
|----------------------------------------------------------- | ------------------------- | ------------------------ | ---
|
|
|Operating Revenues from Consolidated Subsidiaries           |                           |                          |    
|                                                            | First Hydro               |                          | $  
|                                                            | Doga(2)                   |                          |    
|                                                            | Other                     |                          |    
|                                                            |                           |                          |    
|                                                            |                           | $                        | 452
|                                                            |                           |                          |    
|Income (Loss) before Taxes and Minority Interest (Earnings) |                           |                          |    
|                                                            | Consolidated operations   |                          |    
|                                                            | First Hydro               |                          |    
|                                                            | Doga                      |                          |    
|                                                            | Other                     |                          |    
|                                                            | Unconsolidated affiliates |                          |    
|                                                            | ISAB                      |                          |    
|                                                            | Other                     |                          |    
|                                                            | Regional overhead         |                          |    
|                                                            |                           |                          |    
|                                                            |                           | $                        | 50 
|                                                            |                           |                          |    

---

First Hydro

Operating revenues increased $84 million in 2002 from 2001, and decreased $100 million in 2001 from 2000. On March 27, 2001, the United
Kingdom pool pricing system was replaced with a bilateral physical trading system referred to as the new electricity trading arrangements. The new electricity trading arrangements are described in
further detail under "Market Risk ExposuresUnited Kingdom." The 2002 increase resulted primarily from higher electric revenues from the First Hydro plant due to increased
volumes of power sales and higher ancillary services revenues during 2002 from 2001. As a result of the bilateral market under the new electricity trading arrangements, First Hydro has entered into
purchase and sales contracts covering greater volumes of power to optimize the timing of generation from First Hydro's pumped storage plants. The 2001 decrease resulted primarily from lower capacity
revenues from the First Hydro plant. These new electricity trading arrangements resulted

51

---

in lower capacity prices in 2001, compared to 2000. The First Hydro plant is expected to provide for higher electric revenues during its winter months.

Earnings
from First Hydro increased $10 million in 2002 from 2001, and decreased $105 million in 2001 from 2000. The change in earnings in these periods is primarily due to
the impact of the change in market prices and the simultaneous introduction of the electricity trading arrangement described above. In addition, EME has reduced plant operating costs in 2002 in light
of the United Kingdom market.

Doga

Revenues from Doga decreased $7 million in 2002 from 2001 and increased $19 million in 2001 from 2000. The 2002 decrease is due to lower costs of
natural gas which is reimbursable under the power purchase agreement, partially offset by an increase in generation. The 2001 increase is due to improved plant operating performance over 2000 when
Doga experienced significant downtime on one gas turbine.

Earnings
from Doga increased $6 million in 2002 from 2001 and increased $3 million in 2001 from 2000. The increase in earnings in 2002 is primarily due to increased
generation, lower operations and maintenance costs, and a reduction in allowance for doubtful accounts, partially offset by foreign currency losses. The increase in earnings in 2001 is primarily due
to higher generation, partially offset by higher operations and maintenance costs and foreign currency losses.

ISAB

Earnings from ISAB increased $22 million in 2002 from 2001 and increased $18 million in 2001 from 2000. The 2002 increase was due to increased
generation and settlement of an insurance claim. The 2001 increase reflects improved operational performance of the project after start-up of the project in early 2000. During 2000, EME
recorded losses from this project. Commercial operation of the ISAB project commenced in April 2000.

Other

Earnings from other projects in the Europe region (consolidated subsidiaries and unconsolidated affiliates) decreased $4 million in 2002 from 2001 and
decreased $1 million in 2001 from 2000. The 2002 decrease in earnings was primarily due to lower operating revenues from EME's Spanish Hydro project largely due to lower generation caused by
less rainfall in 2002, partially offset by the gain on sale of a development project in the United Kingdom during December 2002.

Regional G&A

Europe's Regional G&A increased $4 million in 2002 from 2001. There was no change in Regional G&A in 2001 from 2000. The 2002 increase in Regional G&A is
primarily due to the strengthening of the British pound against the U.S. dollar and elimination of cost sharing with the Ferrybridge and Fiddler's Ferry power plants that were sold in
December 2001.

Critical Accounting Policies and Estimates

The accounting policies described below are viewed by EME's management as "critical" because their correct application requires the use of material judgments and
estimates and they have a material impact on EME's results of operations and financial position.

52

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Derivative Financial Instruments and Hedging Activities

EME uses derivative financial instruments for price risk management activities and trading purposes. Derivative financial instruments are mainly utilized to
manage exposure from changes in electricity and fuel prices, interest rates and fluctuations in foreign currency exchange rates. EME follows Statement of Financial Accounting Standards No. 133,
"Accounting for Derivative Instruments and Hedging Activities" (SFAS No. 133), which requires derivative financial instruments to be recorded at their fair value unless an exception applies.
SFAS No. 133 also requires that changes in a derivative's fair value be recognized currently in earnings unless specific hedge accounting criteria are met. For derivatives that qualify for
hedge accounting, depending on the nature of the hedge, changes in fair value are either offset by changes in the fair value of the hedged assets, liabilities or firm commitments through earnings, or
recognized in other comprehensive income until the hedged item is recognized in earnings. The ineffective portion of a derivative's change in fair value is immediately recognized in earnings.

Management's
judgment is required to determine if a transaction meets the definition of a derivative and, if yes, whether the normal sales and purchases exception applies or whether
individual transactions qualify for hedge accounting treatment. The majority of EME's power sales and fuel supply agreements related to its generation activities either: (1) do not meet the
definition of a derivative as they are not readily convertible to cash, (2) qualify as normal purchases and sales and are, therefore, recorded on an accrual basis or (3) qualify for
hedge accounting.

Derivative
financial instruments used for trading purposes includes forwards, futures, options, swaps and other financial instruments with third parties. EME records at fair value
derivative financial
instruments used for trading. The majority of EME's derivative financial instruments with a short-term duration (less than one year) are valued using quoted market prices. In the absence
of quoted market prices, derivative financial instruments are valued at fair value, considering time value of money, volatility of the underlying commodity, and other factors as determined by EME.
Resulting gains and losses are recognized in net gains (losses) from price risk management and energy trading in the accompanying consolidated income statements in the period of change. Assets from
price risk management and energy trading activities include the fair value of open financial positions related to derivative financial instruments recorded at fair value, including cash flow hedges,
that are "in-the-money" and the present value of net amounts receivable from structured transactions. Liabilities from price risk management and energy trading activities
include the fair value of open financial positions related to derivative financial instruments, including cash flow hedges, that are "out-of-the-money" and the
present value of net amounts payable from structured transactions.

Determining
the fair value of derivatives under SFAS No. 133 is a critical accounting estimate because the fair value of a derivative is susceptible to significant change
resulting from a number of factors, including: volatility of energy prices, credits risks, market liquidity and discount rates. See "Market Risk Exposures," for a description of risk
management activities and sensitivities to change in market prices.

EME
enters into master agreements and other arrangements in conducting price risk management and trading activities with a right of setoff in the event of bankruptcy or default by the
counterparty. Such transactions are reported net in the balance sheet in accordance with FASB Interpretation No. 39, "Offsetting Amounts Related to Certain Contracts."

Impairment

Long-Lived Assets. EME follows Statement of Financial Accounting Standards No. 144, "Accounting for the Impairment or Disposal of
Long-Lived Assets" (SFAS No. 144). EME evaluates long-lived assets whenever indicators of impairment exist. This accounting standard requires that if the undiscounted
expected future cash flow from a company's assets or group of assets (without interest

53

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charges) is less than its carrying value, asset impairment must be recognized in the financial statements. The amount of impairment is determined by the difference between the carrying amount and
fair value of the asset.

The
assessment of impairment is a critical accounting estimate because significant management judgment is required to determine: (1) if an indicator of impairment has occurred,
(2) how assets should be grouped, (3) the forecast of undiscounted expected future cash flow over the asset's estimated useful life to determine if an impairment exists, and
(4) if an impairment exists, the fair value of the asset or asset group. Factors EME considers important, which could trigger an impairment, include operating losses from a project, projected
future operating losses, the financial condition of counterparties, or significant negative industry or economic trends. During the fourth quarter of 2002, EME assessed the impairment of its Illinois
Plants. EME has grouped the Illinois Plants into two asset groups: coal-fired
power plants and the small peaker plants. Management judgment was required to make this assessment based on the lowest level of cash flow that was viewed by management as largely independent of each
other. The expected future undiscounted cash flow from EME's merchant power plants is a critical accounting estimate because: (1) estimating future prices of energy and capacity in wholesale
energy markets is susceptible to significant change, and (2) the period of the forecast is over an extended period of time due to the estimated useful life (15 to 33 years) of power
plants, and (3) the impact of an impairment on EME's consolidated financial position and results of operations would be material. The expected undiscounted future cash flow from the Illinois
Plants exceeded the carrying value of those asset groups.

During
the fourth quarter of 2002, an impairment charge of $92 million ($77 million after tax) was recorded by EME's subsidiary holding the Lakeland power plant due to the
change in financial condition of TXU Europe and its subsidiaries, one of which was counterparty to a long-term power purchase agreement (considered an indicator of impairment under SFAS
No. 144). Management's judgment was required to determine the asset group, which was determined as the power plant and claim under the power purchase agreement. Furthermore, a management
estimate was required to determine the fair value of the asset group as the expected undiscounted future cash flow was less that the carrying value of the asset. See "Consolidated
Operating ResultsDiscontinued Operations," for further discussion.

EME
also would record an impairment charge if a decision is made (which generally occurs when EME enters into an agreement to sell an asset) to dispose of an asset and the fair value is
less than EME's book value. Using this type of analysis, EME recorded $1.9 billion impairment of EME's Ferrybridge and Fiddler's Ferry power plants during the third quarter of 2001. See
"Consolidated Operating ResultsDiscontinued Operations," for further discussion.

EME
operates several power plants under leases as described below under "Off-Balance Sheet Financing." Under generally accepted accounting principles as currently
interpreted, EME is not required to record a loss if future cash flows from use of an asset under lease are less than the expected minimum lease payments. This accounting issue has been discussed in
EITF No. 99-14, "Recognition by a Purchaser of Losses on Firmly Committed Executory Contracts," without reaching a consensus. Future minimum lease payments on the Collins Station
are estimated to be $1.4 billion. As a result, if the accounting guidance in this area were to change, EME could be required to record a loss on this lease, depending on an assessment of future
expected cash flow at the time such guidance was changed.

Idle
Facilities. Due to lower wholesale prices for energy during 2002 (see "Market Risk ExposuresCommodity Price Risk"), EME has suspended operations of four
units at the Illinois Plants (Units 1 and 2 at Will County and Units 4 and 5 at the Collins Station). EME also suspended operations during 2002 at three units at First Hydro, two of which had resumed
operations by December 2002. EME continues to record depreciation on such assets during the period that EME has

54

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suspended operations. Accounting for these units as idle facilities requires management's judgment that these units will return to service. EME has continued the maintenance of these units in order
to return
them to service when market conditions improve on a sustained basis and future environmental uncertainties are resolved. If market conditions do not improve on a sustained basis, environmental
uncertainties are not resolved or are resolved unfavorably, or if a decision is made not to return them to service due to other factors, EME could sell or decommission one or more of these units. Such
a decision could result in a loss on sale or a write down of the carrying value of these assets.

Goodwill.
EME follows Statement of Financial Accounting Standards No. 142, "Goodwill and Other Intangibles" (SFAS No. 142). EME evaluates goodwill whenever indicators of
impairment exist, but at least annually on October 1 of each year. EME has recorded goodwill associated with three acquisitions: Contact Energy, First Hydro and Citizens Power LLC. EME
determined through a fair value analysis conducted by third parties that the fair value of the Contact Energy and First Hydro reporting units was in excess of book value. Accordingly, no impairment of
the goodwill related to these reporting units was recorded upon adoption of this standard. EME concluded that, based on fair value of a comparable transaction, the fair value of the reporting unit
related to the Citizens Power LLC acquisition was less than its book value. Accordingly, a goodwill impairment of $14 million, net of $9 million of income tax benefits was recorded. In
accordance with SFAS No. 142, the impairment as of January 1, 2002 is recorded as a cumulative effect of a change in accounting principle in EME's consolidated income statement.

Determining
the fair value of the reporting unit under SFAS No. 142 is a critical accounting estimate because: (1) it is susceptible to change from period to period since
it requires assumptions regarding future revenues and costs of operations and discount rates over an indefinite life, and (2) the impact of recognizing an impairment on EME's consolidated
financial position and results of operations would be material. EME has engaged third parties to conduct appraisals of the fair value of the major reporting units with goodwill on October 1,
2002 (the annual impairment testing date). The fair value of the First Hydro and Contact Energy reporting units set forth in these appraisals exceeded their book value.

Off-Balance Sheet Financing

EME has entered into sale-leaseback transactions related to the Collins, Powerton and Joliet plants in Illinois and the Homer City facilities in
Pennsylvania. See "Contractual Obligations, Commitments and ContingenciesSale-Leaseback Commitments." Each of these transactions was completed and accounted for
by EME as an operating lease in its consolidated financial statements in accordance with Statement of Financial Accounting Standards No. 98 "Sale-Leaseback Transactions Involving
Real Estate" (SFAS No. 98), which requires, among other things, that all of the risk and rewards of ownership of assets be transferred to a new owner without continuing involvement in the
assets by the former owner other than as normal for a lessee. Completion of sale-leaseback transactions of these power plants is a complex matter involving management judgment to determine
compliance with the provisions of SFAS No. 98, including the transfer of all of the risk and rewards of ownership of the power plants to the new owner without EME's continuing involvement other
than as normal for a lessee. These transactions were entered into to provide a source of capital either to fund the original acquisition of the assets or to repay indebtedness previously incurred for
the acquisition. Each of these leases uses special purpose entities.

Based
on existing accounting guidance, EME does not record these lease obligations in its consolidated balance sheet. If these transactions were required to be consolidated as a result
of future changes in accounting guidance, it would: (1) increase property, plant and equipment and long-term obligations in the consolidated financial position, and
(2) impact the pattern of expense recognition related to these obligations as EME would likely change from its current straight-line recognition of rental expense to an annual
recognition of the straight-line depreciation on the leased assets as well as

55

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the interest component of the financings which is weighted more heavily toward the early years of the obligations. The difference in expense recognition would not affect EME's cash flows under these
transactions. See "Liquidity and Capital ResourcesOff-Balance Sheet TransactionsSale-Leaseback Transactions."

In
January 2003, the Financial Accounting Standards Board issued Statement of Financial Accounting Standards Interpretation No. 46, "Consolidation of Variable Interest
Entities" (FIN 46). This interpretation of Accounting Research Bulletin No. 51, "Consolidated Financial Statements," addresses consolidation by business enterprises of variable interest
entities. The primary objective of the interpretation is to provide guidance on the identification of, and financial reporting for, entities over which control is achieved through means other than
voting rights; such entities are known as variable-interest entities. This interpretation applies to variable interest entities created after January 31, 2003, and applies to variable interest
entities in which EME holds a variable interest that it acquired before February 1, 2003, beginning July 1, 2003.

EME
has concluded that it is the primary beneficiary of Brooklyn Navy Yard Cogeneration Partners L.P. since it is at risk with respect to a majority of its losses and is entitled
to receive a majority of its residual returns. Accordingly, EME will consolidate Brooklyn Navy Yard Cogeneration Partners L.P. effective July 1, 2003. In accordance with the transition
provisions of FIN 46, the consolidation of Brooklyn Navy Yard Cogeneration Partners L.P. will be based on the historical cost of the assets, liabilities and non-controlling interest
which would have been carried by EME effective when EME became the primary beneficiary. This means that EME will consolidate the assets and liabilities of Brooklyn Navy Yard Cogeneration
Partners L.P. using the June 30, 2003 balance sheet and eliminate intercompany balances. EME expects the consolidation of this entity to increase total assets by approximately
$365 million and total liabilities by approximately $445 million. Furthermore, EME expects to record a loss of approximately $80 million as a cumulative change of accounting as a
result of consolidating this variable interest entity. This loss is primarily due to cumulative losses allocated to the other 50% partner in excess of equity contributions recorded. See "New
Accounting Standards - Statement of Financial Accounting Standards Interpretation No. 46."

Income Taxes

SFAS No. 109, "Accounting for Income Taxes" (SFAS No. 109), requires the asset and liability approach for financial accounting and reporting for
deferred income taxes. EME uses the asset and liability method of accounting for deferred income taxes and provides deferred income taxes for all significant income tax temporary differences. See
Note 13 to the "Mission Energy Holding Company and Subsidiaries Notes to Consolidated Financial Statements" for additional details.

As
part of the process of preparing its consolidated financial statements, EME is required to estimate its income taxes in each of the jurisdictions in which it operates. This process
involves estimating actual current tax expense together with assessing temporary differences resulting from differing treatment of items, such as depreciation, for tax and accounting purposes. These
differences result in deferred tax assets and liabilities, which are included within EME's consolidated balance sheet. EME does not provide for federal income taxes or tax benefits on the
undistributed earnings or losses of its international subsidiaries because such earnings are reinvested indefinitely.

For
additional information regarding MEHC's accounting policies, see "Mission Energy Holding Company and Subsidiaries Notes to Consolidated Financial
StatementsNote 2. Summary of Significant Accounting Policies."

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LIQUIDITY AND CAPITAL RESOURCES

At December 31, 2002, MEHC and its subsidiaries had cash and cash equivalents of $734 million and EME had available a total of $355 million
of borrowing capacity under its $487 million corporate credit facility. MEHC's consolidated debt at December 31, 2002 was $7.2 billion, including $911 million of debt
maturing in December 2003 which is owed by EME's largest subsidiary, Edison Mission Midwest Holdings. In addition, EME's subsidiaries have $7 billion of long-term lease
obligations that are due over a period ranging up to 32 years.

The
$911 million of debt of Edison Mission Midwest Holdings maturing in December 2003 will need to be repaid, extended or refinanced. Edison Mission Midwest Holdings is not
expected to have sufficient cash to repay the $911 million debt due in December 2003, and there is no assurance that it will be able to extend or refinance its debt obligation on similar
terms and rates as the existing debt, on commercially reasonable terms, on the terms permitted under the financing documents entered into by MEHC in July 2001 or at all. MEHC's independent
accountants' audit opinion for the year ended December 31, 2002 contains an explanatory paragraph that indicates the consolidated financial statements have been prepared on the basis that MEHC
will continue as a going concern and that the uncertainty about Edison Mission Midwest Holdings' ability to repay, extend or refinance this obligation raises substantial doubt about MEHC's ability to
continue as a going concern. Accordingly, the consolidated financial statements do not include any adjustments that might result from the resolution of this uncertainty. Within Item 8, see "Report of
Independent Accountants" and "Mission Energy Holding Company and Subsidiaries Notes to Consolidated Financial StatementsNote 10. Financial Instruments."

Mission Energy Holding Company's Liquidity

MEHC's ability to honor its obligations under the senior secured notes and the term loan after the two year interest reserve period (which expires July 2,
2003 for the term loan and July 15, 2003 for the senior secured notes) and to pay overhead is substantially dependent upon the receipt of dividends from EME and receipt of
tax-allocation payments from MEHC's parent, The Mission Group and ultimately Edison International. Part of the proceeds from the senior secured notes and the term loan were used to fund
escrow accounts to secure the first four interest payments due under the senior secured notes and the interest payments for the first two years under the term loan. Other than the dividends received
from EME, funds received pursuant to MEHC's tax-allocation arrangements (seeIntercompany Tax-Allocation Payments") with MEHC's affiliates and the interest reserve
account, MEHC will not have any other source of funds to meet its obligations under the senior secured notes and the term loan. Dividends
from EME may be limited based on its earnings and cash flow, terms of restrictions contained in EME's contractual obligations (including its corporate credit facility), charter documents, business and
tax considerations, and restrictions imposed by applicable law. MEHC did not receive any distributions from EME during 2002.

At
December 31, 2002, MEHC had cash and cash equivalents of $87 million and restricted cash of $150 million (excluding amounts held by EME and its subsidiaries).
Restricted cash represents monies deposited into the interest escrow accounts described above. The funds collected in the accounts will be used to make the interest payments due under the senior
secured notes and the term loan through July 15, 2003. The timing and amount of distributions from EME and its subsidiaries may be affected by many factors beyond MEHC's control, some of which
are described below under "Risk Factors."

If
MEHC is unable to make any payment on the senior secured notes or under the term loan as that payment becomes due, it would result in a default under the senior secured notes and the
term loan and could lead to foreclosure on MEHC's ownership interest in the capital stock of EME.

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The term loan bears interest at a floating rate equal to the three-month London interbank offered rate (LIBOR) plus 7.50% and matures on July 2, 2006. In
July 2004, on the third anniversary of the term loan, the lenders under the term loan may require that MEHC repay up to $100 million of the principal amount at par.

Edison Mission Energy's Credit Ratings

On October 1, 2002, Moody's downgraded EME's senior unsecured rating to Ba3 (below investment grade) from Baa3 (investment grade), and the ratings of EME's
wholly owned indirect subsidiaries, Edison Mission Midwest Holdings Co. (bank facility to Ba2 from Baa2) and Midwest Generation (lessor notes to Ba3 from Baa3). Moody's has continued to keep the
ratings for each of these entities under review for further downgrade. On November 25, 2002, Standard & Poor's downgraded EME's senior unsecured credit rating to BB- (below
investment grade) from BBB- (investment grade). Standard & Poor's also lowered its credit rating on EME's wholly owned indirect subsidiaries, Edison Mission Midwest Holdings (bank
facility to BB- from BBB-), and Edison Mission Marketing & Trading, Inc. (senior unsecured credit rating to BB- from BBB-).
Standard & Poor's has assigned a negative rating outlook for each of the entities that were downgraded.

These
ratings actions did not trigger any defaults under EME's credit facilities or those of the other affected entities; however, the changed ratings will restrict the amount of
distributions EME receives from certain subsidiaries, will increase the borrowing costs under certain credit facilities, and will increase EME's obligation to provide collateral for its trading
activities.

For
interest payments on EME's corporate credit facility, the applicable margin as determined by EME's long-term credit ratings increased for Tranche A (to LIBOR plus 3.625%
from LIBOR plus 2.375%) and Tranche B (to LIBOR plus 3.50% from LIBOR plus 2.25%). In addition to the interest payments, the facility fee as determined by EME's long-term credit ratings
increased for Tranche A (to 0.875% from 0.625%) and Tranche B (to 1.00% from 0.75%). EME estimates that the annual interest and lease costs payable by it and its subsidiaries will increase by
$49 million as a result of the downgrade of its credit rating based on existing debt and lease agreements.

As
a result of these rating actions, EME has:



Moreover,
as a result of these ratings actions, EME has been required to provide collateral for certain of its United Kingdom trading activities. To this end, EME's subsidiary, Edison
Mission Operation and Maintenance Limited, has obtained a cash collateralized credit facility in the amount of £17 million, under which letters of credit totaling
£15 million have been issued as of December 31, 2002. EME also anticipates that sales of power from its Illinois Plants, Homer City facilities and First Hydro plants in the
United Kingdom may require additional credit support, depending upon market conditions and the strategies adopted for the sale of this power. Changes in forward market prices and margining
requirements could further increase the need for credit support for the price risk management and trading activities related to these projects. EME currently projects the potential

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working capital to support its price risk management and trading activity to be between $100 million and $200 million from time to time during 2003.

EME
cannot provide assurance that its current credit ratings or the credit ratings of its subsidiaries will remain in effect for any given period of time or that one or more of these
ratings will not be lowered again. EME notes that these credit ratings are not recommendations to buy, sell or hold its securities and may be revised or withdrawn at any time by a rating agency.

Downgrade of Edison Mission Midwest Holdings

As a result of the downgrade of Edison Mission Midwest Holdings below investment grade, provisions in the agreements binding on Edison Mission Midwest Holdings
and Midwest Generation restrict the ability of Edison Mission Midwest Holdings to make distributions to its parent company, thereby eliminating distributions to EME.

The
following table summarizes the provisions restricting cash distributions (sometimes referred to as cash traps) and the related changes in the cost of borrowing by Edison Mission
Midwest Holdings under the applicable financing agreements. The currently applicable provisions are those set forth in the same row as the Standard & Poor's rating "BB-."

|S&P Rating     |  | Moody's Rating |  | Cost of Borrowing
Margin |  | Cash Trap                                                                                               
|-------------- |  | -------------- |  | ------------------------ |  | --------------------------------------------------------------------------------------------------------
|
|BBB- or higher |  | Baa3 or higher |  | 150                      |  | No cash trap                                                                                            
|BB+            |  | Ba1            |  | 225                      |  | 50% of excess cash flow trapped until six month debt service reserve is funded                          
|BB             |  | Ba2            |  | 275                      |  | 100% of excess cash flow trapped                                                                        
|BB-            |  | Ba3            |  | 325                      |  | 100% of excess cash flow trapped                                                                        
|B+             |  | B1             |  | 325                      |  | 100% cash sweep by lenders to repay debt (i.e., 100% of excess cash flow trapped and used to repay debt)

As
a result of the downgrades affecting Edison Mission Midwest Holdings, provisions in the agreements binding on Edison Mission Midwest Holdings require it to deposit, on a quarterly
basis, 100% of its defined excess cash flow into a cash flow recapture account held and maintained by the collateral agent. In accordance with these provisions, Edison Mission Midwest Holdings
deposited $50 million into the cash flow recapture account on October 31, 2002, and another $28 million on January 27, 2003. The funds in the cash flow recapture account
may be used only to meet debt service obligations of Edison Mission Midwest Holdings if funds are not otherwise available from working capital.

As
part of the sale-leaseback of the Powerton and Joliet power stations, Midwest Generation loaned the proceeds ($1.4 billion) to EME in exchange for promissory notes
in the same aggregate amount. Debt service payments by EME on the promissory notes may be used by Midwest Generation to meet its payment obligations under these leases in whole or part. Furthermore,
EME has guaranteed the lease obligations of Midwest Generation under these leases. EME's obligations under the promissory notes payable to Midwest Generation are general corporate obligations of EME
and are not contingent upon receiving distributions from Edison Mission Midwest Holdings. See "Restricted Assets of EME's SubsidiariesEdison Mission Midwest Holdings
(Illinois Plants)" for a discussion of implications for the Powerton and Joliet leases.

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Downgrade of Edison Mission Marketing & Trading

Pursuant to the Homer City sale-leaseback documents, a downgrade of Edison Mission Marketing & Trading to below investment grade restricts the
ability of EME Homer City Generation L.P. (EME Homer City) to sell forward the output of the Homer City facilities. Under the sale-leaseback documents, EME Homer City may only engage in
permitted trading activities as defined in the documents. These documents include a requirement that the counterparty to such transactions, and EME Homer City, if acting as seller to an unaffiliated
third party, be investment grade. EME currently sells all of the output from the Homer City facilities through Edison Mission Marketing & Trading, and EME Homer City is not rated. Therefore, in
order for EME to continue to sell forward the output of the Homer City facilities in the event of a downgrade in Edison Mission Marketing & Trading's credit, either: (1) EME must obtain
consent from the sale-leaseback owner participant to permit EME Homer City to sell directly into the market or through Edison Mission Marketing & Trading; or (2) Edison
Mission Marketing & Trading must provide assurances of performance consistent with the requirements of the sale-leaseback documents. EME has obtained a consent from the
sale-leaseback owner participant that will allow EME Homer City to enter into limited amounts of such sales, under specified conditions, through September 25, 2003. EME is permitted
to sell the output of the Homer City facilities into the Pennsylvania-New Jersey-Maryland Power Pool (PJM) at any time on a spot-market basis. See "Market Risk
ExposuresHomer City Facilities."

Edison Mission Energy's Liquidity

EME has a $487 million corporate credit facility which includes a one-year $275 million component, Tranche A, that expires on
September 16, 2003 and a three-year $212 million component, Tranche B, that expires on September 17, 2004. At December 31, 2002, EME had borrowing capacity
under this facility of $355 million and corporate cash and cash equivalents of $64 million. During 2002, EME's cash position was significantly increased due to the following:



Cash
distributions from EME's subsidiaries and partnership investments, tax-allocation payments from Edison International and unused capacity under its corporate credit
facilities represent EME's major sources of liquidity to meet its cash requirements. EME plans to discuss with its lenders an extension of the Tranche A line of credit beyond its scheduled expiration.
In addition, EME expects to complete the Sunrise project financing by summer 2003 which, upon completion, will result in the receipt by EME of approximately $150 million of capital previously
invested in this project. See "Subsidiary Financing Plans." EME expects its 2003 cash requirements to be primarily comprised of:



The
timing and amount of distributions from EME's subsidiaries may be affected by many factors beyond its control. See "Risk Factors." Also see "Historical
Distributions Received by Edison

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Mission EnergyRestricted Assets of EME's Subsidiaries." In addition, the right of EME to receive tax-allocation payments, and the timing and amount of tax-allocation payments
received by EME are subject to factors beyond EME's control. See "Intercompany Tax-Allocation Payments." If Tranche A of the corporate facility is not extended and the
Sunrise project financing is not completed as scheduled, EME's ability to provide credit support for bilateral contracts for power and fuel of its merchant energy operations will be severely limited.
If EME is unable to provide such credit support, this will reduce the number of counterparties willing to enter into bilateral contracts with EME's subsidiaries, thus requiring EME's subsidiaries to
rely on short-term markets instead of bilateral contracts. Furthermore, if this situation occurs, EME may not be able to meet margining requirements if forward prices for power increase
significantly. Failure to meet a margining requirement would permit the counterparty to terminate the related bilateral contract early and demand immediate payment for the replacement value of the
contract. See "Risk Factors."

EME's
corporate credit facility provides credit available in the form of cash advances or letters of credit. At December 31, 2002, there were no cash advances outstanding under
either Tranche and $132 million of letters of credit outstanding under Tranche B. In addition to the interest payments, EME pays a facility fee determined by its long-term credit
ratings (0.875% and 1.00% at December 31, 2002 for Tranche A and Tranche B, respectively) on the entire credit facility independent of the level of borrowings.

Under
the credit agreement governing its credit facility, EME has agreed to maintain an interest coverage ratio that is based on cash received by EME, including
tax-allocation payments, cash disbursements and interest paid. At December 31, 2002, EME met this interest coverage ratio. The interest coverage ratio in the
ring-fencing provisions of EME's certificate of incorporation and bylaws remains relevant for determining EME's ability to make distributions. See "Edison Mission Energy's
Interest Coverage Ratio."

Discussion of Historical Cash Flow

Cash Flows From Operating Activities

Net cash provided by (used in) operating activities:

Years Ended December 31,2002

2001

2000(in millions)Continuing operations

$
866

$
(4
)
$
655Discontinued operations


54


(113
)

10$
920

$
(117
)
$
665


The
higher operating cash flow from continuing operations in 2002, compared to 2001, includes $89 million and $395 million in tax-allocation payments received
from Edison International to MEHC and EME, respectively, during 2002. For further discussion of the tax-allocation payments, see "Intercompany Tax-Allocation
Payments." In addition, EME received higher distributions from energy projects in 2002. In March 2002, EME received distributions from its investments in partnerships subsequent to their
receipt of payments of past due accounts receivable from Southern California Edison. Lower distributions from energy projects during 2001 primarily resulted from the delay in payments from the
California utilities to EME's investments in California qualifying facilities. The change in operating cash flow from continuing operations in 2002 was also due to the timing of cash payables related
to working capital items.

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Cash
provided by operating activities from discontinued operations reflects the settlement of working capital items from the Ferrybridge and Fiddler's Ferry power plants and operating
income from the Lakeland power plant during 2002.

Cash
provided by continuing operating activities is derived primarily from operations of the Illinois Plants and the Homer City facilities, distributions from energy projects and
dividends from investments in oil and gas. The lower operating cash flow from continuing operations in 2001, compared to 2000, reflects lower distributions from energy projects and higher current
income taxes payable due to the sale-leaseback of the Homer City facilities, partially offset by higher dividends from oil and gas investments. The change in operating cash flow in 2001
was also due to the timing of cash receipts and payables related to working capital items. Lower distributions from energy projects in 2001 primarily
resulted from the delay in payments from the California utilities to EME's investments in California qualifying facilities.

Net
working capital at December 31, 2002 was $(383) million compared to $291 million at December 31, 2001. The decrease primarily reflects the increase in
current maturities under a long-term obligation related to the $911 million debt due in December 2003 under Tranche A at Edison Mission Midwest Holdings.

Cash
used in operating activities from discontinued operations in 2001 reflects operating losses from the Ferrybridge and Fiddler's Ferry power plants in 2001, as compared to operating
income during 2000, and the timing of cash payables related to working capital items.

Cash Flows From Financing Activities

Net cash provided by (used in) financing activities:

Years Ended December 31,2002

2001

2000(in millions)Continuing operations

$
(296
)
$
(182
)
$
(994
)Discontinued operations


(19
)

(1,085
)

211$
(315
)
$
(1,267
)
$
(783
)


Cash
used in financing activities from continuing operations during 2002 consisted of payment of $100 million of senior notes that matured in 2002, net payments of
$80 million on EME's $487 million
corporate credit facility, $44 million related to debt service payments of one of EME's subsidiaries, and payments of $86 million on EME's Coal and Capex facility. In addition, a wholly
owned subsidiary borrowed $84 million under a note purchase agreement in January 2002. EME also made net payments of $30 million in connection with a swap agreement with a bank
related to lease payments with EME's Homer City facilities. In 2002, dividends of $34 million were paid to minority shareholders from the Contact Energy project.

Cash
used in financing activities from discontinued operations in 2002 reflects repayments of long-term debt from the Lakeland power plant.

In
July 2001, MEHC issued $800 million of 13.5% senior secured notes due 2008 and incurred borrowings of $385 million under a term loan contributing to the cash
provided by financing activities from continuing operations in 2001. Cash used in financing activities from continuing operations in 2001 consisted of net proceeds from bond issuances totaling
$1 billion, the proceeds of which were partially used to permanently repay $677 million under EME's former corporate credit facilities. In addition, EME used the proceeds from the
December 2001 Homer City sale-leaseback transaction to permanently repay $250 million under the Homer City facilities construction loan and to make a $350 million
payment under EME's $750 million corporate credit facility. During 2001, dividends

62

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totaling $811 million were paid by MEHC to The Mission Group, which was loaned to Edison International, MEHC's ultimate parent company. In addition, EME paid $65 million and
$33 million to The Mission Group and MEHC, respectively, and ultimately $97 million was paid to Edison International, EME's ultimate parent company, in 2001, compared to
$88 million in 2000.

Cash
used in financing activities from discontinued operations in 2001 was primarily related to the early repayment of the term loan facility in connection with the sale of the
Ferrybridge and Fiddler's Ferry power plants on December 21, 2001.

Payments
made under EME's credit facilities totaling $1.4 billion, a $500 million payment on EME's floating rate notes and the redemption of the Flexible Money Market
Cumulative Preferred Stock for $125 million were the primary contributors of the net cash used in financing activities from continuing operations during 2000. EME used the proceeds from the
August 2000 Powerton and Joliet sale-leaseback transaction for a significant portion of those payments under EME's credit facilities, commercial paper facilities and EME's floating
rate notes. In 2000, EME also had borrowings of $1.2 billion under its credit facilities and commercial paper facilities.

Cash
provided by financing activities from discontinued operations in 2000 was primarily related to a loan from Edison Capital, an indirect affiliate. During 2001, the financing was
repaid with interest.

Cash Flows From Investing Activities

Net cash provided by (used in) investing activities:

Years Ended December 31,2002

2001

2000(in millions)Continuing operations

$
(305
)
$
(50
)
$
760Discontinued operations


1


926


(42
)$
(304
)
$
876

$
718


Cash
used in investing activities from continuing operations during 2002 included $80 million paid for the purchase of a power sales agreement held by a third party. EME invested
$554 million in 2002 in new plant and equipment principally related to the Valley Power Peaker project in Australia, the Illinois Plants, the Homer City facilities, and payments related to
three turbines to Siemens Westinghouse. Also, included in capital expenditures in 2002 were payments for three turbines purchased under EME's Master Turbine Lease with funds from restricted cash of
$61 million, which reduced EME's restricted cash. In addition, $25 million of restricted cash was used to satisfy EME's obligation related to the termination of EME's Master Turbine
Lease, thereby reducing EME's restricted cash account. In addition, included in capital expenditures during 2002 was a $300 million payment for the Illinois peaker power units that were subject
to a lease with $255 million received as a repayment of the note receivable held by EME. In 2002, $34 million and $11 million were paid in equity contributions for Phase 2 of the
Sunrise project and the CBK project, respectively, and $16 million was paid towards the purchase price for the Italian Wind projects. EME received proceeds of $49 million from the sales
of EME's 50% interests in the Commonwealth Atlantic and James River projects and EME's 30% interest in the Harbor project and a development project in the U.K. In addition, EME received
$79 million as a return of capital from the Kern River and Sycamore projects subsequent to their receipt of payments of past due accounts receivable from Southern California Edison during the
first quarter of 2002. Restricted cash totaling $53 million was used to meet EME's lease payment obligations. As a result of a downgrade in its credit rating, Edison Mission Midwest Holdings
deposited $50 million into a restricted cash account in 2002. See "Edison Mission Energy's Credit Ratings."

63

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Cash
used in investing activities from continuing operations in 2001 included cash used by EME for equity contributions totaling approximately $134 million to meet capital calls
by partnerships who own qualifying facilities that have power purchase agreements with Southern California Edison and Pacific Gas and Electric. In addition, restricted cash increased due to a portion
of the net proceeds from the sale of 13.5% senior secured notes and the term loan placed into an escrow account totaling approximately $292 million at December 31, 2001. In addition, EME
paid $10 million as equity contributions for the CBK project; $6 million as part of the purchase price and $3 million as equity contributions for the Italian Wind projects;
$20 million as part of the purchase of the 50% interest in the CBK project; and $63 million for the purchase of additional shares in Contact Energy. Included in 2001 investing activities
was proceeds of $782 million received from the sale-leaseback transaction with respect to the Homer City facilities in December 2001. In connection with this transaction,
$139 million was deposited into a restricted cash account on the closing date resulting in a further increase of restricted cash in 2001. In June 2001, a subsidiary of EME also completed
the sale of a 50% interest in the Sunrise project to Texaco for $84 million.

In
2001, cash provided by investing activities from discontinued operations was primarily due to £643 million proceeds received from the sale of the Ferrybridge and
Fiddler's Ferry power plants on December 21, 2001.

In
2000, net cash provided by investing activities from continuing operations included proceeds of $1.4 billion and $300 million received from the
sale-leaseback transactions with respect to the Powerton and Joliet power facilities in August 2000 and the Illinois peaker power units in July 2000, respectively. In
connection with the Illinois peaker power units transaction, EME purchased $255 million of notes issued by the lessor. In 2000, $31 million was paid toward the purchase price and
$13 million in equity contributions for the Italian Wind projects, $45 million for the Citizens trading operations and structured transaction investments, and $27 million for the
acquisition of the Sunrise project. In addition, $34 million, $21 million and $20 million was made in equity contributions for the EcoEléctrica project
(June 2000), the Tri Energy project (July 2000) and the ISAB project (September 2000), respectively.

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Historical Distributions Received By Edison Mission Energy

The following table is presented as an aid in understanding the cash flow of EME and its various subsidiary holding companies which depend on distributions from
subsidiaries and affiliates to fund general and administrative costs and debt service costs of recourse debt.

Years Ended
December 31,2002

2001(in millions)Distributions from Consolidated Operating Projects:Edison Mission Midwest Holdings (Illinois Plants)

$


$
75EME Homer City Generation L.P. (Homer City facilities)(1)





121First Hydro Holdings (First Hydro project)





52Holding companies of other consolidated operating projects


94


Distributions from Non-Consolidated Operating Projects:Edison Mission Energy Funding Corp. (Big 4 Projects)(2)


137


129Four Star Oil & Gas Company


21


61Holding companies of other non-consolidated operating projects


99


32Total Distributions

$
351

$
470


---

Total
distributions to EME decreased between 2002 and 2001 due to:



Partially
offset by:



65

---



Restricted Assets of EME's Subsidiaries

Each of EME's direct or indirect subsidiaries is organized as a legal entity separate and apart from EME and its other subsidiaries. Assets of EME's subsidiaries
are not available to satisfy EME's obligations or the obligations of any of its other subsidiaries. However, unrestricted cash or other assets that are available for distribution may, subject to
applicable law and the terms of financing arrangements of the parties, be advanced, loaned, paid as dividends or otherwise distributed or contributed to EME or to its subsidiary holding companies. Set
forth below is a description of
covenants binding EME's principal subsidiaries that may restrict the ability of those entities to make distributions to EME directly or indirectly through the other holding companies owned by EME.



Edison Mission Midwest Holdings Co. is the borrower under a $1.9 billion credit facility with a group of commercial banks. The funds borrowed under this
facility were used to fund the acquisition of the Illinois Plants and provide working capital to such operations. Midwest Generation, a wholly owned subsidiary of Edison Mission Midwest Holdings, owns
or leases and operates the Illinois Plants. Midwest Generation entered into sale-leaseback transactions for the Collins Station as part of the original acquisition and for the Powerton
Station and the Joliet Station in August 2000. In order for Edison Mission Midwest Holdings to make a distribution, Edison Mission Midwest Holdings and Midwest Generation must be in compliance
with the covenants specified in these agreements, including maintaining a minimum credit rating. Due to the downgrade of the credit rating of Edison Mission Midwest Holdings to below investment grade,
no distributions can currently be made by Edison Mission Midwest Holdings to its parent company and ultimately, to EME at this time. See "Edison Mission Energy's Credit
RatingsDowngrade of Edison Mission Midwest Holdings."

Edison
Mission Midwest Holdings must also maintain a debt service coverage ratio for the prior twelve-month period of at least 1.50 to 1 as long as the power purchase agreements with
Exelon Generation represent 50% or more of Edison Mission Midwest Holdings' and its subsidiaries' revenues. If the power purchase agreements with Exelon Generation represent less than 50% of Edison
Mission Midwest Holdings' and its subsidiaries' revenues, it must maintain a debt service coverage ratio of at least 1.75 to 1. EME expects that revenues for 2003 from Exelon Generation will represent
50% or more of Edison Mission Midwest Holdings' and its subsidiaries' revenues. In addition, Edison Mission Midwest Holdings must maintain a debt-to-capital ratio no greater
than 0.60 to 1. Failure to meet the historical debt service coverage ratio and the debt-to-capital ratio are events of default under the credit agreement and Collins lease
agreements, which, upon a vote by a majority of the lenders, could cause an acceleration of the due date of the obligations of Edison Mission Midwest Holdings and those associated with the Collins
lease. Such an acceleration would result in an event of default under the Powerton and Joliet leases. During the 12 months ended December 31, 2002, the historical debt service coverage
ratio was 4.04 to 1 and the debt-to-capital ratio was 0.51 to 1.

There
are no restrictions on the ability of Midwest Generation to make payments on the outstanding intercompany loans from its affiliate Edison Mission Overseas Co. (which is also a
subsidiary of Edison Mission Midwest Holdings) or to make distributions directly to Edison Mission Midwest Holdings.



EME Homer City Generation L.P. completed a sale-leaseback of the Homer City facilities in December 2001. In order to make a distribution, EME
Homer City must be in compliance with the

66

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covenants specified in the lease agreements, including the following financial performance requirements measured on the date of distribution:



During
the 12 months ended December 31, 2002, the senior rent service coverage ratio was 2.48 to 1.



A subsidiary of First Hydro Holdings, First Hydro Finance plc, is the borrower of £400 million of Guaranteed Secured Bonds due in 2021. In
order to make a distribution, First Hydro Finance must be in compliance with the covenants specified in its bond indenture, including the following interest coverage ratio:



First
Hydro Holdings' interest coverage ratio must also exceed a minimum default threshold included in the Guaranteed Secured Bonds. When measured for the twelve-month period ended
December 31, 2002, First Hydro Holdings' interest coverage ratio was 1.7 to 1.

On
March 14, 2003, First Hydro Finance plc received a letter from the trustee for the First Hydro bonds, requesting that First Hydro Finance engage in a process to determine
whether an early redemption option in favor of the bondholders has been triggered under the terms of the First Hydro bonds. This letter states that, given requests made of the trustee by a group of
First Hydro bondholders, the trustee needs to satisfy itself whether the termination of the pool system in the United Kingdom (replaced with the new electricity trading arrangements, referred to as
NETA), was materially prejudicial to the interests of the bondholders. If this were the case, it could provide the First Hydro bondholders with an early redemption option. In this regard, on
August 29, 2000, First Hydro Finance notified the trustee that the enactment of the Utilities Act of 2000, which laid the foundation for NETA, would result, after its implementation, in a so
called restructuring event under the terms of the First Hydro bonds. However, First Hydro Finance did not believe then, nor does it believe now, that this event was materially prejudicial to the First
Hydro bondholders. Since NETA implementation, First Hydro Finance has continued to meet all of its debt service obligations and financial covenants under the bond documentation, including the required
interest coverage ratio. Until its receipt of the trustee's March 14, 2003 letter, First Hydro Finance had not received a response from the trustee to its August 29, 2000 notice. First
Hydro Finance will vigorously dispute any attempt to have the early redemption option deemed applicable due to NETA implementation.

67

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Neither the August 2000 notice provided to the trustee, nor the March 14, 2003 letter from the trustee constitutes an event of default under the terms of the First Hydro
bonds; and there is no recourse to EME for the obligations of First Hydro Finance in respect of the First Hydro bonds. However, if the bondholders were entitled to an early redemption option, First
Hydro Finance would be obligated to purchase all First Hydro bonds put to it by bondholders at par plus an early redemption premium. If all bondholders opted for the early redemption option, it is
unlikely that First Hydro Finance would have sufficient financial resources to so purchase the bonds. There is no assurance that First Hydro Finance would be able to obtain additional financing to
fund the purchase of the First Hydro bonds. Therefore, an exercise of the early redemption option by the bondholders could lead to administration proceedings as to First Hydro Finance in the United
Kingdom, which is similar to Chapter 11 bankruptcy proceedings in the United States. If these events were to occur, it would have a material adverse effect upon First Hydro Finance and could have a
material adverse effect upon EME.



EME's subsidiaries, which EME refers to as the guarantors, that hold EME's interests in the Big 4 Projects completed a $450 million secured financing in
December 1996. Edison Mission Energy Funding Corp., a special purpose Delaware corporation, issued notes ($260 million) and bonds ($190 million), the net proceeds of which were
lent to the guarantors in exchange for a note. The guarantors have pledged their cash proceeds from the Big 4 Projects to Edison Mission Energy Funding as collateral for the note. All distributions
receivable by the guarantors from the Big 4 Projects are deposited into a trust account from which debt service payments are made on the obligations of Edison Mission Energy Funding and from which
distributions may be made to EME if Edison Mission Energy Funding is in compliance with the terms of the covenants in its financing documents, including the following requirements measured on the date
of distribution:



The
debt service coverage ratio is determined by the amount of distributions received by the guarantors from the Big 4 Projects during the relevant quarter divided by the debt service
(principal and interest) on Edison Mission Energy Funding's notes and bonds paid or due in the relevant quarter. During the
12 months ended December 31, 2002, the debt service coverage ratio was 4.94 to 1. Although the credit ratings of Edison Mission Energy Funding's notes and bonds are below investment
grade, this had no effect on the ability of the guarantors to make distributions to EME.

Other Matters Related to Distributions from Subsidiaries or Affiliates

Paiton ProjectOn December 23, 2002, an amendment to the original power purchase agreement
became effective, bringing to a close and resolving a series of disputes between Paiton Energy and PT PLN which began in 1999 and were caused, in large part, by the effects of the regional financial
crisis in Asia and Indonesia. The amended power purchase agreement includes changes in the price for power and energy charged under the power purchase agreement, provides for payment over time of
amounts unpaid prior to January 2002 and extends the expiration date of the power purchase agreement from 2029 to 2040. These terms have been in effect since January 2002 under a
previously agreed Binding Term Sheet which was replaced by the power purchase agreement amendment.

In
February 2003, Paiton Energy and all of its lenders completed the restructuring of the project's debt. As part of the restructuring, Export-Import Bank of the United States
loaned the project $381 million, which was used to repay loans made by commercial banks during the period of the project's construction. In addition, the amortization schedule for repayment of
the project's loans was

68

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extended to take into account the effect upon the project of the lower cash flow resulting from the restructured electricity tariff. The initial principal repayment under the new amortization
schedule was made on February 18, 2003. Distributions from the project are not anticipated to occur until 2006.

Mission Energy Holding Company's Interest Coverage Ratio

The following details of MEHC's interest coverage ratio are provided as an aid to understanding the components of the computations that are set forth in the
indenture governing MEHC's senior secured notes. This information is not intended to measure the financial performance of MEHC and, accordingly, should not be used in lieu of the financial information
set forth in MEHC's consolidated financial statements. The terms Funds Flow from Operations, Operating Cash Flow and Interest Expense are as defined in the indenture and are not the same as would be
determined in accordance with generally accepted accounting principles.

MEHC's
interest coverage ratio is comprised of interest income and expense related to its holding company activities and the consolidated financial information of EME. For a complete
discussion of EME's interest coverage ratio and the components included therein, see "Edison Mission Energy's Interest Coverage Ratio" below. The following table sets forth MEHC's interest coverage
ratio for the year ended December 31, 2002 and a pro forma calculation of MEHC's interest coverage ratio for the year ended December 31, 2001.

December 31, 2001December 31,
2002

Actual

Pro Forma
Adjustments(1)

Pro
Forma(in millions)Funds Flow From Operations:Edison Mission Energy

$
691

$
499




$
499Less: Operating cash flow from unrestricted subsidiaries


(16
)







Add: Outflows of funds from operations of projects sold


2


103





103Mission Energy Holding


7


5

$
5


10$
684

$
607

$
5

$
612Interest Expense:Edison Mission Energy

$
293

$
305




$
305Edison Mission Energyaffiliate debt


2


3





3Mission Energy Holding interest expense


159


82

$
80


162Less: Interest savings on projects sold





(4
)




(4
)$
454

$
386

$
80

$
466Interest Coverage Ratio


1.51


1.57





1.31


---

The
above interest coverage ratio was determined in accordance with the definitions set forth in the bond indenture governing MEHC's senior secured notes and the credit agreement
governing the term loan agreement. The interest coverage ratio prohibits MEHC, EME and its subsidiaries from incurring additional indebtedness, except as specified in the indenture and the financing
documents, unless MEHC's interest coverage ratio exceeds 1.75 to 1 for the immediately preceding four fiscal

69

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quarters prior to June 30, 2003 and 2.0 to 1 for periods thereafter. Since the issuance of the senior secured notes and term loan occurred mid-year, the pro forma calculation is
provided as an indication of the interest coverage ratio on a full-year basis.

Ability of Edison Mission Energy to Pay Dividends

EME's organizational documents contain restrictions on its ability to declare or pay dividends or distributions. These restrictions require the unanimous approval
of its board of directors, including at least one independent director, before it can declare or pay dividends or distributions, unless either of the following is true:



EME's
interest coverage ratio for the four quarters ended December 31, 2002 was 2.36 to 1. See further details of EME's interest coverage ratio below. Accordingly,
EME is currently permitted to pay dividends of up to $32.5 million in the first quarter of 2003 under the "ring-fencing" provisions of EME's certificate of incorporation and bylaws.
EME did not pay or declare any dividends to MEHC during 2002.

Edison Mission Energy's Interest Coverage Ratio

The following details of EME's interest coverage ratio are provided as an aid to understanding the components of the computations that are set forth in EME's
organizational documents. This information is not intended to measure the financial performance of EME and, accordingly, should not be used in lieu of the financial information set forth in MEHC's
consolidated financial statements. The terms Funds Flow from Operations, Operating Cash Flow and Interest Expense are as defined in EME's organizational documents and are not the same as would be
determined in accordance with generally accepted accounting principles.

70

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The
following table sets forth the major components of one of EME's interest coverage ratio for 2002 and 2001:

December 31,
2002

December 31,
2001(in millions)Funds Flow from Operations:Operating Cash Flow(1) from Consolidated Operating Projects(2):Illinois Plants(3)

$
294

$
201Homer City


51


175Ferrybridge and Fiddler's Ferry


(2
)

(104
)First Hydro


47


46Other consolidated operating projects


160


64Price risk management and trading


16


28Distributions from non-consolidated Big 4 projects(4)


137


129Distributions from other non-consolidated operating projects


120


94Interest income


8


9Operating expenses


(139
)

(143
)Total funds flow from operations


692


499Interest Expense:From obligations to unrelated third parties


178


189From notes payable to Midwest Generation


115


116Total interest expense


293


305Interest Coverage Ratio


2.36


1.64


---



71

---



The
above interest coverage ratio is not determined in accordance with generally accepted accounting principles as reflected in EME's Consolidated Statements of Cash Flows. Accordingly,
this ratio should not be considered in isolation or as a substitute for cash flows from operating activities or cash flow statement data set forth in EME's Consolidated Statement of Cash Flows. This
ratio does not measure the liquidity or ability of EME's subsidiaries to meet their debt service obligations. Furthermore, this ratio is not necessarily comparable to other similarly titled captions
of other companies due to differences in methods of calculations.

Edison Mission Energy Recourse Debt to Recourse Capital Ratio

Under the credit agreement governing its credit facility, EME has agreed to maintain a recourse debt to recourse capital ratio as shown in the table below.

|Financial Ratio                         |  | Covenant                    |  | Actual at
December 31, 2002 |  | Description                                                                                                                                                                            
|--------------------------------------- |  | --------------------------- |  | --------------------------- |  | ---------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
|Recourse Debt to Recourse Capital Ratio |  | Less than or equal to 67.5% |  | 62.2%                       |  | Ratio of (a) senior recourse debt to (b) sum of (i) shareholder's equity per EME's balance sheet adjusted by comprehensive income after December 31, 1999,plus(ii) senior recourse debt

Discussion of Recourse Debt to Recourse Capital Ratio

The recourse debt to recourse capital ratio of EME at December 31, 2002 and 2001 was calculated as follows:

December 31,
2002

December 31,
2001(in millions)Recourse Debt(1)Corporate Credit Facilities

$
140

$
204Senior Notes


1,600


1,700Guarantee of termination value of Powerton/Joliet operating leases


1,452


1,432Coal and Capex Facility


182


251Other


30


46Total Recourse Debt to EME

$
3,404

$
3,633Adjusted Shareholder's Equity(2)

$
2,066

$
2,039Recourse Capital(3)

$
5,470

$
5,672Recourse Debt to Recourse Capital Ratio


62.2
%

64.1
%


---

72

---

During
the year ended December 31, 2002, the recourse debt to recourse capital ratio improved due to:



During
2001, the recourse debt to recourse capital ratio was adversely affected by a decrease in EME's shareholder's equity from $1.1 billion of after-tax losses
attributable to the loss on sale of EME's Ferrybridge and Fiddler's Ferry coal-fired power plants located in the United Kingdom. EME sold the Ferrybridge and Fiddler's Ferry power plants
in December 2001 due, in part, to the adverse impact of the negative cash flow pertaining to these plants.

Edison Mission Energy's Subsidiary Financing Plans

The estimated capital and construction expenditures of EME's subsidiaries for 2003 total $88 million. These expenditures are planned to be financed by
existing subsidiary credit agreements and cash generated from their operations, except with respect to the Homer City project. Under the Homer City sale-leaseback agreements, EME has
committed to provide funds for capital expenditures needed by the power plant. Approximately $22 million was contributed during 2002 and EME expects to contribute an additional
$14 million in 2003. See "Contractual Obligations, Commitments and Contingencies."

Edison Mission Midwest Holdings

EME's wholly owned subsidiary, Edison Mission Midwest Holdings, had long-term debt with the following maturities at December 31, 2002:

Amount

Due Date(in millions)$
911

December 2003808

December 2004$
1,719


In
addition, Edison Mission Midwest Holdings has a $150 million working capital facility (unused at December 31, 2002) which is scheduled to expire in December 2004.
Edison Mission Midwest Holdings is not expected to have sufficient cash to repay the $911 million debt due in December 2003. Edison Mission Midwest Holdings plans to extend or refinance
the $911 million debt obligation at or prior to its expiration in December 2003. Completion of this extension or refinancing is subject to a number of uncertainties, including the
ability of the Illinois Plants to generate funds during 2003 and the availability of credit from financial institutions on acceptable terms in light of industry conditions. Accordingly, there is no
assurance that Edison Mission Midwest Holdings will be able to extend or refinance this debt when it becomes due or that the terms will not be substantially different from those under its current
credit facility. See "Risk Factors."

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Sunrise Project Financing

EME owns a 50% interest in Sunrise Power Company, which owns a natural gas-fired facility currently under construction in Kern County, California,
which EME refers to as the Sunrise project. The Sunrise project consists of two phases. Phase 1, a simple-cycle gas-fired facility (320 MW), was completed on June 27, 2001. Phase 2,
conversion to a combined-cycle gas-fired facility (bringing the capacity to a total of 560 MW), is currently scheduled to be completed in July 2003. Sunrise Power
Company entered into a long-term power purchase agreement with the California Department of Water Resources on June 25, 2001. The agreement was amended on December 31, 2002
as part of the settlement of certain matters between Sunrise Power Company and the State of California. For further discussion related to this agreement, see "Item 3. Legal
ProceedingsRegulatory Developments Affecting Sunrise Power Company." The construction of the Sunrise project has been funded with equity contributions by its partners, including EME.
Sunrise Power Company has engaged a financial advisor to assist with obtaining project financing. Completion of project financing is subject to a number of uncertainties, including market
uncertainties and obtaining final environmental permits. EME believes that project financing will be obtained in 2003, although no assurance can be provided in this regard. If project financing is
completed by mid-2003, EME estimates a distribution of approximately $150 million from the proceeds of such financing.

Intercompany Tax-Allocation Payments

MEHC and EME are included in the consolidated federal and combined state income tax returns of Edison International and are eligible to participate in
tax-allocation payments with other subsidiaries of Edison International. These arrangements depend on Edison International continuing to own, directly or indirectly, at least 80% of the voting power
of the stock of MEHC and EME and at least 80% of the value of such stock. The arrangements are subject to the terms of tax allocation and payment agreements among Edison International, MEHC, EME and
other Edison International subsidiaries. The agreements to which MEHC and EME are parties may be terminated by the immediate parent company of MEHC at any time, by notice given before the first day of
the first year with respect to which the termination is to be effective. However, termination does not relieve any party of any obligations with respect to any tax year beginning prior to the notice.
MEHC became a party to the tax-allocation agreement with The Mission Group on July 2, 2001, when it became part of the Edison International consolidated filing group. EME and MEHC
have historically received tax-allocation payments related to domestic net operating losses incurred by EME and MEHC. The right of MEHC and EME to receive and the amount and timing of
tax-allocation payments are dependent on the inclusion of MEHC and EME, respectively, in the consolidated income tax returns of Edison International and its subsidiaries, the amount of net
operating losses and other tax items of MEHC, EME and its subsidiaries and other subsidiaries of Edison International and specific procedures regarding allocation of state taxes. MEHC and EME receive
tax-allocation payments for tax losses when and to the extent that the consolidated Edison International group generates sufficient taxable income in order to be able to utilize MEHC's tax
losses or the tax losses of EME in the consolidated income tax returns for Edison International and its subsidiaries. This occurred in 2002, and, accordingly, MEHC received $89 million in
tax-allocation payments. In addition, EME received $395 million in tax-allocation payments during 2002 from Edison International, which included $258 million
related to tax-allocation amounts for periods prior to 2002 and $137 million as an estimated tax-allocation payment for 2002. In the future, based on the application of
the factors cited above, MEHC or EME may be obligated during periods they generate taxable income to make payments under the tax-allocation agreements.

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Contractual Obligations, Commitments and Contingencies

Contractual Obligations

The following table summarizes consolidated contractual obligations as of December 31, 2002.

|                                            |  | Payments Due by Period |       | 
|------------------------------------------- |  | ---------------------- | ----- | 
|
|
|
|Long-term debt (excluding EME)              |  | $                      |      | 
|EME's long-term debt                        |  |                        | 1,090 | 
|Operating lease obligations (including EME) |  |                        | 341   | 
|EME's Chicago In-City obligation            |  |                        | 22    | 
|EME's fuel supply contracts                 |  |                        | 605   | 
|EME's gas transportation agreements         |  |                        | 8     | 
|                                            |  |                        |       | 
|Total Contractual Cash Obligations          |  | $                      | 2,066 | 
|                                            |  |                        |       | 

Sale-Leaseback Commitments

At December 31, 2002, minimum operating lease payments were primarily related to long-term leases for the Collins, Powerton, Joliet and Homer
City power plants. In connection with the 1999 acquisition of the Illinois Plants, EME assigned the right to purchase the Collins gas and oil-fired power plant to third-party lessors. The
third-party lessors purchased the Collins Station for $860 million and leased the plant to EME. During 2000, EME entered into sale-leaseback transactions for equipment, primarily
the Illinois peaker power units, and for two power facilities, the Powerton and Joliet coal fired stations located in Illinois, with third-party lessors. In August 2002, EME exercised its
option and repurchased the Illinois peaker power units. During the fourth quarter of 2001, EME entered into a sale-leaseback transaction for the Homer City coal-fired
facilities located in Pennsylvania, with third-party lessors. Total minimum lease payments (included in the table above under "operating lease obligations") during the next five years are
$311 million in 2003, $291 million in 2004, $343 million in 2005, $427 million in 2006, and $465 million in 2007. At December 31, 2002, the minimum lease
payments due after 2007 were $4.9 billion. For further discussion, see "Off-Balance Sheet TransactionsSale-Leaseback Transactions."

Chicago In-City Obligation

Pursuant to the acquisition documents for the purchase of generating assets from Commonwealth Edison, EME's subsidiary, Midwest Generation, committed to install
one or more gas-fired electric generating units having an additional gross dependable capacity of 500 MW at or adjacent to an existing power plant site in Chicago, this commitment being
referred to as the In-City Obligation, for an estimated cost of $320 million. The acquisition documents required that commercial operation of this project commence by
December 15, 2003. Due to additional capacity for new gas-fired generation in the Mid-America Interconnected Network, generally referred to as the MAIN Region, and the
improved reliability of power generation in the Chicago area, EME did not believe the additional gas-fired generation was needed. In February 2003, Midwest Generation finalized an
agreement with Commonwealth Edison to terminate this commitment in exchange for the following:



75

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As
a result of this agreement with Commonwealth Edison, Midwest Generation recorded a loss of $45 million during the fourth quarter of 2002. The loss was determined by the sum of:
(a) the present value of the cash payments to both Commonwealth Edison and Calumet Energy Team LLC (capacity payments), less (b) the fair market value of the option to purchase power
under the replacement contract with Calumet Energy Team LLC. As a result of the agreement with Commonwealth Edison, Midwest Generation is no longer obligated to build the additional
gas-fired generation.

Fuel Supply Contracts

At December 31, 2002, EME's subsidiaries had contractual commitments to purchase and/or transport coal and fuel oil. The minimum commitments are based on
the contract provisions, which consist of fixed prices, subject to adjustment clauses in some cases.

Gas Transportation Agreements

At December 31, 2002, EME had contractual commitments to transport natural gas beginning the later of May 1, 2003 or the first day that expansion
capacity is available for transportation services. In June 2001, EME entered into an agreement with Texaco Power & Gasification Holdings, Inc. for the purpose of committing, and
eventually assigning, one of the contracts to the Sunrise project. In this agreement, Texaco Power & Gasification Holdings, Inc. has agreed to assume 50% of EME's liabilities under the
specified contract until its formal assignment to the Sunrise project. EME is committed to pay minimum fees under these agreements, which have a term of 15 years.

Other Commercial Commitments

The following table summarizes EME's consolidated commercial commitments as of December 31, 2002. Details regarding these commercial commitments are
discussed in the sections following the table.

|                                                   |  | Amount of Commitments Per Period |     | 
|-------------------------------------------------- |  | -------------------------------- | --- | 
|
|
|
|Standby letters of credit                          |  | $                                | 135 | 
|Firm commitment for asset purchase                 |  |                                  | 2   | 
|Firm commitments to contribute project equity      |  |                                  | 75  | 
|Capital improvements at EME's project subsidiaries |  |                                  | 38  | 
|                                                   |  |                                  |     | 
|Total Commercial Commitments                       |  | $                                | 250 | 
|                                                   |  |                                  |     | 

Firm Commitment for Asset Purchase

Projects

Local Currency

U.S. Currency(in millions)Italian Wind and Expansion(i)

2 million Euro

$
2


---

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Firm Commitments to Contribute Project Equity

Projects

U.S. Currency(in millions)CBK(i)

$
37Italian Wind Expansion(ii)

$
2Sunrise(iii)

$
36


---

Firm
commitments to contribute project equity to the CBK project and the Italian Wind expansion project could be accelerated due to events of default as defined in the
non-recourse project financing facilities.

Contingencies

Paiton Project

A wholly owned subsidiary of EME owns a 40% interest in PT Paiton Energy, which owns a 1,230 MW coal-fired power plant in operation in East
Java, Indonesia, which is referred to as the Paiton project. Under the terms of a long-term power purchase agreement between Paiton Energy and PT PLN, the state-owned electric utility
company, PT PLN is required to pay for capacity and fixed operating costs since each unit and the plant have achieved commercial operation.

On
December 23, 2002, an amendment to the original power purchase agreement became effective, bringing to a close and resolving a series of disputes between Paiton Energy and PT
PLN

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which began in 1999 and were caused, in large part, by the effects of the regional financial crisis in Asia and Indonesia. The amended power purchase agreement includes changes in the price for power
and energy charged under the power purchase agreement, provides for payment over time of amounts unpaid prior to January 2002 and extends the expiration date of the power purchase agreement
from 2029 to 2040. These terms have been in effect since January 2002 under a previously agreed Binding Term Sheet which was replaced by the power purchase agreement amendment.

In
February 2003, Paiton Energy and all of its lenders concluded a restructuring of the project's debt. As part of the restructuring, Export-Import Bank of the United States
loaned the project $381 million, which was used to repay loans made by commercial banks during the period of the project's construction. In addition, the amortization schedule for repayment of
the project's loans was extended to take into account the effect upon the project of the lower cash flow resulting from the restructured electricity tariff. The initial principal repayment under the
new amortization schedule was made on February 18, 2003. Distributions from the project to shareholders are not anticipated to commence until 2006. As a condition to the making of the loans by
Export-Import Bank of the United States, all commercial disputes related to the project were settled without a material effect on EME. EME believes that it will ultimately recover its investment in
the project.

EME's
investment in the Paiton project increased to $514 million at December 31, 2002 from $492 million at December 31, 2001. The increase in the investment
account resulted from EME's
subsidiary recording its proportionate share of net income from Paiton Energy. EME's investment in the Paiton project will increase (decrease) from earnings (losses) from Paiton Energy and decrease by
cash distributions. Assuming Paiton Energy remains profitable, EME expects the investment account to increase substantially during the next several years as earnings are expected to exceed cash
distributions.

BHP Fuel Supply Agreement Arbitration

During 2002, PT Batu Hitam Perkasa (BHP), one of the other shareholders in Paiton Energy, reinstated a previously suspended arbitration to resolve disputes under
the fuel supply agreement between BHP and Paiton Energy. The arbitration commenced in 1999 but had been stayed since that time to allow the parties to engage in settlement discussions related to a
restructuring of the coal supply arrangements for the Paiton project. These discussions did not at the time lead to settlement, and BHP requested an arbitration tribunal to reinstate the original
arbitration and to permit BHP to assert additional claims. In total, BHP's claims amounted to $250 million.

On
December 19, 2002, Paiton Energy and BHP entered into an agreement whereby all claims in the arbitration were settled and agreement was reached to dismiss the arbitration with
no material effect upon Paiton Energy. Paiton Energy made the required payment to BHP under the terms of the settlement agreement, and all claims have been dismissed.

Brooklyn Navy Yard Project

Brooklyn Navy Yard is a 286 MW gas-fired cogeneration power plant in Brooklyn, New York. EME's subsidiary owns 50% of the project. In
February 1997, the construction contractor asserted general monetary claims under the turnkey agreement against Brooklyn Navy Yard Cogeneration Partners, L.P. for damages in the amount of
$137 million. Brooklyn Navy Yard Cogeneration Partners asserted general monetary claims against the contractor. In connection with a $407 million non-recourse project
refinancing in 1997, EME agreed to indemnify Brooklyn Navy Yard Cogeneration Partners and its partner from all claims and costs arising from or in connection with the contractor litigation, which
indemnity has been assigned to Brooklyn Navy Yard Cogeneration Partners' lenders. During December 2002, the parties held mediation sessions and reached a settlement of all outstanding claims. A
settlement agreement was executed on January 17, 2003, and all litigation has been dismissed. The settlement agreement did not have a material effect upon the project or EME.

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ISAB Project

In connection with the financing of the ISAB project, which is located near Siracusa in Sicily, Italy, EME guaranteed, for the benefit of the banks financing the
construction of the ISAB project, the obligation of one of its subsidiaries to contribute project equity and subordinated debt totaling up to approximately $39 million. The amount of payment
under the obligation was contingent upon the outcome of an arbitration proceeding brought in 1999 by the contractor of the project against ISAB Energy. During December 2002, the parties reached
agreement on a full and final settlement of all claims at issue. Conditions to the settlement were satisfied in February 2003. The agreement provides for no payments to be made by the ISAB
project and thus no payments will be required under the EME guarantee referred to above.

Regulatory Developments Affecting Sunrise Power Company

Sunrise Power Company, in which EME's wholly owned subsidiary owns a 50% interest, sells all its output to the California Department of Water Resources under a
power purchase agreement entered into on June 25, 2001. On February 25, 2002, the California Public Utilities Commission and the California Electricity Oversight Board filed complaints
with the Federal Energy Regulatory Commission against all sellers of power under long-term contracts to the California Department of Water Resources, including Sunrise Power Company. The
California Public Utilities Commission complaint alleged that the contracts were "unjust and unreasonable" on price and other terms, and requested that the contracts be abrogated. The California
Electricity Oversight Board complaint made a similar allegation and requested that the contracts be deemed voidable at the request of the California Department of Water Resources or, in the
alternative, abrogated as of a future date, to allow for the possibility of renegotiation. In January 2003, the California Public Utilities Commission and California Electricity Oversight Board
dismissed their complaints against Sunrise Power Company pursuant to a global settlement that also involved a restructuring of Sunrise Power Company's long-term contract with the
California Department of Water Resources. On December 31, 2002, Sunrise Power Company restructured its contract with the California Department of Water Resources. The restructured agreement
reduced by 5% the capacity payments to be made to Sunrise Power Company as compensation for having power available when needed. In addition, Sunrise Power Company's option to extend the agreement for
one year beyond December 31, 2011 was terminated; however, the term of the restructured agreement was extended until June 30, 2012.

On
May 2, 2002, the United States Justice Foundation announced that it had filed a complaint in the Superior Court of the State of California, Los Angeles County, against the
California Department of Water Resources, all sellers of power under long-term energy contracts entered into in 2001, including Sunrise Power Company, and Vikram Budhraja, one of the
consultants involved in the negotiation of energy contracts on behalf of the California Department of Water Resources. The lawsuit asks the Superior Court to void all the contracts entered into in
2001, as well as all the contracts renegotiated in 2002, as a result of a purported conflict of interest by Mr. Budhraja. Sunrise Power Company has not yet been served with the complaint.

On
May 15, 2002, Sunrise Power Company was served with a complaint filed in the Superior Court of the State of California, City and County of San Francisco, by James M. Millar,
"individually, and on behalf of the general public and as a representative taxpayer suit" against sellers of long-term power to the California Department of Water Resources, including
Sunrise Power Company. The lawsuit alleges that the defendants, including Sunrise Power Company, engaged in unfair and fraudulent business practices by knowingly taking advantage of a manipulated
power market to obtain unfair contract terms. The lawsuit seeks to enjoin enforcement of the "unfair and oppressive terms and conditions" in the contracts, as well as restitution by the defendants of
excessive monies obtained by the defendants. Plaintiffs in several other class action lawsuits pending in Northern California have filed petitions seeking to have the Millar lawsuit consolidated with
those lawsuits. The defendants in the Millar

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lawsuit and other class action suits removed all the lawsuits to the U.S. District Court, Northern District of California, and filed a motion to stay all proceedings pending final resolution of the
jurisdictional issue. Various plaintiffs have filed pleadings opposing the removal and requesting that the matters be remanded to state court. The motions are still pending. EME believes that the
outcome of this litigation will not have a material adverse effect on its consolidated financial position or results of operations.

Regulatory Developments Affecting Doga Project

On August 4, 2002, a new Electricity Market License Regulation was implemented in Turkey. The regulation contains, among other things, a requirement for
each generator to obtain a generation license. Historically, Doga's Implementation Contract has been its sole license. The new regulation contemplates an initial fixed license fee and a yearly license
fee based on the amount of energy generated, which will increase the project's costs of operation by an undetermined amount. In addition, the regulation allows the insertion of provisions in the
license which are different from those in the Implementation Contract.

The
effect of the new regulation is still undetermined, as the new license provisions have not been specified. The new regulation requires Doga to apply for a generation license between
March and April of 2003. If actions or inactions undertaken pursuant to the new regulation directly or indirectly impede, hinder, prevent or delay the operation of the Doga facility or increase Doga's
cost of performing its obligations under its project documents, this may constitute a risk event under Doga's Implementation Contract. A risk event may permit Doga to request an increase in its tariff
or, under certain circumstances, request a buyout of the project by the Ministry of Energy and Natural Resources.

On
October 3, 2002, Doga and several other independent power producers filed a lawsuit in the Danistay, Turkey's high administrative court, against the Energy Market Regulatory
Authority seeking invalidation of certain provisions of the new regulation, arguing the unconstitutionality of the imposition of new license requirements that do not take into account the vested
rights of companies presently performing electricity generation pursuant to previously agreed conditions. No decision has been rendered and discussions with the Turkish authorities continue.

Federal Income Taxes

Edison International received a notice on August 7, 2002, from the Internal Revenue Service asserting deficiencies in EME's federal corporation income
taxes for its 1994 to 1996 tax years. Edison International filed a timely protest to this notice. EME believes that it has meritorious legal defenses to those deficiencies and believes that the
ultimate outcome of this matter will not result in a material impact on its consolidated results of operations or financial position.

EME
is, and may in the future be, under examination by tax authorities in varying tax jurisdictions with respect to positions EME takes in connection with the filing of its tax returns.
Matters raised upon audit may involve substantial amounts, which, if resolved unfavorably, an event not currently anticipated, could possibly be material. However, in EME's opinion, it is unlikely
that the resolution of any such matters will have a material adverse effect upon EME's financial condition or results of operations.

Guarantees and Indemnities



In connection with the sale-leaseback transactions that EME has entered into related to the Collins Station, Powerton and Joliet plants in Illinois
and the Homer City facilities in Pennsylvania, EME or one of its subsidiaries has entered into tax indemnity agreements. Under these tax indemnity agreements, EME has agreed to indemnify the lessors
in the sale-leaseback transactions for specified

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adverse tax consequences that could result in certain situations set forth in each tax indemnity agreement, including specified defaults under the respective leases. The potential indemnity
obligations under these tax indemnity agreements could be significant. Due to the nature of these obligations under these tax indemnity agreements, EME cannot determine a maximum potential liability.
The indemnities would be triggered by a valid claim from the lessors. EME has not recorded a liability related to these indemnities.



In connection with the acquisition of the Illinois Plants, EME agreed to indemnify Commonwealth Edison against damages, claims, fines, liabilities and expenses
and losses arising from, among other things, environmental liabilities before and after the date of sale as specified in the Asset Sale Agreement dated March 22, 1999. The indemnification
claims are reduced by any insurance proceeds and tax benefits related to such claims and are subject to a requirement by Commonwealth Edison to take all reasonable steps to mitigate losses related to
any such indemnification claim. Due to the nature of the obligation under this indemnity, a maximum potential liability cannot be determined. The indemnification for the environmental liabilities
referred to above is not limited in term and would be triggered by a valid claim from Commonwealth Edison. Except as discussed below, EME has not recorded a liability related to this indemnity.

Midwest
Generation entered into a supplemental agreement to resolve a dispute regarding interpretation of its reimbursement obligation for asbestos claims under the environmental
indemnities set forth in the Asset Sale Agreement. Under this supplemental agreement, Midwest Generation agreed to reimburse Commonwealth Edison 50% of specific existing asbestos claims less recovery
of insurance costs, and agreed to a sharing arrangement for liabilities associated with future asbestos related claims as specified in the agreement. The obligations under this agreement are not
subject to a maximum liability. The supplemental agreement has a five-year term with an automatic renewal provision (subject to the right to terminate). Payments are made under this
indemnity by a valid claim provided from Commonwealth Edison. At December 31, 2002, Midwest Generation recorded a $5 million liability related to known claims provided by Commonwealth
Edison.



In connection with the acquisition of the Homer City facilities, EME Homer City Generation L.P. is obligated to indemnify the sellers against damages,
claims and losses arising from environmental liabilities before and after the date of sale as specified in the Asset Purchase Agreement dated August 1, 1998. EME guaranteed the obligations of
EME Homer City. Due to the nature of the obligation under this indemnity provision, it is not subject to a maximum potential liability nor has an expiration date. Payments would be triggered under
this indemnity by a claim from the sellers. EME has not recorded a liability related to this indemnity.



In connection with the sale of assets, EME has provided indemnities to the purchasers for taxes imposed with respect to operations of the asset prior to the sale,
and EME or its subsidiaries have received similar indemnities from purchasers related to taxes arising from operations after the sale.
EME also provided indemnities to purchasers for items specified in each agreement (for example, specific pre-existing litigation matters and/or environmental conditions). Due to the nature
of the obligations under these indemnity agreements, a maximum potential liability cannot be determined. Indemnities under the asset sale agreements do not have specific expiration dates. Payments
would be triggered under these indemnities by valid claims from the sellers or purchasers, as the case may be. EME has not recorded a liability related to these indemnities.

81

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Brooklyn Navy Yard is a 286 MW gas-fired cogeneration power plant in Brooklyn, New York. EME's wholly owned subsidiary owns 50% of the project.
In February 1997, the construction contractor asserted general monetary claims under the turnkey agreement against Brooklyn Navy Yard Cogeneration Partners, L.P. A settlement agreement was
executed on January 17, 2003, and all litigation has been dismissed. EME has indemnified Brooklyn Navy Yard Cogeneration Partners, L.P. for any payments due under this settlement agreement
which are scheduled through 2006. At December 31, 2002, EME recorded a liability of $32 million related to this indemnity.



TM Star was formed for the limited purpose to sell natural gas to the March Point Cogeneration Company, an affiliate through common ownership, under a fuel supply
agreement that extends through December 31, 2011. TM Star has entered into fuel purchase contracts with unrelated third parties to meet a portion of the obligations under the fuel supply
agreement. EME has guaranteed 50% of TM Star's obligation under the fuel supply agreement to March Point Cogeneration. Due to the nature of the obligation under this guarantee, a maximum potential
liability cannot be determined. TM Star has met its obligations to March Point Cogeneration, and, accordingly, no claims against this guarantee have been made.



EME has guaranteed, jointly and severally with Texaco Inc., the obligations of March Point Cogeneration Company under its project power sales agreements to
repay capacity payments to the project's power purchaser in the event that the power sales agreement terminates, March Point Cogeneration Company abandons the project, or the project fails to return
to normal operations within a reasonable time after a complete or partial shutdown, during the term of the power contracts. In
addition, subsidiaries of EME have guaranteed the obligations of Kern River Cogeneration Company and Sycamore Cogeneration Company under their project power sales agreements to repay capacity payments
to the projects' power purchaser in the event that the projects unilaterally terminate their performance or reduce their electric power producing capability during the term of the power contracts. The
obligations under the indemnification agreements as of December 31, 2002, if payment were required, would be $209 million. EME has no reason to believe that any of these projects will
either cease operations or reduce its electric power producing capability during the term of its power contract.



EME has indemnified its lenders under its credit facilities from amounts drawn on a $33 million letter of credit issued for the benefit of the lenders to
ISAB Energy, a 49% unconsolidated affiliate, in lieu of ISAB Energy funding a debt service reserve account using additional equity contributions. Accordingly, a default under ISAB Energy's project
debt could result in a draw under the letter of credit which, in turn, would result in a borrowing under EME's credit facilities. The letter of credit is renewed each six-month period or
until ISAB Energy funds the debt service account. The indemnification is subject to the maximum amount drawn under the letter of credit. EME has not recorded a liability related to this indemnity.



A subsidiary of EME has indemnified Central Maine Power Company against decreases in the value of power deliveries by CL Power Sales Eight, L.L.C., an
unconsolidated affiliate, to Central Maine Power as a result of the implementation of a location-based pricing system in the New England Power Pool. The indemnity has the same term as a power supply
agreement between Central Maine

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Power and CL Eight, which runs through December 2016. It is not possible to determine potential differences in values between the various points of delivery in New England Power Pool at this
time. Due to the nature of this indemnity, a maximum potential liability cannot be determined. To the extent EME's subsidiary would be required to make a payment under this indemnity, it and EME are
indemnified by Peabody Energy Corporation pursuant to the 2000 Purchase and Sale Agreement for the acquisition of Citizens Power LLC. EME's subsidiary has not recorded a liability related to this
indemnity.



A subsidiary of EME has guaranteed the obligations of two unconsolidated affiliates to make payments to third parties for power delivered under fixed-price power
sales agreements. These agreements run through 2008. EME believes there is sufficient cash flow to pay the power suppliers assuming timely payment by the power purchasers. Due to the nature of this
indemnity, a maximum potential liability cannot be determined. To the extent EME's subsidiary would be required to make payments under the guarantee, EME's subsidiary and EME are indemnified by
Peabody Energy Corporation pursuant to the 2000 Purchase and Sale Agreement for Citizens Power LLC. EME's subsidiary has not recorded a liability related to this indemnity.

Litigation

EME experiences other routine litigation in the normal course of its business. None of such pending routine litigation is expected to have a material adverse
effect on EME's consolidated financial position or results of operations.

Contingent Obligations to Contribute Project Equity

Projects

Local Currency

U.S. Currency(in millions)Paiton(i)



$
5ISAB(ii)

37 million Euro

$
39


---



For
more information on the ISAB project, see "ISAB Project" above.



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Off-Balance Sheet Transactions

EME has off-balance sheet transactions in two principal areas: investments in projects accounted for under the equity method and operating leases
resulting from sale-leaseback transactions.

Investments Accounted for Under the Equity Method

Investments in which EME has a 50% or less ownership interest are accounted for under the equity method in accordance with and as required by current accounting
standards. Under the equity method, the project assets and related liabilities are not consolidated in EME's consolidated balance sheet. Rather, EME's financial statements reflect its investment in
each entity and it records only its
proportionate ownership share of net income or loss. These investments are of three principal categories.

Historically,
EME has invested in so-called qualifying facilities, that is, those which produce electrical energy and steam, or other forms of useful energy, and which
otherwise meet the requirements set forth in 18 C.F.R. 292.101et seq., otherwise known as the Public Utility Regulatory Policies Act. See "Item 1.
BusinessRegulatory MattersU.S. Federal Energy Regulation." These regulations limit EME's ownership interest in qualifying facilities to no more than 50% due to EME's
affiliation with Southern California Edison, a public utility. For this reason, EME owns a number of domestic energy projects through partnerships in which it has a 50% or less ownership interest.

On
an international basis, for purposes of risk mitigation, EME has often invested in energy projects with strategic partners where its ownership interest is 50% or less.

EME
owns a minority interest in Four Star Oil & Gas Company, an oil and gas company which provides a natural hedge of a portion of the fuel price risk associated with its merchant
power plants.

Entities
formed to own these projects are generally structured with a management committee or board of directors in which EME exercises significant influence but cannot exercise
unilateral control over the operating, funding or construction activities of the project entity. EME's energy projects have generally secured long-term debt to finance the assets
constructed and/or acquired by them. These financings generally are secured by a pledge of the assets of the project entity, but do not provide for any recourse to EME. Accordingly, a default on a
long-term financing of a project could result in foreclosure on the assets of the project entity resulting in a loss of some or all of EME's project investment, but would generally not
require EME to contribute additional capital. At December 31, 2002, entities which EME has accounted for under the equity method had indebtedness of $6 billion, of which
$3 billion is proportionate to EME's ownership interest in these projects. See "New Accounting Standards" for a discussion of the Statement of Financial Accounting Standards
Interpretation No. 46, "Consolidation of Variable Interest Entities" (FIN 46).

Sale-Leaseback Transactions

EME has entered into sale-leaseback transactions related to the Collins, Powerton and Joliet plants in Illinois and the Homer City facilities in
Pennsylvania. See "Contractual Obligations, Commitments and ContingenciesSale-Leaseback Commitments." Each of these transactions was completed and accounted for
in accordance with Statement of Financial Accounting Standards No. 98, which requires, among other things, that all of the risk and rewards of ownership of assets be transferred to a new owner
without continuing involvement in the assets by the former owner other than as normal for a lessee. These transactions were entered into to provide a source of capital either to fund the original
acquisition of the assets or to repay indebtedness previously incurred for the acquisition. In each of these transactions, the assets (or, in the case of the Collins Station, the rights to purchase
them) were sold to and then leased from owner/lessors owned by independent equity investors. In addition to the
equity invested in them, these owner/lessors incurred or assumed long-term debt, referred to as lessor debt, to finance the purchase of the assets. In the case of Powerton and

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Joliet and Homer City, the lessor debt takes the form generally referred to as secured lease obligation bonds. In the case of Collins, the lessor debt takes the form of lessor notes as described in
the footnote to the table below.

EME's
subsidiaries account for these leases as financings in their separate financial statements due to specific guarantees provided by EME or another one its subsidiaries as part of the
sale-leaseback transactions. These guarantees do not preclude EME from recording these transactions as operating leases in its consolidated financial statements, but constitute continuing
involvement under SFAS No. 98 that precludes EME's subsidiaries from utilizing this accounting treatment in their separate subsidiary financial statements. Instead, each subsidiary continues to
record the power plants as assets in a similar manner to a capital lease and records the obligations under the leases as lease financings. EME's subsidiaries, therefore, record depreciation expense
from the power plants and interest expense from the lease financing in lieu of an operating lease expense which EME uses in preparing its consolidated financial statements. The treatment of these
leases as an operating lease in its consolidated financial statements in lieu of a lease financing, which is recorded by EME's subsidiaries, results in an increase in consolidated net income by
$89 million, $55 million and $40 million in 2002, 2001 and 2000, respectively.

The
lessor equity and lessor debt associated with the sale-leaseback transactions for the Collins, Powerton, Joliet and Homer City assets are summarized in the following
table as of December 31, 2002:

Power Station(s)

Acquisition
Price

Equity
Investor

Equity Investment
in Owner/Lessor

Amount of
Lessor Debt

Maturity
Date of
Lessor Debt(in millions)Collins

$
860

PSEG

$
117

$
774

(i)Powerton/Joliet


1,367

PSEG/Citicapital


238


333.5
813.5

2009
2016Homer City


1,591

GECC


798


300
530

2019
2026


---

PSEGPSEG
Resources, Inc.
GECCGeneral Electric Capital Corporation



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The
operating lease payments to be made by each of EME's subsidiary lessees are structured to service the lessor debt and provide a return to the owner/lessor's equity investors. Neither
the value of the leased assets nor the lessor debt is reflected in EME's consolidated balance sheet. In accordance with generally accepted accounting principles, EME records rent expense on a
levelized basis over the terms of the respective leases. To the extent that EME's cash rent payments exceed the amount levelized over the term of each lease, EME records prepaid rent. At
December 31, 2002 and 2001, prepaid rent on these leases was $117 million and $21 million, respectively. To the extent that EME's cash rent payments are less than the amount
levelized, EME reduces the amount of prepaid rent.

In
the event of a default under the leases, each lessor can exercise all of its rights under the applicable lease, including repossessing the power plant and seeking monetary damages.
Each lease sets forth a termination value payable upon termination for default and in certain other circumstances, which generally declines over time and in the case of default may be reduced by the
proceeds arising from the sale of the repossessed power plant. A default under the terms of the Collins, Powerton and Joliet or Homer City leases could result in a loss of EME's ability to use such
power plant and would trigger obligations under EME's guarantee of the Powerton and Joliet leases. These events could have a material adverse effect on EME's results of operations and financial
position.

EME's
minimum lease obligations under its power related leases are set forth under "Contractual Obligations, Commitments and
ContingenciesSale-Leaseback Commitments."

Parent Company Obligations to Midwest Generation

The proceeds, in the aggregate amount of approximately $1.4 billion, received by Midwest Generation from the sale of the Powerton and Joliet plants,
described above under Sale-Leaseback Transactions, were loaned to EME. EME used the proceeds from this loan to repay corporate indebtedness. Although interest and principal payments made
by EME to Midwest Generation under this intercompany loan assist in the payment of the lease rental payments owing by Midwest Generation, the intercompany obligation does not appear on EME's
consolidated balance sheet. This obligation was disclosed to the credit rating agencies at the time of the transaction and has been included by them in assessing EME's credit ratings. The following
table summarizes principal payments due under this intercompany loan:

Years Ending December 31,

Amount(in millions)2003

$
12004


12005


22006


32007


3Thereafter


1,357Total

$
1,367


EME
funds the interest and principal payments due under this intercompany loan from distributions from EME's subsidiaries, including Midwest Generation, cash on hand, and amounts
available under corporate lines of credit. A default by EME in the payment of this intercompany loan could result in a shortfall of cash available for Midwest Generation to meet its lease and debt
obligations. A default by Midwest Generation in meeting its obligations could in turn have a material adverse effect on EME.

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MARKET RISK EXPOSURES

EME's primary market risk exposures are associated with the sale of electricity from and the procurement of fuel for its uncontracted generating plants. These
risks arise from fluctuations in electricity and fuel prices, emission and transmission rights, interest rates and foreign currency exchange rates. EME manages these risks in part by using derivative
financial instruments in accordance with established policies and procedures. See "GeneralCurrent Developments" and "Liquidity and Capital
ResourcesEdison Mission Energy's Credit Ratings" for a discussion of market developments and their impact on EME's credit and the credit of its counterparties.

Commodity Price Risk

EME's merchant power plants and energy trading activities expose EME to commodity price risks. 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 time. Procedures exist which allow for monitoring of all commitments
and positions with regular reviews by a risk management committee. 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 commodity risk, compare risk on a consistent basis and identify the drivers of the risk. Value at risk measures the possible 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 the use of stress testing and worst-case scenario analysis, as well as stop loss limits and counterparty credit exposure limits. Despite this, there can be no assurance that
all risks have been accurately identified, measured and/or mitigated.

Electric
power generated at EME's merchant plants is generally sold under bilateral arrangements with utilities and power marketers under short-term contracts with terms of
two years or less, or, in the case of the Homer City facilities, to the Pennsylvania-New Jersey-Maryland Power Pool (PJM) or the New York Independent System Operator (NYISO). As discussed
further below, beginning in 2003, EME is selling a significant portion of the power generated from its Illinois Plants into wholesale energy markets. In order to provide more predictable earnings and
cash flow, EME may hedge a portion of the electric output of its merchant plants, the output of which is not committed to be sold under long-term contracts. When appropriate, EME manages
the spread between electric prices and fuel prices, and uses forward contracts, swaps, futures, or options contracts to achieve those objectives. There is no assurance that contracts to hedge changes
in market prices will be effective.

EME's
revenues and results of operations during the estimated useful lives of its merchant power plants will depend upon prevailing market prices for capacity, energy, ancillary
services, fuel oil, coal and natural gas and associated transportation costs and emission credits in the market areas where EME's merchant plants are located. Among the factors that influence the
price of power in these markets are:



87

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A
discussion of each market area is set forth below by region.

Americas

Illinois Plants

Electric power generated at the Illinois Plants is currently sold under three power purchase agreements between EME's wholly owned subsidiary, Midwest Generation,
and Exelon Generation Company, under which Exelon Generation 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 capacity and energy payments. Exelon Generation is obligated to make a capacity payment for the plants under contract and an
energy payment for the electricity produced by these plants and taken by Exelon Generation. The capacity payments provide the revenue for fixed charges, and the energy payments compensate the Illinois
Plants for variable costs of production.

Virtually
all of the energy and capacity sales from the Illinois Plants in 2002 were to Exelon Generation under the power purchase agreements. Under each of the power purchase
agreements, Exelon Generation, upon notice by a given date, has the option to terminate each agreement with respect to all or a portion of the units subject to it.

In
July 2002, under the power purchase agreement related to Midwest Generation's coal-fired generation units, Exelon Generation exercised its option to purchase 1,265
MW of capacity and energy during 2003 (of a possible total of 3,949 MW subject to option) from the option coal units. As a result, 2,684 MW of capacity of the Will County 1 and 2, Joliet 6 and 7, and
Powerton 5 and 6 units ceased to be subject to the power purchase agreement from and after January 1, 2003. Exelon Generation continues to have a similar option, exercisable not later than
180 days prior to January 1, 2004, to retain or release for 2004 all or a portion of the option coal units retained for 2003. Exelon Generation remains committed to purchase the capacity
of certain committed units having 1,696 MW of capacity for both 2003 and 2004.

In
October 2002, under the power purchase agreements related to Midwest Generation's Collins Station and peaking units, Exelon Generation exercised its option to terminate the
existing power purchase agreements during 2003 with respect to (a) 1,614 MW of capacity and energy (of a possible total of 2,698 MW subject to the option to terminate) from the Collins Station,
a natural gas and oil-fired electric generating station, and (b) 113 MW of capacity and energy (of a possible total of 807 MW subject to the option to terminate) from the natural
gas and oil-fired peaking units, in accordance with the terms of each applicable power purchase agreement. As a result, 1,614 MW of capacity from the Collins Units 2, 4 and 5, and 113 MW
of capacity from the Lombard 33 and Calumet 33 and 34 peaking units, ceased to be subject to a power purchase agreement from and after January 1, 2003. Previously, Exelon Generation exercised
its option to terminate 137 MW of capacity from the Bloom and Waukegan peaking units effective January 1, 2002. Exelon Generation continues to have a similar option to terminate, exercisable
not later than 90 days prior to January 1, 2004, the power purchase agreements for 2004 with respect to all or a portion of the Collins Station and peaking units not
previously terminated for 2003 (1,084 MW from the Collins Station and 694 MW from the peaking units).

88

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The
energy and capacity from any units which are not subject to one of the power purchase agreements with Exelon Generation will be sold under terms, including price and quantity, to be
negotiated with customers through a combination of bilateral agreements, forward energy sales and spot market sales. Thus, EME will be subject to market risks related to the price of energy and
capacity described above. EME expects that capacity prices for merchant energy sales will, in the near term, be substantially lower than those Midwest Generation currently receives under its existing
agreements with Exelon Generation (with the possibility of minimal revenues due to the current oversupply conditions in this marketplace). EME further expects that the lower revenues resulting from
this difference will be offset in part by energy prices, which EME believes will, in the near term, be higher for merchant energy sales than those Midwest Generation currently receives under its
existing agreements, as indicated below in the table of forward-looking prices. EME intends to manage this price risk, in part, by accessing both the wholesale customer and
over-the-counter markets described below as well as using derivative financial instruments in accordance with established policies and procedures.

During
2003, the primary markets available to Midwest Generation for wholesale sales of electricity from the Illinois Plants are expected to be "wholesale customer" and
"over-the-counter." The most liquid over-the-counter markets in the Midwest region are sales into the control area of Cinergy, referred to as "Into
Cinergy," and, to a lesser extent, sales into the control area of Commonwealth Edison, referred to as "Into ComEd." "Into Cinergy" and "Into ComEd" are bilateral markets for the sale or purchase of
electrical energy for future delivery. Performance of transactions in these markets is subject to contracts that generally provide for liquidated damages supported by a variety of credit requirements,
which may include independent credit assessment, parental guarantees, letters of credit and cash margining arrangements.

The
following table sets forth the forward month-end market prices for energy per megawatt-hour for the calendar 2003 and calendar 2004 "strips" (defined as
energy purchases for the entire calendar year) as publicly quoted for sales "Into ComEd" and "Into Cinergy" during 2002. These forward prices will continue to fluctuate as a result of a number of
factors, including gas prices, electricity demand, which is also affected by economic growth, and the amount of existing and planned power plant capacity. The actual spot prices for electricity
delivered into these markets may vary materially from the forward market prices.

Into ComEd*

|                   |  | 2003 |       | 2004
|------------------ |  | ---- | ----- | ----
|
|
|January 31, 2002   |  | $    | 27.26 |     
|February 28, 2002  |  |      | 28.96 |     
|March 31, 2002     |  |      | 32.50 |     
|April 30, 2002     |  |      | 32.55 |     
|May 31, 2002       |  |      | 30.85 |     
|June 30, 2002      |  |      | 29.54 |     
|July 31, 2002      |  |      | 28.64 |     
|August 30, 2002    |  |      | 28.75 |     
|September 30, 2002 |  |      | 29.16 |     
|October 31, 2002   |  |      | 29.01 |     
|November 27, 2002  |  |      | 29.11 |     
|December 31, 2002  |  |      | 29.98 |     

89

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Into Cinergy**

|                   |  | 2003 |       | 2004
|------------------ |  | ---- | ----- | ----
|
|
|January 31, 2002   |  | $    | 28.38 |     
|February 28, 2002  |  |      | 30.30 |     
|March 31, 2002     |  |      | 33.82 |     
|April 30, 2002     |  |      | 34.03 |     
|May 31, 2002       |  |      | 31.74 |     
|June 30, 2002      |  |      | 31.08 |     
|July 31, 2002      |  |      | 29.34 |     
|August 30, 2002    |  |      | 29.63 |     
|September 30, 2002 |  |      | 30.56 |     
|October 31, 2002   |  |      | 30.64 |     
|November 27, 2002  |  |      | 30.59 |     
|December 31, 2002  |  |      | 31.73 |     

---

The
average price that EME derives from electricity sales is normally higher than a 24-hour price as it manages its generation to optimize on-peak periods when
power prices are higher.

Midwest
Generation intends to hedge a portion of its merchant portfolio risk. To the extent it does not do so, the unhedged portion will be subject to the risks and benefits of
spot-market price movements. The extent to which Midwest Generation will hedge its market price risk through forward over-the-counter sales depends on several
factors. First, Midwest Generation will evaluate over-the-counter market prices to determine whether sales at forward market prices are sufficiently attractive compared to
assuming the risk associated with spot market sales. Second, Midwest Generation's ability to enter into hedging transactions will depend upon Midwest Generation's and its affiliate's liquidity and
upon the over-the-counter forward sales markets' having sufficient liquidity to enable Midwest Generation to identify counterparties who are able and willing to enter into
hedging transactions with Midwest Generation. Due to factors beyond Midwest Generation's control, market liquidity decreased significantly during 2002, and a number of formerly significant trading
parties have completely withdrawn from the market or substantially reduced their trading activities. See "Credit Risks."

In
addition to the prevailing market prices, the ability of Midwest Generation to derive profits from the sale of electricity from the released units will be affected by the cost of
production, including costs incurred to comply with environmental regulations. The costs of production of the released units vary and, accordingly, depending on market conditions, the amount of
generation that will be sold from the released units is expected to vary from unit to unit. In this regard, Midwest Generation suspended operations of Units 1 and 2 at its Will County plant and Units
4 and 5 at its Collins Station at the end of 2002 pending improvement in market conditions. If market conditions were to be depressed for an extended period of time, Midwest Generation would need to
consider decommissioning these units, which would result in a charge against income.

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Midwest Generation's ability to transmit energy to counterparty delivery points to consummate spot sales and hedging transactions may be affected by transmission service limitations and
constraints and new standard market design proposals proposed by and currently pending before the Federal Energy Regulatory Commission. Although the Federal Energy Regulatory Commission and the
relevant industry participants are working to minimize such issues, Midwest Generation cannot determine how quickly or how effectively such issues will be resolved.

Homer City Facilities

Electric power generated at the Homer City facilities 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 New York Independent System Operator (NYISO). These pools have short-term markets, which establish an
hourly clearing price. The Homer City facilities are situated in the PJM control area and are physically connected to high-voltage transmission lines serving both the PJM and NYISO
markets. The Homer City facilities can also transmit power to the Midwestern United States.

The
following table depicts the average market prices per megawatt-hour in PJM during the past three years:

24-Hour PJM
Historical Energy Prices*2002

2001

2000January

$
20.52

$
36.66

$
23.15February


20.62


29.53


23.84March


24.27


35.05


21.97April


25.68


34.58


23.79May


21.98


28.64


28.41June


24.98


26.61


23.06July


30.01


30.21


23.53August


30.40


43.99


29.01September


29.00


22.44


25.12October


27.64


21.95


29.20November


25.18


19.58


30.68December


27.33


19.66


44.63Yearly Average

$
25.63

$
29.07

$
27.20


---

As
shown on the above table, the average historical market prices at the Homer City busbar (delivery point) during 2002 are below the average historical market prices during 2001.
Forward market prices in PJM fluctuate as a result of a number of factors, including natural gas prices, transmission congestion, changes in market rules, electricity demand which is affected by
weather and economic growth, and the amount of existing and planned power plant capacity. The actual spot prices for electricity delivered into these markets may vary materially from the forward
market prices.

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The
following table sets forth the forward month-end market prices for energy per megawatt-hour for the calendar 2003 and calendar 2004 "strips," which are
defined as energy purchases for the entire calendar year, for sales in PJM during 2002:

24-Hour PJM
Forward Energy Prices*2003

2004January 31, 2002

$
25.48

$
26.31February 28, 2002


27.11


27.59March 31, 2002


29.69


29.66April 30, 2002


29.19


28.81May 31, 2002


28.40


28.24June 30, 2002


27.96


28.09July 31, 2002


27.94


28.43August 30, 2002


28.10


28.17September 30, 2002


29.00


28.99October 31, 2002


29.11


29.17November 27, 2002


29.67


29.24December 31, 2002


31.87


30.18


---

The
forward prices at PJM West (an index of multiple delivery points) are generally higher than the prices of the Homer City busbar (delivery point) due to transmission congestion
charges. The average PJM West price has been 5% higher than the average Homer City busbar price during the past 24 months. The average price that the Homer City facilities derive from
electricity sales is normally higher than the 24-hour price as EME manages its generation to optimize the on-peak periods when power prices are higher.

The
ability of EME's subsidiary, EME Homer City, to make payments under the long-term lease entered into as part of the sale-leaseback transaction discussed under
"Off-Balance Sheet TransactionsSale-Leaseback Transactions," depends on revenues generated by the Homer City facilities, which depend in part on the
market conditions for the sale of capacity and energy. These market conditions are beyond EME's control.

Europe

United Kingdom

Since 1989, EME's plants in the U.K. have sold their electrical energy and capacity through a centralized electricity pool, which established a
half-hourly clearing price, also referred to as the pool price, for electrical energy. On March 27, 2001, this system was replaced by the U.K. government with a bilateral physical
trading system referred to as the new electricity trading arrangements. The First Hydro plant has entered into forward contracts of varying terms that expire on various dates through
August 2005.

The
new electricity trading arrangements provide for, among other things, the establishment of a range of voluntary short-term power exchanges and brokered markets operating
from a year or more in advance to 1 hour prior to a trading period of one-half hour; 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. The grid operator retains the right under the new market

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mechanisms to purchase system reserve and response services to maintain the quality of the electrical supply directly from generators (generally referred to as "ancillary services"). Ancillary
services contracts typically run for a year and can consist of both fixed amounts and variable amounts represented by prices for services that are only paid for when actually called upon by the grid
operator. Physical bilateral contracts have replaced the prior financial contracts for differences, but have a similar commercial function. A key feature of the new arrangements is to require firm
physical delivery, which
means that a generator must deliver, and a consumer must take delivery of, its net contracted positions or pay for any energy imbalance at highly volatile imbalance prices calculated by the market
operator. A consequence of this new system has been to increase greatly the motivation of parties to contract in advance and to further develop forwards and futures markets of greater liquidity than
at present. Furthermore, another consequence of the market change is that counterparties may require additional credit support, including parent company guarantees or letters of credit.

The
legislation introducing the new trading arrangements set a principal objective for the Gas and Electric Market Authority to "protect the interests of consumers...where appropriate by
promoting competition...." This represents a shift in emphasis toward the consumer interest. However, this is qualified by a recognition that license holders should be able to finance their
activities. The Utilities Act of 2000 also contains new powers for the Secretary of State to issue guidance to the Gas and Electric Market Authority on social and environmental matters, changes to the
procedures for modifying licenses and a new power for the Gas and Electric Market Authority to impose financial penalties on companies for breach of license conditions. EME is monitoring the operation
of these new provisions.

Following
the introduction of the new trading arrangements in 2001, there has been a significant reduction in the wholesale price of electricity driven principally by surplus generating
capacity. In addition, First Hydro was adversely affected in the second half of 2001 by a fall in the differential of the peak day time energy price compared to the cost of purchasing power at night
time to pump water back to the top reservoir. This was a reflection both of excess generating capacity on the United Kingdom system as a whole and also of the practice of generators holding plants on
the system at part load to protect themselves against being out of balance in the new market. During 2002, there was further downward pressure on wholesale prices but some recovery in the peak/off
peak differentials during the winter period.

Despite
the difficult market conditions, First Hydro has continued to meet the interest coverage ratios specified in its bond financing documents, and to meet its half yearly interest
payments without recourse to the project's debt service reserve. EME believes that if market and trading conditions experienced in 2002 are sustained, First Hydro will continue to be compliant with
the requirements of its bond financing documents. This compliance is, however, subject to market conditions for electric energy and ancillary services which are beyond EME's control.

Asia Pacific

Australia

The Loy Yang B plant and the Valley Power Peaker project sell 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 and the
Valley Power Peaker project have entered into a number of financial hedges. 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

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Commission of Victoria's obligations under the State Hedge. From January 2001 to July 2014, approximately 77% of the Loy Yang B plant output sold is hedged under the State Hedge. From
August 2014 to October 2016, approximately 56% of the Loy Yang B plant output sold is hedged under the State Hedge. Additionally, the Loy Yang B plant and the Valley Power Peaker project
have entered into a number of derivative contracts to mitigate further against price volatility inherent in the electricity pool. These contracts consist of fixed forward electricity contracts and/or
cap contracts that expire on various dates through December 31, 2006.

New Zealand

A substantial portion of Contact Energy's generation output is hedged by sales to retail electricity customers and forward contracts with other wholesale
electricity counterparties. Contact Energy has entered into forward contracts and/or option contracts of varying terms that expire on various dates through March 31, 2007. The New Zealand
Government commissioned an inquiry into the electricity industry in February 2000. Following the inquiry report the New Zealand Government released a Government Policy Statement, at the center
of which was a call for the industry to rationalize the three existing industry codes, form a single governance structure and address transmission pricing methodology. The Government Policy
Statement also requested a model use of system agreement be developed, that is, a framework by which the retailers contract for services from each of the distribution networks, and a consumer
complaints ombudsman be established. An essential theme throughout the Government Policy Statement was the desire that the industry retain a private multilateral self-governing structure.
During 2001, an amendment to the Electricity Act of 1992 was passed that laid out the form that regulation would take if the industry does not heed the Government's call. A draft single governance
code was put forward to the New Zealand Commerce Commission for approval early in 2002. In October 2002, the Commerce Commission approved the new arrangements in the form of a rulebook for the
self-governance of the electricity sector. The Commission conditioned this authorization upon:



The
authorization will expire four years from the date of the implementation of the rulebook, or on March 31, 2007, whichever is earlier.

Credit Risks

In conducting EME's price risk management and trading activities, EME contracts with a number of utilities, energy companies and financial institutions. Due to
factors beyond EME's control, market liquidity has decreased significantly since the beginning of 2002, and a number of formerly significant trading parties have completely withdrawn from the market
or substantially reduced their trading activities. The reduction in the credit quality of traditional trading parties increases EME's credit risk. In addition, the decrease in market liquidity may
require EME to rely more heavily on wholesale electricity sales to wholesale customer markets, which may also increase EME's credit risk. While various industry groups and regulatory agencies have
taken steps to address market liquidity, transparency and credit issues, there is no assurance as to when, or how effectively, such efforts will restore market confidence. In the event a counterparty
were to default on its trade obligation, EME

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would be exposed to the risk of possible loss associated with reselling the contracted product at a lower price if the non-performing counterparty were unable to pay the resulting
liquidated damages owed to EME. Further, EME would be exposed to the risk of non-payment of accounts receivable accrued for products delivered prior to the time such counterparty
defaulted.

To
manage credit risk, EME looks at the risk of a potential default by its counterparties. Credit risk is measured by the loss EME would record if its counterparties failed to perform
pursuant to the terms of their contractual obligations. EME has established controls to determine and monitor the creditworthiness of counterparties and uses master netting agreements whenever
possible to mitigate its exposure to counterparty risk. EME may require counterparties to pledge collateral when deemed necessary. EME tries to manage the credit in its portfolio based on credit
ratings using published ratings of counterparties and other publicly disclosed information, such as financial statements, regulatory filings, and press releases, to guide it in the process of setting
credit levels, risk limits and contractual arrangements including master netting agreements. The credit quality of EME's counterparties is reviewed regularly by EME's risk management committee. In
addition to continuously monitoring its credit exposure to its counterparties, EME also takes appropriate steps to limit or lower
credit exposure. Despite this, there can be no assurance that EME's actions to mitigate risk will be wholly successful or that collateral pledged will be adequate.

EME
measures credit risk exposure from counterparties of its merchant energy activities by the sum of: (i) 60 days of accounts receivable, (ii) current fair value of
open positions, and (iii) a credit value at risk. EME's subsidiaries enter into master agreements and other arrangements in conducting price risk management and trading activities which
typically provide for a right of setoff in the event of bankruptcy or default by the counterparty. Accordingly, EME's credit risk exposure from counterparties is based on net exposure under these
agreements. The credit ratings of EME's counterparties were as follows:

S&P Credit Rating

December 31, 2002(in millions)A or higher

$
45A-


37BBB+


24BBB


27BBB-


2Below investment grade


2Total

$
137


Exelon
Generation accounted for 41%, 43% and 49% of EME's consolidated operating revenues in 2002, 2001 and 2000, respectively. EME expects the percentage to be less in 2003 because a
smaller number of plants will be subject to contracts with Exelon Generation. See "Market Risk ExposuresAmericasIllinois Plants." Any failure of Exelon Generation to make
payments to Midwest Generation under the power purchase agreements could result in a shortfall of cash available for Midwest Generation to meet its obligations. A default by Midwest Generation in
meeting its obligations could in turn have a material adverse effect on EME.

EME's
contracted power plants and the plants owned by unconsolidated affiliates in which EME owns an interest sell power under long-term power purchase agreements. Generally,
each plant sells its output to one counterparty. Accordingly, a default by a counterparty under a long-term power purchase agreement, including a default as a result of a bankruptcy, would
likely have a material adverse affect on the operations of such power plant. During 2002, the counterparty to the Lakeland project power purchase agreement filed a notice of disclaimer of its power
purchase agreement with the project,

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ultimately resulting in an impairment of $77 million, after tax. See "Consolidated Operating ResultsDiscontinued Operations." The Big 4 projects sell power to
Southern California Edison, which is currently non-investment grade. Southern California Edison was adversely affected by the California energy crisis and during that time defaulted on its
long-term power purchase agreements with each of the Big 4 projects. It has since repaid the past due amounts, with interest. If Southern California Edison again defaults on its
long-term power purchase agreements with each of the Big 4 projects, it would have a material adverse effect on the related project.

Interest Rate Risk

MEHC has mitigated the risk of interest rate fluctuations associated with the $385 million term loan due 2006 by arranging for variable rate financing with
interest rate swaps. Swaps covering interest accrued from January 2, 2002 to January 2, 2003 expired on January 2, 2003. Subsequently, MEHC entered into swaps that cover interest
accrued from January 2, 2003 to July 2, 2004. A 10% fluctuation in market interest rates at December 31, 2002 would change the fair value of MEHC's interest rate swaps by
approximately $1 million.

The
fair market value of MEHC's parent only total long-term obligations was $0.7 billion at December 31, 2002, compared to the carrying value of
$1.2 billion. A 10% increase in market interest rates at December 31, 2002 would result in a decrease in the fair value of total long-term obligations by approximately
$22 million. A 10% decrease in market interest rates at December 31, 2002 would result in an increase in the fair value of total long-term obligations by approximately
$27 million.

Interest
rate changes affect the cost of capital needed to operate EME's projects and the lease costs under the Collins Station lease. EME has mitigated the risk of interest rate
fluctuations by arranging for fixed rate financing or variable rate financing with interest rate swaps, interest rate options or other hedging mechanisms for a number of its project financings.
Interest expense included $34 million, $17 million and $15 million of additional interest expense for the years 2002, 2001 and 2000, respectively, as a result of interest rate
hedging mechanisms. EME has entered into several interest rate swap agreements under which the maturity date of the swaps occurs prior to the final maturity of the underlying debt. A 10% increase in
market interest rates at December 31, 2002 would result in a $9 million increase in the fair value of EME's interest rate hedge agreements. A 10% decrease in market interest rates at
December 31, 2002 would result in a $10 million decrease in the fair value of EME's interest rate hedge agreements. Based on the amount of variable rate long-term debt for
which EME has not entered into interest rate hedge agreements and the amount of the Collins lease at December 31, 2002, a 100 basis point change in interest rates at December 31, 2002
would increase or decrease 2003 income before taxes by approximately $33 million.

EME
had short-term obligations of $78 million at December 31, 2002, consisting of promissory notes related to Contact Energy. The fair values of these
obligations approximated their carrying values at December 31, 2002, and would not have been materially affected by changes in market interest rates. The fair market values of
long-term fixed interest rate obligations are subject to interest rate risk. The fair market value of MEHC's total long-term obligations (including current portion) was
$5.6 billion at December 31, 2002, compared to the carrying value of $7.1 billion. A 10% increase in market interest rates at December 31, 2002 would result in a decrease
in the fair value of total long-term obligations by approximately $132 million. A 10% decrease in market interest rates at December 31, 2002 would result in an increase in
the fair value of total long-term obligations by approximately $153 million.

Foreign Exchange Rate Risk

Fluctuations in foreign currency exchange rates can affect, on a U.S. dollar equivalent basis, the amount of EME's equity contributions to, and distributions
from, its international projects. At times, EME has hedged a portion of its current exposure to fluctuations in foreign exchange rates through

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financial derivatives, offsetting obligations denominated in foreign currencies, and indexing underlying project agreements to U.S. dollars or other indices reasonably expected to correlate with
foreign exchange movements. In addition, EME has used statistical forecasting techniques to help assess foreign exchange risk and the probabilities of various outcomes. EME cannot provide assurances,
however, that fluctuations in exchange rates will be fully offset by hedges or that currency movements and the relationship between certain macroeconomic variables will behave in a manner that is
consistent with historical or forecasted relationships.

The
First Hydro plant in the U.K. and the plants in Australia have been financed in their local currencies, pounds sterling and Australian dollars, respectively, thus hedging the
majority of their acquisition costs against foreign exchange fluctuations. Furthermore, EME has evaluated the return on the remaining equity portion of these investments with regard to the likelihood
of various foreign exchange scenarios. These analyses use market-derived volatilities, statistical correlations between specified variables, and long-term forecasts to predict ranges of
expected returns.

During
2002, foreign currencies in the U.K., Australia and New Zealand increased in value compared to the U.S. dollar by 11%, 10% and 26%, respectively (determined by the change in the
exchange rates from December 31, 2001 to December 31, 2002). The increase in value of these currencies was the primary reason for the foreign currency translation gain of
$125 million during 2002. A 10% increase or decrease in the exchange rates at December 31, 2002 would result in foreign currency translation gains or losses of $93 million.

Contact
Energy enters into foreign currency forward exchange contracts to hedge identifiable foreign currency commitments associated with transactions in the ordinary course of business.
The contracts are
primarily in Australian and U.S. dollars with varying maturities through August 2003. At December 31, 2002, the outstanding notional amount of the contracts totaled $10 million
and the fair value of the contracts totaled $(151) thousand. Contact Energy recognized a foreign exchange loss of $1 million in 2002, compared to a foreign exchange gain of
$1 million in 2001 related to the contracts that matured during the respective periods. A 10% decrease in the exchange rates at December 31, 2002 would result in a $2 million
increase in the fair value of the contracts.

In
addition, Contact Energy enters into cross currency interest rate swap contracts in the ordinary course of business. These cross currency swap contracts involve swapping fixed and
floating-rate U.S. and Australian dollar loans into floating-rate New Zealand dollar loans with varying maturities through April 2018.

EME
will continue to monitor its foreign exchange exposure and analyze the effectiveness and efficiency of hedging strategies in the future.

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Non-Trading Derivative Financial Instruments

The following table summarizes the fair values for outstanding derivative financial instruments used for purposes other than trading by risk category and
instrument type (in millions):

December 31,
2002

December 31,
2001Derivatives:Interest rate:Interest rate swap/cap agreements

(56
)
(37
)Interest rate options

(2
)
(1
)Commodity price:Electricity

(100
)
(74
)Natural gas



(8
)Foreign currency forward exchange agreements



(1
)Cross currency interest rate swaps

(2
)
28


In
assessing the fair value of EME's non-trading derivative financial instruments, EME uses a variety of methods and assumptions based on the market conditions and associated
risks existing at each balance sheet date. The fair value of commodity price contracts takes into account quoted market prices, time value of money, volatility of the underlying commodities and other
factors. The fair value of outstanding derivative commodity price contracts that would be expected after a ten percent adverse price change at December 31, 2002 is $(53) million. The following
table summarizes the maturities, the valuation method and the related fair value of EME's commodity price risk management assets and liabilities (as of December 31, 2002) (in millions):

Total
Fair Value

Maturity
<1 year

Maturity
1 to 3
years

Maturity
4 to 5
years

Maturity
>5 yearsPrices actively quoted

$
(10
)
$
(10
)
$


$


$
Prices based on models and other valuation methods


(90
)

3


(7
)

(13
)

(73
)Total

$
(100
)
$
(7
)
$
(7
)
$
(13
)
$
(73
)


The
fair value of the electricity rate swap agreements (included under commodity price-electricity) entered into by the Loy Yang B plant and the First Hydro plant has been estimated by
discounting the future net cash flows resulting from the difference between the average aggregate contract price per MW and a forecasted market price per MW multiplied by the number of MW remaining to
be sold under the contract.

Energy Trading Derivative Financial Instruments

On September 1, 2000, EME acquired the trading operations of Citizens Power LLC and, subsequently, combined them with EME's risk management and trading
operations, now conducted by its subsidiary, Edison Mission Marketing & Trading. As a result of a number of industry and credit related factors, Edison Mission Marketing & Trading has
minimized its price risk management activities and its trading activities with third parties not related to EME's power plants or investments in energy projects. See "Current
Developments." To the extent Edison Mission Marketing & Trading engages in trading activities, Edison Mission Marketing & Trading seeks to manage price risk and to create stability of
future income by selling electricity in the forward markets and, to a lesser degree, to generate profit from price volatility of electricity and fuels by buying and selling these commodities in
wholesale markets. EME generally balances forward sales and purchase contracts and manages its exposure through a value at risk analysis as described under "Commodity Price Risk."

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The
fair value of the commodity financial instruments related to energy trading activities as of December 31, 2002 and December 31, 2001, are set forth below (in millions):

December 31, 2002

December 31, 2001Assets

Liabilities

Assets

LiabilitiesElectricity

$
109

$
15

$
7

$
5Other





2


2


2Total

$
109

$
17

$
9

$
7


The
fair value of trading contracts that would be expected after a ten percent adverse price change at December 31, 2002 are shown in the table below (in millions):

Fair Value

Fair Value After 10%
Adverse Price ChangeElectricity

$
94

$
93Other


(2
)

(2
)Total

$
92

$
91


The
change in the fair value of trading contracts for the year ended December 31, 2002, was as follows (in millions):

Fair value of trading contracts at January 1, 2002

$
2Purchase of power sales agreement


80Net gains from energy trading activities


42Amount realized from energy trading activities


(32
)Fair value of trading contracts at December 31, 2002

$
92


Quoted
market prices are used to determine the fair value of the financial instruments related to energy trading activities, except for the power sales agreement with an unaffiliated
electric utility that EME's subsidiary purchased and restructured and a long-term power supply agreement with another unaffiliated party. EME's subsidiary recorded these agreements at fair
value based upon a discounting of future electricity prices derived from a proprietary model using a discount rate equal to the cost of borrowing the non-recourse debt incurred to finance
the purchase of the power supply agreement. The following table summarizes the maturities, the valuation method and the related fair value of energy trading assets and liabilities (as of
December 31, 2002) (in millions):

|                                                   |  | Total
Fair Value |    | Maturity
<1 year |   | Maturity
1 to 3
years |   | Maturity
4 to 5
years |   | Maturity
>5 years
|-------------------------------------------------- |  | ---------------- | -- | ---------------- | - | --------------------- | - | --------------------- | - | -----------------
|Prices actively quoted                             |  | $                | (1 | )                | $ | (1                    | ) | $                     |  |                  
|Prices based on models and other valuation methods |  |                  | 93 |                  |   | (3                    | ) |                       | 4 |                  
|                                                   |  |                  |    |                  |   |                       |   |                       |   |                  
|Total                                              |  | $                | 92 |                  | $ | (4                    | ) | $                     | 4 |                  
|                                                   |  |                  |    |                  |   |                       |   |                       |   |                  

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EME's net gains (losses) arising from energy trading activities recognized on a fair value basis are as follows (in millions):

Years Ended December 31,2002

2001

2000Operating RevenuesUnrealized gains (losses), net

$
10

$
(12
)
$
12Realized gains, net


32


22


50Total

$
42

$
10

$
62


Risk Factors

MEHC depends upon cash flows from EME and tax-allocation payments from Edison International to service its debt.

MEHC's principal asset is the common stock of EME. In July 2001, MEHC issued $800 million of 13.50% senior secured notes due 2008. Concurrently with
the consummation of the offering of its senior secured notes, MEHC borrowed $385 million under a term loan. The senior secured notes and the term loan are secured by a first priority security
interest in EME's common stock. Any foreclosure on the pledge of EME's common stock by the holders of the senior secured notes or the lenders under the term loan would result in a change in control of
EME. For a discussion of MEHC's liquidity, see "Mission Energy Holding Company's Liquidity." For a discussion of the provisions in EME's formation documents that constrain its ability to
pay dividends or distributions to MEHC, see "Edison Mission Energy's Credit Ratings."

If
MEHC or EME were no longer included in the consolidated tax returns of Edison International as a result of Edison International no longer continuing to own, directly or indirectly, at
least 80% of the voting power of the stock of such company and at least 80% of the value of such stock, such company would no longer be eligible to participate in tax-allocation payments
with other subsidiaries of Edison International. The arrangements are subject to the terms of tax allocation and payment agreements among Edison International, MEHC, EME and other Edison International
subsidiaries. The agreements to which MEHC and EME are parties may be terminated by the immediate parent company of MEHC at any time, by notice given before the first day of the first year with
respect to which the termination is to be effective. However, termination does not relieve any party of any obligations with respect to any tax year beginning prior to the notice. If MEHC and EME did
not participate in the respective tax-allocation agreements, they would not be entitled to receive tax-allocation payments if payments were due under the agreements. See
"Intercompany Tax-Allocation Payments."

EME and its subsidiaries have a substantial amount of indebtedness, including a substantial amount of short-term indebtedness and
long-term lease obligations.

As of December 31, 2002, consolidated debt of EME was $6 billion, including $911 million of debt maturing in December 2003 which is
owed by EME's largest subsidiary, Edison Mission Midwest Holdings. EME also has a $487 million credit facility, $275 million of which matures in September 2003. In addition, EME's
subsidiaries have $7 billion of long-term lease obligations that are due over a period ranging up to 33 years.

The
$911 million of debt of Edison Mission Midwest Holdings maturing in December 2003 will need to be repaid, extended or refinanced. Edison Mission Midwest Holdings is not
expected to have sufficient cash to repay the $911 million debt due in December 2003, and there is no assurance that it will be able to extend or refinance this debt obligation on
similar terms and rates as the existing debt,

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on commercially reasonable terms, on the terms permitted under the financing documents entered into by MEHC in July 2001 or at all. MEHC's independent accountants' audit opinion for the year
ended December 31, 2002 contains an explanatory paragraph that indicates the consolidated financial statements are prepared on the basis that MEHC will continue as a going concern and that the
uncertainty about Edison Mission Midwest Holdings' ability to repay, extend or refinance this obligation raises substantial doubt about MEHC's ability to continue as a going concern. Accordingly, the
consolidated financial statements do not include any adjustments that might result from the resolution of this uncertainty.

A
failure to repay, extend or refinance Edison Mission Midwest Holdings' $911 million of debt as required by its terms would result in an event of default under the Edison Mission
Midwest Holdings financing documents, which would permit the lenders to accelerate $808 million of indebtedness in addition to the $911 million which matures in December 2003.
Furthermore, these events would trigger cross-defaults under agreements to which Edison Mission Midwest Holdings and Midwest Generation are parties, including the Collins, Powerton and Joliet leases.
An acceleration of debt and lease payments due under these agreements could result in a substantial claim for termination value under the EME guarantee of the Powerton and Joliet leases and could
result in a default under EME's financing arrangements. A default by EME on its financing arrangements or a default by one of its subsidiaries on indebtedness considered under the MEHC financing
documents as having recourse to EME is likely to result in a default under the MEHC financing documents. These events could make it necessary for MEHC or EME or both to file a petition for
reorganization under Chapter 11 of the United States Bankruptcy Code.

The
substantial amount of consolidated debt and financial obligations presents the risk that EME and its subsidiaries might not have sufficient cash to service their indebtedness or
long-term lease obligations and that the existing corporate, project debt and lease obligations could limit the ability of EME and its subsidiaries to compete effectively or to operate
successfully under adverse economic conditions.

EME's credit ratings are below investment grade, which may adversely affect its ability to extend Tranche A of its corporate credit facility and provide
credit support to subsidiaries.

EME provides credit support to its subsidiaries in the form of letters of credit or parent company guarantees for bilateral contracts for power and fuel. Without
investment grade ratings, EME's ability to provide credit support to its subsidiaries may be limited. On September 16, 2003, Tranche A of EME's corporate credit facility is scheduled to expire.
Although EME plans to discuss with its lenders an extension of the line of credit beyond its scheduled expiration, there is no assurance that the lenders will agree to such an extension or, if an
extension is obtained, that the terms will not be substantially different than those in the current facility. EME expects to complete the Sunrise project financing by summer 2003. If Tranche A of the
corporate facility is not extended and the Sunrise project financing is not completed as scheduled, EME's ability to provide credit support for bilateral contracts for power and fuel of its merchant
energy operations will be severely limited. If EME is unable to provide credit support, this will reduce the number of counterparties willing to enter into bilateral contracts with EME's subsidiaries,
thus requiring EME's subsidiaries to rely on short-term markets instead of bilateral contracts. Furthermore, if this situation occurs, EME may not be able to meet margining requirements if
forward prices for power increase significantly. Failure to meet a margining requirement would permit the counterparty to terminate the related bilateral contract early and demand immediate
payment for the replacement value of the contract. See "Edison Mission Energy's Credit Ratings" and "Edison Mission Energy's Liquidity."

The
credit ratings of EME and several of its subsidiaries are currently below investment grade, and this may adversely affect their ability to enter into new financings and, to the
extent that new financings or amendments to existing financing arrangements are obtained, may adversely affect the terms and

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interest rates that can be obtained. Any future incremental reduction or withdrawal of one or more of EME's credit ratings or the credit ratings of its subsidiaries could have an additional adverse
effect on their ability to access capital on acceptable terms, including their ability to refinance debt obligations as they mature.

The ability of EME's largest subsidiary, Edison Mission Midwest Holdings, to make distributions is restricted.

During the fourth quarter of 2002, the credit ratings of Edison Mission Midwest Holdings were reduced below investment grade. Edison Mission Midwest Holdings is
the direct parent of Midwest Generation, which owns or leases the Illinois Plants. As a result of the downgrade, Edison Mission Midwest Holdings is restricted in making distributions. Further
downgrades of Edison Mission Midwest Holdings could increase interest costs and trigger a requirement to use excess cash flow to repay indebtedness. For further discussion, see "Edison
Mission Energy's Credit Ratings."

EME
is the guarantor of the Powerton and Joliet leases and is obligated under intercompany notes to Midwest Generation to make debt service payments. Each intercompany note is a general
corporate obligation of EME and payments on it are made from distributions from subsidiaries and other sources of cash received by EME. Accordingly, EME must continue to make payments under the
intercompany notes notwithstanding that Edison Mission Midwest Holdings is not permitted to make distributions to EME. If EME were not able to make the loan payments, it would result in a default
under the financing documents to which Edison Mission Midwest Holdings is a party and could result in a default under EME's financing arrangements. This could have a material adverse effect on the
results of operations and cash flow of MEHC and EME.

EME has substantial interests in merchant energy power plants which are subject to market risks related to wholesale energy prices.

EME's merchant energy power plants do not have long-term power purchase agreements. Because the output of these power plants is not committed to be
sold under long-term contracts, these projects are subject to market forces which determine the amount and price of power sold from the power plants. There is no assurance that EME's
merchant energy power plants will be successful in selling power into their markets or that the prices received for such power will generate positive cash flow. If EME's merchant energy power plants
are not successful, they may not be able to generate enough cash to
service their own debt, which could have a material adverse effect on EME. See "Market Risk ExposuresCommodity Price Risks."

During
2002, Exelon Generation, currently the purchaser of capacity and electricity from the Illinois Plants, exercised its right to terminate for 2003 and thereafter 2,684 MW of
capacity from the coal units and 1,614 MW of capacity from the Collins Station. This has significantly increased EME's exposure to merchant energy markets. The energy and capacity from any units of
the Illinois Plants which are not subject to the power purchase agreements with Exelon Generation will be sold under terms, including price and quantity, to be negotiated with customers or into the
so-called "spot market." Thus, to the extent that Exelon Generation does not purchase power from the Illinois Plants in 2003 or 2004, Midwest Generation will be subject to the market risks
related to the price of energy and capacity. Due to the volatility of market prices for energy and capacity during the past several years, Midwest Generation cannot predict whether or not Exelon
Generation will elect to terminate for 2004 any of the units currently subject to the power purchase agreements for which termination is permitted for that year, and, if it does, whether sales of
energy and capacity to other customers or the market will be at prices sufficient to generate cash flow necessary for Midwest Generation to meet its obligations.

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A substantial amount of EME's revenues are derived under power purchase agreements with a single customer.

During 2002 and 2001, 41% and 43%, respectively, of EME's consolidated operating revenues were derived under three power purchase agreements between EME's wholly
owned subsidiary, Midwest Generation, and Exelon Generation Company, a subsidiary of Exelon Corporation. Midwest Generation expects to be less dependent on Exelon Generation as a major customer during
2003 due to Exelon Generation's release of 2,684 MW of capacity from the coal units and 1,614 MW of capacity from the Collins Station. In 2003, 2,961 MW of capacity from the coal units and 1,084 MW of
capacity from the Collins Station will remain subject to the power purchase agreements. Exelon Generation has the right to terminate for 2004, up to 1,265 MW of capacity from the coal units and 1,084
MW of capacity from the Collins Station. The power purchase agreements terminate at the end of 2004. Exelon Corporation is the holding company of Commonwealth Edison and PECO Energy Company, major
utilities located in Illinois and Pennsylvania. If Exelon Generation were to fail, become unable to fulfill, or choose to terminate some of its obligations under these power purchase agreements,
Midwest Generation might not be able to find another customer on similar terms for the output of the Illinois Plants. Any material failure by Exelon Generation to make payments to Midwest Generation
under these power purchase agreements could result in a shortfall of cash available for Midwest Generation to meet its obligations. A default by Midwest Generation in meeting its obligations could in
turn have a material adverse effect on EME. For a further discussion of the power purchase agreements, see "Item 1. BusinessAmericasIllinois Plants."

Restrictions in EME's certificate of incorporation, its credit facilities and the MEHC financing documents limit the ability of EME and its subsidiaries
to enter into specified transactions that they otherwise might enter into and may significantly impede their ability to refinance their debt.

The financing documents entered into by MEHC contain financial and investment covenants restricting EME and its subsidiaries. EME's certificate of incorporation
binds it to the provisions in MEHC's financing documents by restricting EME's ability to enter into specified transactions and engage in specified business activities without shareholder approval. The
instruments governing EME's indebtedness also contain financial and investment covenants. Restrictions contained in these documents could affect, and in some cases significantly limit or prohibit, EME
and its subsidiaries' ability to, among other things, incur, refinance, and prepay debt, make capital expenditures, pay dividends and make other distributions, make investments, create liens, sell
assets, enter into sale and leaseback transactions, issue equity interests, enter into transactions with affiliates, create restrictions on the ability to pay dividends or make other distributions and
engage in mergers and consolidations. These restrictions may significantly impede the ability of EME and its subsidiaries, including Edison Mission Midwest Holdings, to develop and implement any
refinancing plans in respect of their indebtedness. See "EME and its subsidiaries have a substantial amount of indebtedness, including a substantial amount of short-term
indebtedness and long-term lease obligations," for further discussion.

In
addition, in connection with the entry into new financings or amendments to existing financing arrangements, EME's and its subsidiaries' financial and operational flexibility may be
further reduced as a result of more restrictive covenants, requirements for security and other terms that are often imposed on sub-investment grade entities.

EME's international projects are subject to risks of doing business in foreign countries.

EME's international projects are subject to political and business risks, including uncertainties associated with currency exchange rates, currency repatriation,
expropriation, political instability and other issues that have the potential to restrict the projects from making dividends or other distributions and against which EME may not be fully capable of
insuring. See "Market Risk ExposuresForeign Exchange Rate Risk."

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Generally,
the uncertainty of the legal structure in some foreign countries could make it more difficult to enforce rights under agreements relating to the projects. In addition, the
laws and regulations of some countries may limit the ability to hold a majority interest in some of the projects. The economic crisis in Indonesia during 1998 necessitated a restructuring of the power
purchase agreement between PLN, the state-owned electric utility, and the Paiton project and the project debt agreements. During 2002 and the first quarter of 2003, the restructuring of these
agreements was completed. However, as a result of the restructuring, the project's expected dividends have been delayed until at least 2006. See "Contractual Obligations, Commitments and
ContingenciesPaiton."

EME is subject to extensive government regulation.

EME's operations are subject to extensive regulation by governmental agencies in each of the countries in which operations are conducted. See "Item 1.
BusinessRegulatory Matters." EME's domestic projects are subject to energy, environmental and other governmental laws and regulations at the federal, state and local levels in connection
with the development, ownership and operation of the projects. EME's projects are also subject to federal, state and local laws and regulations that govern the geographical location, zoning and land
use of or with respect to a project. EME's international projects are subject to the energy, environmental and other laws and regulations of the foreign jurisdictions in which these projects are
located. The degree of regulation varies according to each country and may be materially different from the regulatory regimes in the United States.

There
is no assurance that the introduction of new laws or other future regulatory developments in countries in which EME or its subsidiaries conduct business will not have a material
adverse effect on its business, results of operations or financial condition, nor is there any assurance that EME or its subsidiaries will be able to obtain and comply with all necessary licenses,
permits and approvals for its projects. If projects cannot comply with all applicable regulations, EME's business, results of operations and financial condition could be adversely affected. In
addition, if any projects were to lose their status as a qualifying facility, exempt wholesale generator or foreign utility company under U.S. federal regulations, EME could become subject to
regulation as a "holding company" under the Public Utility Holding Company Act of 1935. If that were to occur, EME would be required to divest all operations not functionally related to the operation
of a single integrated utility system and would be required to obtain approval of the Securities and Exchange Commission for various actions. See "Item 1. BusinessRegulatory
MattersU.S. Federal Energy Regulation."

General operating risks and catastrophic events may adversely affect EME's projects.

The
operation of power generating plants involves many risks, including start-up problems, the breakdown or failure of equipment or processes, performance below expected
levels of output, the inability to meet expected efficiency standards, operator errors, strikes, work stoppages or labor disputes and catastrophic events such as terrorist activities, earthquakes,
landslides, fires, floods, explosions or similar calamities. The occurrence of any of these events could significantly reduce revenues generated by EME's projects or increase their generating
expenses. Equipment and plant warranties and insurance may not be adequate to cover lost revenues or increased expenses and, as a result, a project may be unable to fund principal and interest
payments under its financing obligations and may operate at a loss. A default under a financing obligation of a project entity could result in a loss of EME's interest in the project.

Environmental Matters and Regulations

EME is subject to environmental regulation by federal, state and local authorities in the United States and foreign regulatory authorities with jurisdiction over
projects located outside the United States. EME believes that it is in substantial compliance with environmental regulatory requirements and that maintaining compliance with current requirements will
not materially affect its financial

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position or results of operation. However, possible future developments, such as the promulgation of more stringent environmental laws and regulations, and future proceedings that may be initiated by
environmental authorities, could affect the costs and the manner in which EME conducts its business and could cause it to make substantial additional capital expenditures. There is no assurance that
EME would be able to recover these increased costs from its customers or that EME's financial position and results of operations would not be materially adversely affected.

Typically,
environmental laws require a lengthy and complex process for obtaining licenses, permits and approvals prior to construction and operation of a project. Meeting all the
necessary requirements can delay or sometimes prevent the completion of a proposed project as well as require extensive modifications to existing projects, which may involve significant capital
expenditures. If EME fails to comply with applicable environmental laws, it may be subject to penalties and fines imposed against EME by regulatory authorities.

StateIllinois

Air Quality.In June 2001, Illinois passed legislation mandating the Illinois Environmental Protection Agency to
evaluate and issue a report to the Illinois legislature addressing the need for further emissions controls on fossil fuel-fired electric generating stations, including the potential need
for additional controls on nitrogen oxides, sulfur dioxide and mercury. The study, which is to be submitted between September 30, 2003 and September 30, 2004, also requires an evaluation
of incentives to promote renewable energy and the establishment of a banking system for certifying credits from voluntary reductions of greenhouse gases. The law allows the Illinois Environmental
Protection Agency to propose regulations based on its findings no sooner than 90 days after the issuance of its findings, and requires the Illinois Pollution Control Board to act within one
year on such proposed regulations. Until the Illinois Environmental Protection Agency issues its findings and proposes regulations in accordance with the findings, if such regulations are proposed,
EME cannot evaluate the potential impact of this legislation on the operations of its facilities.

Beginning
with the 2003 ozone season (May 1 through September 30), EME must comply with an average NOx emission rate of 0.25 lb NOx/mmBtu of heat input. This limitation is
commonly referred to as the East St. Louis State Implementation Plan (SIP). This regulation is a State of Illinois
requirement. Compliance with this standard will be met by averaging the emissions of all EME's power plants. Additional burner controls planned for installation at Powerton in the spring of 2003 along
with over-compliance at EME's other Illinois Plants, will facilitate compliance with this standard.

Beginning
with the 2004 ozone season, an additional NOx emission regulation will go into effect. This federally mandated regulation, commonly referred to as the "NOx SIP Call" will cap
NOx emissions within a 19-state region east of the Mississippi with a tonnage cap on NOx emissions. This program allows NOx trading similar to the current SO2 trading program already in
effect. EME's compliance plan is to rely upon a combination of strategies. EME has already qualified for early reduction credits by reducing NOx emissions at various plants ahead of the imposed
deadline. Additionally, the installation of emission control technology at select plants will ensure over-compliance at those individual plants with pending NOx emission limitations.
Finally, NOx emission trading will be utilized as needed to comply with any shortfall in emission credits anticipated with the deferral of the SCR projects at EME's Powerton Station.

Water Quality.The Illinois EPA is reviewing the water quality standards for the DesPlaines River adjacent to the Joliet
Station and immediately downstream of the Will County Station to determine if the use classification should be upgraded. One of the limitations for discharges to the river that could be made more
stringent if the existing secondary contact classification is changed would be the allowable temperature of the discharges from Joliet and Will County. At this time no new standards have been
proposed, so EME cannot estimate the financial impact of this review.

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StatePennsylvania

Water Quality.The discharge from the treatment plant receiving the wastewater stream from EME's Unit 3 flue gas
desulfurization system at the Homer City facilities has exceeded the stringent, water-quality based limits for selenium in the station's NPDES permit. As a result, EME has been notified by PADEP that
it has been included in the Quarterly Noncompliance Report submitted to the United States Environmental Protection Agency. EME has met with the contractor responsible for the Unit 3 flue gas
desulfurization system to discuss approaches to resolving the water quality issues and is investigating technical alternatives for maximizing the level of selenium removal in the discharge. EME has
also discussed these approaches for resolving the water quality issues with PADEP. Pilot studies are underway, but until they are completed and the results are evaluated, EME cannot estimate the costs
to comply with these selenium limits. After the results of the pilot studies are evaluated, EME will instruct the contractor to make the necessary improvements and then meet with PADEP to discuss the
drafting of a consent agreement to address the selenium issue. The consent agreement may include the payment of civil penalties, but the amount cannot be estimated at this time.

FederalUnited States of America

Clean Air Act.EME expects that compliance with the Clean Air Act and the regulations and revised State Implementation Plans
developed as a consequence of the Act will result in increased capital expenditures and operating expenses. EME's approach to meeting these obligations will consist of a blending of capital
expenditure and emissions allowance purchases that will be based on an ongoing assessment of the dynamics of its market conditions. EME anticipates that upgrades to its environmental controls to
reduce nitrogen oxide (NOx) emissions will result in capital expenditures of $28 million in 2003 and $2 million in 2004-2007.

Mercury Maximum Achievable Control Technology Determination.On December 20, 2000, the Environmental Protection Agency
issued a regulatory finding that it is "necessary and appropriate" to regulate emissions of mercury and other hazardous air pollutants from coal-fired power plants. The agency has added
coal-fired power plants to the list of source categories under Section 112(c) of the Clean Air Act for which "maximum achievable control technology" standards will be developed.
Eventually, unless overturned or reconsidered, the Environmental Protection Agency will issue technology-based standards that will apply to every coal-fired unit owned by EME or its
affiliates in the United States. The regulations are required to become final in 2004 with controls in place by 2007. This section of the Clean Air Act provides only for technology-based standards,
and does not permit market trading options. Until the standards are actually promulgated, the potential cost of these control technologies cannot be estimated, and EME cannot evaluate the potential
impact on the operations of its facilities.

National Ambient Air Quality Standards.A new ambient air quality standard was adopted by the Environmental Protection Agency
in July 1997 to address emissions of fine particulate matter. It is widely understood that attainment of the fine particulate matter standard may require reductions in nitrogen oxides and
sulfur dioxides, although, under the time schedule announced by the Environmental Protection Agency when the new standard was adopted, non-attainment areas were not to have been designated
until 2002 and control measures to meet the standard were not to have been identified until 2005. In May 1999, the United States Court of Appeals for the District of Columbia Circuit held that
Section 109(b)(1) of the Clean Air Act, the section of the Clean Air Act requiring the promulgation of national ambient air quality standards, as interpreted by the Environmental Protection
Agency, was an unconstitutional delegation of legislative power. The Court of Appeals remanded both the fine particulate matter standard and the revised ozone standard to allow the Environmental
Protection Agency to determine whether it could articulate a constitutional application of Section 109(b)(1). On February 27, 2001, the Supreme Court, inWhitman
v. American Trucking Associations, Inc., reversed the Circuit Court's judgment on this issue and remanded the case back to

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the Court of Appeals to dispose of any other preserved challenges to the particulate matter and ozone standards. On March 26, 2002, the District of Columbia Circuit, on remand, held that the
revised ozone and fine particulate matter ambient air quality standards were neither arbitrary nor capricious. Further action by the EPA with respect to the implementation of the revised ozone
standard and the
promulgation of a new coarse particulate matter standard is required pursuant to the first District of Columbia Circuit opinion and the Supreme Court's decision in Whitmanv.American Trucking Associations, Inc.

Because
of the delays resulting from the litigation over the standards, the Environmental Protection Agency is drafting new schedules for implementing the 8-hour ozone and
fine particulate matter (PM 2.5) standards. Pursuant to a negotiated settlement, the EPA has agreed to designate attainment and nonattainment areas under the 8-hour ozone standard in 2004.
The EPA has announced that it also intends to designate attainment and nonattainment areas under the fine particulate matter standard in 2004. Once these designations are published, states will be
required to revise their implementation plans to achieve attainment with the revised standards, which plans are likely to require additional emission reductions from facilities that are significant
emitters of ozone precursors and particulates. Any obligations on EME's facilities to further reduce their emissions of sulfur dioxide, nitrogen oxides and fine particulates as a result of the
8-hour ozone and fine particulate matter standards will not be known until the states revise their implementation plans.

Federal Legislative Initiatives.There have been a number of bills introduced in the last session of Congress and the current
session of Congress that would amend the Clean Air Act to specifically target emissions of certain pollutants from electric utility generating stations. These bills would mandate reductions in
emissions of nitrogen oxides, sulfur dioxide and mercury; some bills would also impose limitations on carbon dioxide emissions. The various proposals differ in many details, including the timing of
any required reductions; the extent of required reductions; and the relationship of any new obligations that would be imposed by these bills with existing legal requirements. There is significant
uncertainty as to whether any of the proposed legislative initiatives will pass in their current form or whether any compromise can be reached that would facilitate passage of legislation.
Accordingly, EME is not able to evaluate the potential impact of these proposals at this time.

Comprehensive Environmental Response, Compensation, and Liability Act.Under various federal, state and local environmental
laws and regulations, a current or previous owner or operator of any facility, including an electric generating facility, may be required to investigate and remediate releases or threatened releases
of hazardous or toxic substances or petroleum products located at that facility, and may be held liable to a governmental entity or to third parties for property damage, personal injury and
investigation and remediation costs incurred by these parties in connection with these releases or threatened releases. Many of these laws, including the Comprehensive Environmental Response,
Compensation and Liability Act of 1980, commonly referred to as CERCLA, as amended by the Superfund Amendments and Reauthorization Act of 1986, impose liability without regard to whether the owner
knew of or caused the presence of the hazardous substances, and courts have interpreted liability under these laws to be strict and joint and several. The cost of investigation, remediation or removal
of these substances may be substantial. In connection with the ownership and operation of EME's facilities, EME may be liable for these costs.

In
addition, persons who arrange for the disposal or treatment of hazardous or toxic substances at a disposal or treatment facility may be liable for the costs of removal or remediation
of a release or threatened release of hazardous or toxic substances at that disposal or treatment facility, whether or not that facility is owned or operated by that person. Some environmental laws
and regulations create a lien on a contaminated site in favor of the government for damages and costs it incurs in connection
with the contamination. The owner of a contaminated site and persons who arrange for the disposal of hazardous substances at that site also may be subject to common law claims by third parties based
on

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damages and costs resulting from environmental contamination emanating from that site. In connection with the ownership and operation of its facilities, EME may be liable for these costs.

With
respect to EME's liabilities arising under CERCLA or similar laws for the investigation and remediation of contaminated property, EME accrues a liability to the extent the costs are
probable and can be reasonably estimated. Generally, EME does not believe the costs for environmental remediation can be reasonably estimated before a remedial investigation has been completed for a
particular site. In connection with due diligence conducted for the acquisition of EME's Illinois Plants, EME engaged a third-party consultant to conduct an assessment of the potential costs for
environmental remediation of the plants. This assessment, which was based on information provided to EME by the former owner of these plants, was less rigorous than a remedial investigation conducted
in the course of a voluntary or required site cleanup.

Midwest
Generation has accrued $2 million for estimated environmental investigation and remediation costs for the Illinois Plants. This estimate is based upon the number of sites,
the scope of work and the estimated range of costs for environmental activity where such expenditures could be reasonably estimated. The midpoint of the range was used for the accrual. Future
estimated costs may vary based on changes in regulations or requirements of federal, state, or local governmental agencies, changes in technology, and actual costs of disposal. Management believes
that future costs in excess of the amounts disclosed on all known and quantifiable environmental contingencies will not be material to EME's financial position.

Enforcement Issues.EME owns an indirect 50% interest in EcoEléctrica, L.P., a limited partnership which owns
and operates a liquefied natural gas import terminal and cogeneration project at Peñuelas, Puerto Rico. In 2000, the U.S. Environmental Protection Agency issued to
EcoEléctrica a notice of violation and a compliance order alleging violations of the Federal Clean Air Act primarily related to start-up activities. Representatives of
EcoEléctrica met with the Environmental Protection Agency at that time to discuss the notice of violations and compliance order. On August 15, 2002, the U.S. Department of
Justice notified EcoEléctrica that it was preparing to bring a federal court action for violations of the Clean Air Act and regulations promulgated thereunder, and requested a meeting
with EcoEléctrica to discuss and possibly settle the matter. The initial meeting with the Department of Justice took place on January 15, 2003. EME expects settlement discussions
will continue during the first half of 2003.

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, or
NSR, 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 United States Environmental Protection Agency 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 Environmental Protection Agency has also issued requests for information pursuant to the Clean Air Act to numerous other electric utilities, including the prior owners of the Homer City
facilities, seeking to determine whether these utilities also engaged in activities that may have been in violation of the Clean Air Act's NSR requirements.

To
date, several utilities have reached formal agreements with the United States (or reached agreements-in-principle) to resolve alleged NSR violations. All of
the settlements have included the installation of additional pollution controls, supplemental environment projects, and the payment of civil penalties. Some of the settlements have also included the
retirement or repowering of coal-fired generating units. The agreements provide for a phased approach to achieving required emission reductions over the next 10 to 15 years. The
total cost of some of these settlements exceeds $1 billion;

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the civil penalties agreed to by these utilities range between $1 million and $10 million. Because of the uncertainty created by the Bush administration's review of the NSR regulations
and NSR enforcement proceedings, some of the settlements referred to above have not been finalized. However, in January 2002, the Department of Justice completed its review and concluded that
"the EPA has a reasonable basis for arguing that the enforcement actions are consistent with both the Clean Air Act and the Administrative Procedure Act." Accordingly, the Department of Justice has
continued to prosecute NSR enforcement cases against electric utilities, with some cases scheduled for trial in 2003.

On
December 31, 2002, the Environmental Protection Agency finalized a rule to improve the NSR program. This rule is intended to provide additional flexibility with respect to NSR
by, among other things, modifying the method by which a facility calculates the emissions' increase from a plant modification; exempting, for a period of ten years, units that have complied with NSR
requirements or otherwise installed pollution control technology that is equivalent to what would have been required by NSR; and allowing a facility to make modifications without being required to
comply with NSR if the facility maintained emissions below plantwide applicability limits. The rule became effective on March 3, 2003, although states, industry groups and environmental
organizations have filed litigation challenging various aspects of the regulation. In addition to this regulation, the Environmental Protection Agency has also proposed a regulation to clarify the
"routine maintenance and repair" exclusion contained in the Environmental Protection Agency's regulations. While EME will carefully evaluate both of these rules to determine impacts on its operations,
the proposed rule will be of greater interest. By more clearly defining "routine maintenance, repair and replacement," this rule will allow EME to determine what investments can be made at its
existing plants to improve the safety, efficiency, and reliability of its operations without triggering NSR permitting requirements.

Prior
to EME's purchase of the Homer City facilities, the Environmental Protection Agency requested information from the prior owners of the plant concerning physical changes at the
plant. On February 21, 2003, Midwest Generation received a request for information regarding past operations, maintenance and physical changes at the Illinois coal plants from the Environmental
Protection Agency. Other than these requests for information, no proceedings have been initiated with respect to any of EME's United States facilities. Depending on the outcome of Environmental
Protection Agency review and regulatory developments, EME could be required to invest in additional pollution control requirements, over and above the upgrades it is planning to install, and could be
subject to fines and penalties. EME cannot estimate the outcome of these discussions or the potential costs of investing in additional pollution control requirements, fines or penalties at this time.

International

United Nations Framework Convention on Climate Change.Since the adoption of the United Nations Framework Convention on
Climate Change in 1992, there has been worldwide attention with respect to greenhouse gas emissions. In December 1997, the Clinton administration participated in the Kyoto, Japan negotiations,
where the basis of a Climate Change treaty was formulated. Under the treaty, known as the Kyoto Protocol, the United States would be required, by 2008-2012, to reduce its greenhouse gas
emissions by 7% from 1990 levels.

The
Kyoto Protocol has yet to be submitted to the U.S. Senate for ratification. In March 2001, the Bush administration announced that the United States would not ratify the Kyoto
Protocol, but would instead offer an alternative. On February 14, 2002, President Bush announced objectives to slow the growth of greenhouse gas emissions by reducing the amount of greenhouse
gas emissions per unit of economic output by 18% by 2012 and to provide funding for climate-change related programs. The President's proposed program does not include mandatory reductions of
greenhouse gas emissions. However, various bills have been, or are expected to be, introduced in Congress to require greenhouse gas emissions reductions and to address other issues related to climate
change. Apart from the Kyoto

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Protocol, EME may be impacted by future federal or state legislation relating to controlling greenhouse gas emissions.

Notwithstanding
the Bush administration position, environment ministers from around the world have reached a compromise agreement on the mechanics and rules of the Kyoto Protocol. The
compromise agreement is believed to clear the way for countries to begin the treaty ratification process.

EME
either has an equity interest in or owns and operates generating plants in the following countries:

 Australia

 Spain Indonesia

 Thailand Italy

 Turkey New Zealand

 United Kingdom Philippines

 United States


All
of the countries, with the exception of Indonesia, the Philippines and Thailand, are classified as Annex 1 or "developed" countries and are subject to national greenhouse gas
emission reduction targets during the period of 2008-2012 (e.g., Phase 1). Each nation is actively developing policies and measures meant to assist it with meeting the individual national
emission targets as set out within the Kyoto Protocol.

With
the exception of Turkey, all of the countries identified have ratified the UN Framework Convention on Climate Change, as well as signed the Kyoto Protocol. Italy, New Zealand,
Spain, Thailand, and the United Kingdom have also ratified the Kyoto Protocol, and, with the exception of Australia and the United States, all of the other remaining countries are expected to do so by
the end of 2003.

For
the treaty to come into effect, approximately 55 countries that also represent at least 55% of the greenhouse gas emissions of the developed world must ratify it. With Canada
becoming the 100th country to ratify the agreement in December 2002, the Kyoto Protocol can account for 43.7% of carbon dioxide emissions. Russia also indicated at the Johannesburg Summit on
September 2002 its desire to ratify the treaty. Representing 17.4% of the developed world's greenhouse gas emissions, Russian ratification is now essential to bring the treaty into effect.

If
EME does become subject to limitations on emissions of carbon dioxide from its fossil fuel-fired electric generating plants, these requirements could have a significant
economic impact on its operations.

United Nations Proposed Framework Convention on Mercury.The United Nations Environment Programme (UNEP) has convened a
Global Mercury Assessment Working Group which met in Geneva in September 2002 and finalized a global mercury assessment report for submittal to the UNEP Governing Council at the Global
Ministerial Environment Forum in Nairobi, Kenya, February 2003. Based upon the report's key findings, the working group concluded that "there is sufficient evidence of
significant global adverse impacts to warrant international action to reduce the risks to human health and the environment arising from the release of mercury into the environment."

The
United States has indicated that it will support a decision to take international action on mercury at the Global Ministerial Environment Forum. However, the United States has
further stated that it does not support negotiation of a legally-binding convention at this time. In general, the United States approach: 1) agrees that there is sufficient evidence of adverse
impacts of mercury to warrant international action; 2) urges countries to take actions within the context of their national circumstances to identify exposed populations and to reduce
anthropogenic emissions of mercury; 3) recommends the establishment of a "Mercury Program" within UNEP, 4) recommends coordination between UNEP and other international organizations that
work on mercury issues such as the World

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Health Organization; and 5) asks countries to make voluntary contributions to support efforts of the Mercury Program under UNEP.

If
EME does become subject to limitations on emissions of mercury from its coal-fired electric generating plants, these requirements could have a significant economic impact
on its operations.

New Accounting Standards

Statement of Financial Accounting Standards No. 133

In December 2001, the Derivative Implementation Group of the Financial Accounting Standards Board issued a revised interpretation of "Normal Purchases and
Normal Sales Exception for Certain Option-Type Contracts and Forward Contracts in Electricity," referred to as Statement No. 133 Implementation Issue Number C15 (DIG C15). Under
this revised interpretation, EME's forward electricity contracts no longer qualify for the normal sales exception since EME has net settlement agreements with its counterparties. Under this exception,
EME records revenue on an accrual basis. Subsequent to the implementation of DIG C15, EME accounted for these contracts as cash flow hedges. Under a cash flow hedge, EME records the fair value of the
forward sales agreements on its balance sheet and records the effective portion of the cash flow hedge as part of other comprehensive income. The ineffective portion of EME's cash flow hedges is
recorded directly in its income statement. EME implemented this interpretation on April 1, 2002. EME recorded assets at fair value of $12 million, deferred taxes of $6 million and
a $6 million increase to other comprehensive income as the cumulative effect of adoption of this interpretation.

EITF Issue No. 02-03 Related to Energy Contracts

In October 2002, the FASB Emerging Issues Task Force (commonly referred to as EITF) reached a consensus to rescind EITF No. 98-10,
"Accounting for Contracts Involved in Energy Trading and Risk Management Activities," subject to transition positions, as part of its deliberations on Issue No. 02-03, "Recognition
and Reporting of Gains and Losses on Energy Trading Contracts," under EITF Issues No. 98-10, "Accounting for Contracts Involved in Energy Trading and Risk Management Activities,"
and No. 00-17, "Measuring the Fair Value of Energy-Related Contracts in Applying Issue No. 98-10." The rescission of EITF No. 98-10 means that
energy trading and risk management activities will no longer be marked to market as trading activities, but will instead follow Statement of Financial Accounting Standards No. 133, "Accounting
for Derivatives" (SFAS No. 133). Under SFAS No. 133, each energy contract must be assessed to determine whether or not it meets the definition of a derivative subject to SFAS
No. 133. If an energy contract meets the definition of a derivative, then it would be recorded at fair value (i.e., mark-to-market), subject to permitted exceptions. If
an energy contract does not meet the definition of a derivative, then it would be recorded on an accrual basis. As a result of this new consensus, EME discontinued application of EITF
No. 98-10 for its energy trading operations for all new contracts entered into after October 25, 2002 and instead applies SFAS No. 133 to these transactions. EME does
not expect the rescission of EITF No. 98-10 to have a material impact on its consolidated financial statements.

Statement of Financial Accounting Standards No. 142

Effective January 1, 2002, EME adopted Statement of Financial Accounting Standards No. 142, "Goodwill and Other Intangible Assets." SFAS
No. 142 establishes accounting and reporting standards requiring goodwill not to be amortized but rather tested for impairment at least annually at the reporting unit level. The statement
requires that goodwill should be tested for impairment using a two-step approach. The first step used to identify a potential impairment compares the fair value of a reporting unit to its
carrying amount, including goodwill. If the fair value of the reporting unit is less than its carrying amount, the second step of the impairment test is performed to measure the amount of the
impairment loss. The second step of the impairment test is a comparison of the implied fair

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value of goodwill to its carrying amount. The impairment loss is equal to the excess carrying amount of the goodwill over its implied fair value. The fair value of the reporting units for the Contact
Energy and First Hydro operations was in excess of related book value at January 1, 2002. Accordingly, no impairment of the goodwill related to these reporting units was recorded upon adoption
of this standard. EME concluded that fair value of the goodwill related to the Citizens Power LLC acquisition was impaired by $14 million net of $9 million of income tax benefit.

Estimates
of fair value were determined using comparable transactions. In accordance with SFAS No. 142, this decrease to continuing operations was recorded as of January 1,
2002 as a cumulative effect of a change in accounting principle, reflected in EME's consolidated income statement for the year ended December 31, 2002.

Included
in "Restricted cash and other assets" on EME's consolidated balance sheet are customer contracts with a gross carrying amount of $97 million and accumulated amortization
of $5 million at December 31, 2002. The contracts have a weighted average amortization period of 20 years. For the year ended December 31, 2002, the amortization expense
was $5 million. Based on the current amount of intangible assets subject to amortization, the estimated amortization expense for fiscal years 2003 through 2007 is $5 million each year.
Intangible assets classified in "Restricted cash and other assets" of $1 million at December 31, 2002 consists of an additional minimum pension liability at Midwest Generation.

Changes
in the carrying amount of goodwill, by segment, for the year ended December 31, 2002 are as follows:

|                                      |  | Americas |     | Asia Pacific |   | Europe |   | Total |    
|------------------------------------- |  | -------- | --- | ------------ | - | ------ | - | ----- | ---
|
|Carrying amount at December 31, 2001  |  | $        | 25  |              | $ | 360    |   | $     | 247
|Impairment losses                     |  |          | (23 | )            |   |       |   |       |   
|Intangibles reclassed to other assets |  |          |    |              |   | (77    | ) |       |   
|Translation adjustments and other     |  |          |    |              |   | 101    |   |       | 27 
|                                      |  |          |     |              |   |        |   |       |    
|Carrying amount at December 31, 2002  |  | $        | 2   |              | $ | 384    |   | $     | 274
|                                      |  |          |     |              |   |        |   |       |    

The
following table sets forth what net income would have been exclusive of goodwill amortization for years ended December 31, 2002, 2001 and 2000.

|                                            |  | Years Ended December 31,
|------------------------------------------- |  | ------------------------
|
|
|Reported net income (loss)                  |  | $                       
|Add back: Goodwill amortization, net of tax |  |                         
|                                            |  |                         
|Adjusted net income (loss)                  |  | $                       
|                                            |  |                         

Statement of Financial Accounting Standards No. 143

Effective January 1, 2003, EME adopted Statement of Financial Accounting Standards No. 143, "Accounting for Asset Retirement Obligations." SFAS
No. 143 requires entities to record the fair value of a liability for an asset retirement obligation in the period in which it is incurred. When the liability is initially recorded, the entity
capitalizes a cost by increasing the carrying amount of the related long-lived asset. Over time, the liability is increased to its present value each period, and the capitalized cost is
depreciated over the useful life of the related asset. Upon settlement of the liability, an entity either settles the obligation for its recorded amount or incurs a gain or loss upon settlement. EME
expects to record a cumulative effect adjustment effective January 1, 2003, that will decrease net income by approximately $10 million, after tax.

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Statement of Financial Accounting Standards No. 145

In April 2002, the Financial Accounting Standards Board issued Statement of Financial Accounting Standards No. 145, "Rescission of FASB Statements
No. 4, 44, and 64, Amendment of FASB Statement No. 13, and Technical Corrections," which supersedes previous guidance for reporting gains and losses from extinguishment of debt and
accounting for leases, among other things. The portion of the statement relating to the rescission of SFAS No. 4, "Reporting Gains and Losses from Extinguishment of Debt" requires that any gain
or loss on extinguishment of debt that was classified as an extraordinary item that does not meet the unusual in nature and infrequent of occurrence criteria in APB Opinion No. 30, "Reporting
the Results of OperationsReporting the Effects of Disposal of a Segment of a Business, and Extraordinary, Unusual and Infrequently Occurring Events and Transactions" shall be
reclassified. The standard, effective on January 1, 2003, was adopted by EME in the fourth quarter of 2002, which required EME to reclassify as part of Income from Continuing Operations, an
extraordinary gain of $6 million, net of tax, recorded in December 2001. The extraordinary gain was attributable to the extinguishment of debt that was assumed by the third-party lessors
in the December 2001 Homer City sale-leaseback transaction.

Statement of Financial Accounting Standards No. 146

Effective January 1, 2003, EME adopted Statement of Financial Accounting Standards No. 146, "Accounting for Costs Associated with Exit or Disposal
Activities." SFAS No. 146 requires that liabilities for costs associated with exit or disposal activities initiated after December 31, 2002 be recognized when incurred, rather than at
the date of a commitment to an exit or disposal plan. EME does not expect that this standard will have a material impact on its consolidated financial statements.

Statement of Financial Accounting Standards Interpretation No. 45

In November 2002, the Financial Accounting Standards Board issued Statement of Financial Accounting Standards Interpretation No. 45, "Guarantor's
Accounting and Disclosure Requirements for Guarantees, Including Indirect Guarantees of Indebtedness of Others." This interpretation establishes reporting requirements to be made by a guarantor about
its obligations under certain guarantees that it has issued. It also clarifies that a guarantor is required to recognize, at the inception of a guarantee, a liability for the fair value of the
obligation undertaken in issuing the guarantee. The initial recognition and initial measurement provisions of this interpretation are applicable on a prospective basis to
guarantees issued or modified after December 31, 2002. See "Contractual Obligations, Commitments and ContingenciesGuarantees and Indemnities."

Statement of Financial Accounting Standards Interpretation No. 46

In January 2003, the Financial Accounting Standards Board issued Statement of Financial Accounting Standards Interpretation No. 46, "Consolidation
of Variable Interest Entities" (FIN 46). This interpretation of Accounting Research Bulletin No. 51, "Consolidated Financial Statements," addresses consolidation by business enterprises of
variable interest entities. The primary objective of the interpretation is to provide guidance on the identification of, and financial reporting for, entities over which control is achieved through
means other than voting rights; such entities are known as variable-interest entities. This interpretation applies to variable interest entities created after January 31, 2003, and applies to
variable interest entities in which EME holds a variable interest that it acquired before February 1, 2003, beginning July 1, 2003.

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EME believes it is reasonably possible that the following partnership interests in energy projects are variable interest entities under FIN 46 due to equity
capitalization which is about 10% or less of each entity's total assets:

American Bituminous Power Partners, L.P.EME owns a 50% partnership interest in American Bituminous Power Partners, L.P.,
which owns an 80 MW waste-coal power plant located in Grant Town, West Virginia. American Bituminous Partners sells electricity to Monongahela Power Company under a power purchase
agreement that expires in 2023. The maximum exposure to loss from EME's interest in this entity is $2 million at December 31, 2002.

Brooklyn Navy Yard Cogeneration Partners L.P.EME owns a 50% partnership interest in Brooklyn Navy Yard Cogeneration Partners
L.P., which owns a 286 MW natural gas and oil-fired cogeneration facility located near Brooklyn, New York. Brooklyn Navy Yard sells electricity and steam to Consolidated Edison Company of
New York, Inc. under a power purchase agreement that expires in 2039. The maximum exposure to loss from EME's interest in this entity is $92 million at December 31, 2002.

Derwent Cogeneration LimitedEME owns a 33% interest in Derwent Cogeneration Limited, which owns a 214 MW
gas-fired cogeneration plant in Derby, England. Derwent sells electricity to Scottish and
Southern Electric plc under a power purchase agreement that expires in 2010 and sells steam to Courtaulds Chemicals (Holdings) Limited under a steam supply contract that also expires in 2010. The
maximum exposure to loss from EME's interest in this entity is $6 million at December 31, 2002.

EcoEléctrica L.P.EME owns a 50% partnership interest in EcoEléctrica L.P., which owns a 540 MW
power plant located Peñuelas, Puerto Rico. EcoEléctrica sells electricity to Puerto Rico Electric Power Authority under a power purchase agreement that expires in 2018
and sells water to Puerto Rico Water & Sewer Authority under a water supply agreement that also expires in 2018. The maximum exposure to loss from EME's interest in this entity is
$307 million at December 31, 2002.

ISAB Energy S.r.l.EME owns a 49% interest in ISAB Energy S.r.l., which owns a 518 MW integrated gasification combined cycle
power plant in Sicily, Italy, which EME refers to as the ISAB project. ISAB sells electricity to Gestore Rete Transmissione Nazionale, Italy's state transmission company, under a power purchase
agreement that expires in 2020. The ISAB project is located at an oil refinery owned by ERG Petroli SpA. The maximum exposure to loss from EME's interest in this entity is $72 million at
December 31, 2002.

IVPC 4 S.r.l.In 2000, EME purchased Edison Mission Wind Power Italy B.V., which owns a 50% interest in 13 power projects that
are in operation in Italy by UPC International Partnership CV II, which EME collectively refers to as the Italian Wind project. The projects use wind to generate electricity from turbines, which is
sold under fixed-price, long-term tariffs to Gestore Rete Transmissione Nazionale. The maximum exposure to loss from EME's interest in this entity is $40 million at
December 31, 2002.

PT Paiton EnergyEME owns a 40% interest in PT Paiton Energy (Paiton Energy), which owns a 1,230 MW coal-fired
power plant in operation in East Java, Indonesia. Paiton Energy sells electricity to PT PLN, the state-owned electric utility company, under a power purchase agreement. The maximum exposure to loss
from EME's interest in this entity is $541 million at December 31, 2002.

TM StarEME owns a 50% interest in TM Star, which was formed for the limited purpose to sell natural gas to March Point
Cogeneration Company, an affiliate through common ownership, under a fuel supply agreement. TM Star has entered into fuel purchase contracts with unrelated third parties to meet a portion of the
obligations under the fuel supply agreement. EME has guaranteed 50% of the

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obligation under the fuel supply agreement to March Point Cogeneration Company. The maximum loss is subject to changes in natural gas prices. Accordingly, the maximum exposure to loss cannot be
determined.



EME also believes it is reasonably possible that the following interests in non-utility generators purchased as part of the Citizens Power acquisition
in 2000 are variable interest entities under FIN 46:

CL Power Sales One, LLCEME owns a 25% interest in CL Power Sales One, LLC (CL One). CL One was formed for a limited purpose
to sell capacity under a contract to Central Maine Power with a capacity purchase contract from an unrelated third-party generator. The purchases and sales of capacity are substantially on the same
terms and are non-recourse to EME and its subsidiaries. EME does not have exposure to loss from this entity at December 31, 2002.

CL Power Sales Two, LLCEME owns a 25% interest in CL Power Sales Two, LLC (CL Two). CL Two was formed with the limited
purpose to sell power to New York State Electric & Gas Company under a power sales agreement through August 2007. CL Two acquires the power through its affiliate CL Power Sale Seven,
LLC. The maximum exposure to loss from EME's interest in this entity is $1 million at December 31, 2002.

CL Power Sales Seven, LLCEME owns a 25% interest in CL Power Sales Seven, LLC (CL Seven). CL Seven was formed with the
limited purpose to sell power to CL Two under a power sales agreement through August 2007. CL Seven acquires the power from Exelon Generation Co., LLC. The maximum exposure to loss from EME's
interest in this entity is less than $1 million at December 31, 2002.

CL Power Sales Eight, LLCEME owns a 25% interest in CL Power Sales Eight, LLC (CL Eight). CL Eight was formed for the limited
purpose to sell power to Central Maine Power under a power sales agreement through December 2016. CL Eight acquires the power through Edison Mission Marketing & Trading, which in turn
acquires its power from NRG Power Marketing Inc. The maximum exposure to loss from EME's interest in this entity is $5 million at December 31, 2002.

CL Power Sales Nine, LLCEME owns a 25% interest in CL Power Sales Nine, LLC (CL Nine). CL Nine was formed with the limited
purpose to sell power to Jersey Central Power & Light Company, doing business as GPU Energy through June 2004. CL Nine acquires its power through Edison Mission Marketing &
Trading, which in turn acquires its power from Exelon Generation Co., LLC. The maximum exposure to loss from EME's interest in this entity is less than $1 million as of December 31,
2002.

CL Power Sales Ten, LLCEME owns a 25% interest in CL Power Sales Ten, LLC (CL Ten). CL Ten was formed with the limited
purpose to sell power to New York State Electric & Gas Company under a power sales agreement through April 2008. CL Ten acquires its power from PG&E Energy
TradingPower L.P. The maximum exposure to loss from EME's interest in this entity is less than $1 million as of December 31, 2002.



Under FIN 46, an enterprise that will (1) absorb a majority of a variable interest entity's expected losses (if they occur), (2) receive a majority
of a variable interest entity's expected residual returns (if they occur), or (3) both of the above, must consolidate the variable interest entity. The enterprise that consolidates the variable
interest entity is called the primary beneficiary. EME is in the process of reviewing the entities listed above that have a reasonable possibility of being variable interest entities to determine if
it is the primary beneficiary.

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EME has concluded that it is the primary beneficiary of Brooklyn Navy Yard Cogeneration Partners L.P. since it is at risk with respect to a majority of its losses
and is entitled to receive a majority of its residual returns. Accordingly, EME will consolidate Brooklyn Navy Yard Cogeneration Partners L.P. effective July 1, 2003. In accordance with the
transition provisions of FIN 46, the consolidation of Brooklyn Navy Yard Cogeneration Partners L.P. will be based on the historical cost of the assets, liabilities and non-controlling
interest which would have been carried by EME effective when EME became the primary beneficiary. This means that EME will consolidate the assets and liabilities of Brooklyn Navy Yard Cogeneration
Partners L.P. using the June 30, 2003 balance sheet and eliminate intercompany balances. EME expects the consolidation of this entity to increase total assets by approximately
$365 million and total liabilities by approximately $445 million. Furthermore, EME expects to record a loss of approximately $80 million as a cumulative change of accounting as a
result of consolidating this variable interest entity. This loss is primarily due to cumulative losses allocated to the other 50% partner in excess of equity contributions recorded.

Recent Development

On March 3, 2003, Contact Energy completed a transaction with NGC Holdings Ltd. to acquire the Taranaki Combined Cycle power station and related
interests for NZ$500 million. The NZ$500 million purchase price was financed with bridge loan facilities. Contact Energy intends to refinance these facilities with the issuance of
long-term senior debt. The Taranaki station is a 357 MW combined cycle, natural gas-fired plant located near Stratford, New Zealand.

ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

Information responding to Item 7A is filed with this report under "Item 7. Management's Discussion and Analysis of Results of Operations and Financial Condition."

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ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA

|Financial Statements: |                                                                                                             | 
|--------------------- | ----------------------------------------------------------------------------------------------------------- | 
|                      | Report of Independent Accountants                                                                           | 
|                      | Consolidated Statements of Income (Loss) for the years ended December 31, 2002, 2001 and 2000               | 
|                      | Consolidated Balance Sheets at December 31, 2002 and 2001                                                   | 
|                      | Consolidated Statements of Shareholder's Equity for the years ended December 31, 2002, 2001 and 2000        | 
|                      | Consolidated Statements of Comprehensive Income (Loss) for the years ended December 31, 2002, 2001 and 2000 | 
|                      | Consolidated Statements of Cash Flows for the years ended December 31, 2002, 2001 and 2000                  | 
|                      | Notes to Consolidated Financial Statements                                                                  | 

ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE

None.

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MISSION ENERGY HOLDING COMPANY AND SUBSIDIARIES  REPORT OF INDEPENDENT ACCOUNTANTS

To
the Board of Directors of Mission Energy Holding Company:

In
our opinion, the consolidated financial statements listed in the accompanying index present fairly, in all material respects, the financial position of Mission Energy Holding Company
and its subsidiaries at December 31, 2002 and December 31, 2001, and the results of its operations and its cash flows for each of the three years in the period ended December 31,
2002 in conformity with accounting principles generally accepted in the United States of America. In addition, in our opinion, the financial statement schedules listed in the index appearing under
Item 15 on page 199 present fairly, in all material respects, the information set forth therein when read in conjunction with the related consolidated financial statements. These financial statements
and financial statement schedules are the responsibility of the Company's management; our responsibility is to express an opinion on these financial statements and financial statement schedules based
on our audits. We conducted our audits of these statements in accordance with auditing standards generally accepted in the United States of America, which 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, assessing the accounting principles used and significant estimates made by management, and evaluating the overall financial statement presentation. We believe that our audits
provide a reasonable basis for our opinion.

The
accompanying financial statements have been prepared assuming that the Company will continue as a going concern. As discussed in Note 10 to the financial statements, Edison
Mission Energy's largest subsidiary, Edison Mission Midwest Holdings has $911 million in debt that matures in December 2003. Uncertainty regarding the ability of the Company to repay,
extend or refinance this obligation raises substantial doubt about its ability to continue as a going concern. Management's plan in regard to this matter is described in Note 10. The financial
statements do not include any adjustments that might result from the resolution of this uncertainty.

As
explained in Note 2 to the financial statements, effective October 1, 2002, the Company has changed its method of accounting for debt extinguishments in accordance with
SFAS No. 145, "Rescission of
FASB Statements No. 4, 44, and 64, Amendment of FASB Statement No. 13, and Technical Corrections." As also explained in Note 2 to the financial statements, effective
January 1, 2001, the Company has changed its method of accounting for derivative instruments and hedging activities in accordance with SFAS No. 133, "Accounting for Derivative
Instruments and Hedging Activities." Further explained in Note 2 to the financial statements, effective January 1, 2002, the Company has changed its method of accounting for goodwill and
other intangible assets in accordance with SFAS No. 142, "Goodwill and Other Intangible Assets."

PricewaterhouseCoopers
LLP

Los
Angeles, California
March 25, 2003

118

---



MISSION ENERGY HOLDING COMPANY AND SUBSIDIARIES        CONSOLIDATED STATEMENTS OF INCOME (LOSS)        (In thousands)

|                                                                                                                                             |                                                                             | Years Ended December 31,     |        
|-------------------------------------------------------------------------------------------------------------------------------------------- | --------------------------------------------------------------------------- | ---------------------------- | -------
|
|Operating Revenues                                                                                                                           |                                                                             |                              |        
|                                                                                                                                             | Electric revenues                                                           |                              | $      
|                                                                                                                                             | Net gains (losses) from price risk management and energy trading            |                              |        
|                                                                                                                                             | Operation and maintenance services                                          |                              |        
|                                                                                                                                             |                                                                             |                              |        
|                                                                                                                                             |                                                                             | Total operating revenues     |        
|                                                                                                                                             |                                                                             |                              |        
|Operating Expenses                                                                                                                           |                                                                             |                              |        
|                                                                                                                                             | Fuel                                                                        |                              |        
|                                                                                                                                             | Plant operations and transmission costs                                     |                              |        
|                                                                                                                                             | Plant operating leases                                                      |                              |        
|                                                                                                                                             | Operation and maintenance services                                          |                              |        
|                                                                                                                                             | Depreciation and amortization                                               |                              |        
|                                                                                                                                             | Long-term incentive compensation                                            |                              |        
|                                                                                                                                             | Settlement of postretirement employee benefit liability                     |                              |        
|                                                                                                                                             | Asset impairment and other charges                                          |                              |        
|                                                                                                                                             | Administrative and general                                                  |                              |        
|                                                                                                                                             |                                                                             |                              |        
|                                                                                                                                             |                                                                             | Total operating expenses     |        
|                                                                                                                                             |                                                                             |                              |        
|                                                                                                                                             | Operating income                                                            |                              |        
|                                                                                                                                             |                                                                             |                              |        
|Other Income (Expense)                                                                                                                       |                                                                             |                              |        
|                                                                                                                                             | Equity in income from unconsolidated affiliates                             |                              |        
|                                                                                                                                             | Interest and other income                                                   |                              |        
|                                                                                                                                             | Gain on sale of assets                                                      |                              |        
|                                                                                                                                             | Gain on early extinguishment of debt                                        |                              |        
|                                                                                                                                             | Interest expense                                                            |                              |        
|                                                                                                                                             | Dividends on preferred securities                                           |                              |        
|                                                                                                                                             |                                                                             |                              |        
|                                                                                                                                             |                                                                             | Total other income (expense) |        
|                                                                                                                                             |                                                                             |                              |        
|                                                                                                                                             | Income from continuing operations before income taxes and minority interest |                              |        
|                                                                                                                                             | Provision (benefit) for income taxes                                        |                              |        
|                                                                                                                                             | Minority interest                                                           |                              |        
|                                                                                                                                             |                                                                             |                              |        
|Income From Continuing Operations                                                                                                            |                                                                             |                              | 3,074  
|Income (loss) from operations of discontinued foreign subsidiaries (including loss on disposal of $1.1 billion in 2001), net of tax (Note 7) |                                                                             |                              | (57,329
|                                                                                                                                             |                                                                             |                              |        
|Income (Loss) Before Accounting Change                                                                                                       |                                                                             |                              | (54,255
|Cumulative effect of change in accounting, net of tax (Note 2)                                                                               |                                                                             |                              | (13,986
|                                                                                                                                             |                                                                             |                              |        
|Net Income (Loss)                                                                                                                            |                                                                             | $                            | (68,241
|                                                                                                                                             |                                                                             |                              |        

The
accompanying notes are an integral part of these consolidated financial statements.

119

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MISSION ENERGY HOLDING COMPANY AND SUBSIDIARIES        CONSOLIDATED BALANCE SHEETS        (In thousands)

|                                         |                                                                                    | December 31,                     
|---------------------------------------- | ---------------------------------------------------------------------------------- | ---------------------------------
|
|Assets                                   |                                                                                    |                                  
|Current Assets                           |                                                                                    |                                  
|                                         | Cash and cash equivalents                                                          |                                  
|                                         | Accounts receivabletrade, net of allowance of $13,113 in 2002 and $14,603 in 2001 |                                  
|                                         | Accounts receivableaffiliates                                                     |                                  
|                                         | Assets under price risk management and energy trading                              |                                  
|                                         | Inventory                                                                          |                                  
|                                         | Prepaid expenses and other                                                         |                                  
|                                         |                                                                                    |                                  
|                                         |                                                                                    | Total current assets             
|                                         |                                                                                    |                                  
|Investments in Unconsolidated Affiliates |                                                                                    |                                  
|                                         |                                                                                    |                                  
|Property, Plant and Equipment            |                                                                                    |                                  
|                                         | Less accumulated depreciation and amortization                                     |                                  
|                                         |                                                                                    |                                  
|                                         |                                                                                    | Net property, plant and equipment
|                                         |                                                                                    |                                  
|Other Assets                             |                                                                                    |                                  
|                                         | Long-term receivables                                                              |                                  
|                                         | Goodwill                                                                           |                                  
|                                         | Deferred financing costs                                                           |                                  
|                                         | Long-term assets under price risk management and energy trading                    |                                  
|                                         | Restricted cash and other                                                          |                                  
|                                         |                                                                                    |                                  
|                                         |                                                                                    | Total other assets               
|                                         |                                                                                    |                                  
|Assets of Discontinued Operations        |                                                                                    |                                  
|                                         |                                                                                    |                                  
|Total Assets                             |                                                                                    | $                                
|                                         |                                                                                    |                                  

The
accompanying notes are an integral part of these consolidated financial statements.

120

---



MISSION ENERGY HOLDING COMPANY AND SUBSIDIARIES        CONSOLIDATED BALANCE SHEETS        (In thousands)

|                                                        |                                                                                                   | December 31,                         |           
|------------------------------------------------------- | ------------------------------------------------------------------------------------------------- | ------------------------------------ | ----------
|
|Liabilities and Shareholder's Equity                    |                                                                                                   |                                      |           
|Current Liabilities                                     |                                                                                                   |                                      |           
|                                                        | Accounts payableaffiliates                                                                       |                                      | $         
|                                                        | Accounts payable and accrued liabilities                                                          |                                      |           
|                                                        | Liabilities under price risk management and energy trading                                        |                                      |           
|                                                        | Interest payable                                                                                  |                                      |           
|                                                        | Short-term obligations                                                                            |                                      |           
|                                                        | Current portion of long-term incentive compensation                                               |                                      |           
|                                                        | Current maturities of long-term obligations                                                       |                                      |           
|                                                        |                                                                                                   |                                      |           
|                                                        |                                                                                                   | Total current liabilities            |           
|                                                        |                                                                                                   |                                      |           
|Long-Term Obligations Net of Current Maturities         |                                                                                                   |                                      | 6,033,775 
|                                                        |                                                                                                   |                                      |           
|Long-Term Deferred Liabilities                          |                                                                                                   |                                      |           
|                                                        | Deferred taxes and tax credits                                                                    |                                      |           
|                                                        | Deferred revenue                                                                                  |                                      |           
|                                                        | Long-term incentive compensation                                                                  |                                      |           
|                                                        | Long-term liabilities under price risk management and energy trading                              |                                      |           
|                                                        | Other                                                                                             |                                      |           
|                                                        |                                                                                                   |                                      |           
|                                                        |                                                                                                   | Total long-term deferred liabilities |           
|                                                        |                                                                                                   |                                      |           
|Liabilities of Discontinued Operations                  |                                                                                                   |                                      | 3,024     
|                                                        |                                                                                                   |                                      |           
|Total Liabilities                                       |                                                                                                   |                                      | 9,925,264 
|                                                        |                                                                                                   |                                      |           
|Minority Interest                                       |                                                                                                   |                                      | 423,844   
|                                                        |                                                                                                   |                                      |           
|Preferred Securities of Subsidiaries                    |                                                                                                   |                                      |           
|                                                        | Company-obligated mandatorily redeemable security of partnership holding solely parent debentures |                                      |           
|                                                        | Subject to mandatory redemption                                                                   |                                      |           
|                                                        |                                                                                                   |                                      |           
|                                                        | Total preferred securities of subsidiaries                                                        |                                      |           
|                                                        |                                                                                                   |                                      |           
|Commitments and Contingencies (Notes 10, 11, 16 and 17) |                                                                                                   |                                      |           
|Shareholder's Equity                                    |                                                                                                   |                                      |           
|                                                        | Common stock, $.01 par value; 1,000 shares authorized; 1,000 shares issued and outstanding        |                                      |           
|                                                        | Additional paid-in capital                                                                        |                                      |           
|                                                        | Retained deficit                                                                                  |                                      |           
|                                                        | Accumulated other comprehensive loss                                                              |                                      |           
|                                                        |                                                                                                   |                                      |           
|Total Shareholder's Equity                              |                                                                                                   |                                      | 736,168   
|                                                        |                                                                                                   |                                      |           
|Total Liabilities and Shareholder's Equity              |                                                                                                   | $                                    | 11,366,501
|                                                        |                                                                                                   |                                      |           

The
accompanying notes are an integral part of these consolidated financial statements.

121

---

MISSION ENERGY HOLDING COMPANY AND SUBSIDIARIES        CONSOLIDATED STATEMENTS OF SHAREHOLDER'S EQUITY        (In thousands)

|                             |                                                      | Additional
Paid-in
Capital |           | Retained
Earnings |   | Accumulated
Other
Comprehensive
Income |            | Shareholder's
Equity |         
|---------------------------- | ---------------------------------------------------- | -------------------------- | --------- | ----------------- | - | -------------------------------------- | ---------- | -------------------- | --------
|Balance at December 31, 1999 |                                                      | $                          | 2,693,536 |                   | $ | 364,434                                |            | $                    | 10,507  
|                             | Net income                                           |                            |           |                  |   |                                        | 125,252    |                      |         
|                             | Other comprehensive loss                             |                            |           |                  |   |                                        |           |                      |         
|                             | Cash dividends to parent                             |                            |           |                  |   |                                        | (88,000    | )                    |         
|                             | Stock option price appreciation on options exercised |                            |           |                  |   |                                        | (290       | )                    |         
|                             |                                                      |                            |           |                   |   |                                        |            |                      |         
|Balance at December 31, 2000 |                                                      |                            | 2,693,536 |                   |   | 401,396                                |            |                      | (146,748
|                             | Net loss                                             |                            |           |                  |   |                                        | (1,169,652 | )                    |         
|                             | Other comprehensive loss                             |                            |           |                  |   |                                        |           |                      |         
|                             | Cash dividends to parent                             |                            |           | (479,331          | ) |                                        | (428,388   | )                    |         
|                             | Other stock transactions, net                        |                            |           | 1,920             |   |                                        |           |                      |         
|                             |                                                      |                            |           |                   |   |                                        |            |                      |         
|Balance at December 31, 2001 |                                                      |                            | 2,216,125 |                   |   | (1,196,644                             | )          |                      | (302,627
|                             | Net loss                                             |                            |           |                  |   |                                        | (68,241    | )                    |         
|                             | Other comprehensive income                           |                            |           |                  |   |                                        |           |                      |         
|                             | Stock option price appreciation on options exercised |                            |           |                  |   |                                        | (286       | )                    |         
|                             | Capital contributions from parent                    |                            |           | 600               |   |                                        |           |                      |         
|                             | Other stock transactions, net                        |                            |           | 1,560             |   |                                        |           |                      |         
|                             |                                                      |                            |           |                   |   |                                        |            |                      |         
|Balance at December 31, 2002 |                                                      | $                          | 2,218,285 |                   | $ | (1,265,171                             | )          | $                    | (216,946
|                             |                                                      |                            |           |                   |   |                                        |            |                      |         

The
accompanying notes are an integral part of these consolidated financial statements.

122

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MISSION ENERGY HOLDING COMPANY AND SUBSIDIARIES        CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (LOSS)        (In thousands)

|                                                  |                                                                         | Years Ended December 31,                                                                                                                                |        
|------------------------------------------------- | ----------------------------------------------------------------------- | ------------------------------------------------------------------------------------------------------------------------------------------------------- | -------
|
|Net Income (Loss)                                 |                                                                         | $                                                                                                                                                       | (68,241
|Other comprehensive income (expense), net of tax: |                                                                         |                                                                                                                                                         |        
|                                                  | Foreign currency translation adjustments:                               |                                                                                                                                                         |        
|                                                  |                                                                         | Foreign currency translation adjustments, net of income tax expense (benefit) of $3,775, $(1,349) and $(3,934) for 2002, 2001 and 2000, respectively    |        
|                                                  |                                                                         | Reclassification adjustments for sale of investment in a foreign subsidiary                                                                             |        
|                                                  | Minimum pension liability adjustment                                    |                                                                                                                                                         |        
|                                                  | Unrealized gains (losses) on derivatives qualified as cash flow hedges: |                                                                                                                                                         |        
|                                                  |                                                                         | Cumulative effect of change in accounting for derivatives, net of income tax expense (benefit) of $5,562 and $(124,400) for 2002 and 2001, respectively |        
|                                                  |                                                                         | Other unrealized holding gains (losses) arising during period, net of income tax expense of $5,752 and $62,500 for 2002 and 2001, respectively          |        
|                                                  |                                                                         | Reclassification adjustments included in net income (loss), net of income tax benefit of $3,722 and $7,800 for 2002 and 2001, respectively              |        
|                                                  |                                                                         |                                                                                                                                                         |        
|Other comprehensive income (expense)              |                                                                         |                                                                                                                                                         | 85,681 
|                                                  |                                                                         |                                                                                                                                                         |        
|Comprehensive Income (Loss)                       |                                                                         | $                                                                                                                                                       | 17,440 
|                                                  |                                                                         |                                                                                                                                                         |        

The
accompanying notes are an integral part of these consolidated financial statements.

123

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MISSION ENERGY HOLDING COMPANY AND SUBSIDIARIES        CONSOLIDATED STATEMENTS OF CASH FLOWS        (In thousands)

|                                                                        |                                                                                                | Years Ended December 31,                                        |         
|----------------------------------------------------------------------- | ---------------------------------------------------------------------------------------------- | --------------------------------------------------------------- | --------
|
|Cash Flows From Operating Activities                                    |                                                                                                |                                                                 |         
|                                                                        | Income (loss) from continuing operations, after accounting change, net                         |                                                                 | $       
|                                                                        | Adjustments to reconcile income (loss) to net cash provided by (used in) operating activities: |                                                                 |         
|                                                                        |                                                                                                | Equity in income from unconsolidated affiliates                 |         
|                                                                        |                                                                                                | Distributions from unconsolidated affiliates                    |         
|                                                                        |                                                                                                | Depreciation and amortization                                   |         
|                                                                        |                                                                                                | Amortization of discount on obligations                         |         
|                                                                        |                                                                                                | Deferred taxes and tax credits                                  |         
|                                                                        |                                                                                                | Gain on sale of assets                                          |         
|                                                                        |                                                                                                | Asset impairment and other charges                              |         
|                                                                        |                                                                                                | Cumulative effect of change in accounting, net of tax           |         
|                                                                        |                                                                                                | Settlement of postretirement employee benefit liability         |         
|                                                                        | Changes in operating assets and liabilities:                                                   |                                                                 |         
|                                                                        |                                                                                                | Decrease (increase) in accounts receivable                      |         
|                                                                        |                                                                                                | Decrease (increase) in inventory                                |         
|                                                                        |                                                                                                | Decrease in prepaid expenses and other                          |         
|                                                                        |                                                                                                | Increase (decrease) in accounts payable and accrued liabilities |         
|                                                                        |                                                                                                | Increase in interest payable                                    |         
|                                                                        |                                                                                                | Increase (decrease) in long-term incentive compensation         |         
|                                                                        |                                                                                                | Decrease (increase) in net assets under risk management         |         
|                                                                        | Other operating, net                                                                           |                                                                 |         
|                                                                        |                                                                                                |                                                                 |         
|                                                                        |                                                                                                |                                                                 | 866,539 
|                                                                        | Operating cash flow from discontinued operations                                               |                                                                 |         
|                                                                        |                                                                                                |                                                                 |         
|                                                                        |                                                                                                | Net cash provided by (used in) operating activities             |         
|                                                                        |                                                                                                |                                                                 |         
|Cash Flows From Financing Activities                                    |                                                                                                |                                                                 |         
|                                                                        | Borrowing on long-term debt and lease swap agreements                                          |                                                                 |         
|                                                                        | Payments on long-term debt agreements                                                          |                                                                 |         
|                                                                        | Short-term financing and lease swap agreements, net                                            |                                                                 |         
|                                                                        | Contributions from parent                                                                      |                                                                 |         
|                                                                        | Cash dividends                                                                                 |                                                                 |         
|                                                                        | Funds provided to discontinued operations                                                      |                                                                 |         
|                                                                        | Issuance of preferred securities                                                               |                                                                 |         
|                                                                        | Redemption of preferred securities                                                             |                                                                 |         
|                                                                        | Financing costs                                                                                |                                                                 |         
|                                                                        |                                                                                                |                                                                 |         
|                                                                        |                                                                                                |                                                                 | (296,524
|                                                                        | Financing cash flow from discontinued operations                                               |                                                                 |         
|                                                                        |                                                                                                |                                                                 |         
|                                                                        |                                                                                                | Net cash used in financing activities                           |         
|                                                                        |                                                                                                |                                                                 |         
|Cash Flows From Investing Activities                                    |                                                                                                |                                                                 |         
|                                                                        | Investments in and loans to energy projects                                                    |                                                                 |         
|                                                                        | Purchase of common stock of acquired companies                                                 |                                                                 |         
|                                                                        | Purchase of generating stations                                                                |                                                                 |         
|                                                                        | Purchase of power sales agreement                                                              |                                                                 |         
|                                                                        | Capital expenditures                                                                           |                                                                 |         
|                                                                        | Proceeds from sale-leaseback transactions                                                      |                                                                 |         
|                                                                        | Proceeds from return of capital and loan repayments                                            |                                                                 |         
|                                                                        | Proceeds from sale of interest in projects                                                     |                                                                 |         
|                                                                        | Increase in restricted cash                                                                    |                                                                 |         
|                                                                        | Investments in other assets                                                                    |                                                                 |         
|                                                                        | Other, net                                                                                     |                                                                 |         
|                                                                        |                                                                                                |                                                                 |         
|                                                                        |                                                                                                |                                                                 | (305,420
|                                                                        | Investing cash flow from discontinued operations                                               |                                                                 |         
|                                                                        |                                                                                                |                                                                 |         
|                                                                        |                                                                                                | Net cash provided by (used in) investing activities             |         
|                                                                        |                                                                                                |                                                                 |         
|Effect of exchange rate changes on cash                                 |                                                                                                |                                                                 | 24,739  
|Effect on cash from de-consolidation of subsidiary                      |                                                                                                |                                                                 | (26,927 
|                                                                        |                                                                                                |                                                                 |         
|Net increase (decrease) in cash and cash equivalents                    |                                                                                                |                                                                 | 299,259 
|Cash and cash equivalents at beginning of period                        |                                                                                                |                                                                 | 435,191 
|                                                                        |                                                                                                |                                                                 |         
|Cash and cash equivalents at end of period                              |                                                                                                |                                                                 | 734,450 
|Cash and cash equivalents classified as part of discontinued operations |                                                                                                |                                                                 | (76     
|                                                                        |                                                                                                |                                                                 |         
|Cash and cash equivalents of continuing operations                      |                                                                                                | $                                                               | 734,374 
|                                                                        |                                                                                                |                                                                 |         

The accompanying notes are an integral part of these consolidated financial statements.

124

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MISSION ENERGY HOLDING COMPANY AND SUBSIDIARIES        NOTES TO CONSOLIDATED FINANCIAL STATEMENTS        (Dollars in millions)

Note 1. General

Organization

Mission Energy Holding Company (MEHC) is a wholly owned subsidiary of The Mission Group, a wholly owned, non-utility subsidiary of Edison
International, the parent holding company of Southern California Edison Company. MEHC was formed on June 8, 2001 to engage in the financings described in Note 10Financial
InstrumentsLong-Term Obligations. Prior to July 2, 2001, The Mission Group owned Edison Mission Energy (EME). On July 2, 2001, The Mission Group contributed to
MEHC all of the outstanding common stock of EME. The contribution of EME's common stock to MEHC has been accounted for as a transfer of ownership of companies under common control, which is similar to
a pooling of interest. This means that MEHC's historical financial results of operations and financial position include the historical financial results and results of operations of EME and its
subsidiaries as though MEHC had such ownership throughout the periods presented. MEHC does not have any substantive operations other than through EME and its subsidiaries and other investments.
Through MEHC's ownership of EME and its subsidiaries, MEHC is engaged in the business of owning or leasing and operating electric power generation facilities worldwide. Through EME, MEHC also conducts
price risk management and energy trading activities in power markets open to competition. The inclusion in this report of information pertaining to EME or any of its subsidiaries should not be
understood to mean that EME or any of its subsidiaries has agreed to pay or become liable for any debt of MEHC. EME and MEHC are separate entities with separate obligations.

Note 2. Summary of Significant Accounting Policies

Consolidations

The consolidated financial statements include MEHC and its majority-owned subsidiaries, partnerships and a special purpose corporation. All significant
intercompany transactions have been eliminated. Certain prior year reclassifications have been made to conform to the current year financial statement presentation. Except as indicated, amounts
reflected in the notes to the consolidated financial statements relate to continuing operations of MEHC.

Management's Use of Estimates

The preparation of financial statements in conformity with generally accepted accounting principles requires MEHC to make estimates and assumptions that affect
the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the
reported period. Actual results could differ from those estimates.

Cash Equivalents

Cash equivalents include time deposits and other investments totaling $568 million and $231 million at December 31, 2002 and 2001,
respectively, with maturities of three months or less. All investments are classified as available-for-sale.

125

---

Investments

Investments in unconsolidated affiliates with 50% or less voting stock are accounted for by the equity method. The majority of energy projects and all investments
in oil and gas are accounted for under the equity method at December 31, 2002 and 2001. The equity method of accounting is generally used to
account for the operating results of entities over which EME has a significant influence but in which EME does not have a controlling interest.

Property, Plant and Equipment

Property, plant and equipment, including leasehold improvements and construction in progress, are capitalized at cost and are principally comprised of EME's
majority-owned subsidiaries' plants and related facilities. Depreciation and amortization are computed by using the straight-line method over the useful life of the property, plant and
equipment and over the lease term for leasehold improvements.

As
part of the acquisition of the Illinois Plants and the Homer City facilities, EME acquired emission allowances under the Environmental Protection Agency's Acid Rain Program. Although
the emission allowances granted under this program are freely transferable, EME intends to use substantially all the emission allowances in the normal course of its business to generate electricity.
Accordingly, EME has classified emission allowances expected to be used by EME to generate power as part of property, plant and equipment. Acquired emission allowances will be amortized over the
estimated lives of the plants on a straight-line basis.

Useful
lives for property, plant, and equipment are as follows:

Furniture and office equipment

3-11 yearsBuilding, plant and equipment

3-100 yearsEmission allowances

25-40 yearsCivil works

40-100 yearsLeasehold improvements

Life of lease


Goodwill and Intangible Assets

Goodwill and other intangible assets generally result from business acquisitions. Goodwill represents the cost incurred in excess of the fair value of net assets
acquired in a purchase transaction. Since January 1, 2002, upon adoption of Statement of Financial Accounting Standards No. 142, "Goodwill and Other Intangible Assets," goodwill and
other intangible assets with indefinite useful lives are no longer amortized but instead are reviewed for impairment and any excess in the carrying value over the estimated fair value is charged to
results of operations. Customer contracts with finite useful lives are amortized on a straight-line basis over their estimated useful lives of 20 years. Goodwill and intangible
assets are discussed further in Note 4Goodwill and Intangible Assets.

Impairment of Investments and Long-Lived Assets

EME periodically evaluates the potential impairment of its investments in projects and other long-lived assets based on a review of estimated future
cash flows expected to be generated. If the

126

---

carrying amount of the investment or asset exceeds the amount of the expected future cash flows, undiscounted and without interest charges, then an impairment loss for EME's investments in projects
and other long-lived assets is recognized in accordance with Accounting Principles Board Opinion No. 18, "The Equity Method of Accounting for Investments in Common Stock" and
Statement of Financial Accounting Standards No. 144, "Accounting for the Impairment or Disposal of Long-Lived Assets," respectively.

Capitalized Interest

Interest incurred on funds borrowed by EME to finance project construction is capitalized. Capitalization of interest is discontinued when the projects are
completed and deemed operational. Such capitalized interest is included in investment in energy projects and property, plant and equipment.

Capitalized
interest is amortized over the depreciation period of the major plant and facilities for the respective project.

Years Ended December 31,2002

2001

2000Interest incurred

$
616

$
638

$
566Interest capitalized


(4
)

(14
)

(14
)$
612

$
624

$
552


Income Taxes

MEHC is included in the consolidated federal and state income tax returns of Edison International and participates in tax-allocation and payment
agreements with other subsidiaries of Edison International. MEHC calculates its tax provision in accordance with these tax agreements. MEHC's current tax liability or benefit is determined on a "with
and without" basis. This means Edison International computes its combined federal and state tax liabilities including and excluding MEHC's taxable income or loss and state apportionment factors. This
method is similar to a separate company return, except that MEHC recognizes without regard to separate company limitations additional tax liabilities or benefits based on the impact to the combined
group of including MEHC's taxable income or losses and state apportionment factors.

MEHC
accounts for income taxes using the asset-and-liability method, wherein deferred tax assets and liabilities are recognized for future tax consequences of
temporary differences between the carrying amounts and the tax bases of assets and liabilities using enacted rates. Investment and energy tax credits are deferred and amortized over the term of the
power purchase agreement of the respective project. MEHC does not provide for federal income taxes or tax benefits on the undistributed earnings or losses of its international subsidiaries because
such earnings are reinvested indefinitely. Income tax accounting policies are discussed further in Note 13Income Taxes.

127

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Maintenance Accruals

Certain of EME's plant facilities' major pieces of equipment require major maintenance on a periodic basis. These costs are expensed as incurred. Through
December 31, 1999, EME accrued for major maintenance costs incurred during the period between overhauls (referred to as "accrue in advance" accounting method). In March 2000, EME
voluntarily decided to change its accounting policy to record major maintenance costs as an expense as incurred. This change in accounting policy is considered preferable based on guidance provided by
the Securities and Exchange Commission. In accordance with Accounting Principles Board Opinion No. 20, "Accounting Changes," EME recorded a $22 million, after tax, increase to income
from continuing operations, as the cumulative effect of change in the accounting for major maintenance costs during the quarter ended March 31, 2000.

Project Development Costs

EME capitalizes only the direct costs incurred in developing new projects subsequent to being awarded a bid. These costs consist of professional fees, salaries,
permits, and other directly related development costs incurred by EME. The capitalized costs are amortized over the life of operational projects or charged to expense if management determines the
costs to be unrecoverable.

Deferred Financing Costs

Bank, legal and other direct costs incurred in connection with obtaining financing are deferred and amortized as interest expense on a basis which approximates
the effective interest rate method over the term of the related debt. Accumulated amortization of these costs amounted to $81 million in 2002 and $48 million in 2001.

Derivative Instruments and Hedging Activities

EME's primary market risk exposures arise from fluctuations in electricity and fuel prices, emission and transmission rights, interest rates and foreign currency
exchange rates. EME manages these risks in part by using derivative financial instruments in accordance with established policies and procedures. Effective January 1, 2001, MEHC adopted
Statement of Financial Accounting Standards No. 133, "Accounting for Derivative Instruments and Hedging Activities." SFAS No. 133 established accounting and reporting standards requiring
that derivative instruments be recorded in the balance sheet as either assets or liabilities measured at their fair value unless they meet an exception. SFAS No. 133 also requires that changes
in the derivative's fair value be recognized currently in earnings unless specific hedge accounting criteria are met. For derivatives that qualify for hedge accounting, depending on the nature of the
hedge, changes in fair value are either offset by changes in the fair value of the hedged assets, liabilities or firm commitments through earnings, or recognized in other comprehensive income until
the hedged item is recognized in earnings.

Effective
January 1, 2001, MEHC recorded all derivatives at fair value unless the derivatives qualified for the normal sales and purchases exception. This exception applies to
physical sales and purchases of power or fuel where it is probable that physical delivery will occur, the pricing provisions are clearly and closely related to the contracted prices and the
documentation requirements of SFAS No. 133 are met.

128

---

Accounting
for derivatives under SFAS No. 133 is complex. Each transaction requires an assessment of whether it is a derivative according to the definition under SFAS
No. 133, including amendments and interpretations. Transactions that do not meet the definition of a derivative are accounted by MEHC on the accrual basis.

Discussion of Initial Adoption of SFAS No. 133

On January 1, 2001, EME recorded a $250 thousand, after tax, increase to income from continuing operations and a $230 million, after tax,
decrease to other comprehensive income as the cumulative effect of the adoption of SFAS No. 133. The following material items were recorded at fair value:



Discussion of July 1, 2001 Adoption of Interpretations of SFAS No. 133

Effective July 1, 2001, the Derivative Implementation Group of the Financial Accounting Standards Board under Statement No. 133 Implementation Issue
Number C15 modified the normal sales and purchases exception to include electricity contracts which include terms that require physical delivery by the seller in quantities that are expected to be
sold in the normal course of business. This modification has two significant impacts:



129

---



Discussion of April 1, 2002 Adoption of Interpretation of SFAS No. 133

In December 2001, the Derivative Implementation Group of the Financial Accounting Standards Board issued a revised interpretation of Issue Number C15 (DIG
C15). Under this revised interpretation, EME's forward electricity contracts no longer qualify for the normal sales exception since EME has net settlement agreements with its counterparties. Under
this exception, EME records revenue on an accrual basis. Subsequent to the implementation of DIG C15, EME accounted for these contracts as cash flow hedges. Under a cash flow hedge, EME records the
fair value of the forward sales agreements on its balance sheet and records the effective portion of the cash flow hedge as part of other comprehensive income. The ineffective portion of EME's cash
flow hedges is recorded directly in its income statement. EME implemented this interpretation on April 1, 2002. EME recorded assets at
fair value of $12 million, deferred taxes of $6 million and a $6 million increase to other comprehensive income as the cumulative effect of adoption of this interpretation.

Under
SFAS No. 133, the portion of a cash flow hedge that does not offset the change in value of the transaction being hedged, which is commonly referred to as the ineffective
portion, is immediately recognized in earnings. EME recorded a net loss of approximately $2 million and $1 million in 2002 and 2001, respectively, representing the amount of cash flow
hedges' ineffectiveness, reflected in net gains (losses) from price risk management and energy trading in its consolidated income statement.

Revenue Recognition

EME records revenue and related costs as electricity is generated or services are provided unless EME is subject to SFAS No. 133 and does not qualify for
the normal sales and purchases exception. For EME's long-term power contracts that provide for higher pricing in the early years of the contract, revenue is recognized in accordance with
Emerging Issues Task Force Issued Number 91-6, "Revenue Recognition of Long-Term Sales Contract," which results in a deferral and levelization of revenues being recognized.
Also included in deferred revenues is the deferred gain from the termination of the Loy Yang B power sales agreement.

130

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Energy Trading

Financial instruments that are utilized for trading purposes entered into prior to October 25, 2002, are accounted for using the fair value method under
EITF 98-10, "Accounting for Contracts Involved in Energy Trading and Risk Management Activities." In October 2002, the FASB Emerging Issues Task Force reached a consensus to rescind
EITF 98-10 for energy trading contracts executed after October 25, 2002. See, "New Accounting Standards" for further discussion. Under the fair value 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 energy trading activities. In the
absence of quoted market prices, financial instruments are valued at fair value, considering time value, volatility of the underlying commodity, and other factors as determined by EME. Resulting gains
and losses are recognized in net gains (losses) from price risk management and energy trading in the accompanying Consolidated Income Statements in the period of change. Assets from price risk
management and energy trading 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 price risk management and energy trading activities include the fair value of open financial positions related to trading activities of open financial positions related to trading
activities and the present value of net amounts payable from structured transactions.

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 shareholder's equity. Gains or losses resulting from foreign
currency transactions are normally included in other income in the consolidated statements of income. Foreign currency transaction gains/(losses) amounted to $(8) million, $7 million and
$13 million for 2002, 2001 and 2000, respectively.

Stock-based Compensation

At December 31, 2002, Edison International has stock-based employee compensation plans, which are described more fully in Note 15Stock
Compensation Plans. EME accounts for those plans under the recognition and measurement principles of APB Opinion No. 25, "Accounting for Stock Issued to Employees," and related interpretations.
No stock-based employee compensation cost is reflected in net income, as all options granted under those plans had an exercise price equal to the market value of the underlying common stock on the
date of grant. The following table illustrates the effect on net income

131

---

(loss) if EME had applied the fair value recognition provisions of SFAS No. 123, "Accounting for Stock-Based Compensation," to stock-based employee compensation.

Years Ended December 31,2002

2001

2000Net income (loss), as reported

$
(68
)
$
(1,170
)
$
125Deduct: Total stock-based employee compensation expense determined under fair value based method for all awards, net of related tax effects


(1
)

(1
)

(1
)Pro forma net income (loss)

$
(69
)
$
(1,171
)
$
124


New Accounting Standards



In October 2002, the FASB Emerging Issues Task Force (commonly referred to as EITF) reached a consensus to rescind EITF No. 98-10,
"Accounting for Contracts Involved in Energy Trading and Risk Management Activities," subject to transition positions, as part of its deliberations on Issue No. 02-03, "Recognition
and Reporting of Gains and Losses on Energy Trading Contracts," under EITF Issues No. 98-10, "Accounting for Contracts Involved in Energy Trading and Risk Management Activities,"
and No. 00-17, "Measuring the Fair Value of Energy-Related Contracts in Applying Issue No. 98-10." The rescission of EITF No. 98-10 means that
energy trading and risk management activities will no longer be marked to market as trading activities, but will instead follow Statement of Financial Accounting Standards No. 133, "Accounting
for Derivatives" (SFAS No. 133). Under SFAS No. 133, each energy contract must be assessed to determine whether or not it meets the definition of a derivative subject to SFAS
No. 133. If an energy contract meets the definition of a derivative, then it would be recorded at fair value (i.e., mark-to-market), subject to permitted exceptions. If
an energy contract does not meet the definition of a derivative, then it would be recorded on an accrual basis. As a result of this new consensus, EME discontinued application of EITF
No. 98-10 for its energy trading operations for all new contracts entered into after October 25, 2002 and instead applies SFAS No. 133 to these transactions. EME does
not expect the rescission of EITF No. 98-10 to have a material impact on its consolidated financial statements.



Effective January 1, 2003, EME adopted Statement of Financial Accounting Standards No. 143, "Accounting for Asset Retirement Obligations." SFAS
No. 143 requires entities to record the fair value of a liability for an asset retirement obligation in the period in which it is incurred. When the liability is initially recorded, the entity
capitalizes a cost by increasing the carrying amount of the related long-lived asset. Over time, the liability is increased to its present value each period, and the capitalized cost is
depreciated over the useful life of the related asset. Upon settlement of the liability, an entity either settles the obligation for its recorded amount or incurs a gain or loss upon settlement. EME
expects to record a cumulative effect adjustment effective January 1, 2003, that will decrease net income by approximately $10 million, after tax.

132

---



In April 2002, the Financial Accounting Standards Board issued Statement of Financial Accounting Standards No. 145, "Rescission of FASB Statements
No. 4, 44, and 64, Amendment of FASB Statement No. 13, and Technical Corrections," which supersedes previous guidance for reporting gains and losses from extinguishment of debt and
accounting for leases, among other things. The portion of the statement relating to the rescission of SFAS No. 4, "Reporting Gains and Losses from Extinguishment of Debt" requires that any gain
or loss on extinguishment of debt that was classified as an extraordinary item that does not meet the unusual in nature and infrequent of occurrence criteria in APB Opinion No. 30, "Reporting
the Results of OperationsReporting the Effects of Disposal of a Segment of a Business, and Extraordinary, Unusual and Infrequently Occurring Events and Transactions" shall be
reclassified. The standard, effective on January 1, 2003, was adopted by EME in the fourth quarter of 2002, which required EME to reclassify as part of Income from Continuing Operations, an
extraordinary gain of $6 million, net of tax, recorded in December 2001. The extraordinary gain was attributable to the extinguishment of debt that was assumed by the third-party lessors
in the December 2001 Homer City sale-leaseback transaction.



Effective January 1, 2003, EME adopted Statement of Financial Accounting Standards No. 146, "Accounting for Costs Associated with Exit or Disposal
Activities." SFAS No. 146 requires that liabilities for costs associated with exit or disposal activities initiated after December 31, 2002 be recognized when incurred, rather than at
the date of a commitment to an exit or disposal plan. EME does not expect that this standard will have a material impact on its consolidated financial statements.



In November 2002, the Financial Accounting Standards Board issued Statement of Financial Accounting Standards Interpretation No. 45, "Guarantor's
Accounting and Disclosure Requirements for Guarantees, Including Indirect Guarantees of Indebtedness of Others." This interpretation establishes reporting requirements to be made by a guarantor about
its obligations under certain guarantees that it has issued. It also clarifies that a guarantor is required to recognize, at the inception of a guarantee, a liability for the fair value of the
obligation undertaken in issuing the guarantee. The initial recognition and initial measurement provisions of this interpretation are applicable on a prospective basis to guarantees issued or modified
after December 31, 2002. See disclosure regarding guarantees and indemnities in Note 16Commitments and Contingencies.



In January 2003, the Financial Accounting Standards Board issued Statement of Financial Accounting Standards Interpretation No. 46, "Consolidation
of Variable Interest Entities" (FIN 46). This interpretation of Accounting Research Bulletin No. 51, "Consolidated Financial Statements," addresses consolidation by business enterprises of
variable interest entities. The primary objective of the Interpretation is to provide guidance on the identification of, and financial reporting for, entities over which control is achieved through
means other than voting rights; such entities are known as variable-interest entities. This interpretation applies to variable interest entities created after January 31, 2003,

133

---

and applies to variable interest entities in which EME holds a variable interest that it acquired before February 1, 2003, beginning July 1, 2003. See disclosure regarding variable
interest entities in Note 8Investments in Unconsolidated Affiliates.

Note 3. Inventory

Inventory is stated at the lower of weighted average cost or market. Inventory at December 31, 2002 and December 31, 2001 consisted of the
following:

2002

2001Coal and fuel oil

$
111

$
110Spare parts, materials and supplies


65


57Total

$
176

$
167


Note 4. Goodwill and Intangible Assets

Effective January 1, 2002, EME adopted Statement of Financial Accounting Standards No. 142, "Goodwill and Other Intangible Assets." SFAS
No. 142 establishes accounting and reporting standards requiring goodwill not to be amortized but rather tested for impairment at least annually at the reporting unit level. The statement
requires that goodwill should be tested for impairment using a two-step approach. The first step used to identify a potential impairment compares the fair value of a reporting unit to its
carrying amount, including goodwill. If the fair value of the reporting unit is less than its carrying amount, the second step of the impairment test is performed to measure the amount of the
impairment loss. The second step of the impairment test is a comparison of the implied fair value of goodwill to its carrying amount. The impairment loss is equal to the excess carrying amount of the
goodwill over its implied fair value. The fair value of the reporting units for the Contact Energy and First Hydro operations was in excess of related book value at January 1, 2002.
Accordingly, no impairment of the goodwill related to these reporting units was recorded upon adoption of this standard. EME concluded that fair value of the goodwill related to the Citizens Power LLC
acquisition impaired by $14 million, net of $9 million of income tax benefit.

Estimates
of fair value were determined using comparable transactions. In accordance with SFAS No. 142, this decrease to continuing operations was recorded as of January 1,
2002 as a cumulative effect of a change in accounting principle, reflected in EME's consolidated income statement for the year ended December 31, 2002.

Included
in "Restricted cash and other assets" on EME's consolidated balance sheet are customer contracts with a gross carrying amount of $97 million and accumulated amortization
of $5 million at December 31, 2002. The contracts have a weighted average amortization period of 20 years. For the year ended December 31, 2002, the amortization expense
was $5 million. Based on the current amount of intangible assets subject to amortization, the estimated amortization expense for fiscal years 2003 through 2007 is $5 million each year.
Intangible assets classified in "Restricted cash and other assets" of $1 million at December 31, 2002 consists of an additional minimum pension liability at Midwest Generation.

134

---



Changes in the carrying amount of goodwill, by segment, for the year ended December 31, 2002 are as follows:

|                                      |  | Americas |     | Asia Pacific |   | Europe |   | Total |    
|------------------------------------- |  | -------- | --- | ------------ | - | ------ | - | ----- | ---
|Carrying amount at December 31, 2001  |  | $        | 25  |              | $ | 360    |   | $     | 247
|Impairment losses                     |  |          | (23 | )            |   |       |   |       |   
|Intangibles reclassed to other assets |  |          |    |              |   | (77    | ) |       |   
|Translation adjustments and other     |  |          |    |              |   | 101    |   |       | 27 
|                                      |  |          |     |              |   |        |   |       |    
|Carrying amount at December 31, 2002  |  | $        | 2   |              | $ | 384    |   | $     | 274
|                                      |  |          |     |              |   |        |   |       |    

The
following table sets forth what net income would have been exclusive of goodwill amortization for the years ended December 31, 2002, 2001 and 2000.

|                                            |  | Years Ended December 31,
|------------------------------------------- |  | ------------------------
|
|Reported net income (loss)                  |  | $                       
|Add back: Goodwill amortization, net of tax |  |                         
|                                            |  |                         
|Adjusted net income (loss)                  |  | $                       
|                                            |  |                         

Note 5. Accumulated Other Comprehensive Income (Loss)

Accumulated other comprehensive income (loss), including the discontinued operations of the Ferrybridge and Fiddler's Ferry power plants and Lakeland project,
consisted of the following:

Currency
Translation
Adjustments

Unrealized
Gains (Losses)
on Cash Flow
Hedges

Minimum Pension
Liability
Adjustment(1)

Accumulated Other
Comprehensive Income (Loss)Balance at December 31, 2001

$
(133
)
$
(169
)
$


$
(302
)Current period change


125


(29
)

(11
)

85Balance at December 31, 2002

$
(8
)
$
(198
)
$
(11
)
$
(217
)


---

Unrealized
gains (losses) on cash flow hedges included those related to the hedge agreement with the State Electricity Commission of Victoria for electricity prices from the Loy Yang B
project in Australia. This contract does not qualify under the normal sales and purchases exception because financial settlement of the contract occurs without physical delivery. Approximately 39% of
MEHC's unrealized gains (losses) on cash flow hedges at December 31, 2002 related to net unrealized losses on the cash flow hedge resulting from this contract. These losses arise because
current forecasts of future electricity prices in these markets are greater than contract prices. In addition to this contract,

135

---

unrealized gains (losses) on cash flow hedges included those related to EME's share of interest rate swaps of its unconsolidated affiliates and the Loy Yang B project.

As
EME's hedged positions are realized, approximately $6 million, after tax, of the net unrealized gains on cash flow hedges at December 31, 2002 are expected to be
reclassified into earnings during 2003. Management expects that when the hedged items are recognized in earnings, the net unrealized gains associated with them will be offset. The maximum period over
which EME has designated a cash flow hedge, excluding those forecasted transactions related to the payment of variable interest on existing financial instruments, is 14 years. Actual amounts
ultimately reclassed into earnings over the next 12 months could vary materially from this estimated amount as a result of changes in market conditions.

Interest
rate swaps entered into to hedge the floating interest rate risk on the $385 million term loan due 2006 qualify for treatment under SFAS No. 133 as cash flow
hedges with appropriate adjustments made to other comprehensive income. At December 31, 2002 and 2001, MEHC recorded approximately $5 million, after tax, and $1 million, after
tax, respectively, decrease to other comprehensive income resulting from unrealized holding losses on these contracts.

Note 6. Acquisitions and Dispositions

Acquisitions

Acquisition of Interest in CBK Power Co. Ltd.

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 760 MW Caliraya-Botocan-Kalayaan (CBK) hydroelectric
project located in the Philippines. Financing for this $460 million project comprises equity commitments of $117 million, of which EME's 50% share is $58.5 million, and debt
financing which is in place for the remainder of the cost for this project. As of December 31, 2002, EME has made equity contributions of $21 million. For a more detailed discussion of
the commitment to contribute project equity, refer to "Commitments and ContingenciesFirm Commitments to Contribute Project Equity."

Acquisition of Sunrise Project

On November 17, 2000, EME completed a transaction with Texaco Power & Gasification Holdings 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 included all rights, title and interest held
by Texaco Power & Gasification in the Sunrise project, except that Texaco Power & Gasification had an option to repurchase at cost a 50% interest in the project prior to its commercial
operation, which commenced on June 27, 2001. On June 25, 2001, Texaco Power & Gasification exercised its option and repurchased a 50% interest for $84 million. As part of
EME's acquisition of the Sunrise project, EME also: (i) acquired from Texaco Power & Gasification two gas turbines for the project and (ii) granted Texaco Power &
Gasification an option to acquire a 50% interest in 1,000 MW of future power plant projects EME designates. The Sunrise project consists of two phases, with Phase 1, a single-cycle
gas-fired facility (320 MW), completed on June 27, 2001, and Phase 2,

136

---

conversion to a combined-cycle gas-fired facility (increasing total capacity to 560 MW), currently scheduled to be completed in July 2003. EME entered into a long-term
power purchase agreement with the California Department of Water Resources on June 25, 2001. The power purchase agreement is discussed further in Note 16Commitments and
ContingenciesContingenciesRegulatory Developments Affecting Sunrise Power Company.

The
total purchase price of the Sunrise project from Texaco Power & Gasification was $27 million. EME funded the purchase with cash. The total estimated construction cost
of this project through 2003 is approximately $418 million. The project intends to obtain project financing to return a portion of the equity invested in the project to its owners.

Acquisition of Trading Operations of Citizens Power LLC

On September 1, 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 structured transaction investments relating to long-term power purchase agreements. The purchase price of $44.9 million
was based on the sum of: (a) fair market value of the trading portfolio and the structured transaction investments at the date of the acquisition and (b) $25 million. The
acquisition was funded with cash. As a result of this acquisition, EME has expanded its operations beyond the traditional marketing of its electric power to include trading of electricity and fuels,
although this represents a small portion of EME's consolidated operations. By the end of the third quarter of 2000, the Citizens trading operations were merged into EME's own marketing operations
under Edison Mission Marketing & Trading, Inc.

Acquisition of Interest in Italian Wind Project

On March 15, 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 which is sold under fixed-price, long-term tariffs. At December 31, 2002, 303 MW had been commissioned and are operational. The total purchase price was
47 million Euro dollars, with equity contribution obligations of up to 17 million Euro dollars. As of December 31, 2002, EME's payments in respect of these projects
included $53 million toward the purchase price and $16 million, which funded EME's entire equity contribution obligation.

Acquisition of Interest in Contact Energy

On May 14, 1999, EME completed a transaction with the New Zealand government to acquire 40% of the shares of Contact Energy Limited. The remaining 60% of
Contact Energy's shares were sold in a New Zealand and 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. 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 2,302 MW.

137

---

Consideration
for EME's interest in Contact Energy consisted of a cash payment of approximately $635 million (NZ$1.2 billion), which was financed by $120 million of
preferred securities, a $214 million (NZ$400 million at the time of the acquisition) credit facility, a $300 million equity contribution to EME from Edison International and cash.
The credit facility was subsequently paid off with proceeds from the issuance of additional preferred securities.

During
2000, EME increased its share of ownership in Contact Energy to 42.6%. Subsequently, during the second quarter of 2001, EME completed the purchase of additional shares of Contact
Energy for NZ$152 million, thereby increasing its ownership interest from 42.6% to 51.2%. Due to acquisition of a controlling interest, EME began accounting for Contact Energy on a consolidated
basis effective June 1, 2001. Prior to June 1, 2001, EME used the equity method of accounting for Contact Energy. In order to finance the purchase of the additional shares, EME obtained
a NZ$135 million, 364-day bridge loan from an investment bank under a credit facility which was syndicated by the bank. In addition to other security arrangements, a security
interest over all Contact Energy shares held by EME has been provided as collateral. On July 2, 2001, EME redeemed NZ$400 million preferred securities issued by one of EME's
subsidiaries, EME Taupo. Funding for the redemption of the existing preferred securities was provided by a NZ$400 million credit facility scheduled to mature in July 2005. The financing
documents provide that the credit facility may be funded under either, or a combination of, a letter of credit facility or a revolving credit facility. The NZ$400 million was originally funded
as a revolving credit facility. From June 2001 to October 2001, EME issued NZ$250 million of new preferred securities through one of its subsidiaries. The proceeds were used to
repay borrowings outstanding under the NZ$400 million credit facility and to repay the bridge loan.

On
March 3, 2003, Contact Energy completed a transaction with NGC Holdings Ltd. to acquire the Taranaki Combined Cycle power station and related interests for
NZ$500 million. The NZ$500 million purchase price was financed with bridge loan facilities. Contact Energy intends to refinance these
facilities with the issuance of long-term senior debt. The Taranaki station is a 357 MW combined cycle, natural gas-fired plant located near Stratford, New Zealand.

Accounting Treatment of Acquisitions

Each of the acquisitions described above has been accounted for utilizing the purchase method. The purchase price was allocated to the assets acquired and
liabilities assumed based on their respective fair market values. Amounts in excess of the fair value of the net assets acquired have been assigned to goodwill. MEHC's consolidated statement of income
reflects the operations of Sunrise beginning July 1, 2001, Citizens beginning September 1, 2000, Italian Wind beginning April 1, 2000, and Contact Energy beginning May 1,
1999. EME began accounting for Contact Energy on a consolidated basis effective June 1, 2001, upon acquisition of a controlling interest.

Pro Forma Data

Pro forma financial information is not presented for the acquisition of trading operations of Citizens Power LLC as the effect of this acquisition was not
material to MEHC's results of operations or financial position.

138

---

The
table below summarizes additional acquisitions by EME or its wholly owned subsidiaries from 2000 through 2002.

Date

Acquisition

Percentage
Acquired

Purchase PriceOil and GasDecember 19, 2001

Four Star Oil & Gas Company

1.4
%
$
7July 28, 2000

Four Star Oil & Gas Company

1.7
%

1May 15, 2000

Four Star Oil & Gas Company

1.7
%

2


Dispositions

During 2002, EME completed the sales of its 50% interests in the Commonwealth Atlantic and James River projects and its 30% interest in the Harbor project.
Proceeds received from the sales were $44 million. During 2001, EME recorded asset impairment charges of $32 million related to these projects based on the expected sales proceeds. No
gain or loss was recorded from the sale of EME's interests in these projects during 2002.

On
December 21, 2001, EME completed the sale of the Ferrybridge and Fiddler's Ferry coal-fired power plants located in the United Kingdom to two wholly owned
subsidiaries of American Electric Power. In addition, as part of the transactions, the purchasers acquired other assets and assumed specified liabilities associated with the plants. EME acquired the
plants in 1999 from PowerGen UK plc for £1.3 billion. In accordance with SFAS No. 144, the results of Ferrybridge and Fiddler's Ferry have been reflected as discontinued
operations in EME's consolidated financial statements. See Note 7Discontinued Operations. The loss from operations of Ferrybridge and Fiddler's Ferry in 2001 includes
$1.9 billion ($1.1 billion after tax) related to the loss on disposal. Net proceeds from the sales of £643 million were used to repay borrowings outstanding under the
existing debt facility related to the acquisition of the power plants.

During
2001, EME sold its 50% interest in the Nevada Sun-Peak project, 50% interest in the Saguaro project and 25% interest in the Hopewell project for a total gain on sale
of $45 million ($24 million after tax). In addition, EME entered into agreements, subject to obtaining consents from third parties and
other conditions precedent to closing, for the sale of its interests in the Commonwealth Atlantic, Gordonsville, EcoEléctrica, Harbor and James River projects. During 2001, EME recorded
asset impairment charges of $34 million related to the Commonwealth Atlantic, Gordonsville, Harbor and James River projects based on the expected sales proceeds. The sales of EME's interests in
the EcoEléctrica and Gordonsville projects have not closed, and in each case the buyer has terminated the sale agreement.

On
June 25, 2001, EME completed the sale of a 50% interest in the Sunrise project to Texaco Power & Gasification Holdings Inc. Proceeds from the sale were
$84 million.

On
August 16, 2000, EME completed the sale of 30% of its interest in the Kwinana cogeneration plant to SembCorp Energy. EME retains the remaining 70% ownership interest in the
plant. Proceeds from the sale were $12 million. EME recorded a gain on the sale of $8 million ($8 million after tax).

139

---

On
June 30, 2000, EME completed the sale of its 50% interest in the Auburndale project to the existing partner. Proceeds from the sale were $22 million. EME recorded a gain
on the sale of $17 million ($10 million after tax).

Note 7. Discontinued Operations

Lakeland Project

EME's Lakeland project operated a 220 MW combined cycle, natural gas-fired power plant located in the United Kingdom. The assets of the project are
owned by EME's indirect subsidiary, Lakeland Power Ltd., which sold power generated from the plant pursuant to a power sales agreement with Norweb Energi Ltd., a subsidiary of TXU (UK)
Holdings Limited (TXU UK) and an indirect subsidiary of TXU Europe Group plc (TXU Europe).

On
November 19, 2002, TXU UK and TXU Europe, together with a related entity, TXU Europe Energy Trading Limited (TXU Energy), entered into formal administration proceedings in the
United Kingdom (similar to bankruptcy proceedings in the United States). As a result of these actions and their effect upon Norweb Energi Ltd. and EME's contractual arrangements with other
parties, the Lakeland power plant suspended operations.

In
December 2002, the directors of Norweb Energi Ltd. appointed a liquidator to wind up its contractual rights and obligations. On December 4, 2002, Norweb
Energi Ltd. provided a notice of disclaimer of the power sales agreement under Section 178 of the Insolvency Act 1986. The disclaimer effectively terminated the power sales agreement.

On
December 19, 2002, the lenders to the Lakeland project accelerated the debt owing under the bank agreement that governs the project's indebtedness, and on December 20,
2002, the Lakeland project lenders appointed Michael Thomas Seery and Michael Vincent McLoughlin, partners with KPMG LLP as administrative receiver over the assets of Lakeland Power Ltd. The
administrative receiver is appointed to take control of the affairs of Lakeland Power Ltd. and has a wide range of powers (specified in the Insolvency Act), including authorizing the sale of
the power plant. The appointment of the administrative receiver requires the treatment of Lakeland power plant as an asset held for sale under Statement of Financial Accounting Standards
No. 144, "Accounting for the Impairment or Disposal of Long-Lived Assets" (SFAS No. 144). Due to EME's loss of control arising from the appointment of the administrative
receiver, EME no longer consolidates the activities of Lakeland Power Ltd. The consolidated financial statements have been restated to conform to discontinued operations treatment for all
historical periods presented.

The
bank loans of Lakeland Power Ltd. are non-recourse to EME. Furthermore, neither the defaults on these loans nor the institution of administrative proceedings
cross-default to any other indebtedness of EME or its affiliates.

Ferrybridge and Fiddler's Ferry Plants

On December 21, 2001, EME completed the sale of the Ferrybridge and Fiddler's Ferry coal-fired power plants located in the United Kingdom to
two wholly owned subsidiaries of American Electric Power. In addition, as part of the transactions, the purchasers acquired other assets and assumed

140

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specified liabilities associated with the plants. The sale was the result of a competitive bidding process. EME acquired the plants in 1999 from PowerGen UK plc for £1.3 billion.
Net proceeds from the sales of £643 million were used to repay borrowings outstanding under the existing debt facility related to the acquisition of the power plants. The early
repayment of the projects' existing debt facility of £682 million at December 21, 2001 resulted in a loss of $28 million, after tax, attributable to the
write-off of unamortized debt issue costs. In accordance with SFAS No. 144, the results of Ferrybridge and Fiddler's Ferry have been reflected as discontinued operations in EME's
consolidated financial statements. The consolidated financial statements have been restated to conform to discontinued operations treatment for all historical periods presented.

Summarized
results of discontinued operations are as follows:

Years Ended December 31,2002

2001

2000Total operating revenues

$
74

$
600

$
785Income (loss) before income taxes


(75
)

(2,000
)

39Income (loss) before accounting change


(57
)

(1,225
)

42Cumulative effect of change in accounting, net of income expense (benefit) of $2 million and $(2) million for 2001 and 2000, respectively





6


(4
)Income (loss) from operations of discontinued foreign subsidiary


(57
)

(1,219
)

38


The
loss from operations of Lakeland in 2002 includes an impairment charge of $92 million ($77 million after tax) and a provision for bad debts of $1 million, after
tax, arising from the write-down of the Lakeland power plant and related claims under the power sales agreement (an asset group under SFAS No. 144) to their fair market value. The
fair value of the asset group was determined based on discounted cash flows and estimated recovery under related claims under the power sales agreement.

The
loss from operations of Ferrybridge and Fiddler's Ferry in 2002 includes a $7 million loss on settlement of the pension plan related to previous employees of the Ferrybridge
and Fiddler's Ferry project, partially offset from an insurance recovery from claims filed prior to the sale of the power plants. The loss on settlement of the pension plan arose from the election by
former employees in March 2002 to transfer to American Electric Power's new pension plan and the subsequent transfer of pension assets and liabilities in December 2002 in accordance with
the terms of the sale agreement.

Effective
January 1, 2001, EME recorded a $6 million, after tax, increase to income (loss) from discontinued operations, as the cumulative effect of change in accounting
for derivatives. The majority of EME's activities related to the Ferrybridge and Fiddler's Ferry power plants did not qualify for either the normal purchases and sales exception or as cash flow hedges
under SFAS No. 133. EME could not conclude that the timing of generation from these power plants met the probable requirement for a specific forecasted transaction under SFAS No. 133.
Accordingly, the majority of these contracts were recorded at fair value with subsequent changes in fair value recorded through the income statement.

141

---

The
loss from operations of Ferrybridge and Fiddler's Ferry in 2001 includes $1.9 billion ($1.1 billion after tax) related to the loss on disposal. Included in the loss on
disposal is the asset impairment charge of $1.9 billion ($1.2 billion after tax) EME recorded in the third quarter of 2001 to reduce the carrying amount of the power plants to reflect
the estimated fair value less the cost to sell and related currency adjustments.

Effective
January 1, 2000, EME recorded a $4 million, after tax, decrease to income (loss) from discontinued operations, as the cumulative effect of change in accounting
for major maintenance costs. Through December 31, 1999, EME accrued for major maintenance costs incurred during the period at the Ferrybridge and Fiddler's Ferry power plants between overhauls
(referred to as "accrue in advance" accounting method). In March 2000, EME voluntarily decided to change its accounting policy to record major maintenance costs as an expense as incurred.

The
following summarizes the balance sheet information of the discontinued operations:

December 31,2002

2001Cash and cash equivalents

$


$
79Accounts receivabletrade, net of allowance of $2 million in 2002 and $1 million in 2001


1


95Other current assets


3


2Total current assets


4


176Net property, plant and equipment





135Other assets


6


8Total long-term assets


6


143Assets of discontinued operations

$
10

$
319Accounts payable and accrued liabilities

$
3

$
59Interest payable





6Current maturities of long-term obligations





18Total current liabilities


3


83Long-term obligations net of current maturities





62Deferred taxes and tax credits





39Liabilities of discontinued operations

$
3

$
184


Net
operating and capital loss carryforwards total approximately $1.5 billion and $1.4 billion at December 31, 2002 and 2001, respectively. Although there are no
expiration dates related to the use of these loss carryforwards, EME's ability to offset taxable income with these carryforwards is subject to substantial restrictions and limitations under U.K. tax
regulations. Accordingly, no income tax benefits have been recognized and no tax asset recorded for these tax loss carryforwards.

142

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Note 8. Investments in Unconsolidated Affiliates

Investments in unconsolidated affiliates, generally 50% or less owned partnerships and corporations, are accounted for by the equity method. These investments are
primarily in energy and oil and gas projects. The difference between the carrying value of these investments and the underlying equity in
the net assets amounted to $272 million at December 31, 2002. The differences are being amortized over the life of the energy projects or on a unit-of-production
basis over the life of the reserves for the oil and gas projects. The following table presents summarized financial information of the investments in unconsolidated affiliates:

2002

2001Domestic InvestmentsEquity investment

$
767

$
994Loans receivable


183


173Subtotal


950


1,167International InvestmentsEquity investment


695


663Total

$
1,645

$
1,830


EME's
subsidiaries have provided loans or advances related to certain projects. Domestic loans at December 31, 2002 consist of the following: a $123 million, 10% interest
loan, due on demand; a $26 million, 5% interest promissory note, interest payable semiannually, due April 2008; and a $34 million, 12% interest loan, due on demand.

The
undistributed earnings of investments accounted for by the equity method were $275 million in 2002 and $331 million in 2001.

The
following table presents summarized financial information of the investment in the CBK project accounted for by the equity method:

Years Ended December 31,2002

2001

2000Revenues

$
51

$
24

$
Expenses


14


3


Net income

$
37

$
21

$



143

---

December 31,2002

2001Current assets

$
18

$
7Noncurrent assets


451


311Total assets

$
469

$
318Current liabilities

$
29

$
16Noncurrent liabilities


324


242Equity


116


60Total liabilities and equity

$
469

$
318


The
following table presents summarized financial information of the remaining investments in unconsolidated affiliates accounted for by the equity method:

Years Ended December 31,2002

2001

2000Revenues

$
2,949

$
3,123

$
2,854Expenses


2,374


2,490


2,245Net income

$
575

$
633

$
609


December 31,2002

2001Current assets

$
1,847

$
2,139Noncurrent assets


6,861


7,116Total assets

$
8,708

$
9,255Current liabilities

$
2,820

$
1,884Noncurrent liabilities


4,280


5,364Equity


1,608


2,007Total liabilities and equity

$
8,708

$
9,255


The
majority of noncurrent liabilities are comprised of project financing arrangements that are non-recourse to EME.

144

---

The
following table presents, as of December 31, 2002, the investments in unconsolidated affiliates accounted for by the equity method that represent at least five percent (5%) of
MEHC's income before tax or in which MEHC has an investment balance greater than $50 million.

|Unconsolidated Affiliates |  | Location                         |  | Investment |  | Ownership
Interest |   | Operating Status                                     
|------------------------- |  | -------------------------------- |  | ---------- |  | ------------------ | - | -----------------------------------------------------
|Paiton                    |  | East Java, Indonesia             |  | 514        |  | 40                 | % | Operating coal-fired facility                        
|EcoEléctrica              |  | Peñuelas, Puerto Rico            |  | 269        |  | 50                 | % | Operating liquefied natural gas cogeneration facility
|Sunrise                   |  | Fellows, CA                      |  | 160        |  | 50                 | % | Operating gas-fired facility                         
|Watson                    |  | Carson, CA                       |  | 97         |  | 49                 | % | Operating cogeneration facility                      
|Brooklyn Navy Yard        |  | Brooklyn, NY                     |  | 92         |  | 50                 | % | Operating cogeneration facility                      
|ISAB                      |  | Sicily, Italy                    |  | 72         |  | 49                 | % | Operating gasification facility                      
|Sycamore                  |  | Bakersfield, CA                  |  | 61         |  | 50                 | % | Operating cogeneration facility                      
|Midway-Sunset             |  | Fellows, CA                      |  | 51         |  | 50                 | % | Operating cogeneration facility                      
|March Point               |  | Anacortes, WA                    |  | 49         |  | 50                 | % | Operating cogeneration facility                      
|Kern River                |  | Bakersfield, CA                  |  | 46         |  | 50                 | % | Operating cogeneration facility                      
|IVPC4                     |  | Italy                            |  | 40         |  | 50                 | % | Operating wind facilities                            
|Gordonsville              |  | Gordonsville, VA                 |  | 31         |  | 50                 | % | Operating cogeneration facility                      
|CBK                       |  | Ratchaburi Province, Philippines |  | 30         |  | 50                 | % | Operating hydro facility                             
|Four Star                 |  | Houston, TX                      |  | 30         |  | 37                 | % | Operating oil and gas properties                     
|Tri Energy                |  | Laguna Province, Thailand        |  | 18         |  | 25                 | % | Operating gas-fired facility                         
|Sargent Canyon            |  | San Ardo, CA                     |  | 17         |  | 50                 | % | Operating cogeneration facility                      
|Salinas River             |  | San Ardo, CA                     |  | 17         |  | 50                 | % | Operating cogeneration facility                      
|Coalinga                  |  | Coalinga, CA                     |  | 16         |  | 50                 | % | Operating cogeneration facility                      
|Mid-Set                   |  | Fellows, CA                      |  | 9          |  | 50                 | % | Operating cogeneration facility                      
|Derwent                   |  | Derby, England                   |  | 5          |  | 33                 | % | Operating cogeneration facility                      

During
December 2001, EME purchased additional shares in its oil and gas project (Four Star Oil & Gas Company) for $7.4 million, increasing its interest from 35.84%
to 37.20%.

Disclosure Requirements under FIN 46



EME believes it is reasonably possible that the following partnership interests in energy projects are variable interest entities under FIN 46 due to equity
capitalization which is about 10% or less of each entity's total assets:

American Bituminous Power Partners, L.P.EME owns a 50% partnership interest in American Bituminous Power Partners, L.P.,
which owns an 80 MW waste-coal power plant located in Grant Town, West Virginia. American Bituminous Partners sells electricity to Monongahela Power Company under a power purchase
agreement that expires in 2023. The maximum exposure to loss from EME's interest in this entity is $2 million at December 31, 2002.

145

---



Brooklyn Navy Yard Cogeneration Partners L.P.EME owns a 50% partnership interest in Brooklyn Navy
Yard Cogeneration Partners L.P., which owns a 286 MW natural gas and oil-fired cogeneration facility located near Brooklyn, New York. Brooklyn Navy Yard sells electricity and steam to
Consolidated Edison Company of New York, Inc. under a power purchase agreement that expires in 2039. The maximum exposure to loss from EME's interest in this entity is $92 million at
December 31, 2002.

Derwent Cogeneration LimitedEME owns a 33% interest in Derwent Cogeneration Limited, which owns a 214 MW
gas-fired cogeneration plant in Derby, England. Derwent sells electricity to Southern Electric plc under a power purchase agreement that expires in 2010 and sells steam to Courtaulds
Chemicals (Holdings) Limited under a steam supply contract that also expires in 2010. The maximum exposure to loss from EME's interest in this entity is $6 million at December 31, 2002.

EcoEléctrica L.P.EME owns a 50% partnership interest in EcoEléctrica L.P., which owns a 540 MW
power plant located Peñuelas, Puerto Rico. EcoEléctrica sells electricity to Puerto Rico Electric Power Authority under a power purchase agreement that expires in 2018
and sells water to Puerto Rico Water & Sewer Authority under a water supply agreement that also expires in 2018. The maximum exposure to loss from EME's interest in this entity is
$307 million at December 31, 2002.

ISAB Energy S.r.l.EME owns a 49% interest in ISAB Energy S.r.l., which owns a 518 MW integrated gasification combined cycle
power plant in Sicily, Italy, which EME refers to as the ISAB project. ISAB sells electricity to Gestore Rete Transmissione Nazionale, Italy's state transmission company, under a power purchase
agreement that expires in 2020. The ISAB project is located at an oil refinery owned by ERG Petroli SpA. The maximum exposure to loss from EME's interest in this entity is $72 million at
December 31, 2002.

IVPC 4 S.r.l.In 2000, EME purchased Edison Mission Wind Power Italy B.V., which owns a 50% interest in 13 power projects that
are in operation in Italy by UPC International Partnership CV II, which EME collectively refers to as the Italian Wind project. The projects use wind to generate electricity from turbines, which is
sold under fixed-price, long-term tariffs to Gestore Rete Transmissione Nazionale. The maximum exposure to loss from EME's interest in this entity is $40 million at
December 31, 2002.

PT Paiton EnergyEME owns a 40% interest in PT Paiton Energy (Paiton Energy), which owns a 1,230 MW coal-fired
power plant in operation in East Java, Indonesia. Paiton Energy sells electricity to PT PLN, the state-owned electric utility company, under a power purchase agreement. The maximum exposure to loss
from EME's interest in this entity is $541 million at December 31, 2002.

TM StarEME owns a 50% interest in TM Star which was formed for the limited purpose to sell natural gas to March Point
Cogeneration Company, an affiliate through common ownership, under a fuel supply agreement. TM Star has entered into fuel purchase contracts with unrelated third parties to meet a portion of the
obligations under the fuel supply agreement. EME has guaranteed 50% of the obligation under the fuel supply agreement to March Point Cogeneration Company. The maximum loss is subject to changes in
natural gas prices. Accordingly, the maximum exposure to loss cannot be determined.

146

---



EME also believes it is reasonably possible that the following interests in non-utility generators purchased as part of the Citizens Power acquisition
in 2000 are variable interest entities under FIN 46:

CL Power Sales One, LLCEME owns a 25% interest in CL Power Sales One, LLC (CL One). CL One was formed for a limited purpose
to sell capacity under a contract to Central Maine Power with a capacity purchase contract from an unrelated third-party generator. The purchases and sales of capacity are substantially on the same
terms and are non-recourse to EME and its subsidiaries. EME does not have exposure to loss from this entity at December 31, 2002.

CL Power Sales Two, LLCEME owns a 25% interest in CL Power Sales Two, LLC (CL Two). CL Two was formed with the limited
purpose to sell power to New York State Electric & Gas Company (NYSEG) under a power sales agreement through August 2007. CL Two acquires the power through its affiliate CL Power Sale
Seven, LLC. The maximum exposure to loss from EME's interest in this entity is $1 million at December 31, 2002.

CL Power Sales Seven, LLCEME owns a 25% interest in CL Power Sales Seven, LLC (CL Seven). CL Seven was formed with the
limited purpose to sell power to CL Two under a power sales agreement through August 2007. CL Seven acquires the power from Exelon Generation Co., LLC. The maximum exposure to loss from EME's
interest in this entity is less than $1 million at December 31, 2002.

CL Power Sales Eight, LLCEME owns a 25% interest in CL Power Sales Eight, LLC (CL Eight). CL Eight was formed for the limited
purpose to sell power to Central Maine Power under a power sales agreement through December 2016. CL Eight acquires the power through Edison Mission Marketing & Trading, which in turn
acquires its power from NRG Power Marketing Inc. The maximum exposure to loss from EME's interest in this entity is $5 million at December 31, 2002.

CL Power Sales Nine, LLCEME owns a 25% interest in CL Power Sales Nine, LLC (CL Nine). CL Nine was formed with the limited
purpose to sell power to Jersey Central Power & Light Company, doing business as GPU Energy through June 2004. CL Nine acquires its power through Edison Mission Marketing &
Trading, which in turn acquires its power from Exelon Generation Co., LLC. The maximum exposure to loss from EME's interest in this entity is less than $1 million as of December 31,
2002.

CL Power Sales Ten, LLCEME owns a 25% interest in CL Power Sales Ten, LLC (CL Ten). CL Ten was formed with the limited
purpose to sell power to New York State Electric & Gas Company under a power sales agreement through April 2008. CL Ten acquires its power from PG&E Energy TradingPower L.P.
The maximum exposure to loss from EME's interest in this entity is less than $1 million as of December 31, 2002.



Under FIN 46, an enterprise that will (1) absorb a majority of a variable interest entity's expected losses (if they occur), (2) receive a majority
of a variable interest entity's expected residual returns (if they occur), or (3) both of the above, must consolidate the variable interest entity. The enterprise that consolidates the variable
interest entity is called the primary beneficiary. EME is in the process of

147

---

reviewing the entities listed above that have a reasonable possibility of being variable interest entities to determine if it is the primary beneficiary.



EME has concluded that it is the primary beneficiary of Brooklyn Navy Yard Cogeneration Partners L.P. since it is at risk with respect to a majority of its losses
and is entitled to receive a majority of its residual returns. Accordingly, EME will consolidate Brooklyn Navy Yard Cogeneration Partners L.P. effective July 1, 2003. In accordance with the
transition provisions of FIN 46, the consolidation of Brooklyn Navy Yard Cogeneration Partners L.P. will be based on the historical cost of the assets,
liabilities and non-controlling interest which would have been carried by EME effective when EME became the primary beneficiary. This means that EME will consolidate the assets and
liabilities of Brooklyn Navy Yard Cogeneration Partners L.P. using the June 30, 2003 balance sheet and eliminate intercompany balances. EME expects the consolidation of this entity to increase
total assets by approximately $365 million and total liabilities by approximately $445 million. Furthermore, EME expects to record a loss of approximately $80 million as a
cumulative change of accounting as a result of consolidating this variable interest entity. This loss is primarily due to cumulative losses allocated to the other 50% partner in excess of equity
contributions recorded.

Note 9. Property, Plant and Equipment

Property, plant and equipment consist of the following:

December 31,2002

2001Buildings, plant and equipment

$
3,451

$
3,741Emission allowances


1,305


1,305Civil works


2,776


1,342Construction in progress


77


130Capitalized leased equipment


41


1887,650


6,706Less accumulated depreciation and amortization


888


603Net property, plant and equipment

$
6,762

$
6,103


In
connection with the Loy Yang B, First Hydro, Doga and Iberian Hy-Power plant financings, lenders have taken a security interest in the respective plant assets.

Note 10. Financial Instruments

Management Plans for Refinancing $911 Million Debt Maturity at Edison Mission Midwest Holdings

MEHC's consolidated debt at December 31, 2002 was $7.2 billion, including $911 million of debt maturing in December 2003 which is owed
by EME's largest subsidiary, Edison Mission Midwest Holdings. Edison Mission Midwest Holdings is not expected to have sufficient cash to repay the $911 million debt due in December 2003.
Edison Mission Midwest Holdings plans to extend or

148

---

refinance the $911 million debt obligation prior to its expiration in December 2003. At December 31, 2002, Edison Mission Midwest Holdings had cash and cash equivalents of
$320 million and $50 million deposited into a restricted cash account. Management believes that Edison Mission Midwest Holdings will generate positive cash flow from operations during
2003 which, in combination with its existing cash position, will contribute positively to discussions with lenders to extend or refinance the $911 million debt obligation. Completion of this
extension or refinancing is subject to a number of uncertainties, including the ability of the Illinois Plants to generate funds during 2003 and the availability of new credit from financial
institutions on acceptable terms in light of industry conditions. Accordingly, there is no assurance that Edison Mission Midwest Holdings will be able to extend or refinance this debt when it becomes
due or that the terms will not be substantially different from those under the current credit facility.

Short-Term Obligations

December 31,2002

2001Citibank, N.A. Credit Agreement

$


$
80Other short-term obligations


78


88Total

$
78

$
168Weighted-average interest rate


6.13
%

7.3
%


At
December 31, 2002, EME had available $355 million of borrowing capacity and approximately $132 million in letters of credit issued under a $487 million
revolving credit facility that expires in September 2003 (Tranche A) and September 2004 (Tranche B). At December 31, 2002, other short-term borrowings consisted
of several promissory notes due January through March 2003, which relates to the Contact Energy project.

At
December 31, 2001, EME had available $554 million of borrowing capacity and approximately $116 million in letters of credit issued under a $750 million
revolving credit facility that expired in September 2002 (Tranche A, consisting of the $80 million outstanding borrowing) and September 2004 (Tranche B). At December 31,
2001, other short-term borrowings consisted of a 55 million Australian dollar construction facility for the Valley Power project due November 2002 of which
US$24 million was outstanding and a floating rate note due March 2002, which relates to the Contact Energy project.

EME's
recourse debt to recourse capital ratio:

Financial Ratio

Covenant

Actual at December 31, 2002

DescriptionRecourse Debt to Recourse Capital Ratio

Less than or equal to 67.5%

62.2%

Ratio of (a) senior recourse debt to (b) sum of (i) shareholder's equity per EME's balance sheet adjusted by comprehensive income after December 31, 1999, plus (ii) senior recourse
debt


149

---

At
December 31, 2002, EME met the above financial covenant. In addition, EME met the interest coverage ratio pursuant to the EME corporate facilities at December 31, 2002.
The interest coverage ratio is based on cash received by EME, including tax-allocation payments, cash disbursements and interest paid.

Long-Term Obligations

Long-term obligations include both corporate debt and non-recourse project debt, whereby lenders rely on specific project assets to repay
such obligations. MEHC used the common stock of EME as the security for MEHC's corporate debt obligations. The senior secured notes and the credit agreement are non-recourse to Edison
International and EME and its subsidiaries and, accordingly, none of Edison International, EME or EME's subsidiaries has any obligation under the senior secured notes or the credit agreement. At
December 31, 2002, recourse debt to EME totaled $1.9 billion and non-recourse project debt totaled $4.1 billion. Long-term obligations consist of the
following:

December 31,2002

2001Corporate debt (with recourse to MEHC)Mission Energy Holding Company (parent only)Senior Notes, net due 2008 (13.5%)

$
785

$
783Credit Agreement due 2004 (LIBOR+7.50%) (9.29% at 12/31/02)


98


97Credit Agreement due 2006 (LIBOR+7.50%) (9.29% at 12/31/02)


279


278Corporate debt (with recourse to EME)Edison Mission Energy (parent only)Senior Notes, netdue 2002 (8.125%)





100due 2008 (10.0%)


400


400due 2009 (7.73%)


597


597due 2011 (9.875%)


600


600Pounds Sterling Coal and Capex Facility due 2004 (Sterling LIBOR+2.25%+0.0101% - 0.0102%) (6.27% at 12/31/02)


181


252Long-Term ObligationsAffiliate


78


78Non-recourse (unless otherwise noted)Edison Mission Energy Funding Corp.Series A Notes, net due 1997-2003 (6.77%)


47


91Series B Bonds, net due 2004-2008 (7.33%)


189


189EME CP Holdings Co.Note Purchase Agreement due 2015 (7.31%)


84


Edison Mission Midwest Holdings Co.Tranche A due 2003 (LIBOR+2.25%) (3.66% at 12/31/02)


911


911Tranche B due 2004 (LIBOR+2.00%) (3.41% at 12/31/02)


808


808


150

---

Contact Energy projectMedium Term NoteUS$75 MM due 2013 (6.94% at 12/31/02)


75


79Medium Term NoteUS$25 MM due 2018 (7.13% at 12/31/02)


25


26Floating Rate NoteUS$50 MM due 2007 (2.21% at 12/31/02)


50


50Floating Rate NoteA$120 MM due 2007 (5.78% at 12/31/02)


67


62Medium Term NoteNZ$70 MM due 2003 (7.25% at 12/31/02)


37


29Term Loan FacilityNZ$50 MM due 2004 (6.43% at 12/31/02)


26


21CSFB Revolving Credit Facility due 2005 (BKBM+1.75%) (7.71% at 12/31/02)


150


118Doga projectFinance Agreement between Doga and OPIC due 2010 (U.S. Treasury Note+3.75%) (11.2% at 12/31/02)


70


78NCM Credit Agreement due 2010 (U.S. LIBOR+1.25%) (3.28% at 12/31/02)


26


29First Hydro plantsFirst Hydro Finance plc £400 MM Guaranteed Secured Bonds due 2021 (9%)


644


582£18 MM Credit Agreement due 2003 (Sterling LIBOR+0.55%+0.0103%) (4.74% at 12/31/02)


29


26Iberian Hy-Power plantsEuro dollar Project Finance Credit Facility due 2012 (EURIBOR+0.75%) (3.64% at 12/31/02)


43


49Euro dollar Subordinated Loan due 2003 (9.408%)


22


7Euro dollar Compagnie Générale Des Eaux due 2003 (non-interest bearing)recourse


30


23Euro dollar Banco Vitalicio due 2006 (6.17% at 12/31/02)


2


Kwinana plantAustralian dollar Syndicated Project Facility Agreement due 2012 (BBR+1.3%) (6.37% at 12/31/02)


47


44Loy Yang B plantAustralian dollar Amortising Term Facility due 2017 (BBR+0.6% to 1.1%) (5.532% at 12/31/02)


382


354Australian dollar Interest Only Term Facility due 2012 (BBR+0.6% to 0.85%) (5.532% at 12/31/02)


276


251Australian dollar Working Capital Facility due 2017 (BBR+0.6% to 1.1%) (5.532% at 12/31/02)


6


5


151

---

Valley Power plantAustralian dollar Amortising Facility due 2011 (BBR+1.55%) (6.438% at 12/31/02)


39


Australian dollar Bullet Facility due 2007 (BBR+1.55%) (6.438% at 12/31/02)


21


Subtotal

$
7,124

$
7,017Current maturities of long-term obligations


(1,090
)

(172
)Total

$
6,034

$
6,845


Bond Financing of First Hydro

The ability of EME's subsidiary to make payments of interest on the First Hydro bonds is dependent on revenues generated by the First Hydro plant, which depend on
market conditions for electric energy and ancillary services. These market conditions are beyond EME's control. The financial covenants included in the bond financing of First Hydro require EME's
subsidiary to maintain a minimum interest coverage ratio for each trailing 12-month period as of June 30 and December 31 of each year. EME's subsidiary was in compliance with
this ratio for the 12 months ended December 31, 2002. Compliance with this ratio depends on market conditions for electric energy and ancillary services. There is no assurance that these
requirements will be met and, if not met, will be waived by the holders of First Hydro's bonds. The bond financing documents stipulate that a breach of a financial covenant constitutes an immediate
event of default and, if the event of default is not waived or cured, the holders of the First Hydro bonds are entitled to enforce their security over First Hydro's assets, including its power plants.

On
March 14, 2003, First Hydro Finance plc received a letter from the trustee for the First Hydro bonds, requesting that First Hydro Finance engage in a process to determine
whether an early redemption option in favor of the bondholders has been triggered under the terms of the First Hydro bonds. This letter states that, given requests made of the trustee by a group of
First Hydro bondholders, the trustee needs to satisfy itself whether the termination of the pool system in the United Kingdom (replaced with the new electricity trading arrangements, referred to as
NETA), was materially prejudicial to the interests of the bondholders. If this were the case, it could provide the First Hydro bondholders with an early redemption option. In this regard, on
August 29, 2000, First Hydro Finance notified the trustee that the enactment of the Utilities Act of 2000, which laid the foundation for NETA, would result, after its implementation, in a so
called restructuring event under the terms of the First Hydro bonds. However, First Hydro Finance did not believe then, nor does it believe now, that this event was materially prejudicial to the First
Hydro bondholders. Since NETA implementation, First Hydro Finance has continued to meet all of its debt service obligations and financial covenants under the bond documentation, including the required
interest coverage ratio. Until its receipt of the trustee's March 14, 2003 letter, First Hydro Finance had not received a response from the trustee to its August 29, 2000 notice. First
Hydro Finance will vigorously dispute any attempt to have the early redemption option deemed applicable due to NETA implementation.

152

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Neither
the August 2000 notice provided to the trustee, nor the March 14, 2003 letter from the trustee constitutes an event of default under the terms of the First Hydro
bonds; and there is no recourse to EME for the obligations of First Hydro Finance in respect of the First Hydro bonds. However, if the bondholders were entitled to an early redemption option, First
Hydro Finance would be obligated to purchase all First Hydro bonds put to it by bondholders at par plus an early redemption premium. If all bondholders opted for the early redemption option, it is
unlikely that First Hydro Finance would have sufficient financial resources to so purchase the bonds. There is no assurance that First Hydro Finance would be able to obtain additional financing to
fund the purchase of the First Hydro bonds. Therefore, an exercise of the early redemption by the bondholders could lead to administration proceedings as to First Hydro Finance in the United Kingdom,
which is similar to Chapter 11 bankruptcy proceedings in the United States. If these events were to occur, it would have a material adverse effect upon First Hydro Finance and could have a material
adverse effect upon EME.

Long-term ObligationsAffiliates

During 1997, EME declared a dividend of $78 million to The Mission Group which was recorded as a note payable due in June 2007 with interest at
LIBOR plus 0.275% (1.93% at December 31, 2002). The note was subsequently exchanged for two notes with the same terms and conditions and assigned to other subsidiaries of Edison International.

Financing of the Ferrybridge and Fiddler's Ferry Plants

As part of the financing of the Ferrybridge and Fiddler's Ferry plants, EME had entered into a 359 million pounds sterling Coal and Capex Facility due
January 2004 and July 2004, respectively. Following the completion of the sale of the power plants, this facility was cancelled. During 2002, EME made total payments of
$86 million from settlement of assets and liabilities of EME's discontinued operations. EME plans to repay the borrowings outstanding under the Coal and Capex Facility from cash flows generated
from EME's foreign subsidiaries at its maturity in 2004.

Annual Maturities on Long-Term Debt

Annual maturities on long-term debt at December 31, 2002, for the next five years are summarized as follows:
2003$1,090 million; 2004$1,209 million; 2005$239 million; 2006$374 million; and 2007$307 million.

Restricted Cash

Several cash balances are restricted primarily to pay amounts required for debt payments and letter of credit expenses. The total restricted cash included in
MEHC's consolidated balance sheet under the caption "Restricted cash and other assets" was $406 million at December 31, 2002 and $574 million at December 31, 2001. Debt
service reserves classified in Restricted cash and other assets were $159 million at December 31, 2002 and $43 million at December 31, 2001.

Collateral
reserves classified in Restricted cash and other assets were $45 million and $82 million at December 31, 2002 and 2001, respectively. At
December 31, 2001, the EME Turbine Trust agreement entered into on December 4, 2000 required collateral reserves of $74 million.

153

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MEHC
is organized as a legal entity separate and apart from EME and its other subsidiaries. Assets of EME and its subsidiaries may not be available to satisfy MEHC's obligations.

Fair Values of Non-Derivative Financial Instruments

The following table summarizes the fair values for outstanding non-derivative financial instruments:

December 31,2002

2001InstrumentsNon-derivatives:Long-term receivables

$
6

$
265Long-term obligations


4,480


6,991Preferred securities subject to mandatory redemption


246


258


In
assessing the fair value of MEHC's financial instruments, MEHC uses a variety of methods and assumptions that are based on market conditions and risk existing at each balance sheet
date. Quoted market prices for the same or similar instruments are used for long-term receivables, interest rate derivatives, long-term obligations and preferred securities.
Foreign currency forward exchange agreements and cross currency interest rate swaps are estimated by obtaining quotes from the bank. The carrying amounts reported for cash equivalents, commercial
paper facilities and other short-term debt approximate fair value due to their short maturities.

Note 11. Risk Management and Derivative Financial Instruments

EME's risk management policy allows for the use of derivative financial instruments to limit financial exposure on EME's investments and to manage exposure from
fluctuations in electricity and fuel prices, emission and transmission rights, interest rates and foreign currency exchange rates for both trading and non-trading purposes.

Commodity Price Risk Management

EME's merchant power plants and energy trading activities expose EME to commodity price risks. 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 time. Procedures exist which allow for monitoring of all commitments
and positions with regular reviews by a risk management committee. 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 commodity risk, compare risk on a consistent basis and identify the drivers of the risk. Value at risk measures the possible 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 the use of stress testing and worst-case scenario analysis, as well as stop loss limits and counterparty credit exposure limits. Despite this, there can be no assurance that
all risks have been accurately identified, measured and/or mitigated.

154

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Interest Rate Risk Management

MEHC has mitigated the risk of interest rate fluctuations associated with the $385 million term loan due 2006 by arranging for variable rate financing with
interest rate swaps. Swaps covering interest accrued from January 2, 2002 to January 2, 2003 expired on January 2, 2003. Subsequently, MEHC entered into swaps that cover interest
accrued from January 2, 2003 to July 2, 2004. Under MEHC's variable to fixed swap agreements, MEHC will pay counterparties interest at a weighted average fixed rate of 3.04% and 2.76% at
December 31, 2002 and 2001, respectively. Counterparties will pay MEHC interest at a weighted average variable rate based on LIBOR of 1.63% and 1.98% at December 31, 2002 and 2001,
respectively.

Interest
rate changes affect the cost of capital needed to operate EME's projects and the lease costs under the Collins Station lease. EME has mitigated the risk of interest rate
fluctuations by arranging for fixed rate financing or variable rate financing with interest rate swaps, interest rate options or other hedging mechanisms for a number of EME's project financings. EME
has entered into several interest rate swap agreements under which the maturity date of the swaps occurs prior to the final maturity of the underlying debt.

Under
EME's fixed to variable swap agreements, the fixed interest rate payments are at a weighted average rate of 6.91% and 5.97% at December 31, 2002 and 2001, respectively.
Variable rate payments under EME's corporate agreements were based on six-month LIBOR capped at 9% at December 31, 2001. Variable rate payments pertaining to EME's foreign
subsidiary agreements are based on an equivalent interest rate benchmark to LIBOR. The weighted average rate applicable to these agreements was 6.18% and 2.80% at December 31, 2002 and 2001,
respectively. Under the variable to
fixed swap agreements, EME will pay counterparties interest at a weighted average fixed rate of 6.96% and 7.12% at December 31, 2002 and 2001, respectively. Counterparties will pay EME interest
at a weighted average variable rate of 5.10% and 4.76% at December 31, 2002 and 2001, respectively. The weighted average variable interest rates are based on LIBOR or equivalent interest rate
benchmarks for foreign denominated interest rate swap agreements. Under EME's interest rate options, the weighted average strike interest rate was 6.90% and 6.76% at December 31, 2002 and 2001,
respectively.

Credit Risk

In conducting EME's price risk management and trading activities, EME contracts with a number of utilities, energy companies and financial institutions. Due to
factors beyond EME's control, market liquidity has decreased significantly since the beginning of 2002, and a number of formerly significant trading parties have completely withdrawn from the market
or substantially reduced their trading activities. The reduction in the credit quality of traditional trading parties increases EME's credit risk. In addition, the decrease in market liquidity may
require EME to rely more heavily on wholesale electricity sales to wholesale customer markets, which may also increase EME's credit risk. While various industry groups and regulatory agencies have
taken steps to address market liquidity, transparency and credit issues, there is no assurance as to when, or how effectively, such efforts will restore market confidence. In the event a counterparty
were to default on its trade obligation, EME would be exposed to the risk of possible loss associated with reselling the contracted product at a lower price if the non-performing
counterparty were unable to pay the resulting liquidated damages owed to

155

---

EME. Further, EME would be exposed to the risk of non-payment of accounts receivable accrued for products delivered prior to the time such counterparty defaulted.

To
manage credit risk, EME looks at the risk of a potential default by its counterparties. Credit risk is measured by the loss EME would record if its counterparties failed to perform
pursuant to the terms of their contractual obligations. EME has established controls to determine and monitor the creditworthiness of counterparties and uses master netting agreements whenever
possible to mitigate its exposure to counterparty risk. EME may require counterparties to pledge collateral when deemed necessary. EME tries to manage the credit in its portfolio based on credit
ratings using published ratings of counterparties and other publicly disclosed information, such as financial statements, regulatory filings, and press releases, to guide it in the process of setting
credit levels, risk limits and contractual arrangements including master netting agreements. The credit quality of EME's counterparties is reviewed regularly by EME's risk management committee. In
addition to continuously monitoring its credit exposure to its counterparties, EME also takes appropriate steps to limit or lower credit exposure. Despite this, there can be no assurance that EME's
actions to mitigate risk will be wholly successful or that collateral pledged will be adequate.

Exelon
Generation accounted for 41%, 43% and 49% of EME's consolidated operating revenues in 2002, 2001 and 2000, respectively. EME expects the percentage to be less in 2003 because a
smaller number of plants will be subject to contracts with Exelon Generation. Any failure of Exelon Generation to make payments to Midwest Generation under the power purchase agreements could
result in a shortfall of cash available for Midwest Generation to meet its obligations. A default by Midwest Generation in meeting its obligations could in turn have a material adverse effect on EME.

EME's
contracted power plants and the plants owned by unconsolidated affiliates in which EME owns an interest, sell power under long-term power purchase agreements.
Generally, each plant sells its output to one counterparty. Accordingly, a default by a counterparty under a long-term power purchase agreement, including a default as a result of a
bankruptcy, would likely have a material adverse affect on the operations of such power plant. During 2002, the counterparty to the Lakeland project power purchase agreement filed a notice of
disclaimer of its power purchase agreement with the project ultimately resulting in an impairment of $77 million, after tax. See Note 7Discontinued Operations. The Big 4
projects sell power to Southern California Edison, which is currently non-investment grade. Southern California Edison was adversely affected by the California energy crisis and during
that time defaulted on its long-term power purchase agreements with each of the Big 4 projects. It has since repaid the past due amounts, with interest. If Southern California Edison again
defaults on its long-term power purchase agreements with each of the Big 4 projects, it would have a material adverse effect on the related project.

Foreign Exchange Rate Risk

Fluctuations in foreign currency exchange rates can affect, on a U.S. dollar equivalent basis, the amount of EME's equity contributions to, and distributions
from, its international projects. 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 U.S. dollars or other indices reasonably expected to correlate with foreign exchange movements. In addition, EME has used
statistical forecasting techniques to help assess

156

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foreign exchange risk and the probabilities of various outcomes. EME cannot provide assurances, however, that fluctuations in exchange rates will be fully offset by hedges or that currency movements
and the relationship between certain macroeconomic variables will behave in a manner that is consistent with historical or forecasted relationships.

At
December 31, 2002 and 2001, EME had outstanding foreign currency forward exchange contracts entered into to hedge identifiable foreign currency commitments associated with
transactions in the ordinary course of business and cross currency interest rate swap contracts entered into in the ordinary course of business. The periods of the contracts correspond to the periods
of the hedged transactions.

Non-Trading Derivative Financial Instruments

The following table summarizes the fair values for outstanding derivative financial instruments used for purposes other than trading by risk category and
instrument type:

December 31,2002

2001Derivatives:Interest rate:Interest rate swap/cap agreements

(56
)
(37
)Interest rate options

(2
)
(1
)Commodity price:Electricity

(100
)
(74
)Natural gas



(8
)Foreign currency forward exchange agreements



(1
)Cross currency interest rate swaps

(2
)
28


In
assessing the fair value of EME's non-trading derivative financial instruments, EME uses a variety of methods and assumptions that are based on market conditions and risk
existing at each balance sheet date. The fair value of the commodity price contracts considers quoted market prices, time value, volatility of the underlying commodities and other factors.

The
fair value of the electricity rate swap agreements (included under commodity price-swaps) entered into by the Loy Yang B plant and the First Hydro plant has been estimated by
discounting the future cash flows on the difference between the average aggregate contract price per MW and a forecasted market price per MW, multiplied by the amount of MW sales remaining under
contract.

Energy Trading

On September 1, 2000, EME acquired the trading operations of Citizens Power LLC. As a result of this acquisition, EME has expanded its operations beyond
the traditional marketing of its electric power to include trading of electricity and fuels. In conducting EME's trading activities, EME seeks to generate profit from price volatility of electricity
and fuels by buying and selling these commodities in wholesale markets. EME generally balances forward sales and purchases contracts and manages its exposure through a value at risk analysis as
described further below. EME also conducts price risk

157

---

management activities with third parties not related to EME's power plants or investments in energy projects, including the restructuring of power sales and power supply agreements.

The
fair value of the commodity financial instruments related to energy trading activities as of December 31, 2002 and 2001, are set forth below:

December 31, 2002

December 31, 2001Assets

Liabilities

Assets

LiabilitiesElectricity

$
109

$
15

$
7

$
5Other





2


2


2Total

$
109

$
17

$
9

$
7


Quoted
market prices are used to determine the fair value of the financial instruments related to trading activities.

EME's
net gains (losses) arising from energy trading activities recognized on a fair value basis are as follows:

Years Ended December 31,2002

2001

2000Operating RevenuesUnrealized gains (losses), net

$
10

$
(12
)
$
12Realized gains, net


32


22


50Total

$
42

$
10

$
62


Note 12. Preferred Securities

Company-Obligated Mandatorily Redeemable Securities of Partnership Holding Solely Parent Debentures.In November 1994,
Mission Capital, L.P., a limited partnership of which EME is the sole general partner, issued 3.5 million 9.875% Cumulative Monthly Income Preferred Securities, Series A at a price of
$25 per security and invested the proceeds in 9.875% junior subordinated deferrable interest debentures due 2024 which were issued by EME in November 1994. The Series A securities are
redeemable at the option of Mission Capital, in whole or in part, with mandatory redemption in 2024 at a redemption price of $25 per security, plus accrued and unpaid distributions. No securities have
been redeemed as of December 31, 2002. During August 1995, Mission Capital issued 2.5 million 8.5% Cumulative Monthly Income Preferred Securities, Series B at a price of
$25 per security and invested the proceeds in 8.5% junior subordinated deferrable interest debentures due 2025 which were issued by EME in August 1995.
The Series B securities are redeemable at the option of Mission Capital, in whole or in part, with mandatory redemption in 2025 at a redemption price of $25 per security, plus accrued and
unpaid distributions. No securities have been redeemed as of December 31, 2002. EME issued a guarantee in favor of the holders of the preferred securities, which guarantees the payments of
distributions declared on the preferred securities, payments upon a liquidation of Mission Capital and payments on redemption with respect to any preferred securities called for redemption by Mission
Capital.

158

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EME has the right from time to time to extend the interest payment period on its junior subordinated deferrable interest debentures to a period not exceeding 60
consecutive months, at the end of which all accrued and unpaid interest will be paid in full. If EME does not make interest payments on its junior subordinated debentures, it is expected that Mission
Capital will not declare or pay distributions on its cumulative monthly income preferred securities. During an extension period, EME may not do any of the following:



Furthermore,
so long as any preferred securities remain outstanding, EME will not be able to declare or pay, directly or indirectly, any dividend on, or purchase, acquire or make a
distribution or liquidation payment with respect to, any of EME's common stock if at such time (i) EME shall be in default with respect to EME's payment obligations under the guarantee,
(ii) there shall have occurred any event of default under the subordinated indenture, or (iii) EME shall have given notice of its selection of the extended interest payment period
described above and such period, or any extension thereof, shall be continuing.

Subject to Mandatory Redemption.During June 1999, Edison Mission Energy Taupo Limited, a New Zealand corporation, an
indirect, wholly owned affiliate of EME, issued $84 million of Class A Redeemable Preferred Shares (16,000 shares at a price of 10,000 New Zealand dollars per share). The dividend rate
ranged from 6.19% to 6.86%. The shares were redeemable in June 2003 at 10,000 New Zealand dollars per share. From July through November 1999, Edison Mission Energy Taupo issued
$125 million of retail redeemable preferred shares (240 million shares at a price of one New Zealand dollar per share). The dividend rate ranged from 5.00% to 6.37%. The shares were
redeemable at one New Zealand dollar per share in June 2001 (64 million), June 2002 (43 million), and June 2003 (133 million).

On
July 2, 2001, the Class A Redeemable Preferred Shares were redeemed at 10,000 New Zealand dollars per share and the retail redeemable preferred shares were redeemed at
one New Zealand dollar per share from the existing holders. Funding for the redemption of the shares was provided by a NZ$400 million credit facility scheduled to mature in July 2005.

From
June through October 2001, Mission Contact Finance Limited issued $104 million of Redeemable Preferred Shares (250 million shares at a price of one New Zealand
dollar per share). The dividend rate is 6.03%. The shares are redeemable in July 2006 at one New Zealand dollar per share. Mission Contact Finance Limited is a special purpose company
established by Mission Energy Universal Holdings (Universal) to raise funds from the public and other institutional subscribers, to be used by it to subscribe for redeemable preferred shares in
Mission Energy Pacific Holdings (Pacific). Universal and Pacific are wholly owned subsidiaries of EME. Mission Contact Finance will call on

159

---

Pacific to redeem Pacific's Redeemable Preferred Shares held by Mission Contact Finance as and when necessary to provide it with the funds required to redeem the Mission Contact Finance Redeemable
Preferred Shares. The redemption of the shares can be accelerated if Mission Contact Finance exercises its option under the terms of the issue of the shares to redeem all or part of the shares, at its
discretion, by giving 45 days' irrevocable notice to the holders. Events of default will result in automatic redemption. Optional early redemption may occur if the holders pass an extraordinary
resolution to redeem the shares if Mission Contact Finance or Pacific ceases to be a subsidiary of EME, or in the case of failure by Pacific to comply with the terms of the security trust deed. The
Mission Contact Finance Redeemable Preferred Shares rank ahead of the ordinary shares in Mission Contact Finance for payment of amounts due on the shares. The holders of the shares have a shared
indirect security interest, through a security trustee, in all of the ordinary shares of Contact Energy held by Pacific. The Security Trust Deed secures a limited recourse guarantee by Pacific of
Mission Contact Finance's payment obligations to holders of the redeemable preferred shares. Mission Contact Finance may not, without the security trustee's prior written consent, make any
distribution after an enforcement event (primarily a payment default) has occurred which remains unremedied.

Note 13. Income Taxes

Current and Deferred Taxes

Income tax expense includes the current tax liability from operations and the change in deferred income taxes during the year. The components of the net
accumulated deferred income tax liability for continuing operations were:

December 31,2002

2001Deferred tax assetsItems deductible for book not currently deductible for tax

$
78

$
92Loss carryforwards


81


93Deferred income


172


179Dividends in excess of equity earnings


8


8Other


4


4Subtotal


343


376Valuation allowance


(22
)

(25
)Total

$
321

$
351


160

---

December 31,2002

2001Deferred tax liabilitiesBasis differences

$
1,457

$
1,228Tax credits, net


18


19Price risk management


25


1Other


2


Total


1,502


1,248Deferred taxes and tax credits, net

$
1,181

$
897


Foreign
loss carryforwards, primarily Australian, total $204 million and $197 million at December 31, 2002 and 2001, respectively, with no expiration date. State
loss carryforwards for various states total $230 million and $202 million at December 31, 2002 and 2001, respectively, with various expiration dates. State capital loss
carryforwards total $128 million and $186 million at December 31, 2002 and 2001, respectively, and will expire in 2005.

The
components of income (loss) before income taxes and minority interest applicable to continuing operations are as follows:

Years Ended December 31,2002

2001

2000U.S.

$
(164
)
$
41

$
2Foreign


174


82


143Total

$
10

$
123

$
145


United
States income taxes have not been provided on unrepatriated foreign earnings of approximately $515 million and $483 million at December 31, 2002 and 2001,
respectively. EME does not provide for federal income taxes or tax benefits on the undistributed earnings or losses of its international subsidiaries because such earnings are reinvested indefinitely.
If EME repatriated all of its undistributed earnings in the form of dividends or otherwise, EME would be subject to both U.S. income taxes and withholding taxes in various international jurisdictions.
Determination of the related amount of unrecognized deferred U.S. income tax liability is not practicable because of the complexities associated with its hypothetical calculation. In addition, foreign
income taxes have not been provided on unrepatriated foreign earnings from a different foreign jurisdiction of approximately $75 million and $54 million at December 31, 2002 and
2001, respectively.

161

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The
provision (benefit) for income taxes applicable to continuing operations is comprised of the following:

Years Ended December 31,2002

2001

2000CurrentFederal

$
(175
)
$
(44
)
$
(206
)State


(83
)

8


(20
)Foreign


35


14


46Total current

$
(223
)
$
(22
)
$
(180
)DeferredFederal

$
163

$
49

$
213State


28


31


38Foreign


12


8


5Total deferred


203


88


256Provision (benefit) for income taxes

$
(20
)
$
66

$
76


The
components of the deferred tax provision from continuing operations, which arise from tax credits and timing differences between financial and tax reporting, are presented below:

Years Ended December 31,2002

2001

2000Basis differences and tax credit amortization

$
139

$
(11
)
$
282Loss carryforwards


6


29


(28
)Deferred income


7


4


3State tax deduction


6


(7
)

(5
)Items deductible for book and tax in different accounting periods


12


41


45Price risk management


24


39


(39
)Other


9


(7
)

(2
)Total deferred provision

$
203

$
88

$
256


162

---

Variations
from the 35% federal statutory rate for income from continuing operations are as follows:

Years Ended December 31,2002

2001

2000Expected provision for federal income taxes

$
4

$
43

$
51Increase (decrease) in the provision for taxes resulting from:State taxnet of federal deduction


(36
)

22


12Dividends received deduction


(5
)

(10
)

(11
)Taxes payable under anti-deferral regimes


14


14


6Taxes on foreign operations at different rates


(13
)

(14
)

(4
)Non-utilization of foreign losses


11


9


16Other


5


2


6Total provision (benefit) for income taxes

$
(20
)
$
66

$
76Effective tax rate


(200
)%

54
%

53
%


EME
is, and may in the future be, under examination by tax authorities in varying tax jurisdictions with respect to positions EME takes in connection with the filing of its tax returns.
Matters raised upon audit may involve substantial amounts, which, if resolved unfavorably, an event not currently anticipated, could possibly be material. However, in EME's opinion, it is unlikely
that the resolution of
any such matters will have a material adverse effect upon EME's financial condition or results of operations.

Note 14. Employee Benefit Plans

United States employees of EME are eligible for various benefit plans of Edison International. Several of EME's Australian, United Kingdom and Spanish
subsidiaries also participate in their own respective defined benefit pension plans. MEHC has no full-time employees.

Pension Plans

Defined benefit pension plans (some with cash balance features) cover employees who fulfill minimum service and other requirements.

Ferrybridge
and Fiddler's Ferry employees joined a separate defined benefit pension plan utilized by some of the employees of First Hydro and Edison Mission Energy Limited during the
first quarter of 2000. Amounts for the year 2000 are included in the table below. Pension expense for Ferrybridge and Fiddler's Ferry totaled $1.5 million for the year 2000 and is included in
the table below. On December 21, 2001, the Ferrybridge and Fiddler's Ferry plants were sold to two wholly owned subsidiaries of American Electric Power. American Electric Power hired EME's
employees upon completion of the purchase and was required, pursuant to the asset purchase agreement, to set up a pension plan similar to EME's by March 31, 2002. All of EME's former employees
transferred to the new plan as of December 20, 2002. Pursuant to SFAS No. 88, "Employers' Accounting for Settlements and Curtailments of Defined Benefit Pension Plans and for Termination
Benefits," EME recorded a

163

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curtailment gain of approximately $10 million related to the cessation of future benefits for EME's former employees in 2001. The curtailment gain reduced actuarial losses incurred during the
year and, therefore, did not impact EME's pension expense.

At
December 31, 2002, the accumulated benefit obligation of the defined benefit pension plan utilized by First Hydro and Edison Mission Energy Limited employees exceeded the
market value of the pension plan assets at the measurement date. Pursuant to SFAS No. 87, "Employers' Accounting for Pensions" and SFAS No. 132, "Employers' Disclosures about Pensions
and Postretirement Benefits," EME recorded an additional minimum liability of approximately $11 million as a reduction to shareholder's equity through a charge to accumulated other
comprehensive income. The charge to accumulated other comprehensive income would be restored through shareholder's equity in future periods to the extent the fair value of the plan assets exceeded the
accumulated benefit obligation.

Information
on plan assets and benefit obligations is shown below:

|                                |                                                | Years Ended December 31,                 |    
|------------------------------- | ---------------------------------------------- | ---------------------------------------- | ---
|
|
|Change in Benefit Obligation    |                                                |                                          |    
|                                | Benefit obligation at beginning of year        |                                          | $  
|                                | Service cost                                   |                                          |    
|                                | Interest cost                                  |                                          |    
|                                | Amendments                                     |                                          |    
|                                | Actuarial loss (gain)                          |                                          |    
|                                | Curtailment/settlement                         |                                          |    
|                                | Plan participants' contribution                |                                          |    
|                                | Benefits paid                                  |                                          |    
|                                |                                                |                                          |    
|                                |                                                | Benefit obligation at end of year        |    
|                                |                                                |                                          |    
|Change in Plan Assets           |                                                |                                          |    
|                                | Fair value of plan assets at beginning of year |                                          | $  
|                                | Actual return on plan assets                   |                                          |    
|                                | Employer contributions                         |                                          |    
|                                | Curtailment/settlement                         |                                          |    
|                                | Plan participants' contribution                |                                          |    
|                                | Benefits paid                                  |                                          |    
|                                |                                                |                                          |    
|                                |                                                | Fair value of plan assets at end of year |    
|                                |                                                |                                          |    
|Funded Status                   |                                                | $                                        | (65
|Unrecognized net loss (gain)    |                                                |                                          | 29 
|Unrecognized net obligation     |                                                |                                          | 1  
|Unrecognized prior service cost |                                                |                                          | 2  
|                                |                                                |                                          |    
|Pension asset (liability)       |                                                | $                                        | (33
|                                |                                                |                                          |    

164

---

|                               |  | Years Ended December 31,
|------------------------------ |  | ------------------------
|
|
|Discount rate                  |  | 6.50%                   
|Rate of compensation increase  |  | 5.00%                   
|Expected return on plan assets |  | 8.50%                   

The
projected benefit obligation, accumulated benefit obligation, and fair value of plan assets for the pension plans with accumulated benefit obligations in excess of plan assets were
$88 million, $71 million and $51 million, respectively, as of December 31, 2002. As of December 31, 2001, the fair value of plan assets exceeded the accumulated
benefit obligations for all pension and postretirement benefit plans.

Components
of pension expense were:

|                               |  | Years Ended December 31, |   
|------------------------------ |  | ------------------------ | --
|
|
|Service cost                   |  | $                        | 13
|Interest cost                  |  |                          | 5 
|Expected return on plan assets |  |                          | (3
|Net amortization and deferral  |  |                          | 1 
|                               |  |                          |   
|Total pension expense          |  | $                        | 16
|                               |  |                          |   

Postretirement Benefits Other Than Pensions

Most United States non-union 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. Eligibility depends on a number of factors, including the employee's hire date.

Employees
in union-represented positions at the Illinois Plants were covered by a retirement health care and other benefits plan that expired on June 15, 2002. In
October 2002, Midwest Generation reached an agreement with its union-represented employees on new benefits plans, which extend from January 1, 2003 through June 30, 2005. Midwest
Generation continued to provide benefits at the same level as those in the expired agreement until December 31, 2002. The accounting for postretirement benefits liabilities has been determined
on the basis of a substantive plan under Statement of Financial Accounting Standards No. 106, "Employers' Accounting for Postretirement Benefits Other Than Pensions." A substantive plan means
that Midwest Generation assumed, for accounting purposes, that it would provide for postretirement health care benefits to union-represented employees following conclusion of negotiations to replace
the current benefits agreement, even though Midwest Generation had no legal obligation to do so. Under the new agreement, postretirement health care benefits will not be provided. Accordingly, Midwest
Generation treated this as a plan termination under SFAS No. 106 and recorded a pre-tax gain of $71 million during the fourth quarter of 2002.

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Information
on plan assets and benefit obligations is shown below:

Years Ended December 31,2002

2001Change in Benefit ObligationBenefit obligation at beginning of year

$
118

$
120Service cost


5


5Interest cost


8


7Settlement


(71
)

Actuarial loss (gain)


(3
)

(14
)Benefits paid


(1
)

Benefit obligation at end of year

$
56

$
118Change in Plan AssetsFair value of plant assets at beginning of year

$


$
Employer contributions


1


Benefits paid


(1
)

Fair value of plan assets at end of year

$


$
Funded status

$
(56
)
$
(118
)Unrecognized net loss (gain)


9


1Unrecognized prior service cost


(2
)

(2
)Recorded liability

$
(49
)
$
(119
)Discount rate


6.75
%

7.25
%Expected return on plan assets


na


8.20
%


The
components of postretirement benefits other than pensions expense were:

Years Ended December 31,2002

2001

2000Service cost

$
5

$
5

$
5Interest cost


8


7


8Settlement


(71
)




Net expense

$
(58
)
$
12

$
13


The
assumed rate of future increases in the per-capita cost of health care benefits is 9.75% for 2003, 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, 2002, by $12 million and annual aggregate service and interest costs by
$1 million. Decreasing the health care cost trend rate by one percentage point would decrease the accumulated obligation as of December 31, 2002, by $10 million and annual
aggregate service and interest costs by $1 million.

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Employee Stock Plans

A 401(k) plan is maintained to supplement eligible United States employees' retirement income. The plan received contributions from EME of $6 million in
2002, $6 million in 2001 and $5 million in 2000.

Doga
employees are included in a separate government scheme, Pension Plan of Social Security Institution. The plan is administered by the officers of the Turkish Government.
Contributions to the plan are based on a percentage of compensation for the covered employees and are assessed by the Ministry of Labor and Social Security. The plan is substantially funded at the end
of each month. Pension expense recorded by Doga was $114 thousand in 2002, $97 thousand in 2001 and $114 thousand in 2000.

EME
also sponsors a defined contribution plan for specified United Kingdom subsidiaries. Annual contributions are based on ten percent of covered employees' salaries. Contribution
expense for the subsidiaries totaled approximately $1 million in 2002, 2001 and 2000.

Note 15. Stock Compensation Plans

Stock Options

Under the Edison International Equity Compensation Plan, shares of Edison International common stock may be issued pursuant to plan awards to key EME employees in
various forms, including the exercise of stock options. In May 2000, Edison International adopted an additional plan, the 2000 Equity Plan under which stock options, including the special
options discussed below may be awarded. Under these programs, there are currently outstanding at December 31, 2002 to employees and former employees of EME, options on 2,181,812 shares of
Edison International common stock. MEHC has no full-time employees.

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 generally expire 10 years after the date of grant, and vest over a period of up to five years.

Edison
International stock options awarded prior to 2000 include a dividend equivalent feature. Dividend equivalents on options issued after 1993 and prior to 2000 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 liability and associated expense is accrued each quarter for the dividend equivalents for each option year. At the end of the performance
measurement period, the expense and related liability is adjusted accordingly. Upon exercise, the dividends are paid out and the associated liability is reduced on EME's consolidated balance sheet.

Options
issued after 1997 generally have a four-year vesting period. The special options granted in 2000 vest over five years in 25% increments beginning May 2002.
Earlier options had a three-year vesting period with one-third of the total award vesting annually. If an option holder retires, dies, is terminated by the company, or is
terminated while permanently and totally disabled (qualifying event) during the vesting period, the unvested options will vest on a pro rata basis.

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The
fair value for each option granted during 2002, 2001 and 2000, reflecting the basis for the 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:

|                        |  | 2002         |  | 2001         |  | 2000        
|----------------------- |  | ------------ |  | ------------ |  | ------------
|Expected life           |  | 7-10 years   |  | 7-10 years   |  | 7-10 years  
|Risk-free interest rate |  | 4.7% to 6.1% |  | 4.7% to 6.1% |  | 4.7% to 6.0%
|Expected volatility     |  | 18% to 54%   |  | 17% to 52%   |  | 17% to 46%  

The
application of fair-value accounting to calculate the pro forma disclosures is not an indication of future income statement effects. The recognition of dividend
equivalents results in no dividends assumed for purposes of fair-value determination. The pro forma disclosures do not reflect the effect of fair-value accounting on
stock-based compensation awards granted prior to 1995.

Other Equity-Based Awards

For years after 1999, a portion of the executive long-term incentives was awarded in the form of performance shares. The 2000 performance shares were
restructured as retention incentives in December 2000, which pay as a combination of Edison International common stock and cash if the executive remains employed at the end of the performance
period. The performance period ended December 31, 2001, for half of the award, and ends on December 31, 2002, for the remainder.
Additional performance shares were awarded in January 2001 and January 2002. The 2001 performance shares vest December 31, 2003, half in shares of Edison International common
stock and half in cash. The 2002 performance shares vest December 31, 2004; also half in shares of common stock and half in cash. The number of shares that will be paid out from the 2002
performance share awards will depend on the performance of Edison International common stock relative to the stock performance of a specified group of peer companies.

The
2000 and 2001 performance shares and deferred stock unit values are accrued ratably over a three-year performance period. The 2002 performance shares will be valued based
on Edison International's stock performance relative to the stock performance of other such entities. In March 2001, deferred stock units were awarded as part of a retention program. These vest
and were paid March 12, 2003. The deferred stock units are payable on the vesting date in shares of Edison International common stock.

In
October 2001, a stock option retention exchange offer was extended offering holders of Edison International stock options granted in 2000 the opportunity to exchange those
options for a lesser number of deferred stock units. The exchange ratio was based on the Black-Scholes value of the options and the stock price at the time the offer was extended. The exchange took
place in November 2001; the options that participants elected to exchange were cancelled, and deferred stock units were issued. Approximately three options were cancelled for each deferred
stock unit issued. Twenty-five percent of the deferred stock units will vest and be paid in Edison International common stock per year over four years, with the first vesting and payment
date in November 2002. The following assumptions were used in determining fair value through the Black-Scholes option-pricing model: expected life: 8-9 years;
risk-free interest rate: 5.10%; expected volatility: 52%.

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EME measures compensation expense related to stock-based compensation by the intrinsic value method. Compensation expense recorded under the stock compensation
program was approximately $4 million, $3 million and $1 million for the years ended December 31, 2002, 2001 and 2000, respectively.

The
weighted-average fair value of options granted during 2002, 2001 and 2000 was $7.88 per share option, $3.88 per share option and $5.63 per share option, respectively. The
weighted-average remaining life of options outstanding was 6 years as of December 31, 2002 and 2001 and 8 years as of December 31, 2000.

A
summary of the status of Edison International's stock options granted to EME employees is as follows:

Share
Options

Exercise Price

Weighted
Exercise PriceOutstanding, December 31, 1999

479,071

$
14.56 - $29.34

$
23.84Granted

2,550,660

$
20.06 - $28.13

$
21.84Transferred to EME from Edison International

514,750

$
14.56 - $28.13

$
23.68Forfeited

(147,518
)
$
18.75 - $28.13

$
24.58Exercised

(43,592
)
$
14.56 - $28.13

$
19.01Outstanding, December 31, 2000

3,353,371

$
14.56 - $29.34

$
22.31Granted

649,768

$
9.10 - $15.25

$
9.78Transferred to EME from Edison International

1,327,105

$
14.56 - $28.94

$
20.16Forfeited

(3,583,233
)
$
9.15 - $29.34

$
20.79Outstanding, December 31, 2001

1,747,011

$
9.10 - $29.34

$
19.07Granted

967,405

$
10.60 - $18.73

$
18.61Transferred from EME to Edison International

(22,046
)
$
9.15 - $28.94

$
21.33Forfeited

(466,382
)
$
9.10 - $29.34

$
20.09Exercised

(44,176
)
$
15.18 - $18.80

$
16.75Outstanding, December 31, 2002

2,181,812

$
9.10 - $28.94

$
18.60


The
number of options exercisable and their weighted-average exercise prices at December 31, 2002, 2001 and 2000 were 731,009 at $21.29, 780,802 at $22.49 and 562,662 at $21.55,
respectively.

Phantom Stock Options

EME, as a part of the Edison International long-term incentive compensation program, issued phantom stock option performance awards to key employees
from 1994 through 1999. Each phantom stock option could be exercised to realize any appreciation in the value of one hypothetical share of EME stock over its exercise price. Compensation expense was
recognized during the period that the employee had the right to receive this appreciation. Exercise prices for EME's phantom stock were escalated on an annually compounded basis over the grant price
by 9%. The value of the phantom stock was recalculated annually as determined by a formula linked to the value of EME's portfolio of investments less general and administrative costs. The options had
a 10-year term with one-third of the

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total award vesting in each of the first three years of the award term, for all awards prior to 1998. 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. In August 2000, all outstanding phantom stock options were cancelled and replaced with a combination of cash and stock equivalent units relating to
Edison International common stock in accordance with the EME Affiliate Option Exchange Offer.

Compensation
expense recorded with respect to phantom stock options was $2 million, $6 million and $4 million (before the $60 million adjustment referred to
below) in 2002, 2001 and 2000, respectively.

Due
to the lower valuation of the exchange offer, compared to the values previously accrued, the liability for accrued incentive compensation was reduced by approximately
$60 million in the third quarter of 2000.

Note 16. Commitments and Contingencies

Firm Commitment for Asset Purchase

Projects

Local Currency

U.S. CurrencyItalian Wind and Expansion(i)

2 million Euro

$
2


---

Firm Commitments to Contribute Project Equity

Projects

U.S. CurrencyCBK(i)

$
37Italian Wind Expansion(ii)

$
2Sunrise(iii)

$
36


---

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---



Firm
commitments to contribute project equity to the CBK project and the Italian Wind expansion project could be accelerated due to events of default as defined in the
non-recourse project financing facilities.

Chicago In-City Obligation

Pursuant to the acquisition documents for the purchase of generating assets from Commonwealth Edison, EME's subsidiary, Midwest Generation, committed to install
one or more gas-fired electric generating units having an additional gross dependable capacity of 500 MW at or adjacent to an existing power plant site in Chicago, this commitment being
referred to as the In-City Obligation, for an estimated cost of $320 million. The acquisition documents require that commercial operation of this project commence by
December 15, 2003. Due to additional capacity for new gas-fired generation in the Mid-America Interconnected Network, generally referred to as the MAIN Region, and the
improved reliability of power generation in the Chicago area, EME did not believe the additional gas-fired
generation was needed. In February 2003, Midwest Generation finalized an agreement with Commonwealth Edison to terminate this commitment in exchange for the following:



As
a result of this agreement with Commonwealth Edison, Midwest Generation recorded a loss of $45 million during the fourth quarter of 2002. The loss was determined by the sum of:
(a) the present value of the cash payments to both Commonwealth Edison and Calumet Energy Team LLC (capacity

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payments), less (b) the fair market value of the option to purchase power under the replacement contract with Calumet Energy Team LLC. As a result of the agreement with Commonwealth Edison,
Midwest Generation is no longer obligated to build the additional gas-fired generation.

Fuel Supply Contracts

At December 31, 2002, EME's subsidiaries had contractual commitments to purchase and/or transport coal and fuel oil. Based on the contract provisions,
which consist of fixed prices, subject to adjustment clauses in some cases, these minimum commitments are currently estimated to aggregate $2,137 million in the next five years summarized as
follows: 2003$605 million; 2004$487 million; 2005$453 million; 2006$366 million; and
2007$226 million.

Gas Transportation Agreements

At December 31, 2002, EME had contractual commitments to transport natural gas beginning the later of May 1, 2003 or the first day that expansion
capacity is available for transportation services. In June 2001, EME entered into an agreement with Texaco Power & Gasification Holdings, Inc. for the purpose of committing, and
eventually assigning, one of the contracts to the Sunrise project. In this
agreement, Texaco Power & Gasification Holdings, Inc. has agreed to assume 50% of EME's liabilities under the specified contract until its formal assignment to the Sunrise project. EME's
share of the commitment to pay minimum fees under these agreements, which have a term of 15 years, is currently estimated to aggregate $71 million in the next five years, summarized as
follows: 2003$8 million; 2004$16 million; 2005$16 million; 2006$16 million; and 2007$15 million.

Contingencies

Paiton Project

A wholly owned subsidiary of EME owns a 40% interest in PT Paiton Energy, which owns a 1,230 MW coal-fired power plant in operation in East Java,
Indonesia, which is referred to as the Paiton project. Under the terms of a long-term power purchase agreement between Paiton Energy and PT PLN, the state-owned electric utility company,
PT PLN is required to pay for capacity and fixed operating costs since each unit and the plant have achieved commercial operation.

On
December 23, 2002, an amendment to the original power purchase agreement became effective, bringing to a close and resolving a series of disputes between Paiton Energy and PT
PLN which began in 1999 and were caused, in large part, by the effects of the regional financial crisis in Asia and Indonesia. The amended power purchase agreement includes changes in the price for
power and energy charged under the power purchase agreement, provides for payment over time of amounts unpaid prior to January 2002 and extends the expiration date of the power purchase
agreement from 2029 to 2040. These terms have been in effect since January 2002 under a previously agreed Binding Term Sheet which was replaced by the power purchase agreement amendment.

In
February 2003, Paiton Energy and all of its lenders concluded a restructuring of the project's debt. As part of the restructuring, Export-Import Bank of the United States
loaned the project $381 million, which was used to repay loans made by commercial banks during the period of the project's construction. In addition, the amortization schedule for repayment of
the project's loans was

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extended to take into account the effect upon the project of the lower cash flow resulting from the restructured electricity tariff. The initial principal repayment under the new amortization
schedule was made on February 18, 2003. Distributions from the project to shareholders are not anticipated to commence until 2006. As a condition to the making of the loans by Export-Import
Bank of the United States, all commercial disputes related to the project were settled without a material effect on EME. EME believes that it will ultimately recover its investment in the project.

EME's
investment in the Paiton project increased to $514 million at December 31, 2002 from $492 million at December 31, 2001. The increase in the investment
account resulted from EME's subsidiary recording its proportionate share of net income from Paiton Energy. EME's investment in the Paiton project will increase (decrease) from earnings (losses) from
Paiton Energy and decrease by cash distributions. Assuming Paiton Energy remains profitable, EME expects the investment account to increase substantially during the next several years as earnings are
expected to exceed cash distributions.

BHP Fuel Supply Agreement Arbitration

During 2002, PT Batu Hitam Perkasa (BHP), one of the other shareholders in Paiton Energy, reinstated a previously suspended arbitration to resolve disputes under
the fuel supply agreement between BHP and Paiton Energy. The arbitration commenced in 1999 but had been stayed since that time to allow the parties to engage in settlement discussions related to a
restructuring of the coal supply arrangements for the Paiton project. These discussions did not at the time lead to settlement, and BHP requested an arbitration tribunal to reinstate the original
arbitration and to permit BHP to assert additional claims. In total, BHP's claims amounted to $250 million.

On
December 19, 2002, Paiton Energy and BHP entered into an agreement whereby all claims in the arbitration were settled and agreement was reached to dismiss the arbitration with
no material effect upon Paiton Energy. Paiton Energy made the required payment to BHP under the terms of the settlement agreement, and all claims have been dismissed.

Brooklyn Navy Yard Project

Brooklyn Navy Yard is a 286 MW gas-fired cogeneration power plant in Brooklyn, New York. EME's subsidiary owns 50% of the project. In
February 1997, the construction contractor asserted general monetary claims under the turnkey agreement against Brooklyn Navy Yard Cogeneration Partners, L.P. for damages in the amount of
$137 million. Brooklyn Navy Yard Cogeneration Partners asserted general monetary claims against the contractor. In connection with a $407 million non-recourse project
refinancing in 1997, EME agreed to indemnify Brooklyn Navy Yard Cogeneration Partners and its partner from all claims and costs arising from or in connection with the contractor litigation, which
indemnity has been assigned to Brooklyn Navy Yard Cogeneration Partners' lenders. During December 2002, the parties held mediation sessions and reached a settlement of all outstanding claims. A
settlement agreement was executed on January 17, 2003, and all litigation has been dismissed. The settlement agreement did not have a material effect upon the project or EME.

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ISAB Project

In connection with the financing of the ISAB project, which is located near Siracusa in Sicily, Italy, EME guaranteed, for the benefit of the banks financing the
construction of the ISAB project, the obligation of one of its subsidiaries to contribute project equity and subordinated debt totaling up to approximately $39 million. The amount of payment
under the obligation was contingent upon the outcome of an arbitration proceeding brought in 1999 by the contractor of the project against ISAB Energy. During December 2002, the parties reached
agreement on a full and final settlement of all claims at issue. Conditions to the settlement were satisfied in February 2003. The agreement provides for no payments to be made by the ISAB
project and thus no payments will be required under the EME guarantee referred to above.

Regulatory Developments Affecting Sunrise Power Company

Sunrise Power Company, in which EME's wholly owned subsidiary owns a 50% interest, sells all its output to the California Department of Water Resources under a
power purchase agreement entered into on June 25, 2001. On February 25, 2002, the California Public Utilities Commission and the California Electricity Oversight Board filed complaints
with the Federal Energy Regulatory Commission against all sellers of power under long-term contracts to the California Department of Water Resources, including Sunrise Power Company. The
California Public Utilities Commission complaint alleged that the contracts were "unjust and unreasonable" on price and other terms, and requested that the contracts be abrogated. The California
Electricity Oversight Board complaint made a similar allegation and requested that the contracts be deemed voidable at the request of the California Department of Water Resources or, in the
alternative, abrogated as of a future date, to allow for the possibility of renegotiation. In January 2003, the California Public Utilities Commission and California Electricity Oversight Board
dismissed their complaints against Sunrise Power Company pursuant to a global settlement that also involved a restructuring of Sunrise Power Company's long-term contract with the
California Department of Water Resources. On December 31, 2002, Sunrise Power Company restructured its contract with the California Department of Water Resources. The restructured agreement
reduced by 5% the capacity payments to be made to Sunrise Power Company as compensation for having power available when needed. In addition, Sunrise Power Company's option to extend the agreement for
one year beyond December 31, 2011 was terminated; however, the term of the restructured agreement was extended until June 30, 2012.

On
May 2, 2002, the United States Justice Foundation announced that it had filed a complaint in the Superior Court of the State of California, Los Angeles County, against the
California Department of Water Resources, all sellers of power under long-term energy contracts entered into in 2001, including Sunrise Power Company, and Vikram Budhraja, one of the
consultants involved in the negotiation of energy contracts on behalf of the California Department of Water Resources. The lawsuit asks the Superior Court to void all the contracts entered into in
2001, as well as all the contracts renegotiated in 2002, as a result of a purported conflict of interest by Mr. Budhraja. Sunrise Power Company has not yet been served with the complaint.

On
May 15, 2002, Sunrise Power Company was served with a complaint filed in the Superior Court of the State of California, City and County of San Francisco, by James M. Millar,
"individually, and on behalf of the general public and as a representative taxpayer suit" against sellers of long-term power to

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the California Department of Water Resources, including Sunrise Power Company. The lawsuit alleges that the defendants, including Sunrise Power Company, engaged in unfair and fraudulent business
practices by knowingly taking advantage of a manipulated power market to obtain unfair contract terms. The lawsuit seeks to enjoin enforcement of the "unfair and oppressive terms and conditions" in
the contracts, as well as restitution by the defendants of excessive monies obtained by the defendants. Plaintiffs in several other class action lawsuits pending in Northern California have filed
petitions seeking to have the Millar lawsuit consolidated with those lawsuits. The defendants in the Millar lawsuit and other class action suits removed all the lawsuits to the U.S. District Court,
Northern District of California, and filed a motion to stay all proceedings pending final resolution of the jurisdictional issue. Various plaintiffs have filed pleadings opposing the removal and
requesting that the matters be remanded to state court. The motions are still pending. EME believes that the outcome of this litigation will not have a material adverse effect on its consolidated
financial position or results of operations.

Regulatory Developments Affecting Doga Project

On August 4, 2002, a new Electricity Market License Regulation was implemented in Turkey. The regulation contains, among other things, a requirement for
each generator to obtain a generation license. Historically, Doga's Implementation Contract has been its sole license. The new regulation contemplates an initial fixed license fee and a yearly license
fee based on the amount of energy generated, which will increase the project's costs of operation by an undetermined amount. In addition, the regulation allows the insertion of provisions in the
license which are different from those in the Implementation Contract.

The
effect of the new regulation is still undetermined, as the new license provisions have not been specified. The new regulation requires Doga to apply for a generation license between
March and April of 2003. If actions or inactions undertaken pursuant to the new regulation directly or indirectly impede, hinder, prevent or delay the operation of the Doga facility or increase Doga's
cost of performing its obligations under its project documents, this may constitute a risk event under Doga's Implementation Contract. A risk event may permit Doga to request an increase in its tariff
or, under certain circumstances, request a buyout of the project by the Ministry of Energy and Natural Resources.

On
October 3, 2002, Doga and several other independent power producers filed a lawsuit in the Danistay, Turkey's high administrative court, against the Energy Market Regulatory
Authority seeking invalidation of certain provisions of the new regulation, arguing the unconstitutionality of the imposition of new license requirements that do not take into account the vested
rights of companies presently performing electricity generation pursuant to previously agreed conditions. No decision has been rendered and discussions with the Turkish authorities continue.

Guarantees and Indemnities



In connection with the sale-leaseback transactions that EME has entered into related to the Collins Station, Powerton and Joliet plants in Illinois
and the Homer City facilities in Pennsylvania, EME or one of its subsidiaries has entered into tax indemnity agreements. Under these tax indemnity

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agreements, EME has agreed to indemnify the lessors in the sale-leaseback transactions for specified adverse tax consequences that could result in certain situations set forth in each tax
indemnity agreement, including specified defaults under the respective leases. The potential indemnity obligations under these tax indemnity agreements could be significant. Due to the nature of these
obligations under these tax indemnity agreements, EME cannot determine a maximum potential liability. The indemnities would be triggered by a valid claim from the lessors. EME has not recorded a
liability related to these indemnities.



In connection with the acquisition of the Illinois Plants, EME agreed to indemnify Commonwealth Edison against damages, claims, fines, liabilities and expenses
and losses arising from, among other things, environmental liabilities before and after the date of sale as specified in the Asset Sale Agreement dated March 22, 1999. The indemnification
claims are reduced by any insurance proceeds and tax benefits related to such claims and are subject to a requirement by Commonwealth Edison to take all reasonable steps to mitigate losses related to
any such indemnification claim. Due to the nature of the obligation under this indemnity, a maximum potential liability cannot be determined. The indemnification for the environmental liabilities
referred to above is not limited in term and would be triggered by a valid claim from Commonwealth Edison. Except as discussed below, EME has not recorded a liability related to this indemnity.

Midwest
Generation entered into a supplemental agreement to resolve a dispute regarding interpretation of its reimbursement obligation for asbestos claims under the environmental
indemnities set forth in the Asset Sale Agreement. Under this supplemental agreement, Midwest Generation agreed to reimburse Commonwealth Edison 50% of specific existing asbestos claims less recovery
of insurance costs, and agreed to a sharing arrangement for liabilities associated with future asbestos related claims as specified in the agreement. The obligations under this agreement are not
subject to a maximum liability. The supplemental agreement has a five-year term with an automatic renewal
provision (subject to the right to terminate). Payments are made under this indemnity by a valid claim provided from Commonwealth Edison. At December 31, 2002, Midwest Generation recorded a
$5 million liability related to known claims provided by Commonwealth Edison.



In connection with the acquisition of the Homer City facilities, EME Homer City Generation L.P. is obligated to indemnify the sellers against damages, claims and
losses arising from environmental liabilities before and after the date of sale as specified in the Asset Purchase Agreement dated August 1, 1998. EME guaranteed the obligations of EME Homer
City. Due to the nature of the obligation under this indemnity provision, it is not subject to a maximum potential liability nor has an expiration date. Payments would be triggered under this
indemnity by a claim from the sellers. EME has not recorded a liability related to this indemnity.



In connection with the sale of assets, EME has provided indemnities to the purchasers for taxes imposed with respect to operations of the asset prior to the sale,
and EME or its subsidiaries have

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received similar indemnities from purchasers related to taxes arising from operations after the sale. EME also provided indemnities to purchasers for items specified in each agreement (for example,
specific pre-existing litigation matters and/or environmental conditions). Due to the nature of the obligations under these indemnity agreements, a maximum potential liability cannot be
determined. Indemnities under the asset sale agreements do not have specific expiration dates. Payments would be triggered under these indemnities by valid claims from the sellers or purchasers, as
the case may be. EME has not recorded a liability related to these indemnities.



Brooklyn Navy Yard is a 286 MW gas-fired cogeneration power plant in Brooklyn, New York. EME's wholly owned subsidiary owns 50% of the project. In
February 1997, the construction contractor asserted general monetary claims under the turnkey agreement against Brooklyn Navy Yard Cogeneration Partners, L.P. A settlement agreement was
executed on January 17, 2003, and all litigation has been dismissed. EME has indemnified Brooklyn Navy Yard Cogeneration Partners, L.P. for any payments due under this settlement agreement
which are scheduled through 2006. At December 31, 2002, EME recorded a liability of $32 million related to this indemnity.



TM Star was formed for the limited purpose to sell natural gas to the March Point Cogeneration Company, an affiliate through common ownership, under a fuel supply
agreement that extends through December 31, 2011. TM Star has entered into fuel purchase contracts with unrelated third parties to meet a portion of the obligations under the fuel supply
agreement. EME has guaranteed 50% of TM Star's obligation under the fuel supply agreement to March Point Cogeneration. Due to the nature of the obligation under this guarantee, a maximum potential
liability cannot be determined. TM Star has met its obligations to March Point Cogeneration, and, accordingly, no claims against this guarantee have been made.



EME has guaranteed, jointly and severally with Texaco Inc., the obligations of March Point Cogeneration Company under its project power sales agreements to
repay capacity payments to the project's power purchaser in the event that the power sales agreement terminates, March Point Cogeneration Company abandons the project, or the project fails to return
to normal operations within a reasonable time after a complete or partial shutdown, during the term of the power contracts. In addition, subsidiaries of EME have guaranteed the obligations of Kern
River Cogeneration Company and Sycamore Cogeneration Company under their project power sales agreements to repay capacity payments to the projects' power purchaser in the event that the projects
unilaterally terminate their performance or reduce their electric power producing capability during the term of the power contracts. The obligations under the indemnification agreements as of
December 31, 2002, if payment were required, would be $209 million. EME has no reason to believe that any of these projects will either cease operations or reduce its electric power
producing capability during the term of its power contract.

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EME has indemnified its lenders under its credit facilities from amounts drawn on a $33 million letter of credit issued for the benefit of the lenders to
ISAB Energy, a 49% unconsolidated affiliate, in lieu of ISAB Energy funding a debt service reserve account using additional equity contributions. Accordingly, a default under ISAB Energy's project
debt could result in a draw under the letter of credit which, in turn, would result in a borrowing under EME's credit facilities. The letter of credit is renewed each six-month period or
until ISAB Energy funds the debt service account. The indemnification is subject to
the maximum amount drawn under the letter of credit. EME has not recorded a liability related to this indemnity.



A subsidiary of EME has indemnified Central Maine Power Company against decreases in the value of power deliveries by CL Power Sales Eight, L.L.C., an
unconsolidated affiliate, to Central Maine Power as a result of the implementation of a location-based pricing system in the New England Power Pool. The indemnity has the same term as a power supply
agreement between Central Maine Power and CL Eight, which runs through December 2016. It is not possible to determine potential differences in values between the various points of delivery in
New England Power Pool at this time. Due to the nature of this indemnity, a maximum potential liability cannot be determined. To the extent EME's subsidiary would be required to make a payment under
this indemnity, it and EME are indemnified by Peabody Energy Corporation pursuant to the 2000 Purchase and Sale Agreement for the acquisition of Citizens Power LLC. EME's subsidiary has not recorded a
liability related to this indemnity.



A subsidiary of EME has guaranteed the obligations of two unconsolidated affiliates to make payments to third parties for power delivered under fixed-price power
sales agreements. These agreements run through 2008. EME believes there is sufficient cash flow to pay the power suppliers assuming timely payment by the power purchasers. Due to the nature of this
indemnity, a maximum potential liability cannot be determined. To the extent EME's subsidiary would be required to make payments under the guarantee, EME's subsidiary and EME are indemnified by
Peabody Energy Corporation pursuant to the 2000 Purchase and Sale Agreement for Citizens Power LLC. EME's subsidiary has not recorded a liability related to this indemnity.

Litigation

EME experiences other routine litigation in the normal course of its business. None of such pending routine litigation is expected to have a material adverse
effect on EME's consolidated financial position or results of operations.

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Contingent Obligations to Contribute Project Equity

Projects

Local Currency

U.S. CurrencyPaiton(i)



$
5ISAB(ii)

37 million Euro

$
39


---





EME
is not aware of any other significant contingent obligations to contribute project equity.

Environmental Matters and Regulations

EME is subject to environmental regulation by federal, state and local authorities in the United States and foreign regulatory authorities with jurisdiction over
projects located outside the United States. EME believes that it is in substantial compliance with environmental regulatory requirements and that maintaining compliance with current requirements will
not materially affect its financial position or results of operation. However, possible future developments, such as the promulgation of more stringent environmental laws and regulations, and future
proceedings that may be initiated by environmental authorities, could affect the costs and the manner in which EME conducts its business and could cause it to make substantial additional capital
expenditures. There is no assurance that EME would be able to recover these increased costs from its customers or that EME's financial position and results of operations would not be materially
adversely affected.

Typically,
environmental laws require a lengthy and complex process for obtaining licenses, permits and approvals prior to construction and operation of a project. Meeting all the
necessary requirements can delay or sometimes prevent the completion of a proposed project as well as require extensive modifications to existing projects, which may involve significant capital
expenditures. If EME fails to

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comply with applicable environmental laws, it may be subject to penalties and fines imposed against EME by regulatory authorities.

StateIllinois

Air Quality.In June 2001, Illinois passed legislation mandating the Illinois Environmental Protection Agency to
evaluate and issue a report to the Illinois legislature addressing the need for further emissions controls on fossil fuel-fired electric generating stations, including the potential need
for additional controls on nitrogen oxides, sulfur dioxide and mercury. The study, which is to be submitted between September 30, 2003 and September 30, 2004, also requires an evaluation
of incentives to promote renewable energy and the establishment of a banking system for certifying credits from voluntary reductions of greenhouse gases. The law allows the Illinois Environmental
Protection Agency to propose regulations based on its findings no sooner than 90 days after the issuance of its findings, and requires the Illinois Pollution Control Board to act within one
year on such proposed regulations. Until the Illinois Environmental Protection Agency issues its findings and proposes regulations in accordance with the findings, if such regulations are proposed,
EME cannot evaluate the potential impact of this legislation on the operations of its facilities.

Beginning
with the 2003 ozone season (May 1 through September 30), EME must comply with an average NOx emission rate of 0.25 lb NOx/mmBtu of heat input. This limitation is
commonly referred to as the East St. Louis State Implementation Plan (SIP). This regulation is a State of Illinois requirement. Compliance with this standard will be met by averaging the emissions of
all EME's power plants. Additional burner controls planned for installation at Powerton in the spring of 2003 along with over-compliance at EME's other Illinois Plants, will facilitate
compliance with this standard.

Beginning
with the 2004 ozone season, an additional NOx emission regulation will go into effect. This federally mandated regulation, commonly referred to as the "NOx SIP Call" will cap
NOx emissions within a 19-state region east of the Mississippi with a tonnage cap on NOx emissions. This program allows NOx trading similar to the current SO2 trading program already in
effect. EME's compliance plan is to rely upon a combination of strategies. EME has already qualified for early reduction credits by reducing NOx emissions at various plants ahead of the imposed
deadline. Additionally, the installation of emission control technology at select plants will ensure over-compliance at those individual plants with pending NOx emission limitations.
Finally, NOx emission trading will be utilized as needed to comply with any shortfall in emission credits anticipated with the deferral of the SCR projects at EME's Powerton Station.

Water Quality.The Illinois EPA is reviewing the water quality standards for the DesPlaines River adjacent to the Joliet
Station and immediately downstream of the Will County Station to determine if the use classification should be upgraded. One of the limitations for discharges to the river that could be made more
stringent if the existing secondary contact classification is changed would be the allowable temperature of the discharges from Joliet and Will County. At this time no new standards have been
proposed, so EME cannot estimate the financial impact of this review.

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StatePennsylvania

Water Quality.The discharge from the treatment plant receiving the wastewater stream from EME's Unit 3 flue gas
desulfurization system at the Homer City facilities has exceeded the stringent, water-quality based limits for selenium in the station's NPDES permit. As a result, EME has been notified by PADEP that
it has been included in the Quarterly Noncompliance Report submitted to the United States Environmental Protection Agency. EME has met with the contractor responsible for the Unit 3 flue gas
desulfurization system to discuss approaches to resolving the water quality issues and is investigating technical alternatives for maximizing the level of selenium removal in the discharge. EME has
also discussed these approaches for resolving the water quality issues with PADEP. Pilot studies are underway, but until they are completed and the results are evaluated, EME cannot estimate the costs
to comply with these selenium limits. After the results of the pilot studies are evaluated, EME will instruct the contractor to make the necessary improvements and then meet with PADEP to discuss the
drafting of a consent agreement to address the selenium issue. The consent agreement may include the payment of civil penalties, but the amount cannot be estimated at this time.

FederalUnited States of America

Clean Air Act.EME expects that compliance with the Clean Air Act and the regulations and revised State Implementation Plans
developed as a consequence of the Act will result in increased capital expenditures and operating expenses. EME's approach to meeting these obligations will consist of a blending of capital
expenditure and emissions allowance purchases that will be based on an ongoing assessment of the dynamics of its market conditions. EME anticipates that upgrades to its environmental controls to
reduce nitrogen oxide (NOx) emissions will result in capital expenditures of $28 million in 2003 and $2 million in 2004-2007.

Mercury Maximum Achievable Control Technology Determination.On December 20, 2000, the Environmental Protection Agency
issued a regulatory finding that it is "necessary and appropriate" to regulate emissions of mercury and other hazardous air pollutants from coal-fired power plants. The agency has added
coal-fired power plants to the list of source categories under Section 112(c) of the Clean Air Act for which "maximum achievable control technology" standards will be developed.
Eventually, unless overturned or reconsidered, the Environmental Protection Agency will issue technology-based standards that will apply to every coal-fired unit owned by EME or its
affiliates in the United States. The regulations are required to become final in 2004 with controls in place by 2007. This section of the Clean Air Act provides only for technology-based standards,
and does not permit market trading options. Until the standards are actually promulgated, the potential cost of these control technologies cannot be estimated, and EME cannot evaluate the potential
impact on the operations of its facilities.

National Ambient Air Quality Standards.A new ambient air quality standard was adopted by the Environmental Protection Agency
in July 1997 to address emissions of fine particulate matter. It is widely understood that attainment of the fine particulate matter standard may require reductions in nitrogen oxides and
sulfur dioxides, although, under the time schedule announced by the Environmental Protection Agency when the new standard was adopted, non-attainment areas were not to have been designated
until 2002 and control measures to meet the standard were not to have been

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identified until 2005. In May 1999, the United States Court of Appeals for the District of Columbia Circuit held that Section 109(b)(1) of the Clean Air Act, the section of the Clean
Air Act requiring the promulgation of national ambient air quality standards, as interpreted by the Environmental Protection Agency, was an unconstitutional delegation of legislative power. The Court
of Appeals remanded both the fine particulate matter standard and the revised ozone standard to allow the Environmental Protection Agency to determine whether it could articulate a constitutional
application of Section 109(b)(1). On February 27, 2001, the Supreme Court, inWhitman v. American Trucking Associations, Inc., reversed
the Circuit Court's judgment on this issue and remanded the case back to the Court of Appeals to dispose of any other preserved challenges to the particulate matter and ozone standards. On
March 26, 2002, the District of Columbia Circuit, on remand, held that the revised ozone and fine particulate matter ambient air quality standards were neither arbitrary nor capricious. Further
action by the EPA with respect to the implementation of the revised ozone standard and the promulgation of a new coarse particulate matter standard is required pursuant to the first District of
Columbia Circuit opinion and the Supreme Court's decision inWhitmanv.American Trucking Associations,
Inc.

Because
of the delays resulting from the litigation over the standards, the Environmental Protection Agency is drafting new schedules for implementing the 8-hour ozone and
fine particulate matter (PM 2.5) standards. Pursuant to a negotiated settlement, the EPA has agreed to designate attainment and nonattainment areas under the 8-hour ozone standard in 2004.
The EPA has announced that it also intends to designate attainment and nonattainment areas under the fine particulate matter standard in 2004. Once these designations are published, states will be
required to revise their implementation plans to achieve attainment with the revised standards, which plans are likely to require additional emission reductions from facilities that are significant
emitters of ozone precursors and particulates. Any obligations on EME's facilities to further reduce their emissions of sulfur dioxide, nitrogen oxides and fine particulates as a result of the
8-hour ozone and fine particulate matter standards will not be known until the states revise their implementation plans.

Federal Legislative Initiatives.There have been a number of bills introduced in the last session of Congress and the current
session of Congress that would amend the Clean Air Act to specifically target emissions of certain pollutants from electric utility generating stations. These bills would mandate reductions in
emissions of nitrogen oxides, sulfur dioxide and mercury; some bills would also impose limitations on carbon dioxide emissions. The various proposals differ in many details, including the timing of
any required reductions; the extent of required reductions; and the relationship of any new obligations that would be imposed by these bills with existing legal requirements. There is significant
uncertainty as to whether any of the proposed legislative initiatives will pass in their current form or whether any compromise can be reached that would facilitate passage of legislation.
Accordingly, EME is not able to evaluate the potential impact of these proposals at this time.

Comprehensive Environmental Response, Compensation, and Liability Act.Under various federal, state and local environmental
laws and regulations, a current or previous owner or operator of any facility, including an electric generating facility, may be required to investigate and remediate releases or threatened releases
of hazardous or toxic substances or petroleum products located at that facility, and may be held liable to a governmental entity or to third parties for property damage, personal injury and
investigation and remediation costs incurred by these parties in connection with these releases or

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threatened releases. Many of these laws, including the Comprehensive Environmental Response, Compensation and Liability Act of 1980, commonly referred to as CERCLA, as amended by the Superfund
Amendments and Reauthorization Act of 1986, impose liability without regard to whether the owner knew of or caused the presence of the hazardous substances, and courts have interpreted liability under
these laws to be strict and joint and several. The cost of investigation, remediation or removal of these substances may be substantial. In connection with the ownership and operation of EME's
facilities, EME may be liable for these costs.

In
addition, persons who arrange for the disposal or treatment of hazardous or toxic substances at a disposal or treatment facility may be liable for the costs of removal or remediation
of a release or threatened release of hazardous or toxic substances at that disposal or treatment facility, whether or not that facility is owned or operated by that person. Some environmental laws
and regulations create a lien on a contaminated site in favor of the government for damages and costs it incurs in connection with the contamination. The owner of a contaminated site and persons who
arrange for the disposal of hazardous substances at that site also may be subject to common law claims by third parties based on damages and costs resulting from environmental contamination emanating
from that site. In connection with the ownership and operation of its facilities, EME may be liable for these costs.

With
respect to EME's liabilities arising under CERCLA or similar laws for the investigation and remediation of contaminated property, EME accrues a liability to the extent the costs are
probable and can be reasonably estimated. Generally, EME does not believe the costs for environmental remediation can be reasonably estimated before a remedial investigation has been completed for a
particular site. In connection with due diligence conducted for the acquisition of EME's Illinois Plants, EME engaged a third-party consultant to conduct an assessment of the potential costs for
environmental remediation of the plants. This assessment, which was based on information provided to EME by the former owner of these plants, was less rigorous than a remedial investigation conducted
in the course of a voluntary or required site cleanup.

Midwest
Generation has accrued $2 million for estimated environmental investigation and remediation costs for the Illinois Plants. This estimate is based upon the number of sites,
the scope of work and the estimated range of costs for environmental activity where such expenditures could be reasonably estimated. The midpoint of the range was used for the accrual. Future
estimated costs may vary based on changes in regulations or requirements of federal, state, or local governmental agencies, changes in technology, and actual costs of disposal. Management believes
that future costs in excess of the amounts disclosed on all known and quantifiable environmental contingencies will not be material to EME's financial position.

Enforcement Issues.EME owns an indirect 50% interest in EcoEléctrica, L.P., a limited partnership which owns
and operates a liquefied natural gas import terminal and cogeneration project at Peñuelas, Puerto Rico. In 2000, the U.S. Environmental Protection Agency issued to
EcoEléctrica a notice of violation and a compliance order alleging violations of the Federal Clean Air Act primarily related to start-up activities. Representatives of
EcoEléctrica met with the Environmental Protection Agency at that time to discuss the notice of violations and compliance order. On August 15, 2002, the U.S. Department of
Justice notified EcoEléctrica that it was preparing to bring a federal court action for violations of the Clean Air Act and regulations promulgated thereunder, and requested a meeting
with EcoEléctrica to discuss and possibly settle the matter. The initial meeting with the Department of

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Justice took place on January 15, 2003. EME expects settlement discussions will continue during the first half of 2003.

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, or
NSR, 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 United States Environmental Protection Agency 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 Environmental Protection Agency has also issued requests for information pursuant to the Clean Air Act to numerous other electric utilities, including
the prior owners of the Homer City facilities, seeking to determine whether these utilities also engaged in activities that may have been in violation of the Clean Air Act's NSR requirements.

To
date, several utilities have reached formal agreements with the United States (or reached agreements-in-principle) to resolve alleged NSR violations. All of
the settlements have included the installation of additional pollution controls, supplemental environment projects, and the payment of civil penalties. Some of the settlements have also included the
retirement or repowering of coal-fired generating units. The agreements provide for a phased approach to achieving required emission reductions over the next 10 to 15 years. The
total cost of some of these settlements exceeds $1 billion; the civil penalties agreed to by these utilities range between $1 million and $10 million. Because of the uncertainty
created by the Bush administration's review of the NSR regulations and NSR enforcement proceedings, some of the settlements referred to above have not been finalized. However, in January 2002,
the Department of Justice completed its review and concluded that "the EPA has a reasonable basis for arguing that the enforcement actions are consistent with both the Clean Air Act and the
Administrative Procedure Act." Accordingly, the Department of Justice has continued to prosecute NSR enforcement cases against electric utilities, with some cases scheduled for trial in 2003.

On
December 31, 2002, the Environmental Protection Agency finalized a rule to improve the NSR program. This rule is intended to provide additional flexibility with respect to NSR
by, among other things, modifying the method by which a facility calculates the emissions' increase from a plant modification; exempting, for a period of ten years, units that have complied with NSR
requirements or
otherwise installed pollution control technology that is equivalent to what would have been required by NSR; and allowing a facility to make modifications without being required to comply with NSR if
the facility maintained emissions below plantwide applicability limits. The rule became effective on March 3, 2003, although states, industry groups and environmental organizations have filed
litigation challenging various aspects of the regulation. In addition to this regulation, the Environmental Protection Agency has also proposed a regulation to clarify the "routine maintenance and
repair" exclusion contained in the Environmental Protection Agency's regulations. While EME will carefully evaluate both of these rules to determine impacts on its operations, the proposed rule will
be of greater interest. By more clearly defining "routine maintenance, repair and replacement," this rule will allow EME to determine what investments can be made at its existing plants to improve the
safety, efficiency, and reliability of its operations without triggering NSR permitting requirements.

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Prior
to EME's purchase of the Homer City facilities, the Environmental Protection Agency requested information from the prior owners of the plant concerning physical changes at the
plant. On February 21, 2003, Midwest Generation received a request for information regarding past operations, maintenance and physical changes at the Illinois coal plants from the Environmental
Protection Agency. Other than these requests for information, no proceedings have been initiated with respect to any of EME's United States facilities. Depending on the outcome of Environmental
Protection Agency review and regulatory developments, EME could be required to invest in additional pollution control requirements, over and above the upgrades it is planning to install, and could be
subject to fines and penalties. EME cannot estimate the outcome of these discussions or the potential costs of investing in additional pollution control requirements, fines or penalties at this time.

International

United Nations Framework Convention on Climate Change.Since the adoption of the United Nations Framework Convention on
Climate Change in 1992, there has been worldwide attention with respect to greenhouse gas emissions. In December 1997, the Clinton administration participated in the Kyoto, Japan negotiations,
where the basis of a Climate Change treaty was formulated. Under the treaty, known as the Kyoto Protocol, the United States would be required, by 2008-2012, to reduce its greenhouse gas
emissions by 7% from 1990 levels.

The
Kyoto Protocol has yet to be submitted to the U.S. Senate for ratification. In March 2001, the Bush administration announced that the United States would not ratify the Kyoto
Protocol, but would instead offer an alternative. On February 14, 2002, President Bush announced objectives to slow the growth of greenhouse gas emissions by reducing the amount of greenhouse
gas emissions per unit of economic output by 18% by 2012 and to provide funding for climate-change related programs. The President's proposed program does not include mandatory reductions of
greenhouse gas emissions. However, various bills have been, or are expected to be, introduced in Congress to require greenhouse gas
emissions reductions and to address other issues related to climate change. Apart from the Kyoto Protocol, EME may be impacted by future federal or state legislation relating to controlling greenhouse
gas emissions.

Notwithstanding
the Bush administration position, environment ministers from around the world have reached a compromise agreement on the mechanics and rules of the Kyoto Protocol. The
compromise agreement is believed to clear the way for countries to begin the treaty ratification process.

EME
either has an equity interest in or owns and operates generating plants in the following countries:

 Australia

 Spain Indonesia

 Thailand Italy

 Turkey New Zealand

 The United Kingdom Philippines

 The United States


All
of the countries, with the exception of Indonesia, the Philippines and Thailand, are classified as Annex 1 or "developed" countries and are subject to national greenhouse gas
emission reduction

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targets during the period of 2008-2012 (e.g., Phase 1). Each nation is actively developing policies and measures meant to assist it with meeting the individual national emission targets
as set out within the Kyoto Protocol.

With
the exception of Turkey, all of the countries identified have ratified the UN Framework Convention on Climate Change, as well as signed the Kyoto Protocol. Italy, New Zealand,
Spain, Thailand, and the United Kingdom have also ratified the Kyoto Protocol, and, with the exception of Australia and the United States, all of the other remaining countries are expected to do so by
the end of 2003.

For
the treaty to come into effect, approximately 55 countries that also represent at least 55% of the greenhouse gas emissions of the developed world must ratify it. With Canada
becoming the 100th country to ratify the agreement in December 2002, the Kyoto Protocol can account for 43.7% of carbon dioxide emissions. Russia also indicated at the Johannesburg Summit on
September 2002 its desire to ratify the treaty. Representing 17.4% of the developed world's greenhouse gas emissions, Russian ratification is now essential to bring the treaty into effect.

If
EME does become subject to limitations on emissions of carbon dioxide from its fossil fuel-fired electric generating plants, these requirements could have a significant
economic impact on their operations.

United Nations Proposed Framework Convention on Mercury.The United Nations Environment Programme (UNEP) has convened a
Global Mercury Assessment Working Group which met in Geneva in September 2002 and finalized a global mercury assessment report for submittal to the UNEP Governing Council at the Global
Ministerial Environment Forum in Nairobi, Kenya, February 2003. Based upon the report's key findings, the working group concluded that "there is sufficient evidence of significant global
adverse impacts to warrant international action to reduce the risks to human health and the environment arising from the release of mercury into the environment."

The
United States has indicated that it will support a decision to take international action on mercury at the Global Ministerial Environment Forum. However, the United States has
further stated that it does not support negotiation of a legally-binding convention at this time. In general, the United States approach: 1) agrees that there is sufficient evidence of adverse
impacts of mercury to warrant international action; 2) urges countries to take actions within the context of their national circumstances to identify exposed populations and to reduce
anthropogenic emissions of mercury; 3) recommends the establishment of a "Mercury Program" within UNEP, 4) recommends coordination between UNEP and other international organizations that
work on mercury issues such as the World Health Organization; and 5) asks countries to make voluntary contributions to support efforts of the Mercury Program under UNEP.

If
EME does become subject to limitations on emissions of mercury from its coal-fired electric generating plants, these requirements could have a significant economic impact
on their operations.

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Note 17. Lease Commitments

MEHC and EME lease office space, property and equipment under noncancelable lease agreements that expire in various years through 2063.

Future
minimum payments for operating leases at December 31, 2002, are:

Years Ending December 31,

Operating
Leases2003

$
3412004


3192005


3622006


4442007


481Thereafter


5,057Total future commitments

$
7,004


Operating
lease expense amounted to $233 million, $163 million and $122 million in 2002, 2001 and 2000, respectively.

Sale-Leaseback Transactions

On December 7, 2001, a subsidiary of EME completed a sale-leaseback of EME's Homer City facilities to third-party lessors for an aggregate
purchase price of $1.6 billion, consisting of $782 million in cash and assumption of debt (the fair value of which was $809 million). Under the terms of the 33.67-year
leases, EME's subsidiary is obligated to make semi-annual lease payments on each April 1 and October 1.
If a lessor intends to sell its interest in the Homer City facilities, EME has a right of first refusal to acquire the interest at fair market value. Minimum lease payments (included in the table
above) are $174 million in 2003, $142 million in 2004, $152 million in 2005, $152 million in 2006 and $151 million in 2007. At December 31, 2002, the total
remaining minimum lease payments are $3.2 billion. Lease costs will be levelized over the terms of the leases. The gain on the sale of the facilities has been deferred and is being amortized
over the term of the leases.

On
August 24, 2000, a subsidiary of EME completed a sale-leaseback of EME's Powerton and Joliet power facilities located in Illinois to third-party lessors for an
aggregate purchase price of $1.4 billion. Under the terms of the leases (33.75 years for Powerton and 30 years for Joliet), EME's subsidiary makes semi-annual lease
payments on each January 2 and July 2, which began January 2, 2001. EME guarantees its subsidiary's payments under the leases. If a lessor intends to sell its interest in the
Powerton or Joliet power facility, EME has a right of first refusal to acquire the interest at fair market value. Minimum lease payments (included in the table above) are $97 million in 2003,
$97 million in 2004, $141 million in 2005, $185 million in 2006, and $185 million in 2007. At December 31, 2002, the total remaining minimum lease payments are
$2.2 billion. Lease costs of these power facilities will be levelized over the terms of the respective leases. The gain on the sale of the power facilities has been deferred and is being
amortized over the term of the leases.

In
connection with the acquisition of the Illinois Plants, EME assigned the right to purchase the Collins gas and oil-fired power plant to third-party lessors. The
third-party lessors purchased the Collins Station for $860 million and entered into leases of the plant with EME. The leases, which are being

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accounted for as operating leases, have an initial term of 33.75 years with payments due on a quarterly basis. The base lease rent includes both a fixed and variable component; the variable
component of which is impacted by movements in defined short-term interest rate indexes. Under the terms of the leases, EME may request a lessor, at its option, to refinance the lessor's
debt, which if completed would impact the base lease rent. If a lessor intends to sell its interest in the Collins Station, EME has a first right of refusal to acquire the facility at fair market
value. Minimum lease payments (included in the table above) are $40 million in 2003, $52 million in 2004, $50 million in 2005, $90 million in 2006 and $129 million
in 2007. At December 31, 2002, the total remaining minimum lease payments were $1.4 billion.

Note 18. Related Party Transactions

Specified administrative services such as payroll and employee benefit programs, all performed by Edison International or Southern California Edison Company
employees, are shared among all affiliates of Edison International, and the costs of these corporate support services are allocated to all affiliates, including MEHC. Costs are allocated based on one
of the following formulas: percentage of time worked, equity in investment and advances, number of employees, or multi-factor (operating revenues, operating expenses, total assets and number of
employees). In addition, services of Edison International or Southern California Edison employees are sometimes directly requested by MEHC and these services are performed for MEHC's benefit. Labor
and expenses of these directly requested services are specifically identified and billed at cost. MEHC believes the allocation methodologies
utilized are reasonable. MEHC made reimbursements for the cost of these programs and other services, which amounted to $53 million, $71 million and $65 million in 2002, 2001 and
2000, respectively. Accounts payableaffiliates associated with these administrative services totaled $12 million at December 31, 2002 and 2001.

MEHC
participates in the insurance program of Edison International, including property, general liability, workers compensation and various other specialty policies. MEHC's insurance
premiums are generally based on MEHC's share of risk related to each policy. In connection with the property insurance program, a portion of the risk is reinsured by a captive insurance subsidiary of
Edison International. Under these reinsurance policies, MEHC is entitled to receive a premium refund to the extent that MEHC's loss experience is less than estimated.

MEHC
records accruals for tax liabilities and/or tax benefits which are settled quarterly according to a series of tax-allocation agreements as described in Note 2.
Under these agreements, MEHC recognized tax benefits applicable to continuing operations of $258 million, $36 million and $226 million for 2002, 2001 and 2000, respectively. See
Note 13Income Taxes. Amounts included in Accounts receivableaffiliates associated with these tax benefits totaled $30 million and $254 million at
December 31, 2002 and 2001, respectively.

Edison
Mission Operation & Maintenance, Inc., an indirect, wholly owned affiliate of EME, has entered into operation and maintenance agreements with partnerships in which
EME has a 50% or less ownership interest. Pursuant to the negotiated agreements, Edison Mission Operation & Maintenance is to perform all operation and maintenance activities necessary for the
production of power by these partnerships' facilities. The agreements continue until terminated by either party. Edison Mission Operation & Maintenance is paid for all costs incurred with
operating and maintaining such facilities

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and may also earn an incentive compensation as set forth in the agreements. EME recorded revenues under the operation and maintenance agreements of $22 million, $24 million and
$28 million in 2002, 2001 and 2000, respectively. Accounts receivableaffiliates for Edison Mission Operation & Maintenance totaled $7 million and $6 million at
December 31, 2002 and 2001, respectively.

Specified
EME subsidiaries have ownership in partnerships that sell electricity generated by their project facilities to Southern California Edison Company and others under the terms of
long-term power purchase agreements. Sales by these partnerships to Southern California Edison Company under these agreements amounted to $548 million, $983 million and
$716 million in 2002, 2001 and 2000, respectively.

Note 19. Supplemental Statements of Cash Flows Information

|                               |                                      | Years Ended December 31, |   
|------------------------------ | ------------------------------------ | ------------------------ | --
|
|Cash paid                      |                                      |                          |   
|                               | Interest (net of amount capitalized) |                          | $ 
|                               | Income taxes (receipts)              |                          | $ 
|Details of assets acquired     |                                      |                          |   
|                               | Fair value of assets acquired        |                          | $ 
|                               | Liabilities assumed                  |                          |   
|                               |                                      |                          |   
|Net cash paid for acquisitions |                                      | $                        | 16
|                               |                                      |                          |   

Note 20. Business Segments

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

Electric
power and steam generated in the United States is sold primarily under (1) long-term contracts, with terms of 15 to 30 years, to domestic electric
utilities and industrial steam users, (2) through a centralized power pool, or (3) under three power purchase agreements with Commonwealth Edison, which assigned its rights and
obligations under these power purchase agreements to Exelon Generation Company, which began December 15, 1999 and have a term of up to five years. EME currently derives a significant source of
its revenues from the sale of energy and capacity to Exelon Generation Company under these power purchase agreements. EME's revenues from Commonwealth Edison were
$1.1 billion for each of the years ended December 31, 2002, 2001 and 2000, respectively. This represents 41%, 43% and 49% of EME's consolidated revenues in 2002, 2001 and 2000,
respectively. Commonwealth Edison revenues are included in the Americas region shown below.

The
Loy Yang B power plant and the Valley Power Peaker power plant both located in Australia sell their energy and capacity production through a centralized power pool by entering into
short and/or long-term contracts to hedge against the volatility of price fluctuations in the pool. The First

189

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Hydro power plants located in the United Kingdom sell their energy and capacity production by entering into physical bilateral contracts with various counterparties. Other electric power generated
overseas is sold under short and/or long-term contracts to either electricity companies, electricity buying groups or electric utilities located in the country where the power is
generated. Intercompany transactions have been eliminated in the following segment information.

|                                                                                   |                               | Americas |       | Asia
Pacific |   | Europe |       | Corporate/
Other |       | Total |  
|---------------------------------------------------------------------------------- | ----------------------------- | -------- | ----- | ------------ | - | ------ | ----- | ---------------- | ----- | ----- | -
|2002                                                                               |                               |          |       |              |   |        |       |                  |       |       |  
|Operating revenues from consolidated subsidiaries                                  |                               | $        | 1,564 |              | $ | 707    |       | $                | 452   |       | $
|Net gains (losses) from price risk management and energy trading                   |                               |          | 39    |              |   | (1     | )     |                  | (9    | )     |  
|                                                                                   |                               |          |       |              |   |        |       |                  |       |       |  
|                                                                                   | Total operating revenues      |          |       | 1,603        |   |        | 706   |                  |       | 443   |  
|                                                                                   |                               |          |       |              |   |        |       |                  |       |       |  
|Fuel, plant operations and transmission costs, and plant operating leases,         |                               |          | 1,209 |              |   | 419    |       |                  | 313   |       |  
|Depreciation and amortization                                                      |                               |          | 139   |              |   | 68     |       |                  | 34    |       |  
|Long-term incentive compensation                                                   |                               |          |      |              |   |       |       |                  |      |       |  
|Settlement of postretirement employee benefit liability                            |                               |          | (71   | )            |   |       |       |                  |      |       |  
|Asset impairment and other charges                                                 |                               |          | 131   |              |   |       |       |                  |      |       |  
|Administrative and general                                                         |                               |          | 46    |              |   | 17     |       |                  | 17    |       |  
|                                                                                   |                               |          |       |              |   |        |       |                  |       |       |  
|                                                                                   | Income (loss) from operations |          |       | 149          |   |        | 202   |                  |       | 79    |  
|                                                                                   |                               |          |       |              |   |        |       |                  |       |       |  
|Equity in income from unconsolidated affiliates                                    |                               |          | 207   |              |   | 36     |       |                  | 40    |       |  
|Interest and other income                                                          |                               |          | 7     |              |   | 2      |       |                  |      |       |  
|Gain on sale of assets                                                             |                               |          |      |              |   |       |       |                  | 5     |       |  
|Interest expense                                                                   |                               |          | 16    |              |   | (92    | )     |                  | (74   | )     |  
|Dividends on preferred securities                                                  |                               |          |      |              |   | (7     | )     |                  |      |       |  
|                                                                                   |                               |          |       |              |   |        |       |                  |       |       |  
|                                                                                   | Total other income (expense)  |          |       | 230          |   |        | (61   | )                |       | (29   | )
|                                                                                   |                               |          |       |              |   |        |       |                  |       |       |  
|Income (loss) from continuing operations before income taxes and minority interest |                               | $        | 379   |              | $ | 141    |       | $                | 50    |       | $
|                                                                                   |                               |          |       |              |   |        |       |                  |       |       |  
|Identifiable assets                                                                |                               | $        | 4,233 |              | $ | 2,992  |       | $                | 2,038 |       | $
|Assets of discontinued operations                                                  |                               |          |      |              |   |       |       |                  | 10    |       |  
|Equity investments and advances                                                    |                               |          | 950   |              |   | 580    |       |                  | 115   |       |  
|                                                                                   |                               |          |       |              |   |        |       |                  |       |       |  
|                                                                                   | Total assets                  |          | $     | 5,183        |   | $      | 3,572 |                  | $     | 2,163 |  
|                                                                                   |                               |          |       |              |   |        |       |                  |       |       |  
|Additions to property and plant                                                    |                               | $        | 493   |              | $ | 56     |       | $                | 2     |       | $

190

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|                                                                                   |                               | Americas |       | Asia
Pacific |   | Europe |       | Corporate/
Other |       | Total |  
|---------------------------------------------------------------------------------- | ----------------------------- | -------- | ----- | ------------ | - | ------ | ----- | ---------------- | ----- | ----- | -
|2001                                                                               |                               |          |       |              |   |        |       |                  |       |       |  
|Operating revenues from consolidated subsidiaries                                  |                               | $        | 1,617 |              | $ | 464    |       | $                | 369   |       | $
|Net gains (losses) from price risk management and energy trading                   |                               |          | 35    |              |   | (4     | )     |                  | 3     |       |  
|                                                                                   |                               |          |       |              |   |        |       |                  |       |       |  
|                                                                                   | Total operating revenues      |          |       | 1,652        |   |        | 460   |                  |       | 372   |  
|                                                                                   |                               |          |       |              |   |        |       |                  |       |       |  
|Fuel, plant operations and transmission costs, and plant operating leases,         |                               |          | 1,166 |              |   | 266    |       |                  | 250   |       |  
|Depreciation and amortization                                                      |                               |          | 166   |              |   | 54     |       |                  | 35    |       |  
|Long-term incentive compensation                                                   |                               |          |      |              |   |       |       |                  |      |       |  
|Asset impairment and other charges                                                 |                               |          | 59    |              |   |       |       |                  |      |       |  
|Administrative and general                                                         |                               |          | 46    |              |   | 12     |       |                  | 15    |       |  
|                                                                                   |                               |          |       |              |   |        |       |                  |       |       |  
|                                                                                   | Income (loss) from operations |          |       | 215          |   |        | 128   |                  |       | 72    |  
|                                                                                   |                               |          |       |              |   |        |       |                  |       |       |  
|Equity in income from unconsolidated affiliates                                    |                               |          | 351   |              |   | 8      |       |                  | 15    |       |  
|Interest and other income                                                          |                               |          | 8     |              |   |       |       |                  | 7     |       |  
|Gain on sale of assets                                                             |                               |          | 43    |              |   | (2     | )     |                  |      |       |  
|Gain on early extinguishment of debt                                               |                               |          | 10    |              |   |       |       |                  |      |       |  
|Interest expense                                                                   |                               |          | (70   | )            |   | (73    | )     |                  | (74   | )     |  
|Dividends on preferred securities                                                  |                               |          |      |              |   | (8     | )     |                  |      |       |  
|                                                                                   |                               |          |       |              |   |        |       |                  |       |       |  
|                                                                                   | Total other income (expense)  |          |       | 342          |   |        | (75   | )                |       | (52   | )
|                                                                                   |                               |          |       |              |   |        |       |                  |       |       |  
|Income (loss) from continuing operations before income taxes and minority interest |                               | $        | 557   |              | $ | 53     |       | $                | 20    |       | $
|                                                                                   |                               |          |       |              |   |        |       |                  |       |       |  
|Identifiable assets                                                                |                               | $        | 3,742 |              | $ | 2,511  |       | $                | 1,759 |       | $
|Assets of discontinued operations                                                  |                               |          |      |              |   |       |       |                  | 319   |       |  
|Equity investments and advances                                                    |                               |          | 1,166 |              |   | 563    |       |                  | 101   |       |  
|                                                                                   |                               |          |       |              |   |        |       |                  |       |       |  
|                                                                                   | Total assets                  |          | $     | 4,908        |   | $      | 3,074 |                  | $     | 2,179 |  
|                                                                                   |                               |          |       |              |   |        |       |                  |       |       |  
|Additions to property and plant                                                    |                               | $        | 142   |              | $ | 67     |       | $                | 13    |       | $

191

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|                                                                                   |                               | Americas |       | Asia
Pacific |   | Europe |       | Corporate/
Other |       | Total |  
|---------------------------------------------------------------------------------- | ----------------------------- | -------- | ----- | ------------ | - | ------ | ----- | ---------------- | ----- | ----- | -
|2000                                                                               |                               |          |       |              |   |        |       |                  |       |       |  
|Operating revenues from consolidated subsidiaries                                  |                               | $        | 1,571 |              | $ | 184    |       | $                | 450   |       | $
|Net gains (losses) from price risk management and energy trading                   |                               |          | (17   | )            |   |       |       |                  |      |       |  
|                                                                                   |                               |          |       |              |   |        |       |                  |       |       |  
|                                                                                   | Total operating revenues      |          |       | 1,554        |   |        | 184   |                  |       | 450   |  
|                                                                                   |                               |          |       |              |   |        |       |                  |       |       |  
|Fuel, plant operations and transmission costs, and plant operating leases,         |                               |          | 1,132 |              |   | 61     |       |                  | 213   |       |  
|Depreciation and amortization                                                      |                               |          | 189   |              |   | 38     |       |                  | 37    |       |  
|Long-term incentive compensation                                                   |                               |          |      |              |   |       |       |                  |      |       |  
|Administrative and general                                                         |                               |          | 25    |              |   | 16     |       |                  | 16    |       |  
|                                                                                   |                               |          |       |              |   |        |       |                  |       |       |  
|                                                                                   | Income (loss) from operations |          |       | 208          |   |        | 69    |                  |       | 184   |  
|                                                                                   |                               |          |       |              |   |        |       |                  |       |       |  
|Equity in income from unconsolidated affiliates                                    |                               |          | 257   |              |   | 16     |       |                  | (5    | )     |  
|Interest and other income                                                          |                               |          | 5     |              |   | (2     | )     |                  | 4     |       |  
|Gain on sale of assets                                                             |                               |          | 17    |              |   | 9      |       |                  |      |       |  
|Interest expense                                                                   |                               |          | (184  | )            |   | (66    | )     |                  | (80   | )     |  
|Dividends on preferred securities                                                  |                               |          |      |              |   | (18    | )     |                  |      |       |  
|                                                                                   |                               |          |       |              |   |        |       |                  |       |       |  
|                                                                                   | Total other income (expense)  |          |       | 95           |   |        | (61   | )                |       | (81   | )
|                                                                                   |                               |          |       |              |   |        |       |                  |       |       |  
|Income (loss) from continuing operations before income taxes and minority interest |                               | $        | 303   |              | $ | 8      |       | $                | 103   |       | $
|                                                                                   |                               |          |       |              |   |        |       |                  |       |       |  
|Identifiable assets                                                                |                               | $        | 5,607 |              | $ | 1,409  |       | $                | 1,773 |       | $
|Assets of discontinued operations                                                  |                               |          |      |              |   |       |       |                  | 3,574 |       |  
|Equity investments and advances                                                    |                               |          | 952   |              |   | 1,049  |       |                  | 86    |       |  
|                                                                                   |                               |          |       |              |   |        |       |                  |       |       |  
|                                                                                   | Total assets                  |          | $     | 6,559        |   | $      | 2,458 |                  | $     | 5,433 |  
|                                                                                   |                               |          |       |              |   |        |       |                  |       |       |  
|Additions to property and plant                                                    |                               | $        | 294   |              | $ | 4      |       | $                | 17    |       | $

During
2002, MEHC changed its presentation of segment performance by presenting the measure of profit or loss for each reportable segment as income (loss) from continuing operations
before income taxes and minority interest compared to income (loss) from operations as reported in 2001 and 2000.

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Geographic Information

Foreign operating revenues and assets by country included in the table above are shown below.

|                   |                | Years Ended December 31,
|------------------ | -------------- | ------------------------
|
|Operating revenues |                |                         
|                   | Australia      |                         
|                   | New Zealand    |                         
|                   |                |                         
|Total Asia Pacific |                | $                       
|                   |                |                         
|                   | United Kingdom |                         
|                   | Turkey         |                         
|                   | Spain          |                         
|                   |                |                         
|Total Europe       |                | $                       
|                   |                |                         

|                   |                    | December 31,
|------------------ | ------------------ | ------------
|
|Assets             |                    |             
|                   | Australia          |             
|                   | New Zealand        |             
|                   | Indonesia          |             
|                   | Other Asia Pacific |             
|                   |                    |             
|Total Asia Pacific |                    | $           
|                   |                    |             
|                   | United Kingdom(1)  |             
|                   | Turkey             |             
|                   | Spain              |             
|                   | Italy              |             
|                   | Other Europe       |             
|                   |                    |             
|Total Europe       |                    | $           
|                   |                    |             

---

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Note 21. Quarterly Financial Data (unaudited)

Amounts reported below are different from those previously reported on Form 10-Q because the results of Lakeland have been classified as
discontinued operations for all historical periods presented and the reclassification of equity in income of unconsolidated affiliates from operating revenues to other income (expense). For more
information on Lakeland, see Note 7Discontinued Operations.

|2002                                                              |  | First(i) |     | Second |   | Third(i) |   | Fourth(i) |     | Total |  
|----------------------------------------------------------------- |  | -------- | --- | ------ | - | -------- | - | --------- | --- | ----- | -
|Operating revenues                                                |  | $        | 537 |        | $ | 673      |   | $         | 954 |       | $
|Operating income (loss)                                           |  |          | (13 | )      |   | 73       |   |           | 251 |       |  
|Income (loss) from continuing operations before accounting change |  |          | (63 | )      |   | (29      | ) |           | 132 |       |  
|Discontinued operations, net                                      |  |          | 5   |        |   | 9        |   |           | 7   |       |  
|Net income (loss)                                                 |  |          | (72 | )      |   | (20      | ) |           | 139 |       |  

|2001                                                              |  | First(i) |     | Second |   | Third(i) |   | Fourth(i) |        | Total  |  
|----------------------------------------------------------------- |  | -------- | --- | ------ | - | -------- | - | --------- | ------ | ------ | -
|Operating revenues                                                |  | $        | 482 |        | $ | 585      |   | $         | 924    |        | $
|Operating income (loss)                                           |  |          | 22  |        |   | 79       |   |           | 300    |        |  
|Income (loss) from continuing operations before accounting change |  |          | (15 | )      |   | 37       |   |           | 138    |        |  
|Discontinued operations, net                                      |  |          | 23  |        |   | (37      | ) |           | (1,204 | )(iii) |  
|Net income (loss)                                                 |  |          | 8   |        |   |         |   |           | (1,050 | )(iii) |  

---

194

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PART III

ITEM 10. DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANT

Positions with Mission Energy Holding Company

Listed below are MEHC's current directors and executive officers and their ages and positions as of March 27, 2003.

|Name, Position and Age                                                          |  | Director
Continuously
Since |  | Term
Expires |  | Position Held
Continuously
Since |  | Term
Expires
|------------------------------------------------------------------------------- |  | --------------------------- |  | ------------ |  | -------------------------------- |  | ------------
|John E. Bryson, 59
    Director, Chairman of the Board                          |  | 2001                        |  | 2003         |  |                                 |  |            
|Frank B. Bilotta, 42
    Director                                               |  | 2001                        |  | 2003         |  |                                 |  |            
|Bryant C. Danner, 65
    Director                                               |  | 2001                        |  | 2003         |  |                                 |  |            
|Theodore F. Craver, Jr., 51
    Director, Chief Executive Officer and President |  | 2001                        |  | 2003         |  | 2001                             |  | 2003        
|Barbara Mathews, 50
    Secretary and Assistant General Counsel                 |  |                            |  |             |  | 2001                             |  | 2003        
|Kevin M. Smith, 45
    Senior Vice President and Chief Financial Officer        |  |                            |  |             |  | 2001                             |  | 2003        
|Raymond W. Vickers, 60
    Senior Vice President and General Counsel            |  |                            |  |             |  | 2001                             |  | 2003        

Business Experience

Below is a description of the principal business experience during the past five years of each of the individuals named above and the name of each public company
in which any director named above is a director.

Mr. Brysonhas been director and chairman of the board of Mission Energy Holding Company since June 2001. Since January 2003,
Mr. Bryson has been chairman of the board, president and chief executive officer of Edison International and chairman of the board of Southern California Edison. Mr. Bryson was director
and chairman of the board of Edison Mission Energy from January 2000 through December 2002. Mr. Bryson was director of Edison Mission Energy from January 1986 to January 1998. Mr. Bryson
was chairman of the board, president and chief executive officer of Edison International since January 2000 through December 2002. He served as chairman of the board and chief executive officer of
Edison International and Southern California Edison from 1990 through 1999. Mr. Bryson has been a director of Edison International since 1990. Mr. Bryson was a director of Southern
California Edison from 1990 through 1999 and from January 2003 to date. Mr. Bryson is a
director of The Boeing Company, Pacific American Income Shares, Inc. & Western Asset Funds, Inc., and The Walt Disney Company.

Mr. Bilottahas been director of Mission Energy Holding Company since June 2001 and serves as Mission Energy Holding Company's
independent director. Mr. Bilotta has over 16 years of diversified accounting and legal experience with an emphasis in asset-backed securities. Prior to joining Global Securitization Services
in September of 2000, Mr. Bilotta served as senior vice president at Lord Securities Corporation. He also served as an independent director on a variety of structured finance

195

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vehicles. Mr. Bilotta served as manager of Securitized Debt at Morgan Stanley & Co. Incorporated prior to joining Lord Securities in December 1996. He was vice president at Lehman
Brothers Inc. prior to joining Morgan Stanley in 1995.

Mr. Dannerhas been director of Mission Energy Holding Company since June 2001. Mr. Danner has been director of Edison
Mission Energy since May 1993. Mr. Danner has been executive vice president and general counsel of Edison International since June 1995. Mr. Danner was executive vice president and
general counsel of Southern California Edison from June 1995 until January 2000.

Mr. Craverhas been director, chief executive officer and president of Mission Energy Holding Company since June 2001.
Mr. Craver has been director of Edison Mission Energy since January 2001. Since January 2002, Mr. Craver has been executive vice president of Edison International. Mr. Craver has
been senior vice president, chief financial officer, and treasurer of Edison International since January 2000. Mr. Craver has been chairman of the board and chief executive officer of Edison
Enterprises since September 1999. Mr. Craver served as senior vice president and treasurer of Edison International from February 1998 to January 2000. Mr. Craver served as senior vice
president and treasurer of Southern California Edison from February 1998 to September 1999. Mr. Craver served as vice president and treasurer of Edison International and Southern California
Edison from September 1996 to February 1998.

Ms. Mathewshas been secretary and assistant general counsel of Mission Energy Holding Company since June 2001. Ms. Mathews
has been assistant general counsel of Edison International and Southern California Edison since August 1996.

Mr. Smithhas been senior vice president and chief financial officer of Mission Energy Holding Company since September 2001.
Mr. Smith has been senior vice president and chief financial officer of Edison Mission Energy since May 1999. Mr. Smith served as treasurer of Edison Mission Energy from 1992 to 2000 and
was elected a vice president in 1994. During March 1998 until September 1999, Mr. Smith also held the position of regional vice president of the Americas region.

Mr. Vickershas been senior vice president and general counsel of Mission Energy Holding Company since June 2001.
Mr. Vickers has been senior vice president and general counsel of Edison Mission Energy since March 1999. Prior to joining Edison Mission Energy, Mr. Vickers was a partner with the law
firm of Skadden, Arps, Slate, Meagher & Flom LLP concentrating on international business transactions, particularly cross-border capital markets and investment transactions, project
implementation and finance.

ITEM 11. EXECUTIVE COMPENSATION

MEHC officers receive compensation from EME or Edison International and receive no compensation from MEHC. For information concerning the chief executive officer
and four most highly paid executive officers, other than the chief executive officer, of EME and Edison International, see Item 11 of EME's Form 10-K for the year ended
December 31, 2002 and the Summary Compensation Table in the Executive Compensation section of Edison International's Proxy Statement relating to its 2003 Annual Meeting of Shareholders,
respectively, which are incorporated by reference.

Compensation of Directors

MEHC's directors do not receive any compensation for serving on its board of directors or attending meetings, thereof, except that MEHC's independent director,
Frank B. Bilotta, receives customary compensation. During 2002, Mr. Bilotta received an annual fee of $3,500 for providing independent directorship services.

196

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ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT

Certain Beneficial Owners

Set forth below is certain information regarding each person who is known to MEHC to be the beneficial owner of more than five percent of MEHC's common stock.

|Title of Class             |  | Name and Address
of Beneficial Owner                                           |  | Amount and Nature of
Beneficial Ownership                                 |  | Percent of Class |  
|-------------------------- |  | ------------------------------------------------------------------------------ |  | ------------------------------------------------------------------------- |  | ---------------- | -
|Common Stock, no par value |  | The Mission Group
18101 Von Karman Avenue,
Suite 1700
Irvine, California 92612 |  | 1,000 shares held directly and with exclusive voting and investment power |  | 100              | %

For
information concerning the number of equity securities of Edison International beneficially owned by all directors and executive officers of EME and Edison International,
individually and as a group, see Item 12 of EME's Form 10-K for the year ended December 31, 2002 and the table entitled "Stock Ownership of Directors and Executive Officers" of
Edison International's Proxy Statement relating to its 2003 Annual Meeting of Shareholders, respectively, which are incorporated by reference.

ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS

Effective August 1, 2002, Edison International entered into a consulting agreement with Mr. Heller. Pursuant to the agreement, Mr. Heller
agreed to provide consulting services in connection with Edison International's business affairs with which he became familiar while employed by Edison International or any of its affiliates. For such
services, Edison International paid a retainer of $100,000 in 2002 and agreed to pay $200 per hour for up to 40 hours monthly for the first six months of the contract, and for up to 20 hours monthly
for the second six months. No additional amounts were paid for hourly services in 2002.

Other Management Transactions

In July 1999, EME made an interest-free loan to Georgia R. Nelson, who at that time was senior vice president of EME and president of Midwest
Generation in the amount of $179,800 in exchange for a note executed by Ms. Nelson and payable to EME 365 days following the conclusion of her assignment in Chicago, Illinois.

ITEM 14. CONTROLS AND PROCEDURES

Under the Sarbanes-Oxley Act of 2002 and implementing rules and regulations adopted by the Securities and Exchange Commission (SEC), MEHC must maintain disclosure
controls and procedures. The term "disclosure controls and procedures" is defined in the SEC's regulations to mean, as applied to MEHC, controls and other procedures that are designed to ensure that
information required to be disclosed by MEHC in reports filed with the SEC is recorded, processed, summarized, and reported within the time frames specified in the SEC's rules and forms. Disclosure
controls and procedures include, without limitation, controls and procedures designed to ensure that information required to be disclosed by MEHC in its SEC reports is accumulated and communicated to
MEHC's management, including its Chief Executive Officer and its Chief Financial Officer, as appropriate to allow timely decisions regarding disclosure. The SEC's regulations also require MEHC to
carry out evaluations, under the supervision and with the participation of MEHC's management, including its Chief Executive Officer and its Chief Financial Officer, of the effectiveness of the design
and operation of MEHC's disclosure controls and procedures. These evaluations must be carried out within the 90-day period prior to the filing date of certain reports, including this
annual report on Form 10-K.

197

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The
Chief Executive Officer and the Chief Financial Officer of MEHC have evaluated the effectiveness of the design and operation of MEHC's disclosure controls and procedures as of
March 20, 2003. They have concluded that those disclosure controls and procedures, as of the evaluation date, were effective in ensuring that information required to be disclosed by MEHC in its
reports filed with the SEC was (1) accumulated and communicated to MEHC's management, as appropriate to allow timely decisions regarding disclosure, and (2) recorded, processed,
summarized, and reported within the time frames specified in the SEC's rules and forms.

The
Chief Executive Officer and the Chief Financial Officer of MEHC also have concluded that there were no significant changes in MEHC's internal controls or in other factors that could
significantly affect those controls subsequent to the date of their evaluation, including any corrective actions with regard to significant deficiencies and material weaknesses.

198

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PART IV

ITEM 15. EXHIBITS, FINANCIAL STATEMENT SCHEDULES AND REPORTS ON FORM 8-K

(a)  (1)
List of Financial Statements

See
Index to Consolidated Financial Statements at Item 8 of this report.



The
following items are filed as a part of this report pursuant to Item 14(d) of Form 10-K:

PageInvestment in Unconsolidated Affiliates Financial Statements:California Power Group Combined Financial Statements as of December 31, 2002, 2001 and 2000

212Watson Cogeneration Company Financial Statements as of December 31, 2002, 2001 and 2000

229CPC Cogeneration LLC Financial Statements as of December 31, 2002, 2001 and 2000

239Four Star Oil & Gas Company Consolidated Financial Statements as of December 31, 2002, 2001 and 2000

246Midway-Sunset Cogeneration Company Financial Statements as of December 31, 2002, 2001 and 2000

262March Point Cogeneration Company Financial Statements as of December 31, 2002, 2001 and 2000

276EcoEléctrica Holdings, Ltd. and Subsidiaries Consolidated Financial Statements as of December 31, 2002, 2001 and 2000

288Gordonsville Energy, L.P. Financial Statements as of December 31, 2002, 2001 and 2000

309Brooklyn Navy Yard Cogeneration Partners, L.P. Financial Statements as of December 31, 2002, 2001 and 2000

322PT Paiton Energy Financial Statements as of December 31, 2002, 2001 and 2000

338Schedule ICondensed Financial Information of Parent

369Schedule IIValuation and Qualifying Accounts

372


All
other schedules have been omitted since the required information is not present in amounts sufficient to require submission of the schedule, or because the required information is
included in the consolidated financial statements or notes thereto.



The
registrant filed the following reports on Form 8-K during the quarter ended December 31, 2002.

Date of Report

Date Filed

Item(s) ReportedOctober 1, 2002

October 3, 2002

5November 19, 2002

November 27, 2002

5


199

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|Exhibit No. |  | Description                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                            
|----------- |  | -----------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
|2.1         |  | Agreement for the sale and purchase of shares in First Hydro Limited, dated December 21, 1995, between PSB Holding Limited and First Hydro Finance Plc, incorporated by reference to Exhibit 2.1 to Edison Mission
Energy's Form 8-K dated December 21, 1995.                                                                                                                                                                                                                                                                                                                                                                                                          
|2.2         |  | Transaction Implementation Agreement, dated March 29, 1997, between The State Electricity Commission of Victoria, Edison Mission Energy Australia Limited, Loy Yang B Power Station Pty Ltd, Loy Yang Power Limited, The Honorable Alan Robert
Stockdale, Leanne Power Pty Ltd and Edison Mission Energy, incorporated by reference to Exhibit 2.2 to Edison Mission Energy's Form 8-K dated May 22, 1997.                                                                                                                                                                                                                                                             
|2.3         |  | Stock Purchase and Assignment Agreement, dated December 23, 1998, between KES Puerto Rico, L.P., KENETECH Energy Systems, Inc., KES Bermuda, Inc. and Edison Mission Energy del Caribe for the (i) sale and purchase of KES Puerto Rico, L.P.'s
shares in EcoEléctrica Holdings Ltd.; (ii) assignment of KENETECH Energy Systems' rights and interests in that certain Project Note from the Partnership; and (iii) assignment of KES Bermuda, Inc.'s rights and interests in that
certain Administrative Services Agreement dated October 31 1997, incorporated by reference to Exhibit 2.3 to Edison Mission Energy's Form 10-K for the year ended December 31, 1998.
|2.4         |  | Asset Purchase Agreement, dated August 1, 1998, between Pennsylvania Electric Company, NGE Generation, Inc., New York State Electric & Gas Corporation and Mission Energy Westside, Inc., incorporated by reference to Exhibit 2.4 to Edison
Mission Energy's Form 10-K for the year ended December 31, 1998.                                                                                                                                                                                                                                                                                                                                                          
|2.5         |  | Asset Sale Agreement, dated March 22, 1999, between Commonwealth Edison Company and Edison Mission Energy as to the Fossil Generating Assets, incorporated by reference to Exhibit 2.5 to Edison Mission Energy's Form 10-K for the year
ended December 31, 1998.                                                                                                                                                                                                                                                                                                                                                                                                      
|2.6         |  | Agreement for the Sale and Purchase of Shares in Contact Energy Limited, dated March 10, 1999, between Her Majesty the Queen in Right of New Zealand, Edison Mission Energy Taupo Limited and Edison Mission Energy, incorporated by reference to
Exhibit 2.6 to the Edison Mission Energy's Form 10-Q for the quarter ended March 31, 1999.                                                                                                                                                                                                                                                                                                                           
|2.9         |  | Purchase and Sale Agreement, dated May 10, 2000, between Edison Mission Energy, P & L Coal Holdings Corporation and Gold Fields Mining Corporation, incorporated by reference to Exhibit 2.9 to Edison Mission Energy's 10-Q for the quarter
ended September 30, 2000.                                                                                                                                                                                                                                                                                                                                                                                                 
|2.10        |  | Asset Purchase Agreement dated 3 March 2000 between MEC International B.V. and UPC International Partnership CV II, incorporated by reference to Exhibit 10.80 to Edison Mission Energy's Form 10-Q for the quarter ended March 31,
2000.                                                                                                                                                                                                                                                                                                                                                                                                                              
|2.11        |  | Stock Purchase Agreement, dated November 17, 2000 between Mission Del Sol, LLC and Texaco Inc., incorporated by reference to Exhibit 2.11 to Edison Mission Energy's Form 10-K for the year ended December 31, 2000.                                                                                                                                                                                                                                                                                                                                                                                                                                                   
|2.12        |  | Agreement relating to the sale and purchase of the business carried on at Fiddler's Ferry Power Station, Warrington, Cheshire, dated October 6, 2001, among Edison First Power Limited, AEP Energy Services UK Generation Limited, AEPR Global Holland
Holding BV, and American Electric Power Company, Inc., incorporated by reference to Exhibit 2.12 to Edison Mission Energy's Form 8-K dated December 21, 2001.                                                                                                                                                                                                                                                   
|            |  |                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                        

200

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|2.13 |  | Agreement relating to the sale and purchase of the business carried on at Ferrybridge "C" Power Station, Knottingley, West Yorkshire, dated October 6, 2001, among Edison First Power Limited, AEP Energy Services UK Generation Limited, AEPR Global
Holland Holding BV, and American Electric Power Company, Inc., incorporated by reference to Exhibit 2.13 to Edison Mission Energy's Form 8-K dated December 21, 2001.                                                                                           
|---- |  | ----------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
|3.1  |  | Amended and Restated Certificate of Incorporation, as amended, of Mission Energy Holding Company, incorporated by reference to Exhibit 3.1 to Mission Energy Holding Company's Registration Statement on Form S-4 to the Securities and Exchange
Commission on August 29, 2001.                                                                                                                                                                                                                                       
|3.2  |  | By-laws of Mission Energy Holding Company, incorporated by reference to Exhibit 3.2 to Mission Energy Holding Company's Registration Statement on Form S-4 to the Securities and Exchange Commission on August 29, 2001.                                                                                                                                                                                                                                                                                              
|3.3  |  | Certificate of Incorporation of Edison Mission Energy dated August 14, 2001, incorporated by reference to Exhibit 3.1 to Edison Mission Energy's Form 8-K dated October 26, 2001.                                                                                                                                                                                                                                                                                                                                     
|3.4  |  | By-Laws of Edison Mission Energy, dated August 15, 2001, incorporated by reference to Exhibit 3.2 to Edison Mission Energy's Form 8-K dated October 26, 2001.                                                                                                                                                                                                                                                                                                                                                         
|4.1  |  | Indenture, dated as of July 2, 2001, by and between Mission Energy Holding Company and Wilmington Trust Company with respect to $900 million aggregate principal amount of 13.50% Senior Secured Notes due 2008, incorporated by reference to
Exhibit 4.1 to Mission Energy Holding Company's Registration Statement on Form S-4 to the Securities and Exchange Commission on August 29, 2001.                                                                                                                        
|4.2  |  | Registration Rights Agreement, dated as of July 2, 2001, by and between Mission Energy Holding Company and Goldman, Sachs & Co., incorporated by reference to Exhibit 4.2 to Mission Energy Holding Company's Registration Statement on
Form S-4 to the Securities and Exchange Commission on August 29, 2001.                                                                                                                                                                                                        
|4.3  |  | Indenture Escrow and Security Agreement, dated as of July 2, 2001, by and among Mission Energy Holding Company, Wilmington Trust Company, as Trustee, and Wilmington Trust Company, as Indenture Escrow Agent, incorporated by reference to
Exhibit 4.3 to Mission Energy Holding Company's Registration Statement on Form S-4 to the Securities and Exchange Commission on August 29, 2001.                                                                                                                          
|4.4  |  | Amended and Restated Credit Agreement, dated as of July 3, 2001, by and among Mission Energy Holding Company, the lenders party thereto from time to time, Goldman Sachs Credit Partners L.P., as sole Lead Arranger, as Administrative Agent and as
Term Loan Collateral Agent, and Lehman Commercial Paper Inc., as Syndication Agent, incorporated by reference to Exhibit 4.4 to Mission Energy Holding Company's Registration Statement on Form S-4 to the Securities and Exchange Commission on
August 29, 2001.
|4.5  |  | Loan Escrow and Security Agreement, dated as of July 2, 2001, by and among Mission Energy Holding Company, Goldman, Sachs & Co., as Collateral Agent, Goldman Sachs Credit Partners L.P., as Administrative Agent, and Wilmington Trust Company,
as Loan Escrow Agent, incorporated by reference to Exhibit 4.5 to Mission Energy Holding Company's Registration Statement on Form S-4 to the Securities and Exchange Commission on August 29, 2001.                                                                  
|     |  |                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                       

201

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|4.6    |  | Pledge and Security Agreement, dated as of July 2, 2001, by and among Mission Energy Holding Company, Goldman Sachs Credit Partners L.P., as Administrative Agent, and Wilmington Trust Company, as Trustee and Joint Collateral Agent, incorporated
by reference to Exhibit 4.6 to Mission Energy Holding Company's Registration Statement on Form S-4 to the Securities and Exchange Commission on August 29, 2001.                                                    
|------ |  | -------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
|4.7    |  | Indenture, dated as of August 10, 2001, among Edison Mission Energy and The Bank of New York as Trustee, incorporated by reference to Exhibit 4.1 to Edison Mission Energy's Registration Statement on Form S-4 to the Securities and
Exchange Commission on August 29, 2001.                                                                                                                                                                                            
|4.7.1  |  | Form of 10% Senior Note due 2008 (included in Exhibit 4.1) to Edison Mission Energy's Registration Statement on Form S-4 to the Securities and Exchange Commission on August 29, 2001).                                                                                                                                                                                                                                                                                  
|4.8    |  | Registration Rights Agreement, dated as of August 7, 2001, among Edison Mission Energy, Credit Suisse First Boston Corporation, BMO Nesbitt Burns Corp., Salomon Smith Barney Inc., SG Cowen Securities Corporation, TD Securities (USA) Inc. and
Westdeutsche Landesbank Girozentrale (Düsseldorf), incorporated by reference to Exhibit 4.2 to Edison Mission Energy's Registration Statement on Form S-4 to the Securities and Exchange Commission on August 29, 2001.
|4.9    |  | Indenture, dated as of April 5, 2001, among Edison Mission Energy and United States Trust Company of New York as Trustee, incorporated by reference to Exhibit 4.20 to Edison Mission Energy's and Midwest Generation LLC's Registration
Statement on Form S-4 to the Securities and Exchange Commission on April 20, 2001.                                                                                                                                              
|4.9.1  |  | Form of 9.875% Senior Note due 2011 (included in Exhibit 4.1 to Edison Mission Energy's Registration Statement on Form S-4 to the Securities and Exchange Commission on April 24, 2001).                                                                                                                                                                                                                                                                                 
|4.10   |  | Registration Rights Agreement, dated as of April 2, 2001, among Edison Mission Energy and Credit Suisse First Boston Corporation and Westdeutsche Landesbank Girozentrale (Düsseldorf) as representatives of the Initial Purchasers,
incorporated by reference to Exhibit 4.2 to Edison Mission Energy's Registration Statement on Form S-4 to the Securities and Exchange Commission on April 24, 2001.                                                                 
|4.11   |  | Guarantee, dated as of August 17, 2000, made by Edison Mission Energy, as Guarantor in favor of Powerton Trust I, as Owner Lessor, incorporated by reference to Exhibit 4.9 to Edison Mission Energy's and Midwest Generation LLC's Registration
Statement on Form S-4 to the Securities and Exchange Commission on April 20, 2001.                                                                                                                                      
|4.11.1 |  | Schedule identifying substantially identical agreement to Guarantee constituting Exhibit 4.11 hereto, incorporated by reference to Exhibit 4.9.1 to Edison Mission Energy's and Midwest Generation LLC's Registration Statement on Form S-4
to the Securities and Exchange Commission on April 20, 2001.                                                                                                                                                                 
|4.12   |  | Guarantee, dated as of August 17, 2000, made by Edison Mission Energy, as Guarantor in favor of Joliet Trust I, as Owner Lessor, incorporated by reference to Exhibit 4.10 to Edison Mission Energy's and Midwest Generation LLC's Registration
Statement on Form S-4 to the Securities and Exchange Commission on April 20, 2001.                                                                                                                                       
|4.12.1 |  | Schedule identifying substantially identical agreement to Guarantee constituting Exhibit 4.12 hereto, incorporated by reference to Exhibit 4.10.1 to Edison Mission Energy's and Midwest Generation LLC's Registration Statement on
Form S-4 to the Securities and Exchange Commission on April 20, 2001.                                                                                                                                                                
|       |  |                                                                                                                                                                                                                                                                                                                                                                                                                                                                          

202

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|4.13   |  | Registration Rights Agreement, dated as of August 17, 2000, among Edison Mission Energy, Midwest Generation, LLC and Credit Suisse First Boston Corporation and Lehman Brothers Inc., as representatives of the Initial Purchasers, incorporated by
reference to Exhibit 4.11 to Edison Mission Energy's and Midwest Generation LLC's Registration Statement on Form S-4 to the Securities and Exchange Commission on April 20, 2001.                                                                                                                                                                                 
|------ |  | ----------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
|4.14   |  | Participation Agreement (T1), dated as of August 17, 2000, by and among, Midwest Generation, LLC, Powerton Trust I, as the Owner Lessor, Wilmington Trust Company, as the Owner Trustee, Powerton Generation I, LLC, as the Owner Participant, Edison
Mission Energy, United States Trust Company of New York, as the Lease Indenture Trustee, and United States Trust Company of New York, as the Pass Through Trustees, incorporated by reference to Edison Mission Energy's and Midwest Generation LLC's
Registration Statement on Form S-4 to the Securities and Exchange Commission on April 20, 2001.           
|4.14.1 |  | Schedule identifying substantially identical agreement to Participation Agreement constituting Exhibit 4.14 hereto, incorporated by reference to Exhibit 4.12.1 to Edison Mission Energy's and Midwest Generation LLC's Registration Statement
on Form S-4 to the Securities and Exchange Commission on April 20, 2001.                                                                                                                                                                                                                                                                                               
|4.15   |  | Participation Agreement (T1), dated as of August 17, 2000, by and among, Midwest Generation, LLC, Joliet Trust I, as the Owner Lessor, Wilmington Trust Company, as the Owner Trustee, Joliet Generation I, LLC, as the Owner Participant, Edison
Mission Energy, United States Trust Company of New York, as the Lease Indenture Trustee and United States Trust Company of New York, as the Pass Through Trustees, incorporated by reference to Exhibit 4.13 to Edison Mission Energy's and Midwest
Generation LLC's Registration Statement on Form S-4 to the Securities and Exchange Commission on April 20, 2001.
|4.15.1 |  | Schedule identifying substantially identical agreement to Participation Agreement constituting Exhibit 4.15 hereto, incorporated by reference to Exhibit 4.13.1 to Edison Mission Energy's and Midwest Generation LLC's Registration Statement
on Form S-4 to the Securities and Exchange Commission on April 20, 2001.                                                                                                                                                                                                                                                                                               
|4.16   |  | Copy of the Global Debenture representing Edison Mission Energy's 97/8% Junior Subordinated Deferrable Interest Debentures, Series A, Due 2024, incorporated by reference to Exhibit 4.1 to Edison Mission Energy's
Form 10-K for the year ended December 31, 1994.                                                                                                                                                                                                                                                                                                                                                   
|4.17   |  | Conformed copy of the Indenture, dated as of November 30, 1994, between Edison Mission Energy and The First National Bank of Chicago, as Trustee, incorporated by reference to Exhibit 4.2 to Edison Mission Energy's Form 10-K for the
year ended December 31, 1994.                                                                                                                                                                                                                                                                                                                                                 
|4.17.1 |  | First Supplemental Indenture, dated as of November 30, 1994, to Indenture dated as of November 30, 1994 between Edison Mission Energy and The First National Bank of Chicago, as Trustee, incorporated by reference to Exhibit 4.2.1 to
Edison Mission Energy's Form 10-K for the year ended December 31, 1994.                                                                                                                                                                                                                                                                                                       
|4.17.2 |  | Second Supplemental Indenture, dated as of August 8, 1995, to Indenture dated as of November 30, 1994 between Edison Mission Energy and The First National Bank of Chicago, as Trustee, incorporated by reference to Exhibit 4.11.2 to
Edison Mission Energy's Registration Statement on Form S-4 to the Securities and Exchange Commission on August 29, 2001.                                                                                                                                                                                                                                                       
|       |  |                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                       

203

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|4.18    |  | Indenture, dated as of June 28, 1999, between Edison Mission Energy and The Bank of New York, as Trustee, incorporated by reference to Exhibit 4.1 to Edison Mission Energy's Registration Statement on Form S-4 to the Securities and
Exchange Commission on February 18, 2000.                                                                                                                                                                                                                                                                
|------- |  | ------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
|4.18.1  |  | First Supplemental Indenture, dated as of June 28, 1999, to Indenture dated as of June 28, 1999, between Edison Mission Energy and The Bank of New York, as Trustee, incorporated by reference to Exhibit 4.2 to Edison Mission Energy's
Registration Statement on Form S-4 to the Securities and Exchange Commission on February 18, 2000.                                                                                                                                                                                                     
|4.20    |  | Promissory Note ($499,450,800), dated as of August 24, 2000, by Edison Mission Energy in favor of Midwest Generation, LLC, incorporated by reference to Exhibit 4.5 to Edison Mission Energy's Form 10-K for the year ended
December 31, 2000.                                                                                                                                                                                                                                                                                                  
|4.20.1  |  | Schedule identifying substantially identical agreements to Promissory Note constituting Exhibit 4.20 hereto, incorporated by reference to Exhibit 4.14 to Edison Mission Energy's Form 10-K for the year ended December 31,
2000.                                                                                                                                                                                                                                                                                                               
|4.22    |  | Participation Agreement, dated as of December 7, 2001, among EME Homer City Generation L.P., Homer City OL1 LLC, as Facility Lessor and Ground Lessee, Wells Fargo Bank Northwest National Association, General Electric Capital Corporation, The
Bank of New York as the Security Agent, The Bank of New York as Lease Indenture Trustee, Homer City Funding LLC and The Bank of New York as Bondholder Trustee, incorporated by reference to Exhibit 4.4 to the EME Homer City Generation L.P.
Form 10-K for the year ended December 31, 2001.
|4.22.1  |  | Schedule identifying substantially identical agreements to Participation Agreement constituting Exhibit 4.22 hereto, incorporated by reference to Exhibit 4.4.1 to the EME Homer City Generation L.P. Form 10-K for the year ended
December 31, 2001.                                                                                                                                                                                                                                                                                           
|4.23    |  | Open-End Mortgage, Security Agreement and Assignment of Rents, dated as of December 7, 2001, among Homer City OLI LLC, as the Owner Lessor to The Bank of New York, as Security Agent and Mortgagee, incorporated by reference to Exhibit 4.9 to
the EME Homer City Generation L.P. Form 10-K for the year ended December 31, 2001.                                                                                                                                                                                                             
|10.1    |  | Registration Rights Agreement, dated as of June 23, 1999, between Edison Mission Energy and the Initial Purchasers specified therein, incorporated by reference to Exhibit 10.1 to Edison Mission Energy's Registration Statement on
Form S-4 to the Securities and Exchange Commission on February 18, 2000.                                                                                                                                                                                                                                   
|10.8    |  | Power Purchase Contract between Southern California Edison Company and Arco Petroleum Products Company (Watson Refinery), incorporated by reference to Exhibit 10.8 to Edison Mission Energy's Form 10.                                                                                                                                                                                                                                                                                                                                         
|10.9    |  | Power Supply Agreement between State Electricity Commission of Victoria, Loy Yang B Power Station Pty. Ltd. and the Company Australia Pty. Ltd., as managing partner of the Latrobe Power Partnership, dated December 31, 1992, incorporated by
reference to Exhibit 10.9 to Edison Mission Energy's Form 10.                                                                                                                                                                                                                                   
|10.10   |  | Power Purchase Agreement between P.T. Paiton Energy Company as Seller and Perusahaan Umum Listrik Negara as Buyer, dated February 12, 1994, incorporated by reference to Exhibit 10.10 to Edison Mission Energy's Form 10.                                                                                                                                                                                                                                                                                                                      
|10.10.1 |  | Amendment to Power Purchase Agreement between P.T. Paiton Energy (formerly known as P.T. Paiton Energy Company) as Seller and P.T. PLN (Persero) (as successor to Perusahaan Umum Listrik Negara) as Buyer, dated as of June 28, 2002, incorporated
by reference to Exhibit 10.10.1 to Edison Mission Energy's Form 10-Q for the quarter ended June 30, 2002.                                                                                                                                                                                   
|        |  |                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                 

204

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|10.11   |  | Amended and Restated Power Purchase Contract between Southern California Energy Company and Midway-Sunset Cogeneration Company, dated May 5, 1988, incorporated by reference to Exhibit 10.11 to Edison Mission Energy's
Form 10.                    
|------- |  | -----------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
|10.12   |  | Parallel Generation Agreement between Kern River Cogeneration Company and Southern California Energy Company, dated January 6, 1984, incorporated by reference to Exhibit 10.12 to Edison Mission Energy's Form 10.                                  
|10.13   |  | Parallel Generation Agreement between Kern River Cogeneration (Sycamore Project) Company and Southern California Energy Company, dated December 18, 1984, incorporated by reference to Exhibit 10.13 to Edison Mission Energy's
Form 10.             
|10.16   |  | Amended and Restated Ground Lease Agreement between Texaco Refining and Marketing Inc. and March Point Cogeneration Company, dated August 21, 1992, incorporated by reference to Exhibit 10.16 to Edison Mission Energy's
Form 10.                   
|10.16.1 |  | Amendment No. 1 to Amended and Restated Ground Lease Agreement between Texaco Refining and Marketing Inc. and March Point Cogeneration Company, dated August 21, 1992, incorporated by reference to Exhibit 10.16 to Edison Mission
Energy's Form 10.
|10.17   |  | Memorandum of Agreement between Atlantic Richfield Company and Products Cogeneration Company, dated September 17, 1987, incorporated by reference to Exhibit 10.17 to Edison Mission Energy's Form 10.                                               
|10.18   |  | Memorandum of Ground Lease between Texaco Producing Inc. and Sycamore Cogeneration Company, dated January 19, 1987, incorporated by reference to Exhibit 10.18 to Edison Mission Energy's Form 10.                                                   
|10.19   |  | Amended and Restated Memorandum of Ground Lease between Getty Oil Company and Kern River Cogeneration Company, dated November 14, 1984, incorporated by reference to Exhibit 10.19 to Edison Mission Energy's Form 10.                               
|10.20   |  | Memorandum of Lease between Sun Operating Limited Partnership and Midway-Sunset Cogeneration Company, incorporated by reference to Exhibit 10.20 to Edison Mission Energy's Form 10.                                                                 
|10.21   |  | Executive Supplemental Benefit Program, incorporated by reference to Exhibits to Forms 10-K filed by SCEcorp (File No. 1-2313).                                                                                                                      
|10.22   |  | 1981 Deferred Compensation Agreement, incorporated by reference to Exhibits to Forms 10-K filed by SCEcorp (File No. 1-2313).                                                                                                                        
|10.23   |  | 1985 Deferred Compensation Agreement for Executives, incorporated by reference to Exhibits to Forms 10-K filed by SCEcorp (File No. 1-2313).                                                                                                         
|10.24   |  | 1987 Deferred Compensation Plan for Executives, incorporated by reference to Exhibits to Forms 10-K filed by SCEcorp (File No. 1-2313).                                                                                                              
|10.25   |  | 1988 Deferred Compensation Plan for Executives, incorporated by reference to Exhibits to Forms 10-K filed by SCEcorp (File No. 1-2313).                                                                                                              
|10.26   |  | 1989 Deferred Compensation Plan for Executives, incorporated by reference to Exhibits to Forms 10-K filed by SCEcorp (File No. 1-9936).                                                                                                              
|10.27   |  | 1990 Deferred Compensation Plan for Executives, incorporated by reference to Exhibits to Forms 10-K filed by SCEcorp (File No. 1-9936).                                                                                                              
|10.28   |  | Annual Deferred Compensation Plan for Executives, incorporated by reference to Exhibits to Forms 10-K filed by SCEcorp (File No. 1-9936).                                                                                                            
|        |  |                                                                                                                                                                                                                                                      

205

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|10.29   |  | Executive Retirement Plan for Executives, incorporated by reference to Exhibits to Forms 10-K filed by SCEcorp (File No. 1-2313).                                                                                                                                                   
|------- |  | ------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
|10.31   |  | Estate and Financial Planning Program for Executive Officers, incorporated by reference to Exhibits to Forms 10-K filed by SCEcorp (File No 1-9936).                                                                                                                                
|10.32   |  | Letter Agreement with Edward R. Muller, incorporated by reference to Exhibit 10.32 to Edison Mission Energy's Form 10.                                                                                                                                                              
|10.34   |  | Conformed copy of the Guarantee Agreement dated as of November 30, 1994, incorporated by reference to Exhibit 10.34 to Edison Mission Energy's Form 10.                                                                                                                             
|10.35   |  | Indenture of Lease between Brooklyn Navy Yard Development Corporation and Cogeneration Technologies, Inc., dated as of December 18, 1989, incorporated by reference to Exhibit 10.35 to Edison Mission Energy's Form 10-K for the year
ended December 31, 1994.                     
|10.35.1 |  | First Amendment to Indenture of Lease between Brooklyn Navy Yard Development Corporation and Cogeneration Technologies, Inc., dated November 1, 1991, incorporated by reference to Exhibit 10.35.1 to Edison Mission Energy's Form 10-K for
the year ended December 31, 1994.       
|10.35.2 |  | Second Amendment to Indenture of Lease between Brooklyn Navy Yard Development Corporation and Cogeneration Technologies, Inc., dated June 3, 1994, incorporated by reference to Exhibit 10.35.2 to Edison Mission Energy's Form 10-K for
the year ended December 31, 1994.          
|10.35.3 |  | Third Amendment to Indenture of Lease between Brooklyn Navy Yard Development Corporation and Cogeneration Technologies, Inc., dated December 12, 1994, incorporated by reference to Exhibit 10.35.3 to Edison Mission Energy's Form 10-K
for the year ended December 31, 1994.      
|10.37   |  | Amended and Restated Limited Partnership Agreement of Mission Capital, L.P., dated as of November 30, 1994, incorporated by reference to Exhibit 10.37 to Edison Mission Energy's Form 10-K for the year ended December 31,
1994.                                                   
|10.38   |  | Action of General Partner of Mission Capital, L.P. creating the 97/8% Cumulative Monthly Income Preferred Securities, Series A, dated as of November 30, 1994, incorporated by reference to Exhibit 10.38 to Edison
Mission Energy's Form 10-K for the year ended December 31, 1994.
|10.39   |  | Action of General Partner of Mission Capital, L.P., creating the 81/2% Cumulative Monthly Income Preferred Securities, Series B, dated as of August 8, 1995, incorporated by reference to Exhibit 10.39 to Edison
Mission Energy's Form 10-Q for the quarter ended June 30, 1995.   
|10.40   |  | Power Purchase Contract between ISAB Energy, S.r.l. as Seller and Enel, S.p.A. as Buyer, dated June 9, 1995, incorporated by reference to Exhibit 10.40 to Edison Mission Energy's Form 10-Q for the quarter ended June 30,
1995.                                                   
|10.41   |  | £400 million Barclays Bank Plc Credit Agreement, dated December 18, 1995, incorporated by reference to Exhibit 10.41 to Edison Mission Energy's Form 8-K, dated December 21, 1995.                                                                                                  
|10.45   |  | Power Purchase Agreement between National Power Corporation and San Pascual Cogeneration Company International B.V., dated September 10, 1997, incorporated by reference to Exhibit 10.45 to Edison Mission Energy's Form 10-K for the year
ended December 31, 1997.                
|        |  |                                                                                                                                                                                                                                                                                     

206

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|10.46   |  | Power Purchase Agreement between Gulf Power Generation Co., LTD., and Electricity Generating Authority of Thailand, dated December 22, 1997, incorporated by reference to Exhibit 10.46 to Edison Mission Energy's Form 10-K for the year
ended December 31, 1997.                                                                                                                                                                                                                                           
|------- |  | -------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
|10.49   |  | Equity Support Guarantee by Edison Mission Energy, dated December 23, 1998, in favor of ABN AMRO Bank N.V., and the Chase Manhattan Bank to guarantee certain equity funding obligations of EcoEléctrica Ltd. and EcoEléctrica Holdings
Ltd. pursuant to EcoEléctrica Ltd.'s Credit Agreement dated as of October 31, 1997, incorporated by reference to Exhibit 10.49 to Edison Mission Energy's Form 10-K for the year ended December 31, 1998.                                                            
|10.50   |  | Master Guarantee and Support Instrument by Edison Mission Energy, dated December 23, 1998, in favor of ABN AMRO Bank N.V., and the Chase Manhattan Bank to guarantee the availability of funds to purchase fuel for the EcoEléctrica project
pursuant to EcoEléctrica Ltd.'s Credit Agreement dated as of October 31, 1997 and Intercreditor Agreement dated as of October 31, 1997, incorporated by reference to Exhibit 10.50 to Edison Mission Energy's Form 10-K for the year
ended December 31, 1998.   
|10.51   |  | Guarantee Assumption Agreement from Edison Mission Energy, dated December 23, 1998, under which Edison Mission Energy assumed all of the obligations of KENETECH Energy Systems, Inc. to Union Carbide Caribe Inc., under the certain Guaranty dated
November 25, 1997, incorporated by reference to Exhibit 10.51 to Edison Mission Energy's Form 10-K for the year ended December 31, 1998.                                                                                                                
|10.52   |  | Transition Power Purchase Agreement, dated August 1, 1998, between New York State Electric & Gas Corporation and Mission Energy Westside, Inc, incorporated by reference to Exhibit 10.52 to Edison Mission Energy's Form 10-K for the
year ended December 31, 1998.                                                                                                                                                                                                                                         
|10.54   |  | Guarantee, dated August 1, 1998, between Edison Mission Energy, Pennsylvania Electric Company, NGE Generation, Inc. and New York State Electric & Gas Corporation, incorporated by reference to Exhibit 10.54 to Edison Mission Energy's
Form 10-K for the year ended December 31, 1998.                                                                                                                                                                                                                     
|10.58.2 |  | Amended and Restated Security Deposit Agreement, dated as of December 7, 2001, among EME Homer City Generation L.P. and The Bank of New York as Collateral Agent, incorporated by reference to Exhibit 10.18.2 to the EME Homer City Generation
L.P. Form 10-K for the year ended December 31, 2001.                                                                                                                                                                                                         
|10.60.4 |  | Intercompany Loan Subordination Agreement, dated March 18, 1999, among Edison Mission Holdings Co., Edison Mission Finance Co., Homer City Property Holdings, Inc., Chestnut Ridge Energy Co., Mission Energy Westside, Inc., EME Homer City
Generation L.P. and United States Trust Company of New York, incorporated by reference to Exhibit 10.60.3 to Amendment No. 2 of Edison Mission Holdings Co.'s Registration Statement on Form S-4 to the Securities and Exchange Commission
on February 29, 2000.
|10.64   |  | Coal and Capex Facility Agreement, dated July 16, 1999 between EME Finance UK Limited, Barclay's Capital and Credit Suisse First Boston, The Financial Institutions named as Banks, and Barclays Bank PLC as Facility Agent, incorporated by
reference to Exhibit 10.64 to Edison Mission Energy's Form 10-Q for the quarter ended September 30, 1999.                                                                                                                                                       
|        |  |                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                              

207

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|10.64.1 |  | Amendment One to Coal and Capex Facility Agreement, dated as of May 29, 2001, by and among Edison Mission Energy Finance UK Limited and Barclays Bank PLC, as Facility Agent, incorporated by reference to Exhibit 10.64.1 to Edison Mission
Energy's Form 10-Q for the quarter ended June 30, 2001.                                                               
|------- |  | -------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
|10.65   |  | Guarantee by Edison Mission Energy dated July 16, 1999 supporting the Coal and Capex Facility Agreement (Facility Agreement) issued by Barclays Bank PLC to secure EME Finance UK Limited obligations pursuant to the Facility Agreement,
incorporated by reference to Exhibit 10.65 to Edison Mission Energy's Form 10-Q for the quarter ended September 30, 1999.
|10.65.1 |  | Amendment One to Guarantee by Edison Mission Energy supporting the Facility Agreement, dated as of August 17, 2000, incorporated by reference to Exhibit 10.65.1 to Edison Mission Energy's Form 10-K for the year ended December 31,
2000.                                                                                                                        
|10.65.2 |  | Amendment Two to Guarantee by Edison Mission Energy Supporting the Facility Agreement, dated as of May 29, 2001, incorporated by reference to Exhibit 10.65.2 to Edison Mission Energy's Form 10-Q for the quarter ended June 30,
2001.                                                                                                                            
|10.75   |  | Exchange and Registration Rights Agreement, dated as of May 27, 1999, by and among the Initial Purchasers named therein, the Guarantors named therein and Edison Mission Holdings Co., incorporated by reference to Exhibit 10.1 to Edison
Mission Holdings Co.'s Registration Statement on Form S-4 to the Securities and Exchange Commission on December 3, 1999.
|10.76   |  | Agreement among Edward R. Muller, Edison International and Edison Mission Energy concerning the terms of Mr. Muller's employment separation, incorporated by reference to Exhibit 10.76 to Edison Mission Energy's Form 10-Q for the quarter
ended March 31, 2000.                                                                                                 
|10.77   |  | Agreement By and Between S. Linn Williams and Edison Mission Energy dated February 5, 2000, incorporated by reference to Exhibit 10.77 to Edison Mission Energy's Form 10-Q for the quarter ended March 31, 2000.                                                                                                                                                  
|10.78   |  | Form of Agreement for 2000 Employee Awards under the Equity Compensation Plan, incorporated by reference to Exhibit 10.78 to Edison Mission Energy's Form 10-Q for the quarter ended March 31, 2000.                                                                                                                                                               
|10.79   |  | Resolution regarding the computation of disability and survivor benefits prior to age 55 for Alan J. Fohrer, incorporated by reference to Exhibit 10.79 to Edison Mission Energy's Form 10-Q for the quarter ended March 31,
2000.                                                                                                                                 
|10.81   |  | Edison International 2000 Equity Plan, incorporated by reference to Exhibit 10.1 to Edison International's Form 10-Q for the quarter ended June 30, 2000 (File No. 1-9936).                                                                                                                                                                                        
|10.82   |  | Form of Agreement for 2000 Employee Awards under the 2000 Equity Plan, incorporated by reference to Exhibit 10.2 to Edison International's Form 10-Q for the quarter ended June 30, 2000 (File No. 1-9936).                                                                                                                                                        
|10.83   |  | Amendment No. 1 to the Edison International Equity Compensation Plan (as restated January 1, 1998), incorporated by reference to Exhibit 10.4 to Edison International's Form 10-Q for the quarter ended June 30, 2000 (File
No. 1-9936).                                                                                                                           
|10.86   |  | Power Purchase Agreement (Crawford, Fisk, Waukegan, Will County, Joliet and Powerton Generating Stations), dated as of December 15, 1999, between Commonwealth Edison Company and Midwest Generation, LLC, incorporated by reference to
Exhibit 10.86 to Edison Mission Energy's Form 10-K for the year ended December 31, 2000.                                   
|        |  |                                                                                                                                                                                                                                                                                                                                                                    

208

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|10.87   |  | Power Purchase Agreement (Collins Generating Station), dated as of December 15, 1999, between Commonwealth Edison Company and Midwest Generation, LLC, incorporated by reference to Exhibit 10.87 to Edison Mission Energy's Form 10-K for
the year ended December 31, 2000.                                                                                                                          
|------- |  | ------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
|10.87.1 |  | Amendment No. 1 to the Power Purchase Agreement, dated July 12, 2000, between Commonwealth Edison Company and Midwest Generation, LLC, incorporated by reference to Exhibit 10.87.1 to Edison Mission Energy's Form 10-K for the year
ended December 31, 2000.                                                                                                                                        
|10.87.2 |  | Amended and Restated Power Purchase Agreement (Collins Generating Station), dated as of September 13, 2000, between Commonwealth Edison Company and Midwest Generation, LLC, incorporated by reference to Exhibit 10.87.2 to Edison Mission
Energy's Form 10-K for the year ended December 31, 2000.                                                                                                  
|10.88   |  | Power Purchase Agreement (Crawford, Fisk, Waukegan, Calumet, Joliet, Bloom, Electric Junction, Sabrooke and Lombard Peaking Units), dated as of December 15, 1999, between Commonwealth Edison Company and Midwest Generation, LLC, incorporated by
reference to Exhibit 10.88 to Edison Mission Energy's Form 10-K for the year ended December 31, 2000.                                             
|10.90   |  | Reimbursement Agreement, dated as of August 17, 2000, between Edison Mission Energy and Midwest Generation, LLC, incorporated by reference to Exhibit 10.90 to Edison Mission Energy's Form 10-K for the year ended December 31,
2000.                                                                                                                                                                
|10.92   |  | Credit Agreement, dated as of September 13, 2001, among Edison Mission Energy, Certain Commercial Lending Institutions, Citicorp USA, Inc., as Administrative Agent, and Citibank, N.A. as Issuing Agent, incorporated by reference to
Exhibit 10.92 to Amendment No. 1 of Edison Mission Energy's Registration Statement on Form S-4 to the Securities and Exchange Commission on September 27, 2001.
|10.92.1 |  | Amendment One to Credit Agreement, dated as of November 14, 2001, by and among Edison Mission Energy, Certain Commercial Lending Institutions and Citicorp USA, Inc., as Administrative Agent, incorporated by reference to Exhibit 10.92.1 to
Edison Mission Energy's Form 10-Q for the quarter ended September 30, 2002.                                                                            
|10.92.2 |  | Amendment Two to Credit Agreement, dated as of September 17, 2002, by and among Edison Mission Energy, Certain Commercial Lending Institutions and Citicorp USA, Inc., as Administrative Agent, incorporated by reference to Exhibit 10.92.2 to
Edison Mission Energy's Form 10-Q for the quarter ended September 30, 2002.                                                                           
|10.93   |  | Edison Mission Energy Exchange Offer Circular, dated as of July 3, 2000, incorporated by reference to Exhibit 10.93 to Edison Mission Energy's Form 10-K for the year ended December 31, 2001.                                                                                                                                                                                                        
|10.94   |  | Edison Mission Energy Option Exchange Offer Summary of Deferred Compensation Alternatives, dated as of July 3, 2000, incorporated by reference to Exhibit 10.94 to Edison Mission Energy's Form 10-K for the year ended December 31,
2001                                                                                                                                                             
|10.95   |  | Executive Retirement Plan Amendment 2001-1, incorporated by reference to Exhibit 10.1 to Edison International's Form 10-Q for the quarter ended March 31, 2001 (File No. 1-9936).                                                                                                                                                                                                                     
|10.96   |  | Restatement of Terms of 2000 basic long-term incentive awards under the Equity Compensation Plan or the 2000 Equity Plan, incorporated by reference to Exhibit 10.2 to Edison International's Form 10-Q for the quarter ended March 31,
2001 (File No. 1-9936).                                                                                                                                       
|        |  |                                                                                                                                                                                                                                                                                                                                                                                                       

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|10.97    |  | Terms of 2001 basic long-term incentive awards under the Equity Compensation Plan or the 2000 Equity Plan, incorporated by reference to Exhibit 10.3 to Edison International's Form 10-Q for the quarter ended March 31, 2001 (File
No. 1-9936).                     
|-------- |  | ---------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
|10.98    |  | Terms of 2001 special long-term incentive awards under the Equity Compensation Plan or the 2000 Equity Plan, incorporated by reference to Exhibit 10.4 to Edison International's Form 10-Q for the quarter ended March 31, 2001 (File
No. 1-9936).                   
|10.99    |  | Terms of 2001 retention incentives under the Equity Compensation Plan, incorporated by reference to Exhibit 10.5 to Edison International's Form 10-Q for the quarter ended March 31, 2001 (File No. 1-9936).                                                         
|10.100   |  | Executive Severance Plan as adopted effective January 1, 2001, incorporated by reference to Exhibit 10.34 to Edison International's Form 10-K for the year ended December 31, 2001 (File No. 1-9936).                                                                
|10.101   |  | Terms of 2002 stock option and performance share awards under the Equity Compensation Plan or the 2000 Equity Plan, incorporated by reference to Exhibit 10.1 to Edison International's Form 10-Q for the quarter ended March 31, 2002
(File No. 1-9936).            
|10.102   |  | Executive Grantor Trust Agreement, incorporated by reference to Exhibit 10.12 to Edison International's Form 10-K for the year ended December 31, 1995 (File No. 1-9936).                                                                                            
|10.102.1 |  | Executive Grantor Trust Agreement Amendment 2002-1, effective May 14, 2002, incorporated by reference to Exhibit 10.3 to Edison International's Form 10-Q for the quarter ended June 30, 2002 (File No. 1-9936).                                                     
|10.103   |  | Director Grantor Trust Agreement, incorporated by reference to Exhibit 10.10 to Edison International's Form 10-K for the year ended December 31, 1995 (File No. 1-9936).                                                                                             
|10.103.1 |  | Director Grantor Trust Agreement Amendment 2002-1, effective May 14, 2002, incorporated by reference to Exhibit 10.4 to Edison International's Form 10-Q for the quarter ended June 30, 2002 (File No. 1-9936).                                                      
|10.104   |  | Separation Agreement by and between William J. Heller and Edison Mission Energy effective July 31, 2002, incorporated by reference to Exhibit 10.104 to Edison Mission Energy's Form 10-Q for the quarter ended September 30,
2002.                                  
|10.105   |  | Consulting Agreement with William J. Heller, incorporated by reference to Exhibit 10.2 to Edison International's Form 10-Q for the quarter ended September 30, 2002 (File No. 1-9936).                                                                               
|10.106   |  | Amended and Restated Tax-Allocation Agreement, dated September 10, 1996, among The Mission Group and its first-tier subsidiaries, incorporated by reference to Exhibit 10.106 to Mission Energy Holding Company's Form 10-A for the quarter
ended September 30, 2002.
|10.107   |  | Administrative Agreement Re Tax-Allocation Payments, dated July 2, 2002, among Edison International and subsidiary parties, incorporated by reference to Exhibit 10.107 to Edison Mission Energy's Form 10-Q for the quarter ended
September 30, 2002.               
|10.108   |  | Performance and Retention Incentive Agreement between Thomas R. McDaniel and Edison Mission Energy, incorporated by reference to Exhibit 10.108 to Edison Mission Energy's Form 10-K for the year ended December 31, 2002.                                           
|18.1     |  | Preferability Letter Regarding Change in Accounting Principle for Major Maintenance Costs, incorporated by reference to Exhibit 18.1 to Edison Mission Energy's Form 10-Q for the quarter ended March 31, 2000.                                                      
|21       |  | List of Subsidiaries of Mission Energy Holding Company.*                                                                                                                                                                                                             
|         |  |                                                                                                                                                                                                                                                                      

210

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|99.1 |  | Homer City Facilities Funds Flow From Operations for the twelve months ended December 31, 2002, incorporated by reference to Exhibit 99.1 to Edison Mission Energy's Form 10-K for the year ended December 31, 2002.
|---- |  | --------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
|99.2 |  | Illinois Plants Funds Flow From Operations for the twelve months ended December 31, 2002, incorporated by reference to Exhibit 99.2 to Edison Mission Energy's Form 10-K for the year ended December 31, 2002.      
|99.3 |  | Statement Pursuant to 18 U.S.C. Section 1350.*                                                                                                                                                                      

---

The
financial statements referred to in (a)(2) above represent the entities, or a combination of those entities, that are Investments in Unconsolidated Affiliates, which were 50% or less
owned by EME and that met the requirements of Rule 3-09 of Regulation S-X. Financial statements with respect to ISAB Energy S.r.l. which meets the definition of a
foreign business as defined in Rule 1-02(i) of Regulation S-X to be filed by amendment not later than six months after December 31, 2002 pursuant to Rule 3-09 of Regulation S-X.

211

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REPORT OF INDEPENDENT ACCOUNTANTS

To
the Board of Directors of
Edison Mission Energy and ChevronTexaco Corporation:

In
our opinion, the accompanying combined balance sheets and the related combined statements of income, cash flows and changes in equity present fairly, in all material respects, the
combined financial position of Kern River Cogeneration Company, Sycamore Cogeneration Company, Coalinga Cogeneration Company, Mid-Set Cogeneration Company, Salinas River Cogeneration
Company, Sargent Canyon Cogeneration Company, and Sunrise Power Company, LLC (together, the California Power Group) at December 31, 2002 and 2001, and the results of their operations and their
cash flows for each of the three years in the period ended December 31, 2002 in conformity with accounting principles generally accepted in the United States of America. These financial
statements are the responsibility of the California Power Group's management; our responsibility is to express an opinion on these financial statements based on our audits. We conducted our audits of
these statements in accordance with auditing standards generally accepted in the United States of America, which 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, assessing the
accounting principles used and significant estimates made by management, and evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our
opinion.

As
discussed in Note 2 to the financial statements, on January 1, 2000, the California Power Group changed its method of accounting for major maintenance activities.

PricewaterhouseCoopers
LLP

Los
Angeles, California
February 24, 2003

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CALIFORNIA POWER GROUP        COMBINED BALANCE SHEETS        (Amounts in thousands)

|                                                        |                                                    | As of December 31,
|------------------------------------------------------- | -------------------------------------------------- | ------------------
|
|Assets                                                 
|Current Assets                                          |                                                    |                   
|                                                        | Cash and cash equivalents                          |                   
|                                                        | Trade receivables:                                 |                   
|                                                        | Related party                                     |                   
|                                                        | Other                                             |                   
|                                                        | Inventories                                        |                   
|                                                        | Fair value of gas swaps                            |                   
|                                                        | Prepaid and other current assets                   |                   
|                                                        |                                                    |                   
|                                                        |                                                    |                   
|Property, plant and equipment, net                      |                                                    |                   
|Fair value of gas swaps, net of current portion         |                                                    |                   
|Other assets                                            |                                                    |                   
|                                                        |                                                    |                   
|                                                        |                                                    | $                 
|                                                        |                                                    |                   
|Liabilities and Equity                                 
|Current Liabilities:                                    |                                                    |                   
|                                                        | Current portion of project financing loans payable |                   
|                                                        | Accounts payable:                                  |                   
|                                                        | Related party                                     |                   
|                                                        | Trade and other                                   |                   
|                                                        | Fair value of gas swaps                            |                   
|                                                        | Unearned revenue                                   |                   
|                                                        |                                                    |                   
|                                                        |                                                    |                   
|Project financing loans payable, net of current portion |                                                    |                   
|Long-term liabilities                                   |                                                    |                   
|Fair value of gas swaps, net of current portion         |                                                    |                   
|                                                        |                                                    |                   
|                                                        |                                                    |                   
|Commitments and Contingencies (Notes 7 and 8)           |                                                    |                   
|Equity                                                  |                                                    |                   
|                                                        |                                                    |                   
|                                                        |                                                    | $                 
|                                                        |                                                    |                   

The
accompanying notes are an integral part of these combined financial statements.

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CALIFORNIA POWER GROUP        COMBINED STATEMENTS OF INCOME        (Amounts in thousands)

|                                                                               |                                     | Year ended December 31, |        
|------------------------------------------------------------------------------ | ----------------------------------- | ----------------------- | -------
|
|Operating Revenues                                                             |                                     |                         |        
|                                                                               | Sales of energy                     |                         | $      
|                                                                               | Sales of steam                      |                         |        
|                                                                               |                                     |                         |        
|                                                                               |                                     |                         | 555,144
|                                                                               |                                     |                         |        
|Operating Expenses                                                             |                                     |                         |        
|                                                                               | Fuel expense                        |                         |        
|                                                                               | Other operating expenses            |                         |        
|                                                                               | Administrative and general expenses |                         |        
|                                                                               | Depreciation and amortization       |                         |        
|                                                                               |                                     |                         |        
|                                                                               |                                     |                         | 350,830
|                                                                               |                                     |                         |        
|                                                                               | Income from operations              |                         |        
|                                                                               |                                     |                         |        
|Other Income (Expense)                                                         |                                     |                         |        
|                                                                               | Interest and other income           |                         |        
|                                                                               | Interest expense                    |                         |        
|                                                                               |                                     |                         |        
|                                                                               |                                     |                         | 6,010  
|                                                                               |                                     |                         |        
|Income before change in accounting principle                                   |                                     |                         | 210,324
|                                                                               |                                     |                         |        
|Cumulative effect of change in accounting for major maintenance costs (Note 2) |                                     |                         |       
|                                                                               |                                     |                         |        
|Net income                                                                     |                                     | $                       | 210,324
|                                                                               |                                     |                         |        

The
accompanying notes are an integral part of these combined financial statements.

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CALIFORNIA POWER GROUP        COMBINED STATEMENTS OF CASH FLOWS        (Amounts in thousands)

|                                      |                                                                   | Year Ended December 31,                             |                            
|------------------------------------- | ----------------------------------------------------------------- | --------------------------------------------------- | ---------------------------
|
|Cash flows from operating activities: |                                                                   |                                                     |                            
|                                      | Net income                                                        |                                                     | $                          
|                                      | Adjustments to reconcile income to cash from operating activities |                                                     |                            
|                                      |                                                                   | Cumulative effect of change in accounting principle |                            
|                                      |                                                                   | Unrealized (gain) loss on derivative instruments    |                            
|                                      |                                                                   | Depreciation and amortization                       |                            
|                                      |                                                                   | Changes in assets and liabilities:                  |                            
|                                      |                                                                   |                                                     | Trade and other receivables
|                                      |                                                                   |                                                     | Inventories                
|                                      |                                                                   |                                                     | Prepaids and other assets  
|                                      |                                                                   |                                                     | Other assets               
|                                      |                                                                   |                                                     | Accounts payable           
|                                      |                                                                   |                                                     | Unearned revenue           
|                                      |                                                                   |                                                     | Long-term liabilities      
|                                      |                                                                   |                                                     |                            
|                                      | Cash provided by operating activities                             |                                                     |                            
|                                      |                                                                   |                                                     |                            
|Cash flows from investing activities: |                                                                   |                                                     |                            
|                                      | Capital expenditures, net                                         |                                                     |                            
|                                      |                                                                   |                                                     |                            
|Cash flows from financing activities: |                                                                   |                                                     |                            
|                                      | Loan repayments                                                   |                                                     |                            
|                                      | Contributions from partners                                       |                                                     |                            
|                                      | Distributions to partners                                         |                                                     |                            
|                                      |                                                                   |                                                     |                            
|                                      | Cash (used for) provided by financing activities                  |                                                     |                            
|                                      |                                                                   |                                                     |                            
|Cash and cash equivalents             |                                                                   |                                                     |                            
|                                      | Net increase                                                      |                                                     |                            
|                                      | Beginning of year                                                 |                                                     |                            
|                                      |                                                                   |                                                     |                            
|                                      | End of year                                                       |                                                     | $                          
|                                      |                                                                   |                                                     |                            
|Supplemental Cash Flow Information:   |                                                                   |                                                     |                            
|                                      | Cash paid during the year for interest                            |                                                     | $                          
|                                      |                                                                   |                                                     |                            
|                                      | Contributed property, plant and equipment                         |                                                     | $                          
|                                      |                                                                   |                                                     |                            

The
accompanying notes are an integral part of these combined financial statements.

215

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CALIFORNIA POWER GROUP        COMBINED STATEMENTS OF EQUITY        (Amounts in thousands)

|                              |  | Edison Mission
Energy affiliates |          | Chevron Texaco
affiliates |   | Total    |  
|----------------------------- |  | -------------------------------- | -------- | ------------------------- | - | -------- | -
|Balances at December 31, 1999 |  | $                                | 162,432  |                           | $ | 119,202  |  
|Cash distributions            |  |                                  | (78,975  | )                         |   | (78,975  | )
|Net income                    |  |                                  | 97,767   |                           |   | 97,767   |  
|                              |  |                                  |          |                           |   |          |  
|Balances at December 31, 2000 |  |                                  | 181,224  |                           |   | 137,994  |  
|Cash distributions            |  |                                  | (123,025 | )                         |   | (123,025 | )
|Cash contributions            |  |                                  | 182,894  |                           |   | 182,894  |  
|Net income                    |  |                                  | 158,736  |                           |   | 158,736  |  
|                              |  |                                  |          |                           |   |          |  
|Balances at December 31, 2001 |  |                                  | 399,829  |                           |   | 356,599  |  
|Cash distributions            |  |                                  | (204,100 | )                         |   | (204,100 | )
|Cash contributions            |  |                                  | 33,925   |                           |   | 33,925   |  
|Net income                    |  |                                  | 105,162  |                           |   | 105,162  |  
|                              |  |                                  |          |                           |   |          |  
|Balances at December 31, 2002 |  | $                                | 334,816  |                           | $ | 291,586  |  
|                              |  |                                  |          |                           |   |          |  

The
accompanying notes are an integral part of these combined financial statements.

216

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CALIFORNIA POWER GROUP        NOTES TO COMBINED FINANCIAL STATEMENTS

NOTE 1: ORGANIZATION

Edison Mission Energy (EME), an indirect wholly-owned non-utility subsidiary of Edison International (EIX), and ChevronTexaco Corporation (Chevron)
jointly own six cogeneration projects and one power project located in California:



The
seven projects are together referred to as the California Power Group. The six cogeneration projects are together referred to as the Cogeneration Partnerships.

Principles of combination

These combined financial statements include the accounts of the California Power Group. The financial statements include substantial transactions with related
parties. All significant intercompany transactions and balances have been eliminated. The combined financial statements have been prepared for purposes of EME's compliance with certain requirements of
the Securities and Exchange Commission.

Nature of Operations

The Cogeneration Partnerships were organized under California law during the period from 1983 to 1989 to design, construct, own and operate cogeneration
facilities for the purpose of selling steam for use in oil field operations and providing electric energy under long-term contracts with two regulated utilities in California. The
Cogeneration Partnerships are organized as general partnerships between subsidiaries of EME and Chevron. The income or loss from each of the projects is allocated equally to the partners. Each of the
partnerships shall terminate on the latter of the date the steam and electric contracts expire (from 2004 through 2008) or the date the individual partnership elects to cease operations, unless
terminated at an earlier date pursuant to the general partnership agreement.

Westside Cogeneration Projects

Coalinga, Mid-Set, Salinas River and Sargent Canyon (together, the Westsides) each own and operate natural gas-fired cogeneration
facilities, ranging in size from 36 MWs to 38 MWs. The Westsides sell electric energy to Pacific Gas & Electric Company (PG&E) for resale to its retail electric customers. The plants also sell
steam to Chevron and/or Aera Energy, LLC (Aera) for use in oil recovery operations.

217

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Eastside Cogeneration Projects

Kern River and Sycamore (together, the Eastsides) each own and operate a 300 megawatt (MW) natural gas-fired cogeneration facility located in Kern
County, California. The Eastsides sell electric energy to Southern California Edison Company (SCE), a wholly-owned subsidiary of EIX, for resale to its retail electric customers, and sell steam to a
subsidiary of Chevron for use in its enhanced oil recovery operations in the Kern River oil field. Prior to July 1, 2002, the Eastsides also sold electric energy to Chevron for use in its Kern
River oil field operations.

Sunrise

Subsidiaries of EME and Chevron organized Sunrise as a Delaware limited liability company on May 29, 2001 to complete construction of, own and operate a
gas-fired electric generation facility located in Kern County, California. The facility is being constructed in two phases. The first phase achieved commercial operation on June 29,
2001, and consists of a 320 MW simple-cycle peaking facility. During the second phase, the facility will be converted to a 580 MW combined cycle facility. Management expects the second phase to be
completed by August 1, 2003. Sunrise sells electric energy to the California Department of Water Resources (CDWR) for resale to electric consumers in California.

Sunrise
will terminate on the latter of 2011 or the date it elects to cease operations. Income or loss are allocated equally between the members.

NOTE 2: SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

Use of Estimates

The preparation of financial statements in conformity with accounting principles generally accepted in the United States of America requires management to make
estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements and the reported
amounts of revenues and expenses during the reporting period. Actual results could differ from those estimates.

Cash and cash equivalents

Cash and cash equivalents include cash on hand and highly liquid investments with original maturities of three months or less. The carrying amount of cash and
cash equivalents approximates fair value because of the short maturity of these instruments.

Inventories

Inventories primarily consist of spare parts for the operation of the generation facilities. Inventories are stated at the lower of weighted average cost or
market.

Risk management

The Westsides utilize gas swap agreements to mitigate their exposure to fluctuations in gas prices (see Note 6).

218

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Property, plant and equipment

Property, plant and equipment are stated at cost. The plant balance includes all costs incurred prior to commercial operation of the plants, net of revenue earned
during the pre-commission phase. Depreciation is calculated on a straight-line basis. The operating facilities and related equipment are depreciated over their estimated useful
lives, ranging from 27 to 30 years.

Normal
repairs for maintenance and minor replacements that do not improve or extend the lives of the assets are charged to expense as incurred.

Impairment of long-lived assets

Long-lived assets are reviewed for impairment whenever events or changes in circumstances indicate that the carrying amount of an asset may not be
fully recoverable. Recoverability of assets to be held
and used is measured by a comparison of the carrying amount of the assets to their fair value, which is normally determined through analysis of the future net cash flows expected to be generated by
the assets. If such assets are considered to be impaired, the impairment to be recognized is measured by the amount that the carrying amount of the assets exceeds the fair value of the assets.

Revenues

Revenue and related costs are recorded as electricity and steam are generated or services are provided.

As
a result of July 31, 2001 agreements to amend the related purchase power agreements (see Note 5), SCE paid Kern River and Sycamore one month in advance for services to
be provided in the following month. The advance payments were trued up the following month based on actual deliveries and gas prices. SCE stopped paying in advance after all past due amounts were paid
in March 2002. Prepaid amounts as of December 31, 2001 are reflected as unearned revenue in the accompanying financial statements.

Income taxes

The California Power Group includes partnerships and a limited liability corporation and its income is included in the income tax returns of the partners and
members. Therefore, no provision (benefit) for income taxes has been included in the accompanying financial statements.

Major maintenance accrual

The operating facilities require major maintenance, including inspections and overhauls, on a periodic basis. These costs are expensed as incurred.

Through
December 31, 1999, the Cogeneration Partnerships accrued for major maintenance costs during the period between turnarounds (referred to as the "accrue in advance"
accounting method). In March 2000, the Cogeneration Partnerships voluntarily decided to change their accounting policy to record major maintenance costs as an expense when incurred. This change
in accounting policy is considered preferable based on guidance provided by the Securities and Exchange Commission. In accordance with Accounting Principles Board Opinion No. 20, Accounting Changes,
 the Cogeneration

219

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Partnerships recorded a $16.8 million increase in income as the cumulative effect of change in the accounting for major maintenance costs.

Recent accounting pronouncements

On January 1, 2001, the California Power Group adopted Statement of Financial Accounting Standards (SFAS) No. 133, Accounting for Derivative Instruments
and Hedging Activities, as amended. Under SFAS 133, all derivative instruments, except those meeting
specific exceptions, are recognized in the balance sheet at their fair value. Changes in fair value are recognized immediately in earnings unless specific hedge accounting criteria are met. For
derivatives that qualify for hedge accounting, depending on the nature of the hedge, changes in fair value are either offset by changes in the fair value of the hedged assets, liabilities or firm
commitments through earnings, or recognized in other comprehensive income until the hedged item is recognized in earnings.

Management
has determined that the California Power Group's energy and capacity sales commitments and physical gas purchases qualify for the normal purchases and normal sales exception
provided by SFAS 133 and related guidance issued by the Derivatives and Implementation Group. This exception applies to physical sales and purchases of power or fuel where it is probable that
physical delivery will occur, the pricing provisions are clearly and closely related to the contracted prices and the SFAS 133 documentation requirements are met. Management also determined
that the Cogeneration Partnership's steam sales do not meet the definition of a derivative and are, therefore, not subject to the requirements of the standard. During 2001, the Westsides entered into
certain gas swaps that are subject to the requirements of SFAS 133 (see Note 6).

On
January 1, 2003, the California Power Group adopted SFAS No. 143,Accounting for Asset Retirement Obligations, which
requires entities to record the fair value of a liability for an asset retirement obligation in the period in which it is incurred. When the liability is initially recorded, the entity capitalizes the
cost by increasing the carrying amount of the related long-lived asset. Over time, the liability is increased to its present value each period, and the capitalized cost is depreciated over
the useful life of the related asset. Upon settlement of the liability, an entity either settles the obligation for its recorded amount or incurs a gain or loss upon settlement. Under certain of its
leases, the California Power Group is legally required to dismantle and remove the operating facilities at the end of the lease term. As of January 1, 2003, the California Power Group
recognized a liability of $16.3 million for asset retirement obligations. The cumulative effect of a change in accounting principle from unrecognized accretion and depreciation expense is a
loss of $11.2 million.

In
November 2002, the Financial Accounting Standards Board issued SFAS Interpretation No. 45,Guarantor's Accounting and Disclosure Requirements for
Guarantees, Including Indirect Guarantees of Indebtedness of Others. This interpretation established reporting requirements to be made by a guarantor about its obligations
under certain guarantees that it has issued. It also clarifies that a guarantor is required to recognize, at the inception of a guarantee, a liability for the fair value of the obligation undertaken
in issuing the guarantee. The initial recognition and initial measurement provisions of this interpretation are applicable on a prospective basis to guarantees issued or modified after
December 31, 2002. The California Power Group does not anticipate the adoption of this standard will have a significant effect on their financial position or the results of operations.

220

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NOTE 3: PROPERTY, PLANT AND EQUIPMENT

Property, plant and equipment consist of the following (amounts in thousands):

|                              |  | As of December 31, |         
|----------------------------- |  | ------------------ | --------
|
|Operating facilities          |  | $                  | 666,853 
|Other property and equipment  |  |                    | 18,974  
|                              |  |                    |         
|                              |  |                    | 685,827 
|Accumulated depreciation      |  |                    | (257,281
|Construction work in progress |  |                    | 124,724 
|                              |  |                    |         
|                              |  | $                  | 553,270 
|                              |  |                    |         

Depreciation
expense was approximately $22,652,000, $19,994,000 and $17,108,000 in 2002, 2001 and 2000, respectively.

NOTE 4: PROJECT FINANCING LOANS PAYABLE

Project financing loans payable consist of the following (amounts in thousands):

|               |  | As of December 31,
|-------------- |  | ------------------
|
|Coalinga       |  | $                 
|Salinas River  |  |                   
|Sargent Canyon |  |                   
|               |  |                   
|               |  | $                 
|               |  |                   

The
project financing loans payable are repaid in semi-annual equal installments of $5,050,000 on the last day of February and August, with the final payment of $4,850,000
due on May 30, 2003. The loans payable bear interest at the current Eurodollar market rate plus 1.2% per annum which is payable periodically throughout the year. The interest rate was 2.99% and
3.47% at December 31, 2002 and 2001, respectively. The carrying amount of Project financing loans payable approximates fair value based on the borrowing rates currently available to the
partnerships for long-term debt with similar terms and maturities.

The
project financing loans payable are secured by substantially all of the assets of Coalinga, Salinas River, and Sargent Canyon and place certain restrictions on capital distributions
and permitted investments. As of December 31, 2002, pledged assets total approximately $71.4 million. In addition, Coalinga, Salinas River, and Sargent Canyon are required to maintain on
deposit in an escrow account an amount equal to six months interest expense at an assumed market rate of 10% computed on the then outstanding balance and 5% of the loan balance. The monies on deposit
in the escrow account earn interest at the current market rate.

221

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NOTE 5: SALES AGREEMENTS

The California Power Group has entered into agreements for the sale of contract capacity and net energy and steam generated by the facilities as follows:

|               |  | Energy and Capacity |  | Steam     
|-------------- |  | ------------------- |  | ----------
|
|Kern River     |  | SCE                 |  | 08/09/2005
|Sycamore       |  | SCE                 |  | 12/31/2007
|Coalinga       |  | PG&E                |  | 03/05/2007
|Mid-Set        |  | PG&E                |  | 05/19/2004
|Salinas River  |  | PG&E                |  | 03/06/2007
|Sargent Canyon |  | PG&E                |  | 02/22/2007
|Sunrise        |  | CDWR                |  | 06/31/2012

Energy and Capacity

Eastsides

The Eastsides have entered into Parallel Generation Agreements (PGA) with SCE for long-term sales of contract capacity and net energy. Under the terms
of the agreements, payments for energy are based on a rate calculated using a short-run-avoided-cost based formula (SRAC Floor Formula) that contains a prescribed
energy rate indexed to the Southern California Border spot price of natural gas, and the quantity of kilowatts delivered during on-peak, mid-peak, off-peak and
super off-peak hours.

SCE
also pays the Eastsides for firm capacity based on a contracted amount per kilowatt year, as defined in the PGA. In the event Kern River or Sycamore unilaterally terminates the PGA
prior to the termination date or fail to meet certain performance requirements, the partnership would be required to repay certain capacity payments to SCE. Under these provisions, as of
December 31, 2002, the Eastsides have a total obligation of $69,239,000. Management has no reason to believe that either one of the Eastsides will terminate the PGA or fail to meet the
performance requirements during the remaining term.

On
July 31, 2001, the Eastsides and SCE entered into agreements to resolve issues associated with SCE's failure to pay amounts owed to the Eastsides. In accordance with the terms
of the agreements, all past due amounts (amounting to approximately $230.4 million) were repaid on March 12, 2002.

Prior
to July 1, 2002, Kern River had an agreement to sell contract capacity and net energy to Texaco Exploration and Production Inc. (TEPI), a wholly-owned subsidiary of
Chevron. This agreement was terminated as of July 1, 2002. Kern River sold $5,974,000, $28,517,000 and $20,760,000 to TEPI under this agreement during the years ended December 31, 2002,
2001 and 2000, respectively. As a result of the termination of the TEPI agreement, effective December 6, 2002, Kern River amended the agreement with SCE to increase minimum contract capacity
from 274 MW to 280 MW. The additional capacity payments will be calculated at a rate of $143/kW-year.

Westsides

The Westsides each have Power Purchase Agreements (PPA) with PG&E for the sale of contract capacity and net energy. Under the terms of the agreements, prior to
October 1, 2001, payments for energy were based on an SRAC rate calculated based on PG&E's 1995 average price with an

222

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adjustment to reflect the monthly changes in spot natural gas prices at the California border. As a result of July 31, 2001 amendments to the PPAs, effective October 1, 2001, the energy
price was changed to a fixed price for the remaining term of the contracts. The fixed price will be adjusted based on the amounts of energy delivered during on-peak hours. As of
December 31, 2002, the average fixed energy price was $53.70 per megawatt hour (MWh).

PG&E
also pays the Westsides for firm capacity based on a contracted amount per kilowatt year, as defined in the PPAs. In the event one of the Westsides unilaterally terminates its PPA
prior to the termination date or fail to meet certain performance requirements, the partnership would be required to repay certain capacity payments to PG&E. Under these provisions, as of
December 31, 2002, the Westsides have a total obligation of $17,674,000. Management has no reason to believe that any of the Westsides will terminate its PPA or fail to meet the performance
requirements during the remaining term.

On
April 6, 2001, PG&E filed a Chapter 11 bankruptcy petition. On February 14, 2002, the bankruptcy court approved an agreement for the payment of past due amounts totaling
$3.5 million due to the Eastsides. The agreement required the immediate payment of accrued interest and payment of the outstanding balance with interest in equal monthly payments ending
January 31, 2003. PG&E made the final payment when due on January 31, 2003.

Sunrise

Sunrise has a Power Purchase Agreement with CDWR (the CDWR PPA) for the sale of contract capacity and associated energy. The CDWR PPA is contracted in two phases
pending the conversion of the simple-cycle facility to a combined-cycle facility. In January 2003, Sunrise agreed to restructure the second phase of the CDWR PPA. The initial term of the CDWR
PPA will remain in effect until the
commencement of commercial operation of phase two. The second phase will extend through June 30, 2012. Under the terms of the amended agreement, Sunrise will receive capacity payments at a rate
of $170.60 per kilowatt year. Sunrise is also compensated for the number of times the plant is started, which is at the discretion of the State of California.

Sunrise
has no firm contracts for fuel supply. CDWR reimburses Sunrise for all costs, expenses and charges incurred by Sunrise for fuel management, procurement, transportation, storage
and delivery of fuel used by the Sunrise facility for the generation of electricity on behalf of CDWR. The fuel costs and CDWR reimbursement of fuel costs are presented in the Combined Statement of
Income as Fuel costs and Sales of energy, respectively.

Steam Sales

The counterparties to the steam sales agreements pay a steam fuel charge based on the quantity and quality of steam delivered during the month. Pricing for the
steam varies as follows:



223

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The
prices also generally include a processing charge per MMBTu as defined in the agreements. The amount of steam sold under these agreements is expected to be sufficient for the
Cogeneration Partnerships to continue to maintain qualifying facility status.

NOTE 6: PRICE RISK MANAGEMENT

The Cogeneration Partnerships are exposed to price risk associated with the purchase of natural gas for the cogeneration facilities. Market risk arises from the
potential change in the value of financial instruments and physical commodities based on fluctuations in commodity prices and bases. Market risk is also affected by changes in the volatility and
liquidity in markets in which these instruments are traded.

The
Westsides manage approximately 55% of their exposure to fluctuations in the price of natural gas through the use of natural gas swap agreements. Effective November 1, 2001,
the Westsides entered into 24,000 MMBtu per day forward fixed natural gas contacts purchased on the NYMEX exchange with basis swaps at Permian, Southern California Border and San Juan in an attempt to
mitigate price variability through May 31, 2004 (Mid-Set) and September 30, 2006 (Sargent Canyon, Salinas River and Coalinga). Under the agreements, the Westsides make or
receive payment on a specific quantity of natural gas based on the differential between a specified fixed price and the market price of gas at Permian, Southern California Border or San Juan. The
gains and losses related to these hedging instruments will offset fluctuations in the Westsides natural gas costs.

Prior
to January 1, 2003, the gas swap agreements were not formally designated as cash flow hedges; therefore, unrealized gains or losses on the gas swaps are recorded as part of
Fuel expense in the Statements of Income. Effective January 1, 2003, management has designated the contracts as cash flow hedges; therefore, on a go forward basis gains or losses associated
with the effective portion of the hedges will be recorded in other comprehensive income. The fair market value of derivative financial instruments is determined through dealer quotes and may not be
representative of the actual gains or losses that will be recorded when these instruments mature due to future fluctuations in the markets in which they are traded.

Under
the terms of their parallel generation agreements, the Eastsides receive payments for energy based on a formula that is indexed to the Southern California Border spot price of
natural gas. This pricing formula reduces the Eastsides' exposure to changes in gas prices. Under the terms of its power purchase agreement, Sunrise is reimbursed for fuel costs; therefore, Sunrise is
not exposed to price risk associated with gas purchases.

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NOTE 7: RELATED PARTY OPERATING AGREEMENTS

Operating expenses include the following amounts paid to related parties (amounts in thousands):

|                                         |                                                 | For the years ended December 31,
|---------------------------------------- | ----------------------------------------------- | --------------------------------
|
|Fuel expense                             |                                                 |                                 
|                                         | Texaco Natural Gas, Inc.                        |                                 
|                                         | Edison Mission Marketing & Trading, Inc.        |                                 
|Other operations and maintenance expense |                                                 |                                 
|                                         | Edison Mission Operations and Maintenance, Inc. |                                 
|                                         | Mission and affiliates                          |                                 
|                                         | Chevron (land leases)                           |                                 
|                                         | Other                                           |                                 
|Administrative and general               |                                                 |                                 
|                                         | Chevron USA                                     |                                 
|                                         | Texaco Power and Gasification Holdings Inc      |                                 
|                                         |                                                 |                                 
|                                         |                                                 | $                               
|                                         |                                                 |                                 

Fuel Management Agreements

The Cogeneration Partnerships have entered into fuel management agreements with Texaco Natural Gas, Inc. (TNGI), a wholly-owned subsidiary of Chevron,
whereby TNGI procures gas on a spot basis for the partnerships, seeking the lowest possible price balanced with the need for secure supply. The agreements continue until the termination of the related
power purchase agreements. TNGI receives a fixed service fee per MMBtu of fuel gas supplied to the Cogeneration Partnerships, subject to escalation as defined by the agreements. The Cogeneration
Partnerships paid service fees of approximately $2,998,000, $3,110,000 and $2,924,000 as of December 31, 2002, 2001 and 2000, respectively.

Sunrise
is party to an agreement with Edison Mission Marketing & Trading, Inc. (EMMT), a wholly-owned subsidiary of EME, whereby EMMT is to purchase and/or nominate fuel
for and related transportation to the Sunrise facility. The term of this agreement shall remain in effect until terminated by either party with sixty days prior written notice. EMMT receives a fixed
service fee of $0.005 per MMBtu of fuel gas supplied to Sunrise, subject to escalation as defined by the agreement.

Operations and Maintenance Agreements

The members of the California Power Group have entered into agreements with Edison Mission Operation and Maintenance, Inc. (EMOM), a wholly-owned
subsidiary of EME, whereby EMOM performs all operations and maintenance activities necessary for the production of electricity and steam. The agreements will continue until terminated by either party
(the Sunrise agreement requires ninety day prior written notice). EMOM is paid for all costs incurred in connection with operating and maintaining the facilities and may earn incentive compensation as
set forth in the agreements. Amounts paid to EMOM by the California Power Group under these agreements included incentive
compensation of $926,000, $901,000 and $1,084,000 for the years ended December 31, 2002, 2001 and 2000, respectively.

225

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Emission Credits

As part of their initial capital contribution, subsidiaries of Chevron contributed their rights to certain emission offset credits to Kern River, Sycamore and
Mid-Set. EME contributed cash equal to the agreed upon fair value for the credits of $43.3 million. The emission credits have been accounted for at their historical cost of $0 in
the accompanying financial statements.

Land Leases

Certain of the entities in the California Power Group have entered into long-term land leases with Chevron as follows:

|              |  | Termination date |  | Renewal options                                     
|------------- |  | ---------------- |  | ----------------------------------------------------
|Kern River    |  | 04/30/2009       |  | Kern River can extend indefinitely                  
|Mid-Set       |  | 07/15/2006       |  | Mid-Set has the option to extend at any time        
|Salinas River |  | 08/01/2008       |  | Parties may agree to up to 15 one year extensions   
|Sunrise       |  | 11/30/2025       |  | Sunrise has a one-time option to extend for 25 years
|Sycamore      |  | 01/18/2019       |  | None                                                

Lease
payments are indexed to fluctuations in the gross domestic product as defined in the agreements. In addition, the Sunrise lease is subject to a 3% annual increase and Chevron may
charge Sunrise additional amounts for property taxes or government assessments.

Engineering and Administrative Agreements

The Cogeneration Partnerships has agreements with Texaco Inc., a wholly-owned subsidiary of Chevron, whereby Texaco Inc. shall perform work consisting of
engineering and administrative activities required for operation of the Cogeneration Partnerships. Under the terms of the agreement, Texaco Inc. is paid for all costs incurred in connection with the
engineering and administration of the Cogeneration Partnerships. The agreements shall remain in effect until terminated by either party. Effective November 1, 2002, the rights and obligations
of these agreements were assigned to Chevron USA.

Sunrise
has an agreement with Texaco Power and Gasification Holdings Inc. (TPGHI), a wholly-owned subsidiary of Chevron, whereby TPGHI performs all engineering and administrative
activities required by the Sunrise facility. Under the terms of the agreement, TPGHI is paid for all costs incurred in connection with engineering and administrating the Sunrise facility. The
agreement became effective June 25, 2001 and shall remain in effect until terminated by either party with ninety days prior written notice.

NOTE 8: COMMITMENTS AND CONTINGENCIES

Ship or Pay

Pursuant to the terms of the Security of Supply Agreement (the Security Agreement) dated December 1, 1994, the Eastsides and Mid-Set agreed to
underwrite a portion of firm transportation capacity that had been obtained by TNGI from El Paso Gas Pipeline Company (El Paso) under an agreement dated February 15, 1989 (the
El Paso Agreement) and from Mojave Pipeline Company (Mojave) under an agreement dated February 15, 1989 (the Mojave Agreement). The terms of the El Paso and Mojave Agreements
extend to April 1, 2007. Under the original terms of the Security

226

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Agreement, the Eastsides and Mid-Set are required to transport the lesser of 75% of each facility's annual fuel gas requirement or 52,012,500 MMBtu under the terms of the El Paso
and Mojave Agreements or to pay the reservation portion of the transportation fee under each of the transportation
agreements to meet the volumetric commitment. The reservation fees under the two transportation agreements total $0.64 per MMBtu.

As
a consequence of a capacity reallocation program on the El Paso system mandated by the Federal Energy Regulatory Commission (FERC) in 2002, the volume obligations of the
Eastsides and Mid-Set under the Security Agreement with respect to the El Paso Agreement were modified. Effective November 1, 2002, the volumetric obligations were revised such that
Kern River and Sycamore are each financially responsible for 38,986 MMBtu per day or capacity and Mid-Set is financially responsible for 6,000 MMBtu per day of capacity. The
Mid-Set obligation expires on May 1, 2004, at which time Kern River and Sycamore each assume responsibility for one-half of the Mid-Set former obligation.
The Kern River obligation extends to August 9, 2005 and the Sycamore obligation extends to April 1, 2007.

On
July 20, 1990, the Eastsides agreed to accept and underwrite a portion of Chevron's transportation agreement between Chevron and Northwest Pipeline Company extending through
the term of the Eastsides sales agreements with SCE. Under the terms of the agreement, the Eastsides are required to transport 3,558,750 MMBtu annually. The Eastsides would be required to pay $0.30
per deficit MMBtu for failure to transport the required quantity of natural gas on the pipeline. There was no such deficit in 2002, 2001 or 2000. During 2002, all of the Eastsides obligations were
brokered to third parties.

Firm Transportation Agreement

Sunrise has an agreement with the Kern River Gas Transmission Company effective May 2003 and extending for 15 years thereafter, for the right to
firm transportation of 85,000 MMBtu per day of natural gas on the Kern River Gas Transmission Sunrise's pipeline between the Rockies-Opal and the Sunrise facility. The transportation rates
paid by Sunrise will be in accordance with Kern River Gas Transmission Sunrise's tariff schedule filed with the FERC. The reservation fee under the tariff for expansion capacity is currently estimated
to be $0.051 per MMBtu of gas. CDWR will reimburse Sunrise for all costs associated with the agreement during the term of the Power Purchase Agreement.

Long-term Service Agreement

Sunrise has a long-term service agreement with General Electric International, Inc. (GEI), a wholly owned affiliate of General Electric, to
help manage the costs of major maintenance repairs. The agreement terminates on December 21, 2020. Under the terms of the agreement, GEI provides planned and unplanned major maintenance
services and materials. Sunrise pays an annual fee of $250,000 plus a variable fee based on fired hours and factored starts. All fees are subject to escalations based on the consumer price index.
Sunrise also pays for materials priced at a 15% discount to GE's list price and services based on time and materials, discounted at 7%. GE earns an incentive fee based on the availability of the
turbines and is required to pay Sunrise if the turbines do not attain an annual availability factor of 97.5%. There is a $3 million cap on the incentive and availability fees.

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Engineering, Procurement and Construction Agreement

Sunrise has a cost plus construction contract with an independent third-party to engineer, design, furnish, install and provide test services to place into
operation a conversion of the simple-cycle facility to a combined-cycle facility. The contract provides financial incentives to the contractor for completing the project on a timely basis, below
budget and for exceeding certain performance targets. The contract also includes termination penalties of up to $10 million for which performance has been guaranteed by EME and TPGHI. Sunrise
incurred $170.2 million related to the services provided by the contractor through December 31, 2002, which was capitalized in property, plant and equipment at year-end. As of
December 31, 2002, management believes the remaining portion of the combined-cycle facility will cost approximately $47.5 million.

Credit Risk

The California Power Group is exposed to credit risk related to potential nonperformance by counter parties to its energy and capacity and steam sales. The
California Power Group's sales are concentrated among five primary counter parties:

|                                         |  | For the years ended December 31,
|---------------------------------------- |  | --------------------------------
|
|
|Southern California Edison Company       |  | $                               
|Pacific Gas & Electric Company           |  |                                 
|California Department of Water Resources |  |                                 
|Aera Energy, LLC                         |  |                                 
|Affiliates of Chevron                    |  |                                 
|                                         |  |                                 
|                                         |  | $                               
|                                         |  |                                 

Due
to the concentration of credit risk, the California Power Group's liquidity could be impacted by financial difficulties experienced by its counter parties. As a result of the energy
crisis in California, SCE and PG&E suspended payment of amounts due to the Cogeneration Partnerships in December 2000. PG&E is still under Chapter 11 bankruptcy protection and SCE is below
investment grade. However, all past due amounts have now been paid.

Operational Risks

The depreciable lives of the operating facilities exceed the term of the related power purchase agreements. The viability of the facilities subsequent to the
expiration of the power purchase agreements is uncertain and is dependent on the market price of power, the cost to produce power compared to more efficient plants and the ability to sell steam at an
economic rate to the steam hosts. In accordance with its policy for testing impairment of long-lived assets (see Note 2), management periodically evaluates the expected viability of
the plants subsequent to the expiration of the purchase power agreements. Management currently believes that the useful lives are appropriate and that the facilities will continue to operate
profitably subsequent to the expiration of the respective purchase power agreements. However, if management subsequently determines that the plants will not be able to operate profitably beyond the
term of the purchase power agreements, management will accelerate depreciation of the plants and an impairment charge may be required.

228

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REPORT OF INDEPENDENT AUDITORS

The
Management Committee of
Watson Cogeneration Company

We
have audited the accompanying balance sheets of Watson Cogeneration Company (the Company) as of December 31, 2002 and 2001, and the related statements of income, partners'
capital, and cash flows for each of the three years ended December 31, 2002. These financial statements are the responsibility of the Company'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 Watson Cogeneration Company at December 31, 2002 and
2001, and the results of its operations and cash flows for each of the three years ended December 31, 2002 in conformity with accounting principles generally accepted in the United States.

/s/ERNST & YOUNG LLP

Long
Beach, California
February 7, 2003

229

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WATSON COGENERATION COMPANY    BALANCE SHEETS

|                                        |                                                  | December 31,                                    
|--------------------------------------- | ------------------------------------------------ | ------------------------------------------------
|
|
|Assets                                  |                                                  |                                                 
|Current assets:                         |                                                  |                                                 
|                                        | Cash and cash equivalents                        |                                                 
|                                        | Receivables:                                     |                                                 
|                                        |                                                  | Southern California Edison Company              
|                                        |                                                  | BP West Coast Products LLC                      
|                                        |                                                  | CPC Cogeneration LLC                            
|                                        |                                                  | Other receivables                               
|                                        | Inventories                                      |                                                 
|                                        | Prepaid expenses                                 |                                                 
|                                        |                                                  |                                                 
|Total current assets                    |                                                  |                                                 
|Property, plant and equipment, net      |                                                  |                                                 
|Intangible assets, net                  |                                                  |                                                 
|                                        |                                                  |                                                 
|Total assets                            |                                                  | $                                               
|                                        |                                                  |                                                 
|Liabilities and partners' capital       |                                                  |                                                 
|Current liabilities:                    |                                                  |                                                 
|                                        | Accounts payable                                 |                                                 
|                                        | Payables:                                        |                                                 
|                                        |                                                  | Southern California Edison Company              
|                                        |                                                  | BP West Coast Products LLC and BP Energy Company
|                                        | Advance payments from Southern California Edison |                                                 
|                                        | Interest payable                                 |                                                 
|                                        |                                                  |                                                 
|Total current liabilities               |                                                  |                                                 
|Long-term debt:                         |                                                  |                                                 
|                                        | Camino Energy Company                            |                                                 
|                                        | Atlantic Richfield Company                       |                                                 
|Partners' capital                       |                                                  |                                                 
|                                        |                                                  |                                                 
|Total liabilities and partners' capital |                                                  | $                                               
|                                        |                                                  |                                                 

See
accompanying notes.

230

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WATSON COGENERATION COMPANY    STATEMENTS OF INCOME

|               |                                                                      | Year ended December 31,           
|-------------- | -------------------------------------------------------------------- | ----------------------------------
|
|
|Revenues:      |                                                                      |                                   
|               | Sales:                                                               |                                   
|               |                                                                      | BP West Coast Products LLC        
|               |                                                                      | Southern California Edison Company
|               |                                                                      | CPC Cogeneration LLC              
|               | Interest income                                                      |                                   
|               |                                                                      |                                   
|Total revenues |                                                                      |                                   
|Expenses:      |                                                                      |                                   
|               | Fuel purchases from BP West Coast Products LLC and BP Energy Company |                                   
|               | Fuel transportation costsSouthern California Edison Company         |                                   
|               | Fuel other                                                           |                                   
|               | Other operating                                                      |                                   
|               | Depreciation and amortization                                        |                                   
|               | Personnel compensation and other benefitsBP West Coast Products LLC |                                   
|               | Property taxes                                                       |                                   
|               | Interconnection fee to Southern California Edison Company            |                                   
|               | Services fees to BP West Coast Products LLC                          |                                   
|               | Interest                                                             |                                   
|               | Miscellaneous expenses                                               |                                   
|               |                                                                      |                                   
|Total expenses |                                                                      |                                   
|               |                                                                      |                                   
|Net income     |                                                                      | $                                 
|               |                                                                      |                                   

See
accompanying notes.

231

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WATSON COGENERATION COMPANY    STATEMENTS OF PARTNERS' CAPITAL

|                             |                       | Camino
Energy
Company |         | Products
Cogeneration
Company |   | Carson
Cogeneration
Company |        | Total |        
|---------------------------- | --------------------- | --------------------- | ------- | ----------------------------- | - | --------------------------- | ------ | ----- | -------
|
|Balance at December 31, 1999 |                       | $                     | 80,279  |                               | $ | 3,277                       |        | $     | 80,279 
|                             | Capital distribution  |                       |         | (40,670                       | ) |                             | (1,660 | )     |        
|                             | Net income            |                       |         | 41,190                        |   |                             | 1,681  |       |        
|                             |                       |                       |         |                               |   |                             |        |       |        
|Balance at December 31, 2000 |                       |                       | 80,799  |                               |   | 3,298                       |        |       | 80,799 
|                             | Capital distributions |                       |         | (980                          | ) |                             | (40    | )     |        
|                             | Net income            |                       |         | 53,554                        |   |                             | 2,186  |       |        
|                             |                       |                       |         |                               |   |                             |        |       |        
|Balance at December 31, 2001 |                       |                       | 133,373 |                               |   | 5,444                       |        |       | 133,373
|                             | Capital distributions |                       |         | (99,470                       | ) |                             | (4,060 | )     |        
|                             | Net income            |                       |         | 32,626                        |   |                             | 1,332  |       |        
|                             |                       |                       |         |                               |   |                             |        |       |        
|Balance at December 31, 2002 |                       | $                     | 66,529  |                               | $ | 2,716                       |        | $     | 66,529 
|                             |                       |                       |         |                               |   |                             |        |       |        

See
accompanying notes.

232

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WATSON COGENERATION COMPANY        STATEMENTS OF CASH FLOWS

|                                                                                  |                                              | Year ended December 31,                          |         
|--------------------------------------------------------------------------------- | -------------------------------------------- | ------------------------------------------------ | --------
|
|
|Operating activities                                                              |                                              |                                                  |         
|Net income                                                                        |                                              | $                                                | 66,584  
|Adjustments to reconcile net income to net cash provided by operating activities: |                                              |                                                  |         
|                                                                                  | Depreciation and amortization                |                                                  |         
|                                                                                  | Changes in operating assets and liabilities: |                                                  |         
|                                                                                  |                                              | Receivables                                      |         
|                                                                                  |                                              | Inventories                                      |         
|                                                                                  |                                              | Prepaid expenses                                 |         
|                                                                                  |                                              | Accounts payable                                 |         
|                                                                                  |                                              | Affiliate payables                               |         
|                                                                                  |                                              | Advance payments from Southern California Edison |         
|                                                                                  |                                              |                                                  |         
|Net cash provided by operating activities                                         |                                              |                                                  | 185,524 
|Investing activities                                                              |                                              |                                                  |         
|Additions to property, plant and equipment                                        |                                              |                                                  | (2,584  
|                                                                                  |                                              |                                                  |         
|Net cash used in investing activities                                             |                                              |                                                  | (2,584  
|                                                                                  |                                              |                                                  |         
|Financing activities                                                              |                                              |                                                  |         
|Distributions to partners                                                         |                                              |                                                  | (203,000
|                                                                                  |                                              |                                                  |         
|Net cash used in financing activities                                             |                                              |                                                  | (203,000
|                                                                                  |                                              |                                                  |         
|Net (decrease) increase in cash and cash equivalents                              |                                              |                                                  | (20,060 
|Cash and cash equivalents at beginning of year                                    |                                              |                                                  | 23,732  
|                                                                                  |                                              |                                                  |         
|Cash and cash equivalents at end of year                                          |                                              | $                                                | 3,672   
|                                                                                  |                                              |                                                  |         
|Supplemental information                                                          |                                              |                                                  |         
|Interest paid                                                                     |                                              | $                                                | 2,687   

See
accompanying notes.

233

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WATSON COGENERATION COMPANY        NOTES TO FINANCIAL STATEMENTS        DECEMBER 31, 2002

1.    General

Watson Cogeneration Company (WCC) is a general partnership among Products Cogeneration Company (PCC), a wholly owned subsidiary of Atlantic Richfield Company, a
wholly owned subsidiary of BP America Inc. (BP); Carson Cogeneration Company (CCC), a wholly owned subsidiary of CH-Twenty, Inc., a majority-owned subsidiary of Atlantic Richfield
Company, and Camino Energy Company (CEC), a wholly owned subsidiary of Edison Mission Energy, a wholly owned subsidiary of Mission Energy Holding Company, a wholly owned subsidiary of The Mission
Group, a wholly owned non-utility subsidiary of Edison International, the parent holding company of Southern California Edison Company (SCE). PCC, CCC and CEC own 2%, 49% and 49% of the
partnership, respectively. The WCC partnership agreement provides for its termination at the termination of the power purchase agreement with SCE in 2008, unless otherwise extended by the partners.

WCC
was organized under California law in 1986 to design, construct, own and operate a cogeneration facility (Facility), which became fully operational in 1988. WCC, which operates in
one business segment, produces and sells electric energy to SCE for resale to its customers, produces and sells electric energy to CPC Cogeneration LLC (CPC), a limited liability company, owned by
PCC, CCC and CEC 2%, 49% and 49%, respectively. CPC sells power to BP West Coast Products LLC (BPWCP), pursuant to a Power Purchase and Sale Agreement, which was assigned to CPC from WCC. WCC
also produces and sells steam to BPWCP for use at its Carson refinery, and purchases water and fuel gas from BPWCP's Carson refinery. CPC was terminated effective at the close of business
December 31, 2002.

PCC
serves as the managing partner. Insurance coverage is provided by PCC and CEC. WCC reimburses PCC's affiliate BPWCP for personnel compensation and other benefits for operating and
maintaining the Facility. Additionally, BPWCP provides other ancillary services to the partnership under a services contract for a fee.

The
Facility is located on the property of the Carson Refinery of BPWCP. The right to use the property, the refinery infrastructure, and other related rights were contributed by PCC to
WCC at its formation. The rights expire in 2008.

The
results of WCC's operations and its financial position may be significantly different without its relationships with its partners.

2.    Summary of Significant Accounting Policies

Cash and Cash Equivalents

Cash and cash equivalents include highly liquid investments with original maturities of less than 90 days.

Revenue Recognition

Electrical energy and steam revenue and related costs are recognized upon transmission to the customer.

234

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Inventories

Inventories are comprised of materials and supplies, and are stated at their lower of average cost or market.

Property, Plant and Equipment

Property, plant and equipment are stated at cost and are depreciated over the estimated useful lives on a straight-line basis with asset lives ranging
from five to 30 years.

Intangible Assets

Intangible assets are recorded at cost and are amortized on a straight-line basis over 20 years.

Repair and Maintenance

Repair and maintenance costs, including turnarounds, which are incurred in connection with planned major maintenance activities at the cogeneration facility, are
expensed when incurred.

Reclassifications

Certain reclassifications were made to the 2001 amounts to conform to the 2002 presentation.

New Accounting Pronouncements

FASB Statement No. 144

In October 2001, the FASB issued SFAS No. 144,Accounting for the Impairment or Disposal of Long-Lived
Assets,which establishes one accounting model to be used for long-lived assets to be disposed of by sale and broadens the presentation of discontinued operations
to include more disposal transactions. SFAS No. 144 supersedes SFAS No. 121,Accounting for the Impairment of Long-Lived Assets and for
Long-Lived Assets to Be Disposed Of,and the accounting and reporting provisions of Accounting Principle Board (APB) Opinion No. 30. SFAS No. 144 was
effective for fiscal years beginning after December 15, 2001. The adoption of SFAS No. 144 in January 2002 did not have a material impact on the Company's
consolidated financial position or results of operations, and we do not expect any impact in the foreseeable future.

FASB Statement No. 143

In June 2001, the FASB issued Statement No. 143,Accounting for Asset Retirement Obligations.
Statement No. 143 requires entities to record the fair value of a liability for an asset retirement obligation when an existing law or contract requires that the obligation be settled. The
statement requires that the amount recorded as a liability be capitalized by increasing the carrying amount of the related long-lived asset. Subsequent to initial measurement, the
liability is accreted to the ultimate amount anticipated to be paid, and is also adjusted for revisions to the timing or amount of estimated cash flows. The capitalized cost is depreciated over the
useful life of the related asset. Upon settlement of the liability, an entity either settles the obligation for its recorded amount or incurs a gain or loss upon settlement. Statement No. 143
will be effective for financial statements beginning January 1, 2003,

235

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with earlier application encouraged. The Company is currently evaluating the impact of adopting this statement.

Estimates

The preparation of financial statements in conformity with accounting principles generally accepted in the United States requires management to make estimates and
assumptions that affect the reported amounts of assets and liabilities and disclosures of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues
and expenses during the reporting period. Actual results could differ from those estimates.

3.    Southern California Edison Company

The receivable from SCE at December 31, 2001, represents amounts due for power sales for the period from November 30, 2000 to March 25, 2001.
During August 2001, an advance payment agreement was reached between SCE and WCC, whereby SCE must pay WCC for power purchases in advance. The outstanding receivables balance from
November 2000 to March 2001 and accrued interest was paid by SCE in March 2002. In 2002 and 2001 WCC recorded interest income of approximately $1,497,000 and $7,821,000,
respectively, on the outstanding receivables. Subsequent to March 2002, WCC no longer charged interest to SCE on their outstanding balance.

4.    Property, Plant and Equipment

Property, plant and equipment consists of the following:

|                              |  | 2002 |          | 2001 |  
|----------------------------- |  | ---- | -------- | ---- | -
|
|Plant                         |  | $    | 298,847  |      | $
|Construction-in-progress      |  |      | 2,532    |      |  
|Other                         |  |      | 5,747    |      |  
|                              |  |      |          |      |  
|                              |  |      | 307,126  |      |  
|Less accumulated depreciation |  |      | (158,298 | )    |  
|                              |  |      |          |      |  
|                              |  | $    | 148,828  |      | $
|                              |  |      |          |      |  

Depreciation
expense amounted to approximately $10,472,000, $9,973,000, and $10,609,000 for 2002, 2001, and 2000, respectively.

5.    Intangible Assets

Intangible assets, net of accumulated amortization of approximately $21,430,000 and $18,693,000 at December 31, 2002 and 2001, respectively, consist of
outside boundary limit facilities, refinery infrastructure, environmental permits, and land use, which was contributed to the partnership at its formation. Amortization expense was approximately
$2,737,000, $2,334,000, and $1,127,000 for 2002, 2001 and 2000, respectively. Amortization for the next five years is estimated at $2,737,000 per year.

236

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6.    Related Party Debt

The related party debt matures in 2008 and payments of interest only, at a rate of 5%, are due semiannually on April 1 and October 1.

During
the year ended December 31, 2001, WCC borrowed and repaid $1,420,000, $34,790,000, and $34,790,000 from PCC, CCC, and CEC, respectively. The borrowings accrued interest at
LIBOR plus 3% per annum. WCC paid approximately $2,848,000 in interest on these borrowings, during the year ended December 31, 2001, which is included in interest expense.

7.    Significant Contracts

Power Purchase Contract with SCE

Under the terms of the Power Purchase Contract with SCE (SCE Power Purchase Contract), WCC has contracted to sell power generated by the Facility, but not sold to
BPWCP, to SCE at contract rates recognized by the Public Utilities Commission of the State of California. The SCE Power Purchase Contract is for a period, which ends in 2008.

Power, Steam, Fuel, and Water Contracts with BP Affiliates

WCC entered into a Power Purchase and Sale Agreement with BPWCP (as successor to Atlantic Richfield Company), which was assigned, via an Assignment Agreement, to
CPC following CPC's formation. The agreement contains provisions to sell power generated by the Facility to BPWCP's Carson refinery under terms similar to the SCE Power Purchase Contract. Under the
terms of the Water and Steam Purchase and Sale Agreement with BPWCP, WCC contracted to sell steam generated by the Facility to, and to purchase water from, BPWCP's Carson refinery.

In
addition, WCC and CPC agreed to enter into an Energy Sales Agreement (ESA) under which WCC sells power to CPC. The assignment of the Power Purchase and Sale Agreement and the
consummation of the ESA has not had a material effect on the companies.

CPC
was terminated effective at the close of business December 31, 2002. Upon the termination of CPC, the Assignment Agreement was terminated thereby restoring the Power Purchase
and Sale Agreement as a contract between WCC and BPWCP. At the same time, the Energy Sales Agreement between WCC and CPC was terminated, as well as the Services Agreement between WCC and CPC.

Interconnection Facilities Agreement

Under the terms of an Interconnection Facilities Agreement, WCC shall pay a monthly charge to SCE, as defined in the contract, for a portion of the
Interconnection Facilities, which are owned, operated and maintained by SCE.

Other

WCC has entered into water and fuel (natural gas, refinery gas, butane and chemicals) purchase agreements with BP West Coast Products LLC and BP Energy
Company. WCC purchases under these agreements amounted to approximately $122,000,000, $208,000,000, and $154,000,000 during 2002, 2001, and 2000, respectively.

237

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WCC
reimburses PCC's affiliate BPWCP for personnel compensation and other benefits for operating and maintaining the Facility. Additionally, BPWCP provides other ancillary services to
the partnership under a services contract for a fee.

8.    Income Taxes

Income taxes are not recorded by the partnership since the net income or loss is allocated to the partners and included in their respective income tax returns.

9.    Fair Value of Financial Instruments

The fair value of WCC's long-term debt was estimated based on current rates of the same or similar issues. The fair value of the long-term
debt was approximately $40,584,000 and $44,300,000 at December 31, 2002 and 2001, respectively.

10.  Concentrations of Credit Risk

WCC invests its cash primarily in deposits with major banks. Certain deposits may, at times, be in excess of federally insured limits. WCC has not incurred losses
related to such cash balances.

238

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REPORT OF INDEPENDENT AUDITORS

The
Management Committee of
CPC Cogeneration LLC

We
have audited the accompanying balance sheets of CPC Cogeneration LLC (the Company) as of December 31, 2002 and 2001, and the related statements of income, members'
equity, and cash flows for each of the three years ended December 31, 2002. These financial statements are the responsibility of the Company'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 CPC Cogeneration LLC at December 31, 2002 and
2001, and the results of its operations and its cash flows for each of the three years ended December 31, 2002 in conformity with accounting principles generally accepted in the United States.

/s/ERNST & YOUNG LLP

Long
Beach, California
January 31, 2003

239

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CPC COGENERATION LLC  (A LIMITED LIABILITY COMPANY)        BALANCE SHEETS

|                                      |                                            | December 31
|------------------------------------- | ------------------------------------------ | -----------
|
|
|Assets                                |                                            |            
|Current assets:                       |                                            |            
|                                      | Cash and cash equivalents                  |            
|                                      | Receivable from BP West Coast Products LLC |            
|                                      |                                            |            
|Total current assets                  |                                            |            
|                                      |                                            |            
|Total assets                          |                                            | $          
|                                      |                                            |            
|Liabilities and members' equity       |                                            |            
|Current liabilities:                  |                                            |            
|                                      | Payable to Watson Cogeneration Company     |            
|                                      |                                            |            
|Total current liabilities             |                                            |            
|Members' equity                       |                                            |            
|                                      |                                            |            
|Total liabilities and members' equity |                                            | $          
|                                      |                                            |            

See
accompanying notes.

240

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CPC COGENERATION LLC  (A LIMITED LIABILITY COMPANY)        STATEMENTS OF INCOME

|               |                                            | Year ended December 31    
|-------------- | ------------------------------------------ | --------------------------
|
|
|Revenues:      |                                            |                           
|               | Sales:                                     |                           
|               |                                            | BP West Coast Products LLC
|               | Interest income                            |                           
|               |                                            |                           
|Total revenues |                                            |                           
|Expenses:      |                                            |                           
|               | Purchases from Watson Cogeneration Company |                           
|               | Other                                      |                           
|               |                                            |                           
|Total expenses |                                            |                           
|               |                                            |                           
|Net income     |                                            | $                         
|               |                                            |                           

See
accompanying notes.

241

---

CPC COGENERATION LLC  (A LIMITED LIABILITY COMPANY)        STATEMENTS OF MEMBERS' EQUITY

|                             |               | Camino
Energy
Company |       | Products
Cogeneration
Company |   | Carson
Cogeneration
Company |      | Total |      
|---------------------------- | ------------- | --------------------- | ----- | ----------------------------- | - | --------------------------- | ---- | ----- | -----
|
|Balance December 31, 1999    |               | $                     |      |                               | $ |                            |      | $     |     
|                             | Distributions |                       |       | (8,330                        | ) |                             | (340 | )     |      
|                             | Net income    |                       |       | 11,306                        |   |                             | 462  |       |      
|                             |               |                       |       |                               |   |                             |      |       |      
|Balance at December 31, 2000 |               |                       | 2,976 |                               |   | 122                         |      |       | 2,976
|                             | Distributions |                       |       | (14,700                       | ) |                             | (600 | )     |      
|                             | Net income    |                       |       | 14,173                        |   |                             | 580  |       |      
|                             |               |                       |       |                               |   |                             |      |       |      
|Balance at December 31, 2001 |               |                       | 2,449 |                               |   | 102                         |      |       | 2,449
|                             | Distributions |                       |       | (11,095                       | ) |                             | (454 | )     |      
|                             | Net income    |                       |       | 10,021                        |   |                             | 409  |       |      
|                             |               |                       |       |                               |   |                             |      |       |      
|Balance at December 31, 2002 |               | $                     | 1,375 |                               | $ | 57                          |      | $     | 1,375
|                             |               |                       |       |                               |   |                             |      |       |      

See
accompanying notes.

242

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CPC COGENERATION LLC  (A LIMITED LIABILITY COMPANY)        STATEMENTS OF CASH FLOWS

|                                                     |                                                           | December 31 |        
|---------------------------------------------------- | --------------------------------------------------------- | ----------- | -------
|
|
|Operating activities                                 |                                                           |             |        
|Net income                                           |                                                           | $           | 20,451 
|Changes in operating assets and liabilities:         |                                                           |             |        
|                                                     | Net change in receivable from BP West Coast Products LLC. |             |        
|                                                     | Net change in payable to Watson Cogeneration Company      |             |        
|                                                     |                                                           |             |        
|Net cash provided by operating activities            |                                                           |             | 20,560 
|Financing activities                                 |                                                           |             |        
|Distributions to partners                            |                                                           |             | (22,644
|                                                     |                                                           |             |        
|Net cash used in financing activities                |                                                           |             | (22,644
|                                                     |                                                           |             |        
|Net (decrease) increase in cash and cash equivalents |                                                           |             | (2,084 
|Cash and cash equivalents at beginning of year       |                                                           |             | 3,059  
|                                                     |                                                           |             |        
|Cash and cash equivalents at end of year             |                                                           | $           | 975    
|                                                     |                                                           |             |        

See
accompanying notes.

243

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CPC COGENERATION LLC  (A LIMITED LIABILITY COMPANY)        NOTES TO FINANCIAL STATEMENTS        DECEMBER 31, 2002

1.    General

CPC Cogeneration LLC (CPC), a limited liability company, was formed December 23, 1999, by Products Cogeneration Company (PCC), a wholly owned
subsidiary of Atlantic Richfield Company, a wholly owned subsidiary of BP America Inc. (BP); Carson Cogeneration Company (CCC), a wholly owned subsidiary of CH-Twenty, Inc.,
a majority-owned subsidiary of Atlantic Richfield Company, and Camino Energy Company (CEC), a wholly owned subsidiary of Edison Mission Energy, a wholly owned subsidiary of Mission Energy Holding
Company, a wholly owned subsidiary of The Mission Group, a wholly owned non-utility subsidiary of Edison International, the parent holding company of Southern California Edison Company.
PCC, CCC and CEC own 2%, 49% and 49% of CPC and Watson Cogeneration Company (WCC), respectively.

WCC
is a California general partnership that operates a cogeneration facility (Facility), which became fully operational in 1988. Upon the creation of CPC, WCC executed an Assignment
Agreement, which effectively assigned the Power Purchase and Sale Agreement with BP West Coast Products LLC (BPWCP), as successor to Atlantic Richfield Company, from WCC to CPC. Under the terms
of that assignment, CPC assumed WCC's obligations to sell power to BPWCP's Carson Refinery. In addition, WCC and CPC entered into an Energy Sales Agreement (ESA) under which WCC sells power to CPC on
negotiated terms, and also entered into a Services Agreement, under which WCC provides, for compensation, various services to CPC.

CPC
was terminated effective at the close of business December 31, 2002. Effective upon the termination of CPC the Assignment Agreement was terminated thereby restoring the Power
Purchase and Sale Agreement as a contract between WCC and BPWCP. At the same time, the Energy Sales Agreement between WCC and CPC was terminated, as well as the Services Agreement between WCC and CPC.
CPC's receivables and payables as of December 31, 2002 will be collected and paid, respectively, and the remaining cash and cash equivalents will be distributed to its members in 2003.

The
results of CPC's operations and financial position may be significantly different without its relationship with WCC and its members.

2.    Summary of Significant Accounting Policies

Cash and Cash Equivalents

Cash and cash equivalents include highly liquid investments with original maturities of less than 90 days.

Revenue Recognition

CPC recognizes revenue upon providing power.

Estimates

The preparation of financial statements in conformity with accounting principles generally accepted in the United States requires management to make estimates and
assumptions that affect the reported amounts of assets and liabilities and disclosures of contingent assets and liabilities at the date of the

244

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financial statements and the reported amounts of revenues and expenses during the reporting period. Actual results could differ from those estimates.

3.    Income Taxes

Income taxes are not recorded by the CPC, since the net income or loss is allocated to the members and included in their respective income tax returns.

245

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REPORT OF INDEPENDENT ACCOUNTANTS

To
the Stockholders of
Four Star Oil & Gas Company

In
our opinion, the accompanying consolidated balance sheets and the related consolidated statements of income, stockholders' equity and cash flows present fairly, in all material
respects, the financial position of Four Star Oil & Gas Company (the Company) and its subsidiary at December 31, 2002 and 2001 and the results of their operations and their cash flows
for the years then ended, in conformity with accounting principles generally accepted in the United States of America. These financial statements are the responsibility of the Company's management;
our responsibility is to express an opinion on these financial statements based on our audits. We conducted our audits of these statements in accordance with auditing standards generally accepted in
the United States of America, which 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, assessing the accounting principles used and significant estimates made by management
and evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion. The financial statements of the Company as of December 31,
2000 and for the year then ended were audited by other independent accountants who have ceased operations. Those independent accountants expressed an unqualified opinion on those statements in their
report dated March 2, 2001.

As
described in Note 3 to the financial statements, the Company has significant transactions with affiliated companies. Because of these relationships, it is possible that the
terms of these transactions are not the same as those that would result from transactions among wholly-unrelated parties.

/S/
PRICEWATERHOUSECOOPERS LLP

Houston,
Texas
March 7, 2003

246

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FOUR STAR OIL & GAS COMPANY        CONSOLIDATED BALANCE SHEETS        DECEMBER 31, 2002 AND 2001

|                                                            |                                                                                                                                                                                                                                                                                                                        | 2002                           |                                     | 2001 |    
|----------------------------------------------------------- | ---------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------- | ------------------------------ | ----------------------------------- | ---- | ---
|
|Assets                                                      |                                                                                                                                                                                                                                                                                                                        |                                |                                     |      |    
|Current assets:                                             |                                                                                                                                                                                                                                                                                                                        |                                |                                     |      |    
|                                                            | Cash and cash equivalents                                                                                                                                                                                                                                                                                              |                                | $                                   | 21   |    
|                                                            | Accounts receivable:                                                                                                                                                                                                                                                                                                   |                                |                                     |      |    
|                                                            |                                                                                                                                                                                                                                                                                                                        | Trade                          |                                     |      | 3  
|                                                            |                                                                                                                                                                                                                                                                                                                        | Related parties and affiliates |                                     |      | 46 
|                                                            | Other receivables                                                                                                                                                                                                                                                                                                      |                                |                                     | 7    |    
|                                                            | Other current assets                                                                                                                                                                                                                                                                                                   |                                |                                     | 4    |    
|                                                            |                                                                                                                                                                                                                                                                                                                        |                                |                                     |      |    
|                                                            |                                                                                                                                                                                                                                                                                                                        |                                | Total current assets                |      |    
|                                                            |                                                                                                                                                                                                                                                                                                                        |                                |                                     |      |    
|Properties, plant and equipment (successful-efforts method) |                                                                                                                                                                                                                                                                                                                        |                                | 955                                 |      |    
|Lessaccumulated depreciation, depletion and amortization   |                                                                                                                                                                                                                                                                                                                        |                                | (673                                | )    |    
|                                                            |                                                                                                                                                                                                                                                                                                                        |                                |                                     |      |    
|                                                            |                                                                                                                                                                                                                                                                                                                        |                                | Net properties, plant and equipment |      |    
|                                                            |                                                                                                                                                                                                                                                                                                                        |                                |                                     |      |    
|Deferred charges and other assets                           |                                                                                                                                                                                                                                                                                                                        |                                | 1                                   |      |    
|                                                            |                                                                                                                                                                                                                                                                                                                        |                                |                                     |      |    
|                                                            |                                                                                                                                                                                                                                                                                                                        |                                | Total                               |      | $  
|                                                            |                                                                                                                                                                                                                                                                                                                        |                                |                                     |      |    
|Liabilities and Stockholders' Equity                        |                                                                                                                                                                                                                                                                                                                        |                                |                                     |      |    
|Current liabilities:                                        |                                                                                                                                                                                                                                                                                                                        |                                |                                     |      |    
|                                                            | Accounts payable and accrued liabilities                                                                                                                                                                                                                                                                               |                                | $                                   | 7    |    
|                                                            | Related party and affiliate payables                                                                                                                                                                                                                                                                                   |                                |                                     | 54   |    
|                                                            | Taxes payable                                                                                                                                                                                                                                                                                                          |                                |                                     | 10   |    
|                                                            |                                                                                                                                                                                                                                                                                                                        |                                |                                     |      |    
|                                                            |                                                                                                                                                                                                                                                                                                                        |                                | Total current liabilities           |      |    
|                                                            |                                                                                                                                                                                                                                                                                                                        |                                |                                     |      |    
|Note payable to affiliate                                   |                                                                                                                                                                                                                                                                                                                        |                                | 169                                 |      |    
|                                                            |                                                                                                                                                                                                                                                                                                                        |                                |                                     |      |    
|Deferred income taxes                                       |                                                                                                                                                                                                                                                                                                                        |                                | 54                                  |      |    
|                                                            |                                                                                                                                                                                                                                                                                                                        |                                |                                     |      |    
|Commitments and contingencies (Note 10)                     |                                                                                                                                                                                                                                                                                                                        |                                |                                     |      |    
|Stockholders' equity:                                       |                                                                                                                                                                                                                                                                                                                        |                                |                                     |      |    
|                                                            | Preferred stock, $1.00 par value. 400 Class A shares authorized, 96 shares and 230 shares issued and outstanding at December 31, 2002 and 2001, respectively; 400 Class B authorized, 300 shares issued and outstanding at
December 31, 2002 and 2001                                                                  |                                |                                     |     |    
|                                                            | Common stock, $1.00 par value, 1,000 Class A shares authorized, issued and outstanding; 2,000 Class B shares authorized, 373 shares and 239 shares issued and outstanding at December 31, 2002 and 2001, respectively; 1,000
Class C shares authorized, 25 shares issued and outstanding at December 31, 2002 and 2001 |                                |                                     |     |    
|                                                            | Additional paid-in capital                                                                                                                                                                                                                                                                                             |                                |                                     | 29   |    
|                                                            | Retained earnings                                                                                                                                                                                                                                                                                                      |                                |                                     | 41   |    
|                                                            |                                                                                                                                                                                                                                                                                                                        |                                |                                     |      |    
|                                                            |                                                                                                                                                                                                                                                                                                                        | Total stockholders' equity     |                                     |      | 70 
|                                                            |                                                                                                                                                                                                                                                                                                                        |                                |                                     |      |    
|                                                            |                                                                                                                                                                                                                                                                                                                        | Total                          |                                     | $    | 364
|                                                            |                                                                                                                                                                                                                                                                                                                        |                                |                                     |      |    

The accompanying notes are an integral part of these consolidated financial statements.

247

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FOUR STAR OIL & GAS COMPANY
CONSOLIDATED STATEMENTS OF INCOME
YEARS ENDED DECEMBER 31, 2002, 2001 AND 2000

|                                      |                                          | 2002     |     | 2001 |    | 2000 |    
|------------------------------------- | ---------------------------------------- | -------- | --- | ---- | -- | ---- | ---
|
|Revenues:                             |                                          |          |     |      |    |      |    
|                                      | Crude oil                                |          | $   | 45   |    | $    | 46 
|                                      | Natural gas                              |          |     | 139  |    |      | 219
|                                      | Natural gas liquids                      |          |     | 24   |    |      | 38 
|                                      | Other                                    |          |     | 27   |    |      | 14 
|                                      |                                          |          |     |      |    |      |    
|                                      |                                          |          | 235 |      |    | 317  |    
|                                      |                                          |          |     |      |    |      |    
|Costs and expenses:                   |                                          |          |     |      |    |      |    
|                                      | Operating expenses                       |          |     | 47   |    |      | 38 
|                                      | General and administrative expenses      |          |     | 14   |    |      | 13 
|                                      | Depreciation, depletion and amortization |          |     | 44   |    |      | 38 
|                                      | Impairment of oil and gas properties     |          |     | 7    |    |      | 7  
|                                      | Taxes other than income taxes            |          |     | 19   |    |      | 25 
|                                      |                                          |          |     |      |    |      |    
|                                      |                                          |          | 131 |      |    | 121  |    
|                                      |                                          |          |     |      |    |      |    
|Operating income                      |                                          |          | 104 |      |    | 196  |    
|Other income (expense):               |                                          |          |     |      |    |      |    
|                                      | Interest expense                         |          |     | (7   | )  |      | (13
|                                      | Interest income and other                |          |     | 6    |    |      | 1  
|                                      |                                          |          |     |      |    |      |    
|Income before income taxes            |                                          |          | 103 |      |    | 184  |    
|                                      |                                          |          |     |      |    |      |    
|Provision (benefit) for income taxes: |                                          |          |     |      |    |      |    
|                                      | Federal:                                 |          |     |      |    |      |    
|                                      |                                          | Current  |     |      | 36 |      |    
|                                      |                                          | Deferred |     |      | (4 | )    |    
|                                      | State and local:                         |          |     |      |    |      |    
|                                      |                                          | Current  |     |      | (1 | )    |    
|                                      |                                          |          |     |      |    |      |    
|                                      |                                          |          | 31  |      |    | 54   |    
|                                      |                                          |          |     |      |    |      |    
|Net income                            |                                          | $        | 72  |      | $  | 130  |    
|                                      |                                          |          |     |      |    |      |    

The
accompanying notes are an integral part of these consolidated financial statements.

248

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FOUR STAR OIL & GAS COMPANY
CONSOLIDATED STATEMENTS OF STOCKHOLDERS' EQUITY
YEARS ENDED DECEMBER 31, 2002, 2001 AND 2000

|                           |  | Common shares |  | Preferred shares |  |    |  |      |   |     |  |   |   |  |  
|-------------------------- |  | ------------- |  | ---------------- |  | -- |  | ---- | - | --- |  | - | - |  | -
|
|
|Balance, December 31, 1999 |  | 1,000         |  | 159              |  | 25 |  | 310  |   | 300 |  | $ |  |  | $
|Dividends paid             |  |              |  |                 |  |   |  |     |   |    |  |   |  |  |  
|Stock conversion           |  |              |  | 80               |  |   |  | (80  | ) |    |  |   |  |  |  
|Net income                 |  |              |  |                 |  |   |  |     |   |    |  |   |  |  |  
|                           |  |               |  |                  |  |    |  |      |   |     |  |   |   |  |  
|Balance, December 31, 2000 |  | 1,000         |  | 239              |  | 25 |  | 230  |   | 300 |  |   |  |  |  
|Dividends paid             |  |              |  |                 |  |   |  |     |   |    |  |   |  |  |  
|Stock conversion           |  |              |  | 134              |  |   |  | (134 | ) |    |  |   |  |  |  
|Net income                 |  |              |  |                 |  |   |  |     |   |    |  |   |  |  |  
|                           |  |               |  |                  |  |    |  |      |   |     |  |   |   |  |  
|Balance, December 31, 2001 |  | 1,000         |  | 373              |  | 25 |  | 96   |   | 300 |  |   |  |  |  
|Dividends paid             |  |              |  |                 |  |   |  |     |   |    |  |   |  |  |  
|Net income                 |  |              |  |                 |  |   |  |     |   |    |  |   |  |  |  
|                           |  |               |  |                  |  |    |  |      |   |     |  |   |   |  |  
|Balance, December 31, 2002 |  | 1,000         |  | 373              |  | 25 |  | 96   |   | 300 |  | $ |  |  | $
|                           |  |               |  |                  |  |    |  |      |   |     |  |   |   |  |  

The accompanying notes are an integral part of these consolidated financial statements.

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FOUR STAR OIL & GAS COMPANY
CONSOLIDATED STATEMENTS OF CASH FLOWS
YEARS ENDED DECEMBER 31, 2002, 2001 AND 2000

|                                                  |                                                                            | 2002                                                                      |                                                    | 2001                                      |     | 2000 |     
|------------------------------------------------- | -------------------------------------------------------------------------- | ------------------------------------------------------------------------- | -------------------------------------------------- | ----------------------------------------- | --- | ---- | ----
|
|Cash flows from operating activities:             |                                                                            |                                                                           |                                                    |                                           |     |      |     
|                                                  | Net income                                                                 |                                                                           | $                                                  | 72                                        |     | $    | 130 
|                                                  | Reconciliation of net income to net cash provided by operating activities: |                                                                           |                                                    |                                           |     |      |     
|                                                  |                                                                            | Reversal of provision for plug and abandonment                            |                                                    |                                           |    |      |     
|                                                  |                                                                            | Depreciation, depletion and amortization                                  |                                                    |                                           | 44  |      |     
|                                                  |                                                                            | Impairment of oil and gas properties                                      |                                                    |                                           | 7   |      |     
|                                                  |                                                                            | Deferred income taxes and other                                           |                                                    |                                           | (3  | )    |     
|                                                  |                                                                            | Changes in assets and liabilities:                                        |                                                    |                                           |     |      |     
|                                                  |                                                                            |                                                                           | Accounts receivabletrade, net                     |                                           |     | 3    |     
|                                                  |                                                                            |                                                                           | Accounts receivablerelated parties and affiliates |                                           |     | (11  | )   
|                                                  |                                                                            |                                                                           | Other receivables                                  |                                           |     | 15   |     
|                                                  |                                                                            |                                                                           | Other current assets                               |                                           |     | (2   | )   
|                                                  |                                                                            |                                                                           | Deferred charges and other assets                  |                                           |     | 3    |     
|                                                  |                                                                            |                                                                           | Accounts payable and accrued liabilities           |                                           |     | 2    |     
|                                                  |                                                                            |                                                                           | Related party and affiliate payables               |                                           |     | 23   |     
|                                                  |                                                                            |                                                                           | Taxes payable                                      |                                           |     | 2    |     
|                                                  |                                                                            |                                                                           |                                                    |                                           |     |      |     
|                                                  |                                                                            |                                                                           |                                                    | Net cash provided by operating activities |     |      | 155 
|                                                  |                                                                            |                                                                           |                                                    |                                           |     |      |     
|Cash flows from investing activities:             |                                                                            |                                                                           |                                                    |                                           |     |      |     
|                                                  |                                                                            | Capital expenditures                                                      |                                                    |                                           | (28 | )    |     
|                                                  |                                                                            | Proceeds from property sales                                              |                                                    |                                           |    |      |     
|                                                  |                                                                            |                                                                           |                                                    |                                           |     |      |     
|                                                  |                                                                            |                                                                           |                                                    | Net cash used in investing activities     |     |      | (28 
|                                                  |                                                                            |                                                                           |                                                    |                                           |     |      |     
|Cash flows from financing activities:             |                                                                            |                                                                           |                                                    |                                           |     |      |     
|                                                  |                                                                            | Dividends paid                                                            |                                                    |                                           | (59 | )    |     
|                                                  |                                                                            | Loan principal repayment to affiliate                                     |                                                    |                                           | (70 | )    |     
|                                                  |                                                                            |                                                                           |                                                    |                                           |     |      |     
|                                                  |                                                                            |                                                                           |                                                    | Net cash used in financing activities     |     |      | (129
|                                                  |                                                                            |                                                                           |                                                    |                                           |     |      |     
|Increase (decrease) in cash and cash equivalents  |                                                                            |                                                                           | (2                                                 | )                                         |     | 5    |     
|Cash and cash equivalents, beginning of year      |                                                                            |                                                                           | 23                                                 |                                           |     | 18   |     
|                                                  |                                                                            |                                                                           |                                                    |                                           |     |      |     
|Cash and cash equivalents, end of year            |                                                                            | $                                                                         | 21                                                 |                                           | $   | 23   |     
|                                                  |                                                                            |                                                                           |                                                    |                                           |     |      |     
|Supplemental disclosure of cash flow information: |                                                                            |                                                                           |                                                    |                                           |     |      |     
|                                                  |                                                                            | Cash flows from operating activities include the following cash payments: |                                                    |                                           |     |      |     
|                                                  |                                                                            |                                                                           | Income taxes                                       |                                           | $   | 15   |     
|                                                  |                                                                            |                                                                           | Interest                                           |                                           |     | 7    |     

The
accompanying notes are an integral part of these consolidated financial statements.

250

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FOUR STAR OIL & GAS COMPANY        NOTES TO CONSOLIDATED FINANCIAL STATEMENTS        DECEMBER 31, 2002 AND 2001

1.    Basis of Presentation and Description of the Company

Four Star Oil and Gas Company is a subsidiary of ChevronTexaco that explores for and produces crude oil, natural gas and natural gas liquids. The use in this
report of the term "Texaco" refers solely to Texaco Inc., a Delaware corporation, and its consolidated subsidiaries or to subsidiaries and affiliates either individually or collectively.

In
1984, Texaco acquired all of the outstanding common stock of Four Star Oil & Gas Company (Four Star or the Company) for $10.2 billion. At the time of acquisition, Four
Star was an integrated petroleum and natural gas company involved in the exploration for and production, transportation, refining and marketing of crude oil and petroleum products. The acquisition was
accounted for as a purchase, and the Four Star assets and liabilities were recorded at fair market value. In 1989, Texaco sold 20 percent of its interest in Four Star to Edison Mission Energy
(Mission Energy). Four Star was an 80 percent owned subsidiary of Texaco from December 31, 1989 through December 31, 1991. As a result of a series of stock transactions occurring
between January 1, 1992 and December 31, 2002, Texaco's ownership interest in Four Star was reduced to 71%.

In
October 2001, the merger between Texaco and Chevron Corporation was approved and ChevronTexaco Corporation (ChevronTexaco) became the ultimate parent of Texaco Inc.
Texaco Inc.'s investment in Four Star was transferred to ChevronTexaco Global Energy Inc. as part of a restructuring agreement dated November 1, 2001. Texaco Exploration and
Production Inc. (TEPI), a wholly-owned subsidiary of Texaco Inc., was absorbed into Chevron U.S.A. (CUSA), a wholly-owned subsidiary of ChevronTexaco, as part of a legal restructuring in
May 2002. CUSA operates and manages the majority of Four Star's operations under the terms of a service agreement.

As
of December 31, 2002 and 2001, the ownership interests in Four Star were as follows:

|                                                                                 |  | 2002  |   | 2001  |  
|-------------------------------------------------------------------------------- |  | ----- | - | ----- | -
|Chevron U.S.A. (CUSA)                                                            |  | 36.6  | % | 36.6  | %
|ChevronTexaco Global Energy Inc. (CTGEI)                                         |  | 24.3  | % | 24.3  | %
|Edison Mission Energy (Mission Energy)                                           |  | 19.0  | % | 19.0  | %
|Four Star Oil & Gas Holdings Company
(owned jointly by CTGEI and Mission Energy) |  | 20.1  | % | 20.1  | %
|                                                                                 |  |       |   |       |  
|                                                                                 |  | 100.0 | % | 100.0 | %
|                                                                                 |  |       |   |       |  

2.    Significant Accounting Policies

Principles of Consolidation

The consolidated financial statements include the accounts of Four Star Oil & Gas Company (Four Star or the Company) and Mission Energy Methane, a
wholly-owned subsidiary of Four Star. All significant intercompany accounts and transactions have been eliminated in consolidation.

Revenue Recognition

Revenues associated with sales of crude oil, natural gas and other sources are recorded when title passes to the customer, net of royalties, discounts and
allowances, as applicable. Revenues from natural

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gas production from properties in which ChevronTexaco has an interest with other producers are generally recognized on the basis of delivery (sales method).

Cash and Cash Equivalents

Highly liquid investments with a maturity of three months or less when purchased are generally considered to be cash equivalents.

Properties, Plant and Equipment and Depreciation, Depletion and Amortization

The Company follows the successful efforts method of accounting for its oil and gas exploration and production operations.

Lease
acquisition costs related to properties held for oil and gas production are capitalized when incurred. Unproved properties with acquisition costs which are individually significant
are assessed on a property-by-property basis, and a loss is recognized, by provision of a valuation allowance, when the assessment indicates an impairment in value. Unproved
properties with acquisition costs which are not individually significant are generally aggregated, and the portion of such costs estimated to be nonproductive, based on historical experience, is
amortized on an average holding period basis.

Exploratory
costs, excluding the costs of exploratory wells, are charged to expense as incurred. Costs of drilling exploratory wells, including stratigraphic test wells, are capitalized
pending determination of whether the wells have found proved reserves which justify commercial development. If such reserves are not found, the drilling costs are charged to exploratory expenses.
Intangible drilling costs applicable to productive wells and to development dry holes, as well as tangible equipment costs related to the development of oil and gas reserves, are capitalized.

The
costs of productive leaseholds and other capitalized costs related to production activities, including tangible and intangible costs, are amortized principally by field on the
unit-of-production basis by applying the ratio of produced oil and gas to estimated recoverable total proved oil and gas reserves.
Estimated future restoration and abandonment costs are taken into account in determining amortization and depreciation rates.

Depreciation
of properties, plant and equipment related to operations other than production is provided using the straight-line method, with depreciation rates based upon
estimated useful lives applied to the cost of each class of property. The useful lives of such assets range from 3 to 20 years.

Normal
maintenance and repairs of properties, plant and equipment are charged to expense as incurred. Renewals, betterments and major repairs that materially extend the life of
properties are capitalized, and the assets replaced, if any, are retired.

When
fixed capital assets representing complete units of property are disposed of, any profit or loss after accumulated depreciation and amortization is credited or charged to income.

Long-lived
assets, including proved oil and gas properties, are assessed for possible impairment by comparing their carrying values with the undiscounted future net
before-tax cash flows. Events which can trigger assessments for possible impairments include write-downs of proved reserves based on field performance, significant decreases in the market
value of an asset, and significant change in an asset.

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Impaired assets are written down to their estimated fair values, generally their discounted future net before-tax cash flows. As a result, the Company recorded impairment charges of
$7 million, $7 million and $25 million in 2002, 2001 and 2000, respectively, due to downward reserve revisions.

Use of Estimates

The preparation of financial statements in conformity with accounting principles generally accepted in the United States of America requires management to make
estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements and the reported
amounts of revenues and expenses during the reporting period. The most significant estimates pertain to proved oil, NGL and gas reserve volumes and plug and abandonment costs as well as estimates
relating to the calculation of impairments under SFAS No. 144. Actual results could differ from those estimates.

Reclassifications

Certain previously reported amounts have been reclassified to conform to current-year presentation. Such reclassification had no effect on reported
net income or shareholders' equity.

Income Taxes

Deferred taxes result from temporary differences in the recognition of revenues and expenses for tax and financial reporting purposes and are calculated based
upon cumulative book and tax differences in the balance sheet.

Derivatives

The adoption of SFAS No. 133, "Accounting for Derivative Instruments and Hedging Activities," did not have a material effect on the Company's financial
position as the Company has no derivatives as of December 31, 2002 and 2001, except for its physical sale contracts, which qualify as normal sales. The Company adopted SFAS 133 as of
January 1, 2001.

New Accounting Pronouncements

In June 2001, the FASB issued Statement No. 143, "Accounting for Asset Retirement obligations" (SFAS 143). This new standard was adopted
effective January 1, 2003, and applies to legal obligations associated with the retirement of tangible long-lived assets. Adoption of SFAS 143 primarily affects the Company's
accounting for oil and gas producing assets. SFAS 143 differs in several significant respects from current accounting under SFAS 19, "Financial Accounting and Reporting by Oil and Gas
Producing Companies." Adoption of SFAS 143 affects future accounting and reporting of the assets, liabilities and expenses related to these obligations. In the first quarter 2003, the Company
will report an after-tax loss of approximately $9.2 million for the cumulative effect of this change in accounting principle. The effect of adoption will also include an increase of
total assets and total liabilities of $16.8 million and $26 million, respectively. Besides the cumulative-effect adjustment, the effect of the new accounting standard on net income in
2003 is not expected to be materially different from what the result would have been under SFAS 19 accounting.

253

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In
April 2002, the FASB issued SFAS No. 145,Recession of FASB Statement No. 4, 44 and 64, Amendment of FASB Statement No. 13, and
Technical Corrections. Application of the statement will be required in 2003. The Company does not expect adoption of SFAS No. 145 to have a significant impact on its
financial statements.

In
July 2002, the FASB issued SFAS No. 146,Accounting for Exit or Disposal Activities. SFAS No. 146 address the
recognition, measurement and reporting costs associated with exit and disposal activities when they are incurred rather than at the date of a commitment to an exit or disposal plan. SFAS
No. 146 is to be applied prospectively to exit or disposal activities initiated after December 31, 2002.

In
December 2002, the FASB issued Interpretation No. 45 (FIN No. 45),Guarantor's Accounting and Disclosure
Requirements. FIN No. 45 expands required disclosures for certain types of guarantees and recognition of a liability at fair value of such guarantees at the time of
issuance. The disclosure requirements are effective for the Company's December 31, 2002 financial statements, while the fair value accounting requirements apply prospectively to guarantees
issued or modified after December 31, 2002. The Company does not expect FIN No. 45 to have a significant effect on its financial statements.

In
January 2003, the FASB issued Interpretation No. 46, "Consolidation of Variable Interest Entities" (FIN No. 46). FIN No. 46 amended ARB 51, "Consolidated
Financial Statements," and established standards for determining under what circumstances a variable interest entity (VIE) should be consolidated with its primary beneficiary. FIN No. 46 also
requires disclosures about VIEs that the Company is not required to consolidate but in which it has a significant variable interest. The Company does not expect that adoption of FIN No. 46 will
have a significant impact on the results of operations, financial position or liquidity.

Reclassifications

Certain prior year amounts have been reclassified to conform with current year presentation.

3.    Related Party Transactions

Four Star has various business transactions with ChevronTexaco and other ChevronTexaco subsidiaries and affiliates. These transactions principally involve sales
by Four Star of crude oil, natural gas and natural gas liquids. In addition, ChevronTexaco charges Four Star for management, professional, technical and administrative services, as well as direct
charges for exploration and production-related activities.

Effective
December 1, 1999, Four Star entered into a service agreement with TEPI for management, administrative, professional and technical services through November 1,
2004. During 2001, Four Star paid TEPI a monthly fixed fee of $579,785 through November 30, 2001. Four Star paid TEPI a monthly fixed fee of $597,634 from December 1, 2001 through
April 30, 2002, and CUSA a monthly fixed fee of $597,634 from May 1, 2002 through November 30, 2002. Beginning December 1, 2002, the rate was adjusted to $603,034 and this
rate will remain in effect until November 30, 2003. An aggregate amount of $7.2 million, $7.0 million and $6.8 million in service fees was included as a component of
general and administrative and other operating expenses in the accompanying consolidated statement of income for the years ended December 31, 2002, 2001 and 2000, respectively.

254

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In
addition, Four Star paid TEPI a monthly unit fee of $645,015 during the period from December 1, 2000 to November 30, 2001. On December 1, 2001, Four Star
commenced payment of a monthly unit fee of $607,041. On May 1, 2002, TEPI was absorbed into CUSA as part of a legal restructuring agreement dated May 1, 2002. Total unit fees of
$6.8 million, $7.7 million and $7.3 million are included as a component of general and administrative and other operating expenses in the accompanying consolidated statements of
income for the years ended December 31, 2002, 2001 and 2000, respectively. The unit fee is adjusted to actual production within 90 days after contract period ending November 30,
2002.

Pursuant
to the contractual agreement described in Note 10, certain tax benefits and liabilities are assumed by ChevronTexaco.

The
following table summarizes sales to affiliates during 2002, 2001 and 2000. The Company makes no purchases from its affiliates.

|                               |  | 2002 |       | 2001 |   | 2000 
|------------------------------ |  | ---- | ----- | ---- | - | -----
|
|Dynegy                         |  | $    | 87.6  |      | $ |     
|Texaco Natural Gas Inc.        |  |      | 70.6  |      |   | 252.2
|CUSA                           |  |      | 39.6  |      |   |     
|Bridgeline LLCTexaco Pipeline |  |      |      |      |   |     
|Equilon Enterprises LLC(1)     |  |      |      |      |   | 46.3 
|                               |  |      |       |      |   |      
|Total                          |  | $    | 197.8 |      | $ | 298.5
|                               |  |      |       |      |   |      

---

4.    Properties, Plant and Equipment

In 2000, Four Star sold $5.9 million of its properties for $6.3 million, resulting in an approximate $400,000 pretax gain on the sale. In 2002, Four
Star purchased the San Juan LLC 1999 property for $11.6 million.

5.    Note Payable to Affiliate

In September 1999, Four Star retired its loan facility with Chase Bank of Texas, N.A. and entered into a loan agreement with Texaco Inc. The
outstanding balance on the loan agreement was $169 million and $239 million at December 31, 2002 and 2001. The loan bears interest at LIBOR plus one percent and matures on
December 31, 2005. The interest rate was 2.4%, 3.4% and 7.0% at December 31, 2002, 2001 and 2000, respectively. Interest expense during 2002, 2001 and 1999, was $7 million,
$13 million and $18 million, respectively. Four Star pays Texaco Inc. an annual facility fee and administrative fee of $50,000.

The
Company's borrowing base is redetermined annually each September 30 as set forth in the Four Star Oil & Gas Credit Agreement dated September 30, 1999. If the
outstanding aggregate principal amount of the loan, excluding the amount of any debt permitted by the loan agreement,

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exceeds the amount of the revised borrowing base, Four Star must repay such excess to Texaco Inc. in four equal quarterly installments. Throughout 2002 and 2001, Four Star's borrowing base
exceeded the outstanding loan balance, thus no principal payments were due. As of December 31, 2002, the Company's borrowing base under the agreement was $268 million.

Four
Star elected to pre-pay $70 million of the note on December 31, 2002. Four Star has the right, subject to certain conditions, to prepay the note in whole
or in part prior to the maturity date.

6.    Concentration of Credit Risk

Substantially all of the Company's accounts receivable at December 31, 2002, result from sales to the Company's three largest customers, all of which are
ChevronTexaco affiliates, as discussed in Note 3. The Company's credit policy and relatively short duration of receivables mitigate the risk of uncollected receivables. During each of the three
years in the period ended December 31, 2002, the Company did not incur any credit losses on receivables.

7.    Income Taxes

The Company accounts for income taxes in accordance with SFAS No. 109, "Accounting for Income Taxes". Under SFAS No. 109, deferred income taxes are
determined utilizing a liability approach. This method gives consideration to the future tax consequences associated with utilization of energy tax credits and differences between financial accounting
and tax bases of assets and liabilities. Such differences relate mainly to depreciable and depletable properties, intangible drilling costs and nonproductive leases.

The
composition of deferred tax assets and liabilities and the related tax effects at December 31, 2002, 2001 and 2000, were as follows (in millions):

|                                                           |  | 2002 |     | 2001 |   | 2000 |  
|---------------------------------------------------------- |  | ---- | --- | ---- | - | ---- | -
|Deferred tax assets related to energy tax credits          |  | $    |    |      | $ |     |  
|Deferred tax liabilities related to oil and gas properties |  |      | (54 | )    |   | (57  | )
|                                                           |  |      |     |      |   |      |  
|Net deferred tax liability                                 |  | $    | (54 | )    | $ | (57  | )
|                                                           |  |      |     |      |   |      |  

There
are differences between income taxes computed using the statutory rate of 35 percent and the Company's effective income tax rates (29 percent in 2002,
29 percent in 2001 and 31 percent in 2000), primarily as a result of certain tax credits available to the Company. Reconciliations of income taxes computed using the statutory rate to
the Company's effective tax rates are as follows (in millions):

|                                            |  | 2002 |    | 2001 |   | 2000 |  
|------------------------------------------- |  | ---- | -- | ---- | - | ---- | -
|Income taxes computed at the statutory rate |  | $    | 36 |      | $ | 64   |  
|Section 29 tax credits                      |  |      | (7 | )    |   | (7   | )
|Other, net                                  |  |      | 2  |      |   | (3   | )
|                                            |  |      |    |      |   |      |  
|Provision for income taxes                  |  | $    | 31 |      | $ | 54   |  
|                                            |  |      |    |      |   |      |  

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8.    Stockholders' Equity

In 1995, Four Star created four additional classes of stock: Class A common (voting), Class B common (voting), Class C common (nonvoting) and
preferred (Class A preferred and Class B preferred).

In
1999, Texaco, TEPI, and Mission Energy entered into an agreement granting Mission Energy the option to purchase shares of Class A common stock or Class B common stock of
Four Star (class determined by ChevronTexaco), provided that ChevronTexaco's aggregate ownership interest in the common stock at time of purchase shall not be reduced to less than 51 percent of
all common stock outstanding at the time of purchase. The option expires on December 23, 2006. In 2001, the agreement was amended to replace Texaco with CTGEI. In 2002, TEPI was replaced by
CUSA as part of a legal restructure agreement. As of December 31, 2002 and 2001, Mission Energy owned 23 percent of all voting common stock outstanding. Four Star Oil and Gas Holdings
Company (owned jointly by CTGEI and Mission Energy) owned 26 percent of all voting common stock in the Company as of December 31, 2002.

Each
share of Class A preferred stock is entitled to receive cumulative cash dividends of $5,112 per share per annum, payable semiannually. Each share of Class B preferred
stock is entitled to receive cumulative cash dividends of $2,250 per annum, payable semiannually.

9.    Fair Value of Financial Instruments

The Company's financial instruments consist of cash and cash equivalents, short-term receivables and payables and long-term debt. The
carrying amounts of such instruments approximate their fair market values due to the highly liquid nature of the short-term instruments and the floating interest rates associated with the
long-term debt, which reflect market rates.

10.    Commitments and Contingencies

ChevronTexaco has assumed any and all liabilities of Four Star incurred or attributable to periods prior to January 1, 1990, for state and federal income,
windfall profit ad valorem or franchise taxes, and legal
proceedings. In addition, ChevronTexaco has assumed certain of the tax liabilities of Four Star arising from January 1, 1990, to March 1, 1990, attributable to Four Star's status as a
member of the Texaco tax consolidated group.

In
the opinion of the Company, while it is impossible to ascertain the ultimate legal and financial liability with respect to the above or other contingent liabilities, including
lawsuits, claims, guarantees, federal taxes and federal regulations, the aggregate amount of any such liability is not anticipated to be material in relation to the financial position, cash flows or
results of operations of the Company.

11.    Supplemental Information on Oil and Gas Producing Activities (Unaudited)

In accordance with Statement of Financial Accounting Standards No. 69, "Disclosures About Oil and Gas Producing Activities" (FAS 69), this section provides
supplemental information on oil and gas exploration and producing activities of the Company in seven separate tables. Tables I through IV provide historical cost information pertaining to costs
incurred in exploration, property acquisitions and development; capitalized costs; and results of operations. Tables V through VII present information on the Company's estimated net proved reserve
quantities, standardized measure of estimated discounted

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future net cash flows related to proved reserves, and changes in estimated discounted future net cash flows.

Table ICosts incurred in exploration, property acquisitions and development(1)

|                      |                      | 2002 |    | 2001
|--------------------- | -------------------- | ---- | -- | ----
|
|Exploration           |                      | $    | 2  |     
|Property acquisitions |                      |      | 12 |     
|Development           |                      |      | 13 |     
|                      |                      |      |    |     
|                      | Total costs incurred |      | $  | 27  
|                      |                      |      |    |     

---

Table IICapitalized costs related to oil and gas producing activities

|                                               |                         | 2002 |     | 2001
|---------------------------------------------- | ----------------------- | ---- | --- | ----
|
|Unproved properties                            |                         | $    | 1   |     
|Proved properties and related producing assets |                         |      | 939 |     
|Other uncompleted projects                     |                         |      | 15  |     
|                                               |                         |      |     |     
|                                               | Gross capitalized costs |      |     | 955 
|                                               |                         |      |     |     
|Unproved properties valuation                  |                         |      |    |     
|Proved producing properties                    |                         |      | 662 |     
|Future abandonment and restoration             |                         |      | 11  |     
|                                               |                         |      |     |     
|Accumulated provisions                         |                         |      | 673 |     
|                                               |                         |      |     |     
|Net capitalized costs                          |                         | $    | 282 |     
|                                               |                         |      |     |     

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Table IIIResults of operations for oil and gas producing activities

The Company's results of operations from oil and gas producing activities for the years 2002 and 2001 are shown in the following table. In accordance with FAS
No. 69, income taxes in Table III are based on statutory tax rates, reflecting allowable deductions and tax credits. Interest income and expense are excluded from the results reported in Table
III.

|                                                                               |                             | 2002  |     | 2001 |    
|------------------------------------------------------------------------------ | --------------------------- | ----- | --- | ---- | ---
|
|Revenues from net production:                                                  |                             |       |     |      |    
|                                                                               | Sales                       |       | $   | 203  |    
|                                                                               |                             |       |     |      |    
|                                                                               |                             | Total |     |      | 203
|                                                                               | Production expenses         |       |     | (75  | )  
|Proved producing properties: depreciation, depletion and abandonment provision |                             |       | (44 | )    |    
|Other income (expense)                                                         |                             |       | 20  |      |    
|                                                                               |                             |       |     |      |    
|                                                                               | Results before income taxes |       |     | 104  |    
|Income tax expense                                                             |                             |       | (31 | )    |    
|                                                                               |                             |       |     |      |    
|Results of producing operations                                                |                             | $     | 73  |      | $  
|                                                                               |                             |       |     |      |    

Table IVResults of operations for oil and gas producing activitiesunit prices and costs

|                                     |                                      | 2002 |      | 2001 
|------------------------------------ | ------------------------------------ | ---- | ---- | -----
|Average sales prices:                |                                      |      |      |      
|                                     | Liquids, per barrel                  |      | $    | 19.72
|                                     | Natural gas, per thousand cubic feet |      |      | 2.43 
|Average production costs, per barrel |                                      |      | 5.93 |      

Table VReserve quantity information

The Company's estimated net proved underground oil and gas reserves and changes thereto for the years 2002 and 2001 are shown in the following table. Proved
reserves are estimated by Company asset teams composed of earth scientists and reservoir engineers. These proved reserve estimates are reviewed annually by the Company's Reserves Advisory Committee to
ensure that rigorous professional standards and the reserves definitions prescribed by the U.S. Securities and Exchange Commission are consistently applied throughout the Company.

Proved
reserves are the estimated quantities that geologic and engineering data demonstrate with reasonable certainty to be recoverable in future years from known reservoirs under
existing economic and operating conditions. Due to the inherent uncertainties and the limited nature of reservoir data, estimates of underground reserves are subject to change as additional
information becomes available.

259

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Proved
reserves do not include additional quantities recoverable beyond the term of the lease or concession agreement or that may result from extensions of currently proved areas or from
applying secondary or tertiary recovery processes not yet tested and determined to be economic.

Proved
developed reserves are the quantities expected to be recovered through existing wells with existing equipment and operating methods.

"Net"
reserves exclude royalties and interests owned by others and reflect contractual arrangements and royalty obligations in effect at the time of the estimate.

|                              |                            | Net proved
reserves of crude
oil condensate
and natural
gas liquids(1) |    | Net proved
reserves of
natural gas(1) |        
|----------------------------- | -------------------------- | ---------------------------------------------------------------------- | -- | ------------------------------------- | -------
|
|Reserves at December 31, 2000 |                            | 28                                                                     |    | 503,855                               |        
|Changes attributable to:      |                            |                                                                        |    |                                       |        
|                              | Revisions                  |                                                                        | (3 | )                                     | 51,827 
|                              | Extensions and discoveries |                                                                        |   |                                       | 17,320 
|                              | Sales                      |                                                                        |   |                                       | (21    
|                              | Production                 |                                                                        | (3 | )                                     | (61,611
|                              |                            |                                                                        |    |                                       |        
|Reserves at December 31, 2001 |                            | 22                                                                     |    | 511,370                               |        
|                              |                            |                                                                        |    |                                       |        
|Changes attributable to:      |                            |                                                                        |    |                                       |        
|                              | Revisions                  |                                                                        | 3  |                                       | 5,772  
|                              | Extensions and discoveries |                                                                        |   |                                       | 2,756  
|                              | Sales                      |                                                                        |   |                                       |       
|                              | Purchases                  |                                                                        |   |                                       | 24,072 
|                              | Production                 |                                                                        | (4 | )                                     | (56,057
|                              |                            |                                                                        |    |                                       |        
|Reserves at December 31, 2002 |                            | 21                                                                     |    | 487,913                               |        
|                              |                            |                                                                        |    |                                       |        

---

Table VIStandardized measure of discounted future net cash flows related to proved oil and gas reserves

The standardized measure of discounted future net cash flows, related to the preceding proved oil and gas reserves, is calculated in accordance with the
requirements of FAS No. 69. Estimated future cash inflows from production are computed by applying year-end prices for oil and gas to year-end quantities of estimated
net proved reserves. Future price changes are limited to those provided by contractual arrangements in existence at the end of each reporting year. Future development and production costs are those
estimated future expenditures necessary to develop and produce year-end estimated proved reserves based on year-end cost indices, assuming continuation of year-end
economic conditions. Estimated future income taxes are calculated by applying appropriate year-end statutory tax

260

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rates. These rates reflect allowable deductions and tax credits and are applied to estimated future pretax net cash flows, less the tax basis of related assets. Discounted future net cash flows are
calculated using ten percent midperiod discount factors. Discounting requires a year-by-year estimate of when future expenditures will be incurred and when reserves will be
produced.

The
information provided does not represent management's estimate of the Company's expected future cash flows or value of proved oil and gas reserves. Estimates of proved reserve
quantities are imprecise and change over time as new information becomes available. Moreover, probable and possible reserves, which may become proved in the future, are excluded from the calculations.
The arbitrary valuation prescribed under FAS No. 69 requires assumptions as to the timing and amount of future development and production costs. The calculations are made as of
December 31 each year and should not be relied upon as an indication of the Company's future cash flows or value of its oil and gas reserves.

|                                                         |  | 2002 |       | 2001 |  
|-------------------------------------------------------- |  | ---- | ----- | ---- | -
|
|Future cash inflows from production                      |  | $    | 2,088 |      | $
|Future production and development costs                  |  |      | (97   | )    |  
|Future income taxes                                      |  |      | (709  | )    |  
|                                                         |  |      |       |      |  
|Undiscounted future net cash flows                       |  |      | 1,282 |      |  
|Ten percent midyear annual discount for timing of        |  |      |       |      |  
|estimated cash flows                                     |  |      | (486  | )    |  
|                                                         |  |      |       |      |  
|Standardized measure of discounted future net cash flows |  | $    | 796   |      | $
|                                                         |  |      |       |      |  

Table VIIChanges in the standardized measure of discounted future net cash flows from proved reserves

|                                                                     |                              | 2002 |      | 2001 |  
|-------------------------------------------------------------------- | ---------------------------- | ---- | ---- | ---- | -
|
|Present value at January 1                                           |                              | $    | 336  |      | $
|                                                                     |                              |      |      |      |  
|Sales and transfers of oil and gas produced, net of production costs |                              |      | (130 | )    |  
|Development costs incurred                                           |                              |      | 13   |      |  
|Purchases of reserves                                                |                              |      | 33   |      |  
|Extensions, discoveries and improved recovery, less related costs    |                              |      | 5    |      |  
|Revisions of previous quantity estimates                             |                              |      | (14  | )    |  
|Net changes in prices, development and production costs              |                              |      | 786  |      |  
|Accretion of discount                                                |                              |      | 45   |      |  
|Net change in income tax                                             |                              |      | (278 | )    |  
|                                                                     |                              |      |      |      |  
|                                                                     | Net change for the year      |      |      | 460  |  
|                                                                     |                              |      |      |      |  
|                                                                     | Present value at December 31 |      | $    | 796  |  
|                                                                     |                              |      |      |      |  

The
changes in present values between years, which can be significant, reflect changes in estimated proved reserve quantities and prices and assumptions used in forecasting production
volumes and costs. Changes in the timing of production are included with "Revisions of previous quantity estimates."

261

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REPORT OF INDEPENDENT ACCOUNTANTS

To
the Management Committee of
Midway-Sunset Cogeneration Company:

In
our opinion, the accompanying balance sheet as of December 31, 2002 and the related statements of income, partners' equity, and cash flows present fairly, in all material
respects, the financial position of Midway-Sunset Cogeneration Company (a California general partnership) at December 31, 2002, and the results of its operations and its cash flows for the year
then ended in conformity with accounting principles generally accepted in the United States of America. These financial statements are the responsibility of the Partnership's management; our
responsibility is to express an opinion on these financial statements based on our audit. We conducted our audit of these statements in accordance with auditing standards generally accepted in the
United States of America, which 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, assessing the accounting principles used and significant estimates made by management, and
evaluating the overall financial statement presentation. We believe that our audit provides a reasonable basis for our opinion.

PricewaterhouseCoopers
LLP

Los
Angeles, California
March 14, 2003

262

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MIDWAY-SUNSET COGENERATION COMPANY        BALANCE SHEETS        DECEMBER 31, 2002 AND 2001 (UNAUDITED)

|                                        |                                           | 2002                                   |            | 2001      
|--------------------------------------- | ----------------------------------------- | -------------------------------------- | ---------- | ----------
|
|Assets                                  |                                           |                                        |            |           
|Current assets:                         |                                           |                                        |            |           
|                                        | Cash and cash equivalents                 |                                        | $          | 2,629,581 
|                                        | Accounts receivable                       |                                        |            | 59,736,027
|                                        | Inventory                                 |                                        |            | 3,175,010 
|                                        |                                           |                                        |            |           
|                                        |                                           | Total current assets                   |            |           
|Plant and equipment, net                |                                           |                                        | 85,357,870 |           
|Other assets:                           |                                           |                                        |            |           
|                                        | Emission offsets, net                     |                                        |            | 2,216,666 
|                                        | Deposits                                  |                                        |            | 500,849   
|                                        |                                           |                                        |            |           
|                                        |                                           | Total assets                           |            | $         
|                                        |                                           |                                        |            |           
|Liabilities and Partners' Equity        |                                           |                                        |            |           
|Current liabilities:                    |                                           |                                        |            |           
|                                        | Accounts payable to affiliates and others |                                        | $          | 51,282,703
|                                        |                                           |                                        |            |           
|                                        |                                           | Total current liabilities              |            |           
|Payable to Aera Energy LLC              |                                           |                                        |           |           
|                                        |                                           |                                        |            |           
|                                        |                                           | Total liabilities                      |            |           
|                                        |                                           |                                        |            |           
|Commitments and contingencies (Note 10) |                                           |                                        |            |           
|Partners' equity:                       |                                           |                                        |            |           
|                                        | San Joaquin Energy Company                |                                        |            | 51,166,650
|                                        | Aera Energy LLC                           |                                        |            | 51,166,650
|                                        |                                           |                                        |            |           
|                                        |                                           | Total partners' equity                 |            |           
|                                        |                                           |                                        |            |           
|                                        |                                           | Total liabilities and partners' equity |            | $         
|                                        |                                           |                                        |            |           

The
accompanying notes are an integral part of these financial statements.

263

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MIDWAY-SUNSET COGENERATION COMPANY        STATEMENTS OF INCOME        FOR THE YEARS ENDED DECEMBER 31, 2002, 2001 (UNAUDITED) AND 2000 (UNAUDITED)

|          |                                    | 2002                       |   | 2001       |             | 2000
|--------- | ---------------------------------- | -------------------------- | - | ---------- | ----------- | ----
|
|Revenues: |                                    |                            |   |            |             |     
|          | Sales of electricity to affiliates |                            | $ | 95,266,858 |             | $   
|          | Sales of electricity to others     |                            |   | 3,625,518  |             |     
|          |                                    |                            |   |            |             |     
|          |                                    | Total sales of electricity |   |            | 98,892,376  |     
|          | Sales of steam to affiliate        |                            |   | 30,633,411 |             |     
|          | Interest and other income          |                            |   | 889,093    |             |     
|          |                                    |                            |   |            |             |     
|          |                                    | Total revenues             |   |            | 130,414,880 |     
|          |                                    |                            |   |            |             |     
|Expenses: |                                    |                            |   |            |             |     
|          | Fuel                               |                            |   | 79,458,882 |             |     
|          | Maintenance and operations         |                            |   | 3,818,742  |             |     
|          | Contract labor                     |                            |   | 5,127,663  |             |     
|          | Property taxes                     |                            |   | 2,005,646  |             |     
|          | Write-off of development costs     |                            |   | 3,388,089  |             |     
|          | Depreciation and amortization      |                            |   | 7,808,401  |             |     
|          | (Gain)/loss on disposal of asset   |                            |   | (2,121     | )           |     
|          | Interest expense                   |                            |   |           |             |     
|          |                                    |                            |   |            |             |     
|          |                                    | Total expenses             |   |            | 101,605,302 |     
|          |                                    |                            |   |            |             |     
|          |                                    | Net income                 |   | $          | 28,809,578  |     
|          |                                    |                            |   |            |             |     

The
accompanying notes are an integral part of these financial statements.

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MIDWAY-SUNSET COGENERATION COMPANY        STATEMENTS OF CHANGES IN PARTNERS' EQUITY        FOR THE YEARS ENDED DECEMBER 31, 2002, 2001 (UNAUDITED) AND 2000 (UNAUDITED)

|                                       |                    | San Joaquin
Energy
Company |            | Aera Energy
LLC |   | Total      |            
|-------------------------------------- | ------------------ | -------------------------- | ---------- | --------------- | - | ---------- | -----------
|Balance, December 31, 1999 (unaudited) |                    | $                          | 54,872,956 |                 | $ | 54,872,956 |            
|                                       | Net income         |                            |            | 15,564,905      |   |            | 15,564,905 
|                                       | Cash distributions |                            |            | (8,000,000      | ) |            | (8,000,000 
|                                       |                    |                            |            |                 |   |            |            
|Balance, December 31, 2000 (unaudited) |                    |                            | 62,437,861 |                 |   | 62,437,861 |            
|                                       | Net income         |                            |            | 27,824,000      |   |            | 27,824,000 
|                                       | Cash distributions |                            |            | (13,000,000     | ) |            | (13,000,000
|                                       |                    |                            |            |                 |   |            |            
|Balance, December 31, 2001 (unaudited) |                    |                            | 77,261,861 |                 |   | 77,261,861 |            
|                                       | Net income         |                            |            | 14,404,789      |   |            | 14,404,789 
|                                       | Cash distributions |                            |            | (40,500,000     | ) |            | (40,500,000
|                                       |                    |                            |            |                 |   |            |            
|Balance, December 31, 2002             |                    | $                          | 51,166,650 |                 | $ | 51,166,650 |            
|                                       |                    |                            |            |                 |   |            |            

The
accompanying notes are an integral part of these financial statements.

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MIDWAY-SUNSET COGENERATION COMPANY        STATEMENTS OF CASH FLOWS        FOR THE YEARS ENDED DECEMBER 31, 2002, 2001 (UNAUDITED) AND 2000 (UNAUDITED)

|                                                  |                                                                                   | 2002                                                            |                                           | 2001        |            | 2000        |            
|------------------------------------------------- | --------------------------------------------------------------------------------- | --------------------------------------------------------------- | ----------------------------------------- | ----------- | ---------- | ----------- | -----------
|
|Cash flows from operating activities:             |                                                                                   |                                                                 |                                           |             |            |             |            
|                                                  | Net income                                                                        |                                                                 | $                                         | 28,809,578  |            | $           | 55,648,000 
|                                                  | Adjustments to reconcile net income to net cash provided by operating activities: |                                                                 |                                           |             |            |             |            
|                                                  |                                                                                   | Depreciation and amortization                                   |                                           |             | 7,808,401  |             |            
|                                                  |                                                                                   | (Gain) loss on disposal of asset                                |                                           |             | (2,121     | )           |            
|                                                  |                                                                                   | Write-off of development costs                                  |                                           |             | 3,388,089  |             |            
|                                                  |                                                                                   | Decrease (increase) in accounts receivable                      |                                           |             | 41,886,448 |             |            
|                                                  |                                                                                   | (Increase) decrease in inventory                                |                                           |             | (772,863   | )           |            
|                                                  |                                                                                   | Decrease (increase) in deposits                                 |                                           |             | 1,999,151  |             |            
|                                                  |                                                                                   | (Decrease) increase in accounts payable to affiliates and other |                                           |             | (3,483,995 | )           |            
|                                                  |                                                                                   | Decrease in interest payable                                    |                                           |             |           |             |            
|                                                  |                                                                                   | (Decrease) increase in other liabilities                        |                                           |             | (5,333,340 | )           |            
|                                                  |                                                                                   |                                                                 |                                           |             |            |             |            
|                                                  |                                                                                   |                                                                 | Net cash provided by operating activities |             |            | 74,299,348  |            
|                                                  |                                                                                   |                                                                 |                                           |             |            |             |            
|Cash flows from investing activities:             |                                                                                   |                                                                 |                                           |             |            |             |            
|                                                  | Capital expenditures                                                              |                                                                 |                                           | (760,522    | )          |             | (12,924,527
|                                                  | Proceeds from sale of equipment                                                   |                                                                 |                                           | 5,000       |            |             | 12,999     
|                                                  |                                                                                   |                                                                 |                                           |             |            |             |            
|                                                  |                                                                                   |                                                                 | Net cash used in investing activities     |             |            | (755,522    | )          
|                                                  |                                                                                   |                                                                 |                                           |             |            |             |            
|Cash flows from financing activities:             |                                                                                   |                                                                 |                                           |             |            |             |            
|                                                  | Repayment of long-term debt                                                       |                                                                 |                                           |            |            |             |           
|                                                  | Cash distributions                                                                |                                                                 |                                           | (81,000,000 | )          |             | (26,000,000
|                                                  | Repayment of long-term debt                                                       |                                                                 |                                           |            |            |             |           
|                                                  |                                                                                   |                                                                 |                                           |             |            |             |            
|                                                  |                                                                                   |                                                                 | Net cash used in financing activities     |             |            | (81,000,000 | )          
|                                                  |                                                                                   |                                                                 |                                           |             |            |             |            
|Net decrease in cash and cash equivalents         |                                                                                   |                                                                 | (7,456,174                                | )           |            | (2,270,443  | )          
|Cash and cash equivalents, beginning of year      |                                                                                   |                                                                 | 10,085,755                                |             |            | 12,356,198  |            
|                                                  |                                                                                   |                                                                 |                                           |             |            |             |            
|Cash and cash equivalents, end of year            |                                                                                   | $                                                               | 2,629,581                                 |             | $          | 10,085,755  |            
|                                                  |                                                                                   |                                                                 |                                           |             |            |             |            
|Supplemental disclosure of cash flow information: |                                                                                   |                                                                 |                                           |             |            |             |            
|                                                  | Cash paid during the year for interest                                            |                                                                 | $                                         |            |            | $           |           
|                                                  |                                                                                   |                                                                 |                                           |             |            |             |            

The
accompanying notes are an integral part of these financial statements.

266

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MIDWAY-SUNSET COGENERATION COMPANY        NOTES TO FINANCIAL STATEMENTS        DECEMBER 31, 2002, 2001 (UNAUDITED) AND 2000 (UNAUDITED)

1. Organization and Operations

Midway-Sunset Cogeneration Company (the "Partnership") is a California general partnership between San Joaquin Energy Company ("San Joaquin"), holding a
50 percent general partnership interest and Aera Energy LLC ("Aera"), a California limited liability company whose members are (1) SWEPI LP and (2) Shell Onshore
Ventures, Inc. (affiliates of Shell Oil Company) and (3) Mobil California Exploration and Producing Asset Company (affiliate of ExxonMobil), holding a combined 50 percent general
partnership interest. San Joaquin is a wholly owned subsidiary of Edison Mission Energy ("Mission"), an indirect wholly owned subsidiary of Edison International.

The
Partnership was organized to design, construct, own and operate a qualifying cogeneration facility (the "Facility"), as defined in the Public Utility Regulatory Policies Act of 1978
and the regulations promulgated thereunder, all as amended ("PURPA"), located in Kern County, California. The Facility currently sells most of the electricity generated by the facility to Southern
California Edison Company ("SCE"), a wholly owned subsidiary of Edison International, for resale to its customers and sells all steam produced to Aera for use in its Midway-Sunset oil field
operations. The Facility was certified as a "qualifying facility" under PURPA prior to the start of operations, and management believes they have fulfilled all requirements to receive continued
"qualifying facility" status.

The
Facility consists of three combustion turbine generators producing electricity and steam sequentially using one fuel source. The Facility is designed to have the capacity of
generating 228 megawatts of electricity and 1.2 million pounds of steam per hour.

The
Partnership, unless sooner dissolved or extended pursuant to the terms of the partnership agreement, will be dissolved on May 8, 2010.

2. Summary of Significant Accounting Policies

Use of Estimates in Financial Statements

The preparation of financial statements in conformity with generally accepted accounting principles in the United States requires management to make estimates and
assumptions that affect the reported amounts of assets and liabilities and disclosures of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues
and expenses during the reporting period. Actual results could differ from those estimates.

Cash and Cash Equivalents

The Partnership considers cash and cash equivalents to include cash and short-term investments with an original maturity of three months or less.

Inventory

Inventory is stated at the lower of weighted average cost or market.

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Plant and Equipment

Plant and equipment are stated at cost. Depreciation is computed on a straight-line basis over the following estimated useful lives:

Power plant facilities

Up to 30 yearsCapitalized interest

Up to 30 yearsFurniture and office equipment

3 to 7 years


At
January 1, 2000 the Partnership changed the estimated useful life related to the hot gas portion of the three combustion turbine generators from 20 years to
12 years. The change resulted from management's intention to modify the existing turbines to increase efficiency and reduce emissions and to accurately reflect the true life of the hot gas path
components. This modification is commonly referred to as Dry Low Nox.

Capitalized Interest

Interest incurred on funds borrowed by the Partnership to finance plant construction is capitalized. Capitalization of interest is discontinued when the plant is
completed and deemed operational. Such capitalized interest is included in property, plant and equipment.

Major Maintenance

Certain major pieces of equipment require major maintenance on a periodic basis. These costs are expensed as incurred.

Financial Instruments

Financial instruments that potentially subject the Partnership to significant concentrations of credit or valuation risk consist principally of cash equivalents
and accounts receivable.

The
carrying amounts, reported in the balance sheets for cash and cash equivalents, and accounts receivable, approximate fair value.

Revenue Recognition

Revenue is recognized as billable under the provisions of three power purchase agreements which have varying terms of approximately four to twenty years.
Electricity revenue is calculated based on power output and established prices, as defined in the power purchase agreements. Steam revenue is calculated based on steam output and established prices,
as defined in the steam sale and purchase agreement. Revenue is also recognized as billable under the provisions of a steam sale and purchase agreement.

Income Taxes

The Partnership is treated as a partnership for income tax purposes and the income or loss of the Partnership is included in the income tax returns of the
individual partners. Accordingly, no recognition has been given to income taxes in the financial statements.

268

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Project Development Costs

The Partnership capitalizes project development costs as incurred. These costs consist of professional fees, salaries, permits and other directly related costs.
The capitalized costs are amortized over the operational life of the project or charged to expense if management determines the costs to be unrecoverable. The Partnership has written off development
costs of $3,388,089 in 2002. These costs were associated with the planned expansion of the project and were capitalized from 2000 through 2002. A decision was made in 2002 to discontinue funding of
the expansion project and all associated costs were subsequently written off.

New Accounting Pronouncements

Statement of Financial Accounting Standards No. 133

The Partnership adopted Financial Accounting Standards Board (FASB) Statement No. 133, "Accounting for Derivative Instruments and Hedging Transactions"
(FAS 133), as amended by SFAS 138, "Accounting for Derivative Instruments and Hedging Transactionsan amendment of FASB Statement No. 133," effective January 1,
2001. Provisions in Statement No. 133, as amended, affect the accounting and disclosure of certain contractual arrangements and operations of the Partnership. Under Statement No. 133, as
amended, all derivative instruments are recognized in the balance sheet at their fair values and changes in fair value are recognized immediately in earnings, unless the derivatives qualify as hedges
of future cash flows or net investments. For derivatives qualifying as hedges of future cash flows, the effective portion of changes in fair value is recorded in equity until the related hedged items
impact earnings. Any ineffective portion of a hedge is reported in earnings immediately. The Partnership reviewed the activities performed under its contracts and the respective terms and concluded
that the contracts meet the Normal Purchases and Normal Sales Exception defined in FAS 133, which resulted in accrual accounting consistent with the pre-adoption of FAS 133.

Statement of Financial Accounting Standards No. 143

Effective January 1, 2003, the Partnership adopted Statement of Financial Accounting Standards ("SFAS") No. 143, "Accounting for Asset Retirement
Obligations." SFAS No. 143 requires entities to record the fair value of a liability for an asset retirement obligation in the period in which it is incurred. When the liability is initially
recorded, the entity capitalizes a cost by increasing the carrying amount of the related long-lived asset. Over time, the liability is increased to its present value each period, and the
capitalized cost is depreciated over the useful life of the related asset. Upon settlement of the liability, an entity either settles the obligation for its recorded amount or incurs a gain or loss
upon settlement. The Partnership expects to record a cumulative effect adjustment effective January 1, 2003, that will decrease net income by $613,000.

Statement of Financial Accounting Standards No. 145

In April 2002, the Financial Accounting Standards Board ("FASB") issued SFAS No. 145, "Rescission of FASB Statements No. 4, 44, and 64,
Amendment of FASB Statement No. 13, and Technical Corrections," which supersedes previous guidance for reporting gains and losses from extinguishment of debt and accounting for leases, among
other things, which is effective on January 1,

269

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2003. The portion of the statement relating to the rescission of SFAS No. 4, "Reporting Gains and Losses from Extinguishment of Debt" requires that any gain or loss on extinguishment of debt
that was classified as an extraordinary item that does not meet the unusual in nature and infrequent of occurrence criteria in APB Opinion No. 30, "Reporting the Results of
OperationsReporting the Effects of Disposal of a Segment of a Business, and Extraordinary, Unusual and Infrequently Occurring Events and Transactions" shall be reclassified. The
Partnership does not anticipate that the adoption of SFAS No. 145 will have a material effect on its financial position or the results of operations.

Statement of Financial Accounting Standards No. 146

Effective January 1, 2003, the Partnership adopted SFAS No. 146, "Accounting for Costs Associated with Exit or Disposal Activities." SFAS
No. 146 requires that liabilities for costs associated with exit or disposal activities initiated after December 31, 2002 be recognized when incurred, rather than at the date of a
commitment to an exit or disposal plan. The Partnership does not anticipate that the adoption of SFAS No. 146 will have a material effect on its financial position or the results of operations.

Statement of Financial Accounting Standards Interpretation No. 45

In November 2002, the FASB issued SFAS Interpretation No. 45, "Guarantor's Accounting and Disclosure Requirements for Guarantees, Including Indirect
Guarantees of Indebtedness of Others." This interpretation establishes reporting requirements to be made by a guarantor about its obligations under certain guarantees that it has issued. It also
clarifies that a guarantor is required to recognize, at the inception of a guarantee, a liability for the fair value of the obligation undertaken in issuing the guarantee. The initial recognition and
initial measurement provisions of this interpretation are applicable on a prospective basis to guarantees issued or modified after December 31, 2002. The Partnership does not anticipate that
adoption of this standard will have a material effect on its financial position or the results of operations.

3. Accounts Receivable

Accounts receivable consists of the following at December 31, 2002 and 2001:

2002

2001Accounts receivable from affiliates:SCE

$
14,641,191

$
55,563,403Aera


7,044,875


5,723,608Other affiliates


293,155


1,460,57421,979,221


62,747,585Accounts receivable from others


37,756,806


38,874,890$
59,736,027

$
101,622,475


270

---

4. Inventory

Inventory consists of the following at December 31, 2002 and 2001:

2002

2001Fuel gas

$
791,267

$
84,891Materials and spare parts


2,383,743


2,317,256$
3,175,010

$
2,402,147


5. Plant and Equipment

Plant and equipment consists of the following at December 31, 2002 and 2001:

2002

2001Power plant facilities

$
156,080,240

$
155,829,632Capitalized interest


8,769,831


8,769,831Furniture and office equipment


1,171,097


1,085,598Construction in process


221,018


3,223,561166,242,186


168,908,622Less: accumulated depreciation and amortization


(80,884,316
)

(73,461,905
)$
85,357,870

$
95,446,717


6. Other Assets

Emission Offsets

Emission offsets contributed to the Partnership were valued at an amount agreed upon by the partners and are being amortized on a straight-line basis over a
period of 20 years. Emission offsets consist of the following at December 31, 2002 and 2001:

2002

2001Cost

$
7,000,000

$
7,000,000Less: Accumulated amortization


(4,783,334
)

(4,433,334
)$
2,216,666

$
2,566,666


Deposits

The partnership was required to maintain a deposit of $500,000 with the Automated Power Exchange at December 31, 2002. The Partnership was required to
maintain a deposit with the Automated Power Exchange to ensure monthly liquidity requirements. The required deposit was reduced during 2002 as the Partnership became its own scheduling coordinator.

271

---

7. Accounts Payable

Accounts payable consists of the following at December 31, 2002 and 2001:

2002

2001Accounts payable to affiliates:Aera Energy LLC

$
5,381,833

$
6,666,660Edison Mission Operations and Maintenance


315,115


257,876San Joaquin


171,008


234,4085,867,956


7,158,944Accounts payable to others


45,414,747


47,607,754$
51,282,703

$
54,766,698


8. Related Party Transactions

In addition to the related party transactions discussed in Notes 3, 7 and 9, the Partnership entered into certain contracts and agreements with San
Joaquin, Aera and certain other related parties.

Under
the terms of a Power Purchase Agreement ("PPA"), SCE agreed to purchase up to 200 megawatts of the electric power generated by the Facility for a period of 20 years. SCE
operates as a regulated utility and is a sister company of Mission. The Partnership is paid for energy based upon the price of SCE's avoided fuel costs, the quantity of kilowatts delivered and the
incremental energy rate used to determine SCE's published avoided cost of energy. SCE also pays the Partnership for firm capacity based upon a contracted amount per kilowatt year, as determined in the
Power Purchase Agreement.

The
Partnership and SCE signed an amendment to the PPA, which was approved by the California Public Utility Commission during 1999, which was effective as of October 14, 1996. The
amendment contains energy pricing terms that maintain the intent of the PPA's original pricing terms. Energy payments will be based on an energy rate that is calculated using a Short Run Avoided Cost
("SRAC") based formula that contains a prescribed energy rate indexed to the Southern California Border Spot Price of natural gas. At such time as the California Public Utilities Commission issues an
order determining that the California Power Exchange, or equivalent, is functioning properly, as defined in the amendment, the SRAC based energy rate will be compared to a price determined by taking
95 percent of the energy rate posted by the California Power Exchange. The higher of the two rates will be used to calculate energy payments due the Partnership.

Effective
April 30, 1997, the Partnership entered into an agreement with Aera to sell 9 megawatts of excess electric energy generated by the Facility. The terms of the agreement
require Aera to pay for electric energy based on a formula defined in the agreement but provided for a rebate at the conclusion of the contract if cumulative payments exceeded a certain threshold. At
December 31, 2001 the potential rebate was approximately $12 million.

In
January 2002, the original agreement was terminated effective October 1, 2001. The Partnership simultaneously entered into a new agreement with Aera to sell 18 megawatts
of excess electric energy generated by the Facility, which expires on May 08, 2009. The new agreement, among other things, allows the Partnership to defer payment of the $12 million due
Aera under the original agreement.

272

---

Payment of the $12 million is to be made in 27 equal monthly installments, which can be offset against monthly payments due from Aera for energy purchases. At December 31, 2002, the
Partnership has $5,333,340 in current payables related to the new agreement. The new agreement also provides for San Joaquin to be paid a monthly power price adjustment fee, the cumulated total of
which shall not exceed $12 million through the duration of the agreement.

The
Partnership recognized total electricity sales to affiliates of $95,266,858, $173,853,446 and $121,654,339 in 2002, 2001 and 2000, respectively, under these contracts.

The
Partnership has a payable of $34,977,715 to SCE which is wholly offset by a receivable from the California Power Exchange. For further discussion of this situation refer to
Note 9. California Power Crisis.

Under
the terms of a Steam Sale and Purchase Agreement, Aera purchases 8.6 billion pounds of steam per year generated by the Facility through May 1, 2009. The Partnership
is paid a steam fuel charge based upon the quantity and quality of steam delivered during the month, which is priced at the weighted average of the Partnership's cost of fuel and a processing charge
per MMBtu, as defined in the Steam Sale and Purchase Agreement. The Partnership sold $30,633,411, $60,860,800 and $47,393,056 of steam in 2002, 2001 and 2000, respectively, under this agreement which
is included within sales of steam in the accompanying statements of income. The quantity of steam sold under this agreement is sufficient for the Partnership to meet qualifying facility status.

Under
the terms of an Operation and Maintenance Agreement, employees of Edison Mission Operations and Maintenance, Inc. ("EMOM"), a wholly owned subsidiary of Mission, perform all
necessary functions to operate and maintain the Facility. The Partnership pays for direct costs of these services, plus an increment to cover overhead and benefits. In addition, effective
January 1992, the
Agreement was amended to include payment to EMOM of certain annual fees. Pursuant to this Agreement, the Partnership incurred costs of $3,032,198, $3,088,614 and $6,045,133 which included annual fees
earned by EMOM of $336,000 in 2002 and 2001, respectively and $3,099,900 in 2000, which are included in contract labor in the accompanying statements of income.

Under
the terms of the Partnership Agreement, employees of Aera perform services for the Partnership. The Partnership pays for direct costs of these services, plus an increment to cover
overhead and benefits. Pursuant to this arrangement, the Partnership incurred costs of $310,961, $357,526 and $427,796 in 2002, 2001 and 2000, respectively.

The
Partnership entered into a Financial Services Agreement with San Joaquin whereby San Joaquin provides certain required financial, accounting and other services for an annual fee of
$125,000 in 2002, 2001 and 2000.

Under
the terms of a Surface Lease Agreement, the Partnership leases approximately 13 acres of land from AERA, which serves as the Facility site. The initial term of the lease extends
through October 1, 2009, with an annual rental, amended as of January 1998, of $1,450.

9. California Power Crisis

In August of 2001, SCE and the Partnership agreed to a Stipulated amount of $56,862,811 for electric energy, capacity, and other charges covering past due amounts
from November 1, 2000 through

273

---

March 26, 2001. SCE claimed non-payment stems from the undercollection in its tariff rates based on the full cost of providing service to their customers. The Partnership notified
SCE that it was in breach of the Power Purchase Agreement ("PPA") as a result of the delinquent payments.

On
August 3, 2001, the Partnership and SCE entered into a written agreement to address the outstanding issues surrounding SCE's failure to pay past due amounts for energy
deliveries from the past due period. SCE agreed to a payment schedule based on the occurrence of certain events, the first of which occurred with the execution of the agreement. SCE paid
10 percent of the stipulated amount $5,686,281 plus interest of $1,431,455 on August 9, 2001 and agreed to pay an additional 10 percent upon a legislative solution being reached
which would restore SCE to creditworthiness and allow them to pay its debts in a timely manner.

In
return for SCE's agreement to the stipulated past due amounts and to an event determined payment schedule for the unpaid balance, the Partnership agreed to stay the litigation for a
standstill period as specified in the agreement.

On
October 2, 2001, SCE and the California Public Utilities Commission ("CPUC") announced an agreement which was expected to allow SCE to eventually restore its creditworthiness.
The CPUC agreed to freeze consumer rates despite a decline in the price of wholesale electricity.

As
part of the amendment signed December 2001, the Partnership agreed to forego the second 10% payment in favor of full payment prior May 31, 2002.

On
March 1, 2002 SCE paid the Partnership the adjusted balance of the stipulated amount including accrued interest at 7% amounting to approximately $52,469,549 in full settlement
of their obligations.

The
Partnership is owed $36,451,347, included in Accounts Receivable, by the California Power Exchange ("PX") for power sold into the California ISO during 2000 and 2001. The PX, upon
receiving funds from its debtors, will pay the Partnership an amount adjusted for wind down charges. The Partnership will then pro-rate the receipt and reimburse the following parties as
follows: SCE $34,977,715, PG&E $876,472, included in accounts payable, for previous power sales. The partnership is obligated to reimburse SCE and PG&E, only if funds are received from the PX.

10. Commitments and Contingencies

The Partnership has agreed to pay public utility maintenance and other fees during the term of the Interconnection contract for the transmission facilities used
to transport the electric power generated to SCE, PG&E, and others. The Partnership incurred maintenance fees of $1,181,227 for these services in 2002, 2001 and 2000.

Effective
November 1989, the Partnership entered into a 20 year Power Purchase Agreement with PG&E, a public utility, whereby the utility agreed to purchase excess
on-peak and partial peak electricity from the Facility. This excess electricity consists of the facility output less station use, Aera field use and the initial 200 megawatts generated for
sale to SCE. Upon request by the utility, the Facility may deliver during off-peak and super off-peak periods. The Partnership sold $2,046,330, $1,199,680 and $3,069,219 of
electricity in 2002, 2001 and 2000, respectively, under this agreement which is included within sales of electricity to others in the accompanying statements of income.

274

---

Under
the terms of a Gas Management Services Agreement, the Partnership reimburses a third party for the procurement of fuel gas for use in its operations through 2009, cancelable under
certain terms
defined in the agreement. The Partnership incurred costs related to this third party $52,267,451, $130,887,239 and $90,535,134 for fuel gas purchases in 2002, 2001 and 2000, respectively.

The
Partnership purchases the remainder of its natural gas requirements in the spot market. The Partnership may be exposed to fluctuations in the price of natural gas. However,
fluctuations in the prices paid for natural gas are implicitly tied to the revenues received from power and steam under the various agreements.

275

---



REPORT OF INDEPENDENT ACCOUNTANTS

To
the Management Committee of
March Point Cogeneration Company:

In
our opinion, the accompanying balance sheet as of December 31, 2002 and the related statements of income and comprehensive income, partners' equity, and cash flows present
fairly, in all material respects, the financial position of March Point Cogeneration Company (a general partnership between Equilon Enterprises LLC, Texaco March Point Holdings Inc., and San
Juan Energy Company) at December 31, 2002, and the results of its operations and its cash flows for the year then ended in conformity with accounting principles generally accepted in the United
States of America. These financial statements are the responsibility of the Partnership's management; our responsibility is to express an opinion on these financial statements based on our audit. We
conducted our audit of these statements in accordance with auditing standards generally accepted in the United States of America, which 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, assessing the accounting principles used and significant estimates made by management, and evaluating the overall financial statement presentation. We believe that our audit provides a
reasonable basis for our opinion.

PricewaterhouseCoopers
LLP

Los
Angeles, California
January 10, 2003

276

---



MARCH POINT COGENERATION COMPANY        BALANCE SHEETSDECEMBER 31, 2002 AND 2001 (unaudited)

|                                                                                                                          |                                                                                                                                | 2002                     |                                        | 2001      
|------------------------------------------------------------------------------------------------------------------------- | ------------------------------------------------------------------------------------------------------------------------------ | ------------------------ | -------------------------------------- | ----------
|
|Assets                                                                                                                    |                                                                                                                                |                          |                                        |           
|Current Assets:                                                                                                           |                                                                                                                                |                          |                                        |           
|                                                                                                                          | Cash and cash equivalents                                                                                                      |                          | $                                      | 7,285,083 
|                                                                                                                          | Receivables:                                                                                                                   |                          |                                        |           
|                                                                                                                          |                                                                                                                                | Equilon and subsidiaries |                                        |           
|                                                                                                                          |                                                                                                                                | Puget Sound Energy       |                                        |           
|                                                                                                                          |                                                                                                                                | Other                    |                                        |           
|                                                                                                                          | Current portion of escrow account                                                                                              |                          |                                        | 934,215   
|                                                                                                                          | Inventory                                                                                                                      |                          |                                        | 2,036,776 
|                                                                                                                          |                                                                                                                                |                          |                                        |           
|                                                                                                                          |                                                                                                                                |                          | Total current assets                   |           
|                                                                                                                          |                                                                                                                                |                          |                                        |           
|Operating Facility and Equipment, at cost, net of accumulated depreciation of $48,587,514 in 2002 and $43,931,211 in 2001 |                                                                                                                                |                          | 87,772,109                             |           
|                                                                                                                          |                                                                                                                                |                          |                                        |           
|Other Assets:                                                                                                             |                                                                                                                                |                          |                                        |           
|                                                                                                                          | Deferred loan fees, net of accumulated amortization of $1,885,874 in 2002 and $1,777,184 in 2001                               |                          |                                        | 152,830   
|                                                                                                                          | Escrow account, net of current portion                                                                                         |                          |                                        | 686,220   
|                                                                                                                          | Gas purchase agreement at fair value                                                                                           |                          |                                        | 29,596,277
|                                                                                                                          |                                                                                                                                |                          |                                        |           
|                                                                                                                          |                                                                                                                                |                          | Total other assets                     |           
|                                                                                                                          |                                                                                                                                |                          |                                        |           
|                                                                                                                          |                                                                                                                                |                          | Total assets                           |           
|                                                                                                                          |                                                                                                                                |                          |                                        |           
|Liabilities and Partners' Equity                                                                                          |                                                                                                                                |                          |                                        |           
|Current Liabilities:                                                                                                      |                                                                                                                                |                          |                                        |           
|                                                                                                                          | Current portion of project financing loan                                                                                      |                          | $                                      | 13,684,300
|                                                                                                                          | Working capital loan                                                                                                           |                          |                                        | 5,000,000 
|                                                                                                                          | Amounts payable to Equilon and subsidiaries                                                                                    |                          |                                        | 2,502,017 
|                                                                                                                          | Amounts payable to Texaco and subsidiaries                                                                                     |                          |                                        | 214,731   
|                                                                                                                          | Trade and other payables (amount includes $1,799,549 and $1,789,207 payable to related parties in 2002 and 2001, respectively) |                          |                                        | 3,589,331 
|                                                                                                                          |                                                                                                                                |                          |                                        |           
|                                                                                                                          |                                                                                                                                |                          | Total current liabilities              |           
|                                                                                                                          |                                                                                                                                |                          |                                        |           
|Project Financing Loan, net of current portion                                                                            |                                                                                                                                |                          | 13,724,400                             |           
|                                                                                                                          |                                                                                                                                |                          |                                        |           
|Partners' Equity:                                                                                                         |                                                                                                                                |                          |                                        |           
|                                                                                                                          | Equilon Enterprises LLC                                                                                                        |                          |                                        | 24,633,904
|                                                                                                                          | Texaco March Point Holdings Inc.                                                                                               |                          |                                        | 24,831,768
|                                                                                                                          | San Juan Energy Company                                                                                                        |                          |                                        | 49,465,675
|                                                                                                                          |                                                                                                                                |                          |                                        |           
|                                                                                                                          |                                                                                                                                |                          | Total partners' equity                 |           
|                                                                                                                          |                                                                                                                                |                          |                                        |           
|                                                                                                                          |                                                                                                                                |                          | Total liabilities and partners' equity |           
|                                                                                                                          |                                                                                                                                |                          |                                        |           

277

---

MARCH POINT COGENERATION COMPANY        STATEMENTS OF INCOME AND COMPREHENSIVE INCOME        FOR THE YEARS ENDED DECEMBER 31, 2002, 2001 (unaudited) AND 2000 (unaudited)

|                                   |                                                                                  | 2002                                    |   | 2001       |            | 2000
|---------------------------------- | -------------------------------------------------------------------------------- | --------------------------------------- | - | ---------- | ---------- | ----
|
|Revenues:                          |                                                                                  |                                         |   |            |            |     
|                                   | Sales of energy to Puget Sound Energy                                            |                                         | $ | 66,892,786 |            | $   
|                                   | Sales of steam to Equilon                                                        |                                         |   | 13,884,212 |            |     
|                                   | Sales of natural gas                                                             |                                         |   |           |            |     
|                                   | Interest and other income                                                        |                                         |   | 400,153    |            |     
|                                   |                                                                                  |                                         |   |            |            |     
|                                   |                                                                                  | Total revenues                          |   |            | 81,177,151 |     
|                                   |                                                                                  |                                         |   |            |            |     
|Costs and Expenses:                |                                                                                  |                                         |   |            |            |     
|                                   | Plant and other operating expenses                                               |                                         |   | 39,738,925 |            |     
|                                   | Depreciation and amortization                                                    |                                         |   | 4,812,804  |            |     
|                                   | General and administrative expenses                                              |                                         |   | 363,367    |            |     
|                                   | Interest expense                                                                 |                                         |   | 1,240,284  |            |     
|                                   |                                                                                  |                                         |   |            |            |     
|                                   |                                                                                  | Total costs and expenses                |   |            | 46,155,380 |     
|                                   |                                                                                  |                                         |   |            |            |     
|                                   | Income before change in accounting principle                                     |                                         |   | 35,021,771 |            |     
|                                   |                                                                                  |                                         |   |            |            |     
|                                   | Cumulative effect on prior years of change in accounting major maintenance costs |                                         |   |           |            |     
|                                   |                                                                                  |                                         |   |            |            |     
|                                   |                                                                                  | Net income                              |   |            | 35,021,771 |     
|                                   |                                                                                  |                                         |   |            |            |     
|Other comprehensive income/(loss): |                                                                                  |                                         |   |            |            |     
|                                   | Cumulative effect on prior years of change in accounting for derivatives         |                                         |   |           |            |     
|                                   | Unrealized holding gain/(loss) arising during the period                         |                                         |   | (957,635   | )          |     
|                                   | Reclassification adjustment included in net income                               |                                         |   | (1,787,741 | )          |     
|                                   |                                                                                  |                                         |   |            |            |     
|                                   |                                                                                  | Total other comprehensive income/(loss) |   |            | (2,745,376 | )   
|                                   |                                                                                  |                                         |   |            |            |     
|                                   |                                                                                  | Comprehensive income                    |   | $          | 32,276,395 |     
|                                   |                                                                                  |                                         |   |            |            |     

The
accompanying notes are an integral part of these financial statements.

278

---



MARCH POINT COGENERATION COMPANY        STATEMENTS OF PARTNERS' EQUITY        FOR THE YEARS ENDED DECEMBER 31, 2002, 2001 (unaudited), AND 2000 (unaudited)

|                                                |  | Equilon
Enterprises
LLC |            | Texaco
March Point
Holdings Inc. |   | San Juan
Energy
Company |   | Total |           
|----------------------------------------------- |  | ----------------------- | ---------- | -------------------------------- | - | ----------------------- | - | ----- | ----------
|Partners' Equity, December 31, 1999 (unaudited) |  | $                       | 9,660,177  |                                  | $ | 9,737,769               |   | $     | 19,397,948
|Allocation of Comprehensive Income              |  |                         | 6,566,678  |                                  |   | 6,619,423               |   |       | 13,186,101
|Distributions                                   |  |                         | (2,315,700 | )                                |   | (2,334,300              | ) |       | (4,650,000
|                                                |  |                         |            |                                  |   |                         |   |       |           
|Partners' Equity, December 31, 2000 (unaudited) |  |                         | 13,911,155 |                                  |   | 14,022,892              |   |       | 27,934,049
|Allocation of Comprehensive Income              |  |                         | 8,935,827  |                                  |   | 9,007,601               |   |       | 17,943,428
|Distributions                                   |  |                         | (3,199,650 | )                                |   | (3,225,350              | ) |       | (6,425,000
|                                                |  |                         |            |                                  |   |                         |   |       |           
|Partners' Equity, December 31, 2001 (unaudited) |  |                         | 19,647,332 |                                  |   | 19,805,143              |   |       | 39,452,477
|Allocation of Comprehensive Income              |  |                         | 8,036,822  |                                  |   | 8,101,375               |   |       | 16,138,198
|Distributions                                   |  |                         | (3,050,250 | )                                |   | (3,074,750              | ) |       | (6,125,000
|                                                |  |                         |            |                                  |   |                         |   |       |           
|Partners' Equity, December 31, 2002             |  | $                       | 24,633,904 |                                  | $ | 24,831,768              |   | $     | 49,465,675
|                                                |  |                         |            |                                  |   |                         |   |       |           

The
accompanying notes are an integral part of these financial statements.

279

---

MARCH POINT COGENERATION COMPANY        STATEMENTS OF CASH FLOWS        FOR THE YEARS ENDED DECEMBER 31, 2002, 2001 (unaudited) AND 2000 (unaudited)

|                                                  |                                                                                   | 2002                                            |                                           | 2001        |             | 2000        |            
|------------------------------------------------- | --------------------------------------------------------------------------------- | ----------------------------------------------- | ----------------------------------------- | ----------- | ----------- | ----------- | -----------
|
|Cash Flows from Operating Activities:             |                                                                                   |                                                 |                                           |             |             |             |            
|                                                  | Net income                                                                        |                                                 | $                                         | 35,021,771  |             | $           | 18,620,978 
|                                                  | Adjustments to reconcile net income to net cash provided by operating activities: |                                                 |                                           |             |             |             |            
|                                                  |                                                                                   | Depreciation and amortization                   |                                           |             | 4,812,804   |             |            
|                                                  |                                                                                   | Change in repair and maintenance liability, net |                                           |             |            |             |            
|                                                  |                                                                                   | Loss on disposal of equipment                   |                                           |             | 17,806      |             |            
|                                                  |                                                                                   | Ineffectiveness of cash flow hedge              |                                           |             | (14,228,312 | )           |            
|                                                  | Decrease/(increase) in receivables                                                |                                                 |                                           | 158,038     |             |             | 6,067,095  
|                                                  | Decrease/(increase) in inventories                                                |                                                 |                                           | 119,346     |             |             | (111,103   
|                                                  | Increase/(decrease) in payables                                                   |                                                 |                                           | (743,269    | )           |             | (5,165,583 
|                                                  |                                                                                   |                                                 |                                           |             |             |             |            
|                                                  |                                                                                   |                                                 | Net cash provided by operating activities |             |             | 25,158,184  |            
|                                                  |                                                                                   |                                                 |                                           |             |             |             |            
|Cash Flows from Investing Activities:             |                                                                                   |                                                 |                                           |             |             |             |            
|                                                  | Additions to operating facility and equipment, net                                |                                                 |                                           | (838,897    | )           |             | (580,020   
|                                                  | Proceeds from sale of equipment                                                   |                                                 |                                           |            |             |             | 535        
|                                                  |                                                                                   |                                                 |                                           |             |             |             |            
|                                                  |                                                                                   |                                                 | Net cash used in investing activities     |             |             | (838,897    | )          
|Cash Flows from Financing Activities:             |                                                                                   |                                                 |                                           |             |             |             |            
|                                                  | Proceeds from working capital loan                                                |                                                 |                                           | 5,000,000   |             |             | 5,000,000  
|                                                  | Payment on project financing loan                                                 |                                                 |                                           | (13,034,600 | )           |             | (12,384,400
|                                                  | Payment on working capital loan                                                   |                                                 |                                           | (5,000,000  | )           |             | (5,000,000 
|                                                  | Proceeds from escrow account                                                      |                                                 |                                           | 651,730     |             |             | 619,220    
|                                                  | Distributions to partners                                                         |                                                 |                                           | (12,250,000 | )           |             | (12,850,000
|                                                  |                                                                                   |                                                 |                                           |             |             |             |            
|                                                  |                                                                                   |                                                 | Net cash used in financing activities     |             |             | (24,632,870 | )          
|                                                  |                                                                                   |                                                 |                                           |             |             |             |            
|(Decrease) in Cash and Cash Equivalents           |                                                                                   |                                                 | (313,583                                  | )           |             | (1,796,256  | )          
|Cash and Cash Equivalents, beginning of year      |                                                                                   |                                                 | 7,598,666                                 |             |             | 9,394,922   |            
|                                                  |                                                                                   |                                                 |                                           |             |             |             |            
|Cash and Cash Equivalents, end of year            |                                                                                   | $                                               | 7,285,083                                 |             | $           | 7,598,666   |            
|                                                  |                                                                                   |                                                 |                                           |             |             |             |            
|Supplemental Disclosure of Cash Flow Information: |                                                                                   |                                                 |                                           |             |             |             |            
|Cash paid during the period for interest          |                                                                                   | $                                               | 1,427,835                                 |             | $           | 2,959,283   |            
|                                                  |                                                                                   |                                                 |                                           |             |             |             |            

The
accompanying notes are an integral part of these financial statements.

280

---



MARCH POINT COGENERATION COMPANY        NOTES TO FINANCIAL STATEMENTS        DECEMBER 31, 2002

1. NATURE OF OPERATIONS

March Point Cogeneration Company (the Partnership) was organized under California law on July 28, 1989 as a general partnership between Texaco Anacortes
Cogeneration Company (TACC), an indirect wholly-owned subsidiary of Texaco, Inc. and San Juan Energy Company (SJEC), an indirect wholly-owned subsidiary of Edison International (Edison).
Effective January 1, 1998, Equilon Enterprises LLC (Equilon), a subsidiary of Shell Oil Products US, acquired 49.8 percent of TACC's 50 percent interest in the Partnership. On
October 9, 2001 Texaco Inc. and Chevron Corp. merged to form ChevronTexaco Corp. During the year ended December 31, 2001, the partnership interest owned by TACC was acquired by
Texaco March Point Holdings Inc. (TMPHI), an indirect wholly-owned subsidiary of ChevronTexaco Corp. This acquisition has been accounted for as a merger of companies under common control in
which the historical ownership interest of TACC is presented as if historically owned by TMPHI. During the years ended December 31, 2002 and 2001 SJEC, TMPHI (TACC) and Equilon ownership ratios
were 50 percent, 25.1 percent and 24.9 percent, respectively.

The
Partnership was organized to design, construct, own and operate a qualifying cogeneration facility (the Facility), as defined in the Public Utility Regulatory Policies Act of 1978
and the regulations promulgated thereunder, all as amended (PURPA), located in Skagit County, Washington. The Partnership currently sells all the electric energy generated by the facility to Puget
Sound Energy, Inc. (Puget Sound Energy) for resale to its customers, and sells all steam produced to Equilon for use in its crude oil refining operations in its Puget Sound Refinery (PSR). The
Facility was certified as a "qualifying facility" under PURPA prior to the start of operations, and management believes they have fulfilled all requirements to receive continued "qualifying facility"
status.

Partnership
profit (loss) is allocated to the partners in proportion to their ownership percentages. The Partnership shall terminate, unless terminated at an earlier date pursuant to the
general partnership agreement, on the latter of December 31, 2011 or the date the Partnership elects to cease operations.

Construction
of the Facility was done in two Phases (Phase I and Phase II). Phase I of the Facility consists of two gas combustion turbine-generators, which exhaust heat into two heat
recovery steam generators (HRSG) producing electricity and steam sequentially using one fuel source. Phase II consists of one gas combustion turbine-generator, which exhausts heat into a HRSG, and a
steam turbine-generator which accepts steam from Phase I and II to produce additional electricity. The Facility is designed to support the nominally rated production of 140 megawatts of electric
energy and 476,000 pounds per hour of steam (exclusive of supplementary firing of the boilers), with Phase I nominally producing 80 megawatts and 320,000 pounds per hour and Phase II 60 megawatts and
156,000 pounds per hour.

2. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

Revenue Recognition

Revenue is recognized as the product being sold is delivered.

Operating Facility and Equipment

All costs (including interest and field overhead expenses) incurred during the construction and precommission phases of the Facility were capitalized as part of
the cost of the Facility.

281

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The
precommission phases were the periods starting with the testing of the turbines until the start of commercial operations for each phase.

Revenues
earned during the precommission phases were offset against the costs of the Facility. The Facility and related equipment are being depreciated on a straight-line
basis, over 30 years, the estimated life of the Facility.

Expenditures
for maintenance, repairs and renewals are expensed as incurred. Expenditures for additions and improvements are capitalized.

Deferred Loan Fees

All legal and financial fees associated with the Loan and Credit Agreement (see Note 3) were deferred and are being amortized, using the effective interest
method, over the term of the loan.

Statements of Cash Flows

For purposes of reporting cash flows, the Partnership considers short-term temporary cash investments with an original maturity of three months or
less to be cash equivalents.

Change in Accounting Principle

Effective January 1, 2001 the Partnership adopted Financial Accounting Standards Board Statement No. 133, Accounting for Derivative Instruments and
Hedging Activities (SFAS 133). SFAS 133 establishes accounting and reporting standards requiring that derivative instruments be recorded on the balance sheet as either assets or
liabilities measured at their fair value, unless the derivative meets a specific exception. SFAS 133 also requires that changes in a derivatives fair value be recognized currently in earnings
unless specific hedge accounting criteria are met. The Partnership's Fuel Sale and Purchase Agreements and Power Purchase Agreements are considered derivatives under SFAS 133. As of the
adoption of SFAS 133, the Partnership accounted for these contracts under the normal purchase and sale exception, which allows certain contracts to be accounted for using the accrual method of
accounting. However, Derivatives Implementation Group Issue C11 (DIG Issue C11), which became effective July 1, 2001, precludes the TM Star Fuel Purchase Contract from continuing to qualify for
the normal purchase and sale exception because the price of fuel purchased under the agreement is indexed to a broad inflation index and therefore the price paid is not viewed as being clearly and
closely related to the gas being purchased. Subsequent to the implementation of DIG Issue C11, the Partnership accounted for the TM Star Fuel Purchase Contract as a cash flow hedge. As a result, the
Partnership recorded an increase to Other Comprehensive Income of $24,584,225, reflecting the fair value of this contract as of July 1, 2001.

Use of Estimates

The preparation of financial statements in conformity with accounting principles generally accepted in the United States requires management to make estimates and
assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues
and expenses during the reporting period. Actual results could differ from those estimates.

282

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Fair Value of Financial Instruments

The carrying amount of the short-term investments approximates fair value due to the short maturity of those instruments. The project financing loan
payable and the working capital loan payable are variable interest rate loans and, based on the borrowing rates currently available to the Partnership for long-term debt with similar terms
and maturities, the carrying amount of these loans approximates fair value.

Inventory

The Partnership's inventory consists of spare parts, materials and supplies and is valued at the lower of average cost or market.

Income Taxes

Income taxes are not recorded by the Partnership since the net income or loss allocated to the partners is included in their respective income tax returns.

3. LOAN AND CREDIT AGREEMENT

On December 1, 1992, the Partnership entered into a Loan and Credit Agreement (the Agreement) with several banks for a combination of commitments,
including a recurring $5 million short-term working capital loan, to extend loans aggregating up to $132 million (the Commitment). The Commitment of the banks to extend loans
will be reduced on dates and by amounts specified in the Agreement through December 1, 2004 unless terminated earlier as provided for in the Agreement. The
short-term working capital loan must be fully repaid for at least thirty consecutive days per year, but may be re-borrowed through December 1, 2004 unless terminated
earlier. The Agreement places certain restrictions on capital distributions and permitted investments and further provides, among other things, that the Partnership pay a 0.375 percent
commitment fee on the average daily balance of the unused portion of the Commitment. Amounts outstanding under the Agreement bear interest at the current Eurodollar market rate plus
1.30 percent and 1.30 percent in 2002 and 2001 (unaudited), respectively, or at the base rate, per annum. The interest rate on the outstanding loan balances at December 31, 2002
and 2001 was 1.43 percent and 3.53 percent, respectively. Substantially all of the assets of the Partnership are pledged as collateral for the Agreement. Interest is payable periodically
throughout the year, as defined in the Agreement. The loan balance is payable in quarterly installments, with the final payment due on December 1, 2004. The debt paydown schedule, based upon
the amount borrowed, at December 31, 2002 is as follows:

2003

$
18,684,3002004


13,724,400$
32,408,700


Throughout
the term of the Agreement, the Partnership is required to maintain in an escrow account an amount equal to six months' interest expense, computed at ten percent of the
aggregate

283

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balance outstanding. The balance of the escrow account as of December 31, 2002 and 2001 (unaudited) was $1,620,435 and $2,272,165, respectively.

4. RELATED-PARTY TRANSACTIONS

Construction, Operating and Other Costs

Edison, Equilon, and ChevronTexaco as well as their affiliates and subsidiaries are reimbursed for design, construction, operation and other costs incurred on
behalf of the Partnership. The amounts
incurred by Edison, Equilon, ChevronTexaco and their affiliates and subsidiaries for 2002, 2001 and 2000, which are not disclosed elsewhere, were as follows:

|                               |  | 2002 |           | 2001 |   | 2000     
|------------------------------ |  | ---- | --------- | ---- | - | ---------
|
|Equilon and subsidiaries       |  | $    | 141,703   |      | $ | 155,789  
|ChevronTexaco and subsidiaries |  | $    | 1,281,457 |      | $ | 1,281,035

Land Lease

The Partnership entered into a 20-year land lease with ChevronTexaco on January 3, 1991 which has been assigned to Equilon. Costs incurred
under the land lease for 2002 and 2001 were nominal.

Fuel Sales and Purchase Agreements

The Partnership has entered into long-term agreements for the purchase of fuel with TM Star Fuel Company (TM Star), a general partnership between
Texaco Cogeneration Fuel Company, an indirect wholly owned subsidiary of ChevronTexaco, and Southern Sierra Gas Company, an affiliate of Edison.

The
daily contract quantity available under the TM Star agreement is 20,500 MMBtu per day. The price paid for gas under this contract consists of a transportation charge and a commodity
charge, per MMBtu. Beginning January 1, 1993, the price paid for the commodity charge was $2.05 per MMBtu adjusted annually by the Gross Domestic Product Implicit Deflator (GDP), as defined
($2.44 per MMBtu as of December 31, 2002). The agreement also requires the Partnership to pay for the shortfall between the price received by TM Star and the contracted price of this agreement
for any volume of
gas, up to the daily contract quantity, not nominated by the Partnership. This agreement terminates on the earlier of December 31, 2011, the term of the power purchase agreement (see
Note 5), or the written mutual consent of the parties. The agreement may be extended thereafter, on a yearly basis, upon mutual written consent. The amounts incurred under this agreement were
$20,782,402, $21,896,518 and $20,345,704 for 2002, 2001 (unaudited) and 2000 (unaudited), respectively.

As
mentioned in Footnote 2 to these financial statements, the TM Star agreement is accounted for as a cash flow hedge. The fair value of the TM Star agreement is reflected as a Gas
Purchase Agreement at Fair Value in the accompanying balance sheet. Amounts deferred in accumulated other comprehensive income are reclassified into earnings as fuel is purchased under the TM Star
agreement. $14,228,312 and $847,462 of income representing hedge ineffectiveness was recorded as a reduction of plant and other operating expenses during the years ended December 31, 2002 and
2001 (unaudited), respectively. It is expected that within the next twelve months, gains of approximately $2,000,000 will be

284

---

reclassified from accumulated other comprehensive income to earnings. The movements of accumulated other comprehensive income during the years ended December 31, 2001 and 2002 were as follows:

|Balance as of December 31, 2000 (unaudited)                              |  | $ |           |  
|------------------------------------------------------------------------ |  | - | ---------- | -
|Cumulative effect on prior years of change in accounting for derivatives |  |   | 24,584,225 |  
|Unrealized holding loss arising during the period                        |  |   | (4,524,630 | )
|Reclassification adjustment included in net income                       |  |   | (2,793,717 | )
|                                                                         |  |   |           
|Balance as of December 31, 2001 (unaudited)                              |  |   | 17,265,878 |  
|Unrealized holding loss arising during the period                        |  |   | (957,635   | )
|Reclassification adjustment included in net income                       |  |   | (1,787,741 | )
|                                                                         |  |   |           
|Balance as of December 31, 2002                                          |  | $ | 14,520,502 |  
|                                                                         |  |   |           

Due
to the significant increase in natural gas prices at the end of 2000 and beginning of 2001, the Partnership requested that TM Star re-market a portion of the natural gas
it had under contract on the spot market. During December 2000 and January 2001, the Partnership received 80% of net profits from the re-marketing of the natural gas, after
deduction of selling costs due to TM Star. Due to the sale of a portion of the natural gas, the Partnership replaced such raw material needs with low sulphur
distillate fuel purchases from Equilon, which totaled $2,576,388 and $6,079,143 during the year ended December 31, 2001 (unaudited) and 2000 (unaudited).

The
Equilon Refinery Fuels Supply Agreement provides for a firm supply of manufactured refinery gas (MRG) from PSR to the Partnership. The Partnership must accept a minimum daily
delivery of 10,000 MMBtu per day of MRG from Equilon in preference to other fuels. Additional interruptible MRG may be supplied at various volume tiers up to a final tier for total volumes over 16,000
MMBtu per day all as defined in the agreement. The pricing of MRG is based upon the weighted averages of the gas costs to the Partnership with discount factors applying to the various tiers, all as
defined in the agreement. This agreement terminates on the earlier of December 31, 2011 or the mutual written consent of the parties. The amounts incurred under this agreement were $11,874,950,
$11,121,031 (excluding Low Sulphur Distillate fuel purchases) and $9,365,674 for 2002, 2001 (unaudited) and 2000 (unaudited), respectively.

Under
typical operating conditions, approximately 80 percent of the Partnership's gas needs are procured under the aforementioned fixed price gas contracts. Fluctuations in the
prices paid for gas under these contracts are implicitly tied to the revenues received for either power or steam. The Partnership purchases the remaining 20 percent of its gas needs on the spot
market and thus may be exposed, in the short term, to fluctuations in the price of natural gas.

Operation and Maintenance Agreement

The Partnership has an agreement with Equilon, whereby Equilon shall perform all operation and routine running maintenance activities necessary for the production
of electrical energy and steam. The agreement will terminate August 20, 2012 or until terminated by either party. Equilon is paid for all costs incurred in connection with operating and
maintaining the Facility. The amounts incurred under this agreement were $1,878,005, $1,678,067 and $1,501,605 for 2002, 2001 (unaudited) and 2000 (unaudited), respectively.

285

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Steam Purchase and Sale Agreement

The Partnership has entered into an agreement with Equilon, for the sale of steam generated by the Facility. The agreement terminates upon the earlier of
December 31, 2011, or the mutual written agreement of the parties. Equilon pays the Partnership monthly for the steam delivered based upon the weighted average monthly cost of fuel gas and a
steam discount and boiler efficiency factor, as defined in the agreement. Under this agreement, the purchases by Equilon are required to be sufficient for the Partnership to meet qualifying facility
status.

5. COMMITMENTS AND CONTINGENCIES

Power Purchase Agreements

The Partnership has entered into a Power Purchase Agreement with Puget Sound Energy for each phase of the Facility. The agreement for Phase I was executed and
assigned to the Partnership on June 29, 1989. The agreement for Phase II was executed on December 27, 1990. These agreements will remain in effect until December 31, 2011. The
Partnership provides, under the Phase I agreement, up to 90 megawatts of electrical output to Puget Sound Energy. For the Phase II agreement the Partnership provides approximately 60 megawatts of
electrical output. Under Phase I and Phase II, the amount earned by the Partnership is based on the quantity of energy delivered times the sum of the individual variable rates (which are adjusted
annually by the GDP) and the respective fixed rates (which differ during the summer or winter months).

The
Phase I and II agreements contain a termination clause which, upon the occurrence of certain events, could result in the Partnership paying a termination amount, as defined in the
agreements to Puget Sound Energy. If an event of termination occurred as of December 31, 2002, the Partnership would be liable for approximately $140,190,000. Management has no reason to
believe that the project will either terminate its performance or reduce its electric power producing capability during the term of the power contract in a manner which would result in the payment of
a termination amount.

6. NEW ACCOUNTING PRONOUNCEMENTS

Statement of Financial Accounting Standards No. 143

In August 2001, the Financial Accounting Standards Board issued Statement of Financial Accounting Standard No. 143, "Accounting for Asset Retirement
Obligations," (SFAS No. 143) which became effective on January 1, 2003. SFAS No. 143 requires entities to record the fair value of a liability for an asset retirement obligation
in the period in which it is incurred. When the liability is initially recorded, the entity capitalizes a cost by increasing the carrying amount of the related long-lived asset. Over time,
the liability is increased to its present value each period, and the capitalized cost is depreciated over the useful life of the related asset. Upon settlement of the liability, an entity either
settles the obligation for its recorded amount or incurs a gain or loss upon settlement. March Point does not expect the adoption of SFAS No. 143 to have a material impact on its financial
statements.

286

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Statement of Financial Accounting Standards Interpretation No. 46

In January 2003, the Financial Accounting Standards Board issued Statement of Financial Accounting Standards Interpretation No. 46, "Consolidation
of Variable Interest Entities" (FIN 46). This interpretation of Accounting Research Bulletin No. 51, "Consolidated Financial Statements," addresses consolidation by business enterprises of
variable interest entities. The primary objective of the interpretation is to provide guidance on the identification of, and financial reporting for, entities over which control is achieved through
means other than voting rights; such entities are known as variable-interest entities. This interpretation applies to variable interest entities created after January 31, 2003, and applies to
variable interest entities in which the Partnership holds a variable interest that it acquired before February 1, 2003, beginning July 1, 2003. The Partnership does not expect this
interpretation to have a material effect on its financial statements.

Statement of Financial Accounting Standards Interpretation No. 45

In November 2002, the Financial Accounting Standards Board issued Statement of Financial Accounting Standards Interpretation No. 45, "Guarantor's
Accounting and Disclosure Requirements for Guarantees, Including Indirect Guarantees of Indebtedness of Others." This interpretation establishes reporting requirements to be made by a guarantor about
its obligations under certain guarantees that it has issued. It also clarifies that a guarantor is required to recognize, at the inception of a guarantee, a liability for the fair value of the
obligation undertaken in issuing the guarantee. The initial recognition and initial measurement provisions of this interpretation are applicable on a prospective basis to guarantees issued or modified
after December 31, 2002. The Partnership does not expect this interpretation to have a material effect on its financial statements.

287

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REPORT OF INDEPENDENT ACCOUNTANTS

To
the Board of Directors of
EcoEléctrica Holdings, Ltd. and Subsidiaries

In
our opinion, the accompanying consolidated balance sheet and the related consolidated statements of operations, comprehensive income (loss), changes in stockholders' equity, and cash
flows present fairly, in all material respects, the financial position of EcoEléctrica Holdings, Ltd. and Subsidiaries (the "Company") as of December 31, 2002, and the
results of its operations and its cash flows for the year then ended, in conformity with accounting principles generally accepted in the United States of America. These financial statements are the
responsibility of the Company's management; our responsibility is to express an opinion on these financial statements based on our audit. We conducted our audit of these statements in accordance with
auditing standards generally accepted in the United States of America, which 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, assessing the accounting principles used and
significant estimates made by management, and evaluating the overall financial statement presentation. We believe that our audit provides a reasonable basis for our opinion.

As
further discussed in Note 2 to the accompanying financial statements, effective January 1, 2001, the Company changed its method of accounting for derivative instruments
and hedging activities in accordance with Statement of Financial Accounting Standards No. 133, "Accounting for Derivative Instruments and Hedging Activities."

PricewaterhouseCoopers
LLP

San
Juan, Puerto Rico
February 7, 2003

CERTIFIED PUBLIC ACCOUNTANTS
(OF PUERTO RICO)
License No. 216 Expires Dec. 1, 2004
Stamp 1838523 of the P.R. Society of
Certified Public Accountants has been
affixed to the file copy of this report

288

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ECOELÉCTRICA HOLDINGS, LTD. AND SUBSIDIARIES        CONSOLIDATED BALANCE SHEETS        DECEMBER 31, 2002 AND 2001

|                                           |                                                                                                     | December 31,                                                                       |                            
|------------------------------------------ | --------------------------------------------------------------------------------------------------- | ---------------------------------------------------------------------------------- | ---------------------------
|
|
|
|Assets                                     |                                                                                                     |                                                                                    |                            
|Current Assets                             |                                                                                                     |                                                                                    |                            
|                                           | Cash and cash equivalents                                                                           |                                                                                    | $                          
|                                           | Current portion of restricted cash                                                                  |                                                                                    |                            
|                                           | Receivables:                                                                                        |                                                                                    |                            
|                                           |                                                                                                     | Trade, net of allowance for doubtful accounts of $5,698 in 2002 and $3,467 in 2001 |                            
|                                           |                                                                                                     | Insurance claim                                                                    |                            
|                                           |                                                                                                     | Other, including amounts due from affiliates of $119 in 2002                       |                            
|                                           | Inventories                                                                                         |                                                                                    |                            
|                                           | Prepaid expenses                                                                                    |                                                                                    |                            
|                                           |                                                                                                     |                                                                                    |                            
|                                           |                                                                                                     |                                                                                    | Total current assets       
|                                           |                                                                                                     |                                                                                    |                            
|Noncurrent Assets                          |                                                                                                     |                                                                                    |                            
|                                           | Restricted cash                                                                                     |                                                                                    |                            
|                                           | Note and interest receivable from Puerto Rico Electric Power Authority                              |                                                                                    |                            
|                                           | Property, plant and equipment, net                                                                  |                                                                                    |                            
|                                           | Debt issue cost, net                                                                                |                                                                                    |                            
|                                           | Deferred tax asset                                                                                  |                                                                                    |                            
|                                           |                                                                                                     |                                                                                    |                            
|                                           |                                                                                                     |                                                                                    | Total noncurrent assets    
|                                           |                                                                                                     |                                                                                    |                            
|Total Assets                               |                                                                                                     | $                                                                                  | 802,666                    
|                                           |                                                                                                     |                                                                                    |                            
|Liabilities and Stockholder's Equity       |                                                                                                     |                                                                                    |                            
|Current Liabilities                        |                                                                                                     |                                                                                    |                            
|                                           | Current portion of loans payable                                                                    |                                                                                    | $                          
|                                           | Accounts payable and accrued liabilities                                                            |                                                                                    |                            
|                                           | Fair value of interest rate swap agreements                                                         |                                                                                    |                            
|                                           |                                                                                                     |                                                                                    |                            
|                                           |                                                                                                     |                                                                                    | Total current liabilities  
|                                           |                                                                                                     |                                                                                    |                            
|Long-Term Liabilities                      |                                                                                                     |                                                                                    |                            
|                                           | Working capital facilities                                                                          |                                                                                    |                            
|                                           | Loans payable                                                                                       |                                                                                    |                            
|                                           | Deferred tax liability                                                                              |                                                                                    |                            
|                                           | Subordinated notes and accrued interest payable to affiliates                                       |                                                                                    |                            
|                                           | Fair value of interest rate swap agreements                                                         |                                                                                    |                            
|                                           |                                                                                                     |                                                                                    |                            
|                                           |                                                                                                     |                                                                                    | Total long-term liabilities
|                                           |                                                                                                     |                                                                                    |                            
|Total Liabilities                          |                                                                                                     |                                                                                    | 776,068                    
|                                           |                                                                                                     |                                                                                    |                            
|Commitments and contingencies (Note 17)    |                                                                                                     |                                                                                    |                            
|Stockholders' Equity                       |                                                                                                     |                                                                                    |                            
|                                           | Common stock, Class A, $.01 par value, 500,000 shares authorized, 100 shares issued and outstanding |                                                                                    |                            
|                                           | Common stock, Class B, $.01 par value, 500,000 shares authorized, 100 shares issued and outstanding |                                                                                    |                            
|                                           | Additional paid-in capital                                                                          |                                                                                    |                            
|                                           | Accumulated other comprehensive loss, net of deferred income tax of $5,704 in 2002                  |                                                                                    |                            
|                                           | Retained earnings                                                                                   |                                                                                    |                            
|                                           |                                                                                                     |                                                                                    |                            
|Total Stockholders' Equity                 |                                                                                                     |                                                                                    | 26,598                     
|                                           |                                                                                                     |                                                                                    |                            
|Total Liabilities and Shareholder's Equity |                                                                                                     | $                                                                                  | 802,666                    
|                                           |                                                                                                     |                                                                                    |                            

The accompanying notes are an integral part of these financial statements

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ECOELÉCTRICA HOLDINGS, LTD. AND SUBSIDIARIES        CONSOLIDATED STATEMENTS OF OPERATIONS        FOR THE YEARS ENDED DECEMBER 31, 2002, 2001 AND 2000

|                                                    |                                             | Years Ended December 31, |        
|--------------------------------------------------- | ------------------------------------------- | ------------------------ | -------
|
|
|
|Revenues                                            |                                             | $                        | 244,432
|Cost and operating expenses:                        |                                             |                          |        
|                                                    | Liquefied petroleum gas (LPG)               |                          |        
|                                                    | Liquefied natural gas (LNG)                 |                          |        
|                                                    | Fuel oil No. 2                              |                          |        
|                                                    | Depreciation and amortization               |                          |        
|                                                    | Salaries and related benefits               |                          |        
|                                                    | Technical and professional support          |                          |        
|                                                    | Repairs and maintenance                     |                          |        
|                                                    | Utilities and communication                 |                          |        
|                                                    | Provision for doubtful accounts             |                          |        
|                                                    | Insurance                                   |                          |        
|                                                    | Operations, maintenance and fuel management |                          |        
|                                                    | Taxes other than income                     |                          |        
|                                                    | LPG storage and service                     |                          |        
|                                                    | Administrative services                     |                          |        
|                                                    | Other operating expenses                    |                          |        
|                                                    |                                             |                          |        
|                                                    |                                             |                          | 183,427
|                                                    |                                             |                          |        
|Operating income                                    |                                             |                          | 61,005 
|                                                    |                                             |                          |        
|Other (income) expense:                             |                                             |                          |        
|                                                    | Interest expense                            |                          |        
|                                                    | Interest income                             |                          |        
|                                                    | Other expense                               |                          |        
|                                                    |                                             |                          |        
|                                                    |                                             |                          | 49,160 
|                                                    |                                             |                          |        
|Income (loss) before income tax (provision) benefit |                                             |                          | 11,845 
|Deferred income tax (provision) benefit             |                                             |                          | (1,209 
|                                                    |                                             |                          |        
|Net income (loss)                                   |                                             | $                        | 10,636 
|                                                    |                                             |                          |        

The
accompanying notes are an integral part of these financial statements

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ECOELÉCTRICA HOLDINGS, LTD. AND SUBSIDIARIES        CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (LOSS)        FOR THE YEARS ENDED DECEMBER 31, 2002, 2001 AND 2000

|                            |                                                                                                                | Years Ended December 31,                                      |        
|--------------------------- | -------------------------------------------------------------------------------------------------------------- | ------------------------------------------------------------- | -------
|
|
|
|Net Income                  |                                                                                                                | $                                                             | 10,636 
|Other comprehensive loss:   |                                                                                                                |                                                               |        
|                            | Cumulative effect on prior years of change in the method of accounting for interest rate protection agreements |                                                               |        
|                            | Loss on interest rate protection agreements, net of deferred income tax of $5,704 in 2002:                     |                                                               |        
|                            |                                                                                                                | Unrealized holding loss arising during 2002                   |        
|                            |                                                                                                                | Reclassification adjustment for losses included in net income |        
|                            |                                                                                                                |                                                               |        
|                            |                                                                                                                |                                                               | (45,720
|                            |                                                                                                                |                                                               |        
|Comprehensive (loss) income |                                                                                                                | $                                                             | (35,084
|                            |                                                                                                                |                                                               |        

The
accompanying notes are an integral part of these financial statements

291

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ECOELÉCTRICA HOLDINGS, LTD. AND SUBSIDIARIES        CONSOLIDATED STATEMENTS OF CHANGES IN STOCKHOLDERS' EQUITY        FOR THE YEARS ENDED DECEMBER 31, 2002, 2001 AND 2000

|                                         |                                                                                                                     | Common
Stock
Class A
Shares |   | Common
Stock
Class A
Amount |   | Common
Stock
Class B
Shares |     | Class B
Amount |   | Additional
Paid-in
Capital |   | Retained
Earnings |        | Accumulated
Other
Comprehensive
Loss |   | Total  |       
|---------------------------------------- | ------------------------------------------------------------------------------------------------------------------- | --------------------------- | - | --------------------------- | - | --------------------------- | --- | -------------- | - | -------------------------- | - | ----------------- | ------ | ------------------------------------ | - | ------ | ------
|
|Balance at January 1, 2000 (unaudited)   |                                                                                                                     | 100                         |   | $                           |  |                             | 100 |                | $ |                           |   | $                 | 67,000 |                                      | $ | (1,197 | )     
|                                         | Net loss                                                                                                            |                             |  |                             |   |                            |     |               |   |                            |  |                   |        |                                     |   |        | (5,023
|                                         |                                                                                                                     |                             |   |                             |   |                             |     |                |   |                            |   |                   |        |                                      |   |        |       
|Balance at December 31, 2000 (unaudited) |                                                                                                                     | 100                         |   |                             |  |                             | 100 |                |   |                           |   |                   | 67,000 |                                      |   | (6,220 | )     
|                                         | Net loss                                                                                                            |                             |  |                             |   |                            |     |               |   |                            |  |                   |        |                                     |   |        | 30,961
|                                         | Cumulative effect to January 1, 2001, of change in the method of accounting for interest rate protection agreements |                             |   |                             |   |                             |     |                |   |                            |   |                   |        |                                      |   |        |       
|                                         | Loss on interest rate protection agreements                                                                         |                             |  |                             |   |                            |     |               |   |                            |  |                   |        |                                     |   |        |      
|                                         |                                                                                                                     |                             |   |                             |   |                             |     |                |   |                            |   |                   |        |                                      |   |        |       
|Balance at December 31, 2001 (unaudited) |                                                                                                                     | 100                         |   |                             |  |                             | 100 |                |   |                           |   |                   | 67,000 |                                      |   | 24,741 |       
|                                         | Net income                                                                                                          |                             |  |                             |   |                            |     |               |   |                            |  |                   |        |                                     |   |        | 10,636
|                                         | Loss on interest rate protection agreements, net of tax of $5,704                                                   |                             |  |                             |   |                            |     |               |   |                            |  |                   |        |                                     |   |        |      
|                                         |                                                                                                                     |                             |   |                             |   |                             |     |                |   |                            |   |                   |        |                                      |   |        |       
|Balance at December 31, 2002             |                                                                                                                     | 100                         |   | $                           |  |                             | 100 |                | $ |                           |   | $                 | 67,000 |                                      | $ | 35,377 |       
|                                         |                                                                                                                     |                             |   |                             |   |                             |     |                |   |                            |   |                   |        |                                      |   |        |       

The accompanying notes are an integral part of these financial statements

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ECOELÉCTRICA HOLDINGS, LTD. AND SUBSIDIARIES        CONSOLIDATED STATEMENTS OF CASH FLOWS        FOR THE YEARS ENDED DECEMBER 31, 2002, 2001 AND 2000

|                                                                                  |                                                    | Years Ended December 31, |        
|--------------------------------------------------------------------------------- | -------------------------------------------------- | ------------------------ | -------
|
|
|Cash flow from operating activities:                                              |                                                    |                          |        
|                                                                                  | Net income                                         |                          | $      
|                                                                                  |                                                    |                          |        
|Adjustments to reconcile net income to net cash provided by operating activities: |                                                    |                          |        
|                                                                                  | Depreciation and amortization                      |                          |        
|                                                                                  | Provision for doubtful accounts                    |                          |        
|                                                                                  | Deferred income tax provision                      |                          |        
|Changes in operating assets and liabilities that increase (decrease) cash:        |                                                    |                          |        
|                                                                                  | Receivables                                        |                          |        
|                                                                                  | Inventories                                        |                          |        
|                                                                                  | Prepaid expenses                                   |                          |        
|                                                                                  | Accounts payable and accrued liabilities           |                          |        
|                                                                                  | Subordinated accrued interest payable              |                          |        
|                                                                                  |                                                    |                          |        
|                                                                                  |                                                    |                          | 8,998  
|                                                                                  |                                                    |                          |        
|Net cash provided by (used in) operating activities                               |                                                    |                          | 19,634 
|                                                                                  |                                                    |                          |        
|Cash flow from investing activities:                                              |                                                    |                          |        
|                                                                                  | Capital expenditures                               |                          |        
|                                                                                  | Restricted cash                                    |                          |        
|                                                                                  |                                                    |                          |        
|Net cash used in investing activities                                             |                                                    |                          | (15,462
|                                                                                  |                                                    |                          |        
|Cash flow from financing activities:                                              |                                                    |                          |        
|                                                                                  | Payments of principal on loans payable             |                          |        
|                                                                                  | Payments of principal on subordinated debt         |                          |        
|                                                                                  | Draws on loans payable                             |                          |        
|                                                                                  | Draws on working capital facilities                |                          |        
|                                                                                  | Payments on working capital facilities             |                          |        
|                                                                                  | Debt issue costs                                   |                          |        
|                                                                                  | Capital contribution from shareholders             |                          |        
|                                                                                  |                                                    |                          |        
|Net cash (used in) provided by financing activities                               |                                                    |                          | (11,043
|                                                                                  |                                                    |                          |        
|Net (decrease) increase in cash and cash equivalents                              |                                                    |                          | (6,871 
|Cash and cash equivalents, beginning of the year                                  |                                                    |                          | 16,896 
|                                                                                  |                                                    |                          |        
|Cash and cash equivalents, end of the year                                        |                                                    | $                        | 10,025 
|                                                                                  |                                                    |                          |        
|Supplemental cash flow information:                                               |                                                    |                          |        
|                                                                                  | Interest paid (net of $13,598 capitalized in 2000) |                          | $      
|                                                                                  |                                                    |                          |        
|                                                                                  | Income tax paid                                    |                          | $      
|                                                                                  |                                                    |                          |        

The
accompanying notes are an integral part of these financial statements

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ECOELÉCTRICA HOLDINGS, LTD. AND SUBSIDIARIES        NOTES TO CONSOLIDATED FINANCIAL STATEMENTS        DECEMBER 31, 2002, 2001 (UNAUDITED) AND 2000 (UNAUDITED)

1. Organization

EcoElectrica Holdings, Ltd. (Holdings) is a Cayman Islands company that was formed to be the 99% limited partner of EcoElectrica, L.P. (the "Partnership")
and to own 100% of EcoElectrica, Ltd., a Cayman Islands company, which is the 1% general partner of EcoElectrica, L.P. Holdings is 50% owned by Edison Mission Energy del Caribe, a Cayman
Islands company limited by shares and an indirect wholly-owned subsidiary of Edison Mission Energy (EME), a California corporation, which is in turn wholly-owned by Edison International, and 50% owned
by Buenergia Gas & Power Ltd., a Cayman Islands company limited by shares, which in turn in wholly-owned by Enron Corp. (Enron), an Oregon corporation.

The
Partnership, a development stage enterprise until March 21, 2000, is a Bermuda limited partnership formed on August 10, 1994, to develop, design, finance, construct,
own and operate a combined-cycle natural gas-fired cogeneration facility of approximately 507 megawatts, a liquefied natural gas (LNG) import terminal and storage facility, a desalination
facility and other auxillary assets (the Plant) in the Commonwealth of Puerto Rico. The electricity generated is sold to the Puerto Rico Electric Power Authority (PREPA), an instrumentality of the
Commonwealth of Puerto Rico, and one of the largest electric utilities in the United States and its territories, among municipal electric utilities.

The
Power Plant (Phase I) was completed on March 14, 2000 and effective March 21, 2000, the Partnership commenced commercial operations. The LNG Terminal (Phase
II) was completed on August 11, 2000.

2. Summary of Significant Accounting Policies

The following is a summary of the accounting policies followed by Holdings in the preparation of the accompanying financial statements.

Basis of Presentation

The accompanying consolidated financial statements, which include Holdings and its subsidiaries EcoElectrica, Ltd. and the Partnership, have been prepared
in accordance with accounting principles generally accepted in the United States of America. All intercompany balances and transactions have been eliminated in consolidation.

Use of estimates

The preparation of financial statements in conformity with generally accepted accounting principles requires management to make estimates and assumptions that
affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses
during the reporting period. Actual results could differ from those estimates.

Revenue recognition

Energy revenues derived from the conversion of fuel into electricity are recognized based on actual delivery of such converted electricity, in accordance with the
power purchase contract between the Partnership and PREPA. Capacity revenues are recognized when earned.

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Fair Value of Financial Instruments

The carrying amounts of cash and cash equivalents, restricted cash, receivables and accounts payable and accrued liabilities, approximate fair value because of
the short maturity of these items. The estimated fair values of working capital facilities, loans payable and subordinated notes payable are
based on quoted market values or on current interest rates offered for similar borrowings and approximate their carrying values.

In
addition, during 2000, Holdings derived a gain of approximately $5,400,000 on an LPG commodity swap. The gain on this commodity swap was recorded as a reduction of the commodity cost
within the LPG caption of the accompanying statement of operations. No additional commodity swaps have been entered into by Holdings or its subsidiaries.

Statement of Cash Flows

For purposes of reporting cash flows, Holdings and its consolidated subsidiaries consider all highly liquid investments with original maturities of three months
or less to be cash equivalents.

Accounts Receivable

Revenue billed is recorded as a current account receivable, including amounts in dispute with PREPA. An allowance for doubtful accounts is provided for amounts in
dispute with PREPA based on management's estimate of realizability.

Inventories

Inventories are stated at the lower of cost, determined on a first-in, first-out basis or market.

Interest during Construction

Interest on borrowed funds was capitalized as part of Property, Plant and Equipment to the extent such interest was incurred on qualified capital expenditures. No
interest was capitalized during 2002 and 2001.

Debt Issue Costs

The Partnership capitalizes the costs incurred in connection with the issuance of debt. The capitalized debt issue costs are amortized over the term of the
related debt.

Property, Plant and Equipment

Property, plant and equipment are carried at cost (including capitalized interest) less accumulated depreciation and amortization. Depreciation and amortization
are provided on a straight-line basis over the estimated useful lives of the respective assets. Major maintenance expenditures (overhauls) are capitalized and depreciated using the defer
and amortize method over their estimated useful lives (the period of time from the initial overhaul to the next overhaul of same nature, 1.5-3 years) while minor maintenance is
expensed as incurred. When property is retired or sold, the cost and the related

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accumulated depreciation are removed from the accounts and any resulting gain or loss in credited or charged to operations.

Impairment of Long-Lived Assets

Holdings and its consolidated subsidiaries evaluate their long-lived assets considering continued operating losses or significant and
long-term changes in industry conditions as the primary indicators of potential impairment. An impairment is recognized when the future undiscounted cash flows of each asset is estimated
to be insufficient to recover its carrying value. If such carrying value is not recoverable, the asset is written down to estimated fair value. Considerable management judgment is necessary to
estimate future cash flows, accordingly, actual results could vary significantly from such estimates, requiring periodic revaluation based on current events or changes in circumstances. Based on these
evaluations, there were no impairment adjustments to the carrying values of assets during 2002, 2001 and 2000.

Income Tax

Holdings is treated as a limited partnership in the Cayman Islands for tax purposes and as such, is not a taxable entity in that jurisdiction. The Partnership is
a Bermuda limited partnership, and as such, is not a taxable entity in the United States. Under Puerto Rico law, the Partnership is subject to local taxation. In accounting for income tax, the
Partnership recognizes deferred tax assets and liabilities for the expected future tax consequences attributable to differences between tax basis of assets and liabilities and their reported amounts
in the financial statements. In estimating future tax consequences, it considers all expected future events other than the enactment of changes in the tax law or rates. A
valuation allowance is recognized for any deferred tax asset for which, based on management's evaluation, it is more likely that not that some portion or all of the deferred tax asset will not be
realized.

Comprehensive Income (Loss)

Comprehensive income (loss) includes net income and all changes to stockholders' equity during a period except those arising from transactions with shareholders.
In addition to net income, the Partnership recognizes cash flow hedge gains or losses arising from interest rate swaps in other comprehensive income (loss).

Changes in Accounting Principles

Effective January 1, 2001, the Partnership adopted Financial Accounting Standards Board Statement No. 133, "Accounting for Derivative Instruments
and Hedging Activities," as amended by SFAS No. 138, "Accounting for Certain Derivative Instruments and Certain Hedging Activities". The implementation of these pronouncements resulted in the
recognition of an "Accumulated Other Comprehensive Loss", a component of stockholders' equity, of approximately $11,900,000, related to interest rate swap agreements. Both, the power purchase contract
with PREPA and the LNG supply agreement with Tractebel LNG North America, LLC, formerly CABOT LNG Corporation (refer to Note 3), are considered under either the normal purchase and sales
exception under SFAS No. 138 or do not meet the definition of a derivative, therefore are accounted for on the accrual basis.

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SFAS
No. 133, as amended, requires an entity to recognize all derivatives as either assets or liabilities in the statement of financial position and to measure those instruments
at fair value. If certain conditions are met, a derivative may be specifically designated as (a) a hedge of the exposure to changes in the fair value of a recognized asset or liability or an
unrecognized firm commitment, (b) a hedge of the exposure to variable cash flows of a forecasted transaction, or (c) a hedge of the foreign currency exposure of a net investment in a
foreign operation, an unrecognized firm commitment, an available-for-sale security, or a foreign-currency-denominated forecasted transaction. The accounting for changes in the
fair value of a derivative depends on the intended use of the derivative and the resulting designation. The Partnership designated the interest rate swaps as a hedge of the cash flow from its variable
rate loans. Accordingly, the fair value of the interest rate swap agreements is presented as a liability and a component of stockholders' equity net of related deferred taxes, through "Other
Comprehensive Income (Loss)."

SFAS
No. 144 "Accounting for the Impairment or Disposal of Long-Lived Assets," was issued in August 2001. SFAS No. 144 addresses accounting and reporting
for the impairment or disposal of
long-lived assets by requiring that one accounting model be used for assets to be disposed of by sale, whether previously held and used or newly acquired, and by broadening the
presentation of discontinued operations to include more disposal transactions. This statement is effective for fiscal years beginning after June 15, 2002. Holdings adopted this pronouncement in
the first quarter of 2002. No assets have been impaired and/or disposed of as of December 31, 2002.

Recently Issued Accounting Standards

SFAS No. 143, "Accounting for Asset Retirement Obligations," was issued in June 2001. SFAS No. 143 addresses accounting and reporting for
legal obligations associated with the retirement of tangible long-lived assets and the associated asset retirement costs. This statement is effective for fiscal years beginning after
June 15, 2002. The adoption of this statement will not have a significant effect on the consolidated financial statements of Holdings.

Accounting for Costs Association with Exit or Disposal Activities.In June 2002, the FASB issued SFAS No. 146,
"Accounting for Costs Associated with Exit or Disposal Activities." SFAS No. 146 requires that a liability for a cost associated with an exit or disposal activity be recognized when the
liability is incurred. The provisions of this statement are effective for exit or disposal activities that are initiated after December 31, 2002. The adoption of this statement will not have a
significant effect on the consolidated financial statements of Holdings.

Guarantor's Accounting and Disclosure Requirements for Guarantees.In November 2002, the FASB issued interpretation
("FIN") No. 45 "Guarantees." This interpretation requires guarantor of certain types of guarantees to recognize, at the inception of the guarantee, a liability for the fair value of the
obligation undertaken in issuing the guarantee. The provisions for initial recognition are effective for guarantees that are issued or modified after December 31, 2002. The adoption of FIN
No. 45 will not have a material impact on the consolidated financial statements of Holdings.

In
January 2003, the FASB issued FIN No. 46, "Consolidation of Variable Interest Entities, an interpretation of ARB 51." This interpretation provides guidance on the
identification of entities for which control is achieved through means other than through voting rights and how to determine when

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and which entities should be consolidated. The application of this interpretation is required in all financial statements initially issued after January 31, 2003. The adoption of FIN
No. 46 will not have any impact on the consolidated financial statements of Holdings.

Reclassifications

Certain reclassifications were made to the 2001 and 2000 financial statements to conform these with the 2002 presentation.

3. Agreements

Power Purchase Contract

On March 10, 1995, the Partnership and PREPA entered into a power purchase contract (the PPA) under which PREPA is entitled to make energy and capacity
payments to the Partnership commencing on March 21, 2000 (date in which the Partnership started commercial operations) (COD) and continuing for the 22-year term of the PPA
(operating period). Energy payments are based on the actual output of electric power from the Plant and are intended to cover fuel costs. Capacity payments are intended to cover operating and
maintenance costs, debt service, taxes and a return on investment.

The
PPA requires that the Partnership maintain a minimum working capital of $4 million on the COD, $8 million by the end of the first agreement year, $12 million by
the end of the second year and $20 million by the end of the third year and thereafter. A portion of the minimum working capital requirement should be in cash deposited in a financial
institution. The cash deposit should be reduced by any amount properly invoiced to PREPA under this agreement and not paid when due. As of December 31, 2002, amounts owed by PREPA to the
Partnership exceed the cash deposit requirements.

Energy
and capacity revenues under the PPA for the years ended December 31, 2002, 2001, and 2000 were as follows (in thousands):

2002

2001

2000Energy

$
116,500

$
101,960

$
66,427Capacity


127,932


131,477


87,943$
244,432

$
233,437

$
154,370


Construction Contracts

On October 31, 1997, the Partnership entered into an amended and restated offshore design and supply contract (the Supply Contract) with Enron Equipment
Procurement Company (Enron Procurement) and an amended and restated onshore construction contract (the Onshore Contract) with Enron Power I (Puerto Rico), Inc., both indirectly wholly owned
subsidiaries of Enron Corp. Under the Supply Contract, Enron Procurement provided concept design, engineering and procurement services, and supplied power generating equipment to the Plant outside of
Puerto Rico on fixed-price basis. Under the Onshore Contract, Enron Power I (Puerto Rico), Inc. provided detailed design, engineering and procurement services of materials sourced in Puerto
Rico, and construction services for the Plant on a fixed-price basis. Expenditures under both contracts amounted to approximately $450,000,000.

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Administrative Services Agreement

The Partnership entered into an Administrative Services Agreement as of October 31, 1997 with EME (Administrative Manger), to provide administrative and
other support services in connection with the financing, construction and operation of the Plant.

The
Partnership agreed to pay the Administrative Manager all the reimbursable costs incurred plus administrative fees of $500,000 while the Plant was under construction and $42,000 per
month
(escalating from January 1, 1997, in accordance with the Puerto Rico Consumer Price Index (CPI)) during the operating period. The Partnership incurred charges under this agreement of $876,000,
$1,386,000 and $486,000 for the years ended December 31, 2002, 2001 and 2000.

Operations, Maintenance and Fuels Management Agreement

The Partnership has entered into an Operation, Maintenance and Fuels Management Agreement dated as of October 31, 1997 (the OMF Agreement) with El Puerto
Rico Operations Inc. (OMF Manager), an indirectly wholly-owned subsidiary of Enron, for the management of the operations and maintenance of the Plant, as well as all aspects of the purchase,
transportation, delivery and storage of fuel for the Plant.

The
Partnership agreed to pay the OMF Manager certain reimbursable costs, a Phase I start-up fee of $500,000 and monthly operating and fuel management fees of $42,000 and
$29,000, respectively, (escalating from January 1, 1997, in accordance with the Puerto Rico CPI) during the operating period. The Partnership incurred charges under this agreement of
approximately $1,201,000, $885,000 and $818,000 million for the years ended December 31, 2002, 2001 and 2000, respectively.

LPG Storage and Service Agreement

The Partnership entered into a LPG Storage and Service Agreement (the Agreement) dated as of October 31, 1997, with ProCaribe Division of the Protane
Corporation (ProCaribe), an indirect wholly owned subsidiary of Enron Corp. Under the Agreement, ProCaribe will act as a terminal operator mainly providing LPG unloading, storage and redelivery
services to the Partnership. The Agreement, which term extends through December 31, 2020, sets forth an annual compensation for ProCaribe's services comprised of a base annual fee of $75,000,
payable on a monthly basis, and reimbursable incremental costs, as defined in the Agreement. The base annual fee of $75,000 will be adjusted each January 1, according to the increase in the
Puerto Rico Consumer Price Index as compared to the January 1, 1997 index. ProCaribe provided services and charged reimbursable incremental costs to EcoElectrica under the Agreement amounting
to approximately $817,000, $625,000 and $734,000 for the years ended December 31, 2002, 2001 and 2000.

In
addition, the Agreement provides for the borrowing and lending of LPG to each other. ProCaribe borrowed from the Partnership LPG amounting to approximately $2,912,000 and $2,311,000
during the years ended December 31, 2001 and 2000. During 2002 ProCaribe purchased LPG from the Partnership for approximately $118,800.

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LNG Supply Agreement

The Partnership entered into a LNG Supply Agreement with Tractebel LNG North America, LLC, (Tractebel), formerly CABOT LNG Corporation, whereby the Partnership is
committed to purchase and Tractebel committed to supply, an annual contract supply of liquefied natural gas, as stipulated in the agreement, until September 2019. Charges under this agreement
include a commodity charge on LNG supplied based on NYMEX and the Puerto Rico CPI, availability demand charges regardless of actual LNG deliveries. Commodity and demand charges from Tractebel for the
years ended December 31, 2002, 2001 and 2000, were as follows (in thousands):

2002

2001

2000Commodity

$
84,405

$
79,128

$
29,881Demand


23,893


22,790


19,964$
108,298

$
101,918

$
49,845


On
December 13, 2002, the Partnership and Tractebel signed a Letter Agreement that amended the LNG supply agreement for the year 2003 only. This Letter Agreement provides for 100%
supply of LNG to the Partnership, a five (5) cents commodity price reduction and the elimination of the commodity surcharge, all for the year 2003 only. The Lenders were duly notified and did
not oppose the execution of the agreement.

Depository Agreement

On October 31, 1997, the Partnership entered into a depository and disbursement agreement (the Depository Agreement) with a financial institution as
collateral and depository agent, whereby the depository agent will hold and administer monies deposited in the various accounts established at the
financial institution as depository bank pursuant to the Depository Agreement. As part of the Depository Agreement, besides the cash accounts, the following cash reserves are required: an interest
reserve, a principal reserve, a major maintenance reserve, a construction reserve, a distribution reserve, a collateral reserve, a guarantee reserve, an income tax reserve and a fuel supply
interruption reserve. The amounts deposited in the Interest Reserve shall be applied to pay interest expenses. The Principal Reserve is a short-term reserve funded throughout each month of
the quarter, to pay the corresponding principal installment due at the end of the quarter. The amount deposited in the Major Maintenance reserve account shall be applied to pay for expenditures by the
Partnership for regularly scheduled (or reasonably anticipated) major maintenance of the Plant. The amounts deposited in the Construction Account shall be applied to completing certain construction
punchlist items that were pending upon conversion of interim construction loans to term loans. The amounts deposited in the Distribution Reserve shall be used for payment of dividends to stockholders.
The collateral reserve is a cash deposit reserve held as collateral for increases to the PREPA Operating Security Letter of Credit. The Guarantee reserve is a cash deposit with an insurance company as
collateral for a bond in favor of PREPA that serve as a guarantee of a back feed power contract. The amounts deposited in the income tax reserve shall be applied to pay income tax. Amounts deposited
in the fuel supply interruption reserve shall be used for payment of principal and interest on the debt in case there is a business

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interruption. The fuel supply interruption reserve should increase on a quarterly basis as established in the credit agreement. As of December 31, the balances of the reserves were as follows:

|                     |                           | 2002 |        | 2001 
|-------------------- | ------------------------- | ---- | ------ | -----
|
|Current portion:     |                           |      |        |      
|                     | Interest reserve          |      | $      | 59   
|                     | Principal reserve         |      |        | 25   
|                     | Major maintenance reserve |      |        | 2,323
|                     | Construction reserve      |      |        | 1,409
|                     | Distribution reserve      |      |        | 4,490
|                     | Collateral reserve        |      |        | 2,282
|                     | Guarantee reserve         |      |        | 500  
|                     |                           |      |        |      
|                     |                           | $    | 11,088 |      
|                     |                           |      |        |      
|Non-current portion: |                           |      |        |      
|                     | Income tax reserve        |      | $      | 2,696
|                     | Fuel management reserve   |      |        | 2,485
|                     |                           |      |        |      
|                     |                           | $    | 5,181  |      
|                     |                           |      |        |      

Interest,
Principal, Major Maintenance, Construction, Distribution, Collateral and Guarantee Reserves are presented asRestricted Cashin
the current assets section of the accompanying consolidated balance sheet. The income tax and the fuel reserve are presented asRestricted Cashin the
non-current assets section.

Interest Rate Protection Agreement

The Partnership enters into interest rate swap agreements to fix the interest rates on loans payable. Interest rate swaps are agreements to exchange interest rate
payment streams based on a notional principal amount. The fair value of interest rate swaps is the estimated amount that the Partnership would receive or pay to terminate the swap agreements at the
reporting date, taking into account current interest rates and the current credit worthiness of the swap counterparties.

Under
Interest Rate Protection Agreements with ABN AMRO and Banque Paribas, the Partnership contracted a fixed interest rate of 6.385% and 6.365% over approximately 77% of its
outstanding long-term debt. The provisions of these agreements require payment by ABN AMRO and Banque Paribas to the Partnership for the excess of the current LIBOR rate over the fixed
interest rate or for the Partnership to pay ABN AMRO and Banque Paribas for the difference between the fixed interest rate and the current LIBOR rate, if the latter is lower.

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As of December 31, 2002, 2001 and 2000, the Partnership has outstanding interest rate swap agreements, with notional amount of approximately $464,421,000
(2001$471,734,000). The weighted average rate paid and received on these agreements was 6.383% and 1.90237% in 2002, 6.385% and 3.483% in 2001; and 6.385% and 6.472% in 2000,
respectively. The net interest rate differentials paid (received), recorded as adjustments to interest expense, amounted to approximately $21,287,000, $9,280,000 and ($414,000) for the years ended
December 31, 2002, 2001 and 2000. No hedge ineffectiveness has been recognized because this hedge is deemed to be 100% effective.

At
December 31, 2002, the Interest Rate Protection Agreements mature as follows:

|Counterparty   |  | Date       |  | Maturity   |  | Notional
Amount
|-------------- |  | ---------- |  | ---------- |  | ---------------
|
|ABN AMRO       |  | 10/2/2000  |  | 12/15/2017 |  | $              
|ABN AMRO       |  | 12/29/2000 |  | 3/31/2016  |  |                
|Banque Paribas |  | 12/15/1999 |  | 12/17/2017 |  |                
|Banque Paribas |  | 10/2/2000  |  | 12/15/2017 |  |                

The
fair value of the swap agreements liability at December 31, 2002 and 2001 was $81,483,000 and $30,059,000, respectively. As of December 31, 2002, the loss deferred in
accumulated other comprehensive income expected to be reclassified within the next year amounts to $23,100,000.

4. Accounts Receivable

Accounts Receivable include amounts past due from PREPA that started to accumulate since the beginning of commercial operations and continue to increase as
monthly withholdings continue to be made. There are various reasons for the withholdings by PREPA, which are rooted in the interpretations of various contract provisions. The larges amount withheld
relates to the interpretation of a base value in the Energy Payment formula. Management has been working with PREPA since the withholdings began, to achieve a successful resolution of these disputes,
but no agreement has been reached. As of December 31, 2002 $20,903,000 (2001$13,025,000) of the receivables from PREPA are under dispute for which a bad debt allowance of
$5,698,000 (2001$3,467,000) has been provided based on management's estimate of realizability.

5. Insurance Claims Receivable

During 2000, the Partnership suffered losses due to several mechanical failures of its combustion turbines. The Partnership filed claims related to year 2000
under the business interruption, property damage and builders all-risk insurance policies. An insurance claims receivable of approximately $15,700,000, was recorded as of
December 31, 2000, of which $14,000,000 were collected in 2001 and $1,700,000 were collected in 2002.

During
2001, the Partnership filed claims for an additional $10,400,000 which was collected in full in 2002.

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6. Note and Interest Receivable from PREPA

In December 1997, the Partnership made a $5,000,000 loan to PREPA (the PREPA Loan). This loan matures five years after the completion of construction and
will be repaid in a single balloon payment in October 2004. Interest is accrued at LIBOR minus 3% and paid annually. No interest income was earned in year 2002, due to the fact that the 3%
exceeded the LIBOR rate.

7. Inventories

As of December 31, inventories consist of the following (in thousands):

|                                                                             |  | 2002 |        | 2001
|---------------------------------------------------------------------------- |  | ---- | ------ | ----
|
|Liquefied natural gas (LNG)                                                  |  | $    | 5,786  |     
|Liquefied petroleum gas (LPG)                                                |  |      | 2,779  |     
|Fuel oil No. 2                                                               |  |      | 4,006  |     
|Spare parts and supplies, including $13,481, of inventory in transit in 2002 |  |      | 29,353 |     
|                                                                             |  |      |        |     
|                                                                             |  | $    | 41,924 |     
|                                                                             |  |      |        |     

8. Property, Plant and Equipment

As of December 31, property, plant and equipment consist of the following:

|                                                |  | Estimated
Useful Lives |  | 2002 |         | 2001 |  
|----------------------------------------------- |  | ---------------------- |  | ---- | ------- | ---- | -
|
|
|Machinery and equipment                         |  | 35                     |  | $    | 447,144 |      | $
|LNG and LPG facilities and equipment            |  | 2250                  |  |      | 209,039 |      |  
|Buildings                                       |  | 30                     |  |      | 18,146  |      |  
|Major maintenance expenditures                  |  | 1.53                  |  |      | 29,447  |      |  
|Fuel oil facilities                             |  | 50                     |  |      | 2,946   |      |  
|Furniture and fixtures                          |  | 10                     |  |      | 538     |      |  
|Vehicles and equipment                          |  | 3                      |  |      | 167     |      |  
|                                                |  |                        |  |      |         |      |  
|                                                |  |                        |  |      | 707,427 |      |  
|Less: Accumulated depreciation and amortization |  |                        |  |      | (66,902 | )    |  
|                                                |  |                        |  |      |         |      |  
|                                                |  |                        |  |      | 640,525 |      |  
|Land and land improvements                      |  |                        |  |      | 5,350   |      |  
|Construction in progress                        |  |                        |  |      | 1,427   |      |  
|                                                |  |                        |  |      |         |      |  
|                                                |  |                        |  | $    | 647,302 |      | $
|                                                |  |                        |  |      |         |      |  

9. Working Capital Facilities

As of December 31, 2000, the Partnership had drawn $48,000,000 under Working Capital Facilities to fund the ongoing working capital needs, primarily fuel
expenses, which are not expected to match the timing of the Partnership's revenues on a monthly basis. These facilities consist of two lines of

303

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credit of $9,000,000 and $30,000,000, respectively, payable to a financial institution and a line of credit of $9,000,000 payable to Enron LNG Power (Atlantic) Ltd., an indirectly wholly-owned
subsidiary of Enron. Both lines of credit of $9,000,000 were paid in full during 2001.

Draws
on the Working Capital facilities of $9,000,000 and $30,000,000 are subject to a borrowing base tied to the fuel inventory and receivables from PREPA. Also up to $8,000,000 can be
drawn and held in a segregated sub-account subject to lenders' lien to satisfy certain liquidity requirements in the PPA. The Working Capital facilities have an annual, five consecutive
day clean-up feature, for amounts not considered current asset loans, as defined. This clean-up feature does not apply to the $8,000,000. To the extent that the Working Capital
facilities are not refinanced or extended at its initial maturity date, $8,000,000 of Working Capital loans drawn to satisfy the PPA liquidity requirements may be amortized along with the Tranche A
loans on a pro rata basis (see Note 8). The $30,000,000 Working Capital facilities mature on June 15, 2005, has a commitment fee of 0.375%, and bears interest at LIBOR (1.8125% at
December 31, 2002) plus 1.125%.

10. Loans Payable

In December 1997, the Partnership obtained a construction/term loan facility of approximately $614,000,000. As of December 31, loans payable
comprised of the following:

|                      |                | Maturity |               | Commitment
Fee |       | Interest
Over |              | Rate
LIBOR |       | 2002 |         | 2001   
|--------------------- | -------------- | -------- | ------------- | -------------- | ----- | ------------- | ------------ | ---------- | ----- | ---- | ------- | -------
|
|Term Loans:           |                |          |               |                |       |               |              |            |       |      |         |        
|                      | Tranche A Loan |          | June 15, 2016 |                | 0.375 | %             | Construction |            | 1.125 | %    | $       | 486,325
|                      | Tranche B Loan |          | June 15, 2018 |                | 0.375 | %             | Years 15    |            | 1.375 | %    |         | 107,760
|                      |                |          |               |                |       | Years 610    |              | 1.750      | %     |      |         |        
|                      |                |          |               |                |       | Years 1116   |              | 2.000      | %     |      |         |        
|                      |                |          |               |                |       | Years 1618   |              | 2.500      | %     |      |         |        
|                      |                |          |               |                |       |               |              |            |       |      |         |        
|Total loans payable   |                |          |               |                |       |               |              |            |       |      | 594,085 |        
|Less: current portion |                |          |               |                |       |               |              |            |       |      | 18,695  |        
|                      |                |          |               |                |       |               |              |            |       |      |         |        
|                      |                |          |               |                |       |               |              |            |       | $    | 575,390 |        
|                      |                |          |               |                |       |               |              |            |       |      |         |        

As
of December 31, 2002, two installments in the amount of $4,457,000 each had been paid; future maturities of long-term debt are as follows:

|Year       |  | (In thousands)
|---------- |  | --------------
|2003       |  | $             
|2004       |  |               
|2005       |  |               
|2006       |  |               
|2007       |  |               
|Thereafter |  |               
|           |  |               
|           |  | $             
|           |  |               

304

---

The
construction loans were due 18 months after the Phase I Basic Term-Out date of June 15, 2000. The Phase I and Phase II construction loans were converted to
term loans on September 20, 2001. Quarterly amortization payments for Tranche A and Tranche B will commence in approximately 15 months and in the first quarter of the 17th
year, respectively, after the Basic Term-Out date. The balance on the loan facility was collateralized by the Partnership's assets and bears interest at LIBOR (1.40% at December 31,
2002) plus 1.750% payable quarterly.

11. Subordinated Notes Payable

EME and Enron Development Corp. (EDC), an indirectly wholly owned subsidiary of Enron, and certain of their affiliates incurred costs on behalf of the Partnership
during the construction phase. These costs are recorded as part ofProperty, plant and equipmentwith corresponding amounts recorded as Subordinated notes payableandAccrued interest payableto EME and EDC which at December 31, are
as follows:

|                                                              |  | 2002 |        | 2001
|------------------------------------------------------------- |  | ---- | ------ | ----
|
|Subordinated notes payableEdison Mission Energy              |  | $    | 20,000 |     
|Subordinated notes payableEnron Development Corp.            |  |      | 12,000 |     
|Subordinated accrued interest payableEdison Mission Energy   |  |      | 14,235 |     
|Subordinated accrued interest payableEnron Development Corp. |  |      | 7,594  |     
|                                                              |  |      |        |     
|                                                              |  | $    | 53,829 |     
|                                                              |  |      |        |     

The
notes bear interest at the lesser of 12 percent compounded quarterly or the maximum non-usurious rate of interest under New York law. These amounts are
subordinated to any amounts due under the Credit Facilities and can only be paid out of cash otherwise available for distribution to the partners. In November 8, 2002, $8,000,000 (including
interest of $5,872,000) were paid to EME and EDC.

12. Debt Service Reserve Loan Facility

The Partnership also obtained a $19 million Debt Service Reserve Loan Facility which acts as an alternative to a funded debt service reserve and is
available to fund debt service shortfalls. Any draws on the Debt Service Reserve Loan Facility will be repaid out of all excess cash flow. In the event that debt service coverage ratios in any one of
the three years prior to maturity of the Debt Service Reserve Loan Facility are less than 1.4, the facility will be fully drawn and deposited into a Debt Service Reserve Account, with the
reimbursement obligation amortized on a pro rata basis with the Tranche A facility. Thereafter, any draws on the Debt Service Reserve Account will be replenished by all excess cash flow after debt
service. The Debt Service Reserve Loan Facility matures 10 years after the completion of construction, has a commitment fee of 0.375%, bears interest at LIBOR plus 2.125% during year
15 and LIBOR plus 2.35% during years 610. As of December 31, 2002, no amounts have been drawn under this facility.

305

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13. PREPA Letter of Credit Facility

Pursuant to the terms of the PPA, the Partnership, has provided an operating security instrument after commercial operation in the form of a standby letter of
credit from a financial institution. The facility may be drawn upon only if the Plant causes a breach under the PPA, up to a maximum of approximately $15,210,000. PREPA's ability to draw on the
facility will be reduced by amounts outstanding under the PREPA Loan (see Note 5). The operating security was issued when the Plant commenced commercial operations and will mature
December 15, 2007. The obligation with PREPA to replenish any amounts drawn on the facility is due within 90 days. The obligation with the financial institution for any amounts drawn on
the facility prior to the first principal payment on the Tranche A Loan, is to repay in the same proportion and during the same periods as provided for in the Tranche A Loan amortization schedule. The
obligation with the financial institution for any amounts drawn after the first principal payment date of the Tranche A Loan is to repay based on the remaining principal payment dates with the
amortization percentage increased, on a pro rata basis, by the percentage attributable to each prior principal payment date. The facility has a commitment fee of 0.375% and bears interest at LIBOR
plus 1.125% during years 15 of operations and LIBOR plus 1.375% during years 610 of operations. As of December 31, 2002, no amounts were outstanding under this
facility.

The
Partnership is also required, pursuant to the terms of the PPA, to increase the letter of credit at a compound annual escalation rate of 7% throughout the remainder of the facility.
However, as long as the Partnership achieves certain goals, no further escalation shall apply. As of December 31, 2002, the letter of credit issued has been escalated to approximately
$12,414,000 (net of the $5 million note receivable from PREPA), for which $2,233,000 was posted as cash collateral which is presented, including interest, as non-current Restricted Cashin the
accompanying consolidated balance sheet at December 31, 2002.

14. Fuel Performance Letter of Credit Facility

Pursuant to the terms of the LNG Sales Contract entered into between Tractebel and the Partnership, the Partnership is required to purchase certain fuel
requirements of the Plant from Tractebel. The Partnership, as required, has provided a standby letter of credit from a financial institution to Tractebel. The $30 million facility will mature
December 15, 2007, has a commitment fee of 0.375%, bears interest at LIBOR plus 1.0% during construction, LIBOR plus 1.125% during years 15 of operations and LIBOR plus 1.375%
during years 68 of operations. This facility will be used to secure the Partnership's ongoing liabilities to Tractebel in connection with periodic LNG purchases. As fuel expenses are the
first expenses paid out of the Plant's operating account, the facility is not expected to be drawn. However, if drawn, reimbursement obligations will be due within 5 days and will be paid out
of the operating account in the same priority order as fuel expenses. As of December 31, 2002, no amounts have been drawn under this facility.

15. Income Tax

The Partnership is partially exempt from Puerto Rico income and property taxes under the provision of the Puerto Rico Industrial Incentives Act of 1987, as
amended. This grant is effective for the twenty taxable years succeeding the year of commencement of commercial operations, and provides for a 7% flat rate for income tax and a 90% exemption from
property taxes. Pursuant to the grant's provision, the Partnership shall have the option to deduct the total costs incurred after January 1, 1998,

306

---

in the purchase, acquisition, construction, and/or installation of facilities to be utilized in the cogeneration plant in the taxable year that the cost is incurred. The excess of this deduction over
the Partnership's industrial development income (IDI) subject to the 7% tax rate for the taxable year in which the costs were incurred may be carried forward to offset such IDI in subsequent taxable
years, until exhausted. As a result of this deduction, the Partnership's did not incur in a current income tax liability in 2002, 2001 and 2000. A deferred tax liability has been recognized for this
deduction.

The
Partnership's effective tax rate differs from the applicable Puerto Rico statutory income tax rate due to the following:

|                                                            |  | 2002
Amount |        | 2002
% |       | 2001
Amount |   | 2001
%  |   | 2000
Amount |   | 2000
% |       
|----------------------------------------------------------- |  | ----------- | ------ | ------ | ----- | ----------- | - | ------- | - | ----------- | - | ------ | ------
|
|Income tax benefit (provision) at the statutory rate of 39% |  | $           | (4,620 | )      | (39.0 | )           | $ | (12,826 | ) | (39.0       | ) | $      | 4,342 
|Exemption on industrial development income                  |  |             | 3,790  |        | 32.0  |             |   | 10,524  |   | 32.0        |   |        | (3,563
|Other                                                       |  |             | (379   | )      | (3.2  | )           |   | 376     |   | 1.1         |   |        | (91   
|                                                            |  |             |        |        |       |             |   |         |   |             |   |        |       
|Income tax benefit (provision)                              |  | $           | (1,209 | )      | (10.2 | )           | $ | (1,926  | ) | (5.9        | ) | $      | 688   
|                                                            |  |             |        |        |       |             |   |         |   |             |   |        |       

The
components of deferred income tax liabilities or assets as of December 31, 2002, is as follows (in thousands):

|                                   |                                     | 2002                       |   | 2001   |       
|---------------------------------- | ----------------------------------- | -------------------------- | - | ------ | ------
|
|Deferred tax (liabilities) assets: |                                     |                            |   |        |       
|                                   | Construction and installation costs |                            | $ | (2,755 | )     
|                                   | Allowance for doubtful accounts     |                            |   | 399    |       
|                                   |                                     |                            |   |        |       
|                                   |                                     | Net deferred tax liability |   | $      | (2,356
|                                   |                                     |                            |   |        |       

The
deferred tax asset of $5,704 at December 31, 2002 relates exclusively to the other comprehensive loss.

16. Savings Plan

Effective January 1, 1999, the Partnership established a savings plan for all eligible non-union employees of the Partnership. Participants may
contribute from 1% to 10% of their annual pre-tax compensation up to a maximum of $8,000. The Partnership's matching contribution is 50% of the first 6% of a participant's annual
contribution. Effective January 1, 2002, the Partnership agreed with the United Steel Workers of America to establish a savings plan for all eligible union employees with substantially the same
provisions as the non-union plan. The Partnership's contribution to these plans during 2002, 2001 and 2000 amounted to approximately $54,000, $41,000 and $62,500, respectively, which is
expensed as salaries and related benefits.

307

---

17. Commitments and Contingencies

In addition to the commitments and contingencies disclosed in the other notes to the accompanying financial statements, following are some related leases and to
legal and administrative procedures.

Leases

The Partnership leases its administrative office facilities under an operating lease agreement expiring in August 2006. During 2002, 2001 and 2000, rental
expense was approximately $123,000, $110,000 and $90,000, respectively, including basic rent plus a proportionate share of taxes, operating and maintenance expenses.

Future
minimum annual lease payments are as follows (in thousands):

Year

Amount2003

$
802004


802005


802006


54$
294


Contingencies

During March 2000, the United States Environmental Protection Agency (the EPA) issued a Notice of Violation (NOV) and a Compliance Order (CO) to the
Partnership in connection with alleged violations of the Clean Air Act. The Partnership is currently working with the EPA to address those issues and does not believe the NOV or CO will have a
material adverse effect on its financial position or results of operations.

The
Partnership is involved in various other legal and administrative actions, generally related to its operations. Management believes that, based on advice from legal counsel, the
outcome of such actions will not have a material adverse effect on the financial position or results of operations of the Partnership.

308

---



REPORT OF INDEPENDENT ACCOUNTANTS

To
the Management Committee of
Gordonsville Energy, L.P.:

In
our opinion, the accompanying balance sheet as of December 31, 2002 and the related statements of income and comprehensive income, partners' equity, and cash flows present
fairly, in all material respects, the financial position of Gordonsville Energy, L.P. (a Delaware limited partnership) at December 31, 2002, and the results of its operations and its cash flows
for the year then ended in conformity with accounting principles generally accepted in the United States of America. These financial statements are the responsibility of the Partnership's management;
our responsibility is to express an opinion on these financial statements based on our audit. We conducted our audit of these statements in accordance with auditing standards generally accepted in the
United States of America, which 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, assessing the accounting principles used and significant estimates made by management, and
evaluating the overall financial statement presentation. We believe that our audit provides a reasonable basis for our opinion.

As
explained in Note 2 to the financial statements, effective January 1, 2001, Gordonsville Energy, L.P. changed its method for accounting for major maintenance costs from
"accrue in advance" method to expensing the costs as they are incurred and as explained in Note 3 effective January 1, 2001, Gordonsville Energy, L.P. adopted and implemented Statement
of Financial Accounting Standards No. 133 and No. 138 related to the accounting for derivatives.

PricewaterhouseCoopers
LLP

Los
Angeles, California
March 14, 2003

309

---



GORDONSVILLE ENERGY, L.P.        BALANCE SHEETS        DECEMBER 31, 2002 AND 2001 (UNAUDITED)

|                                        |                                    | 2002                                   |             | 2001      
|--------------------------------------- | ---------------------------------- | -------------------------------------- | ----------- | ----------
|
|Assets                                  |                                    |                                        |             |           
|Current assets:                         |                                    |                                        |             |           
|                                        | Cash and cash equivalents          |                                        | $           | 2,798,660 
|                                        | Accounts receivable                |                                        |             | 7,379,907 
|                                        | Inventory                          |                                        |             | 3,834,235 
|                                        | Prepaid and other                  |                                        |             | 427,869   
|                                        |                                    |                                        |             |           
|                                        |                                    | Total current assets                   |             |           
|                                        |                                    |                                        |             |           
|Property, plant and equipment, net      |                                    |                                        | 140,873,103 |           
|Other assets:                           |                                    |                                        |             |           
|                                        | Deferred financing costs, net      |                                        |             | 2,724,497 
|                                        | Debt service reserves              |                                        |             | 10,335,835
|                                        |                                    |                                        |             |           
|                                        |                                    | Total assets                           |             | $         
|                                        |                                    |                                        |             |           
|Liabilities and Partners' Equity        |                                    |                                        |             |           
|Current liabilities:                    |                                    |                                        |             |           
|                                        | Current portion of long-term debt  |                                        | $           | 13,477,860
|                                        | Accounts payable                   |                                        |             | 1,594,582 
|                                        | Interest payable                   |                                        |             | 587,141   
|                                        | Liability under interest rate swap |                                        |             | 8,868,554 
|                                        |                                    |                                        |             |           
|                                        |                                    | Total current liabilities              |             |           
|Long-term debt, net of current portion  |                                    |                                        | 80,540,434  |           
|                                        |                                    |                                        |             |           
|                                        |                                    | Total liabilities                      |             |           
|                                        |                                    |                                        |             |           
|Commitments and contingencies (Note 10) |                                    |                                        |             |           
|Partners' equity                        |                                    |                                        | 63,305,535  |           
|                                        |                                    |                                        |             |           
|                                        |                                    | Total liabilities and partners' equity |             | $         
|                                        |                                    |                                        |             |           

The
accompanying notes are an integral part of these financial statements.

310

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GORDONSVILLE ENERGY, L.P.        STATEMENTS OF INCOME AND COMPREHENSIVE INCOME        FOR THE YEARS ENDED DECEMBER 31, 2002, 2001 (UNAUDITED) AND 2000 (UNAUDITED)

|                                                                                     |                                   | 2002                        |            | 2001       |            | 2000      
|------------------------------------------------------------------------------------ | --------------------------------- | --------------------------- | ---------- | ---------- | ---------- | ----------
|
|Revenues:                                                                            |                                   |                             |            |            |            |           
|                                                                                     | Sales of capacity and electricity |                             | $          | 40,296,940 |            | $         
|                                                                                     | Sales of steam                    |                             |            | 9,997      |            |           
|                                                                                     | Interest income                   |                             |            | 311,416    |            |           
|                                                                                     |                                   |                             |            |            |            |           
|                                                                                     |                                   | Total revenues              |            |            | 40,618,353 |           
|                                                                                     |                                   |                             |            |            |            |           
|Expenses:                                                                            |                                   |                             |            |            |            |           
|                                                                                     | Operations and maintenance        |                             |            | 12,611,865 |            |           
|                                                                                     | General and administrative        |                             |            | 3,191,946  |            |           
|                                                                                     | Depreciation and amortization     |                             |            | 7,181,522  |            |           
|                                                                                     | Interest expense                  |                             |            | 7,677,463  |            |           
|                                                                                     |                                   |                             |            |            |            |           
|                                                                                     |                                   | Total expenses              |            |            | 30,662,796 |           
|                                                                                     |                                   |                             |            |            |            |           
|Income before change in accounting principle                                         |                                   |                             | 9,955,557  |            |            | 6,894,443 
|Cumulative effect on prior years of change in accounting for major maintenance costs |                                   |                             |           |            |            | 844,809   
|                                                                                     |                                   |                             |            |            |            |           
|                                                                                     |                                   | Net income                  |            |            | 9,955,557  |           
|Other comprehensive (loss) income                                                    |                                   |                             | (5,324,299 | )          |            | (3,544,255
|                                                                                     |                                   |                             |            |            |            |           
|                                                                                     |                                   | Comprehensive income (loss) |            | $          | 4,631,258  |           
|                                                                                     |                                   |                             |            |            |            |           

The
accompanying notes are an integral part of these financial statements.

311

---



GORDONSVILLE ENERGY, L.P.        STATEMENTS OF CHANGES IN PARTNERS' EQUITY        FOR THE YEARS ENDED DECEMBER 31, 2002, 2001 (UNAUDITED) AND 2000 (UNAUDITED)

|                                       |  | Madison
Energy
Company |            | Rapidan
Energy
Company |   | Calpine
Gordonsville
Inc. |   | Accumulated
Other
Comprehensive
Loss |            | Total |  
|-------------------------------------- |  | ---------------------- | ---------- | ---------------------- | - | ------------------------- | - | ------------------------------------ | ---------- | ----- | -
|Balance, December 31, 1999 (unaudited) |  | $                      | 28,133,522 |                        | $ | 574,153                   |   | $                                    | 28,707,676 |       | $
|Capital distributions                  |  |                        | (2,891,000 | )                      |   | (59,000                   | ) |                                      | (2,950,000 | )     |  
|Net income                             |  |                        | 4,343,325  |                        |   | 88,639                    |   |                                      | 4,431,965  |       |  
|Other comprehensive income             |  |                        |           |                        |   |                          |   |                                      |           |       |  
|                                       |  |                        |            |                        |   |                           |   |                                      |            |       |  
|Balance, December 31, 2000 (unaudited) |  |                        | 29,585,847 |                        |   | 603,792                   |   |                                      | 30,189,641 |       |  
|Capital distributions                  |  |                        | (808,500   | )                      |   | (16,500                   | ) |                                      | (825,000   | )     |  
|Net income                             |  |                        | 3,792,233  |                        |   | 77,393                    |   |                                      | 3,869,626  |       |  
|Other comprehensive income             |  |                        |           |                        |   |                          |   |                                      |           |       |  
|                                       |  |                        |            |                        |   |                           |   |                                      |            |       |  
|Balance, December 31, 2001 (unaudited) |  |                        | 32,569,580 |                        |   | 664,685                   |   |                                      | 33,234,267 |       |  
|Capital distributions                  |  |                        | (2,082,500 | )                      |   | (42,500                   | ) |                                      | (2,125,000 | )     |  
|Net income                             |  |                        | 4,878,223  |                        |   | 99,556                    |   |                                      | 4,977,778  |       |  
|Other comprehensive income             |  |                        |           |                        |   |                          |   |                                      |           |       |  
|                                       |  |                        |            |                        |   |                           |   |                                      |            |       |  
|Balance, December 31, 2002             |  | $                      | 35,365,303 |                        | $ | 721,741                   |   | $                                    | 36,087,045 |       | $
|                                       |  |                        |            |                        |   |                           |   |                                      |            |       |  

The accompanying notes are an integral part of these financial statements.

312

---

GORDONSVILLE ENERGY, L.P.        STATEMENTS OF CASH FLOWS        FOR THE YEARS ENDED DECEMBER 31, 2002, 2001 (UNAUDITED) AND 2000 (UNAUDITED)

|                                                     |                                                                                 | 2002                                        |                                           | 2001        |           | 2000        |            
|---------------------------------------------------- | ------------------------------------------------------------------------------- | ------------------------------------------- | ----------------------------------------- | ----------- | --------- | ----------- | -----------
|
|Cash flows from operating activities:                |                                                                                 |                                             |                                           |             |           |             |            
|                                                     | Net income:                                                                     |                                             | $                                         | 9,955,557   |           | $           | 7,739,252  
|                                                     | Adjustments to reconcile net loss to net cash provided by operating activities: |                                             |                                           |             |           |             |            
|                                                     |                                                                                 | Depreciation and amortization               |                                           |             | 7,181,522 |             |            
|                                                     | Changes in assets and liabilities:                                              |                                             |                                           |             |           |             |            
|                                                     |                                                                                 | (Increase) decrease in accounts receivables |                                           |             | (992,371  | )           |            
|                                                     |                                                                                 | Decrease (increase) in inventory            |                                           |             | 814,539   |             |            
|                                                     |                                                                                 | Decrease in non-current spares              |                                           |             |          |             |            
|                                                     |                                                                                 | (Increase) decrease in prepaid and other    |                                           |             | (322,627  | )           |            
|                                                     |                                                                                 | (Decrease) increase in accounts payable     |                                           |             | (525,376  | )           |            
|                                                     |                                                                                 | (Decrease) increase in interest payable     |                                           |             | (45,602   | )           |            
|                                                     |                                                                                 | Decrease in overhaul reserve                |                                           |             |          |             |            
|                                                     | Cumulative effect on prior years of change in accounting principle              |                                             |                                           |            |           |             | (844,809   
|                                                     |                                                                                 |                                             |                                           |             |           |             |            
|                                                     |                                                                                 |                                             | Net cash provided by operating activities |             |           | 16,065,642  |            
|                                                     |                                                                                 |                                             |                                           |             |           |             |            
|Cash flows from investing activities:                |                                                                                 |                                             |                                           |             |           |             |            
|                                                     | Capital expenditures                                                            |                                             |                                           | (118,645    | )         |             | (136,443   
|                                                     |                                                                                 |                                             |                                           |             |           |             |            
|                                                     |                                                                                 |                                             | Net cash used in investing activities     |             |           | (118,645    | )          
|                                                     |                                                                                 |                                             |                                           |             |           |             |            
|Cash flows from financing activities:                |                                                                                 |                                             |                                           |             |           |             |            
|                                                     | (Increase) decrease in debt service reserves                                    |                                             |                                           | (6,179      | )         |             | (628,746   
|                                                     | Capital distributions                                                           |                                             |                                           | (4,250,000  | )         |             | (1,650,000 
|                                                     | Repayment of long-term debt                                                     |                                             |                                           | (12,742,704 | )         |             | (10,618,920
|                                                     |                                                                                 |                                             |                                           |             |           |             |            
|                                                     |                                                                                 |                                             | Net cash used in financing activities     |             |           | (16,998,883 | )          
|                                                     |                                                                                 |                                             |                                           |             |           |             |            
|Net (decrease) increase in cash and cash equivalents |                                                                                 |                                             | (1,051,886                                | )           |           | 2,046,605   |            
|Cash and cash equivalents, beginning of year         |                                                                                 |                                             | 3,850,546                                 |             |           | 1,803,941   |            
|                                                     |                                                                                 |                                             |                                           |             |           |             |            
|Cash and cash equivalents, end of year               |                                                                                 | $                                           | 2,798,660                                 |             | $         | 3,850,546   |            
|                                                     |                                                                                 |                                             |                                           |             |           |             |            
|Supplemental disclosure of cash flow information:    |                                                                                 |                                             |                                           |             |           |             |            
|                                                     | Cash paid for interest                                                          |                                             | $                                         | 7,723,065   |           | $           | 8,678,007  
|                                                     |                                                                                 |                                             |                                           |             |           |             |            

The accompanying notes are an integral part of these financial statements.

313

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GORDONSVILLE ENERGY, L.P.        NOTES TO FINANCIAL STATEMENTS        DECEMBER 31, 2002, 2001 (UNAUDITED) AND 2000 (UNAUDITED)

1.    Organization and Operations

Gordonsville Energy, L.P. (the "Partnership"), is a partnership among Rapidan Energy Company, a California corporation ("Rapidan"), holding a one percent general
partnership interest; Madison Energy Company, a California corporation ("Madison"), holding a 49 percent limited partnership interest; and Calpine Gordonsville Inc., a Delaware
corporation ("Calpine") holding a 50 percent general partnership interest. Rapidan and Madison are wholly owned subsidiaries of Edison Mission Energy ("EME"), an indirect wholly owned
subsidiary of Edison International. Calpine Gordonsville Inc. is an indirect wholly owned subsidiary of Calpine Corporation.

The
Partnership was organized under Delaware law on January 16, 1992, to construct, own and operate an independent qualifying power facility (the "Facility"), as defined in the
Public Utility Regulatory Policies Act of 1978 and the regulations promulgated there under, all as amended ("PURPA"), located near the Town of Gordonsville in Louisa County, Virginia. The Facility was
certified as a "qualifying facility" under PURPA prior to the start of operations, and management believes it has fulfilled all requirements to receive continued "qualifying facility" status.

The
Facility sells 100 percent of its electric energy to a public utility for resale to its customers under two long-term power purchase agreements, each with an
initial term of 30 years. The Facility also provides steam output to Rapidan Service Authority, a political subdivision of the commonwealth of Virginia, for use in treating wastewater generated
by third-party industrial companies. The Partnership will terminate on December 31, 2050, unless sooner terminated pursuant to the limited partnership agreement, or upon the date the
Partnership elects to cease operations, whichever occurs first.

The
Facility commenced commercial operations on June 1, 1994 and consists of two natural gas and oil-fired combustion turbine generators ("Units"). The Facility is
designed to produce approximately 240 megawatts of dependable peaking capacity.

2.    Changes in Accounting Principles

Through December 31, 2000 we have accrued for major maintenance costs during the period between turnarounds (referred to as "accrue in advance" accounting
method). Such accounting policy has been widely used by independent power producers as well as several other industries. In March 2000, the U.S. Securities and Exchange Commission ("SEC")
issued a letter to the Accounting Standards Executive Committee, stating its position that the SEC Staff does not believe it is appropriate to use an "accrue in advance" method for major maintenance
costs as part of an existing project and to issue authoritative guidance by August 2000. Due to the position taken by the SEC Staff, we decided voluntarily to change our accounting policy so as
to record major maintenance costs as an expense as incurred. Such change in accounting policy is considered preferable based on the recent guidance provided by the SEC. In accordance with Accounting
Principles Board Opinion No. 20, "Accounting Changes", we have recorded $844,809, as a cumulative change in the accounting for major maintenance costs during the year ended December 31,
2001. Pro forma data has not been provided for prior periods, as the impact would not have been material.

314

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3.    Summary of Significant Accounting Policies

Use of Estimates in Financial Statements

The preparation of financial statements in conformity with accounting principles generally accepted in the United States requires management to make estimates and
assumptions that affect reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenue and
expenses during the reporting period. Actual results could differ from those estimates.

Cash and Cash Equivalents

The Partnership considers cash and cash equivalents to include cash and short-term investments with original maturities of three months or less.

Inventory

Inventory consists of spare parts, natural gas and fuel oil and is stated at the lower of weighted average cost or market.

Property, Plant and Equipment

Property, plant and equipment are stated at cost. All costs, including interest and field overhead expenses, incurred during construction and the precommission
phase of the Facility were capitalized as part of the cost of the Facility. Depreciation is computed on a straight-line basis over the following estimated useful lives:

Power plant facilities

Up to 30 yearsInterconnection facility

30 yearsFurniture and office equipment

5 to 7 years


Financial Instruments

Financial instruments that potentially subject the Partnership to significant concentrations of credit or valuation risk consist principally of cash and cash
equivalents, accounts receivable, debt service reserves, accounts payable, interest payable and long-term debt.

The
carrying amounts reported in the balance sheet for cash and cash equivalents, accounts receivable, debt service reserves, accounts payable and interest payable approximate fair
market value due to their short maturity or their highly liquid nature. The carrying amount of the long-term debt approximates fair value due to repricing of interest rates associated with
this instrument.

Derivative Instruments and Hedging Activities

The Partnership uses interest rate swaps to manage its interest-rate exposure on debt. Effective January 1, 2001, the Partnership adopted the
provisions of SFAS No. 133, Accounting for Derivative Instruments and Hedging, as amended by SFAS 138, Accounting for Certain Derivative Instruments and Certain Hedging Activities
(collectively SFAS No. 133, as amended). These statements establish accounting and reporting standards for derivative instruments and hedging activities and require an

315

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entity to recognize all derivatives in the statement of financial position and measure those instruments at fair value. Changes in the derivative instrument's fair value must be recognized in
earnings unless specific hedge accounting criteria are met. Changes in fair value of derivative instruments that meet specific cash flow hedge accounting criteria are reported in other comprehensive
income.

At
December 31, 2002 the Partnership was a party to an interest rate swap agreement with a bank to reduce the potential impact of the increases in interest rates on
floating-rate long-term debt (see Note 8) that qualified for hedge accounting. This derivative hedged approximately $89,778,000 of long-term debt that
matures in 2009. Net interest expense was impacted by ($3,794,759) and ($1,350,811) in 2002 and 2001, respectively, to reflect the effects of the cash flow hedge. The fair value of the interest rate
swap at December 31, 2002 was ($8,868,554). As of December 31, 2002, $3,753,277 of losses relating to the interest rate swap were expected to be reclassified from accumulated other
comprehensive income to income within the next 12 months.

Revenue Recognition

Revenue is recognized under the provisions of the power purchase agreements. Revenue is calculated based on available capacity and electric power output using
established prices, as defined in the power purchase agreements.

Major Maintenance

Certain of major pieces of equipment require major maintenance on a periodic basis. These costs are expensed as incurred.

Income Taxes

The Partnership is treated as a partnership for income tax purposes and the income or loss of the Partnership is included in the income tax returns of the
individual partners. Accordingly, no recognition has been given to income taxes in the financial statements.

New Accounting Pronouncements

Statement of Financial Accounting Standards No. 143

Effective January 1, 2003, the Partnership adopted Statement of Financial Accounting Standards ("SFAS") No. 143, "Accounting for Asset Retirement
Obligations." SFAS No. 143 requires entities to record the fair value of a liability for an asset retirement obligation in the period in which it is incurred. When the liability is initially
recorded, the entity capitalizes a cost by increasing the carrying amount of the related long-lived asset. Over time, the liability is increased to its present value each period, and the
capitalized cost is depreciated over the useful life of the related asset. Upon settlement of the liability, an entity either settles the obligation for its recorded amount or incurs a gain or loss
upon settlement. The Partnership does not believe it has an asset retirement obligation as defined under SFAS No. 143.

316

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Statement of Financial Accounting Standards No. 145

In April 2002, the Financial Accounting Standards Board ("FASB") issued SFAS Standards No. 145, "Rescission of FASB Statements No. 4, 44, and
64, Amendment of FASB Statement No. 13, and Technical Corrections," which supersedes previous guidance for reporting gains and losses from extinguishment of debt and accounting for leases,
among other things, which is effective on January 1, 2003. The portion of the statement relating to the rescission of SFAS No. 4, "Reporting Gains and Losses from Extinguishment of Debt"
requires that any gain or loss on extinguishment of debt that was classified as an extraordinary item that does not meet the unusual in nature and infrequent of occurrence criteria in APB Opinion
No. 30, "Reporting the Results of OperationsReporting the Effects of Disposal of a Segment of a Business, and Extraordinary, Unusual and Infrequently Occurring Events and
Transactions" shall be reclassified. The Partnership does not anticipate that the adoption of SFAS No. 145 will have a significant effect on their financial position or the results of
operations.

Statement of Financial Accounting Standards No. 146

Effective January 1, 2003, the Partnership adopted SFAS No. 146, "Accounting for Costs Associated with Exit or Disposal Activities." SFAS
No. 146 requires that liabilities for costs associated with exit or disposal activities initiated after December 31, 2002 be recognized when incurred, rather than at the date of a
commitment to an exit or disposal plan. The Partnership does not anticipate that the adoption of SFAS No. 146 will have a significant effect on their financial position or the results of
operations.

Statement of Financial Accounting Standards Interpretation No. 45

In November 2002, the FASB issued SFAS Interpretation No. 45, "Guarantor's Accounting and Disclosure Requirements for Guarantees, Including Indirect
Guarantees of Indebtedness of Others." This interpretation establishes reporting requirements to be made by a guarantor about its obligations under certain guarantees that it has issued. It also
clarifies that a guarantor is required to recognize, at the inception of a guarantee, a liability for the fair value of the obligation undertaken in issuing the guarantee. The initial recognition and
initial measurement provisions of this interpretation are applicable on a prospective basis to guarantees issued or modified after December 31, 2002. The Partnership does not anticipate that
adoption of this standard will have a significant effect on their financial position or the results of operations.

4.    Inventory

Inventory consists of the following at December 31, 2002 and 2001:

2002

2001(unaudited)Fuel oil

$
3,241,006

$
4,028,730Natural gas


123,185


Spare parts


470,044


620,044$
3,834,235

$
4,648,774


317

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5.    Property, Plant and Equipment

Property, plant and equipment consist of the following at December 31, 2002 and 2001:

2002

2001(unaudited)Power plant facilities

$
196,717,472

$
196,598,826Interconnection facility


3,250,000


3,250,000Furniture and office equipment


813,423


813,424200,780,895


200,662,250Less: Accumulated depreciation


(59,907,792
)

(53,150,868
)Property, plant and equipment, net

$
140,873,103

$
147,511,382


6.    Other Assets

Deferred Financing Costs

Deferred financing costs consist of legal fees and closing costs incurred by the Partnership in obtaining its financing and are being amortized over the term of
the Facility's financing arrangement of 15 years. Amortization expense was $424,598 for 2002 and 2001, and is included in depreciation and amortization expense in the accompanying statements of
income. Accumulated amortization of these costs were $3,644,459 and $3,219,861 at December 31, 2002 and 2001, respectively.

Debt Service Reserves

Debt service reserves are interest bearing accounts required by a bank under the terms of the financing agreement. The Partnership is required to maintain a debt
service account consisting of six months of interest at an assumed rate of 7.28 percent per annum on the aggregate amount of the project commitments, and the next scheduled principal payment.

7.    Accounts Payable

Accounts payable consists of the following at December 31, 2002 and 2001:

2002

2001(unaudited)Accounts payable to affiliates:Rapidan Energy Company

$
6,432

$
33,660Edison Mission Operations and Maintenance, Inc. (EMOM)


886,091


865,894892,523


899,554Accounts payable to others


702,059


1,220,404$
1,594,582

$
2,119,958


318

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8.    Long-Term Debt

On October 15, 1993, the Partnership entered into a Reimbursement and Loan Agreement (the "Agreement") with a bank for a combination of loans and letters
of credit aggregating $222,719,000. The Agreement provides for construction financing loans aggregating $213,609,000. On August 10, 1995, the construction financing loans were converted to a
term loan. After conversion, the Partnership borrowed an additional $13,873,000, of which amount $8,090,452 was used to fund the debt service reserve. Principal repayments ranging from $2,246,310 to
$8,821,872 are due semiannually through June 1, 2009. The commitment of the banks to extend loans and letters of credit will be reduced on dates and by amounts specified in the Agreement. The
Agreement places certain restrictions on capital distributions and further provides that the Partnership pay letter of credit, agency and commitment fees. At December 31, 2002, the Partnership
had outstanding loans of $94,018,294. The Agreement also provides for available letters of credit not to exceed $9,110,000, of which $7,260,000 were issued and outstanding as of December 31,
2002 and 2001. In addition, substantially all of the assets of the Partnership are pledged as collateral for the Agreement.

Amounts
outstanding under the Agreement bear interest at variable Eurodollar Rates or Base Rates, as defined in the Agreement, at the option of the Partnership, and are payable in
varying installments. The Partnership elected to pay Eurodollar interest rates specified as LIBOR (1.820 percent at December 31, 2002), plus a margin of 1.25 percent, which
escalates to 1.875 percent over the term of the loan (1.625 percent at December 31, 2002). Interest paid under the Agreement for the years ended December 31, 2002, 2001 and
2000 was $3,659,837, $7,624,042 and $10,247,399, respectively.

On
October 1, 1993, the Partnership entered into an interest rate swap agreement (the "Swap") with a major financial institution to reduce the risk of interest rate changes on its
debt. The Swap agreement involves exchanging the Partnership's floating Eurodollar market rate for a fixed 5.775 percent resulting in an effective rate of approximately 7.40 percent on
the debt covered by the notional amount of the Swap at December 31, 2002. The Swap had an initial notional principal amount of $146,500,000 ($89,778,000 at December 31, 2002) which
decreases over the term of the swap and expires on June 1, 2009. The notional amount of the Swap is used to measure the interest to be paid or received and does not represent the amount of
exposure to loss. If the variable rate under the notional amount exceeds the fixed rate established by the swap agreement the Partnership could be exposed to the risk of higher interest costs in the
event of non-performance by the counterparty. However, the Partnership does not anticipate non-performance by the counterparty.

The
Partnership made swap payments of $3,772,125 and $953,034 during 2002 and 2001, respectively. Amounts paid under the swap have been reflected in interest expense.

319

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At
December 31, 2002, the future maturities of the debt are as follows:

Year Ending December 31,2003

$
13,477,8602004


14,948,1722005


12,906,0722006


13,804,5962007


14,458,078Thereafter


24,423,516$
94,018,294


9.    Related-Party Transactions

Under the terms of the Operation and Maintenance Agreement, employees of Edison Mission Operation and Maintenance, Inc. ("EMOM"), a wholly owned subsidiary
of EME, perform all necessary functions to operate and maintain the Facility. The Partnership pays for direct costs of these services, plus an increment to cover overhead and benefits. EMOM may also
earn annual incentive compensation up to $200,000 based upon actual operating results compared to budgeted performance. Pursuant to this agreement, the Partnership incurred costs of $2,348,631,
$2,540,784 and $2,524,015, which included $200,000 of incentive compensation, during 2002, 2001 and 2000, respectively.

Under
the terms of the Financial Services Agreement, Rapidan will perform certain required financial, accounting, tax, project management, legal, insurance and other services for the
Partnership. Pursuant to this agreement, the Partnership incurred costs of $1,018,215, $259,707 and $308,918 during 2002, 2001 and 2000, respectively.

10.    Commitments and Contingencies

Site Lease

The Partnership exercised an option to lease the plant site from the town of Gordonsville in January 1993. The lease agreement provides for an initial term
of 30 years from the commencement of commercial operations, with an option to renew the lease for an additional 10 years. Annual rental payments under the lease are $200,000 during the
initial lease term, with annual increases for inflation.

In
accordance with the provisions of the site lease, the Partnership has arranged a $10,000 letter of credit to provide assurance about plant maintenance during the term of the site
lease. The Partnership has also provided the town of Gordonsville with a $300,000 letter of credit, which may be drawn upon the occurrence of certain events of default, as described in the site lease
agreement. This default assurance letter of credit was arranged by an affiliate of Rapidan for the benefit of the Partnership.

Power Purchase Agreements

In October 1992, the Partnership entered into two Power Purchase Agreements for the sale to a public utility of the net electrical output and dependable
capacity from each of the Facility's two Units. The agreements are effective for the 30-year period commencing June 1, 1994, with options for

320

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extension in 5-year periods. The pricing is based on a contractual formula that varies depending on capacity, electric output and other costs, as defined in the agreement.

Under
the Power Purchase Agreements, the Partnership must maintain a letter of credit of $6,960,000 for the term of the agreement to secure the public utility's interest in the
Facility's future commercial operations.

Fuel Supply Agreements

In July 1993, the Partnership entered into an agreement to purchase the majority of the Facility's summer fuel gas requirements from an unrelated party at
a price defined in the agreement. Unless extended by mutual consent or earlier terminated pursuant to the terms of the agreement, the agreement will remain in effect for a 15-year period,
commencing with the commercial operation date, as defined in the agreement. On July 1, 1999 another unrelated party purchased the stock of this fuel supplier and became the new fuel supplier
for the Partnership.

In
July 1993, the Partnership entered into an agreement to purchase winter fuel gas from an unrelated party on an as-available basis, at a price defined in the
agreement. Unless extended by mutual agreement or earlier terminated pursuant to the terms of the agreement, the agreement will remain in effect through the winter period of 2008.

321

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REPORT OF INDEPENDENT ACCOUNTANTS

To
the Management Committee of
Brooklyn Navy Yard Cogeneration Partners, L.P.:

In
our opinion, the accompanying balance sheet as of December 31, 2002 and the related statements of operations, partners' equity, and cash flows present fairly, in all material
respects, the financial position of Brooklyn Navy Yard Cogeneration Partners, L.P. (a Delaware limited partnership) at December 31, 2002, and the results of its operations and its cash flows
for the year then ended in conformity with accounting principles generally accepted in the United States of America. These financial statements are the responsibility of the Partnership's management;
our responsibility is to express an opinion on these financial statements based on our audit. We conducted our audit of these statements in accordance with auditing standards generally accepted in the
United States of America, which 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, assessing the accounting principles used and significant estimates made by management, and
evaluating the overall financial statement presentation. We believe that our audit provides a reasonable basis for our opinion.

PricewaterhouseCoopers
LLP

Los
Angeles, California
March 14, 2003

322

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BROOKLYN NAVY YARD COGENERATION PARTNERS, L.P.        BALANCE SHEETS        DECEMBER 31, 2002 AND 2001 (UNAUDITED)

|                                               |                                                                                                                        | 2002                          |                                        | 2001        |           
|---------------------------------------------- | ---------------------------------------------------------------------------------------------------------------------- | ----------------------------- | -------------------------------------- | ----------- | ----------
|
|Assets                                         |                                                                                                                        |                               |                                        |             |           
|Current assets:                                |                                                                                                                        |                               |                                        |             |           
|                                               | Cash and cash equivalents                                                                                              |                               | $                                      | 3,209,402   |           
|                                               | Accounts receivable, net of allowance for doubtful accounts of $467,000 as of December 31, 2002 and 2001, respectively |                               |                                        | 19,891,453  |           
|                                               | Inventory                                                                                                              |                               |                                        | 8,212,848   |           
|                                               | Prepaids and other                                                                                                     |                               |                                        | 1,275,185   |           
|                                               |                                                                                                                        |                               |                                        |             |           
|                                               |                                                                                                                        |                               | Total current assets                   |             |           
|                                               |                                                                                                                        |                               |                                        |             |           
|Construction in progress                       |                                                                                                                        |                               | 4,299,997                              |             |           
|Plant and equipment, net                       |                                                                                                                        |                               | 417,131,544                            |             |           
|Deferred costs, net                            |                                                                                                                        |                               | 13,193,749                             |             |           
|Deposits                                       |                                                                                                                        |                               | 17,374,047                             |             |           
|                                               |                                                                                                                        |                               |                                        |             |           
|                                               |                                                                                                                        |                               | Total assets                           |             | $         
|                                               |                                                                                                                        |                               |                                        |             |           
|Liabilities and Partners' Equity               |                                                                                                                        |                               |                                        |             |           
|Current liabilities:                           |                                                                                                                        |                               |                                        |             |           
|                                               | Current portion of long-term debt                                                                                      |                               | $                                      | 2,780,000   |           
|                                               | Working capital facility                                                                                               |                               |                                        | 2,500,000   |           
|                                               | Interest and fees payable:                                                                                             |                               |                                        |             |           
|                                               |                                                                                                                        | Long-term debt and other      |                                        |             | 6,168,548 
|                                               |                                                                                                                        | Mission Energy New York, Inc. |                                        |             | 32,137,832
|                                               | Accounts payable                                                                                                       |                               |                                        | 31,088,641  |           
|                                               | Accounts payableaffiliates                                                                                            |                               |                                        | 6,817,298   |           
|                                               | Accrued expenses and other                                                                                             |                               |                                        | 12,660,438  |           
|                                               |                                                                                                                        |                               |                                        |             |           
|                                               |                                                                                                                        |                               | Total current liabilities              |             |           
|                                               |                                                                                                                        |                               |                                        |             |           
|Long-term debt, net of current portion         |                                                                                                                        |                               | 398,400,000                            |             |           
|Loans payable to Partner                       |                                                                                                                        |                               | 90,461,186                             |             |           
|Payable to Contractor                          |                                                                                                                        |                               | 12,551,000                             |             |           
|Other deferred liabilities                     |                                                                                                                        |                               | 4,927,447                              |             |           
|                                               |                                                                                                                        |                               |                                        |             |           
|                                               |                                                                                                                        |                               | Total liabilities                      |             |           
|                                               |                                                                                                                        |                               |                                        |             |           
|Commitments and contingencies (Notes 9 and 12) |                                                                                                                        |                               |                                        |             |           
|Partners' equity:                              |                                                                                                                        |                               |                                        |             |           
|                                               | Mission Energy New York, Inc.                                                                                          |                               |                                        | (55,073,061 | )         
|                                               | B-41 Associates, L.P.                                                                                                  |                               |                                        | (60,831,104 | )         
|                                               |                                                                                                                        |                               |                                        |             |           
|                                               |                                                                                                                        |                               | Total partners' equity                 |             |           
|                                               |                                                                                                                        |                               |                                        |             |           
|                                               |                                                                                                                        |                               | Total liabilities and partners' equity |             | $         
|                                               |                                                                                                                        |                               |                                        |             |           

The accompanying notes are an integral part of these financial statements.

323

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BROOKLYN NAVY YARD COGENERATION PARTNERS, L.P.        STATEMENTS OF OPERATIONS        FOR THE YEARS ENDED DECEMBER 31, 2002, 2001 (UNAUDITED) AND 2000 (UNAUDITED)

|          |                               | 2002           |   | 2001        |             | 2000
|--------- | ----------------------------- | -------------- | - | ----------- | ----------- | ----
|
|Revenues: |                               |                |   |             |             |     
|          | Energy revenue                |                | $ | 103,847,813 |             | $   
|          | Steam revenue                 |                |   | 31,666,098  |             |     
|          | Peaking gas revenue           |                |   | 4,704,829   |             |     
|          | Other revenue                 |                |   | 11,736,327  |             |     
|          | Interest income               |                |   | 411,202     |             |     
|          |                               |                |   |             |             |     
|          |                               | Total revenues |   |             | 152,366,269 |     
|          |                               |                |   |             |             |     
|Expenses: |                               |                |   |             |             |     
|          | Operations and maintenance    |                |   | 117,019,913 |             |     
|          | General and administrative    |                |   | 9,933,368   |             |     
|          | Depreciation and amortization |                |   | 13,922,517  |             |     
|          | Interest expense              |                |   | 37,172,341  |             |     
|          | Loss on sale of asset         |                |   | 2,894,982   |             |     
|          |                               |                |   |             |             |     
|          |                               | Total expenses |   |             | 180,943,121 |     
|          |                               |                |   |             |             |     
|          |                               | Net loss       |   | $           | 28,576,852  |     
|          |                               |                |   |             |             |     

The
accompanying notes are an integral part of these financial statements.

324

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BROOKLYN NAVY YARD COGENERATION PARTNERS, L.P.        STATEMENTS OF CHANGES IN PARTNERS' EQUITY        FOR THE YEARS ENDED DECEMBER 31, 2002, 2001 (UNAUDITED) AND 2000 (UNAUDITED)

|                                       |                                                 | Mission Energy New York, Inc. |             | B-41
Associates
L.P. |   | Total       |            
|-------------------------------------- | ----------------------------------------------- | ----------------------------- | ----------- | -------------------- | - | ----------- | -----------
|Balance, December 31, 1999 (unaudited) |                                                 | $                             | (23,167,171 | )                    | $ | (28,925,214 | )          
|                                       | Net loss                                        |                               |             | (3,947,311           | ) |             | (3,947,311 
|                                       |                                                 |                               |             |                      |   |             |            
|Balance, December 31, 2000 (unaudited) |                                                 |                               | (27,114,482 | )                    |   | (32,872,525 | )          
|                                       | Net loss                                        |                               |             | (13,670,153          | ) |             | (13,670,153
|                                       |                                                 |                               |             |                      |   |             |            
|Balance, December 31, 2001 (unaudited) |                                                 |                               | (40,784,635 | )                    |   | (46,542,678 | )          
|                                       | Contribution from Mission Energy New York, Inc. |                               |             | 32,551,000           |   |             |           
|                                       | Receivable from Mission Energy New York, Inc.   |                               |             | (32,551,000          | ) |             |           
|                                       | Net loss                                        |                               |             | (14,288,426          | ) |             | (14,288,426
|                                       |                                                 |                               |             |                      |   |             |            
|Balance, December 31, 2002             |                                                 | $                             | (55,073,061 | )                    | $ | (60,831,104 | )          
|                                       |                                                 |                               |             |                      |   |             |            

The
accompanying notes are an integral part of these financial statements.

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BROOKLYN NAVY YARD COGENERATION PARTNERS, L.P.        STATEMENTS OF CASH FLOWS        FOR THE YEARS ENDED DECEMBER 31, 2002, 2001 (UNAUDITED) AND 2000 (UNAUDITED)

|                                                     |                                                                                 | 2002                               |                                            | 2001                                                |            | 2000       |            
|---------------------------------------------------- | ------------------------------------------------------------------------------- | ---------------------------------- | ------------------------------------------ | --------------------------------------------------- | ---------- | ---------- | -----------
|
|Cash flows from operating activities:                |                                                                                 |                                    |                                            |                                                     |            |            |            
|                                                     | Net loss                                                                        |                                    | $                                          | (28,576,852                                         | )          | $          | (27,340,306
|                                                     | Adjustments to reconcile net loss to net cash provided by operating activities: |                                    |                                            |                                                     |            |            |            
|                                                     |                                                                                 | Loss on sale of asset              |                                            |                                                     | 2,894,982  |            |            
|                                                     |                                                                                 | Depreciation and amortization      |                                            |                                                     | 13,922,517 |            |            
|                                                     |                                                                                 | Provision for doubtful accounts    |                                            |                                                     |           |            |            
|                                                     |                                                                                 | Changes in assets and liabilities: |                                            |                                                     |            |            |            
|                                                     |                                                                                 |                                    | (Increase) decrease in accounts receivable |                                                     |            | (8,974,898 | )          
|                                                     |                                                                                 |                                    | Decrease (increase) in inventory           |                                                     |            | 1,343,045  |            
|                                                     |                                                                                 |                                    | Increase in prepaids and other             |                                                     |            | (260,856   | )          
|                                                     |                                                                                 |                                    | Increase in interest and fees payable      |                                                     |            | 11,645,286 |            
|                                                     |                                                                                 |                                    | Increase (decrease) in accounts payable    |                                                     |            | 25,634,379 |            
|                                                     |                                                                                 |                                    | Increase in accrued expenses and other     |                                                     |            | 6,977,981  |            
|                                                     |                                                                                 |                                    | Decrease in deferred liabilities           |                                                     |            | (1,888,955 | )          
|                                                     |                                                                                 |                                    | Increase in other liabilities              |                                                     |            | 12,551,000 |            
|                                                     |                                                                                 |                                    |                                            |                                                     |            |            |            
|                                                     |                                                                                 |                                    |                                            | Net cash provided by (used in) operating activities |            |            | 35,267,629 
|                                                     |                                                                                 |                                    |                                            |                                                     |            |            |            
|Cash flows from investing activities:                |                                                                                 |                                    |                                            |                                                     |            |            |            
|                                                     | Capital expenditures                                                            |                                    |                                            | (4,299,997                                          | )          |            | (3,872,252 
|                                                     | Capital expenditures Contractor                                                 |                                    |                                            | (32,551,000                                         | )          |            |           
|                                                     | Proceeds from sales of assets                                                   |                                    |                                            | 108,501                                             |            |            |           
|                                                     | (Increase) Decrease in deposits                                                 |                                    |                                            | (6,548,709                                          | )          |            | 7,344,422  
|                                                     |                                                                                 |                                    |                                            |                                                     |            |            |            
|                                                     |                                                                                 |                                    |                                            | Net cash (used in) provided by investing activities |            |            | (43,291,205
|                                                     |                                                                                 |                                    |                                            |                                                     |            |            |            
|Cash flows from financing activities:                |                                                                                 |                                    |                                            |                                                     |            |            |            
|                                                     | (Repayments) Borrowings to/from working capital facility                        |                                    |                                            | (2,500,000                                          | )          |            | 5,000,000  
|                                                     | Repayment of long-term debt                                                     |                                    |                                            | (1,080,000                                          | )          |            | (1,340,000 
|                                                     |                                                                                 |                                    |                                            |                                                     |            |            |            
|                                                     |                                                                                 |                                    |                                            | Net cash (used in) provided by financing activities |            |            | (3,580,000 
|                                                     |                                                                                 |                                    |                                            |                                                     |            |            |            
|Net (decrease) increase in cash and cash equivalents |                                                                                 |                                    | (11,603,576                                | )                                                   |            | (555,058   | )          
|Cash and cash equivalents, beginning of period       |                                                                                 |                                    | 14,812,978                                 |                                                     |            | 15,368,036 |            
|                                                     |                                                                                 |                                    |                                            |                                                     |            |            |            
|Cash and cash equivalents, end of period             |                                                                                 | $                                  | 3,209,402                                  |                                                     | $          | 14,812,978 |            
|                                                     |                                                                                 |                                    |                                            |                                                     |            |            |            
|Supplemental disclosure of cash flow information:    |                                                                                 |                                    |                                            |                                                     |            |            |            
|                                                     | Cash paid during the year for interest                                          |                                    | $                                          | 25,526,683                                          |            | $          | 33,552,581 
|                                                     |                                                                                 |                                    |                                            |                                                     |            |            |            

The accompanying notes are an integral part of these financial statements.

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BROOKLYN NAVY YARD COGENERATION PARTNERS, L.P.        NOTES TO FINANCIAL STATEMENTS        DECEMBER 31, 2002, 2001 (UNAUDITED) AND 2000 (UNAUDITED)

1.    Organization and Operations

Brooklyn Navy Yard Cogeneration Partners, L.P. (the "Partnership") is a Delaware limited partnership formed pursuant to a limited partnership agreement dated
October 19, 1992 by and between Mission Energy New York, Inc. ("MENY"), holding a 5 percent general partnership interest and a 45 percent limited partnership interest; and
B-41 Associates, L.P. ("B-41"), holding a 5 percent general partnership interest and a 45 percent limited partnership interest. MENY is a wholly owned subsidiary
of Edison Mission Energy ("EME"), an indirect wholly owned subsidiary of Edison International. B-41 is a majority owned subsidiary of York Research Corporation ("York").

On
November 1, 1997, MENY and B-41 entered into an Amended and Restated Limited Partnership Agreement (the "Partnership Agreement"). This agreement amended the
determination of general partner management fees, certain special allocations of income and deductions and the prioritization of cash distributions.

The
Partnership was organized for the purpose of developing, leasing, acquiring, constructing, improving, equipping, owning, operating, installing and financing a natural
gas-fired cogeneration facility (the "Facility") located in Brooklyn, New York. The Facility, which is powered by two natural gas and oil fired combustion turbine generators and two
automatic extraction steam turbines, can produce a nominal output of 220 megawatts of electricity and up to 1,000,000 pounds of steam per hour. The Partnership currently sells substantially all of the
Facility's electric and steam generating capacity and output to a public utility for resale to its customers under an energy sales agreement, which expires on October 31, 2036.

The
Facility is currently a qualifying facility ("QF") under the Public Utility Regulatory Policies Act of 1978, as amended, and the regulations promulgated thereunder by the Federal
Energy Regulatory Commission. The documents executed in connection with the December 1997 debt refinancing (see Note 8), require the Facility to maintain a QF, an exempt wholesale
generator ("EWG") or another similar entity status that is exempt under Public Utilities Holdings Company Act ("PUHCA").

2.    Summary of Significant Accounting Policies

Use of Estimates in Financial Statements

The preparation of financial statements in conformity with accounting principles generally accepted in the United States requires management to make estimates and
assumptions that affect reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and
expenses during the reporting period. Actual results could differ from those estimates.

Cash and Cash Equivalents

The Partnership considers cash and cash equivalents to include cash and short-term investments with original maturities of three months or less.

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Inventory

Inventory consists of spare parts, natural gas and fuel oil. Natural gas and spare parts inventory are stated using the average cost valuation method. The LIFO
method of inventory valuation is used for fuel oil.

Plant and Equipment

Plant and equipment are stated at cost and are depreciated on a straight-line basis over the estimated useful lives of the assets. The useful life for
the Facility is 39 years, and the useful lives for all other equipment and enhancements range from five to seven years.

Deferred Costs

Deferred costs as of December 31, 2002 and 2001, consisted of the following:

2002

2001(unaudited)Deferred financing costs

$
14,142,589

$
14,142,589Accumulated amortization


(3,031,809
)

(2,527,929
)Net deferred financing costs


11,110,780


11,614,660Deferred fuel costs


3,000,000


3,000,000Accumulated amortization


(917,031
)

(759,828
)Net deferred fuel costs


2,082,969


2,240,172Total deferred costs

$
13,193,749

$
13,854,832


Deferred
financing costs consist of legal fees and closing costs incurred by the Partnership in obtaining its financing. These costs are being amortized using the effective interest
method over the life of the related debt (see Note 8).

Deferred
fuel costs include a $3,000,000 advance payment required under a long-term fuel supply agreement (see Note 9). These costs are being amortized over the term
of the fuel supply agreement, beginning March 1, 1997.

Maintenance Accrual

Estimated labor costs for scheduled maintenance events are accrued for on a straight-line basis over the expected operating interval between each like
event. Expenditures for minor maintenance, repairs, and minor renewals are charged to operations as incurred. Expenditures for additions, improvements and replacements are capitalized.

Income Taxes

The Partnership is a limited partnership, and the income or loss of the Partnership for income tax purposes is included in the income tax returns of the
individual partners. Accordingly, no recognition has been given to Federal or state income taxes in the accompanying financial statements.

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Deposits

Deposits consist of bond proceeds and revenues that are used to repay principal, interest and other costs due under the Collateral Agency and Intercreditor
Agreement (see Note 8). Deposits and other assets as of December 31, 2002 and 2001 are as follows:

2002

2001(unaudited)Maintenance fund

$
271,509

$
1,424,804Tax-exempt indenture securities fund


4,421,510


4,421,510Taxable indenturesinterest fund


1,747,039


1,767,073Taxable indenturesprincipal fund


695,000


270,000Letter of credit reimbursement fund


172,343


171,230Working capital reimbursement fund


9,000


6,250Revenue fund





218,903Operating fund


9,760,567


37,000Water treatment fund





1,061,095Solid waste disposal fund





799Water usage fund


204,532


1,621Distribution fund





1,385,787Other deposits


92,547


59,266Total deposits

$
17,374,047

$
10,825,338


Revenue Recognition

Revenue is recognized as billable under the provisions of the Energy Sales Agreement for energy and capacity (the "Energy Sales Agreement") with Consolidated
Edison Company of New York, which has a term of 40 years. Revenue is calculated based on established prices, as defined in the Energy Sales Agreement.

New Accounting Pronouncements

Statement of Financial Accounting Standards No. 133

The Partnership adopted Statement of Financial Accounting Standards ("SFAS") No. 133, "Accounting for Derivative Instruments and Hedging Transactions" as
amended by SFAS No. 138, "Accounting for Derivative Instruments and Hedging Transactionsan amendment of SFAS No. 133," effective January 1, 2001. Provisions in SFAS
No. 133, as amended, affect the accounting and disclosure of certain contractual arrangements and operations of the Partnership. Under SFAS No. 133, as amended, all derivatives
instruments are recognized in the balance sheet as their fair values and changes in fair value are recognized immediately in earnings, unless the derivative qualifies as hedges of future cash flows or
investments. For derivatives qualifying as hedges of future cash flows, the effective portion of changes in fair value is recorded in equity until the related hedge items impact earnings. Any
ineffective portion of a hedge is reported in earnings immediately. The Partnership reviewed the activities performed under its contracts and the respective terms and concluded that the

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contracts meet the Normal Purchase Normal Sale exemption defined in SFAS No. 133, which resulted in accrual accounting consistent with the pre-adoption of SFAS No. 133.

Statement of Financial Accounting Standards No. 143

Effective January 1, 2003, the Partnership adopted Statement of Financial Accounting Standards ("SFAS") No. 143, "Accounting for Asset Retirement
Obligations." SFAS No. 143 requires entities to record the fair value of a liability for an asset retirement obligation in the period in which it is incurred. When the liability is initially
recorded, the entity capitalizes a cost by increasing the carrying amount of the related long-lived asset. Over time, the liability is increased to its present value each period, and the
capitalized cost is depreciated over the useful life of the related asset. Upon settlement of the liability, an entity either settles the obligation for its recorded amount or incurs a gain or loss
upon settlement. The Partnership does not believe it has an asset retirement obligation as defined under SFAS No. 143.

Statement of Financial Accounting Standards No. 145

In April 2002, the Financial Accounting Standards Board ("FASB") issued SFAS No. 145, "Rescission of FASB Statements No. 4, 44, and 64,
Amendment of FASB Statement No. 13, and Technical Corrections," which supersedes previous guidance for reporting gains and losses from extinguishment of debt and accounting for leases, among
other things, which is effective on January 1, 2003. The portion of the statement relating to the rescission of SFAS No. 4, "Reporting Gains and Losses from Extinguishment of Debt"
requires that any gain or loss on extinguishment of debt that was classified as an extraordinary item that does not meet the unusual in nature and infrequent of occurrence criteria in APB Opinion
No. 30, "Reporting the Results of OperationsReporting the Effects of Disposal of a Segment of a Business, and Extraordinary, Unusual and Infrequently Occurring Events and
Transactions" shall be reclassified. The Partnership does not anticipate that the adoption of SFAS No. 145 will have a significant effect on their financial position or the results of
operations.

Statement of Financial Accounting Standards No. 146

Effective January 1, 2003, the Partnership adopted SFAS No. 146, "Accounting for Costs Associated with Exit or Disposal Activities." SFAS
No. 146 requires that liabilities for costs associated with exit or disposal activities initiated after December 31, 2002 be recognized when incurred, rather than at the date of a
commitment to an exit or disposal plan. The Partnership does not anticipate that the adoption of SFAS No. 146 will have a significant effect on their financial position or the results of
operations.

Statement of Financial Accounting Standards Interpretation No. 45

In November 2002, the FASB issued SFAS Interpretation No. 45, "Guarantor's Accounting and Disclosure Requirements for Guarantees, Including Indirect
Guarantees of Indebtedness of Others." This interpretation establishes reporting requirements to be made by a guarantor about its obligations under certain guarantees that it has issued. It also
clarifies that a guarantor is required to recognize, at the inception of a guarantee, a liability for the fair value of the obligation undertaken in issuing the guarantee. The initial recognition and
initial measurement provisions of this interpretation are

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applicable on a prospective basis to guarantees issued or modified after December 31, 2002. The Partnership does not anticipate that adoption of this standard will have a significant effect on
their financial position or the results of operations.

3.    Accounts Receivable

Accounts receivable at December 31, 2002 and 2001 consists of the following:

2002

2001(unaudited)Mission Energy New York, Inc.

$
431,055

$
1,273,224Accounts receivable from others


19,927,398


10,110,331Total accounts receivable


20,358,453


11,383,555Allowance for doubtful accounts


(467,000
)

(467,000
)$
19,891,453

$
10,916,555


4.    Inventory

Inventory at December 31, 2002 and 2001 consists of the following:

2002

2001(unaudited)Fuel oil

$
2,434,040

$
2,593,285Gas


2,610,104


3,755,101Spare parts


3,168,704


3,207,507$
8,212,848

$
9,555,893


5.    Plant and Equipment

Plant and equipment at December 31, 2002 and 2001 consists of the following assets:

2002

2001(unaudited)Plant

$
493,416,895

$
464,325,703Equipment


957,763


977,262Accumulated depreciation


(77,243,114
)

(64,457,504
)Plant and equipment, net

$
417,131,544

$
400,845,461


6.    Disclosures About Fair Value of Financial Instruments

The balance sheet items cash and cash equivalents, accounts receivable, accounts payable and interest and fees payable are financial instruments which, due to
their short maturity or their highly liquid nature, have fair market values which approximate their carrying values. The carrying amount of

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the loans payable to partner approximates fair value due to the variable interest rate feature. The fair value of the long-term debt at December 31, 2002 and 2001 was approximately
$379,079,522 and $380,375,641, respectively (see Note 8).

7.    Loans Payable to Partner

During the period from inception through December 31, 1997, the Partnership entered into various construction loans (the "Partner loans") with MENY. The
interest rate on the Partner loans is variable based on the prime rate plus 6 percent (10.25 percent at December 31, 2002), compounded daily. MENY may, at its discretion, reduce
the rate of interest charged for the Partner loans. Through the years ended December 31, 2002 and 2001, MENY has charged and the Partnership has expensed, interest at 10 percent.
Principal and interest on the loan are payable with proceeds from long-term credit facilities or from revenues of the Partnership over five years commencing April 1, 1997. Any
unpaid interest or principal after March 31, 2002 shall be payable in full from the first available cash flow after giving effect to other priority payments as defined in the Partnership
Agreement. The remaining loan payable as of December 31, 2002 and 2001 was $90,461,186, and is subordinate to the long-term debt discussed in Note 8. For the years ended
December 31, 2002, 2001 and 2000, the Partnership recorded interest expense related to the Partner loans of $11,665,320, $11,135,879 and $10,283,699, respectively.

8.    Long-Term Debt

On December 17, 1997, the New York City Industrial Development Agency (the "Agency") issued Industrial Development Revenue Bonds (Brooklyn Navy Yard
Cogeneration Partners, L.P. Project), of $31,960,000 principal amount 6.20 percent Term Bonds due October 1, 2022, $110,280,000 principal amount 5.65 percent Term Bonds due
October 1, 2028, and $164,760,000 principal amount 5.75 percent Term Bonds due October 1, 2036 (collectively, the "Tax-Exempt Bonds") for the purpose of replacing
Industrial Development Revenue Bonds issued in 1995, which were used to finance a portion of the costs of developing, leasing, acquiring, constructing, improving, equipping and installing the
Facility. The Tax-Exempt Bonds were issued pursuant to a Tax-Exempt Indenture of Trust dated as of December 1, 1997. The principal of and premium, if any, and interest
on the Tax-Exempt Bonds is payable from amounts received by the Agency pursuant to the Amended and Restated Lease Agreement dated as of December 1, 1997 between the Agency and the
Partnership. The payment of principal and premium, if any, and interest on the Tax-Exempt Bonds is unconditionally guaranteed by the Partnership. Interest on the Tax-Exempt
Bonds is payable semi-annually on each April 1 and
October 1, commencing April 1, 1998. The principal is payable on varying maturity dates, but in no case before the full maturity of the bonds described below.

Simultaneously
with the issuance of the Tax-Exempt Bonds, the Partnership issued $100,000,000 principal amount of 7.42 percent Senior Secured Bonds due
October 1, 2020 (the "Taxable Bonds"), together with the Tax-Exempt Bonds (collectively, the "1997 Bonds"). The principal of the Taxable Bonds is payable in semi-annual
installments commencing April 1, 1998 and is secured by the Shared Collateral, as defined below, on a parity basis with the Tax-Exempt Bonds. The bond agreement contains certain
restrictive covenants, which includes restrictions on capital distributions among other restrictions.

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The Partnership entered into a Collateral Agency and Intercreditor Agreement, dated December 1, 1997, which required the establishment of certain funds
pursuant to the terms of the Intercreditor Agreement. Such funds are pledged as security for repayment of the 1997 Bonds. The payment of principal and interest on the 1997 Bonds is also secured by a
lien on and security interest in substantially all of the Partnership's (i) personal property owned or leased, (ii) project contracts (other than unassigned project contract interests,
which include the Site Lease discussed in Note 9 and the Partnership Agreement), (iii) revenues of the Partnership, (iv) permits and governmental approvals, and (v) so long
as any of the Tax-Exempt Bonds are outstanding, all of the Agency's right, title and interest in and to the Amended Lease Agreement, except for the right to receive rental payments
thereunder, and the Company Lease (collectively, the "Shared Collateral").

Pursuant
to the Reimbursement Agreement, dated December 1, 1997 with the Partnership, certain financial institutions have provided letters of credit for the account of the
Partnership in connection with the Facility. These letters of credit secure the Partnership's obligations under various project contracts (see Note 9) and its debt service requirements. The
Partnership had nine letters of credit outstanding totaling $71,520,662 and $67,944,976 as of December 31, 2002 and 2001, respectively. As of December 31, 2002 and 2001, the Partnership
had $10,000,000 available under a working capital facility. Amounts drawn under the working capital facility were $2,500,000 and $5,000,000 at December 31, 2002 and 2001, respectively. Amounts
outstanding under the working capital facility bear interest at LIBOR plus a margin of 0.6 percent (2.02 percent at December 31, 2002). The working capital facility matured on
January 30, 2003. The Partnership secured a $5,000,000 working capital facility in January 2003, which matures on December 17, 2005.

At
December 31, 2002, the future maturities of the debt are as follows:

Year Ending December 31,2003

$
5,280,0002004


4,520,0002005


3,690,0002006


4,950,0002007


5,930,000Thereafter


379,310,000403,680,000Less: current portion


(5,280,000
)$
398,400,000


9.    Commitments and Contingencies

Site Lease

On June 3, 1994, the Partnership entered into a lease agreement, as amended, whereby the Partnership leases the real estate where the Facility is located
through December 31, 2040. Under the terms of the lease agreement, the Partnership makes monthly rental payments in the amount of $20,612, which escalates annually beginning on
January 1, 1997. For the year ended December 31, 2002,

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---

2001 and 2000, the partnership incurred $1,131,599, $1,076,847 and $1,120,561, respectively, in rent expense and total future lease payments due are as follows:

Year Ending December 31,2003

$
523,2052004


561,9382005


603,6062006


598,6582007


627,912Thereafter


44,475,745$
47,391,064


Energy Sales Agreements

Under the terms of an Energy Sales Agreement, dated October 31, 1996, a public utility agreed to purchase electric and steam energy, up to a maximum of 286
megawatts of the electric energy and 1,000,000 pounds per hour of steam energy, generated by the Facility for a period of 40 years commencing on November 1, 1996 through
October 31, 2036. The Partnership is paid for electric energy based upon the prices defined in the Energy Sales Agreement, the quantity of kilowatts delivered and the electric energy escalation
factor, adjusted monthly by a weighted calculation of the GDPIPD and the average closing price of the New York Mercantile Exchange for Henry Hub ("NYMEX") gas deliveries. The public utility also pays
the Partnership for firm electrical capacity based upon contracted amounts per kilowatt, as determined in the Energy Sales Agreement, adjusted annually by a GDPIPD for the previous calendar year.

The
Partnership is paid for steam energy based upon prices defined in the Energy Sales Agreement, and the quantity of pounds delivered. The public utility also pays the Partnership for
firm steam capacity based upon contracted amounts per year, as determined in the Energy Sales Agreement, adjusted annually by a GDPIPD for the previous calendar year.

The
Partnership is paid for energy and steam conversions, as defined, upon request for such conversions by the public utility, based upon contracted prices and the quantity of kilowatts
or pounds delivered.

Under
the terms of an Amended and Restated Energy Sales Agreement, dated April 29, 1994, a local not-for-profit development corporation ("Development
Corp.") agreed to purchase all of their electric and steam energy requirements, up to a maximum of 10 megawatts of electric energy per year and 250 million pounds of steam per heating season,
as defined, which began on March 1, 1999 and terminates on December 31, 2039. The Partnership is paid for electric and steam energy based upon a contracted percentage of the public
utility's Tariff SC4-2, as published by the New York State Public Service Commission, and a contracted percentage of the Development Corp.'s avoided cost for steam, as adjusted monthly
based upon percentage changes in the Brooklyn Union Gas Tariff 5B, respectively.

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Fuel Supply and Transportation Agreements

Effective March 21, 1995, the Partnership entered into a gas purchase agreement, as amended, with a company whereby the Partnership has agreed to purchase
approximately 55 percent of the Facility's daily fuel gas requirements commencing on April 1, 1996 through March 31, 2016, at prices defined in the agreement adjusted monthly
based upon the average closing prices of the NYMEX and the quantity delivered. The agreement included an advance payment of $3,000,000 that is being amortized on a straight-line basis over
the initial term of the agreement commencing on March 1, 1997.

Effective
October 1993, the Partnership entered into two gas purchase agreements, as amended, with two companies whereby the Partnership has agreed to purchase approximately 27
and 18 percent of the Facility's daily fuel requirements, at prices defined in the agreements, adjusted monthly based upon the average closing prices of the NYMEX and the quantity delivered,
commencing on October 1, 1996 through September 30, 2016.

In
connection with the above gas purchase agreements, the Partnership entered into a firm transportation service contract with a company whereby the company agreed to transport to the
fuel manager approximately 45 percent of the Facility's daily natural gas requirements commencing on October 1, 1996 through September 30, 2016. The Partnership pays for these
services based upon prices defined in the firm transportation service contracts and published tariff rates.

Effective
September 25, 1996, the Partnership entered into a fuel management agreement, as amended and revised, with a company whereby the company agreed to manage and administer
all fuel supply and transportation agreements from October 1, 1996 through September 30, 2017. Under the fuel management agreement, the Partnership pays a fixed monthly fee and a
variable fee based on the quantity of fuel used in the Facility. The prices as defined in the fuel management agreement are to be adjusted annually by the GDPIPD.

In
conjunction with the fuel management agreement, the company released to the Partnership certain telescoped rights for the delivery to the fuel manager of approximately
55 percent of the daily fuel transportation from a transportation company. The Partnership pays the transportation company for transportation services based upon published gas tariff rates.

In
connection with the gas sales agreements and the firm transportation agreements noted above, the Partnership entered into a delivery agreement with a company whereby the company
agreed to deliver to the Facility 100 percent of the daily natural gas requirements commencing on October 1, 1996 through November 30, 2011. The Partnership pays the company based
upon prices defined in the delivery agreement.

Operation and Maintenance Agreement

On March 26, 2002, the Partnership renewed an operation and maintenance agreement with a company to provide all necessary services to operate and maintain
the Facility through December 31, 2005. Under the agreement, the Partnership agreed to reimburse the company for labor and certain other personnel costs and expenses and pay a monthly
management fee adjusted annually by the GDPIPD. In addition, the agreement provides for an incentive fee.

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10.    Related Party Transactions

MENY and B-41 have been or will be reimbursed for development, design, construction and other costs incurred on behalf of the Partnership. For the
year ended December 31, 2002, 2001 and 2000, reimbursements paid or payable to MENY totaled $2,075,321, $1,094,102 and $901,651, respectively and to B-41 totaled $246,463, $141,727
and $268,814, respectively.

Under
the terms of the Partnership Agreement, the Partnership is charged a royalty fee and a general partner management fee by MENY and B-41 equal to 4 percent and
5 percent of gross revenue in 2002, 2001 and 2000, respectively, as defined in the Partnership Agreement. Royalty and general partner management fees for the year ended December 31,
2002, 2001 and 2000 totaled $6,111,703, $8,704,667 and $8,706,379, respectively.

11.    York Bankruptcies

In March 2000, York filed a Form 8-K with the Securities and Exchange Commission indicating that an eighty-five percent
owned subsidiary of York (the Subsidiary), engaged in natural gas marketing, filed a voluntary petition for Chapter 11 bankruptcy. Per the 8-K, certain liabilities of the Subsidiary and a
number of contracts for the purchase and/or sale of natural gas have been guaranteed by York. On January 8, 2001, an agreement between York and the Subsidiary creditors was approved by the
bankruptcy court. This agreement terminated due to a lack of funding by York. On December 20, 2001, certain Subsidiary creditors filed an involuntary bankruptcy petition against York. York
filed a response to the petition on January 15, 2002, seeking to have it dismissed.

A
default occurred on the $150,000,000 12% Senior Secured Bonds due October 30, 2007 issued by York Power Funding (Cayman) Limited (the "Portfolio Bonds") when a scheduled
interest and principal payment was not made in full on October 30, 2001. The Portfolio Bonds were guaranteed by York Research Corporation ("York") and certain of its subsidiaries and were
secured by, among other things, York's operational power-generating projects.

After
settlement discussions with holders of the Portfolio Bonds, on June 7, 2002, York filed for a voluntary Chapter 11 bankruptcy. On October 31, 2002, the
bankruptcy court entered an order approving York's First Amended Plan of Reorganization, as modified, and on November 14, 2002, the Plan became effective. Pursuant to the Plan, York's existing
stock was cancelled, the holders of the Portfolio Bonds became the sole stockholders of York.

12.    Litigation

In February 1997, the construction contractor of the Brooklyn Navy Yard cogeneration plant facilities asserted general monetary claims under the turnkey
agreement against the Partnership, for damages in the amount of $137 million. The Partnership asserted general monetary claims against the contractor. In connection with a $407 million
non-recourse project refinancing in 1997, EME agreed to indemnify the Partnership and its partners from all claims and costs arising from or in connection with the contractor litigation, which
indemnity has been assigned to Partnership's lenders. During December 2002, the parties held mediation sessions and reached a settlement of all outstanding claims. A settlement agreement was
executed on January 17, 2003, and all litigation has been dismissed. At December 31, 2002, the Partnership recorded a liability of $32 million related to the settlement agreement
and recorded a corresponding increase to property, plant and equipment as part of the cost

336

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to complete construction of the cogeneration facilities. EME has indemnified the Partnership for payments due under this settlement agreement which are scheduled through 2006. In January 2003,
EME contributed $20 million to the Partnership under this indemnity.

On
March 14, 2002 the Partnership received notice from the New York State Department of Taxation and Finance of a proposed tax audit adjustment to the Partnership which if upheld
would cause the partnership to owe $7,300,000 in tax and penalties in connection with unpaid gas importation taxes. The notice of proposed adjustment relates to natural gas purchased by the Facility
during the period December 1, 1996 through November 30, 1999. The Partnership's management believes the Partnership is exempt from the gas importation tax requirement. The Partnership
has engaged legal counsel and intends to vigorously defend against the proposed adjustment should it become a final assessment. The ultimate outcome of this matter is uncertain at this time.

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Independent Auditor's Report

No.:
L.02 - 1694 - 03/US.

The
Shareholders,
Board of Commissioners and Board of Directors
PT Paiton Energy:

We
have audited the accompanying balance sheets of PT Paiton Energy as of 31 December 2002 and 2001, and the related statements of income, comprehensive income, changes in
shareholders' equity and cash flows for each of the years in the three-year period ended 31 December 2002. These financial statements are the responsibility of the Company'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 of America. 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 PT Paiton Energy as of 31 December 2002 and 2001,
and the results of its operations and its cash flows for each of the years in the three-year period ended 31 December 2002, in conformity with accounting principles generally
accepted in the United States of America.

As
discussed in Notes 2i to the financial statements, the Company changed its method of accounting for derivative instruments and hedging activities effective 1 January 2001.

Siddharta
Siddharta & Widjaja
Registered Public Accountants
License No. KEP-232/KM.6/2002

Drs. Istata Taswin Siddharta Public Accountant License No. 98.1.0192

Jakarta,
27 February 2003

338

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PT PAITON ENERGY        BALANCE SHEETS        31 DECEMBER 2002 AND 2001        (In thousands of U.S. Dollars, except per share amounts)

|                         |                               | Note                 |              | 2002      |         | 2001     
|------------------------ | ----------------------------- | -------------------- | ------------ | --------- | ------- | ---------
|ASSETS                   |                               |                      |              |           |         |          
|CURRENT ASSETS           |                               |                      |              |           |         |          
|                         | CASH AND CASH EQUIVALENTS     |                      | 2b,3         |           | 233,711 |          
|                         | ACCOUNTS RECEIVABLE           |                      |              |           | 83,204  |          
|                         | FUEL INVENTORY AND SUPPLIES   |                      | 2d,5         |           | 24,566  |          
|                         | PREPAYMENTS AND OTHER         |                      |              |           | 10,280  |          
|                         |                               |                      |              |           |         |          
|                         |                               | TOTAL CURRENT ASSETS |              |           |         | 351,761  
|                         |                               |                      |              |           |         |          
|PLANT AND EQUIPMENT, net |                               | 2e,6                 |              | 1,921,248 |         | 1,996,554
|                         |                               |                      |              |           |         |          
|OTHER ASSETS             |                               |                      |              |           |         |          
|                         | DEFERRED TAX ASSETS, net      |                      | 2m,13        |           | 4,203   |          
|                         | LONG-TERM RECEIVABLE          |                      | 21,4         |           | 453,270 |          
|                         | DEFERRED CHARGES, net         |                      | 2g,7         |           | 248,890 |          
|                         | DEFERRED FINANCING COSTS, net |                      | 2h           |           | 84,228  |          
|                         | PREPAYMENTS AND OTHER         |                      |              |           | 3,617   |          
|                         |                               |                      |              |           |         |          
|                         |                               | TOTAL OTHER ASSETS   |              |           |         | 794,208  
|                         |                               |                      |              |           |         |          
|                         |                               |                      | TOTAL ASSETS |           |         |          
|                         |                               |                      |              |           |         |          

See
Notes to the Financial Statements, which form an integral part of these financial statements.

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PT PAITON ENERGY        BALANCE SHEETS (Continued)        31 DECEMBER 2002 AND 2001        (In thousands of U.S. Dollars, except per share amounts)

|                                     |                                                 | Note                             |                                            | 2002    |           | 2001      |          
|------------------------------------ | ----------------------------------------------- | -------------------------------- | ------------------------------------------ | ------- | --------- | --------- | ---------
|LIABILITIES AND SHAREHOLDERS' EQUITY |                                                 |                                  |                                            |         |           |           |          
|CURRENT LIABILITIES                  |                                                 |                                  |                                            |         |           |           |          
|                                     | ACCOUNTS PAYABLE TO RELATED PARTIES             |                                  |                                            |         | 180,243   |           | 176,146  
|                                     | TAXES PAYABLE                                   |                                  |                                            |         | 2,891     |           | 5,011    
|                                     | ACCRUED FINANCE COSTS                           |                                  |                                            |         | 26,253    |           | 28,525   
|                                     | OTHER LIABILITIES                               |                                  |                                            |         | 62,614    |           | 34,932   
|                                     | CURRENT MATURITIES OF LONG-TERM LOANS           |                                  | 9                                          |         | 140,851   |           | 1,569,363
|                                     |                                                 |                                  |                                            |         |           |           |          
|                                     |                                                 | TOTAL CURRENT LIABILITIES        |                                            |         |           | 412,852   |          
|                                     |                                                 |                                  |                                            |         |           |           |          
|NON-CURRENT LIABILITIES              |                                                 |                                  |                                            |         |           |           |          
|                                     | LONG-TERM LOANS                                 |                                  | 9                                          |         | 2,228,488 |           | 817,002  
|                                     | ACCRUED FINANCE COSTS                           |                                  |                                            |         | 28,239    |           | 45,820   
|                                     | OTHER LIABILITIES                               |                                  |                                            |         | 7,143     |           |         
|                                     | DERIVATIVE FINANCIAL INSTRUMENTS                |                                  | 2i,10                                      |         | 98,296    |           | 77,707   
|                                     |                                                 |                                  |                                            |         |           |           |          
|                                     |                                                 | TOTAL NON-CURRENT LIABILITIES    |                                            |         |           | 2,362,166 |          
|                                     |                                                 |                                  |                                            |         |           |           |          
|COMMITMENTS AND CONTINGENCIES        |                                                 | 14                               |                                            |        |           |          |          
|                                     |                                                 |                                  |                                            |         |           |           |          
|SHAREHOLDERS' EQUITY                 |                                                 |                                  |                                            |         |           |           |          
|                                     | SHARE CAPITALpar value of USD 10,000 per share |                                  | 12                                         |         |           |           |          
|                                     |                                                 | Authorized capital30,600 shares |                                            |         |           |           |          
|                                     |                                                 | Issued and paid-up25,000 shares |                                            |         |           | 250,000   |          
|                                     |                                                 | Paid in advance                  |                                            |         |           | 56,000    |          
|                                     |                                                 |                                  |                                            |         |           |           |          
|                                     |                                                 |                                  |                                            | 306,000 |           | 306,000   |          
|                                     | SHARE PREMIUM                                   |                                  |                                            |         | 7,000     |           | 7,000    
|                                     | ACCUMULATED OTHER COMPREHENSIVE LOSS            |                                  |                                            |         | (68,807   | )         | (54,395  
|                                     | RETAINED EARNINGS (DEFICIT)                     |                                  |                                            |         | 48,006    |           | (16,245  
|                                     |                                                 |                                  |                                            |         |           |           |          
|                                     |                                                 | TOTAL SHAREHOLDERS' EQUITY       |                                            |         |           | 292,199   |          
|                                     |                                                 |                                  |                                            |         |           |           |          
|                                     |                                                 |                                  | TOTAL LIABILITIES AND SHAREHOLDERS' EQUITY |         |           |           | 3,067,217
|                                     |                                                 |                                  |                                            |         |           |           |          

See
Notes to the Financial Statements, which form an integral part of these financial statements.

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PT PAITON ENERGY        STATEMENTS OF INCOME        YEARS ENDED 31 DECEMBER 2002, 2001 AND 2000        (In thousands of U.S. Dollars, except per share amounts)

|                                                    |                                            | Note  |  | 2002     |          | 2001     |          | 2000     |         
|--------------------------------------------------- | ------------------------------------------ | ----- |  | -------- | -------- | -------- | -------- | -------- | --------
|REVENUES:                                           |                                            | 2c    |  |          |          |          |          |          |         
|                                                    | Net dependable capacity                    |       |  |          | 359,757  |          | 224,924  |          | 359,296 
|                                                    | Net electrical output                      |       |  |          | 91,416   |          | 43,003   |          | 30,726  
|                                                    |                                            |       |  |          |          |          |          |          |         
|                                                    |                                            |       |  | 451,173  |          | 267,927  |          | 390,022  |         
|                                                    |                                            |       |  |          |          |          |          |          |         
|OPERATING EXPENSES:                                 |                                            |       |  |          |          |          |          |          |         
|                                                    | Fuel                                       |       |  |          | (79,338  | )        | (42,350  | )        | (34,554 
|                                                    | Plant operations                           |       |  |          | (27,173  | )        | (13,574  | )        | (11,899 
|                                                    | Depreciation and amortization              |       |  |          | (83,115  | )        | (80,981  | )        | (80,127 
|                                                    | General, administrative and other          |       |  |          | (59,936  | )        | (31,095  | )        | (16,356 
|                                                    |                                            |       |  |          |          |          |          |          |         
|                                                    |                                            |       |  | (249,562 | )        | (168,000 | )        | (142,936 | )       
|                                                    |                                            |       |  |          |          |          |          |          |         
|OPERATING INCOME                                    |                                            |       |  | 201,611  |          | 99,927   |          | 247,086  |         
|                                                    |                                            |       |  |          |          |          |          |          |         
|OTHER INCOME (EXPENSES):                            |                                            |       |  |          |          |          |          |          |         
|                                                    | Interest income                            |       |  |          | 47,938   |          | 3,012    |          | 1,357   
|                                                    | (Loss) gain on foreign currency exchange   |       |  |          | (2,158   | )        | 134      |          | 2,180   
|                                                    | Interest expense and other financing costs |       |  |          | (154,607 | )        | (193,611 | )        | (189,259
|                                                    | Other income (expense)                     |       |  |          | 40       |          | 89       |          | (18     
|                                                    |                                            |       |  |          |          |          |          |          |         
|                                                    |                                            |       |  | (108,787 | )        | (190,376 | )        | (185,740 | )       
|                                                    |                                            |       |  |          |          |          |          |          |         
|INCOME (LOSS) BEFORE TAX                            |                                            |       |  | 92,824   |          | (90,449  | )        | 61,346   |         
|INCOME TAX (EXPENSE) BENEFIT                        |                                            | 2m,13 |  | (28,573  | )        | 25,849   |          | (18,705  | )       
|                                                    |                                            |       |  |          |          |          |          |          |         
|NET INCOME (LOSS)                                   |                                            |       |  | 64,251   |          | (64,600  | )        | 42,641   |         
|                                                    |                                            |       |  |          |          |          |          |          |         
|Weighted-average shares of common stock outstanding |                                            |       |  | 25,000   |          | 25,000   |          | 25,000   |         
|Basic earnings (loss) per share                     |                                            |       |  | 2,570    |          | (2,584   | )        | 1,706    |         

See
Notes to the Financial Statements, which form an integral part of these financial statements.

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PT PAITON ENERGY        STATEMENTS OF COMPREHENSIVE INCOME        YEARS ENDED 31 DECEMBER 2002, 2001 AND 2000        (In thousands of U.S. Dollars, except per share amounts)

|                                      |                                                                                                                                             | 2002    |         | 2001     |         | 2000  
|------------------------------------- | ------------------------------------------------------------------------------------------------------------------------------------------- | ------- | ------- | -------- | ------- | ------
|Net income (loss)                     |                                                                                                                                             | 64,251  |         | (64,600  | )       | 42,641
|                                      |                                                                                                                                             |         |         |          |         |       
|Other comprehensive loss, net of tax: |                                                                                                                                             |         |         |          |         |       
|                                      | Cumulative effect of change in accounting for derivative financial instruments, net of tax benefit of USD 20,058                            |         |        |          | (46,802 | )     
|                                      | Unrealized loss on derivative financial instruments, net of tax benefit of USD 15,421 and USD 9,767 for 2002 and 2001, respectively         |         | (35,982 | )        | (22,791 | )     
|                                      | Reclassification adjustment for losses included in net income (loss), net of tax of USD 9,244 and USD 6,513 for 2002 and 2001, respectively |         | 21,570  |          | 15,198  |       
|                                      |                                                                                                                                             |         |         |          |         |       
|Other comprehensive loss              |                                                                                                                                             | (14,412 | )       | (54,395  | )       |      
|                                      |                                                                                                                                             |         |         |          |         |       
|COMPREHENSIVE INCOME (LOSS)           |                                                                                                                                             | 49,839  |         | (118,995 | )       | 42,641
|                                      |                                                                                                                                             |         |         |          |         |       

See
Notes to the Financial Statements, which form an integral part of these financial statements.

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PT PAITON ENERGY        STATEMENTS OF CHANGES IN SHAREHOLDERS' EQUITY        YEARS ENDED 31 DECEMBER 2002, 2001 AND 2000        (In thousands of U.S. Dollars, except per share amounts)

|                            |                          | Share
capital |   | Share
premium |   | Accumulated
other
comprehensive
loss |         | Retained
earnings
(deficit) |         | Total
shareholders'
equity |        
|--------------------------- | ------------------------ | ------------- | - | ------------- | - | ------------------------------------ | ------- | --------------------------- | ------- | -------------------------- | -------
|Balance at 31 December 1999 |                          | 306,000       |   | 7,000         |   |                                     |         | 5,714                       |         | 318,714                    |        
|                            | Net income for the year  |               |  |               |  |                                      |        |                             | 42,641  |                            | 42,641 
|                            |                          |               |   |               |   |                                      |         |                             |         |                            |        
|Balance at 31 December 2000 |                          | 306,000       |   | 7,000         |   |                                     |         | 48,355                      |         | 361,355                    |        
|                            | Net loss for the year    |               |  |               |  |                                      |        |                             | (64,600 | )                          | (64,600
|                            | Other comprehensive loss |               |  |               |  |                                      | (54,395 | )                           |        |                            | (54,395
|                            |                          |               |   |               |   |                                      |         |                             |         |                            |        
|Balance at 31 December 2001 |                          | 306,000       |   | 7,000         |   | (54,395                              | )       | (16,245                     | )       | 242,360                    |        
|                            | Net income for the year  |               |  |               |  |                                      |        |                             | 64,251  |                            | 64,251 
|                            | Other comprehensive loss |               |  |               |  |                                      | (14,412 | )                           |        |                            | (14,412
|                            |                          |               |   |               |   |                                      |         |                             |         |                            |        
|Balance at 31 December 2002 |                          | 306,000       |   | 7,000         |   | (68,807                              | )       | 48,006                      |         | 292,199                    |        
|                            |                          |               |   |               |   |                                      |         |                             |         |                            |        

See
Notes to the Financial Statements, which form an integral part of these financial statements.

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PT PAITON ENERGY        STATEMENTS OF CASH FLOWS        YEARS ENDED 31 DECEMBER 2002, 2001 AND 2000        (In thousands of U.S. Dollars, except per share amounts)

|                                               |                                                                                                    | 2002                                                  |                                     | 2001    |         | 2000    |        
|---------------------------------------------- | -------------------------------------------------------------------------------------------------- | ----------------------------------------------------- | ----------------------------------- | ------- | ------- | ------- | -------
|CASH FLOWS FROM OPERATING ACTIVITIES:          |                                                                                                    |                                                       |                                     |         |         |         |        
|                                               | Net income (loss)                                                                                  |                                                       | 64,251                              |         | (64,600 | )       | 42,641 
|                                               | Adjustments to reconcile net income (loss) to net cash provided by (used in) operating activities: |                                                       |                                     |         |         |         |        
|                                               |                                                                                                    | Depreciation and amortization                         |                                     | 83,115  |         | 80,981  |        
|                                               |                                                                                                    | Loss on retirement or disposal of plant and equipment |                                     | 3,553   |         |        |        
|                                               |                                                                                                    | Provision for deferred income taxes                   |                                     | 28,573  |         | (25,849 | )      
|                                               |                                                                                                    | Non-cash interest expense                             |                                     | 1,362   |         | 7,383   |        
|                                               |                                                                                                    | Changes in assets and liabilities:                    |                                     |         |         |         |        
|                                               |                                                                                                    |                                                       | Accounts receivable                 |         | (53,940 | )       | (8,622 
|                                               |                                                                                                    |                                                       | Fuel inventory and supplies         |         | (16,123 | )       | (434   
|                                               |                                                                                                    |                                                       | Prepayments and other               |         | (618    | )       | 6,127  
|                                               |                                                                                                    |                                                       | Taxes payable and other liabilities |         | 32,705  |         | 16,645 
|                                               |                                                                                                    |                                                       | Accounts payable to related parties |         | 7,071   |         | 14,920 
|                                               |                                                                                                    |                                                       | Accrued finance costs               |         | (2,272  | )       | (420   
|                                               |                                                                                                    |                                                       |                                     |         |         |         |        
|                                               |                                                                                                    | NET CASH PROVIDED BY (USED IN) OPERATING ACTIVITIES   |                                     | 147,677 |         | 26,131  |        
|                                               |                                                                                                    |                                                       |                                     |         |         |         |        
|CASH FLOWS FROM INVESTING ACTIVITIES:          |                                                                                                    |                                                       |                                     |         |         |         |        
|                                               | Acquisition of fixed assets                                                                        |                                                       | (2,046                              | )       | (2,813  | )       | (14,721
|                                               | Proceeds from sale of fixed assets                                                                 |                                                       | 50                                  |         |        |         |       
|                                               |                                                                                                    |                                                       |                                     |         |         |         |        
|                                               |                                                                                                    | NET CASH USED IN INVESTING ACTIVITIES                 |                                     | (1,996  | )       | (2,813  | )      
|                                               |                                                                                                    |                                                       |                                     |         |         |         |        
|CASH FLOWS FROM FINANCING ACTIVITIES:          |                                                                                                    |                                                       |                                     |         |         |         |        
|                                               | Proceeds from long-term loans                                                                      |                                                       |                                    |         | 46,980  |         |       
|                                               | Repayment of long-term loans                                                                       |                                                       | (20,000                             | )       |        |         |       
|                                               | Advances provided by related parties                                                               |                                                       |                                    |         |        |         | 151,755
|                                               | Proceeds from financing costs refunded                                                             |                                                       |                                    |         | 1,858   |         |       
|                                               |                                                                                                    |                                                       |                                     |         |         |         |        
|                                               |                                                                                                    | NET CASH (USED IN) PROVIDED BY FINANCING ACTIVITIES   |                                     | (20,000 | )       | 48,838  |        
|                                               |                                                                                                    |                                                       |                                     |         |         |         |        
|Net increase in cash and cash equivalents      |                                                                                                    | 125,681                                               |                                     | 72,156  |         | 16,743  |        
|Cash and cash equivalents at beginning of year |                                                                                                    | 108,030                                               |                                     | 35,874  |         | 19,131  |        
|                                               |                                                                                                    |                                                       |                                     |         |         |         |        
|Cash and cash equivalents at end of year       |                                                                                                    | 233,711                                               |                                     | 108,030 |         | 35,874  |        
|                                               |                                                                                                    |                                                       |                                     |         |         |         |        
|Supplemental cash flow disclosures:            |                                                                                                    |                                                       |                                     |         |         |         |        
|                                               | Cash paid for interest                                                                             |                                                       | 155,517                             |         | 186,965 |         | 182,892
|                                               | Conversion of advances provided by related parties to long-term loans                              |                                                       |                                    |         | 216,022 |         |       
|                                               | Conversion of accounts payable to related parties to long-term loans                               |                                                       | 2,974                               |         |        |         |       

See
Notes to the Financial Statements, which form an integral part of these financial statements.

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PT PAITON ENERGY        NOTES TO THE FINANCIAL STATEMENTS        YEARS ENDED 31 DECEMBER 2002, 2001 AND 2000        (In thousands of U.S. Dollars, except per share amounts)

1. GENERAL

a.    PT
Paiton Energy (the "Company") is an Indonesian domiciled company located at Menara Batavia 8th floor, Jalan K.H. Mas Mansyur Kav. 126, Jakarta, which was
established within the framework of Foreign Capital Investment Laws No. 1, 1967 and No. 11, 1970 by deed of notary public Sutjipto SH dated 11 February 1994, No. 64 with
amendment effected by deed of the same notary public dated 11 January 1995, No. 56. These deeds were approved by the Minister of Justice under
No. C2-1-682.HT.01.01.Th.95 on 6 February 1995. The Articles of Association were most recently amended by deed of the same notary public dated 20
November 1998, No. 50; this amendment changed the name of the Company and increased authorized capital. This deed was approved by the Minister of Justice under
No. C-2340.HT.01.04.Th.99 on 3 February 1999.

b.    In
accordance with Article 3 of the Articles of Association, approval by the Capital Investment Coordination Board and the Power Purchase Agreement (the "PPA"), as
amended, the Company's objective and purpose is to engage in any business and activity in the sector of electric power supply, and to build, own and operate a coal-fired power generating
facility (the "Project") consisting of two units located in East Java.

2. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

The accounting and reporting policies followed by the Company are in accordance with accounting principles generally accepted in the United States of America.

The
significant accounting policies, applied in the preparation of the financial statements for the years ended 31 December 2002, 2001 and 2000, were as follows:

a.Basis of preparation of financial statements

The
financial statements are presented in thousands of U.S. Dollars. The Company's functional and reporting currency is the U.S. Dollar as a majority of the Company's cash flows, selling
prices, expenses and financing are denominated in U.S. Dollars. The statements of cash flows have been prepared under the indirect method.

b.Cash and cash equivalents

The
Company considers investments purchased with maturities of three months or less to be cash equivalents.

c.Revenue recognition

In
2002, revenues were recognized upon the availability of net dependable capacity and the delivery of net electrical output to PT Perseroan Listrik Negara ("PLN"), the Indonesian
Government owned electric utility company, and recorded on the basis of prices determined under certain formulae set forth in the PPA, as amended. See Note 14a. PLN is obligated to pay for net
dependable capacity upon its availability. PLN is obligated to pay for net electrical output as it is delivered.

Revenues
for the years ended 31 December 2001 and 2000 represent the amounts billed to PLN under the Interim, Phases I, II and III Interim Agreements, and Binding Term Sheet for
energy

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delivered in the respective financial reporting period plus the estimated recoverable value of arrearages relating to capacity charges and fixed operating costs under the PPA which have not been paid
by PLN.

d.Fuel inventory

Fuel
inventory is valued at the lower of cost or net realizable value. Cost is determined based on the weighted-average method.

e.Plant and equipment

Plant
and equipment are recorded at cost including interest on funds borrowed to finance construction of the Project. Depreciation is calculated on a straight-line basis over
the following estimated useful lives:

Plant assets and facilities

30 yearsFurniture and equipment

4 years


Certain
of the Company's plant assets and facilities require major maintenance on a periodic basis. These costs are expensed as incurred.

f.Accounting for the impairment of long-lived assets

Statement
of Financial Accounting Standards ("SFAS") No. 144, "Accounting for the Impairment or Disposal of Long-Lived Assets", provides a single accounting model for
long-lived assets to be disposed of. The standard also changes the criteria for classifying an asset as held for sale; and broadens the scope of businesses to be disposed of that qualify
for reporting as discontinued operations and changes the timing of recognizing losses on such operations. The Company adopted the standard on 1 January 2002. The adoption of the standard did
not affect the Company's financial statements.

In
accordance with the standard, long-lived assets, such as property, plant, and equipment, and purchased intangibles subject to amortization, are reviewed for impairment
whenever events or changes in circumstances indicate that the carrying amount of an asset may not be recoverable. Recoverability of assets to be held and used is measured by a comparison of the
carrying amount of an asset to estimated undiscounted future cash flows expected to be generated by the asset. If the carrying amount of an asset exceeds its estimated future cash flows, an impairment
charge is recognized by the amount by which the carrying amount of the asset exceeds the fair value of the asset. Assets to be disposed of would be separately presented in the balance sheet and
reported at the lower of the carrying amount or fair value less costs to sell, and are no longer depreciated.

The
assets and liabilities of a disposed group classified as held for sale would be presented separately in the appropriate asset and liability sections of the balance sheet.

Prior
to the adoption of SFAS No. 144, the Company accounted for long-lived assets in accordance with SFAS No. 121, "Accounting for Impairment of
Long-Lived Assets and for Long-Lived Assets to be Disposed Of."

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g.Deferred charges

Costs
incurred for the design, construction and installation of the Special Facilities in accordance with the terms of the PPA are deferred and amortized on a straight-line
basis over 30 years.

h.Deferred financing costs

Costs
incurred to obtain financing are deferred and are amortized as an adjustment to interest expense on a basis which approximates the effective interest rate method over the terms of
the relating financing agreements. Periodic commitment fees incurred subsequent to obtaining financing are treated as interest. Accumulated amortization of these costs amounted to USD 82,450 and USD
63,507 at 31 December 2002 and 2001, respectively.

i.Derivatives

The
Company enters into interest rate swap agreements in its management of interest cost exposures. The interest rate swaps, which hedge interest rates on certain indebtedness involve
the exchange of
floating rate to fixed rate interest payment obligations over the life of the agreements without the exchange of the underlying notional amounts. The Company is exposed to loss if one or more of the
counterparties default. Consequently, the Company's exposure to credit loss is significantly less than the contracted amount.

On
1 January 2001, the Company adopted SFAS No. 133, "Accounting for Derivative Instruments and Certain Hedging Activities" and SFAS No. 138, "Accounting for Certain
Derivative Instruments and Certain Hedging Activities, an Amendment of SFAS 133." SFAS Nos. 133 and 138 require that all derivative instruments be recorded on the balance sheet at their
respective fair values.

In
accordance with the transition provisions of SFAS No. 133, the Company recorded a cumulative effect adjustment of USD 46,802, net of tax of USD 20,058 in accumulated other
comprehensive loss to recognize at fair value all derivatives that are designated as cash-flow hedging instruments. See Note 10. Proforma comprehensive income or loss amounts for
2000 have not been presented as it was impractical to compute such amounts.

On
the date a derivative contract is entered into, the Company designates the derivative as either a hedge of the fair value of a recognized asset or liability or of an unrecognized firm
commitment (fair value hedge), a hedge of a forecasted transaction or the variability of cash flows to be received or paid related to a recognized asset or liability (cash flow hedge), a
foreign-currency fair-value or cash-flow hedge (foreign currency hedge), or a hedge of a net investment in a foreign operation. For all hedging relationships, the Company
formally documents the hedging relationship and its risk-management objective and strategy for undertaking the hedge, the hedging instrument, the item, the nature of the risk being hedged,
how the hedging instrument's effectiveness in offsetting the hedged risk will be assessed, and a description of the method of measuring ineffectiveness. This process includes linking all derivatives
that are designated as fair-value, cash-flow, or foreign-currency hedges to specific assets and liabilities on the balance sheet or to specific firm commitments or forecasted
transactions. The Company also formally assesses, both at the hedge's inception and on an ongoing basis, whether the derivatives that are used in hedging transactions are highly effective in
offsetting changes in fair values

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or cash flows of hedged items. When it is determined that a derivative is not highly effective as a hedge or that it has ceased to be a highly effective hedge, the Company discontinues hedge
accounting prospectively.

Changes
in the fair value of a derivative that is highly effective and that is designated and qualifies as a fair-value hedge, along with the loss or gain on the hedged asset
or liability or unrecognized firm commitment of the hedged item that is attributable to the hedged risk, are recorded in earnings. Changes in the fair value of a derivative that is highly effective
and that is designated and qualifies as a cash-flow hedge are recorded in other comprehensive income to the extent that the derivative is effective as a hedge, until earnings are affected
by the variability in cash flows of the designated hedged item. Changes in the fair value of derivatives that are highly effective as hedges and that are designated and qualify as foreign-currency
hedges are recorded in either earnings or other comprehensive income, depending on whether the hedge transaction is a fair-value hedge or a cash-flow hedge. However, if a
derivative is used as a hedge of a net investment in a foreign operation, its changes in fair value, to the
extent effective as a hedge, are recorded in the cumulative translation adjustments account within other comprehensive income. The ineffective portion of the change in fair value of a derivative
instrument that qualifies as either a fair-value hedge or a cash-flow hedge is reported in earnings. Changes in the fair value of derivative trading instruments are reported in
current period earnings.

j.Comprehensive income

Comprehensive
income is defined as the change in equity (net assets) of a business enterprise during a period from transactions and other events and circumstances from
non-owner sources. It includes all changes in equity during a period except those resulting from investments by owners and distributions to owners. For the Company, other comprehensive
income (loss) consists of changes in the fair market value of derivatives.

k.Foreign currency translation

The
books and records of the Company are maintained in United States Dollars as permitted under the license granted by the Ministry of Finance of the Republic of Indonesia through letter
No. KEP-194/PJ.42/1994 dated 29 September 1994. Transactions in Indonesian Rupiah and in currencies other than United States Dollars are translated at the rate of exchange
prevailing at the date of the transaction. Monetary assets and monetary liabilities outstanding in Indonesian Rupiah and in other currencies at balance sheet date are translated into United States
Dollars at rates prevailing as of that date. Realized and unrealized gains and losses arising from exchange rate fluctuations are reflected in the statement of income.

l.Long-term receivable

The
Company applies Accounting Principles Board (APB) Opinion No. 21, "Interest on Receivables and Payables," to account for its receivable for the restructuring settlement
payments from PLN. The Company has reflected the present value of the restructuring settlement payments, based on a discount rate of 10%. Amortization of the discount is reported as interest income in
the statement of income.

348

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2. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (Continued)

m.Income tax expense

Deferred
taxes are provided based on the asset-liability method whereby deferred tax assets are recognized for deductible temporary differences, and operating loss and tax credit
carryforwards, and deferred tax liabilities are recognized for taxable temporary differences. Temporary differences are the differences between the reported amounts of assets and liabilities and their
tax bases. Deferred tax assets are reduced by a valuation allowance when, in the opinion of management, it is more likely than not that some portion or all of the deferred tax assets will not be
realized. Deferred tax assets and liabilities are adjusted for the effects of changes in tax laws and rates on the date of enactment.

n.Use of estimates

The
preparation of financial statements in conformity with generally accepted accounting principles requires management to make estimates and assumptions that affect the reported amounts
of assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting period.
Actual results could differ from those estimates.

o.New accounting standards

In
June 2001, the FASB issued SFAS No. 143, "Accounting for Asset Retirement Obligations," which is effective on 1 January 2003. The standard requires entities to
record the fair value of a liability for an
asset retirement obligation in the period in which it is incurred. When the liability is initially recorded, the entity capitalizes a cost by increasing the carrying amount of the related
long-lived asset. Over time, the liability is increased to its present value each period, and the capitalized cost is depreciated over the useful life of the related asset. Upon settlement
of the liability, an entity either settles the obligation for its recorded amount or incurs a gain or loss upon settlement. The Company has adopted this standard effective 1 January 2003.
Management does not believe that the new standard will have a material effect on the Company's financial statements.

Effective
1 January 2002, the Company adopted SFAS No. 142, "Goodwill and Other Intangible Assets." The Company did not have goodwill or intangible assets at any time
during 2002, and accordingly the adoption of the standard did not have an effect on the Company's financial statements.

In
April 2002, the FASB issued SFAS No. 145, "Rescission of FASB Statements No. 4, 44, and 64, Amendment of FASB Statement No. 13, and Technical Corrections,"
which supersedes previous guidance for reporting gains and losses from extinguishment of debt and accounting for leases, among other things. The provisions of the Statement related to the rescission
of Statement No. 4 is applied in fiscal years beginning after 15 May 2002. Earlier application of these provisions is encouraged. The provisions of the Statement related to Statement
No. 13 were effective for transactions occurring after 15 May 2002, with early application encouraged. The adoption of this standard is not expected to have a material effect on the
Company's financial statements.

In
July 2002, the FASB issued SFAS No. 146, "Accounting for Costs Associated with Exit or Disposal Activities," which is effective on 1 January 2003. The standard
requires that liabilities for costs associated with exit or disposal activities initiated after 31 December 2002 be recognized when incurred,

349

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rather than at the date of a commitment to an exit or disposal plan. Management does not expect this standard will have a material effect on the Company's financial statements.

In
November 2002, the FASB issued Interpretation No. 45, "Guarantor's Accounting and Disclosure Requirements for Guarantees, Including Indirect Guarantees of Indebtedness
to Others, an interpretation of FASB Statements No. 5, 57 and 107 and a rescission of FASB Interpretation No. 34." This Interpretation elaborates on the disclosures to be made by a
guarantor in its interim and annual financial statements about its obligations under guarantees issued. The Interpretation also clarifies that a guarantor is required to recognize, at inception of a
guarantee, a liability for the fair value of the obligation undertaken. The initial recognition and measurement provisions of the Interpretation are applicable to guarantees issued or modified after
31 December 2002 and are not expected to have a material effect on the Company's financial statements. The disclosure requirements are effective for financial statements of interim or annual
periods ending after 15 December 2002.

3. CASH AND CASH EQUIVALENTS

2002

2001Cash on hand

3

3Cash in banks

231,758

107,145Time deposits



288Call deposits

1,950

594233,711

108,030


4. LONG-TERM RECEIVABLE

As discussed in Note 14a, the Company and PLN entered into the amendments to the PPA, which among other matters provides for restructuring settlement
payments for the settlement of arrearages of amounts billed by the Company to PLN. The Company has reflected the present value of the restructuring settlement payments, based on a discount rate of
10%, as a long-term receivable totaling USD 453,270 and USD 455,803 at 31 December 2002 and 2001, respectively. In 2002, the Company received restructuring settlement payments
aggregating USD 48,000 of which USD 2,534 was accounted for as collections of the receivables owed by PLN. The remainder totaling USD 45,466 was accounted for as interest income.

2002

2001Total restructuring settlement payments

1,392,000

1,440,000Less: unamortized discount

938,730

984,197Long-term receivable less unamortized discount

453,270

455,803


350

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5. FUEL INVENTORY AND SUPPLIES

2002

2001Coal inventory

19,528

7,138Fuel oil inventory

68

120Supplies

4,970

1,18524,566

8,443


6. PLANT AND EQUIPMENT

a.    Plant
and equipment are comprised of the following:

2002Beginning
balance

Additions

Retirements &
disposals

Ending
balanceAt cost:Plant assets and facilities

2,171,605

796

(3,603
)
2,168,798Furniture and equipment

6,513

1,222

(132
)
7,6032,178,118

2,018

(3,735
)
2,176,401Accumulated depreciation:Plant assets and facilities

(177,321
)
(72,514
)


(249,835
)Furniture and equipment

(4,243
)
(1,207
)
132

(5,318
)(181,564
)
(73,721
)
132

(255,153
)Net book value

1,996,554

(71,703
)
(3,603
)
1,921,248


2001Beginning
balance

Additions

Ending
BalanceAt cost:Plant assets and facilities

2,102,632

68,973

2,171,605Furniture and equipment

5,421

1,092

6,5132,108,053

70,065

2,178,118Accumulated depreciation:Plant assets and facilities

(106,983
)
(70,338
)
(177,321
)Furniture and equipment

(2,993
)
(1,250
)
(4,243
)(109,976
)
(71,588
)
(181,564
)Net book value

1,998,077

(1,523
)
1,996,554


351

---



6. PLANT AND EQUIPMENT (Continued)

b.    Depreciation
charged to operating expenses amounted to USD 73,721, USD 71,588, and USD 70,686 in 2002, 2001 and 2000, respectively.

c.    Substantially
all of the Company's assets have been pledged as collateral for the repayment of long-term debt (see Note 9).

7. DEFERRED CHARGES

2002

2001Special facilities costs deferred

281,814

281,786Less accumulated amortization

(32,924
)
(23,530
)Net deferred charges

248,890

258,256


Deferred
charges represent costs incurred for the design, construction and installation of the Special Facilities in accordance with the terms of the PPA. The Special Facilities
constitute electrical interconnection facilities at the Paiton Complex, the expansion of the Paiton Complex's water intake and discharge canals and site preparation work at the Paiton Complex. The
Company had the care, custody, and control and bore the risk of loss with respect to the Special Facilities until they were accepted by PLN in 1999.

The
Special Facilities recorded in these financial statements are owned by PLN; however, the Company has the right to use the Special Facilities throughout the term of the PPA, as
amended.

Amortization
charged to operating expenses amounted to USD 9,394, USD 9,393, and USD 9,441 in 2002, 2001 and 2000, respectively.

8. RELATED PARTY TRANSACTIONS

a.    Reimbursable
costs

Certain
costs were incurred by related parties on behalf of, and charged to the Company. These costs aggregated approximately USD 3,813, USD 2,454 and USD 4,333 in 2002, 2001 and 2000,
respectively.

b.    Certain
other transactions with related parties are also discussed in Note 9 and Note 14.

352

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9. LONG-TERM LOANS

Long-term loans were comprised as follows:

|                                      |                                       | 2002      |         | 2001       |        
|------------------------------------- | ------------------------------------- | --------- | ------- | ---------- | -------
|Senior Debt Facilities                |                                       |           |         |            |        
|                                      | USEXIM Facility                       |           | 507,882 |            | 514,363
|                                      | JEXIM Facilitytranche A              |           | 506,398 |            | 513,000
|                                      | JEXIM Facilitytranche B              |           | 337,603 |            | 342,000
|                                      | OPIC Facility                         |           | 197,480 |            | 200,000
|                                      |                                       |           |         |            |        
|                                      |                                       | 1,549,363 |         | 1,569,363  |        
|                                      |                                       |           |         |            |        
|Senior Debt Funding Loan              |                                       | 180,000   |         | 180,000    |        
|                                      |                                       |           |         |            |        
|Subordinated Loans                    |                                       |           |         |            |        
|                                      | Edison Mission Energy Asia Pte., Ltd. |           | 176,004 |            | 176,004
|                                      | Paiton Power Financing B.V.           |           | 143,018 |            | 143,018
|                                      | Capital Indonesia Power I C.V.        |           | 54,978  |            | 54,978 
|                                      |                                       |           |         |            |        
|                                      |                                       | 374,000   |         | 374,000    |        
|                                      |                                       |           |         |            |        
|Series B Subordinated Loans           |                                       |           |         |            |        
|                                      | Edison Mission Energy Asia Pte., Ltd. |           | 137,296 |            | 135,896
|                                      | Paiton Power Financing B.V.           |           | 92,949  |            | 91,812 
|                                      | Capital Indonesia Power I C.V.        |           | 35,731  |            | 35,294 
|                                      |                                       |           |         |            |        
|                                      |                                       | 265,976   |         | 263,002    |        
|                                      |                                       |           |         |            |        
|Total                                 |                                       | 2,369,339 |         | 2,386,365  |        
|Current maturities of long-term loans |                                       | (140,851  | )       | (1,569,363 | )      
|                                      |                                       |           |         |            |        
|Non-current portion                   |                                       | 2,228,488 |         | 817,002    |        
|                                      |                                       |           |         |            |        

Senior Debt Facilities

On 31 March 1995, the Company entered into an agreement (the "Common Agreement", as amended as of 25 March 1996) with the following lenders: The
Export-Import Bank of the United States ("USEXIM"), Japan Bank for International Cooperation ("JBIC"), as successors in interest to The Export-Import Bank of Japan ("JEXIM"), and Overseas Private
Investment Corporation ("OPIC"). The principal effect of the Common Agreement is to establish certain uniform terms which are applicable to the senior debt facilities provided such as funding,
payments and prepayments, conditions precedent, representations and warranties, affirmative and negative covenants, and events of default. Separate financing agreements for the senior debt facilities
have been entered into with each of the lenders who were to provide an aggregate of USD 1,820,000. All of the senior debt facilities are variable rate based loans except for the JEXIM tranche A loan
which bears interest at 9.44%. The Company has entered into interest rate swap agreements on a portion of its debt to reduce the impact of changes in interest rates on its floating rate
long-term debt. See Note 10.

353

---

The
obligations of the Company are collateralized by pledges of all of the Company's capital stock and liens on and security interests in substantially all of the Company's assets
(including plant assets), its rights under various agreements, all of the Company's revenues and all insurance proceeds payable to the Company. The financing agreements contain restrictions, which,
among other items, require the Company to comply with various administrative requirements. The agreements with lenders also require the Company to pay certain fees.

Interest
on loans is due on a quarterly basis in arrears, and coincides with the scheduled principal payments dates. Repayment of the loan principal becomes due over a period of twelve
years commencing from 1999. None of the scheduled repayments of principal totaling approximately USD
453,761 as of 31 December 2002 were made during 2000 and 2001, and only USD 20,000 was repaid in 2002. See the following paragraph concerning the waivers of events of default.

In
response to PLN's failure to pay invoices submitted to it under the PPA (see Note 14a), on 15 October 1999, the Company entered into an Interim Arrangement Agreement
(the "Interim Arrangement"), as amended as of 30 December 2002 with the senior lenders. Under this agreement, the parties agree to enter into certain waivers pursuant to the Financing
Agreements, and amendments to the Common Agreement, in order to establish an interim arrangement under the Financing Agreements. These waivers include events of default that may exist solely as a
result of the failure of the Company to repay principal amounts on the scheduled dates therefore which occur during the term of the Interim Arrangement. Interest and fees continue to be paid on a
timely basis. This Interim Arrangement terminated on 13 February 2003, when the Company and all the lenders reached an agreement on restructuring the terms of the senior debt facilities. This
restructuring will be accounted for as a troubled debt restructuring in 2003 with no change to the carrying value of the debt.

At
31 December 2002, the amounts due under the senior debt facilities were classified in the balance sheet based on restructured terms for the maturity of the debt. At 31
December 2001, all amounts due under the senior debt facilities were classified as a current liability in the balance sheet as the Company was in default of the debt repayment provisions of the
senior debt financing agreements.

Senior Debt Funding Loan

On 28 March 1996, Paiton Energy Funding B.V., a Netherlands corporation (the "Issuer") issued USD 180,000 of senior secured bonds (the "Bonds") to certain
institutional investors. The net proceeds from the sale of the bonds were used by the Issuer to acquire certain senior indebtedness which consisted of loans made to the Company by various commercial
banks and financial institutions under the Commercial Banks Facilitytranche A in place as of 31 March 1996. Upon closing of the offering for the Bonds, such senior indebtedness was
replaced by the Senior Debt Funding Loan and the payment terms and the interest rate which applied to the such indebtedness were amended to contain terms which are identical to the Bonds. The Bonds
bear interest at 9.34% per annum with interest payable on a quarterly basis commencing in May 1996. The Bonds mature in 2014 and principal payments commence in 2008.

The
Company has unconditionally guaranteed the payment obligations of the Issuer in respect of the Bonds. The Senior Debt Funding Loan and the guarantee will be secured, on a pari passubasis

354

---

with the other senior debt, by pledges of the Company's capital shares and liens on, and security interests in, substantially all of the assets of the Company. The maximum potential amount of
undiscounted future payments that the Company could be required to make under the guarantee is USD 180,000, which is the current carrying amount of the Senior Debt Funding Loan reflected in these
financial statements.

Subordinated Loans

On 31 March 1995, the Company entered into a subordinated loan agreement with Edison Mission Energy Asia Pte., Ltd., Paiton Power Financing B.V.,
and Capital Indonesia Power I C.V. (the "Subordinated Lenders"). Each of the Subordinated Lenders is affiliated with shareholders of the Company. Under this agreement, the Subordinated Lenders or
their affiliates are obligated to make subordinated loans to the Company in a maximum aggregate amount of USD 487,438. The subordinated loans bear no interest prior to the last day of the availability
period (such day has been established as 15 October 1999). After the availability period, interest on the outstanding principal amount is determined at 15% per annum. The repayment of any
outstanding principal will not commence until 27 years after the completion of the Project. The Subordinated Lenders cancelled the Company's interest obligation for the years 2002, 2001 and
2000 on or before the commencement of each of the respective years.

Series B Subordinated Loans

In 2001, the Company entered into the 1999 Series B Subordinated Loan Agreement with the Subordinated Lenders. Under this agreement, the Subordinated
Lenders shall make loans to the Company in a maximum aggregate amount of USD 300,000. The 1999 Series B Subordinated Loans bear no interest until such time as the Company and Subordinated
Lenders agree otherwise in writing. The repayment of any outstanding principal will not commence until 27 years after the completion of the Project.

The
subordinated loans referred to in the two preceding paragraphs are subordinated to the senior debt facilities provided under the Common Agreement and the Senior Debt Funding Loan.

The
following table presents the approximate annual maturities of long-term debt for the five years after 31 December 2002:

2003

140,8512004

140,8512005

140,8512006

140,8512007

140,851Thereafter

1,665,0842,369,339


355

---



10. DERIVATIVE FINANCIAL INSTRUMENTS

The Company has entered into interest rate swap agreements on a portion of its debt to reduce the impact of changes in interest rates on its floating rate
long-term debt. Under the agreements, the Company will receive or pay interest on the differential of notional principal amounts based on the London Interbank Offering Rate ("LIBOR") and
the same notional amounts based on a weighted average fixed interest rate of 7.3% from July 1995 until August 1999, and 9% from August 1999 through August 2011 including
the credit spread. At 31 December 2002, LIBOR was 1.4% per annum. Payments are made at the end of calculation periods (scheduled three-month periods) which commence primarily in 1995 and 1999
and end in 1999 and 2011. The notional principal amounts vary over the calculation periods; however, they were intended to correspond with anticipated borrowing levels over the period of the
long-term financing.

In
accordance with SFAS No. 133, as amended, the Company recorded a liability for the loss on these interest rate swap agreements of USD 98,296 and USD 77,707, before income
taxes, as of 31 December 2002 and 2001, respectively. This amount has been reflected in other comprehensive loss as the Company has designated these agreements as cash flow hedges. The
estimated unrealized losses of USD 98,296 at 31 December 2002 include approximately USD 29,452 that is expected to be reclassified into earnings in 2003.

Under
the agreements, the aggregate notional principal is at its highest level (approximately USD 1,100,000) in 1999. At 31 December 2002, notional principal subject to the swap
agreements totaled approximately USD 408,333, bearing fixed interest at a weighted average rate of approximately 9%.

By
using derivative financial instruments to hedge exposures to changes in interest rates, the Company exposes itself to credit risk and market risk. Credit risk is the failure of the
counterparty to perform under the terms of the derivative contract. When the fair value of a derivative contract is positive, the counterparty owes the Company, which creates credit risk for the
Company. When the fair value of a derivative contract is negative, the Company owes the counterparty and, therefore, it does not possess credit risk. The Company minimizes the credit risk in
derivative instruments by entering into transactions with high-quality counterparties whose credit quality is reviewed regularly.

Market
risk is the adverse effect on the value of a financial instrument that results from a change in interest rates. The market risk associated with interest-rate contracts
is managed by establishing and monitoring parameters that limit the types and degree of market risk that may be undertaken.

The
following table represents the derivatives in place as of 31 December 2002:

Notional
amount

Maturity
date

Swap
rate

Fair market value at
31/12/2002Interest rate swap

131,250

15/08/2011

8.965%

(31,428
)Interest rate swap

131,250

15/08/2011

9.035%

(31,811
)Interest rate swap

72,917

15/08/2011

8.980%

(17,506
)Interest rate swap

72,916

15/08/2011

8.995%

(17,551
)408,333





(98,296
)


356

---

11. FAIR VALUE OF FINANCIAL INSTRUMENTS

The following disclosure of the estimated fair value of financial instruments is made in accordance with the requirements of SFAS No. 107, "Disclosures
about Fair Value of Financial Instruments". The estimated fair value amounts have been determined by the Company, using available market information and appropriate valuation methodologies. However,
considerable judgment is necessarily required in interpreting market data to develop the estimates indicative of the amounts that the Company could realize in a current market exchange. The use of
different market assumptions and/or estimation methodologies may have a material effect on the estimated fair value amounts.

The
following methods and assumptions were used to estimate the fair value of each class of financial instruments:

Cash
and cash equivalents, accounts receivable, and accounts payable to related partiesthe carrying amounts approximate fair value because of the short maturity of these
instruments.

Long-term
receivablethe fair value of the long-term receivable is estimated based on discounting the future cash flows using the interest rate at
which a similar restructuring settlement payment would be agreed with a customer with a similar credit rating and similar remaining maturity.

Long-term
loansthe fair value of long-term loans is estimated by discounting the future cash flows of each instrument at rates currently offered to
the Company for similar debt instruments of comparable maturities by the Company's bankers.

Interest
rate swap contractsthe fair value of interest rate swaps (used for hedging purposes) is the estimated amount the Company would receive (or pay) to terminate the
swap agreements at the reporting date, taking into account current interest rates and the current credit worthiness of the swap counterparties.

|                       |                                     | 2002 |            | 2001 |           
|---------------------- | ----------------------------------- | ---- | ---------- | ---- | ----------
|
|Financial assets:      |                                     |      |            |      |           
|                       | Cash and cash equivalents           |      | 233,711    |      | 233,711   
|                       | Accounts receivable                 |      | 83,204     |      | 83,204    
|                       | Long-term receivable                |      | 453,270    |      | 453,270   
|Financial liabilities: |                                     |      |            |      |           
|                       | Accounts payable to related parties |      | (180,243   | )    | (180,243  
|                       | Long-term loans                     |      | (2,369,339 | )    | (2,238,788
|                       | Interest rate swap contracts        |      | (98,296    | )    | (98,296   

357

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12. SHARE CAPITAL

The composition of the Company's shareholders as of 31 December 2002 and 2001 was as follows:

Issued and paid-up share capitalPaid in advance for shares to be issuedShareholders

Number of
Shares

Par valueMEC Indonesia, B.V.

10,000

100,000

22,400Paiton Power Investment Co. Ltd.

8,125

81,250

18,200Capital Indonesia Power I C.V.

3,125

31,250

7,000PT Batu Hitam Perkasa

3,750

37,500

8,40025,000

250,000

56,000


13. INCOME TAX

Income tax (expense) benefit attributable to income (loss) from operations consists of:

2002

2001

2000Current





Deferred

(28,573
)
25,849

(18,705
)(28,573
)
25,849

(18,705
)


The
Company's income tax (expense) benefit differed from the amount computed by applying the Indonesian tax rate of 30% to income (loss) before tax as follows:

2002

2001

2000Indonesian income tax (expense) benefit at statutory rate

(27,847
)
27,135

(18,404
)Items not deductible for tax purposes

(726
)
(1,286
)
(301
)(28,573
)
25,849

(18,705
)


358

---

The
items that give rise to significant portions of the deferred tax assets and deferred tax liabilities at 31 December 2002 and 2001 are presented below:

2002

2001Deferred tax assets:Derivative financial instruments

29,489

23,312Accrued liabilities

12,929

7,681Deferred financing costs

1,667

Net operating loss carryforwards

18,536

43,242Net deferred tax assets

62,621

74,235Deferred tax liabilities:Fixed assets and deferred charges, principally due to differences in depreciation and capitalized interest

(58,418
)
(45,544
)Deferred financing costs



(2,092
)Net deferred tax liabilities

(58,418
)
(47,636
)Deferred tax assets, net

4,203

26,599


At
31 December 2002, the Company had tax loss carryforwards totaling approximately USD 62,000 which will expire in 2006. Realization of the Company's deferred tax assets is
dependent upon profitable operations. Although realization is not assured, the Company believes that it is more likely than not that these deferred tax assets will be realized through the offset of
future taxable income. The amount of deferred tax assets considered realizable, however, could be reduced if actual future taxable income is lower than estimated.

Under
the Indonesian tax laws, the Company submits tax returns on the basis of self-assessment. The taxation authorities may assess or amend taxes within ten years after the
date the tax became payable. The Company is, and may in the future be, under examination by the Indonesian tax authority with respect to positions taken in connection with the filing of tax returns.
Matters raised upon audit may involve substantial amounts, which, if resolved unfavorably, an event not currently anticipated, could
possibly be material. However, in the Company's opinion, it is unlikely that the resolution of any such matters will have a material adverse effect upon the Company's financial condition or results of
operations.

14. COMMITMENTS AND CONTINGENCIES

a.Power Purchase Agreement

On
12 February 1994, the Power Purchase Agreement (the "PPA", as amended as of 28 June 2002), was entered into by the Company and PLN. Under the PPA, as amended, the
Company is responsible for arranging the design, engineering, supply and construction of the Project as well as the operation and maintenance of the power generating units and associated common and
shared facilities.

359

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The Company has constructed and owns and operates the plant facilities at a site provided by PLN which is located at Paiton, East Java. The Company is obligated
to pay PLN Rp 160,000,000 (approximately USD 18 as of 31 December 2002) annually for the right to use the site.

Upon
commercial operation of the Project, the Company is obligated to make available the net electrical output of the Project's plant facilities to PLN which will be purchased by PLN at
amounts determined under certain formulae set forth in the PPA, as amended. The amounts to be paid by PLN for the purchase of net dependable capacity, net electrical output, emergency output and other
items provided for within the PPA, as amended, may be adjusted to ensure that the Company has the same net, after tax economic return should a triggering event occur. Triggering events include but are
not limited to the adoption, enactment, or application of, or any change in the interpretation or application of any legal requirements of any governmental instrumentality of the Republic of Indonesia
which has or will result in material cost or savings to the Company of producing electricity.

The
term of the PPA, as amended, commenced on 12 February 1994 and will expire on 31 December 2040, unless terminated earlier in accordance with the terms of the PPA, as
amended.

Under
the PPA, as amended, the electricity unit price to be paid for net dependable capacity and net electrical output consists of two parts, the capacity payment (which includes
Component A for capital cost recovery, and Component B for fixed operation and maintenance cost recovery) and the energy payment (which includes Component C for fuel and
Component D for variable operation and maintenance cost recovery). In addition to the two-part electricity unit price, supplemental payments shall be payable in the case of
emergency output, start-up fuel costs attributable to PLN actions and net electrical output prior to commission date.

The
electricity unit price is comprised of foreign currency and non-foreign currency portions which essentially represent U.S. Dollars and Rupiah, respectively. The majority
of revenues earned based on the unit price are denominated in U.S. Dollars.

In
May 1999, the Company notified PLN that the first 615 MW unit of the Project had achieved commercial operation under terms of the PPA, as amended, and, in July 1999,
that the second 615 MW unit of the Project had similarly achieved such commercial operation. Because of the economic downturn, PLN was experiencing low electricity demand and PLN had, through
February 2000, been dispatching the Paiton plant to zero. Pending finalization of discussions to amend and restructure the original PPA, PLN and the Company entered into various interim
agreements, underwhich dispatch level fixed and energy payments were agreed.

On
28 June 2002, the Company and PLN entered into the Amendment to Power Purchase Agreement ("PPAA"). Under the PPAA, both parties agreed to amend certain provisions of the
Original PPA and to set out certain other matters in connection with such amendments. On 23 December 2002, the Company and PLN signed the Certificate of Effectiveness of the PPAA. Previously,
the Company and PLN entered into a Binding Term Sheet, dated as of 14 December 2001 and effective as of 1 January 2002, to set forth the commercial terms of agreement on the principal
amendments to the original PPA, including among other things changing the term of the Original PPA, and providing for Restructuring Settlement Payments ("RSP") for the settlement of arrearages.

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Under
the PPAA, the Company is to be paid for capacity and energy charges, as well as a monthly Restructuring Settlement Payment ("RSP") covering arrears owed by PLN as well as
settlement of other claims. The monthly RSP is USD 4,000 and is payable over a period of 30 years commencing on 1 January 2002. See Note 4.

b.EPC Contract

The
Company entered into a turnkey engineering, procurement and construction contract (the "EPC Contract") dated 10 February 1995 with a consortium of companies (the "Contractor")
which include Mitsui & Co., Ltd., a company which has an affiliation with one of the Company's shareholders. Under the EPC Contract, the Contractor will provide to the Company design,
engineering, procurement, construction, start-up testing and commissioning services for the Project's plant and special facilities. The total price to be paid to the Contractor is
approximately USD 1,800,000. Services under the EPC contract commenced in 1995 and were substantially completed in 1999.

The
Company was in arbitration proceedings with its Contractor carrying out construction work at the Company's project site arising out of a slope failure at the site. Initial awards
were rendered establishing that the Contractor was not responsible for the slope failure and are, therefore, entitled to certain costs incurred in connection with the slope failure. The Contractor
applied to the Arbitral Tribunal for a Partial Final Award and on 7 December 1999, the Tribunal issued a Provisional Award totaling USD 15,000, which was paid (less 2% withholding tax) by the
Company to the Contractor in December 1999. On 5 January 2001, Contractor and the Company's respective counsel jointly advised the Arbitral Tribunal of the parties' fully executed Global
Settlement Agreement, and requested that the
arbitration be terminated and dismissed. The Arbitral Administrator acknowledged the dismissal of the arbitration.

On
14 March 2000, the Company and Contractor entered into a Global Settlement Agreement (the "GSA", as amended on 18 December 2000). Under the GSA, the Company committed to
pay the Contractor the sum of USD 135,000 as a Final Costs Claim Payment ("FCCP").

The
Final Cost Claims Payment shall be the full and final compensation for all of the Contractor's cost claims, known and unknown, arising out of or related to its performance of work on
project, including but not limited to, all extra work claims, all requests for change orders, payment of the retention, payment of all unpaid payment milestones, claims arising out of inadequate
access to the PLN grid, claims arising out of the failure and subsequent remediation of the south slope, all claims arising out of the Company's alleged improper set-off of amount payable
to the Contractor, and all the interest claims related thereto. Interest accrues on the unpaid portion of the FCCP until the FCCP is paid in full. The Company recognized interest expense in this
connection aggregating approximately USD 25,914 through 31 December 2002. Under the GSA, the Company is obligated to repay the entire amount of the FCCP as soon as reasonably practicable
and, in any event, 30 September 2003 has been set as a target date for full payment of amounts owed to the Contractor pursuant to the GSA. However, this date represents only a
non-binding estimate of the date of final payment, and there are no consequences to the Company if the Company is unable to settle the final payment by this date. The Company must pay all
amounts owing under the GSA prior to payments of the subordinated debt

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or dividends. The accompanying financial statements include amounts due to the Contractor aggregating USD 177,164 and USD 171,856 as of 31 December 2002 and 2001, respectively.

The
Company had initiated an arbitration claim against the insurance carriers of the Company's construction all risk policy for costs relating to the slope failure. The Company has
decided not to proceed with its claims against the insurance carrier, and filed a Notice of Discontinuance dated 11 December 2002 at the High Court in London. The insurer has asserted that it
is entitled to recover its costs of arbitration. The Company and legal counsel have no basis to estimate the amount of costs that may be claimed by the insurer.

c.Operations and Maintenance Agreement

The
Company is a party to an operations and maintenance agreement (the "O&M Agreement") with PT Edison Mission Operation and Maintenance Indonesia (the "Operator"), which is affiliated
with one of the Company's shareholders. The obligations of the Company and the Operator under the O&M Agreement became effective in April 1995 and continue for a term that is coterminous with
the PPA. The obligations of the Operator under the O&M Agreement are guaranteed by Edison Mission Operation and Maintenance Incorporated (also affiliated with one of the shareholders of the Company).

Under
the terms of the O&M Agreement, the Operator will provide the operation, maintenance and repair services necessary for the production and delivery of electrical energy by the
plant.

The
Operator will receive an annual base fee of USD 3,250 payable in equal monthly installments. The base fee shall be subject to periodic adjustments based on the US Consumer
Price Index. The Company was billed USD 3,595, USD 3,502 and USD 3,385 by the Operator in 2002, 2001 and 2000, respectively.

Commencing
from Operational Acceptance of the Plant, the Company shall pay to or receive from the Operator an incentive fee or performance shortfall amount. The Company incurred an
incentive fee of USD 1,533 in 2002 which was charged to plant operations costs in the statement of income. No incentive fees were incurred nor were performance shortfall amounts received in
2001 and 2000.

d.Fuel Supply

The
Company entered into a fuel supply agreement (the "Fuel Supply Agreement") with PT Batu Hitam Perkasa ("BHP"), one of the shareholders of the Company. Under this agreement, BHP was
obligated to deliver coal to the plant in accordance with the approved coal supply plan. The Fuel Supply Agreement was for a term which commenced in April 1995 and which was scheduled to terminate on
the thirtieth anniversary of the commercial operation date of the plant. From and after the commercial operation date, the Company was obligated to purchase a minimum of 700,000 tons of coal per
quarter.

BHP
made a claim of approximately Rp 48,000,000 (USD 5,400) for coal delivered to the Company. BHP claimed that it was entitled to an upward adjustment in the price of coal delivered to
reflect foreign exchange rate fluctuations since January 1998. The Company disputed the entire claim,

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while having paid one half of the pending claim under protest. An arbitration proceeding initiated by the Company under the Fuel Supply Agreement was commenced in 1999.

On
15 September 1999, a Fuel Chain Temporary Suspension Agreement (the "Agreement"), as amended on 21 December 1999, was entered by and among the Company, BHP, PT Adaro
Indonesia ("Adaro"), PT Indonesia Bulk Terminal ("IBT"), Louis Dreyfus Amarteurs, S.N.C. ("LDA"), (the "Parties"). Under the Agreement, the Parties agreed to suspend their respective rights and
obligations under each of the Contracts (Fuel Supply Agreement between the Company and BHP, Coal Purchase Agreement between BHP and Adaro, Coal Terminal Service Agreement between BHP and IBT, Contract
of Affreightment between BHP and LDA) until March 2002. In July 2002, BHP informed the Tribunal that it wished to reactivate the arbitration and asserted additional claims against the
Company totaling
approximately USD 250,000. On 19 December 2002, the Company and BHP entered into a Settlement Agreement. Under the Agreement, the Company and BHP agreed to settle for an aggregate settlement of
USD 16,225. The Company paid BHP USD 10,250 on 30 December 2002 and has accrued the remaining USD 5,975 in its financial statements at 31 December 2002. In
December 2002, the Company and BHP jointly notified the Tribunal of the Settlement Agreement and requested that BHP's supplemental counterclaims be dismissed with prejudice.

Subsequent
to 31 December 2002, on 12 February 2003, the Company and IBT entered into the IBT Settlement Agreement. Under this Agreement, the Coal Terminal Service
Agreement entered into by BHP and IBT in 1995 has been terminated. Under the IBT Settlement Agreement, the Company is obligated to make a termination payment aggregating USD 28,572 payable in three
instalments, USD 15,957 payable on 31 October 2003, USD 5,472 payable on 31 December 2003 and USD 7,143 payable on 31 March 2004. The total termination payment was
accrued in the 31 December 2002 financial statements.

The
Company and Louis Dreyfus Armateurs, S.N.C ("LDA") entered into the LDA Settlement Agreement (the "Agreement") dated 4 December 2001, as amended as of 31 January 2003.
Under the Agreement, the Company shall pay to LDA an aggregate principal amount of USD 13,000 as the Termination Payment. The Company shall pay the full amount of the Termination Payment on the
date that is 30 days after the date on which the Company shall have made the second of two consecutive, regularly scheduled principal payments under the Senior Lender Financing Agreements. The
maximum delay payment is on or before 31 December 2006. Interest is payable on the aggregate unpaid principal amount of Termination Payment at LIBOR plus 1.5% per annum beginning on
31 January 2003.

On
20 December 2002, the Company reached agreements with PT Adaro Indonesia and PT Kideco Jaya Agung ("fuel suppliers") for primary fuel supply. The fuel suppliers agree to supply
coal to the Company up to a maximum specified annual quantity through 2006. The base price of coal will be equal to its fuel component. There is no commitment on the part of the Company with regard to
minimum fuel take in any year.

e.PLN Labor Union Litigation

PLN's
Labor Union initiated a lawsuit in 2001 against the Company, PLN, the Minister of Mines & Energy and a former PLN President Director. The suit seeks the termination of the
PPA,

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damages equal to USD 590,000, as well as USD 2,500,000 of immaterial damages (damages the amount of which cannot now be stated) and other relief. On 17 April 2002, the Court
rendered a decision in favor of the Company and the other defendants. On 23 April 2002, the PLN Union registered its appeal against the decision of the District Court to the High Court. All the
appeals are pending at the High Court.

The
Company's counsel has advised the Company that PLN's Labor Union has no standing under existing law to assert any such claim against the Company and there are numerous legal and
factual defects in the plaintiff's claim for relief. The Company will vigorously defend this meritless action and will move promptly for a dismissal of this suit. Management believes that, based upon
applicable law in place in Indonesia at this time, the suit is clearly without merit and, upon the proper application of applicable legal precepts by the court, this suit will be resolved in the
Company's favor.

15. CONCENTRATIONS OF RISK

The Company's operations are currently principally conducted in Indonesia and it is accordingly subject to special considerations and significant risks not
typically associated with companies incorporated in the United States of America and Western European countries.

The
Company's results may be adversely affected by changes in the political and social conditions in Indonesia and by changes in governmental policies with respect to laws and
regulations, anti-inflationary measures, currency conversion and remittance abroad, and rates and methods of taxation, among other things.

Many
Asia Pacific countries, including Indonesia, are experiencing severe economic difficulties including volatile currency fluctuations and interest rates, liquidity problems,
volatility in prices, and significant slowdowns in business activity. The crisis has also involved declining prices in shares listed on Indonesian stock exchanges, tightening of available credit,
stoppage or postponement of certain construction projects.

The
Company's operations have been affected and may continue to be affected, for the foreseeable future, by the political and economic turmoil. It is uncertain how future political and
economic developments in Indonesia will affect the Company's operation and results. As a result, there are uncertainties that may affect future operations of the Company.

The
economic crisis in Indonesia during 1998 necessitated a restructuring of the PPA with PLN, the Company's sole customer. PLN's inability pay to the Company a portion of the amounts
due under the PPA resulted in the Company not being able to make repayments of the senior debt in accordance with the original debt amortization schedules. As a result, the Company was in default of
the senior debt agreements. This resulted in a significant uncertainty with respect to the Company's ability to continue as a going concern as at 31 December 2001 and 2000.

In
December 2002, the PPA was amended as discussed in Note 14a. PLN has paid all invoices and all Restructuring Settlement Payments for 2002, as required and in accordance
with the billing procedures agreed in the Binding Term Sheet and the amended PPA.

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As
discussed in Note 9, the senior debt was restructured in February 2003. In connection with the restructuring of the senior debt, the amortization schedule for repayment
of the Company's loans was extended to take into account the effect upon the Company of the lower cash flow resulting from the restructured electricity tariff set forth in the PPA as amended. The
initial principal repayment under the new amortization schedule was made on 18 February 2003, totaling approximately USD 35,200. The Company believes that it will have sufficient cash
flows to meet its obligations for repayment of debt, interest and other liabilities as and when they come due in 2003.

The
generation of electricity by the plant requires the use of coal for fuel that must meet certain quality standards. The Company purchases coal from a limited number of suppliers,
however, the Company believes that other suppliers could provide similar quality coal on comparable terms. The time required to locate and qualify other coal suppliers, however, could cause a delay in
electricity generation that may be disruptive to the Company.

16. LIQUIDITY

The Company's management has undertaken a detailed analysis of the cash flows of the Company for the twelve months ended 31 December 2003. Based on the
forecast for the next twelve months, management has determined that sufficient liquidity exists to fund the operations of the business during that period. In preparing the forecast, management has
reviewed historic cash requirements of the Company as well as key factors which may impact the operations of the Company during the next twelve-month period, and are of the opinion that the
assumptions and sensitivities which are included in the cash flow forecast are reasonable. However, as with all assumptions in regard to future events, these are subject to inherent limitations and
uncertainties and some or all of these assumptions may not be realized.

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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.

| |  | MISSION ENERGY HOLDING COMPANY(Registrant)
| |  | ------------------------------------------
| |  | By:                                       
| |  | Date:                                     

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:                       |  |                                 |  |               
|/s/ Theodore F. Craver, Jr.Theodore F. Craver, Jr. |  | Chief Executive Officer         |  | March 27, 2003
|Controller or
Principal Accounting Officer:        |  |                                 |  |               
|/s/ Mark C. ClarkeMark C. Clarke                   |  | Controller                      |  | March 27, 2003
|Majority of Board of Directors:                    |  |                                 |  |               
|/s/ John E. BrysonJohn E. Bryson                   |  | Director, Chairman of the Board |  | March 27, 2003
|/s/ Bryant C. DannerBryant C. Danner               |  | Director                        |  | March 27, 2003
|/s/ Theodore F. Craver, Jr.Theodore F. Craver, Jr. |  | Director                        |  | March 27, 2003

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CERTIFICATIONS

I,
Theodore F. Craver, certify that:





|Date: March 27, 2003 |  | By: |  | /s/ Theodore F. CraverTheodore F. Craver Director, Chief Executive Officer
and President
|-------------------- |  | --- |  | ----------------------------------------------------------------------------------------

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CERTIFICATIONS

I,
Kevin M. Smith, certify that:





|Date: March 27, 2003 |  | By: |  | /s/ Kevin M. SmithKevin M. Smith Senior Vice President and
Chief Financial Officer
|-------------------- |  | --- |  | ----------------------------------------------------------------------------------

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SCHEDULE I

MISSION ENERGY HOLDING COMPANY AND SUBSIDIARIES        CONDENSED FINANCIAL INFORMATION OF PARENT(1)        Condensed Balance Sheets        (In thousands)

|                                                                     |  | December 31,
|-------------------------------------------------------------------- |  | ------------
|
|Assets                                                               |  |             
|Cash and cash equivalents                                            |  | $           
|Affiliate receivables                                                |  |             
|Other current assets                                                 |  |             
|                                                                     |  |             
|Total current assets                                                 |  |             
|Investments in subsidiaries                                          |  |             
|Investment in discontinued operations                                |  |             
|Other long-term assets                                               |  |             
|                                                                     |  |             
|Total Assets                                                         |  | $           
|                                                                     |  |             
|Liabilities and Shareholder's Equity                                 |  |             
|Accounts payable and accrued liabilities                             |  | $           
|Affiliate payables                                                   |  |             
|Liabilities under price risk management and energy trading           |  |             
|                                                                     |  |             
|Total current liabilities                                            |  |             
|Long-term obligations                                                |  |             
|Long-term liabilities under price risk management and energy trading |  |             
|Deferred taxes and other                                             |  |             
|                                                                     |  |             
|Total Liabilities                                                    |  |             
|Common Shareholder's Equity                                          |  |             
|                                                                     |  |             
|Total Liabilities and Shareholder's Equity                           |  | $           
|                                                                     |  |             

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369

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MISSION ENERGY HOLDING COMPANY AND SUBSIDIARIES        CONDENSED FINANCIAL INFORMATION OF PARENT(1)        Condensed Statements of Income (Loss)        (In thousands)

|                                                            |  | Years Ended December 31, |         
|----------------------------------------------------------- |  | ------------------------ | --------
|
|Operating expenses                                          |  | $                        | (465    
|                                                            |  |                          |         
|Operating income (loss)                                     |  |                          | (465    
|Equity in income from continuing operations of subsidiaries |  |                          | 82,813  
|Equity in loss from discontinued operations of subsidiaries |  |                          | (57,329 
|Interest expense and other                                  |  |                          | (151,830
|                                                            |  |                          |         
|Loss before income taxes                                    |  |                          | (126,811
|Benefit for income taxes                                    |  |                          | (58,570 
|                                                            |  |                          |         
|Net loss                                                    |  | $                        | (68,241 
|                                                            |  |                          |         

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370

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MISSION ENERGY HOLDING COMPANY AND SUBSIDIARIES        CONDENSED FINANCIAL INFORMATION OF PARENT(1)        Condensed Statements of Cash Flows        (In thousands)

|                                                 |                                           | Years Ended December 31, |       
|------------------------------------------------ | ----------------------------------------- | ------------------------ | ------
|
|Net cash provided by operating activities        |                                           | $                        | 93,012
|Net cash provided by financing activities        |                                           |                          | 600   
|Net cash used in investing activities            |                                           |                          | (7,344
|                                                 |                                           |                          |       
|Net increase in cash and cash equivalents        |                                           |                          | 86,268
|Cash and cash equivalents at beginning of period |                                           |                          | 942   
|                                                 |                                           |                          |       
|Cash and cash equivalents at end of period       |                                           | $                        | 87,210
|                                                 |                                           |                          |       
|Other Cash Flow Data:                            |                                           |                          |       
|                                                 | Cash dividends received from subsidiaries |                          | $     
|                                                 |                                           |                          |       

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371

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SCHEDULE II

MISSION ENERGY HOLDING COMPANY AND SUBSIDIARIES        VALUATION AND QUALIFYING ACCOUNTS        (In thousands)

|                             |                                    |  |   | Additions |  |   |        | 
|---------------------------- | ---------------------------------- |  | - | --------- |  | - | ------ | 
|
|Year Ended December 31, 2002 |                                    |  |   |           |  |   |        | 
|                             | Allowance for doubtful accounts(1) |  | $ | 14,603    |  | $ | 1,554  | 
|Year Ended December 31, 2001 |                                    |  |   |           |  |   |        | 
|                             | Allowance for doubtful accounts(1) |  | $ | 1,126     |  | $ | 14,603 | 
|Year Ended December 31, 2000 |                                    |  |   |           |  |   |        | 
|                             | Allowance for doubtful accounts    |  | $ | 1,126     |  |   |       | 
|                             | Maintenance Accruals(2)            |  | $ | 31,540    |  |   |       | 

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