UNITED STATES
SECURITIES 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, 2003

Commission File Number 333-68632

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Mission Energy Holding Company

(Exact name of registrant as specified in its charter)

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

Aggregate market value of the registrant's Common Stock held by non-affiliates of the registrant as of June 27, 2003: $0. Number of shares
outstanding of the registrant's Common Stock as of March 10, 2004: 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, 2003                           |  | 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                                                                            |  | 30  
|Item 3.  |  | Legal Proceedings                                                                     |  | 31  
|Item 4.  |  | Submission of Matters to a Vote of Security Holders                                   |  | 32  
|PART II 
|Item 5.  |  | Market for Registrant's Common Equity and Related Stockholder Matters                 |  | 33  
|Item 6.  |  | Selected Financial Data                                                               |  | 34  
|Item 7.  |  | Management's Discussion and Analysis of Financial Condition and Results of Operations |  | 35  
|Item 7a. |  | Quantitative and Qualitative Disclosures about Market Risk                            |  | 119 
|Item 8.  |  | Financial Statements and Supplementary Data                                           |  | 120 
|Item 9.  |  | Changes in and Disagreements with Accountants on Accounting and Financial Disclosure  |  | 120 
|Item 9A. |  | Controls and Procedures                                                               |  | 120 
|PART III
|Item 10. |  | Directors and Executive Officers of the Registrant                                    |  | 187 
|Item 11. |  | Executive Compensation                                                                |  | 189 
|Item 12. |  | Security Ownership of Certain Beneficial Owners and Management                        |  | 189 
|Item 13. |  | Certain Relationships and Related Transactions                                        |  | 189 
|Item 14. |  | Principal Accounting Fees and Services                                                |  | 190 
|PART IV 
|Item 15. |  | Exhibits, Financial Statement Schedules, and Reports on Form 8-K                      |  | 191 
|         |  | Signatures                                                                            |  | 348 

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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 Edison Mission Group Inc. (formerly The Mission Group), which is a wholly owned subsidiary of Edison
International. MEHC was formed to hold the common stock of EME. On July 2, 2001, Edison Mission Group Inc. 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.

As
of December 31, 2003, consolidated debt of MEHC was $7.4 billion, including debt maturing on December 15, 2004, which is owed by EME's largest subsidiary, Edison
Mission Midwest Holdings Co. The $693 million of debt of Edison Mission Midwest Holdings maturing in December 2004 will need to be repaid or refinanced. Edison Mission Midwest Holdings
currently does not have sufficient cash to repay this indebtedness when due. EME expects that this debt will be refinanced well in advance of its December maturity, although there is no assurance that
this will be accomplished. A failure to repay or refinance Edison Mission Midwest Holdings' $693 million obligation is likely to result in a default under the MEHC senior secured notes and term
loan. 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. MEHC's independent auditors'
audit opinion for the year ended December 31, 2003 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 or refinance its $693 million 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 "Liquidity and Capital Resources" and "Management's Overview" in "Item 7. Management's Discussion and Analysis of Financial Condition and Results
of Operations."

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.

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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, include:



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 Financial Condition and Results of Operations that appear in

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Part II
of this annual report. Readers are urged to read this entire annual report 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 the Industry

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 specified types of non-utility power producers,
known as qualifying facilities, under specified 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 Financial Condition and Results of
OperationsManagement's Overview, Risks Related to Business and Critical Accounting Policies."

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, 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 reducing debt and operating, maintaining, and maximizing the value of its current asset base. Accordingly, EME has engaged
in asset sales, has canceled, deferred or sold new development projects, and has taken a number of actions to decrease capital expenditures, including reductions in operating costs, and suspension of
operations at several power plants. This trend reflects

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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.

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
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.

The
proposed introduction of a new standard market design structure by the Federal Energy Regulatory Commission, or the FERC, in those regions not currently organized into centralized
power markets and the continued expansion by utilities of unbundled retail distribution services could lead to increased competition in the U.S. 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 mitigate somewhat the effects of regional markets, regional economic downturns or unusual weather conditions. Through its presence
in these regions, EME has taken advantage of the increasing globalization of the independent power market. See "Mission Energy Holding Company and Subsidiaries Notes to Consolidated Financial
StatementsNote 21. Business Segments."

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Regional Overview of Business Segments

As of December 31, 2003, EME had ownership or leasehold interests in the following operating power plants in the Americas Region:

|Power Plants                   |                | Location      |  | Primary Electric Purchaser(3) |  | Type of
Facility(4) |  | Ownership Interest |   | Net Physical Capacity (in MW) |        | EME's Capacity Pro Rata Share (in MW)
|------------------------------ | -------------- | ------------- |  | ----------------------------- |  | ------------------- |  | ------------------ | - | ----------------------------- | ------ | -------------------------------------
|American Bituminous(1)         |                | West Virginia |  | MPC                           |  | Waste Coal          |  | 50                 | % | 80                            |        | 40                                   
|Brooklyn Navy Yard(2)          |                | New York      |  | CE                            |  | Cogeneration/EWG    |  | 50                 | % | 286                           |        | 143                                  
|Coalinga(1)                    |                | California    |  | PG&E                          |  | Cogeneration        |  | 50                 | % | 38                            |        | 19                                   
|EcoEléctrica                   |                | Puerto Rico   |  | PREPA                         |  | Cogeneration        |  | 50                 | % | 524                           |        | 262                                  
|Homer City(1)                  |                | Pennsylvania  |  | PJM/NYISO                     |  | EWG                 |  | 100                | % | 1,884                         |        | 1,884                                
|Illinois Plants (11 plants)(1) |                | Illinois      |  | EG                            |  | EWG                 |  | 100                | % | 9,218                         |        | 9,218                                
|Kern River(1)                  |                | California    |  | SCE                           |  | Cogeneration        |  | 50                 | % | 300                           |        | 150                                  
|March Point                    |                | Washington    |  | PSE                           |  | Cogeneration        |  | 50                 | % | 140                           |        | 70                                   
|Mid-Set(1)                     |                | California    |  | PG&E                          |  | Cogeneration        |  | 50                 | % | 38                            |        | 19                                   
|Midway-Sunset(1)               |                | California    |  | SCE                           |  | Cogeneration        |  | 50                 | % | 225                           |        | 113                                  
|Salinas River(1)               |                | California    |  | PG&E                          |  | Cogeneration        |  | 50                 | % | 38                            |        | 19                                   
|Sargent Canyon(1)              |                | California    |  | PG&E                          |  | Cogeneration        |  | 50                 | % | 38                            |        | 19                                   
|Sunrise (1)                    |                | California    |  | CDWR                          |  | EWG                 |  | 50                 | % | 572                           |        | 286                                  
|Sycamore(1)                    |                | California    |  | SCE                           |  | Cogeneration        |  | 50                 | % | 300                           |        | 150                                  
|Watson                         |                | California    |  | SCE                           |  | Cogeneration        |  | 49                 | % | 385                           |        | 189                                  
|                               |                |               |  |                               |  |                     |  |                    |   |                               |        |                                      
|                               | Total Americas |               |  |                               |  |                     |  |                    |   |                               | 14,066 |                                      
|                               |                |               |  |                               |  |                     |  |                    |   |                               |        |                                      

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CDWR

California Department of Water Resources

PG&E

Pacific Gas & Electric CompanyCE

Consolidated Edison Company of New York, Inc.

PREPA

Puerto Rico Electric Power AuthorityEG

Exelon Generation Company

PSE

Puget Sound Energy, Inc.MPC

Monongahela Power Company

SCE

Southern California Edison CompanyPJM/NYISO

Pennsylvania-New Jersey-Maryland/New York Independent System Operator


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As of December 31, 2003, EME had ownership or leasehold interests in the following operating power plants in the Europe and Asia Pacific
Regions:

|Power Plants                         |                               | Location              |  | Primary
Electric
Purchaser(3) |  | Ownership
Interest |      | Net Physical
Capacity (in MW) |       | EME's Capacity
Pro Rata Share
(in MW)
|------------------------------------ | ----------------------------- | --------------------- |  | ----------------------------- |  | ------------------ | ---- | ----------------------------- | ----- | -------------------------------------
|Europe:                              |                               |                       |  |                               |  |                    |      |                               |       |                                      
|Derwent(1)                           |                               | England               |  | SSE                           |  | 33                 | %    | 214                           |       | 71                                   
|Doga(1)                              |                               | Turkey                |  | TEDAS                         |  | 80                 | %    | 180                           |       | 144                                  
|First Hydro (2 plants)(1)            |                               | Wales                 |  | Various                       |  | 100                | %    | 2,088                         |       | 2,088                                
|Iberian Hy-Power I&II (18 plants)(1) |                               | Spain                 |  | FECSA                         |  | 100                | %(5) | 84                            | (7)   | 81                                   
|ISAB                                 |                               | Italy                 |  | GRTN                          |  | 49                 | %    | 528                           |       | 259                                  
|Italian Wind (13 plants)             |                               | Italy                 |  | GRTN                          |  | 50                 | %    | 303                           |       | 152                                  
|                                     |                               |                       |  |                               |  |                    |      |                               |       |                                      
|                                     |                               | Total Europe          |  |                               |  |                    |      |                               |       | 3,397                                
|                                     |                               |                       |  |                               |  |                    |      |                               |       |                                      
|Asia Pacific:                        |                               |                       |  |                               |  |                    |      |                               |       |                                      
|Contact Energy (11 plants)           |                               | New Zealand/Australia |  | Pool                          |  | 51                 | %(6) | 2,597                         |       | 1,215                                
|CBK(3 plants)(2)                     |                               | Philippines           |  | NPC                           |  | 50                 | %    | 423                           | (8)   | 211                                  
|Kwinana(1)                           |                               | Australia             |  | WP/BP                         |  | 70                 | %    | 118                           |       | 83                                   
|Loy Yang B(1)                        |                               | Australia             |  | Pool(4)                       |  | 100                | %    | 940                           |       | 940                                  
|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            |                       |  |                               |  |                    |      |                               | 6,308 |                                      
|                                     |                               |                       |  |                               |  |                    |      |                               |       |                                      
|                                     | Total Europe and Asia Pacific |                       |  |                               |  |                    |      |                               | 9,705 |                                      
|                                     |                               |                       |  |                               |  |                    |      |                               |       |                                      

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BP

British Petroleum Kwinana Refinery Electricity

Pool

Electricity trading market for Australia andEGAT

Generating Authority of Thailand



New ZealandFECSA

Fuerzas Eléctricas de SSE Cataluña, S.A.

SSE

SSE Energy Supply Ltd.GRTN

Gestore Rete Transmissione Nazionale

TEDAS

Türkiye Elektrik Dagitim Anonim SirketiNPC

National Power Corp.

WP

Western PowerPLN

PT PLN


Asset Sales

On December 31, 2003, EME entered into a sale agreement with a third party for its 50% partnership interest in the Brooklyn Navy Yard project which is
expected to be completed during the first quarter of 2004. EME is considering the sale of additional investments, including its interest in the EcoEléctrica project and some or all of
its international projects depending on, among other things, market prices. Management has not committed to the sale of any specific project other than the Brooklyn Navy Yard project. See
"Management's Discussion and Analysis of Financial Condition and Results of OperationsManagement's Overview" for further details on EME's asset sales.

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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.

Americas

As of December 31, 2003, EME had 25 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.

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

MegawattsElectric Generating FacilitiesCollins Station

Grundy County, Illinois

leased

oil/gas

2,698
(1)Crawford Station

Chicago, Illinois

owned

coal

542Fisk Station

Chicago, Illinois

owned

coal

326Joliet Unit 6

Joliet, Illinois

owned

coal

290Joliet Units 7 and 8

Joliet, Illinois

leased

coal

1,044Powerton Station

Pekin, Illinois

leased

coal

1,538Waukegan Station

Waukegan, Illinois

owned

coal

789Will County Station

Romeoville, Illinois

owned

coal

1,092
(1)Peaking UnitsCrawford

Chicago, Illinois

owned

oil/gas

121Fisk

Chicago, Illinois

owned

oil/gas

163Joliet

Joliet, Illinois

owned

oil/gas

101Waukegan

Waukegan, Illinois

owned

oil/gas

92Calumet

Chicago, Illinois

owned

oil/gas

129Bloom

Chicago Heights, Illinois

owned

oil/gas


(2)Electric Junction

Aurora, Illinois

owned

oil/gas

159Lombard

Lombard, Illinois

owned

oil/gas

64Sabrooke

Rockford, Illinois

owned

oil/gas

70Total

9,218


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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

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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 Financial Condition and Results of Operations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, Commonwealth Edison assigned these agreements to its affiliate, Exelon Generation. Under these agreements, Midwest Generation agreed to make the
capacity of specific units of the Illinois Stations available to Exelon Generation. These agreements allow Midwest Generation to sell any excess energy, including energy not dispatched by Exelon
Generation, to other purchasers under specified conditions. Payments under these power purchase agreements constituted approximately 21%, 41% and 43% of EME's consolidated operating revenues for 2003,
2002 and 2001, respectively. As discussed in detail below, Exelon Generation has released 5,428 MW of Midwest Generation's generating capacity from the power purchase agreements for 2004. Therefore,
3,859 MW of Midwest Generation's generating capacity remains subject to power purchase agreements with Exelon Generation in 2004.

Coal-Fired Stations Power Purchase Agreement

The
power purchase agreement for the coal-fired stations provides for capacity payments for the units under contract, whether or not energy is generated, and for energy
payments for energy taken by Exelon Generation. The capacity payments compensate Midwest Generation for fixed charges such as debt service, labor and insurance, and the energy payment compensates
Midwest Generation for variable costs of actual electricity production taken by Exelon Generation. 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 also supplies ancillary services with respect to the coal-fired stations. If
Exelon Generation does not request all available energy from the coal-fired stations under the power purchase agreement, Midwest Generation may sell the excess energy to third parties,
subject to certain conditions.

Pursuant
to the provisions of the coal-fired power purchase agreement, Exelon Generation has elected to retain 2,383 MW of coal-fired capacity for contract year
2004, thus releasing from the contract 3,262 MW of capacity. The final contract year under this power purchase agreement is 2004.

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The
following table lists the coal-fired units from which Exelon Generation is committed to purchase capacity and energy during 2004 and the units which have been released
from the terms of the power purchase agreement, along with related pricing information set forth in the power purchase agreement.

2004  Coal-Fired Units

|                     |                       | Unit Size (MW) |     | Summer(1)
Capacity Charge
($ per MW Month) |        | Non-Summer(1)
Capacity Charge
($ per MW Month) |       | Energy Prices
($/MWhr)
|-------------------- | --------------------- | -------------- | --- | ------------------------------------------ | ------ | ---------------------------------------------- | ----- | ----------------------
|Units under Contract |                       |                |     |                                            |        |                                                |       |                       
|                     | Waukegan Unit 7       |                | 328 |                                            | 11,000 |                                                | 1,375 |                       
|                     | Crawford Unit 8       |                | 326 |                                            | 11,000 |                                                | 1,375 |                       
|                     | Will County Unit 4    |                | 520 |                                            | 11,000 |                                                | 1,375 |                       
|                     | Joliet Unit 8         |                | 522 |                                            | 11,000 |                                                | 1,375 |                       
|                     | Waukegan Unit 8       |                | 361 |                                            | 21,300 |                                                | 2,663 |                       
|                     | Fisk Unit 19          |                | 326 |                                            | 21,300 |                                                | 2,663 |                       
|                     |                       |                |     |                                            |        |                                                |       |                       
|                     |                       | 2,383          |     |                                            |        |                                                |       |                       
|Released Units(2)    |                       |                |     |                                            |        |                                                |       |                       
|                     | Waukegan Unit 6       |                | 100 |                                            |       |                                                |      |                       
|                     | Crawford Unit 7       |                | 216 |                                            |       |                                                |      |                       
|                     | Will County Unit 1(3) |                | 156 |                                            |       |                                                |      |                       
|                     | Will County Unit 2(3) |                | 154 |                                            |       |                                                |      |                       
|                     | Will County Unit 3    |                | 262 |                                            |       |                                                |      |                       
|                     | Joliet Unit 6(4)      |                | 314 |                                            |       |                                                |      |                       
|                     | Joliet Unit 7         |                | 522 |                                            |       |                                                |      |                       
|                     | Powerton Unit 5       |                | 769 |                                            |       |                                                |      |                       
|                     | Powerton Unit 6       |                | 769 |                                            |       |                                                |      |                       
|                     |                       |                |     |                                            |        |                                                |       |                       
|                     |                       | 3,262          |     |                                            |        |                                                |       |                       
|                     |                       |                |     |                                            |        |                                                |       |                       
|                     |                       | 5,645          |     |                                            |        |                                                |       |                       
|                     |                       |                |     |                                            |        |                                                |       |                       

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As noted in the above table, 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
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

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monthly
capacity payment for the coal-fired units is 65% for the summer months and 55% for the non-summer months.

Collins Station Power Purchase Agreement

The
Collins Station power purchase 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
partially compensates Midwest Generation for variable costs of actual electricity production taken by Exelon Generation. 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 Collins Station power purchase agreement, Exelon Generation has elected to retain 1,084 MW of capacity of the units at the Collins Station for contract
year 2004, thus releasing from the contract 1,614 MW of capacity. The final contract year under this power purchase agreement is 2004.

The
following table lists the generating units at the Collins Station from which Exelon Generation is committed to purchase capacity and energy during 2004 and the generating units which
have been released from the terms of the power purchase agreement, along with related pricing information set forth in the power purchase agreement.

2004  Collins Station

|Generating Unit      |                   | Unit Size (MW) |     | Summer(1)
Capacity Charge
($ per MW Month) |       | Non-Summer(1)
Capacity Charge
($ per MW Month) |       | Energy Prices
($/MWhr)
|-------------------- | ----------------- | -------------- | --- | ------------------------------------------ | ----- | ---------------------------------------------- | ----- | ----------------------
|Units Under Contract |                   |                |     |                                            |       |                                                |       |                       
|                     | Collins Unit 1    |                | 554 |                                            | 8,333 |                                                | 2,083 |                       
|                     | Collins Unit 3    |                | 530 |                                            | 8,333 |                                                | 2,083 |                       
|                     |                   |                |     |                                            |       |                                                |       |                       
|                     |                   | 1,084          |     |                                            |       |                                                |       |                       
|Released Units(2)    |                   |                |     |                                            |       |                                                |       |                       
|                     | Collins Unit 2    |                | 554 |                                            |      |                                                |      |                       
|                     | Collins Unit 4(3) |                | 530 |                                            |      |                                                |      |                       
|                     | Collins Unit 5(3) |                | 530 |                                            |      |                                                |      |                       
|                     |                   |                |     |                                            |       |                                                |       |                       
|                     |                   | 1,614          |     |                                            |       |                                                |       |                       
|                     |                   |                |     |                                            |       |                                                |       |                       
|                     |                   | 2,698          |     |                                            |       |                                                |       |                       
|                     |                   |                |     |                                            |       |                                                |       |                       

---

As noted in the above table, the Collins Station power purchase agreement sets forth different capacity charges for the 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 energy purchased under the power

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purchase 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 more than a threshold amount of energy. See
"Item 7. Management's Discussion and Analysis of Financial Condition and Results of OperationsLiquidity and Capital Resources" for discussion related to planned termination of the Collins
lease. In addition, see "Item 7. Management's Discussion and Analysis of Financial Condition and Results of OperationsCritical Accounting Policies and Estimates" for discussion related to
the asset impairment for Midwest Generation's Collins Station.

Peaking Units Power Purchase Agreement

The
peaking units power purchase agreement provides for capacity payments for the units under contract, whether or not energy is generated, and for energy payments for energy 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 power purchase agreement, Exelon Generation has elected to retain 392 MW of capacity of the peaking units for contract year 2004, thus releasing from
the contract 552 MW of capacity. The final contract year under this power purchase agreement is 2004.

The
following table shows the peaking units from which Exelon Generation is committed to purchase capacity and energy during 2004 and the peaking units which have been released from the
terms of the power purchase agreement, along with related pricing information set forth in the power purchase agreement.

2004  Peaking Units

|Generating Unit      |  | Unit Size (MW) |  | Summer(1)
Capacity Charge
($ per MW Month) |  | Non-Summer(1)
Capacity Charge
($ per MW Month) |  | Energy Prices
($/MWhr)
|-------------------- |  | -------------- |  | ------------------------------------------ |  | ---------------------------------------------- |  | ----------------------
|Units Under Contract |  | 392            |  | 9,500                                      |  | 1,500                                          |  | 60-95                 
|Released Units(2)    |  | 552            |  |                                           |  |                                               |  |                      
|                     |  |                |  |                                            |  |                                                |  |                       
|                     |  | 944            |  |                                            |  |                                                |  |                       
|                     |  |                |  |                                            |  |                                                |  |                       

---

See "Item 7. Management's Discussion and Analysis of Financial Condition and Results of OperationsManagement's Overview" for
discussion related to asset impairment charges for Midwest Generation's peaking units.

Illinois Power Markets

Beginning in 2003, Midwest Generation has been selling a significant portion of its energy into wholesale power markets. As discussed above, Exelon Generation has
released 5,428 MW of Midwest Generation's generating capacity from the power purchase agreements entered into by Exelon Generation and Midwest Generation, leaving 3,859 MW of Midwest Generation's
generating capacity subject to the power purchase agreements with Exelon Generation for the remainder of 2004. All these power purchase agreements expire on December 31, 2004. Energy produced
by Midwest Generation not under contract with Exelon Generation is sold at market prices to utilities, third-party electricity retailers and power marketers through Edison Mission Marketing &
Trading.

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With
respect to the capacity that has been released from the power purchase agreements with Exelon Generation, Midwest Generation's coal units derive their revenue from forward sales to
regional utilities and power marketers and from sales on a spot basis, and the Collins Station and the peaking units derive revenue from sales on a spot basis.

The
primary markets currently available to Midwest Generation for sales of electricity and capacity not subject to power purchase agreements are direct "wholesale customers" and
broker-arranged "over-the-counter customers." Wholesale customer transactions are bilateral sales 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 sales into the control area of Cinergy,
referred to as "Into Cinergy," and, to a lesser extent, sales into the control areas of Commonwealth Edison and American Electric Power, referred to as "Into ComEd" and "Into AEP," respectively. Due
to geographic proximity, "Into ComEd" has been the primary market for Midwest Generation. Since 2002, liquidity has decreased significantly in these markets and continues to be limited because of the
decision by many trading entities to reduce or discontinue operations. In addition, the financial problems of other trading entities have resulted in far fewer creditworthy participants in these
markets.

The
emergence of "Into Cinergy," "Into ComEd" and "Into AEP" as commercial hubs for the trading of physical power not only facilitates 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, ComEd's, or AEP'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,
parent company guarantees, letters of credit and cash margining arrangements. As noted, however, liquidity in all of these markets has been adversely affected by the financial problems of trading and
marketing entities.

As
discussed below, the prices for certain sales by Midwest Generation could be adversely affected if Commonwealth Edison's transmission system is integrated into the transmission system
administered by PJM Interconnection, LLC, commonly referred to as PJM, and if market power mitigation measures for the Northern Illinois Control Area, referred to as NICA, as currently proposed by
PJM, and pending before the Federal Energy Regulatory Commission, or FERC, are adopted.

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

Currently,
sales of power produced by Midwest Generation that is not under a power purchase agreement with Exelon Generation require using transmission which must be obtained from
Commonwealth Edison. An independent system operator does not yet oversee operations of the Commonwealth Edison control area; however, it has requested that such operations be placed under the control
of PJM effective May 1, 2004. Such request is currently pending decision by the FERC (see further discussion of this proceeding below). In addition, a number of other utilities in the region
participate in the Midwest Independent System Operator (Midwest ISO), a Regional Transmission Organization (RTO) authorized pursuant to the FERC's Order No. 2000, where a bilateral market with

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a
single rate for transmission within the RTO already exists. The regional market is further supported by open access transmission under various utility company transmission tariffs that are not
within the Midwest ISO. The open access transmission tariffs of the Midwest ISO and others in the region allow Midwest Generation to utilize their transmission and distribution systems to sell power
at wholesale on a non-discriminatory basis relative to the system owners. Such tariffs are vital to allow Midwest Generation to compete in the deregulated electricity markets because they
provide a uniform set of prices and standards of transmission service that have been approved by regulatory agencies and are publicly available.

The
Illinois Electric Service Customer Choice and Rate Relief Law of 1997 requires each Illinois electric utility that owns or controls transmission facilities or provides transmission
services in Illinois, and is a member in the Mid-American Interconnected Network, such as Commonwealth Edison to submit for approval by the FERC an application for establishing or joining
an independent system operator. On December 11, 2002, Commonwealth Edison, American Electric Power and others filed with the FERC seeking permission to join PJM as their RTO. PJM is a prominent
independent
system operator providing system operations and market settlement throughout the Mid-Atlantic States. The effect of including Commonwealth Edison and American Electric Power in the PJM RTO
would be to transfer functional control of their transmission 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. Another effect would be
to make the transmission systems of Commonwealth Edison and American Electric Power subject to the PJM Open Access Transmission Tariff (referred to herein as the "PJM Tariff") and Market Rules. Under
such rules (and assuming the inclusion of both Commonwealth Edison and American Electric Power in PJM), sales of power from the Midwest Generation plants can be made within the broad regional area
encompassed by PJM without the necessity of securing physical reservations of transmission capacity, either through bilateral transactions with specific purchasers or into the
PJM-dispatched markets without a named counterparty.

Approval
of the December 11 application of Commonwealth Edison and American Electric Power was granted by the FERC on April 1, 2003. However, the ability of American
Electric Power to join PJM has been brought into question by the enactment of legislation in Virginia on April 2, 2003, requiring the approval of Virginia state authorities for any transfer of
control from American Electric Power to PJM of American Electric Power transmission assets located in Virginia. In July 2003, state authorities in Kentucky placed similar obstacles on the transfer of
control of American Electric Power transmission assets located in that state.

On
April 16, 2003, Commonwealth Edison and PJM issued a joint press release stating that the integration of Commonwealth Edison into PJM would proceed separately from that of
American Electric Power, notwithstanding the absence of a direct transmission link owned by Commonwealth Edison between its service territory and the existing PJM. In response, EME, Midwest
Generation, and other affected parties filed with the FERC for clarification or rehearing of its April 1, 2003 order, and essentially contested the appropriateness of Commonwealth Edison
joining PJM on an "islanded" basis, without a direct transmission link between its service territory and that of the existing PJM. On June 4, 2003, the FERC clarified that a series of
pre-conditions imposed by an order issued on July 31, 2002, which tentatively approved the stated decisions of Commonwealth Edison and American Electric Power to join PJM together,
continue to be applicable to the separate application of Commonwealth Edison to join PJM alone. On August 1, 2003, Commonwealth Edison filed a notice of appeal of the July 31, 2002 order
and the June 4, 2003 order on rehearing with the U.S. Court of Appeals for the D.C. Circuit.

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Processing
by PJM of Commonwealth Edison's application to integrate Commonwealth Edison's operations under PJM separately from American Electric Power was delayed following the
August 14, 2003 blackout in the Midwest and Northeast. On December 31, 2003, PJM and Commonwealth Edison made a filing with the FERC seeking its approval to commence full integration of
Commonwealth Edison on May 1, 2004, without AEP. On January 21, 2004, EME and Midwest Generation filed a
protest opposing the separate integration of Commonwealth Edison into PJM on an "islanded" basis on numerous grounds, including the adverse impact of a separate, stand-alone segment of PJM limited to
the control area of Commonwealth Edison, which would be essentially disconnected from the rest of PJM by the states of Indiana and Ohio. One of the primary objections to such a circumscribed market
within PJM, which would be subject to its market rules, is the fact that the PJM Market Monitor utilizes price mitigation techniques that do not take into account the availability of imports of
electricity from non-PJM sources in evaluating the existence of competitive conditions and in deciding whether to apply restraints on bids from generators located within PJMin
this instance, the service territory of Commonwealth Edison. PJM subsequently filed its intended rules for the application of its market mitigation techniques to such territory, which EME and Midwest
Generation have also opposed on numerous factual and legal grounds (see further discussion below). It is not possible to predict the outcome of such further proceedings at this time.

On
July 23, 2003, the FERC issued an order finding that the regional through and out rates, or RTORs, of the Midwest ISO and PJM are unjust and unreasonable when applied to
transactions sinking within the proposed Midwest ISO/PJM footprint and directed Midwest ISO and PJM to make a compliance filing within thirty days eliminating the RTORs. The FERC also initiated an
investigation and hearing to determine whether the through and out rate under the tariffs of Commonwealth Edison, AEP and others (for which RTO membership has been delayed) are unjust, unreasonable or
unduly discriminatory or preferential for transactions sinking in the proposed Midwest ISO/PJM footprint. Such actions by FERC were designed to achieve the elimination of transmission rate pancaking
within the broad region encompassed by PJM, as expanded, and the Midwest ISO, which was one of several actions required as a condition of its approval in July 2002 of the decisions of
Commonwealth Edison and American Electric Power to join PJM instead of the Midwest ISO. Numerous transmission owners sought rehearing of the July 23 order, and the FERC subsequently issued an
order on rehearing on November 17, 2003, setting a new effective date of April 1, 2004, for the elimination of the through and out rates and making certain other adjustments to phase in
the new rates. However, the affected utilities in the region have continued to protest the alleged adverse financial impact of the described orders on them, and FERC subsequently moved the date for
the elimination of the through and out rates to May 1, 2004. On March 5, 2004, the affected parties announced an agreement to postpone the date for the elimination of through and out
rates to December 1, 2004, in an effort to facilitate a settlement of the longer term issues. EME and Midwest Generation oppose such agreement on legal and policy grounds, but it has been filed
with the FERC with a request for approval by March 19, 2004. The outcome cannot be predicted.

In
the meantime, on September 29 and 30, 2003, the FERC held a Commissioner-level hearing and inquiry into regional transmission organization issues related to the Midwest ISO and
PJM. The purpose of the inquiry was to gather sufficient information to move forward in resolving the commitment made by several entities, including Commonwealth Edison, to establish a joint and
common market in the Midwest and PJM region. Following such inquiry on November 25, 2003, the FERC issued an order finding that the actions of the state of Virginia described above and similar
actions of state authorities in Kentucky were impeding the ability of American Electric Power to join PJM and thus potentially thwarting the development of regional power markets in the Midwest. The
order set for hearing certain issues that must be addressed in order to "exempt" a utility from a state law or regulation having such effect, and required a decision by the assigned Administrative Law
Judge by March 15, 2004. Such hearings have been completed, and the matter has been briefed and argued to the Administrative Law Judge, where it is currently under submission awaiting his
decision. The

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November 25,
2003 order also required American Electric Power to be integrated into PJM by October 1, 2004.

As
described above, there currently is a proposal pending before FERC to integrate Commonwealth Edison into PJM on an "islanded" basis effective May 1, 2004. On February 5,
2004, PJM filed proposed revisions to the PJM Tariff to incorporate market power mitigation measures for the NICA, which would become effective upon Commonwealth Edison's integration into PJM on a
stand-alone basis, currently scheduled for May 1, 2004. In its February 5, 2004 filing, PJM claimed that, while the NICA markets were expected to generally be competitive, mitigation
measures were required to control the exercise of market power in certain circumstances. With regard to the NICA energy market, PJM has proposed that in certain circumstances, sales by marginal units
would be capped at the greater of such units' incremental operating cost plus ten percent or the NICA market price. With regard to sales of capacity in the NICA, PJM also has proposed that offers of
capacity be capped at $30 per megawatt-day, plus any additional amounts that are demonstrated to compensate the seller for its opportunity costs or other annual avoidable incremental
costs. In certain circumstances, this offer cap could be increased to $160 per megawatt-day. On February 26, 2004, Midwest Generation filed a protest to PJM's proposed market power
mitigation measures for the NICA which contested the need for these mitigation measures and requested that FERC defer Commonwealth Edison's integration into PJM until American Electric Power's
scheduled integration into PJM on October 1, 2004. It is not possible to predict at this time whether PJM's proposed market power mitigation measures for the NICA will be accepted by FERC,
either in whole, or in part. If FERC should accept these market power mitigation measures as currently proposed by PJM, the prices for certain sales by Midwest Generation could be adversely affected.

For
a discussion of the risks related to Midwest Generation's transmission service, see "Item 7. Management's Discussion and Analysis of Financial Condition and Results of
Operations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 Financial Condition and Results of Operations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 Financial Condition and Results of OperationsOff-Balance Sheet Transactions."

Big 4 Projects

EME owns partnership investments in 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. See "Mission Energy Holding Company and Subsidiaries Notes to Consolidated Financial StatementsNote 2. Summary of Significant Accounting

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Policies," for discussion of EME's accounting for this entity. 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 ChevronTexaco Exploration and Producing 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, California, which EME refers to as the Midway-Sunset project. Midway-Sunset sells electricity to Southern California Edison, Aera Energy LLC (Aera) 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 ChevronTexaco Exploration and Producing 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 BP West Coast Products LLC under a steam supply agreement that also expires in 2008.

Other Americas Power Plants

Sunrise Power Plant

EME owns a 50% interest in Sunrise Power Company, LLC, which owns a 572 MW natural gas-fired facility in Kern County, California, which EME refers to
as the Sunrise project. The Sunrise project was constructed in two phases. Phase 1 achieved commercial operation in June 2001 and consisted of a 320 MW simple-cycle peaking facility. Phase 2, a
combined-cycle gas-fired facility, converted the simple-cycle peaking facility to a 572 MW combined cycle plant. Phase 2 achieved commercial operation in June 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Sunrise Power Company Lawsuits."

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

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Consolidated
Edison Company of New York, Inc. under a power purchase agreement that expires in 2036. EME expects to complete the sale of its 50% partnership interest in the Brooklyn Navy Yard
project during the first quarter of 2004. See "Asset Sales."

EcoEléctrica Power Plant

EME owns a 50% partnership interest in EcoEléctrica L.P., which owns a 524 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 7. Management's Discussion and Analysis of Financial Condition and Results of OperationsManagement's Overview" for discussion of planned asset sales.

March Point Cogeneration Plant

EME owns a 50% partnership interest in March Point Cogeneration Company, which owns a 140 MW natural gas-fired cogeneration facility located in
Anacortes, Washington, which EME refers to as the March Point project. The March Point project consists of two phases. Phase 1 is an 80 MW gas turbine cogeneration facility and Phase 2 is a 60
MW gas turbine combined cycle facility. March Point Cogeneration sells electricity to Puget Sound Energy, Inc. under a power purchase agreement that expires in 2011 and sells shares to Equilon
Enterprises, LLC under a steam supply agreement that also expires in 2011.

Westside Power Plants

EME owns partnership investments in Coalinga Cogeneration Company, Mid-Set Cogeneration Company, Salinas River Cogeneration Company, and Sargent
Canyon Cogeneration Company. Due to similar economic characteristics, EME views these projects collectively and refers to them as the Westside projects. EME owns a 50% partnership interest in each of
the companies listed above and each company owns a 38 MW natural gas-fired cogeneration facility located in California. Each of the projects sells electricity to Pacific Gas &
Electric Company under 15-year power purchase agreements with expirations through 2007.

American Bituminous Power Plant

EME owns a 50% interest in American Bituminous Power Partners, L.P., which owns a 80 MW waste coal facility located in Grant Town, West Virginia, which EME
refers to as the Ambit project. Ambit sells electricity to Monongahela Power Company under a power purchase agreement that expires in 2027.

Investment in Four Star Oil & Gas Company

As of December 31, 2003, EME owned a 38.5% direct and indirect interest, with 37.4% 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. On
January 7, 2004, EME sold 100% of the stock of Edison Mission Energy Oil & Gas, which in turn holds minority interests in Four Star Oil & Gas. Proceeds from the sale were
approximately $100 million. EME expects to record a pre-tax gain on the sale of approximately $47 million during the first quarter of 2004.

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Asia Pacific

As of December 31, 2003, EME had 19 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 Australia, with an additional office located in Singapore. 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. See "Item 7. Management's Discussion and Analysis of Financial Condition and Results of OperationsManagement's
Overview" for discussion of planned asset sales.

Australia

Loy Yang B Power Plant

EME owns a 940 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 Financial Condition and Results of Operations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 118 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 electricity and steam to the British Petroleum Kwinana Refinery under an energy and services agreement
which also expires in 2021.

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New Zealand

Contact Energy

EME owns a 51% 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 30% 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 Financial Condition and Results of OperationsMarket Risk Exposures." Contact Energy owns the
following power plants:

Plant

Type

MegawattsNew Plymouth

Gas thermal

400Clyde

Hydro

432Otahuhu B

Natural gas

380Taranaki

Natural gas

357Roxbugh

Hydro

320Oakey(1)

Natural gas

300Wairakei

Geothermal

165Ohaaki

Geothermal

104Poihipi

Geothermal

55Te Rapa

Natural gas

44Otahuhu A

Natural gas

402,597


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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

As of December 31, 2003, EME owned 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. In January 2004, EME acquired additional shares of Paiton Energy for $14 million, thereby increasing its
ownership interest from 40% to 45%. 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.

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

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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.

Philippines

CBK Power Plants

EME owns a 50% interest in CBK Power Co. Ltd. CBK Power operates under a 25-year build-rehabilitate-operate-transfer agreement with National
Power Corporation for the 792 MW Caliraya-Botocan-Kalayaan hydro electric complex located in the Republic of the Philippines, which EME refers to as the CBK project. CBK Power is paid capital recovery
fees and operations and maintenance fees for generating electricity and providing other services under the agreement. As of
November 30, 2003, all units forming part of the project had completed their net dependable capacity tests, and are operational with tested capacity of 792 MW (net physical capacity) against a
guaranteed minimum of 728 MW. As of December 31, 2003, National Power Corporation had not issued certificates of completion for the Kalayaan Phase II units and as such 369 MW were still
considered under construction and 423 MW 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, 2003, 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. See "Item 7. Management's Discussion and Analysis of Financial Condition and Results of OperationsManagement's Overview" for discussion of planned
asset sales.

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 Financial Condition and Results of OperationsMarket Risk Exposures" and "Historical Distributions Received by EME," as well as "Mission Energy
Holding Company and Subsidiaries Notes to Consolidated Financial StatementsNote 11. Financial Instruments."

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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 SSE Energy Supply Ltd. under a power purchase agreement that expires in 2010 and sells steam to Acetate Products 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 528 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, an international subsidiary of EME 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, 2003, the entire planned 303 MW had been commissioned and 283 MW are in commercial operation. 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. It is expected that GRTN will complete the interconnection in the second quarter of 2004.

Spain

Spanish Hydro Power Plants

EME's wholly owned subsidiary, Iberica de Energias, S.L., owns 18 small, run-of-the-river hydro electric plants regionally
dispersed in Spain totaling 84 MW, which EME refers to as the Spanish Hydro project. Iberica de Energias, S.L. sells electricity to Fuerzas Eléctricas de Cataluña, 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 Türkiye Elektrik Dagitim Anonim Sirketi, commonly known as TEDAS, under a power purchase agreement that expires in 2019. See
"Item 7. Management's Discussion and Analysis of and Financial Condition and Results of Operations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

For a description of discontinued operations see "Edison Mission Energy and Subsidiaries Notes to Consolidated Financial StatementsNote 8.
Discontinued Operations."

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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 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 continues to be limited. 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 a smaller set of wholesale customers, which may also increase EME's credit risk. As noted, a reduction in price reporting has also limited price transparency in
certain markets, which also may increase trading risks. 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.

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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 define risk tolerances for each EME regional business unit. 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 in respect of its Illinois
Plants, its Homer City facilities and its proprietary positions. The use of value at risk allows management to aggregate overall commodity risk, compare risk on a consistent basis and identify the
risk factors. 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 for key risk factors, 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 Financial Condition and Results of OperationsManagement's Overview, Risks Related to the Business and Critical Accounting
PoliciesRisks Related to the Business."

Seasonality

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.

EME's
third quarter electric revenues are materially higher than revenues related to other quarters of the year because warmer weather in 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 have higher electric revenues during the winter months.

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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 power plant and the ownership of a power plant. 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. Intricate and changing environmental and other regulatory requirements could necessitate
substantial expenditures and could create a significant risk of expensive delays or significant loss of value in a project if it were to become unable to function as planned due to changing
requirements or local opposition.

U.S. Federal Energy Regulation

The FERC 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 under that Act by the FERC provided incentives for the development of cogeneration facilities and small power production facilities using alternative or renewable fuels by establishing
certain exemptions from the Federal Power Act and the Public Utility Holding Company Act for the owners of 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.

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 FERC. 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.

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An
"exempt wholesale generator" under the Public Utility Holding Company Act is an entity determined by the FERC 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 FERC 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 FERC 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 the FERC 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 FERC thereunder, but the FERC 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 FERC 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 FERC typically also grants blanket approval for the issuance of securities and partial waiver of the
restrictions on interlocking directorates. The FERC 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 FERC ratemaking regulation under the Federal Power Act. EME's future domestic non-qualifying facility independent power projects will also be subject to the
FERC 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 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.

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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 FERC thereunder. Second, the FERC 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 FERC'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 FERC'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 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 FERC 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

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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 FERC would be
required. In addition, the project would be required to cease selling electricity to any retail customers, in order to qualify for exempt wholesale generator status, and could become subject to
additional state regulation. Loss of 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.

Over
the past few years, the U.S. Congress has considered various legislative proposals to restructure the electric industry that would require, among other things, retail customer
choice, repeal of the Public Utility Holding Company Act, or PUHCA, and prospective, partial repeal of the Public Utility Regulatory Policies Act. There are also a number of other proposals that have
been introduced in Congress that incorporate provisions related to restructuring electricity markets. Different versions of such legislation passed both houses of Congress late in the last session and
included provisions related to PUHCA repeal, providing the FERC with new authority related to imposing reliability standards but restricting the FERC's ability to mandate adoption of a standard
wholesale market design. A joint Conference Committee produced a report that was acceptable to the House, but was unable to obtain sufficient votes in the Senate to limit extended debate by opponents
of the conference report seeking to delay final adoption of the bill (known as a filibuster). It is unclear at this time whether the Senate will be able to muster sufficient votes in the current
session to overcome a filibuster and obtain the needed waivers from budgetary rules and pass the Conference report. While there are some pending efforts to enact portions of the comprehensive energy
bill on an individual basis, the Congressional leadership and administration have thus far opposed such efforts and the likelihood of success is uncertain.

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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 FERC
has jurisdiction over certain sales of natural gas and over transportation and storage of natural gas in interstate commerce. The FERC has granted blanket authority to all persons to make sales of
natural gas without restriction but continues to exercise significant oversight with respect to transportation and storage of natural gas services in interstate commerce.

Recent Foreign Regulatory Matters

See the discussion on recent foreign regulatory matters in "Item 7. Management's Discussion and Analysis of Financial Condition and Results of
Operations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 FERC when the entity providing the transmission service is a jurisdictional public utility under the Federal Power Act.

The
Energy Policy Act of 1992 laid the groundwork for a competitive wholesale market for electricity. Among other things, the Energy Policy Act expanded the FERC's authority to order
electric utilities to transmit third-party electricity over their transmission lines, thus allowing qualifying facilities under the Public Utility Regulatory Policies Act of 1978, power marketers and
those qualifying as exempt wholesale generators under the Public Utility Holding Company Act of 1935 to more effectively compete in the wholesale market.

In
1996 the FERC issued Order No. 888, also known as the Open Access Rules, which require utilities to offer eligible wholesale transmission customers
non-discriminatory open access on utility transmission lines on a comparable basis to the utilities' own use of the lines. In addition, the Open Access Rules directed jurisdictional public
utilities that control a substantial portion of the nation's electric transmission networks to file uniform, non-discriminatory open access tariffs containing the terms and conditions
under which they would provide such open access transmission service. The FERC 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 FERC 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
December 1999, the FERC 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 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 joining and required utilities to explain in detail their reasons for deviating from the
objectives set forth in the Order. RTOs meeting the FERC'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.

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In
subsequent orders, the FERC has progressively tightened its policies in favor of RTO formation, including 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
January 15, 2003, the FERC proposed to allow additional percentage points on a utility's return on equity in its transmission rates when it participates in an RTO, divests its
RTO-operated transmission assets, or pursues additional measures that promote efficient operation and expansion of the transmission grid. As outlined below, the FERC has also proposed to
establish a standard market design that would govern transmission service and energy trading arrangements in all regions of the country.

On
July 31, 2002, the FERC 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, or 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 the U.S. Congress, and the anticipated timetable for issuance of a final rule is now unclear.

In
April 2003, the FERC attempted to address some more controversial aspects of its SMD proposal in a "White Paper," which set forth the elements of its SMD proposal that it
regarded as the most fundamental features of a sound wholesale market "platform" and modified its proposal as to other aspects that it regarded as subject to regional variation. Currently, the SMD
policies are being implemented in different degrees and on different schedules in various parts of the country, and are the subject of active consideration and focus by stakeholders in wholesale
markets in the Midwest. These and other regulatory initiatives by the FERC 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. Volatility in California and other regional power markets has resulted in several states slowing, and in some cases reversing or reassessing, their plans to allow retail competition.

Environmental Matters and Regulations

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

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Employees

MEHC has no full-time employees. At December 31, 2003, EME and its subsidiaries employed 2,610 people, all of whom were full-time
employees and 141, 159 and 1,001 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 and expires on December 31, 2004. 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 37,000 square feet and expires on July 31, 2007. At December 31, 2003,
approximately 38% 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 MEHC'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.

Description of Properties

|Plant           |  | Business
Segment |  | Location                 |  | Interest In
Land |  | Plant Description                          
|--------------- |  | ---------------- |  | ------------------------ |  | ---------------- |  | -------------------------------------------
|Contact Energy  |  | Asia Pacific     |  | Wellington, New Zealand  |  | Owned/Leased     |  | Various                                    
|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     
|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     
|Kern River      |  | Americas         |  | Oildale, California      |  | Leased           |  | Natural gas-turbine cogeneration facility  
|Kwinana         |  | Asia Pacific     |  | 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  
|Midway-Sunset   |  | Americas         |  | Fellows, California      |  | Leased           |  | Natural gas-turbine cogeneration facility  
|Paiton          |  | Asia Pacific     |  | East Java, Indonesia     |  | Leased           |  | Coal fired generation facility             
|Sunrise         |  | Americas         |  | Fellows, California      |  | Leased           |  | Combined cycle generation facility         
|Sycamore        |  | Americas         |  | Oildale, California      |  | Leased           |  | Natural gas-turbine cogeneration facility  
|Watson          |  | Americas         |  | Carson, California       |  | Leased           |  | Natural gas-turbine cogeneration facility  

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ITEM 3. LEGAL PROCEEDINGS

EcoEléctrica 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 United States Environmental Protection Agency, or EPA, 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. EcoEléctrica and the Department of Justice agreed to settle the
matter for $195 thousand. The parties signed a Stipulation, Settlement Agreement and Order reflecting their agreement. The Department of Justice then filed its complaint, which was subsequently
dismissed by the court in recognition of the Stipulation, Settlement Agreement and Order, and EcoEléctrica paid the $195 thousand fine, and the settlement became final.

Sunrise Power Company Lawsuits

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 FERC 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 was not served with the complaint. On
November 25, 2003, the plaintiffs filed a voluntary dismissal with prejudice of this lawsuit. The dismissal was entered by the court on December 2, 2003.

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

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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. On July 9, 2003, Judge Whaley of the U.S. District Court concluded the federal court lacked jurisdiction and remanded the case to the originating San
Francisco Superior Court. Defendants, including Sunrise Power Company, stipulated to respond to the complaint thirty days after it is assigned to a specific court of the San Francisco Superior Court.
In December 2003, James Millar filed a First Amended Class Action and Representative Action Complaint which contains allegations similar to those in the earlier complaint but also alleges a
class action. One of the newly added parties has again removed the lawsuit to federal court, where it is currently pending (subject to remand). EME believes that the outcome of this litigation will
not have a material adverse effect on its consolidated financial position or results of operations.

Paiton Labor Suit

In April 2001, Paiton Energy was sued in the Central Jakarta District Court by the PLN Labor Union. PT PLN, the state-owned electric utility company, was
also named as a defendant in the suit, along with the Indonesian Minister of Mines and Energy and the former President Director of PT PLN. 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.

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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, Edison Mission
Group Inc. (formerly 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, Edison Mission Group Inc., totaling $65 million
during 2001. MEHC paid two dividends to Edison Mission Group Inc. in 2001: (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. MEHC did not pay any dividends in 2003 and 2002. After MEHC acquired EME in 2001, EME made cash
dividend payments to MEHC totaling $32.5 million in 2001. EME did not pay or declare any dividends to MEHC during 2003 and 2002.

During
the first two years of MEHC's operations, when debt interest payments were funded with restricted cash, MEHC was permitted to distribute to its direct parent, Edison Mission
Group Inc., dividends MEHC received 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 are now 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, 2003 was 2.45 to 1. For more information on these restrictions, see "Item 7. Management's Discussion and
Analysis of Financial Condition and Results of OperationsAbility of EME to Pay Dividends."

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ITEM 6. SELECTED FINANCIAL DATA

|                                                                                                                            |  | Years Ended December 31, |      
|--------------------------------------------------------------------------------------------------------------------------- |  | ------------------------ | -----
|
|
|INCOME STATEMENT DATA                                                                                                       |  |                          |      
|Operating revenues                                                                                                          |  | $                        | 3,181
|Operating expenses                                                                                                          |  |                          | 3,019
|                                                                                                                            |  |                          |      
|Operating income                                                                                                            |  |                          | 162  
|Equity in income from unconsolidated affiliates                                                                             |  |                          | 368  
|Interest expense                                                                                                            |  |                          | (669 
|Interest and other income                                                                                                   |  |                          | 22   
|                                                                                                                            |  |                          |      
|Income (loss) from continuing operations before income taxes and minority interest                                          |  |                          | (117 
|Provision (benefit) for income taxes                                                                                        |  |                          | (85  
|Minority interest                                                                                                           |  |                          | (39  
|                                                                                                                            |  |                          |      
|Income (loss) from continuing operations                                                                                    |  |                          | (71  
|Income (loss) from operations of discontinued subsidiaries (including loss on disposal of $1.1 billion in 2001), net of tax |  |                          | 1    
|                                                                                                                            |  |                          |      
|Income (loss) before accounting change                                                                                      |  |                          | (70  
|Cumulative effect of change in accounting, net of tax                                                                       |  |                          | (9   
|                                                                                                                            |  |                          |      
|Net income (loss)                                                                                                           |  | $                        | (79  
|                                                                                                                            |  |                          |      

---

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

---

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

This Management's Discussion and Analysis of Financial Condition and Results of Operatons (MD&A) 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" and "Risks Related to the
Business."

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.

The
MD&A is presented in four major sections:

PageManagement's Overview, Risks Related to the Business and Critical Accounting Policies

35Results of Operations

51Liquidity and Capital Resources

72Market Risk Exposures

106


MANAGEMENT'S OVERVIEW, RISKS RELATED TO THE BUSINESS AND CRITICAL ACCOUNTING POLICIES

Management's Overview

MEHC as a Holding Company

MEHC is the holding company of EME which, itself, operates through its subsidiaries and affiliates which are engaged in the business of owning or leasing,
operating and selling energy and capacity from electric power generation facilities worldwide. MEHC has no business activities other than through its ownership interest in EME. During 2001, MEHC
issued $800 million of senior secured notes and borrowed $385 million under a term loan. MEHC's ability to honor its obligations under the senior secured notes and the term loan is
entirely dependent upon the receipt of dividends from EME and receipt of tax-allocation payments from MEHC's parent, Edison Mission Group Inc., and ultimately Edison International
(see Intercompany Tax-Allocation Payments). Dividends from EME are limited based on its earnings and cash flow, terms of restrictions contained in EME's contractual
obligations (including its corporate credit facility), EME's charter documents, business and tax considerations, and restrictions imposed by applicable law. MEHC did not receive any distributions from
EME during 2003.

The
lenders under MEHC's $385 million term loan due in 2006 have the right to require MEHC to repurchase up to $100 million of principal amount at par on July 2,
2004 (referred to as the "Term Loan Put-Option"). In order for MEHC to have sufficient cash in the event of an exercise of a significant portion, or all, of the Term Loan
Put-Option, MEHC would require additional cash from dividends from EME, or would need to either extend the effective date of the Term Loan Put-Option

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or
extend or refinance the term loan. Dividends from EME are currently limited as described in "Ability of EME to Pay Dividends."

EME Introduction

EME, is a holding company which operates primarily through its subsidiaries and affiliates which are engaged in the business of owning or leasing, operating and
selling energy and capacity from electric power generation facilities worldwide. EME's subsidiaries or affiliates have typically been formed to own all of or an interest in one or more power plants
and ancillary facilities, with each plant or group of related plants being individually referred to by EME as a project. EME also owns a 51% interest in Contact Energy, an integrated energy company
located in New Zealand. As of December 31, 2003, EME's subsidiaries and affiliates owned or leased interests in 28 projects, of which 14 are domestic and 14 (including
EcoEléctrica) are international.

EME
has financed the development and construction or acquisition of its projects by contributions of equity from EME and the incurrence of so-called project financed debt
obligations by the subsidiaries and affiliates owning the operating facilities. These project level debt obligations are generally structured as non-recourse to EME, with several
exceptions, including EME's guarantee of the Powerton and Joliet leases as part of a refinancing of indebtedness incurred by its project subsidiary to purchase the Illinois Plants. As a result, these
project level debt obligations have structural priority with respect to revenues, cash flows and assets of the project companies over debt obligations incurred by EME, itself. In this regard, EME has,
itself, borrowed funds to make the equity contributions required of it for its projects and for general corporate purposes. Since EME does not, itself, directly own any revenue producing generation
facilities, it depends for the most part on cash distributions from its projects to meet its debt service obligations, to pay for general and administrative expenses and to pay dividends to its
parent, MEHC.

Distributions
to EME from projects are generally only available after all current debt service obligations at the project level have been paid and are further restricted by contractual
restrictions on distributions included in the documentation evidencing the project level debt obligations. Because of such a contractual constraint, distributions to EME from cash generated from the
Illinois Plants has been restricted since October 1, 2002 due to a downgrade of the credit rating of this project's debt to below investment grade. EME also is currently subject to constraints
on its ability to make distributions to its parent, MEHC. For a description of the most significant contractual constraints under the
projects, see "Liquidity and Capital ResourcesDividend Restrictions in Major Financings."

EME's
project portfolio may be grouped into two categories: contracted plants and merchant plants. At December 31, 2003, EME owned 25 projects that sell a majority of their power
to customers under long-term sales arrangements (greater than 5 years) consisting of power purchase agreements or hedge contracts (in the case of Contact Energy, sales are made
through its retail electricity business). While these projects involve a number of risks, their long-term sales arrangements generally provide a stable and predictable revenue stream which
results in reasonably predictable cash distributions to EME.

EME
owns three projects (the Illinois Plants, the Homer City facilities and the First Hydro Power Plants) which operate in whole or in part without long-term sales
arrangements (representing approximately 70% of EME's project portfolio based on capacity). Although the generation of the Illinois Plants was at the time of their acquisition in late 1999 subject to
sale under contracts with Exelon Generation, the amount of capacity and energy subject to sale under these contracts has been gradually reduced in the ensuing contract years, and these contracts will
expire at the end of 2004. Output from merchant plants (as well as excess output from contracted plants) which is not committed to be sold under long-term sales arrangements is subject, in
terms of price and volume, to market forces which determine the actual amount and price of power sold from these power plants. A

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description
of these market forces and the risks associated with them is included under "Market Risk Exposures."

Management Focus in 2003 and 2004

Beginning in 2001, a number of significant developments adversely affected merchant generators (companies that sell a majority of their generation into wholesale
energy markets), including EME. These developments included lower prices and greater volatility 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. As a result of these developments, EME's focus during 2003 was on the following objectives:



In
2004, EME management intends to continue its focus on operational performance at its generating plants, managing its cash and credit resources to support the contracting of its
merchant generation and on implementing its debt restructuring and de-leveraging plan. The key steps to be undertaken in this plan are:





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In
addition, EME's focus includes realizing planned cash distributions from subsidiaries and affiliates, maintaining operational excellence, obtaining a fair public policy outcome with
respect to a well structured expansion of the PJM market, and otherwise supporting the development of competitive markets for wholesale generation in Illinois.

See
"BusinessRegulatory Matters."

Overview of EME's 2003 Operating Performance

EME's 2003 operating performance was significantly improved over 2002. A number of important items affected this performance, including the following:



In
2003, the Illinois Plants had 4,739 MW of contracted capacity (to Exelon Generation) and 3,109 MW of uncontracted capacity available for sale in the merchant generation market,
compared with 8,987 MW of contract capacity and 300 MW of uncontracted capacity in 2002. The reduction in contracted generating capacity decreased revenues from Exelon Generation as a percentage of
the Illinois Plants' total energy and capacity revenues to 68% in 2003 from 99% in each of 2002 and 2001.

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The
reduction in contracted capacity resulted in a decrease of capacity revenues of $222 million, partially offset by an increase of $127 million in energy revenues from sales of
increased merchant generation. Prices realized from sales of merchant generation were significantly higher than energy prices payable under the power purchase agreements with Exelon Generation. EME
expects that capacity prices in the MAIN region will, in the near term, be significantly lower than those payable under the existing agreements with Exelon Generation (due to the generation
overcapacity conditions in the MAIN region market), but also expects that merchant energy prices will, in the near term, be higher than those currently received under the existing agreements with
Exelon. See "Market Risk Exposures" for further discussion of forward market prices in the MAIN region.

A
significant factor affecting merchant generators in 2003 was the substantial increase in the price of natural gas, especially when compared with the less volatile cost of other fuels,
such as coal. During 2003, natural gas prices at Henry Hub (a major natural gas trading hub) averaged $5.48 per million British Thermal Units, commonly referred to as MMBtu, compared to $3.37 per
MMBtu for 2002. Based upon data from NYMEX as of December 26, 2003, the calendar year 2004 forward natural gas price at Henry Hub was $5.45 per MMBtu. Increases in natural gas prices during
2003 resulted in higher wholesale electricity prices (since natural gas is the primary fuel for many generation plants). This increase in natural gas prices was a positive factor for
low-cost merchant coal facilities (such as a majority of EME's domestic merchant plants) in markets dominated by gas-fired plants and somewhat positive for such facilities in
those markets more dependent on low-cost coal and nuclear facilities. In contrast, for gas-fired merchant generators that sell their power into markets dominated by
low-cost coal and nuclear power plants, the increase in natural gas prices adversely affected their results. These conditions adversely affected the Collins Station and small peaking units
in Illinois as discussed above.

Expansion of PJM in Illinois

For the Illinois Plants to achieve their optimal value, it is important that efficient and fair markets exist in the Midwest region. The Illinois Plants are
located within the service territory of Exelon Generation's affiliate, Commonwealth Edison (ComEd), which has made a filing with the Federal Energy Regulatory Commission (FERC) to join the PJM System
effective May 1, 2004. Although FERC has indicated its general approval for ComEd and American Electric Power (AEP) to join PJM if certain conditions designed to foster broad regional markets
in the Midwest are met, the integration of AEP into PJM has been stalled due to the opposition of the states of Virginia and Kentucky. While EME and Midwest Generation have supported the entry of
ComEd and AEP into PJM at the same time, they have nevertheless opposed ComEd's entry into PJM without AEP on numerous grounds, including the importance of the AEP system to the proper functioning of
the markets administered by PJM. This issue is currently pending before FERC.

If
the integration of ComEd into PJM standing alone is allowed by the FERC to proceed on May 1, 2004, the Illinois Plants will become subject to PJM's market rules, including
those designed to mitigate generation market power, which PJM has indicated may be applied as if the market is limited only to the generation within the ComEd footprint. (By contrast, PJM has stated
to the FERC that market mitigation measures will likely not be necessary from and after the integration of AEP into PJM.) EME and Midwest Generation have strongly opposed this limited view of the
market with the FERC, and the matter is pending decision in connection with the ComEd/PJM integration filing. If this opposition is unsuccessful, the price for sales of energy from such plants (during
the period prior to AEP's integration) not sold pursuant to bilateral agreement could be capped at their marginal operating cost to produce such energy plus ten percent, under the proposed rules of
the PJM Market Monitor. See "Risks Related to the BusinessEME is subject to extensive energy industy regulation."

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Contracting Strategy

EME's goal is to reduce the volatility of its earnings and cash flow and, thus, improve the predictability of operating results. To do this, EME plans to
implement a layered contracting strategy for forward sales from the Illinois Plants and the Homer City facilities. A layered contracting strategy means that EME's marketing subsidiary, Edison Mission
Marketing & Trading, plans to enter into a number of forward contracts diversified by counterparty, contract term and generation product to reduce market risk and enhance the predictability of
revenues. Implementation of this strategy is dependent on a number of factors, such as a reduction in the current oversupply of generation, the rate of demand growth, and agreement between
counterparties of reasonable credit support undertakings.

Acquisitions and Dispositions of Investments in Energy Plants

Acquisitions

On March 3, 2003, Contact Energy, EME's 51% owned subsidiary, completed a transaction with NGC Holdings Ltd. to acquire the Taranaki Combined Cycle
power station and related interests. The Taranaki station is a 357 MW combined cycle, natural gas-fired plant located near Stratford, New Zealand. Consideration for the Taranaki station
consisted of a cash payment of approximately $275 million, which was initially financed with bridge loan facilities. The bridge loan facilities were subsequently repaid with proceeds from
Contact Energy's issuance of long-term U.S. dollar denominated notes.

Dispositions

On December 31, 2003, EME agreed to sell its 50% partnership interest in Brooklyn Navy Yard Cogeneration Partners L.P. to a third party. Completion of the
sale, currently expected in the first quarter of 2004, is subject to closing conditions, including obtaining regulatory approval. Proceeds from the sale are expected to be approximately
$42 million. EME recorded an impairment charge of $53 million during the fourth quarter of 2003 related to the planned disposition of this investment.

On
December 12, 2003, EME agreed to sell 100% of its stock of Edison Mission Energy Oil & Gas, which in turn holds minority interests in Four Star Oil & Gas, to
Medicine Bow Energy Corporation. Following receipt of regulatory approvals and satisfaction of all other closing conditions, EME completed this sale on January 7, 2004. Proceeds from the sale
were approximately $100 million. EME expects to record a pre-tax gain on the sale of approximately $47 million during the first quarter of 2004.

On
December 12, 2003, EME completed the sale of its 40% interest in a development project in Thailand to a third party. Proceeds from the sale were $13 million to be paid
in two installments, the first of which, in the amount of $5 million, was received by EME on December 15, 2003. The remaining payment is payable in June 2004.

On
November 21, 2003, Gordonsville Energy Limited Partnership, in which EME owns a 50% interest, completed the sale of the Gordonsville cogeneration facility to Virginia Electric
and Power Company. Proceeds from the sale, including distribution of a debt service reserve fund, were $36 million. EME recorded an impairment charge of $6 million during the second
quarter of 2003 related to the planned disposition of this investment.

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Risks Related to the Business

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 the provisions in EME's formation documents that constrain its ability to pay dividends or distributions to MEHC, see "EME'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 short-term indebtedness and long-term lease
obligations.

As of December 31, 2003, consolidated debt of EME was $6.2 billion, including $693 million of debt maturing in December 2004 which is
owed by EME's largest subsidiary, Edison Mission Midwest Holdings. EME also has a $145 million credit facility expiring in September 2004. In addition, EME's subsidiaries have
$6.7 billion of long-term lease obligations that are due over a period ranging up to 31 years.

The
$693 million of debt of Edison Mission Midwest Holdings maturing in December 2004 will need to be repaid or refinanced. Edison Mission Midwest Holdings is currently not
expected to have sufficient cash to repay the $693 million debt due in December 2004, and there is no assurance that it will be able to 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 under the guarantee entered into by
Midwest Generation EME in December 2003, or at all. MEHC's independent auditors' audit opinion for the year ended December 31, 2003 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 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 or refinance Edison Mission Midwest Holdings' $693 million of debt as required by its terms would result in an event of default under the Edison Mission Midwest
Holdings financing documents. Furthermore, these events would trigger cross-defaults under agreements to which Edison

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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 debt, 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 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.

Among
the factors that influence future market prices for energy and capacity in the MAIN Region and PJM are:



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 flows. If EME's merchant energy power plants are not successful, they may not be able to generate enough cash to service their own debt and lease obligations, which could have a material adverse
effect on EME. See "Market Risk ExposuresCommodity Price Risk."

EME is subject to extensive energy industry 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 also subject to federal laws and regulations that govern, among other things,

42

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transactions
by and with purchasers of power, including utility companies, the operations of a power plant, the ownership of a power plant and various aspects related to transmission access. 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, among other things, the geographical location, zoning, land use and operation of 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. For more information, see "Item 1. BusinessRegulatory Matters."

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."

EME is subject to extensive environmental regulation that may involve significant and increasing costs.

EME's operations are subject to extensive environmental regulation by foreign, federal, state and local authorities. EME believes that it is in substantial
compliance with environmental regulatory requirements and that maintaining compliance with current requirements will not materially affect its financial position or results of operations. However,
possible future developments, such as the promulgation of more stringent environmental laws and regulations and future enforcement proceedings that may be taken 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 its business, 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, operation or modification of a project or
generating facility. 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. EME cannot provide assurance that it will be able to obtain and comply with all necessary licenses, permits and approvals for its plants.

Currently,
environmental advocacy groups and regulatory agencies in the United States have been focusing considerable attention on carbon dioxide emissions from coal-fired
power plants and their potential role in climate change. The adoption of laws and regulations to implement carbon dioxide controls could adversely affect EME's coal-fired plants. EME has
an equity interest in or owns and operates generating plants in a number of countries that have ratified or are expected to ratify the Kyoto Protocol and these nations are actively developing policies
and measures to assist them with meeting the individual national emission targets as set out within the Kyoto Protocol. As a result of the United States' opposition to the treaty, the treaty will not
come into effect unless it is ratified by Russia. If the treaty comes into effect or if other countries in which EME operates adopt laws and

43

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regulations
limiting carbon dioxide emissions even in the absence of the treaty, these requirements could adversely affect EME's operations in those nations. Also, coal plant emissions of nitrogen and
sulfur oxides, mercury and particulates are potentially subject to increased controls and mitigation expenses. Changing environmental regulations could require EME to purchase additional emissions
allowances or make some units uneconomical to maintain or operate. Furthermore, EME's international projects are subject to the environmental laws and regulations of the foreign jurisdictions in which
they are located. The degree of regulation varies according to each country and may be materially different from the regulatory regimes in the United States. If EME cannot comply with all applicable
regulations, its business, results of operations and financial condition could be adversely affected. See "Environmental Matters and Regulations."

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

The credit ratings of Edison Mission Midwest Holdings are below investment grade, thereby restricting its ability to pay dividends to EME. Edison Mission Midwest
Holdings is the direct parent of Midwest Generation, which owns or leases the Illinois Plants. 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's credit ratings are below investment grade, which may adversely affect its ability to refinance debt or to provide credit support to subsidiaries.

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 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.

EME,
directly and through a subsidiary, provides credit support to its subsidiaries. The credit support is in the form of cash and letters of credit. Without an investment grade rating,
EME's ability to provide credit support to its subsidiaries is limited. If EME were unable to provide adequate credit support, this would 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 and spot markets instead of bilateral contracts. Furthermore, if forward prices for power increase
significantly, EME may not be able to meet margining requirements. 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 "Liquidity and Capital ResourcesEME's Credit Ratings."

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

During 2003, 2002 and 2001, 21%, 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.

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Midwest
Generation was less dependent on Exelon Generation as a major customer during 2003 due to Exelon Generation's release of capacity from the coal units. In 2004, 2,383 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. 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 may 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 take advantage of business
opportunities as they arise, to grow their business and compete effectively, or to develop and implement any refinancing plans in respect of their indebtedness. See "EME and its
subsidiaries have a substantial amount of indebtedness, including 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."

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.

45

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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.

Critical Accounting Policies and Estimates

Introduction

The accounting policies described below are viewed by 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.

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, or (2) qualify as normal purchases and sales and are, therefore, recorded on an accrual basis.

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 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

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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 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 second quarter of 2003, 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 forecast is over an extended time period due to the estimated useful life (15 to 33.75 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 small peaker plants did
not exceed the carrying value of that asset group. The book value of these assets was written down from $286 million to an estimated fair market value of $41 million. The estimated fair
market value was determined based on discounting estimated future pretax cash flows using a 17.5% discount rate. The impairment charge relating to the peaking plants resulted from a revised
long-term outlook for capacity revenues from the peaking plants. The lower capacity revenue outlook is the result of a number of factors, including higher long-term natural gas
prices and the current generation overcapacity in the MAIN region market.

In
addition to the asset impairment charge related to the small peaking plants in 2003, EME's indirect subsidiary, Midwest Generation, also reported an impairment charge of
$475 million, after tax, related to the 2,698 MW gas-fired Collins Station in its second quarter report on Form 10-Q. The

47

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impairment
charge resulted from a write-down of the book value of the Collins Station capitalized assets from $858 million to an estimated fair market value of $78 million.
The impairment charge by Midwest Generation is not reflected in the operating results of EME because the lease related to the Collins Station is treated in EME's financial statements as an operating
lease and not as an asset and, therefore, is not subject to impairment for accounting purposes. See "Liquidity and Capital ResourcesEME Recourse Debt to Recourse Capital
Ratio."

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 than 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 to dispose of an asset and the fair value is less than EME's book value. SFAS No. 144 requires the following
criteria to be met to classify an asset held for sale:



EME
has engaged investment bankers to market for sale its international project portfolio which commenced during the first quarter of 2004. Completion of the sale of all or part of EME's
international project portfolio is contingent on receiving acceptable offers in terms of both price and terms and conditions related to risk factors. Due to the uncertainty regarding completion of the
sale of all or part of the international project portfolio through the current offering process, management has concluded that it has not met all of the requirements listed above at
December 31, 2003. EME's book value of its international project portfolio was approximately $2.2 billion at December 31, 2003. There is no assurance that EME will be able to sell
these assets at or above book value.

During
2003, EME met the asset held for sale criteria of SFAS No. 144 regarding its investment in the Gordonsville and Brooklyn Navy projects and recorded an impairment based on
the net proceeds expected from the sale of $6 million and $53 million, respectively.

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,

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"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
$1.3 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 and 2003 (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 continues to record depreciation on such assets during the period that EME
has 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's goodwill is primarily related to the acquisitions of Contact Energy and First Hydro. 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.

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,
2003 (the annual impairment testing date). The fair value of the First Hydro and Contact Energy reporting units set forth in these appraisals exceeded the carrying 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Operating Lease Obligations." 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 provision 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

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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 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." Also see "Liquidity and Capital ResourcesAgreement in Principle to Terminate the Collins Station
Lease."

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 14 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 earnings either are reinvested indefinitely or would not be subject to additional taxes if repatriated. At
December 31, 2003, EME reviewed the undistributed earnings of its international subsidiaries and concluded:



For
additional information regarding EME'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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RESULTS OF OPERATIONS

Consolidated Operating Results

Net Income Summary

Net income is comprised of the following components:

Years Ended December 31,2003

2002

2001(in millions)MEHC (parent company):Loss from continuing operations

$
(99
)
$
(93
)
$
(49
)EME and its Consolidated Subsidiaries:Income from continuing operations

$
28

$
96

$
83Income (loss) from discontinued operations


1


(57
)

(1,219
)Cumulative changes in accounting


(9
)

(14
)

15Net income (loss)

$
(79
)
$
(68
)
$
(1,170
)


MEHC's (parent company's) loss from continuing operations in 2003 was $99 million compared to $93 million in 2002 and
$49 million in 2001. The 2003 increase in loss from continuing operations was primarily due to lower interest income and higher consulting fees in 2003. 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.

EME's
income from continuing operations in 2003 was $28 million compared to $96 million in 2002 and $83 million in 2001. The 2003 decrease in income from continuing
operations was primarily due to asset impairment charges of $182 million, after tax, described below, reduction in revenue from EME's Illinois Plants, lower earnings from EME's First Hydro
plant, and lower state tax benefits than in 2002. Partially offsetting these items were net charges and credits in 2002 totaling $50 million, after tax, described below, higher U.S. energy
prices, the start of operations at Phase 2 of the Sunrise project in June 2003, and increased earnings from Contact Energy and the Paiton project.

The
$182 million after-tax impairment charges included a $150 million, after tax, loss related to eight small peaking plants in Illinois recorded in the second
quarter of 2003, and a $32 million, after tax, loss from the write-down of EME's investment in the Brooklyn Navy Yard project due to its planned disposition recorded in the fourth
quarter of 2003. The impairment charge relating to the peaking plants resulted from a revised long-term outlook for capacity revenues. The lower capacity revenue outlook is the result of a
number of factors, including higher long-term natural gas prices and the current generation overcapacity in the MAIN region market. Since capacity value represents a key revenue component
for these small peaking plants, the revised outlook resulted in a write-down of the book value of these assets to their estimated fair market value.

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 charges and credits during 2002 totaling $36 million, after tax. These after-tax charges and credits include a $52 million
after-tax write-off of capitalized costs related to the termination of equipment purchase contracts and the write-off of capitalized costs associated with the
suspension of the SCR major capital improvements project at the Powerton Station, and a $27 million after-tax loss from a settlement agreement that terminated the obligation to
build additional generation in Chicago,

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partially
offset by a gain of $43 million, after tax, from the settlement of a postretirement employee benefit liability.

EME's
income from discontinued operations in 2003 was $1 million compared to loss from discontinued operations of $57 million in 2002 and $1.2 billion in 2001. 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.

EME's
2003 loss from a change in accounting principle results from the adoption of a new accounting standard for asset retirement obligations. EME's 2002 loss from a change in accounting
principle results from the adoption of a new accounting standard for goodwill. EME's 2001 gain from a change in accounting principle results from the adoption of an accounting standard as amended and
interpreted on derivative instruments. See "Cumulative Effect of Change in Accounting Principle" for further discussion of these changes in accounting.

Operating Revenues

Operating revenues increased 16% in 2003 from 2002, and increased 11% in 2002 from 2001. Operating revenues in 2003 increased from 2002 primarily due to increased
electric revenues from Contact Energy primarily due to higher wholesale electricity prices, higher generation, and an increase in the value of the New Zealand dollar compared to the U.S. dollar. In
addition, operating revenues increased in 2003 due to increased electric revenues from the Homer City facilities due to increased generation and higher energy prices. Partially offsetting these
increases were lower capacity revenues from the Illinois Plants due to a reduction in megawatts under contract with Exelon Generation in 2003.

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.

Net
gains (losses) from price risk management and energy trading activities are comprised of:

Years Ended December 31,2003

2002

2001(in millions)Price risk management

$
4

$
(15
)
$
26Energy trading


40


42


10Net gains

$
44

$
27

$
36


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). Included in net gains (losses) from price risk management were:



52

---



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 net gains (losses) of approximately $13 million, $(2) million and $(1) million in 2003, 2002 and 2001, respectively, representing
the amount of the ineffective portion of the cash flow hedges. The ineffective gain during 2003 from Homer City was primarily attributable to decreases in the difference between energy prices at PJM
West Hub (where EME's subsidiary enters into forward contracts) and the energy prices at the delivery point where power generated by the Homer City facilities is delivered into the transmission system
(referred to as the Homer City busbar). In addition, Homer City recognized ineffective gains related to forward contracts that expired during 2003. See "Market Risk
ExposuresAmericas" for more information regarding forward market prices.

The
2003 net gains from energy trading activities were primarily the result of net gains from transmission congestion contracts and other power contracts in markets where EME has power
plants. The increase in net gains from energy trading activities in 2002 from 2001 was primarily due to the
completion of the restructuring of the power sales agreement described below and as a result of realized gains from transmission congestion contracts. As part of the restructuring 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).

EME's
third quarter electric revenues are generally 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 generally have higher electric revenues during their winter months.

Operating Expenses

Fuel costs increased 17% in 2003 from 2002, and increased 16% in 2002 from 2001. The 2003 increase was primarily due to increased generation from the Homer City
facilities and increased fuel costs from Contact Energy primarily due to higher gas prices and an increase in the value of the New Zealand dollar compared to the U.S. dollar. The 2003 increase in
Homer City generation was primarily the result of outages experienced during the first two quarters of 2002. 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.

53

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Plant
operations and transmission costs increased $147 million in 2003 from 2002, and increased $58 million in 2002 from 2001. Transmission costs were $267 million
in 2003, $187 million in 2002 and $100 million in 2001. The 2003 increase in transmission costs was primarily due to higher retail sales generated by Contact Energy and an increase in
the value of the New Zealand dollar compared to the U.S. dollar. The 2002 increase in transmission costs was primarily due to consolidating Contact Energy, effective June 1, 2001.

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

Depreciation
and amortization expense increased $43 million in 2003 from 2002, and decreased $16 million in 2002 from 2001. The 2003 increase was primarily due to higher
depreciation expense from Contact Energy associated with the Taranaki Station acquisition. Also contributing to the 2003 increase was additional depreciation expense resulting from the termination of
the Midwest Generation equipment lease in August 2002. The 2002 decrease was primarily due to lower depreciation expense from Homer City related to the sale-leaseback transaction
from Homer City in December 2001.

The
settlement of postretirement employee benefit liability in 2002 relates to a retirement health care and other benefits plan for union-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 15, 2006. 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 $304 million in 2003, $131 million in 2002 and $59 million in 2001. Asset impairment charges in 2003 consisted of
$245 million related to the impairment of eight small peaking plants owned by EME's wholly owned subsidiary, Midwest Generation, in Illinois, $53 million to write-down the
estimated net proceeds from the planned sale of the Brooklyn Navy Yard project, and $6 million related to the write-down of EME's investment in the Gordonsville project due to its
planned disposition (refer to "Dispositions" for further discussion). The impairment charge relating to the peaking plants resulted from a revised long-term outlook for
capacity revenues from the peaking plants. The lower capacity revenue outlook is the result of a number of factors, including higher long-term natural gas prices and the current generation
overcapacity in the MAIN region market. See "Market Risk ExposuresIllinois Plants." The book value of these assets was written down from $286 million to an estimated
fair market value of $41 million. The estimated fair market value was determined based on discounting estimated future pretax cash flows using a 17.5% discount rate.

Asset
impairment and other charges in 2002 consisted of $61 million related to the write-off of capitalized costs associated with the termination of equipment purchase
contracts with Siemens Westinghouse, $45 million from a settlement agreement that terminated the obligation to build additional generation in Chicago, and $25 million related to the
write-off of capitalized costs associated

54

---

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 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.

Administrative
and general expenses increased $6 million in 2003 from 2002, and decreased $11 million in 2002 from 2001. The 2003 increase was primarily due to debt
restructuring costs of $16 million recorded in 2003, mostly offset by charges for severance and other related costs of $13 million recorded in 2002. The 2002 decrease was primarily due
to lower business development costs and lower long-term incentive compensation expense recorded in 2002.

Other Income (Expense)

Equity in income from unconsolidated affiliates increased 30% in 2003 from 2002, and decreased 24% in 2002 from 2001. The 2003 increase was primarily due to an
increase in EME's share of income from the Big 4 projects, Four Star Oil & Gas and the Sunrise project. 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. 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 $16 million in 2003 from 2002, and decreased $14 million in 2002 from 2001. The 2003 and 2002 decreases were primarily due to lower
interest income and higher foreign exchange losses from EME's intercompany loans.

Gains
on sale of assets were $13 million, $5 million and $41 million in 2003, 2002 and 2001, respectively. The gain on sale of assets in 2003 and 2002 represents the
sale of development projects in Thailand and the United Kingdom during December 2003 and December 2002, respectively. Proceeds from the sales were $13 million and
$6 million, respectively. Gains on sale of assets for 2001 included:

Project

Gross Proceeds

Partnership
Interest Sold

DateNevada Sun-Peak

$
11

50
%
December 5, 2001Saguaro


67

50

September 20, 2001Hopewell


27

25

June 29, 2001


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."

Interest
expense increased $46 million in 2003 from 2002, and decreased $13 million in 2002 from 2001. The 2003 increase was due to a combination of the following:



55

---



The
2002 decrease in interest expense was due to a combination of the following:



Partially
offset by:



Income Taxes

MEHC had effective tax provision (benefit) rates of (73)% in 2003, (200)% in 2002 and 54% in 2001. The change in the effective income tax benefit rate in 2003
from 2002 is due to income tax benefits related to EME's impairment charges. During the second quarter of 2003, EME recorded a tax benefit of $98 million relating to the impairment of the small
peaking plants in Illinois and its Gordonsville project. The Turkish corporate tax rate decreased from 33% to 30%, retroactive to January 1, 2003, as a result of legislation passed in
April 2003. In accordance with SFAS No. 109, "Accounting for Income Taxes," the reductions in the Turkish income tax rates resulted in an increase in income tax expense of approximately
$4 million during the second quarter of 2003 due to a reduction in deferred tax assets.

The
lower effective income tax rate in 2002 from 2001 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.

Minority Interest

Minority interest expense increased $12 million in 2003 from 2002, and increased $5 million in 2002 from 2001. Minority interest primarily relates
to 49% ownership of Contact Energy by the public in New Zealand.

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 were
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
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

56

---

project
lenders appointed an administrative receiver over the assets of Lakeland Power Ltd. An administrative receiver was appointed to take control of the affairs of Lakeland Power Ltd.
and was given a wide range of powers (specified in the U.K. Insolvency Act), including authorizing the sale of the power plant. On May 14, 2003, a third party completed the purchase of the
Lakeland power plant from the administrative receiver for £24 million. The proceeds from the sale and existing cash were used to fund partial repayment of the outstanding debt owed
to secured creditors of the project.

EME
ceased to consolidate the activities of Lakeland Power Ltd. once the administrative receiver had been appointed. The consolidated financial statements have been restated to
conform to discontinued operations treatment for all historical periods presented. Lakeland Power Ltd.'s administrative receiver has filed a claim against Norweb Energi Ltd. for
termination of the power purchase agreement. To the extent that Lakeland Power Ltd. receives payment under its claim, such amounts will first be used to repay amounts due to creditors with any
residual amount distributed to EME's subsidiary that owns the outstanding shares of Lakeland Power Ltd. There is no assurance that there will be any cash available to distribute from the
ultimate resolution of this claim. See "Mission Energy Holding Company and Subsidiaries Notes to Consolidated Financial StatementsNote 8. Discontinued Operations."

During
the year ended December 31, 2003, EME recorded losses of $2 million from discontinued operations related to administrative expenses incurred as part of the
close-out activities relating to the Lakeland project. In the fourth quarter of 2002, EME recorded 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.

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 specified liabilities associated with the plants.
The sale is 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. 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
2003, EME recorded gains of $3 million from discontinued operations primarily related to an insurance recovery from claims filed prior to the sale of the power plants,
partially offset by losses related to taxes. 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.

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.

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

57

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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 being recorded through the income statement.

Cumulative Effect of Change in Accounting Principle

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 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. As of
January 1, 2003, EME recorded a $9 million, after tax, decrease to net income as the cumulative effect of the adoption of SFAS No. 143.

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. EME commenced its
annual evaluation of goodwill on October 1, 2003. During the third quarter of 2002, 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 and, accordingly, reported this amount as a cumulative change in accounting. In accordance with SFAS No. 3, "Reporting
Accounting Changes in Interim Financial Statements," EME's financial statements for the first quarter of 2002 were restated to reflect the accounting change as of January 1, 2002.

Statement of Financial Accounting Standards No. 133

Effective January 1, 2001, EME 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 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.

On
January 1, 2001, EME recorded a $250 thousand, after tax, increase to net income 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

58

---

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:



Regional Operating Results

Overview

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" or "losses" in this section to describe EME's income or loss from continuing operations before income taxes and minority
interest.

59

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Americas

General

The following section provides a summary of the Americas Region's operating results for the three years ended December 31, 2003 together with discussions
of significant factors contributing to these results.

|                                                                   |                                                          | Years Ended December 31, |      
|------------------------------------------------------------------ | -------------------------------------------------------- | ------------------------ | -----
|
|
|Operating Revenues from Consolidated Subsidiaries                  |                                                          |                          |      
|                                                                   | Illinois Plants                                          |                          | $    
|                                                                   | Homer City                                               |                          |      
|                                                                   | Other                                                    |                          |      
|                                                                   |                                                          |                          |      
|                                                                   |                                                          | $                        | 1,605
|                                                                   |                                                          |                          |      
|Income (Loss) before Taxes and Minority Interest (Earnings/Losses) |                                                          |                          |      
|                                                                   | Consolidated operations                                  |                          |      
|                                                                   | Illinois Plants                                          |                          |      
|                                                                   | Homer City                                               |                          |      
|                                                                   | Charges related to cancellation of turbine orders/leases |                          |      
|                                                                   | Other                                                    |                          |      
|                                                                   | Unconsolidated affiliates                                |                          |      
|                                                                   | Big 4 projects                                           |                          |      
|                                                                   | Four Star Oil & Gas(1)                                   |                          |      
|                                                                   | Sunrise                                                  |                          |      
|                                                                   | March Point                                              |                          |      
|                                                                   | Asset impairment charges                                 |                          |      
|                                                                   | Other                                                    |                          |      
|                                                                   | Regional overhead                                        |                          |      
|                                                                   |                                                          |                          |      
|                                                                   |                                                          | $                        | 186  
|                                                                   |                                                          |                          |      

---

60

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Illinois Plants

Years Ended December 31,2003

2002

2001Statistics  Coal-Fired GenerationGeneration (in GWhr):Power purchase agreement


13,949


26,879


26,231Merchant


13,561


695


396Total coal-fired generation


27,510


27,574


26,627Equivalent Availability(1)


82.7
%(3)

84.8
%(4)

82.9
%(4)Forced outage rate(2)


7.7
%

6.5
%

9.5
%Average realized energy price/MWhr:Power purchase agreement

$
18.08

$
16.78

$
15.87Merchant

$
26.57

$
20.96

$
28.96Total coal-fired generation

$
22.27

$
16.89

$
16.06Capacity revenues (in millions)

$
380

$
601

$
582


---

Operating revenues from the Illinois Plants decreased $95 million in 2003 compared to 2002, and increased $60 million in 2002
compared to 2001. The 2003 decrease was primarily due to lower capacity revenue resulting from the reduction in megawatts contracted under the power purchase agreements with Exelon Generation,
partially offset by an increase in energy revenue due to the shift to merchant generation. The merchant generation currently earns minimal capacity revenues but higher energy
revenues due to higher average realized energy prices as compared to the energy prices set forth in the power purchase agreements with Exelon Generation. 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.

Earnings
from the Illinois Plants decreased $344 million in 2003 from 2002, and increased $129 million in 2002 from 2001. Discrete items affecting the earnings of the
Illinois Plants include:



61

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Earnings
from the Illinois Plants, excluding the above discrete items, for 2003, declined from 2002 primarily due to lower revenues as described above. Earnings from the Illinois Plants
for 2002 improved over 2001 due to the following factors:



During
2003, Midwest Generation had one unit at the Collins Station available for sale into the wholesale power market. Due to the substantial increase in natural gas prices in 2003, the
marginal cost of generation generally exceeded the spot price for energy. As a result, merchant sales from the Collins Station were minimal during 2003. See "Liquidity and Capital
ResourcesAgreement in Principle to Terminate the Collins Station Lease."

The
earnings of the Illinois Plants included interest income related to loans to EME of $113 million in 2003, $119 million in 2002 and $130 million in 2001. In
August 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 guarantee of the related 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.

Losses
from price risk management activities were $3 million in 2003, $1 million in 2002 and $21 million in 2001. The 2003 losses primarily reflect a
mark-to-market adjustment of an embedded derivative Midwest Generation has to purchase energy from Calumet Energy Team LLC. Also included in the 2003 losses is the ineffective
portion of forward contracts which are derivatives that qualify as cash flow hedges under SFAS No. 133. The 2002 and 2001 losses represent the change in market value of futures contracts with
respect to a portion of anticipated fuel purchases that did not qualify as cash flow hedges under SFAS No. 133.

Homer City

Years Ended December 31,2003

2002

2001StatisticsGeneration (in GWhr)


14,403


12,111


12,922Availability(1)


88.7
%

76.8
%

87.4
%Forced outage rate(2)


5.1
%

16.0
%

4.5
%Average realized energy price/MWhr

$
34.02

$
28.70

$
33.07Capacity revenues (in millions)

$
30

$
41

$
67


---

62

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Operating revenues from Homer City increased $132 million in 2003 from 2002, and decreased $105 million in 2002 from 2001. The 2003
increase was due to increased generation and higher energy prices. The increase in generation primarily resulted from an unplanned outage on Unit 3 and extended outages on Units 1 and 2 during the
first half of 2002. 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 operated with the SCR bypassed until June 19, 2003, when it was returned to service. As a result of the Unit 3 ductwork collapse, EME 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
2002 decrease primarily resulted from lower electric revenues from the Homer City facilities due to decreased generation from the unplanned outages described above and lower energy and capacity
prices.

Earnings
from Homer City increased $100 million in 2003 compared to 2002 and decreased $89 million in 2002 compared to 2001. The 2003 increase in earnings is due to
increased generation and higher energy prices. See "Market Risk ExposuresHomer City Facilities." The 2002 decrease in earnings is due to the outages described above and lower
wholesale energy and capacity prices. 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. 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.

Gains
(losses) from price risk management activities were $11 million in 2003 and $(2) million in 2002. The gains (losses) primarily represent the ineffective portion of forward
contracts which are derivatives that qualify as cash flow hedges under SFAS No. 133. See "Consolidated Operating ResultsOperating Revenues" for further discussion. No
comparable amount was recorded for 2001.

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 and
recorded a loss of $25 million during the year ended December 31, 2001. In September 2002, EME notified Siemens Westinghouse of its election to terminate all of the equipment
purchase contracts for nine turbines effective October 25, 2002, in light of lower wholesale energy prices during 2002. Accordingly, EME recorded approximately $61 million to
write-off capitalized costs associated with the termination of these contracts during the year ended December 31, 2002.

Big 4 Projects

EME owns partnership investments (50% ownership or less) in Kern River Cogeneration Company, Midway-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. See "New Accounting StandardsStatement of Financial Accounting Standards Interpretation No. 46," for discussion of EME's accounting for this entity. 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.

63

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Earnings
from the Big 4 projects increased $41 million in 2003 from 2002, and decreased $112 million in 2002 from 2001. The change in earnings in these periods was largely
due to higher energy prices in 2003. The earnings from the Big 4 projects included interest expense related to the debt financing described above of $16 million, $19 million and
$22 million in 2003, 2002 and 2001, respectively.

Four Star Oil & Gas

As of December 31, 2003, EME owned a 38.5% direct and indirect interest, with 37.4% 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 $43 million in 2003, $21 million in 2002 and $41 million in 2001. The 2003 increase in earnings was
primarily due to higher natural gas prices. 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 and $45 million in 2001 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 $19 million in 2003 from 2002, and increased $2 million in 2002 from 2001. The 2003 increase in earnings
primarily resulted from additional earnings from the completion of Phase 2 of the Sunrise project in June 2003. 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.

March Point

Earnings from March Point decreased $8 million in 2003 from 2002, and increased $10 million in 2002 from 2001. The change in earnings in these
periods 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. In addition, the
2003 decrease in earnings was due to lower electric revenues in 2003.

Asset Impairment Charges

Asset impairment charges were $59 million in 2003, none in 2002, and $34 million in 2001. In 2003, EME recorded a $59 million loss related to
the write-down of EME's investment in the Brooklyn Navy Yard and Gordonsville projects due to their planned dispositions. In 2001, EME recorded a $34 million loss related to the
write-down of EME's investments in the Commonwealth Atlantic, Gordonsville, Harbor and James River projects due to their planned dispositions.

Other

Net earnings from other projects in the Americas region (consolidated subsidiaries and unconsolidated affiliates) decreased $26 million in 2003 from 2002,
and decreased $52 million in 2002 from 2001. The 2003 decrease was partially due to lower earnings from the Westside projects due to mark to market gains recorded in 2002 and losses from the TM
Star project due to a change in market value of natural gas contracts that did not qualify for hedge accounting under SFAS No. 133. The 2002

64

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decrease
was primarily due to a $45 million gain recorded in 2001 related to the sale of EME's investment in the Nevada Sun-Peak, Saguaro and Hopewell projects in 2001.

Asia Pacific

General

The following section provides a summary of the Asia Pacific Region's operating results for the three years ended December 31, 2003 together with
discussions of significant factors contributing to these results.

|                                                            |                           | Years Ended December 31, |      
|----------------------------------------------------------- | ------------------------- | ------------------------ | -----
|
|
|Operating Revenues from Consolidated Subsidiaries           |                           |                          |      
|                                                            | Contact Energy            |                          | $    
|                                                            | Loy Yang B                |                          |      
|                                                            | Other                     |                          |      
|                                                            |                           |                          |      
|                                                            |                           | $                        | 1,003
|                                                            |                           |                          |      
|Income (Loss) before Taxes and Minority Interest (Earnings) |                           |                          |      
|                                                            | Consolidated operations   |                          |      
|                                                            | Contact Energy(1)         |                          |      
|                                                            | Loy Yang B                |                          |      
|                                                            | Other                     |                          |      
|                                                            | Unconsolidated affiliates |                          |      
|                                                            | Paiton                    |                          |      
|                                                            | Other                     |                          |      
|                                                            | Regional overhead         |                          |      
|                                                            |                           |                          |      
|                                                            |                           | $                        | 221  
|                                                            |                           |                          |      

---

Contact Energy

Operating revenues increased $257 million in 2003 from 2002, and increased $197 million in 2002 from 2001. The 2003 increase was due to increased
retail revenues and higher generation which primarily resulted from the Taranaki Station acquisition in March 2003. In addition, there was a 24% increase in the average exchange rate of the New
Zealand dollar compared to the U.S. dollar during 2003 compared to 2002. The 2002 increase was 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.

Earnings
from Contact Energy, included in the consolidated statements of income of EME as described above, increased $29 million in 2003 from 2002, and increased
$16 million in 2002 from 2001. In 2003, the higher revenues discussed above were partially offset by increased operating and interest costs associated with the Taranaki Station acquisition. In
addition, 2003 earnings included a $4 million gain in 2003 from price risk management activities related to a change in market value of electricity and financial contracts that were not
designated as cash flow hedges for hedge accounting under SFAS

65

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No. 133.
The increase in earnings in 2002 is primarily due to increased retail sales from the successful expansion of Contact Energy retail customer base and a 12% 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.

Loy Yang B

Operating revenues increased $20 million in 2003 from 2002, and increased $28 million in 2002 from 2001. The 2003 increase was due to a 19% increase
in the average exchange rate of the Australian dollar compared to the U.S. dollar during 2003 compared to 2002. The 2003 increase was partially offset by lower pool prices for the power sold into the
wholesale energy market. The increase in operating revenues in 2002 is due to higher generation and pool prices for the power sold into the wholesale energy market.

Earnings
from Loy Yang B decreased $11 million in 2003 from 2002, and increased $41 million in 2002 from 2001. The 2003 decrease in earnings is due to higher plant
maintenance costs primarily related to the planned outage in March 2003. The increase in earnings from 2002 is due to higher electric revenues discussed above.

Paiton Energy

Earnings from Paiton Energy increased $31 million in 2003 from 2002, and increased $28 million in 2002 from 2001. The 2003 increase in earnings was
primarily due to lower project interest expense and lower depreciation (due to a change from 30 to 41.5 years in the useful life of the power plant resulting from an extension of the power
sales agreement). Earnings from Paiton Energy in 2002 reflect revenue recognized in accordance with the Binding Term Sheet. Prior to the execution of the Binding Term Sheet on January 1, 2002,
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.

Other

Operating revenues from other consolidated subsidiaries in the Asia Pacific Region increased $19 million in 2003 from 2002, and increased
$18 million in 2002 from 2001. Earnings from other projects in the Asia Pacific Region (consolidated subsidiaries and unconsolidated affiliates) increased $29 million in 2003 from 2002,
and increased $5 million in 2002 from 2001. The 2003 increase in revenues is due to higher electric revenues from the Kwinana project primarily due to an increase in the value of the Australian
dollar compared to the U.S. dollar. The 2003 increase in earnings reflects a gain of $13 million on a sale of a development project in Thailand. No comparable gain was recorded in 2002 or 2001.
The increase in both operating revenues and earnings in 2002 was 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.

66

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Europe

General

The following section provides a summary of the Europe Region's operating results for the three years ended December 31, 2003 together with discussions of
significant factors contributing to these results.

|                                                               |                           | Years Ended December 31, |    
|-------------------------------------------------------------- | ------------------------- | ------------------------ | ---
|
|
|Operating Revenues from Consolidated Subsidiaries(1)           |                           |                          |    
|                                                               | First Hydro               |                          | $  
|                                                               | Doga(2)                   |                          |    
|                                                               | Other                     |                          |    
|                                                               |                           |                          |    
|                                                               |                           | $                        | 528
|                                                               |                           |                          |    
|Income (Loss) before Taxes and Minority Interest (Earnings)(1) |                           |                          |    
|                                                               | Consolidated operations   |                          |    
|                                                               | First Hydro               |                          |    
|                                                               | Doga                      |                          |    
|                                                               | Other                     |                          |    
|                                                               | Unconsolidated affiliates |                          |    
|                                                               | ISAB                      |                          |    
|                                                               | Other                     |                          |    
|                                                               | Regional overhead         |                          |    
|                                                               |                           |                          |    
|                                                               |                           | $                        | 43 
|                                                               |                           |                          |    

---

First Hydro

Operating revenues increased $60 million in 2003 from 2002, and increased $84 million in 2002 from 2001. The 2003 increase was primarily due to an
8% increase in the average exchange rate of the British pound compared to the U.S. dollar during 2003, compared to 2002. The 2003 increase was partially offset by lower ancillary services revenues in
2003. 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Europe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 First Hydro plant is expected to provide for higher electric revenues during their winter months.

Earnings
from First Hydro decreased $11 million in 2003 from 2002, and increased $10 million in 2002 from 2001. The change in earnings in this period was primarily due to
the impact of the change in

67

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market
prices. In addition, EME has reduced plant operating costs in 2002 in light of the United Kingdom market.

Doga

Revenues from Doga increased $13 million in 2003 from 2002, and decreased $7 million in 2002 from 2001. The 2003 increase was primarily due to an
increase in steam sales and higher natural gas prices. 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.

Earnings
from Doga decreased $4 million in 2003 from 2002, and increased $6 million in 2002 from 2001. The increase in earnings in 2002 was primarily due to increased
generation, and lower operations and maintenance costs, partially offset by foreign currency losses.

ISAB

Earnings from ISAB decreased $4 million in 2003 from 2002, and increased $22 million in 2002 from 2001. The 2003 decrease in earnings was primarily
due to lower generation as a result of an unplanned outage in December 2003. The 2002 increase in earnings was primarily due to higher generation and settlement of insurance claims.

Other

Operating revenues from other consolidated subsidiaries in the Europe region increased $3 million in 2003 from 2002, and increased $6 million in
2002 from 2001. Earnings from other projects in the Europe region (consolidated subsidiaries and unconsolidated affiliates) increased $8 million in 2003 from 2002, and decreased
$4 million in 2002 from 2001. The 2003 increase in both operating revenues and earnings was primarily due to increased operating revenues from EME's Spanish Hydro project largely due to higher
generation caused by more rainfall in 2003 compared to 2002. 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 compared to 2001, partially offset by the gain on sale of a development project in the United Kingdom during December 2002.

New Accounting Standards

Introduction

A number of changes in accounting standards or interpretations were issued or effective during 2003, including the following items that were relevant to EME.

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 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. As of
January 1, 2003, EME recorded a $9 million, after tax, decrease to net income as the cumulative effect of the adoption of SFAS No. 143.

68

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Statement of Financial Accounting Standards No. 149

In April 2003, the Financial Accounting Standards Board (FASB) issued Statement of Financial Accounting Standards No. 149, "Amendment of Statement
133 on Derivative Instruments and Hedging Activities." This statement amends and clarifies financial accounting and reporting for derivative instruments and for hedging activities under SFAS
No. 133. The amendment reflects decisions made by the FASB and the Derivatives Implementation Group (DIG) process in connection with issues raised about the application of SFAS No. 133.
Generally, the provisions of SFAS No. 149 will be applied prospectively for contracts entered into or modified after June 30, 2003 and for hedging relationships designated after
June 30, 2003. SFAS No. 149 provisions that resulted from the DIG process that became effective in fiscal quarters beginning before June 15, 2003 will continue to be applied based
upon their original effective dates. The adoption of this standard had no impact on EME's consolidated financial statements.

Statement of Financial Accounting Standards No. 150

Effective July 1, 2003, EME adopted Statement of Financial Accounting Standards No. 150, "Accounting for Certain Financial Instruments with
Characteristics of both Liabilities and Equity." SFAS No. 150 establishes standards for how to classify and measure certain financial instruments with characteristics of both liabilities and
equity. It requires that an issuer classify a financial instrument that is within its scope as a liability or asset, as appropriate. At July 1, 2003, EME's company-obligated mandatorily
redeemable securities and redeemable preferred stock were reclassified from the mezzanine equity section to the liability section of EME's consolidated balance sheet. Dividend payments on these
instruments are being recorded as interest expense commencing July 1, 2003 on EME's consolidated
statements of income. Prior period financial statements are not permitted to be restated for either of these changes. Therefore, there was no cumulative impact due to this accounting change incurred
upon adoption.

Emerging Issues Task Force No. 01-08

In May 2003, the Emerging Issues Task Force (EITF) reached a consensus on Issue No. 01-08, "Determining Whether an Arrangement Contains
a Lease," which provides guidance on how to determine whether an arrangement contains a lease that is within the scope of SFAS No. 13, "Accounting for Leases." A lease is defined as an
agreement conveying the right to use property, plant, or equipment (land and/or depreciable assets), usually for a stated period of time. The guidance issued by the EITF could affect the
classification of a power sales agreement that meets specific criteria, such as a power sales agreement for substantially all of the output from a power plant to one customer. If a power sales
agreement meets the guidance issued by the EITF, it would be accounted for as a lease subject to SFAS No. 13. The consensus is effective prospectively for EME arrangements entered into or
modified after June 30, 2003. The consensus had no impact on EME's consolidated financial statements.

Other Statement of Financial Accounting Standards No. 133 Guidance

In June 2003, the Derivative Implementation Group of the FASB under Statement No. 133 Implementation Issue Number C20 issued clarifying guidance
related to pricing adjustments in contracts that qualify under the normal purchases and normal sales exception under SFAS No. 133. This implementation guidance became effective on
October 1, 2003. The guidance had no impact on EME's consolidated financial statements.

69

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Emerging Issues Task Force No. 03-11

In July 2003, the EITF reached a consensus on Issue No. 03-11, "Reporting Realized Gains and Losses on Derivative Instruments that are
Subject to FASB Statement No. 133, Accounting for Derivative Instruments and Hedging Activities, and Not Held for Trading Purposes." EITF Issue No. 03-11 provides guidance on
whether realized gains and losses on derivative contracts should be reported on a net or gross basis and concludes such classification is a matter of judgment that depends on the relevant facts and
circumstances. In analyzing the facts and circumstances, EITF
Issue No. 99-19, "Reporting Revenue Gross as a Principal Versus Net as an Agent," should be considered. Gains and losses on non-trading derivative instruments are
recognized in net gains (losses) from price risk management and energy trading in the accompanying Consolidated Income Statements. The consensus is effective prospectively for EME's transactions or
arrangements entered into or modified after September 30, 2003. The consensus had no impact on EME's consolidated financial statements.

Statement of Financial Accounting Standards Interpretation No. 45

In November 2002, the FASB 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 adoption of this standard had no impact on EME's consolidated financial statements. See "Contractual Obligations, Commitments and
ContingenciesGuarantees and Indemnities."

Statement of Financial Accounting Standards Interpretation No. 46

In December 2003, the FASB issued Statement of Financial Accounting Standards Interpretation No. 46, "Consolidation of Variable Interest Entities"
(FIN 46). 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. 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. 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. This interpretation is effective for special purpose entities as of
December 31, 2003 and for all other entities as of March 31, 2004.

Deconsolidation of Special Purpose Entities

In accordance with FIN 46, EME deconsolidated the following two financing entities:



70

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Variable Interest Entities

EME has concluded that Brooklyn Navy Yard Cogeneration Partners L.P. (Brooklyn) is a variable interest entity in which EME may be the primary beneficiary since
EME expects to absorb the majority of Brooklyn's losses, if any, and expects to receive a majority of Brooklyn's residual returns, if any. This determination is subject to further analysis of
Brooklyn's long-term power sales agreement (see discussion of power contracts below). On December 31, 2003, EME agreed to sell its 50% partnership interest in Brooklyn to a third party.
Completion of the sale, currently expected in the first quarter of 2004, is subject to closing conditions, including obtaining regulatory approval. If the sale is completed prior to March 31,
2004, EME will not be required to consolidate this entity regardless of the results of the power contract analysis described above. If the sale is not completed by this date, EME may be required to
consolidate Brooklyn at March 31, 2004 based on the historical cost of the assets, liabilities and non-controlling interest. The consolidation of this entity would result in EME
recording approximately a $44 million, after tax, decrease to net income as the cumulative effect of consolidating this variable interest entity. This loss is primarily due to cumulative losses
allocated to the other 50% partner in excess of their equity contributions. If this loss was recorded, it would be reversed in a subsequent period if the sale was completed after March 31,
2004.

Guidance
related to implementation of FIN 46 is still evolving. Under an interpretation of FIN 46, a long-term power contract may constitute a variable interest in an asset
that absorbs expected losses from the equity holders. If this interpretation were applied to EME's unconsolidated affiliates it could result in all of EME's unconsolidated affiliates related to
project investments being classified as variable interest entities, although the primary beneficiary may be the counterparties to the long-term contracts (including the counterparty to the
Brooklyn Navy Yard power and steam purchase agreement). EME maximum exposure to loss is generally limited to its investment in these entities.

71

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LIQUIDITY AND CAPITAL RESOURCES

Introduction

At December 31, 2003, MEHC and its subsidiaries had cash and cash equivalents of $654 million. MEHC's consolidated debt at December 31, 2003
was $7.4 billion, including $693 million of debt maturing on December 15, 2004 which is owed by EME's largest subsidiary, Edison Mission Midwest Holdings. In addition, EME's
subsidiaries have $6.7 billion of long-term lease obligations that are due over a period ranging up to 31 years. See "Risks Related to the Business."

The
following discussion of liquidity and capital resources is organized in the following sections:

PageMEHC's Liquidity

72Key Financing Developments

72Agreement in Principle to Terminate the Collins Station Lease

732004 Capital Expenditures

74MEHC's Historical Consolidated Cash Flow

74EME's Credit Ratings

77EME's Liquidity as a Holding Company

79Dividend Restrictions in Major Financings

82Financial Ratios

85Contractual Obligations, Commitments and Contingencies

90Off-Balance Sheet Transactions

96Environmental Matters and Regulations

99


MEHC's Liquidity

MEHC's ability to honor its obligations under the senior secured notes and the term loan, and to pay overhead is entirely dependent upon the receipt of dividends
from EME and receipt of tax-allocation payments from MEHC's parent, Edison Mission Group, and ultimately Edison International (seeIntercompany Tax-Allocation
Payments). Dividends from EME are limited based on its earnings and cash flow, terms of restrictions contained in EME's contractual obligations (including its corporate credit facility), EME's charter
documents, business and tax considerations, and restrictions imposed by applicable law. MEHC did not receive any distributions from EME during 2003.

At
December 31, 2003, MEHC had cash and cash equivalents of $150 million (excluding amounts held by EME and its subsidiaries). The lenders under MEHC's $385 million
term loan due in 2006 have the right to require MEHC to repurchase up to $100 million of principal amount at par on July 2, 2004 (referred to as the "Term Loan Put-Option").
In order for MEHC to have sufficient cash in the event of an exercise of a significant portion, or all, of the Term Loan Put-Option, MEHC would require additional cash from dividends from
EME, or would need to either extend the effective date of the Term Loan Put-Option or extend or refinance the term loan. The timing and amount of dividends from EME and its subsidiaries
may be affected by many factors beyond MEHC's control. Dividends from EME are currently limited as described in "Ability of EME to Pay Dividends."

Key Financing Developments

On December 11, 2003, EME's subsidiary, Mission Energy Holdings International, received funding under a three-year, $800 million secured
loan from Citigroup, Credit Suisse First Boston, JPMorganChaseBank, and Lehman Brothers. Interest on this secured loan is based on LIBOR (with a LIBOR floor of 2%) plus 5%. After payment of
transaction expenses, a portion of the net proceeds from this financing was used to make an equity contribution of $550 million to Edison Mission Midwest Holdings which, together with cash on
hand, was used to repay Edison Mission Midwest Holdings' $781 million indebtedness due December 11, 2003. The remaining net proceeds from this financing

72

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were
used to make a deposit of cash collateral of approximately $67 million under the new letter of credit facility described below and to repay approximately $160 million of
indebtedness of a foreign subsidiary under the Coal and Capex facility guaranteed by EME. Mission Energy Holdings International owns substantially all of EME's international operations through its
subsidiary, MEC International B.V. As security for this loan, Mission Energy Holdings International, directly, and through its subsidiaries, pledged approximately 65% of its ownership interest in MEC
International B.V. See "Management's Overview" for discussion of the plan to sell off some of or all of EME's international projects.

On
December 11, 2003, EME's subsidiary, Midwest Generation EME, LLC, entered into a three-year, $100 million letter of credit facility with Citibank, N.A., as
Issuing Bank. Under the terms of this letter of credit facility, Midwest Generation EME is required to deposit cash in a bank account in order to cash collateralize any letters of credit that may be
outstanding under it. The bank account is pledged to the Issuing Bank. On December 11, 2003, EME canceled $67 million of the commitment under its existing line of credit and was relieved
of its reimbursement obligations with respect to the same amount of letters of credit issued thereunder. Concurrently, such letters of credit were issued under Midwest Generation EME's new letter of
credit facility, and Midwest Generation EME made a deposit of cash collateral in the amount of $67 million for this purpose. The funds for this deposit were obtained as part of the financing
referred to above. At December 31, 2003, $47 million of letters of credit were outstanding under Midwest Generation EME's letter of credit facility. Midwest Generation EME owns 100% of
Edison Mission Midwest Holdings, which in turn owns 100% of Midwest Generation LLC.

Agreement in Principle to Terminate the Collins Station Lease

Midwest Generation operates the Collins Station under a long-term lease. See "Off-Balance Sheet Transactions" for detail of
the lease of the Collins Station. Due in part to higher long-term natural gas prices and the current oversupply of generation in the MAIN region, Midwest Generation does not believe the
Collins Station is economically competitive in the current marketplace. In light of this, Midwest Generation has agreed in
principle with the lease equity investor to terminate the Collins Station lease. The agreement in principle sets forth specified conditions required for the termination, including Midwest Generation
successfully borrowing funds to finance the repayment of Collins Station lease debt of $774 million and settlement of Midwest Generation's termination liability with the lease equity investor.
There is no assurance that the agreement in principle will result in termination of the Collins Station lease. If the termination occurs, Midwest Generation will take title to the Collins Station and,
subject to its contractual obligation to Exelon Generation, plans to subsequently abandon the Collins Station or sell it to a third party.

If
Midwest Generation completes the lease termination and subsequently abandons the Collins Station, EME expects to record a pretax loss of approximately $1 billion (approximately
$620 million after tax). This loss will reduce EME's net worth (using December 31, 2003) from $1.9 billion to approximately $1.3 billion. To avoid the possibility of
covenant defaults which could arise from a decline in net worth, EME plans to take the following actions before or simultaneously with the Collins Station lease termination:



If
Midwest Generation completes the termination of the Collins Station lease followed by abandonment or sale to a third party, EME anticipates that the termination payment would result
in a substantial income tax deduction. Because of these arrangements, EME does not expect that termination of the Collins Station lease will have a material adverse effect on its liquidity. If the
lease

73

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termination
does not occur, the terms of the lease will remain in effect and Midwest Generation will seek to restructure the lease with the lease equity investor.

2004 Capital Expenditures

The estimated construction expenditures of EME's subsidiaries for 2004 are $78 million. These expenditures are planned to be financed by existing
subsidiary credit agreements and cash generated from their operations.

MEHC's Historical Consolidated Cash Flow

Consolidated Cash Flows from Operating Activities

Net cash provided by (used in) operating activities:

Years Ended December 31,2003

2002

2001(in millions)Continuing operations

$
713

$
869

$
12Discontinued operations


(1
)

54


(113
)$
712

$
923

$
(101
)


Cash
provided by operating activities from continuing operations decreased $155 million in 2003 from 2002 and increased $857 million in 2002 from 2001. The 2003 decrease is
due to a combination of the following:



Partially
offset by:



The
2002 increase is primarily due to a combination of the following:



Cash
provided by operating activities from discontinued operations in 2002 reflects a combination of the following:



Cash
used in operating activities from discontinued operations in 2001 reflects a combination of the following:



74

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Consolidated Cash Flows from Financing Activities

Net cash used in financing activities:

Years Ended December 31,2003

2002

2001(in millions)Continuing operations

$
(322
)
$
(298
)
$
(198
)Discontinued operations





(19
)

(1,085
)$
(322
)
$
(317
)
$
(1,283
)


Cash
used in financing activities from continuing operations increased $23 million in 2003 from 2002, and increased $101 million in 2002 from 2001. The 2003 increase was
due to a combination of the following:



Partially
offset by:



The
2002 increase was due to the following:



Partially
offset by:



Cash
used in financing activities from discontinued operations in 2002 reflects the following:



Cash
used in financing activities from discontinued operations in 2001 reflects the following:



75

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Consolidated Cash Flows from Investing Activities

Net cash provided by (used in) investing activities:

Years Ended December 31,2003

2002

2001(in millions)Continuing operations

$
(480
)
$
(305
)
$
(50
)Discontinued operations


4


1


926$
(476
)
$
(304
)
$
876


Cash
used in investing activities from continuing operations increased $175 million in 2003 from 2002, and increased $255 million in 2002 from 2001. The 2003 increase was
due to a combination of the following:



Partially
offset by:



The
2002 increase was due to a combination of the following:



Partially
offset by:



Cash
provided by investing activities from discontinued operations in 2001 is due to the following:



76

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EME's Credit Ratings

Overview

Credit ratings for EME and its subsidiaries, Edison Mission Midwest Holdings and Edison Mission Marketing & Trading, are as follows:

Moody's Rating

S&P RatingEME

B2

BEdison Mission Midwest Holdings

Ba3

BEdison Mission Marketing & Trading

Not Rated

B


On
October 28, 2003, Standard & Poor's Ratings Service downgraded EME's senior unsecured credit rating to B from BB-. Standard & Poor's also lowered the
credit ratings of EME's wholly owned indirect subsidiaries, Edison Mission Midwest Holdings (syndicated loan facility to B from BB-) and Edison Mission Marketing & Trading
(corporate credit rating to B from BB-). Standard & Poor's removed the ratings from CreditWatch with negative implications on December 12, 2003, following the repayment of
$781 million of debt by Edison Mission Midwest Holdings; however, the outlook remains negative. In addition, Moody's Investors Service has assigned a negative rating outlook for EME and Edison
Mission Midwest Holdings.

These
ratings actions did not trigger any defaults under EME's credit facilities or those of the other affected entities. See "Credit Ratings of Edison Mission Midwest Holdings" for a
discussion of the impact of the ratings action on Edison Mission Midwest Holdings. EME does not have any "rating triggers" contained in subsidiary financings that would result in EME being required to
make equity contributions or provide additional financial support to its subsidiaries.

The
credit ratings of EME are below investment grade and, accordingly, EME has agreed to provide collateral in the form of cash and letters of credit for the benefit of counterparties
for its price risk management and domestic trading activities related to accounts payable and unrealized losses ($65 million as of February 27, 2004). EME has also provided collateral
for a portion 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, under which
letters of credit totaling £20 million have been issued as of February 27, 2004.

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

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 further. EME notes that these credit ratings are not recommendations to buy, sell or hold its securities and may be revised at any time by a rating agency.

Credit Ratings of Edison Mission Midwest Holdings

As a result of Edison Mission Midwest Holdings' credit rating being below investment grade since October 2002, provisions in the agreements binding on
Edison Mission Midwest Holdings and Midwest Generation have restricted the ability of Edison Mission Midwest Holdings to make distributions to its parent company, thereby eliminating distributions to
EME. The provisions in the agreements binding on Edison Mission Midwest Holdings required it to deposit, on a quarterly basis, 100% of its excess cash flow as defined in the agreements into a cash
flow recapture account held and maintained by the

77

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collateral
agent. In accordance with these provisions, Edison Mission Midwest Holdings deposited $246 million into the cash flow recapture account in 2002 and 2003.

As
a result of the October 28, 2003 Standard & Poor's downgrade of Edison Mission Midwest Holdings to B from BB-, the cash on deposit in the cash flow recapture
account ($246 million) was required to be used to prepay Edison Mission Midwest Holdings' indebtedness, with the amount of such prepayment applied ratably to the $911 million and
$808 million tranches thereof. Therefore, on October 29, 2003, $130 million from the cash flow recapture account was applied to the $911 million
tranche, and $116 million to the $808 million tranche, thereby reducing Edison Mission Midwest Holdings' debt obligations to $781 million and $693 million, respectively.
Subsequently, Edison Mission Midwest Holdings repaid the $781 million tranche in full on December 11, 2003. In the future, so long as Edison Mission Midwest Holdings' ratings remain at
the current level or lower, amounts of excess cash flow deposited in the cash flow recapture account at the end of each calendar quarter will be used upon deposit to prepay amounts then outstanding
under the $693 million bank facility. There was no change to the cost of borrowings for Edison Mission Midwest Holdings as a result of the downgrade.

Credit Rating of Edison Mission Marketing & Trading

Pursuant to the Homer City sale-leaseback documents, a below investment grade credit rating of Edison Mission Marketing & Trading restricts the
ability of EME Homer City Generation L.P. to enter into permitted trading activities, as defined in the documents, with Edison Mission Marketing & Trading to sell forward the output of the
Homer City facilities. 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, which has a below investment grade credit rating, and EME Homer City is not
rated. Therefore, in order for EME to continue to sell forward the output of the Homer City facilities, 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 such sales, under specified conditions, through December 31, 2004. EME Homer City continues to be in compliance with the terms of the consent, although as a result of the
downgrade of Edison Mission Marketing & Trading's corporate credit rating to B from BB-, the consent is now revocable. The owner participant has not indicated that it intends to
revoke the consent; however, there can be no assurance that it will not do so in the future. Revocation of the consent would not affect trades between Edison Mission Marketing & Trading and EME
Homer City that had been entered into while the consent was still in effect. EME is permitted to sell the output of the Homer City facilities into the spot market at any time. See "Market
Risk ExposuresHomer City Facilities."

78

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EME's Liquidity as a Holding Company

Overview

EME has a $145 million corporate credit facility that expires on September 17, 2004. At December 31, 2003, EME had borrowing capacity of
$145 million and corporate cash and cash equivalents of $179 million. During 2003, EME's cash position increased primarily due to an increase of distributions received from its
consolidated subsidiaries and initial distributions from the Sunrise project upon completion of project financing. The timing and amount of distributions from EME's subsidiaries may be affected by
many factors beyond its control. See "Historical Distributions Received by EMEDividend Restrictions in Major Financings." Also see "Risks Related to the
Business." 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."

EME's
corporate credit facility provides credit available in the form of cash advances or letters of credit. At December 31, 2003, there were no cash advances outstanding or
letters of credit outstanding under the credit facility. In addition to the interest payments, EME pays a facility fee determined by its long-term credit ratings (1.00% at
December 31, 2003) on the 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, 2003, 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
"EME's Interest Coverage Ratio."

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Historical Distributions Received By EME

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 31,2003

2002(in millions)Domestic ProjectsDistributions from Consolidated Operating Projects:EME Homer City Generation L.P. (Homer City facilities)(1)

$
128

$
Holding companies of other consolidated operating projects


1


2Distributions from Unconsolidated Operating Projects:Edison Mission Energy Funding Corp. (Big 4 Projects)(2)


98


137Four Star Oil & Gas Company


21


21Sunrise Power Company(3)


69


Holding companies for Westside projects


25


42Holding companies of other unconsolidated operating projects


7


10Total Distributions from Domestic Projects

$
349

$
212International Projects (Mission Energy Holdings International)Distributions from Consolidated Operating Projects:First Hydro Holdings (First Hydro project)

$
18

$
Loy Yang B


39


27Doga


18


47Contact Energy


16


12Valley Power


8


Kwinana


4


6Distributions from Unconsolidated Operating Projects:ISAB Energy


27


1IVPC4 (Italian Wind project)


10


33Derwent


3


2Paiton(4)


9


Tri Energy


4


3Holding companies of other unconsolidated operating project


2


8Total Distributions from International Projects

$
158

$
139Total Distributions

$
507

$
351


---

80

---

Total distributions to EME increased between 2003 and 2002 due to:



Partially
offset by:



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 tax 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 Edison 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, 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. MEHC received $61 million and
$89 million in tax-allocation payments from Edison International during 2003 and 2002, respectively. EME received $112 million and $395 million in
tax-allocation payments from Edison International during 2003 and 2002, respectively. In the future, based on the application of the factors cited above, MEHC and EME may be obligated
during periods it generates taxable income to make payments under the tax-allocation agreements.

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Dividend Restrictions in Major Financings

General

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. EME
itself has restrictions on its ability to pay dividends under its organizational documents and its corporate credit facility. See "Financial RatiosAbility of EME to Pay
Dividends."

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. (Illinois Plants)

Edison Mission Midwest Holdings Co. is the borrower under a $1.9 billion credit facility with a group of commercial banks. Amounts outstanding under this
facility have been reduced to $693 million as of December 31, 2003. 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. As part of the original acquisition,
Midwest Generation entered into a sale-leaseback transaction for the Collins Station, which Edison Mission Midwest Holdings guarantees, and then subsequently entered into
sale-leaseback transactions 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 must be in compliance with the covenants specified in these agreements, including maintaining a minimum credit rating. Because Edison Mission Midwest Holdings' credit rating is 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 "EME's Credit Ratings."

Edison
Mission Midwest Holdings must 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. 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, 2003, the historical debt service coverage ratio was 2.06 to 1 and the
debt-to-capital ratio was approximately 0.36 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.

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EME Homer City Generation L.P. (Homer City facilities)

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



At
the end of each quarter, the equity and debt portions of rent then due and payable must have been paid. The senior rent service coverage ratio (discussed in the bullet point above)
projected for each of the prospective two twelve-month periods must be greater than 1.7 to 1. No more than two rent default events may have occurred, whether or not cured. A rent default event is
defined as the failure to pay the equity portion of the rent within five business days of when it is due.

During
the 12 months ended December 31, 2003, the senior rent service coverage ratio was 4.68 to 1.

Edison Mission Energy Funding Corp. (Big 4 Projects)

EME's subsidiaries, which EME refers to in this context 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 trust accounts 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 the guarantors and Edison Mission Energy Funding are in compliance with the terms of the covenants in their financing documents, including the following
requirements measured on the date of distribution:



The
debt service coverage ratio is determined primarily based upon 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, 2003, the debt
service coverage ratio was 2.55 to 1. Although the credit ratings of Edison Mission Energy Funding's notes and bonds are below investment grade, this has no effect on the ability of the guarantors to
make distributions to EME.

Mission Energy Holdings International

Mission Energy Holdings International owns substantially all of EME's international operations through its subsidiary, MEC International B.V., as more fully
described in "Key Financing Developments."

83

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In
order to make a distribution, Mission Energy Holdings International must be in compliance with the covenants specified in the credit agreement, including the following:



When
measured for the twelve-month period ended December 31, 2003, Mission Energy Holdings International interest coverage ratio was 2.75 to 1.

The
following subsidiaries of EME have guaranteed the obligations of Mission Energy Holdings International under its secured credit agreement.



Distributions
may be made by any of these entities so long as neither a default nor event of default exists under the Mission Energy Holdings International secured credit agreement.

First Hydro Holdings

A subsidiary of First Hydro Holdings, First Hydro Finance plc, has issued £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, 2003, First Hydro Holdings' interest coverage ratio was 1.6 to 1.

In
March 2003, the trustee for the First Hydro bonds sent a letter to First Hydro Finance plc on behalf of a group of First Hydro bondholders, requesting First Hydro Finance to
engage in a process to determine whether the termination of the pool system in the United Kingdom during 2001 (replaced with the new electricity trading arrangements, referred to as NETA) was
materially prejudicial to the interests of the First Hydro bondholders. If this were the case, it could provide the First Hydro bondholders with an early redemption option. First Hydro Finance does
not believe that this event was materially prejudicial to the First Hydro bondholders and has continued to meet all of its debt service obligations and financial covenants under the bond
documentation, including required interest coverage ratio. First Hydro Finance is not aware of further actions being pursued by First Hydro bondholders regarding this matter.

84

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Financial Ratios

MEHC'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 "EME's Interest Coverage Ratio" below. The following table sets forth MEHC's interest coverage ratio for the years
ended December 31, 2003 and 2002:

December 31,
2003

December 31,
2002(in millions)Funds Flow from Operations:EME

$
699

$
692Operating cash flow from unrestricted subsidiaries


(2
)

(17
)Funds flow from operations of projects sold


(1
)

2MEHC


1


7$
697

$
684Interest Expense:EME

$
286

$
293EMEaffiliate debt


1


2MEHC interest expense


160


159Total interest expense

$
447

$
454Interest Coverage Ratio


1.56


1.51


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. 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 quarters prior to December 31, 2003 and 2.0 to 1 for
periods thereafter.

Ability of EME to Pay Dividends

EME's organizational documents and corporate credit facility 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:



85

---







EME's
interest coverage ratio for the twelve months ended December 31, 2003 was 2.45 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 per quarter beginning the first quarter of 2004 under the "ring-fencing" provisions of EME's certificate of incorporation
and bylaws and corporate credit facility without the approval of the independent director. EME did not pay or declare any dividends to MEHC during 2003.

EME's Interest Coverage Ratio

The following details of EME's interest coverage ratio (defined as Funds Flow from Operations divided by Interest Expense) 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 EME'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.

The
following table sets forth the major components of the interest coverage ratio for 2003 and 2002:

December 31, 2003

December 31, 2002(in millions)Funds Flow from Operations:Operating Cash Flow(1) from Consolidated Operating Projects(2):Illinois Plants(3)

$
242

$
294Homer City


153


51First Hydro


(8
)

47Other consolidated operating projects


165


158Price risk management and energy trading


11


16Distributions from unconsolidated Big 4 projects(4)


98


137Distributions from other unconsolidated operating projects


178


120Interest income


4


8Operating expenses


(144
)

(139
)Total funds flow from operations

$
699

$
692Interest Expense:From obligations to unrelated third parties

$
172

$
178From notes payable to Midwest Generation


113


115Total interest expense

$
285

$
293Interest Coverage Ratio


2.45


2.36


---

86

---

The major factors affecting funds flow from operations during 2003 as compared to 2002, were:



Interest
expense decreased by $8 million for the twelve months ended December 31, 2003, compared to the year ended December 31, 2002 due to a lower average debt
balance.

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.

EME 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, 2003 |   | Description                                                                                                                                       
|--------------------------------------- |  | --------------------------- |  | --------------------------- | - | --------------------------------------------------------------------------------------------------------------------------------------------------
|Recourse Debt to
Recourse Capital Ratio |  | Less than or equal to 67.5% |  | 59.8                        | % | Ratio of (a) senior recourse debt to (b) sum of (i) adjusted shareholder's equity as defined in the credit agreement,plus(ii) senior recourse
debt

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---

The recourse debt to recourse capital ratio of EME at December 31, 2003 and 2002 was calculated as follows:

December 31,
2003

December 31,
2002(in millions)Recourse Debt(1)Corporate Credit Facilities

$


$
140Senior Notes


1,600


1,600Guarantee of termination value of Powerton/Joliet operating leases


1,470


1,452Coal and Capex Facility


29


182Other





30Total Recourse Debt to EME

$
3,099

$
3,404Adjusted Shareholder's Equity(2)

$
2,085

$
2,066Recourse Capital(3)

$
5,184

$
5,470Recourse Debt to Recourse Capital Ratio


59.8
%

62.2
%


---

EME's indirect subsidiary, Midwest Generation, reported in its second quarter report on Form 10-Q an asset impairment charge of
$475 million, after tax, related to the 2,698 MW gas-fired Collins Station. The impairment charge resulted from a write-down of the book value of capitalized assets
related to the Collins Station from $858 million to an estimated fair market value of $78 million. The impairment charge by Midwest Generation is not reflected in the operating results
of EME because the lease related to the Collins Station is treated in EME's financial statements as an operating lease and not as an asset and, therefore, is not subject to impairment for accounting
purposes. See "Agreement in Principle to Terminate the Collins Station Lease" for further discussion of the plan to replace EME's corporate credit facility with a new secured credit
facility.

Mission Energy Holdings International Interest Coverage Ratio

Under the credit agreement governing its term loan (see "Dividend Restrictions in Major FinancingsMission Energy Holdings
International"), Mission Energy Holdings International has agreed to a minimum interest coverage ratio of 1.30 to 1 beginning March 2004 for the trailing twelve month period.

88

---

The
following table sets forth the major components of the interest coverage ratio for the twelve months ended December 31, 2003 on a pro forma basis assuming the term loan had
been in existence at the beginning of 2003:

2003Actual

Pro Forma
Adjustment(2)

Pro Forma(in millions)Funds Flow from OperationsHistorical distributions from international projects(1)

$
158

$


$
158Other fees and cash payments considered distributions under the term loan


20





20Administrative and general expenses


(2
)




(2
)Total Flow of Funds from Operations

$
176

$


$
176Term Loan Interest Expense

$
4

$
60

$
64Interest Coverage Ratio








2.75


---

The above details of Mission Energy Holdings International's interest coverage ratio are provided as an aid to understanding the components of the
computations that are set forth in the term loan credit agreement. The terms Funds Flow from Operations and Interest Expense are as defined in the term loan and are not the same as would be determined
in accordance with generally accepted accounting principles.

Summarized
combined financial information (unaudited) of Mission Energy Holdings International, Inc. and its Subsidiaries and Edison Mission Project Co. is set forth below:

Years Ended December 31,2003

2002

2001Revenues

$
1,526

$
1,148

$
835Expenses


1,410


1,112


2,003Net income (loss)

$
116

$
36

$
(1,168
)


December 31,2003

2002Current assets

$
621

$
473Noncurrent assets


6,723


5,260Total assets

$
7,344

$
5,733Current liabilities

$
580

$
470Noncurrent liabilities


4,994


3,154Minority interest


746


652Preferred security





131Equity


1,024


1,326Total liabilities and equity

$
7,344

$
5,733


89

---

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

Contractual Obligations, Commitments and Contingencies

Contractual Obligations

The following table summarizes EME's consolidated contractual obligations as of December 31, 2003.

|                                        |                               | Payments Due by Period (in millions)
|--------------------------------------- | ----------------------------- | ------------------------------------
|
|
|Long-term debt (excluding EME)(1)       |                               | $                                   
|EME's long-term debt(1)                 |                               |                                     
|EME's junior subordinated debentures(2) |                               |                                     
|EME's preferred securities(2)           |                               |                                     
|EME's operating lease obligations       |                               |                                     
|EME's purchase obligations:             |                               |                                     
|                                        | Capital improvements          |                                     
|                                        | Fuel supply contracts         |                                     
|                                        | Gas transportation agreements |                                     
|                                        | Other contractual obligations |                                     
|                                        |                               |                                     
|Total Contractual Obligations           |                               | $                                   
|                                        |                               |                                     

---

Operating Lease Obligations

At December 31, 2003, 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 during the next five years
are $290 million in 2004, $343 million in 2005, $427 million in 2006, $465 million in 2007, and $466 million in 2008. At December 31, 2003, the minimum lease
payments due after 2008 were $4.5 billion. For further discussion, see "Off-Balance Sheet TransactionsSale-Leaseback Transactions."

Fuel Supply Contracts

At December 31, 2003, 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.

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Gas Transportation Agreement

At December 31, 2003, EME had a contractual commitment to transport natural gas. EME is committed to pay its share of the fixed monthly capacity charges
under the gas transportation agreement which has a term of 15 years.

Other Contractual Obligations

At December 31, 2003, Midwest Generation was party to a long-term power purchase contract with Calumet Energy Team LLC entered into as part of
the settlement agreement with Commonwealth Edison, which terminated Midwest Generation's obligation to build additional gas-fired generation in the Chicago area. The contract requires
Midwest Generation to pay a monthly capacity payment and gives Midwest Generation an option to purchase energy from Calumet Energy Team LLC at prices based primarily on operations and maintenance and
fuel costs.

EME
Homer City entered into a Coal Cleaning Agreement with Homer City Coal Processing Corporation to operate and maintain a coal cleaning plant owned by EME Homer City. Under the terms
of the agreement, EME Homer City is obligated to reimburse Homer City Coal Processing Corporation for the actual costs incurred in the operations and maintenance of the coal cleaning plant, a fixed
general and administrative service fee of approximately $260 thousand per year, and an operating fee that ranges from $.20 to $.35 per ton depending on the level of tonnage. The agreement
expired on August 31, 2002 and was renewed with the same terms through December 31, 2005, with a two-year extension option.

Commercial Commitments

Introduction

EME and certain of is subsidiaries have various financial and performance guarantees and indemnifications which are issued in the normal course of business. As
discussed below, these contracts include performance guarantees, standby letters of credit, guarantee of debt and indemnifications.

Standby Letters of Credit

At December 31, 2003, standby letters of credit aggregated $145 million and were scheduled to expire as follows:
2004$93 million; 2005$13 million; and 2008 and thereafter$39 million.

Guarantees and Indemnities

Tax Indemnity Agreements

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 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.

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Indemnities Provided as Part of the Acquisition of the Illinois Plants

In
connection with the acquisition of the Illinois Plants, EME agreed to indemnify Commonwealth Edison with respect to 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 with Commonwealth Edison on February 20, 2003 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, 2003, Midwest Generation had $10 million recorded as a
liability related to this matter and had made $1 million in payments.

Indemnity Provided as Part of the Acquisition of the Homer City Facilities

In
connection with the acquisition of the Homer City facilities, EME Homer City Generation L.P. (EME Homer City) agreed to indemnify the sellers with respect to 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 and does not have 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.

Indemnities Provided under Asset Sale Agreements

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 has 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. Not all indemnities under the asset sale agreements 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.

Guarantee of Brooklyn Navy Yard Contractor Settlement Payments

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 agreed to indemnify Brooklyn Navy Yard Cogeneration Partners,

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L.P.
for any payments due under this settlement agreement, which are scheduled through 2006. At December 31, 2003, EME recorded a liability of $14 million related to this indemnity.

Guarantee of 50% of TM Star Fuel Supply Obligations

TM
Star was formed for the limited purpose of selling natural gas to 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 Company. 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 Company, and, accordingly, no claims against this guarantee have been made. TM Star was merged into March Point Cogeneration
Company effective as of January 16, 2004, and this guarantee terminated by operation of law as of that date.

Capacity Indemnification Agreements

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 agreements terminate, 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, 2003, if
payment were required, would be $181 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.

Bank Indemnity under a Letter of Credit Supporting ISAB Energy's Debt Service Reserve Account

EME
agreed to indemnify its lenders under its credit facilities from amounts drawn on a $26 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.

Subsidiary Indemnity to Central Maine Power Company for Value of Points of Delivery

A
subsidiary of EME agreed to indemnify Central Maine Power Company against decreases in the value of power deliveries by CL Eight, 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

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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.

Subsidiary Guarantees for Performance of Unconsolidated Affiliates

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.

Contingencies

Legal 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. 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 was not served with the complaint. On November 25, 2003, the plaintiffs filed a voluntary dismissal with
prejudice of this lawsuit. The dismissal was entered by the court on December 2, 2003.

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. On July 9, 2003, Judge Whaley of the U.S. District Court concluded the federal court lacked jurisdiction and remanded the case
to the originating San Francisco Superior Court. Defendants, including Sunrise Power Company, have stipulated to respond to the complaint thirty days after it is assigned to a specific court of the
San Francisco Superior Court. In December 2003, James Millar filed a First Amended Class Action and Representative Action Complaint which contains allegations similar to those in the earlier
complaint but also alleges a class action. One of the newly added parties has again removed the lawsuit to federal court, where it is currently pending (subject to remand). EME believes that the
outcome of this litigation will not have a material adverse effect on its consolidated financial position or results of operations.

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Regulatory Developments Affecting Doga Project

On August 4, 2002, a new Electricity Market License Regulation was implemented in Turkey. The new regulation contains, among other things, a requirement
that each generator 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 new regulation allows the possibility of insertion
of provisions in a new license which may be 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. Doga complied with the new regulation's stipulation to apply for a new
generation license by June 2, 2003. The license has not been issued yet. 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 power producers in Turkey acting independently) filed a lawsuit in the Danistay, Turkey's high administrative court, against the Energy
Market Regulatory Authority seeking both an injunction and permanent invalidation of certain provisions of the new regulation on the grounds of the illegality and unconstitutionality of any new
license requirement that does not take into account the vested rights of a company operating pursuant to previously agreed terms of the Implementation Contract.

On
May 12, 2003, the Danistay rejected Doga's request for injunctive relief (as well as those of the other power companies with similar claims). On July 10, 2003, Doga
appealed the Danistay's ruling. Doga's appeal was heard by the General Council of the Administrative Chambers of Danistay on October 10, 2003 and was rejected. There are no further rights of
appeal against the decision regarding the injunction. The Danistay will continue to hear the merits of Doga's lawsuit. A decision is expected to be rendered late in 2004.

Supply Contract from NRG Power Marketing

A subsidiary of EME, Edison Mission Marketing and Trading (referred to as EMMT) and NRG Power Marketing, Inc. (referred to as NRG Power Marketing) are
parties to a contract pursuant to which NRG Power Marketing sells 217,000 MWhr of electricity annually to EMMT. EMMT then resells this electricity to an unconsolidated 25%-owned affiliate, CL Power
Sales Eight, L.L.C. (referred to as CL Eight). On May 14, 2003, NRG Power Marketing filed for protection under Chapter 11 of the United States Bankruptcy Code. On August 7, 2003, NRG
Power Marketing was successful in having the contract with EMMT rejected by the Bankruptcy Court in the Southern District of New York. EMMT had sought an order lifting the automatic stay so that EMMT
could bring a proceeding at the FERC to seek an order directing NRG Power Marketing to continue performing under the contract with EMMT; the Bankruptcy Court denied this motion. As a result, EMMT is
still obligated to provide electricity to CL Eight, but without the supply from NRG Power Marketing. EMMT is appealing both the contract rejection and the denial of its request to lift the automatic
stay to the U.S. District Court in the Southern District of New York. Briefs are being filed, but no dates for oral arguments in the appeals have been established.

EMMT
has entered into purchase agreements for a portion of the volumes due under the supply contract. Current market prices exceed the price which CL Eight is required to pay to EMMT for
the electricity delivered. To the extent EMMT suffers losses as a result of being required to resell such electricity for less than it paid to purchase it, EMMT and EME are indemnified by Peabody
Energy

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Corporation
pursuant to the 2000 Purchase and Sale Agreement for the acquisition of Citizens Power LLC.

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.

Off-Balance Sheet Transactions

Introduction

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 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 qualifying facilities, those which produce electrical energy and steam, or other forms of energy, and which meet the requirements set forth in 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.

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, 2003, 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.

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Operating Lease Obligations." 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

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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 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
$81 million, $89 million and $55 million in 2003, 2002 and 2001, 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:

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

2009813.5

2016Homer City


1,591

GECC


798


300

2019530

2026


---

PSEGPSEG Resources, Inc.

GECCGeneral Electric Capital Corporation

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

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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, 2003 and 2002,
prepaid rent on these leases was $214 million and $117 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Operating Lease
Obligations." Also see "Agreement in Principle to Terminate the Collins Station Lease."

EME's 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)2004

$
22005


22006


32007


32008


4Thereafter


1,352Total

$
1,366


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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Environmental Matters and Regulations

Introduction

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, future
proceedings that may be initiated by environmental authorities, and settlements agreed to by other companies 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 and regulations require a lengthy and complex process for obtaining licenses, permits and approvals prior to construction, operation or modification of a
project or generating facility. 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 injunctive relief or penalties and fines imposed by
regulatory authorities.

StateIllinois

Air Quality

In June 2001, Illinois passed legislation mandating the Illinois Environmental Protection Agency, or Illinois EPA, 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 EPA 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 EPA 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 has been required to 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 Illinois power plants. Beginning with the 2004 ozone season, Midwest Generation's facilities will become subject to the federally-mandated "NOx SIP Call"
regulation that will cap ozone-season NOx emissions within a 19-state region east of the Mississippi. This program provides for NOx allowance trading similar to the current SO2 (acid rain)
trading program already in effect. EME has already qualified for early reduction allowances by reducing NOx emissions at various plants ahead of the imposed deadline. Additionally, the installation of
emission control technology at certain plants has demonstrated over-compliance at those individual plants with the pending NOx emission limitations. Finally, NOx emission trading will be
utilized as needed to comply with any shortfall at plants where installation of emission control technology has demonstrated reductions at levels short of the pending NOx limitations.

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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. An upgraded use classification could result in more stringent limits being applied to wastewater discharges to the river from these
plants. One of the limitations for discharges to the river that could be made more stringent if the existing use classification is changed would be the temperature of the discharges from Joliet and
Will County. The Illinois EPA has also begun a review of the water quality standards for the Chicago River and Chicago Sanitary and Ship
Canal which are adjacent to the Fisk and Crawford Stations. Proposed changes to the existing standards have not been developed at this time. At this time no new standards have been proposed, so EME
cannot estimate the financial impact of this review. However, the cost of additional cooling water treatment, if required, could be substantial.

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 the Pennsylvania Department of Environmental Protection (PADEP) that it has
been included in the Quarterly Noncompliance Report submitted to the United States EPA. 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 meet with PADEP to discuss the drafting of a consent agreement to address the selenium issue and then instruct the contractor to make the
necessary improvements. 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.

Mercury Maximum Achievable Control Technology Determination

In December 2000, the United States Environmental Protection Agency (EPA) announced its intent to regulate mercury emissions and other hazardous air
pollutants from coal-fired electric power plants under Section 112 of the Clean Air Act, and indicated that it would propose a rule to regulate these emissions by no later than
December 15, 2003. On December 15, 2003, EPA issued proposed rules for regulating mercury emissions from coal-fired power plants. EPA proposed two rule options for public comment:
1) regulate mercury as a hazardous air pollutant under Clean Air Act Sec. 112(d); or 2) rescind EPA's December 2000 finding regarding a need to control coal power plant mercury
emissions as a hazardous air pollutant, and instead, promulgate a new "cap and trade" emissions regulatory program to reduce mercury emissions in two phases by years 2010 and 2018. On

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February 24,
2004, the EPA announced a Supplemental Notice of Proposed Rulemaking that provides more details on their emissions cap and trade proposal for mercury. At this time, EPA anticipates
finalizing the regulations in December, 2004, with controls required to be in place by some time between the end of 2007 (if the technology-based standard is chosen) and 2010 (when Phase I of the cap
and trade approach would be implemented if this approach is chosen).

Management's
preliminary estimate is that the mercury regulations may require EME to spend up to $300 million for capital improvements at its Homer City facilities in the
2006-2010 time frame, although the timing will depend on the which proposal is adopted. Until the mercury regulations are finalized, EME cannot fully evaluate the potential impact of these regulations
on the operations of all its facilities. Additional capital costs related to these regulations could be required in the future and they could be material, depending upon the final standards adopted by
the EPA.

National Ambient Air Quality Standards

New ambient air quality standards for ozone, coarse particulate matter and fine particulate matter were adopted by the EPA in July 1997. It is widely
understood that attainment of the fine particulate matter standard may require reductions in emissions of nitrogen oxides and sulfur dioxides. These standards were challenged in the courts, and on
March 26, 2002, the United States Court of Appeals for the District of Columbia Circuit upheld the EPA's revised ozone and fine particulate matter ambient air quality standards.

Because
of the delays resulting from the litigation over the new standards, the EPA's new schedule for implementing the ozone and fine particulate matter standards calls for designation
of attainment and
non-attainment areas under the two standards in 2004. Once these designations are published, states will be required to revise their implementation plans to achieve attainment of the
revised standards. The revised SIPs are likely to require additional emission reductions from facilities that are significant emitters of ozone precursors and particulates.

In
December 2003, the EPA proposed rules that would require states to revise their SIPs to address alleged contributions to downwind areas that are not in attainment with the
revised standards for ozone and fine particulate matter. This proposed "Interstate Air Quality" rule is designed to be completed before states must revise their SIPs to address local reductions needed
to meet the new ozone and fine particulate matter standards. The proposed rule would establish a two-phase, regional cap and trade program for sulfur dioxide and nitrogen oxide. The
proposed rule would affect 27 states, including Illinois and Pennsylvania. The proposed rule would require sulfur dioxide emissions and nitrogen oxide emissions to be reduced in two phases (by 2010
and 2015), with emissions reductions for each pollutant of 65% by 2015. The EPA is expected to issue final rules in December 2004.

At
this time, EME cannot predict the emission reduction targets that the EPA will ultimately adopt or the specific timing for compliance with those targets. In addition, any additional
obligations on EME's facilities to further reduce their emissions of sulfur dioxide, nitrogen oxides and fine particulates to address local non-attainment with the 8-hour ozone
and fine particulate matter standards will not be known until the states revise their implementation plans. Depending upon the final standards that are adopted, EME may incur substantial costs or
financial impacts resulting from required capital improvements or operational changes.

New Source Review Requirements

On November 3, 1999, the United States Department of Justice filed suit against a number of electric utilities, not including EME, for alleged violations
of the Clean Air Act's "new source review" (NSR) requirements related to modifications of air emissions sources at electric generating stations.

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Several
utilities have reached formal agreements or agreements-in-principle with the United States to resolve alleged NSR violations. These settlements involved
installation of additional pollution controls, supplemental environment projects, and the payment of civil penalties. The agreements provided for a phased approach to achieving required emission
reductions over the next 10 to 15 years, and some called for the retirement or repowering of coal-fired generating units. The total cost of some of these settlements exceeded
$1 billion; the civil penalties agreed to by these utilities generally 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 these settlements have not
been finalized. However, the Department of Justice review released in January 2002 concluded "EPA has a reasonable basis for arguing that the enforcement actions are consistent with both the
Clean Air Act and the Administrative Procedure Act." No change in the Department of Justice's position regarding pending NSR legal actions has been announced as a result of EPA's proposed NSR reforms
(discussed immediately below). In January 2004, EPA announced new enforcement actions against several power generating facilites.

On
December 31, 2002, the EPA 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 plant-wide applicability limits. Although states, industry groups and environmental organizations have filed litigation challenging various aspects of
the rule, it became effective March 3, 2003. To date, the rule remains in effect, although the pending litigation could still result in changes to the final rule.

A
federal district court, ruling on a lawsuit filed by EPA, found on August 7, 2003, that the Ohio Edison Company violated requirements of the NSR within the Clean Air Act by
upgrading certain coal-fired power plants without first obtaining the necessary pre-construction permits. On August 26, 2003, another federal district court ruling in an
NSR enforcement action against Duke Energy Corporation, adopted a different interpretation of the NSR provisions that could limit liability for similar upgrade projects.

On
October 27, 2003, EPA issued a final rule revising its regulations to define more clearly a category of activities that are not subject to NSR requirements under the "routine
maintenance, repair and replacement" exclusion. This clearer definition of "routine maintenance, repair and replacement," would provide EME greater guidance in determining what investments can be made
at its existing plants to improve the safety, efficiency and reliability of its operations without triggering NSR permitting requirements, and might mitigate the potential impact of the Ohio Edison
decision. However, on December 24, 2003, the United States Court of Appeals for the D.C. Circuit blocked implementation of the "routine maintenance, repair and replacement" rule, pending
further judicial review.

Prior
to EME's purchase of the Homer City facilities, the EPA requested information under Section 114 of the Clean Air Act from the prior owners of the plant concerning physical
changes at the plant. This request was part of the EPA's industry-wide investigation of compliance by coal-fired plants with the Clean Air Act NSR requirements. On
February 21, 2003, Midwest Generation received a request for information under Section 114 regarding past operations, maintenance and physical changes at the Illinois coal plants from
the EPA. On July 28, 2003, Commonwealth Edison received a substantially similar request for information from the EPA related to these same plants. Other than these requests for information, no
NSR enforcement-related proceedings have been initiated by the EPA with respect to any of EME's United States facilities.

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EPA's
enforcement policy on alleged NSR violations is currently uncertain. These developments will continue to be monitored by EME to assess what implications, if any, they will have on
the operation of domestic power plants owned or operated by EME or its subsidiaries, or on EME's results of operations or financial position.

Clean Water ActCooling Water Intake Structures

On February 16, 2004, the Administrator of the EPA signed the final Phase II rule implementing Section 316(b) of the Clean Water Act establishing
standards for cooling water intake structures at existing electrical generating stations that withdraw more than 50 million gallons of water per day and use more than 25% of that water for
cooling purposes. The purpose of the regulation is to substantially reduce the number of aquatic organisms that are pinned against cooling water intake structures or drawn into cooling water systems.
EME is in the process of evaluating this regulation, which could have a material impact on some of EME's United States facilities.

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.

Environmental Remediation and Asbestos

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, natural resource damages, 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 remediation of 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.

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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. Midwest Generation has accrued approximately $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 costs for environmental activity where such expenditures could be reasonably estimated. 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. In addition, future remediation costs will be
affected by the nature and extent of contamination discovered at our sites that requires remediation. Given the prior history of the operations at its facilities, EME cannot be certain that the
existence or extent of all contamination at its sites has been fully identified. However, based on available information, 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.

Federal,
state and local laws, regulations and ordinances also govern the removal, encapsulation or disturbance of asbestos-containing materials when these materials are in poor
condition or in the event of construction, remodeling, renovation or demolition of a building. Those laws and regulations may impose liability for release of asbestos-containing materials and may
provide for the ability of third parties to seek recovery from owners or operators of these properties for personal injury associated with asbestos-containing materials. In connection with the
ownership and operation of its facilities, EME may be liable for these costs. EME has agreed to indemnify the sellers of the Illinois Plants and the Homer City facilities with respect to specified
environmental liabilities. See "Contractual Obligations, Commitments and ContingenciesCommercial Commitments" for a discussion of these indemnities.

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.

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. To date, none have passed through Congress. In addition, there have been several petitions from states and other parties to compel
the EPA to regulate greenhouse gases under the Clean Air Act. The EPA denied on September 3, 2003, a petition by Massachusetts, Maine and Connecticut to compel EPA under the Clean Air Act to
require EPA to establish a national ambient air quality standard for carbon dioxide. Since that time, 11 states and other entities have filed suits against EPA in the United States Court of Appeals
for the D.C. Circuit (D.C. Circuit), and, the D.C. Circuit has granted intervention requests from 10 states that support EPA's ruling. The D.C. Circuit has not yet ruled on this matter.

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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 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 United Nations 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 mid-2004.

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. Currently, the
countries ratifying the Kyoto Protocol account for 44.2% of carbon dioxide emissions. Although Russia also indicated at the Johannesburg Summit in September 2002 its desire to ratify the
treaty, it stepped back from that position in late 2003 and has yet to set a date for ratification. Representing 17.4% of the developed world's greenhouse gas emissions, Russian ratification is
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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MARKET RISK EXPOSURES

Introduction

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
market risks arise from fluctuations in electricity and fuel prices, emission allowances, 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 "Management's Overview, Risks Related to the Business and Critical Accounting Policies"
and "Liquidity and Capital Resources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 define risk tolerances for each EME regional business unit. Procedures exist which allow for monitoring of all commitments and
positions with regular reviews by a risk management committee. 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 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:



A
discussion of commodity price risk by region is set forth below.

Americas

Introduction

EME performs a "value at risk" analysis in its daily business to measure, monitor and control its overall market risk exposure in respect of its Illinois Plants,
its Homer City facilities, and its trading

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positions.
The use of value at risk allows management to aggregate overall commodity risk, compare risk on a consistent basis and identify the risk factors. 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 for key risk factors, 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 domestic merchant plants is generally sold under bilateral arrangements with utilities and power marketers under short-term transactions
with terms of two years or less or, in the case of the Homer City facilities, to the PJM and/or the New York Independent System Operator (NYISO). As discussed further below, beginning in 2003, EME has
been selling a significant portion of the power generated from its Illinois Plants into wholesale power markets.

Illinois Plants

Energy generated at the Illinois Plants has historically been sold under three power purchase agreements between EME's wholly owned subsidiary, Midwest
Generation, and Exelon Generation Company, in which Exelon Generation purchases capacity and has the right to purchase energy generated by the Illinois Plants. The power purchase agreements, which
began on December 15, 1999 and expire in December 2004, provide for capacity and energy payments. Exelon Generation is obligated to make capacity payments for the plants under contract
and energy payments for the energy produced by these plants and taken by Exelon Generation. The capacity payments provide the Illinois Plants revenue for fixed charges, and the energy payments
compensate the Illinois Plants for all, or a portion of, variable costs of production.

Approximately
65% of the energy and capacity sales from the Illinois Plants in 2003 were to Exelon Generation under the power purchase agreements. As a result of notices given in 2003,
Midwest Generation's reliance on sales into the wholesale market will increase in 2004 from 2003. As discussed in detail below, 3,859 MW of Midwest Generation's generating capacity remains subject to
power purchase agreements with Exelon Generation in 2004. 2004 is the final contract year under these power purchase agreements.

In
June 2003, Exelon Generation exercised its option to contract 687 MW of capacity and the associated energy output (out of a possible total of 1,265 MW subject to option) during
2004 from Midwest Generation's coal-fired units in accordance with the terms of the existing power purchase agreement related to Midwest Generation's coal-fired generation
units. As a result, 578 MW of capacity at the Crawford Unit 7, Waukegan Unit 6 and Will County Unit 3 is no longer subject to the power purchase agreement beginning January 1, 2004. For 2004,
Exelon Generation will have 2,383 MW of capacity related to its coal-fired generation units under contract with Midwest Generation.

In
October 2003, Exelon Generation exercised its option to retain under a power purchase agreement for calendar year 2004 the 1,084 MW of capacity and energy from Midwest
Generation's Collins Station. Exelon Generation also exercised its option to release from a related power purchase agreement 302 MW of capacity and energy (out of a possible total of 694 MW subject to
the option) from Midwest Generation's natural gas and oil-fired peaking units, thereby retaining under that contract 392 MW of the capacity and energy of such units for calendar year 2004.

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,
negotiated by Edison Mission Marketing & Trading with customers through a combination of bilateral agreements, forward energy sales and spot market sales. These arrangements generally have a
term of two years or less. Thus, EME is 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 negligible in

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comparison
to those Midwest Generation currently receives under its existing agreements with Exelon Generation (the possibility of minimal revenues is 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
2004, the primary markets available to Midwest Generation for wholesale sales of electricity from the Illinois Plants are expected to be direct "wholesale customers" and
broker-arranged "over-the-counter customers." 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 areas of Commonwealth Edison and American Electric Power, referred to as "Into ComEd" and "Into AEP," respectively. "Into
Cinergy," "Into ComEd" and "Into AEP" 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, parent company guarantees, letters of credit, and cash
margining arrangements.

The
following table depicts the historical average market prices for energy per megawatt-hour "Into ComEd" and "Into Cinergy" for 2003. Due to geographic proximity, "Into
ComEd" has been the primary market for Midwest Generation. Market prices are included for "Into Cinergy" for illustrative purposes.

|               |  | Into ComEd* |       | Into Cinergy*
|-------------- |  | ----------- | ----- | -------------
|
|
|January        |  | $           | 42.62 |              
|February       |  |             | 54.43 |              
|March          |  |             | 47.96 |              
|April          |  |             | 39.12 |              
|May            |  |             | 29.59 |              
|June           |  |             | 30.27 |              
|July           |  |             | 41.63 |              
|August         |  |             | 48.75 |              
|September      |  |             | 27.44 |              
|October        |  |             | 24.47 |              
|November       |  |             | 24.78 |              
|December       |  |             | 34.72 |              
|               |  |             |       |              
|Yearly Average |  | $           | 37.15 |              
|               |  |             |       |              

---

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The following table sets forth the forward month-end market prices for energy per megawatt-hour for the calendar year 2004
and calendar year 2005 "strips," which are defined as energy purchases for the entire calendar year, as quoted for sales "Into ComEd" and "Into Cinergy" during 2003. 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.

|Forward Energy Prices |  | Into ComEd*
|--------------------- |  | -----------
|
|
|
|January 31, 2003      |  | $          
|February 28, 2003     |  |            
|March 31, 2003        |  |            
|April 30, 2003        |  |            
|May 31, 2003          |  |            
|June 30, 2003         |  |            
|July 31, 2003         |  |            
|August 30, 2003       |  |            
|September 30, 2003    |  |            
|October 31, 2003      |  |            
|November 27, 2003     |  |            
|December 31, 2003     |  |            

|Forward Energy Prices |  | Into Cinergy*
|--------------------- |  | -------------
|
|
|
|January 31, 2003      |  | $            
|February 28, 2003     |  |              
|March 31, 2003        |  |              
|April 30, 2003        |  |              
|May 31, 2003          |  |              
|June 30, 2003         |  |              
|July 31, 2003         |  |              
|August 30, 2003       |  |              
|September 30, 2003    |  |              
|October 31, 2003      |  |              
|November 27, 2003     |  |              
|December 31, 2003     |  |              

---

Midwest Generation intends to hedge a portion of its merchant portfolio risk through Edison Mission Marketing & Trading. 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

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sales.
Second, Midwest Generation's ability to enter into hedging transactions will depend upon its and Edison Mission Marketing & Trading's credit capacity 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 it. Due to factors beyond Midwest Generation'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, resulting in far fewer creditworthy participants in these electricity markets. See "Credit
Risk," below.

In
addition to the prevailing market prices, Midwest Generation's ability 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 Will County Units 1 and 2 and Collins Station Units 4 and 5 at the end of 2002 pending improvement in market conditions.

Under
PJM's proposed revisions to the PJM Tariff, the integration of Commonwealth Edison into PJM could result in market power mitigation measures being imposed on future power sales by
Midwest Generation in the NICA energy and capacity markets. See "Item 1. BusinessIllinois Power Markets." In addition, power produced by Midwest Generation not under contract with Exelon
Generation is sold using transmission obtained from Commonwealth Edison under its open-access tariff filed with the FERC, and the application of the PJM Tariff to Commonwealth Edison's
transmission system could also affect the rates, terms and conditions of transmission service received by Midwest Generation. EME and Midwest Generation have contested the appropriateness of
Commonwealth Edison joining PJM on an "islanded" basis and the imposition of market power mitigation measures proposed by PJM for the NICA energy and capacity markets. EME is unable to predict the
outcome of these efforts, the effect of integration of Commonwealth Edison into PJM on an "islanded" basis, the effect of integration of American Electric Power into PJM, or any final integration
configuration for PJM on the markets into which Midwest Generation sells its power.

In
addition to the price risks described previously, Midwest Generation's ability to transmit energy to counterparty delivery points to consummate spot sales and hedging transactions may
also 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, or the
FERC. Although the FERC 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 pursuant to transactions
with terms of two years or less, or to the PJM or the NYISO. These pools have short-term markets, which establish an hourly clearing price. The Homer City facilities are situated in the
PJM control area and are physically connected to high-voltage transmission lines serving both the PJM and NYISO markets.

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

24-Hour PJM
Historical Energy Prices*2003

2002

2001January

$
36.56

$
20.52

$
36.66February


46.13


20.62


29.53March


46.85


24.27


35.05April


35.35


25.68


34.58May


32.29


21.98


28.64June


27.26


24.98


26.61July


36.55


30.01


30.21August


39.27


30.40


43.99September


28.71


29.00


22.44October


26.96


27.64


21.95November


29.17


25.18


19.58December


35.89


27.33


19.66Yearly Average

$
35.08

$
25.63

$
29.07


---

As shown on the above table, the average historical market prices at the Homer City busbar (delivery point) during 2003 were higher than the
average historical market prices during 2002, although in September and October of each year the power prices were similar. 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.

Sales
made in the real-time or day-ahead market receive the actual spot prices at the Homer City busbar. In order to mitigate price risk from changes in spot
prices at the Homer City busbar, EME may enter into forward contracts with counterparties for forecasted generation in future periods. Currently, there is not a liquid market for entering into forward
contracts at the Homer City busbar. A liquid market does exist for delivery to a collection of delivery points known as PJM West Hub, which EME's price risk management activities use to enter into
forward contracts. EME's revenues with respect to such forward contracts include:



Under
the PJM market design, locational marginal pricing (sometimes referred to as LMP), which establishes hourly prices at specific locations throughout PJM by considering factors
including generator bids, load requirements, transmission congestion and losses, has the effect of raising prices at those delivery points affected by transmission congestion. During the past
12 months, an increase in transmission congestion at delivery points east of the Homer City facilities has resulted in prices at the PJM West Hub (which includes delivery points east of the
Homer City facilities) being higher than those at the Homer City busbar. Thus, while forward prices at PJM West Hub have historically been

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higher than the prices at the Homer City busbar by less than 5%, increased congestion during the last 12 months at delivery points east of the Homer City facilities has resulted in prices at
PJM West Hub being on average 6% higher than those at the Homer City busbar.

By
entering into forward contracts using the PJM West Hub as the delivery point, EME is exposed to "basis risk," which occurs when forward contracts are executed on a different basis (in
this case PJM West Hub) than the actual point of delivery (Homer City busbar). In order to mitigate basis risk resulting from forward contracts using PJM West Hub as the delivery point, EME has
participated in purchasing fixed transmission rights in PJM, and may continue to do so in the future. A fixed transmission right provides the holder with a financial instrument to receive actual spot
prices at one point of delivery and pay prices at another point of delivery that are pegged to prices at the first point of delivery, plus or minus a fixed amount. Accordingly, EME's price risk
management activities include using fixed transmission rights alone or in combination with forward contracts to manage the risks associated with changes in prices within the PJM market.

The
following table sets forth the forward month-end market prices per megawatt-hour for the calendar 2004 and 2005 "strips," which are defined as energy
purchases for the entire calendar year, as quoted for sales into the PJM West Hub during 2003:

24-Hour PJM West
Forward Energy
Prices*2004

2005January 31, 2003

$
43.03

$
37.75February 28, 2003


42.88


38.18March 31, 2003


39.57


33.88April 30, 2003


34.45


32.85May 31, 2003


30.20


30.60June 30, 2003


34.23


33.45July 31, 2003


41.67


39.77August 30, 2003


42.31


41.61September 30, 2003


30.20


30.62October 31, 2003


29.02


28.51November 27, 2003


29.49


28.74December 31, 2003


30.18


28.51


---

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

The First Hydro plant sells electrical energy and capacity through bilateral contracts of varying terms in the England and Wales wholesale electricity market.

The
electricity trading arrangements introduced in March 2001 provide, among other things, for 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 the delivery or receipt of power. In the final hour

112

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after
the notification of all contracts, the system operator can accept bids and offers in the Balancing Mechanism to balance generation and demand and resolve any transmission constraints. There is 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 system operator can also 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 up to 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. A key feature of the trading arrangements is the requirement for 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 the imbalance prices calculated by the system operator based on the prices of bids and offers accepted
in the Balancing Mechanism. This provides an incentive for parties to contract in advance and for the development of forwards and futures markets. Under these arrangements, there has been an increased
emphasis on credit quality, including the need for parent company guarantees or letters of credit for companies below investment grade.

The
wholesale price of electricity has decreased significantly in recent years. The reduction has been driven principally by surplus generating capacity and increased competition. During
2003, prices were more volatile. There was further downward pressure on wholesale prices in the first part of the year followed by some recovery during the summer in prices and in the peak/off peak
differentials for the upcoming winter period. That recovery tailed off towards the end of the year with a considerable narrowing in the peak/off peak differentials. Compliance with First Hydro's bond
financing documents is subject to market conditions for electric energy and ancillary services, which are beyond First Hydro'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 spot 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 Commission of Victoria's
obligations under the State Hedge. From January 2003 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

Contact Energy generates about 30% of New Zealand's electricity and is the largest retailer of natural gas and electricity in New Zealand. A substantial portion
of Contact Energy's generation output is matched with the demand of its retail electricity customers or sold through forward contracts with other wholesale electricity counterparties. The forward
contracts and/or option contracts have varying

113

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terms
that expire on various dates through June 30, 2010, although the majority of the forward contracts are short term (less than two years).

The
New Zealand government released a government policy statement in December 2001, which called for the industry to rationalize the three existing industry codes, form a
single governance structure and address transmission investment and pricing issues. The industry was unable to agree on new rules to facilitate the government policy statement.

Subsequently,
in May 2003, the New Zealand government announced that it would establish a new governance body to be known as the Electricity Commission along with a set of rules
to govern the market. The Electricity Governance Regulations and Rules were finalized in 2003. The Regulations came into force on January 16, 2004, and the Rules came into force during February
and March of 2004.

During
the winter of 2003, wholesale electricity prices increased significantly in response to lower hydro inflows, higher demand and anticipated restrictions on the availability of
thermal fuel. The New Zealand government responded by calling for nationwide energy savings in the order of 10%. Recent rains and anticipated snowmelt have largely improved the earlier conditions with
wholesale electricity prices returning to more normal levels. The national energy savings program ended in July 2003.

However,
there are ongoing concerns that new investment in generation has not been forthcoming and that there is a significant risk that similar events may arise in subsequent years. As
a consequence the New Zealand government announced that it will take the following steps:



Submissions
have been made in respect of the policy, which are currently being considered by the New Zealand government. Final details of the policy were released in
September 2003, and it is expected that legislation will be passed in 2004.

The
New Zealand government announced in July 2003 that it would purchase a new 155 MW power plant before winter 2004 to increase electricity security. The plant is to be situated
at Whirinaki, Hawkes Bay. The Electricity Commission will be required to include this plant in its portfolio of reserve energy. The Whirinaki plant will be located on a site leased to the government
from Contact Energy and will also be operated under contract by Contact Energy.

Credit Risk

In conducting EME's price risk management and trading activities, EME contracts with a number of utilities, energy companies and financial institutions,
collectively referred to as counterparties. Due to factors beyond EME's control, a number of formerly significant trading parties have completely withdrawn from the market or substantially reduced
their trading activities since the beginning of 2002, thereby potentially increasing exposure to the remaining counterparties. 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. 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.

114

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To
manage credit risk, EME looks at the risk of a potential default by counterparties. Credit risk is measured by the loss that would be incurred if counterparties failed to perform
pursuant to the terms of their contractual obligations. EME measures, monitors and mitigates, to the extent possible, credit risk. To mitigate counterparty risk, master netting agreements are used
whenever possible and counterparties may be required to pledge collateral when deemed necessary. EME also takes other appropriate steps to limit or lower credit exposure. Processes have also been
established to determine and monitor the creditworthiness of counterparties. EME manages the credit risk on the 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. A risk management committee regularly reviews the credit quality of EME's counterparties. Despite this, there can be no assurance that these efforts will be wholly
successful in mitigating credit risk 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. At December 31, 2003, the credit ratings of EME's counterparties were as follows:

S&P Credit Rating

December 31, 2003(in millions)A or higher

$
101A-


26BBB+


82BBB


57BBB-


14Below investment grade


Total

$
280


Exelon Generation accounted for 22%, 41% and 43% of EME's consolidated operating revenues in 2003, 2002 and 2001, respectively. EME expects the
percentage to be less in 2004 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 under the power purchase agreements could adversely affect EME's results of operations and financial condition.

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 "Consolidated Operating ResultsDiscontinued Operations."

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

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entered
into swaps that cover interest accrued from January 2, 2003 to July 2, 2004 and April 2, 2003 to July 2, 2004. A 10% fluctuation in market interest rates at
December 31, 2003 would change the fair value of MEHC's interest rate swaps by approximately $237 thousand.

The
fair market value of MEHC's parent only total long-term obligations was $1.2 billion at December 31, 2003, compared to the carrying value of
$1.2 billion. A 10% increase in market interest rates at December 31, 2003 would result in a decrease in the fair value of total long-term obligations by approximately
$34 million. A 10% decrease in market interest rates at December 31, 2003 would result in an increase in the fair value of total long-term obligations by approximately
$36 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 $60 million, $34 million and $17 million of additional interest expense for the years 2003, 2002 and 2001, 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, 2003 would result in a $14 million increase in the fair value of EME's interest rate hedge agreements. A 10% decrease in market interest rates at
December 31, 2003 would result in a $15 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, 2003, a 100 basis point change in interest rates at December 31, 2003
would increase or decrease 2004 income before taxes by approximately $23 million.

EME
had short-term obligations of $52 million at December 31, 2003, consisting of promissory notes related to Contact Energy. The fair values of these
obligations approximated their carrying values at December 31, 2003, 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
$7.3 billion at December 31, 2003, compared to the carrying value of $7.4 billion. A 10% increase in market interest rates at December 31, 2003 would result in a decrease
in the fair value of total long-term obligations by approximately $159 million. A
10% decrease in market interest rates at December 31, 2003 would result in an increase in the fair value of total long-term obligations by approximately $172 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 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

116

---

exchange
scenarios. These analyses use market-derived volatilities, statistical correlations between specified variables, and long-term forecasts to predict ranges of expected returns.

During
2003, foreign currencies in Australia, New Zealand and the U.K. increased in value compared to the U.S. dollar by 34%, 25% and 11%, respectively (determined by the change in the
exchange rates from December 31, 2002 to December 31, 2003). The increase in value of these currencies was the primary reason for the foreign currency translation gain of
$154 million during 2003. A 10% increase in the exchange rates at December 31, 2003 would result in foreign currency translation gains of $329 million. A 10% decrease in the
exchange rates at December 31, 2003 would result in foreign currency translation gains of $40 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 February 2006. At December 31, 2003, the outstanding notional amount of the contracts totaled
$29 million and the fair value of the contracts totaled $(2) million. A 10% decrease in the exchange rates at December 31, 2003 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.

Fair Value of Financial Instruments

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,
2003

December 31,
2002Derivatives:Interest rate:Interest rate swap/cap agreements

$
(34
)
$
(56
)Interest rate options


(1
)

(2
)Commodity price:Electricity


(126
)

(100
)Foreign currency forward exchange agreements


(2
)

Cross currency interest rate swaps


(91
)

(2
)


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, 2003 is $(143) million. The following table summarizes the maturities,

117

---

the
valuation method and the related fair value of EME's commodity price risk management assets and liabilities (as of December 31, 2003) (in millions):

Total Fair
Value

Maturity
<1 year

Maturity
1 to 3 years

Maturity
4 to 5 years

Maturity
>5 yearsPrices actively quoted

$
(3
)
$
(4
)
$
1

$


$
Prices based on models and other valuation methods


(123
)

19


8


(13
)

(137
)Total

$
(126
)
$
15

$
9

$
(13
)
$
(137
)


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

EME's risk management and trading operations are 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 and trading activities not related to EME's power plants or investments in energy projects. 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."

The
fair value of the commodity financial instruments related to energy trading activities as of December 31, 2003 and December 31, 2002, are set forth below (in millions):

December 31, 2003

December 31, 2002Assets

Liabilities

Assets

LiabilitiesElectricity

$
104

$
11

$
109

$
15Other





1





2Total

$
104

$
12

$
109

$
17


The fair value of trading contracts that would be expected after a ten percent adverse price change at December 31, 2003 are shown in the
table below (in millions):

Fair Value

Fair Value After 10%
Adverse Price ChangeElectricity

$
93

$
94Other


(1
)

(1
)Total

$
92

$
93


118

---

The change in the fair value of trading contracts for the year ended December 31, 2003, was as follows (in millions):

Fair value of trading contracts at January 1, 2003

$
92Net gains from energy trading activities


40Amount realized from energy trading activities


(40
)Fair value of trading contracts at December 31, 2003

$
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, 2003) (in millions):

Total Fair
Value

Maturity
<1 year

Maturity
1 to 3 years

Maturity
4 to 5 years

Maturity
>5 yearsPrices actively quoted

$


$


$


$


$
Prices based on models and other valuation methods


92


(3
)

5


9


81Total

$
92

$
(3
)
$
5

$
9

$
81


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 Financial Condition and Results of Operations."

119

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ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA

|Financial Statements: |                                                                                                             | 
|--------------------- | ----------------------------------------------------------------------------------------------------------- | 
|                      | Report of Independent Auditors                                                                              | 
|                      | Consolidated Statements of Income (Loss) for the years ended December 31, 2003, 2002 and 2001               | 
|                      | Consolidated Balance Sheets at December 31, 2003 and 2002                                                   | 
|                      | Consolidated Statements of Shareholder's Equity for the years ended December 31, 2003, 2002 and 2001        | 
|                      | Consolidated Statements of Comprehensive Income (Loss) for the years ended December 31, 2003, 2002 and 2001 | 
|                      | Consolidated Statements of Cash Flows for the years ended December 31, 2003, 2002 and 2001                  | 
|                      | Notes to Consolidated Financial Statements                                                                  | 

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

None.

ITEM 9A. CONTROLS AND PROCEDURES

Disclosure Controls and Procedures

MEHC's management, with the participation of the company's Chief Executive Officer and Chief Financial Officer, has evaluated the effectiveness of MEHC's
disclosure controls and procedures (as
such term is defined in Rules 13a-15(e) and 15d-15(e) under the Securities Exchange Act of 1934, as amended (the "Exchange Act")) as of the end of the period covered by
this report. Based on such evaluation, the Chief Executive Officer and Chief Financial Officer have concluded that, as of the end of such period, MEHC's disclosure controls and procedures are
effective.

Internal Control Over Financial Reporting

There have not been any changes in MEHC's internal control over financial reporting (as such term is defined in Rules 13a-15(f) and
15d-15(f) under the Exchange Act) during the fourth fiscal quarter of 2003 that have materially affected, or are reasonably likely to materially affect, MEHC's internal control over
financial reporting.

120

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MISSION ENERGY HOLDING COMPANY AND SUBSIDIARIES  REPORT OF INDEPENDENT AUDITORS

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, 2003 and December 31, 2002, and the results of its operations and its cash flows for each of the three years in the period ended December 31,
2003 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 191 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 11 to the financial statements, Edison
Mission Energy's largest subsidiary, Edison Mission Midwest Holdings has $693 million in debt that matures in December 2004. Uncertainty regarding the ability of the Company to repay 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 11. 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, the Company changed its method of accounting for derivative instruments and hedging activities and for the impairment or disposal of
long-lived assets, effective January 1, 2001, for goodwill and other intangible assets, effective January 1, 2002, for debt
extinguishments, effective October 1, 2002, for asset retirement obligations, effective January 1, 2003, financial instruments with characteristics of both debt and equity, effective July 1, 2003, and
certain variable interest entities, effective December 31, 2003.

| |  | PricewaterhouseCoopers LLP
| |  | --------------------------

Los
Angeles, California
March 10, 2004

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

|                                                                                                                                     |                                                                                    | Years Ended December 31,     |        
|------------------------------------------------------------------------------------------------------------------------------------ | ---------------------------------------------------------------------------------- | ---------------------------- | -------
|
|Operating Revenues                                                                                                                   |                                                                                    |                              |        
|                                                                                                                                     | Electric revenues                                                                  |                              | $      
|                                                                                                                                     | Net gains 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                                                      |                              |        
|                                                                                                                                     | 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 (loss) from continuing operations before income taxes and minority interest |                              |        
|                                                                                                                                     | Provision (benefit) for income taxes                                               |                              |        
|                                                                                                                                     | Minority interest                                                                  |                              |        
|                                                                                                                                     |                                                                                    |                              |        
|Income (Loss) From Continuing Operations                                                                                             |                                                                                    |                              | (71,096
|Income (loss) from operations of discontinued subsidiaries (including loss on disposal of $1.1 billion in 2001), net of tax (Note 8) |                                                                                    |                              | 1,008  
|                                                                                                                                     |                                                                                    |                              |        
|Loss Before Accounting Change                                                                                                        |                                                                                    |                              | (70,088
|Cumulative effect of change in accounting, net of tax (Note 2)                                                                       |                                                                                    |                              | (8,571 
|                                                                                                                                     |                                                                                    |                              |        
|Net Loss                                                                                                                             |                                                                                    | $                            | (78,659
|                                                                                                                                     |                                                                                    |                              |        

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

122

---



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 $6,470 in 2003 and $13,113 in 2002 |                                  
|                                         | 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                             |                                                                                   |                                  
|                                         | Goodwill                                                                          |                                  
|                                         | Deferred financing costs                                                          |                                  
|                                         | Long-term assets under price risk management and energy trading                   |                                  
|                                         | Restricted cash                                                                   |                                  
|                                         | Rent payments in excess of levelized rent expense under plant operating leases    |                                  
|                                         | Other long-term assets                                                            |                                  
|                                         |                                                                                   |                                  
|                                         |                                                                                   | Total other assets               
|                                         |                                                                                   |                                  
|Assets of Discontinued Operations        |                                                                                   |                                  
|                                         |                                                                                   |                                  
|Total Assets                             |                                                                                   | $                                
|                                         |                                                                                   |                                  

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

123

---

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 maturities of long-term obligations                                                           |                                      |           
|                                                        |                                                                                                       |                                      |           
|                                                        |                                                                                                       | Total current liabilities            |           
|                                                        |                                                                                                       |                                      |           
|Long-Term Obligations Net of Current Maturities         |                                                                                                       |                                      | 6,497,391 
|                                                        |                                                                                                       |                                      |           
|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                                  |                                      |           
|                                                        | Junior subordinated debentures (Notes 2 and 13)                                                       |                                      |           
|                                                        | Preferred securities subject to mandatory redemption (Notes 2 and 13)                                 |                                      |           
|                                                        | Other                                                                                                 |                                      |           
|                                                        |                                                                                                       |                                      |           
|                                                        |                                                                                                       | Total long-term deferred liabilities |           
|                                                        |                                                                                                       |                                      |           
|Liabilities of Discontinued Operations                  |                                                                                                       |                                      | 581       
|                                                        |                                                                                                       |                                      |           
|Total Liabilities                                       |                                                                                                       |                                      | 10,894,229
|                                                        |                                                                                                       |                                      |           
|Minority Interest                                       |                                                                                                       |                                      | 514,978   
|                                                        |                                                                                                       |                                      |           
|Preferred Securities of Subsidiaries (Notes 2 and 13)   |                                                                                                       |                                      |           
|                                                        | Company-obligated mandatorily redeemable security of partnership holding solely parent debentures     |                                      |           
|                                                        | Subject to mandatory redemption                                                                       |                                      |           
|                                                        |                                                                                                       |                                      |           
|                                                        | Total preferred securities of subsidiaries                                                            |                                      |           
|                                                        |                                                                                                       |                                      |           
|Commitments and Contingencies (Notes 11, 12, 17 and 18) |                                                                                                       |                                      |           
|Shareholder's Equity                                    |                                                                                                       |                                      |           
|                                                        | Common stock, par value $0.01 per share; 1,000 shares authorized; 1,000 shares issued and outstanding |                                      |           
|                                                        | Additional paid-in capital                                                                            |                                      |           
|                                                        | Retained deficit                                                                                      |                                      |           
|                                                        | Accumulated other comprehensive loss                                                                  |                                      |           
|                                                        |                                                                                                       |                                      |           
|Total Shareholder's Equity                              |                                                                                                       |                                      | 849,417   
|                                                        |                                                                                                       |                                      |           
|Total Liabilities and Shareholder's Equity              |                                                                                                       | $                                    | 12,258,624
|                                                        |                                                                                                       |                                      |           

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

124

---



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, 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
|                             | Net loss                                             |                            |           |                   |   |                                        | (78,659    | )                    |         
|                             | Other comprehensive income                           |                            |           |                   |   |                                        |            |                      |         
|                             | Stock option price appreciation on options exercised |                            |           |                   |   |                                        | (263       | )                    |         
|                             | Other stock transactions, net                        |                            |           | 68                |   |                                        |            |                      |         
|                             |                                                      |                            |           |                   |   |                                        |            |                      |         
|Balance at December 31, 2003 |                                                      | $                          | 2,218,353 |                   | $ | (1,344,093                             | )          | $                    | (24,843 
|                             |                                                      |                            |           |                   |   |                                        |            |                      |         

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

125

---

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

|                                                  |                                                                         | Years Ended December 31,                                                                                                                                               |        
|------------------------------------------------- | ----------------------------------------------------------------------- | ---------------------------------------------------------------------------------------------------------------------------------------------------------------------- | -------
|
|Net Loss                                          |                                                                         | $                                                                                                                                                                      | (78,659
|Other comprehensive income (expense), net of tax: |                                                                         |                                                                                                                                                                        |        
|                                                  | Foreign currency translation adjustments:                               |                                                                                                                                                                        |        
|                                                  |                                                                         | Foreign currency translation adjustments, net of income tax expense (benefit) of $5,271, $3,775 and $(1,349) for 2003, 2002 and 2001, 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 $(124,447) for 2002 and 2001, respectively                |        
|                                                  |                                                                         | Other unrealized holding gains (losses) arising during period, net of income tax expense of $3,387, $5,752 and $62,545 for 2003, 2002 and 2001, respectively           |        
|                                                  |                                                                         | Reclassification adjustments included in net income (loss), net of income tax expense (benefit) of $(1,026), $3,722 and ($7,795) for 2003, 2002 and 2001, respectively |        
|                                                  |                                                                         |                                                                                                                                                                        |        
|Other comprehensive income (expense)              |                                                                         |                                                                                                                                                                        | 192,103
|                                                  |                                                                         |                                                                                                                                                                        |        
|Comprehensive Income (Loss)                       |                                                                         | $                                                                                                                                                                      | 113,444
|                                                  |                                                                         |                                                                                                                                                                        |        

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

126

---



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 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                         |         
|                                                                        |                                                                                         | Minority interest                                               |         
|                                                                        |                                                                                         | Deferred taxes and tax credits                                  |         
|                                                                        |                                                                                         | Gain on sale of assets                                          |         
|                                                                        |                                                                                         | Asset impairment charges                                        |         
|                                                                        |                                                                                         | Cumulative effect of change in accounting, net of tax           |         
|                                                                        |                                                                                         | Settlement of postretirement employee benefit liability         |         
|                                                                        | Changes in operating assets and liabilities:                                            |                                                                 |         
|                                                                        |                                                                                         | Decrease in accounts receivable                                 |         
|                                                                        |                                                                                         | Decrease (increase) in inventory                                |         
|                                                                        |                                                                                         | Decrease in prepaid expenses and other                          |         
|                                                                        |                                                                                         | Increase in rent payments in excess of levelized rent expense   |         
|                                                                        |                                                                                         | Increase (decrease) in accounts payable and accrued liabilities |         
|                                                                        |                                                                                         | Increase in interest payable                                    |         
|                                                                        |                                                                                         | Decrease (increase) in net assets under risk management         |         
|                                                                        | Other operating, net                                                                    |                                                                 |         
|                                                                        |                                                                                         |                                                                 |         
|                                                                        |                                                                                         |                                                                 | 713,830 
|                                                                        | Operating cash flow from discontinued operations                                        |                                                                 |         
|                                                                        |                                                                                         |                                                                 |         
|                                                                        |                                                                                         |                                                                 |         
|                                                                        |                                                                                         |                                                                 |         
|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 to parent                                                                |                                                                 |         
|                                                                        | Cash dividends to minority shareholders                                                 |                                                                 |         
|                                                                        | Funds provided to discontinued operations                                               |                                                                 |         
|                                                                        | Issuance of preferred securities                                                        |                                                                 |         
|                                                                        | Redemption of preferred securities                                                      |                                                                 |         
|                                                                        | Financing costs                                                                         |                                                                 |         
|                                                                        |                                                                                         |                                                                 |         
|                                                                        |                                                                                         |                                                                 | (321,661
|                                                                        | Financing cash flow from discontinued operations                                        |                                                                 |         
|                                                                        |                                                                                         |                                                                 |         
|                                                                        |                                                                                         |                                                                 |         
|                                                                        |                                                                                         |                                                                 |         
|Cash Flows From Investing Activities                                    |                                                                                         |                                                                 |         
|                                                                        | Investments in and loans to energy projects                                             |                                                                 |         
|                                                                        | Purchase of common stock of acquired companies                                          |                                                                 |         
|                                                                        | 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                                                                              |                                                                 |         
|                                                                        |                                                                                         |                                                                 |         
|                                                                        |                                                                                         |                                                                 | (480,487
|                                                                        | Investing cash flow from discontinued operations                                        |                                                                 |         
|                                                                        |                                                                                         |                                                                 |         
|                                                                        |                                                                                         |                                                                 |         
|                                                                        |                                                                                         |                                                                 |         
|Effect of exchange rate changes on cash                                 |                                                                                         |                                                                 | 4,815   
|Effect on cash from de-consolidation of subsidiary                      |                                                                                         |                                                                 |        
|                                                                        |                                                                                         |                                                                 |         
|Net increase (decrease) in cash and cash equivalents                    |                                                                                         |                                                                 | (80,680 
|Cash and cash equivalents at beginning of period                        |                                                                                         |                                                                 | 734,450 
|                                                                        |                                                                                         |                                                                 |         
|Cash and cash equivalents at end of period                              |                                                                                         |                                                                 | 653,770 
|Cash and cash equivalents classified as part of discontinued operations |                                                                                         |                                                                 | (183    
|                                                                        |                                                                                         |                                                                 |         
|Cash and cash equivalents of continuing operations                      |                                                                                         | $                                                               | 653,587 
|                                                                        |                                                                                         |                                                                 |         

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

127

---



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 Edison Mission Group Inc. (formerly 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 11Financial InstrumentsLong-Term Obligations. Prior to July 2, 2001, Edison Mission Group Inc. owned Edison Mission Energy
(EME). On July 2, 2001, Edison Mission Group Inc. 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 and partnerships. 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 $437 million and $568 million at December 31, 2003 and 2002,
respectively, with maturities of three months or less. All investments are classified as available-for-sale.

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

128

---

under
the equity method at December 31, 2003 and 2002. 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

25-35 yearsCivil works

25-100 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 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.

129

---

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 31,2003

2002

2001Interest incurred

$
665

$
616

$
638Interest capitalized


(7
)

(4
)

(14
)$
658

$
612

$
624


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 deferred 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 or would not be subject to additional income taxes if repatriated. Income tax accounting policies are discussed further in
Note 14Income Taxes.

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.

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 $111 million in 2003 and $81 million in 2002.

130

---

Revenue Recognition

EME is primarily an independent power producer, operating a portfolio of wholly owned plants and plants which its ownership interest is 50% or less and which are
accounted for under the equity method. In conjunction with its electric generation business, EME produces, as a by-product, thermal energy for sale to customers, principally steam hosts at
cogeneration sites. EME's subsidiaries enter into power and fuel hedging, optimization transactions and energy trading contracts all subject to market conditions. EME's subsidiary executes these
transactions primarily through the use of physical forward commodity purchases and sales and financial commodity swaps and options. With respect to its physical forward contracts, EME's subsidiaries
generally act as the principal, take title to the commodities, and assume the risks and rewards of ownership. Therefore, EME's subsidiaries record settlement of non-trading physical
forward contracts on a gross basis. Consistent with Emerging Issues Task Force No. 03-11, "Reporting Realized Gains and Losses on Derivative Instruments that are Subject to FASB
Statement No. 133, Accounting for Derivative Investments and Hedging Activities, and Not Held for Trading Purposes," EME nets the cost of purchased power against related third party sales in
markets that use locational marginal pricing, currently PJM. Financial swap and option transactions are settled net and, accordingly, EME's subsidiaries do not take title to the underlying commodity.
Accordingly, gains and losses from settlement of financial swaps and options are recorded net. Managed risks typically include commodity price risk associated with fuel purchases and power sales.

EME
records revenue and related costs as electricity is generated or services are provided unless EME is subject to Statement of Financial Accounting Standards No. 133,
"Accounting for Derivative Instruments and Hedging Activities" and does not qualify for the normal sales and purchases exception. Where applicable, revenues are recognized under Emerging Issues Task
Force Issued No. 91-6, "Revenue Recognition of Long Term Power Sales Contracts," ratably over the terms of the related contracts. Also included in deferred revenues is the deferred
gain from the termination of the Loy Yang B power sales agreement.

Derivative Instruments

SFAS No. 133, as amended and interpreted by other related accounting literature, establishes accounting and reporting standards for derivative instruments
(including certain derivative instruments embedded in other contracts). SFAS No. 133 requires companies to record derivatives on their balance sheets as either assets or liabilities measured at
their fair value unless exempted from derivative treatment as a normal sale and purchase. All changes in the fair value of derivatives are recognized currently in earnings unless specific hedge
criteria are met, which requires that a company must formally document, designate, and assess the effectiveness of transactions that receive hedge accounting.

SFAS
No. 133 sets forth the accounting requirements for cash flow hedges, fair value hedges and hedges of the net investment in a foreign operation. SFAS No. 133 provides
that the effective portion of the gain or loss on a derivative instrument designated and qualifying as a cash flow hedging instrument be reported as a component of other comprehensive income and be
reclassified into earnings in the same period during which the hedged forecasted transaction affects earnings. The remaining gain or loss on the derivative instrument, if any, must be recognized
currently in earnings. SFAS No. 133 provides that the changes in fair value of derivatives designated as fair value hedges and the corresponding changes in the fair value of the hedged risk
attributable to a recognized asset, liability, or unrecognized firm commitment be recorded in earnings. If the fair value hedge is effective, the amounts recorded will offset in earnings. SFAS
No. 133 provides that the effective portion of the gain or loss on an instrument designated and qualifying as a hedge of the net investment in a foreign operation be reported as foreign
currency translation adjustments included as a component of other comprehensive income.

131

---

Financial
instruments that are utilized for trading purposes are measured at fair value and 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 and the present value of net amounts payable from
structured transactions.

Where
EME's derivative instruments are subject to a master netting agreement and the criteria of FASB Interpretation (FIN) 39 "Offsetting of Amounts Related to Certain Contracts" are
met, EME presents its derivative assets and liabilities on a net basis in its balance sheet.

Cumulative Effect of Change in Accounting Principle

For the year ended December 31, 2001, EME recorded a $15 million, after tax, increase to net income and a $246 million, after tax, decrease
to other comprehensive income as the cumulative effect of the adoption of SFAS No. 133, as amended and interpreted. For the year ended December 31, 2002, EME recorded a
$6 million, after tax, increase to other comprehensive income as the cumulative effect of adoption of SFAS No. 133 as a result of a revised interpretation effective April 1, 2002.

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 $2 million, $(8) million and
$7 million for 2003, 2002 and 2001, respectively.

Stock-based Compensation

At December 31, 2003, Edison International has three stock-based employee compensation plans, which are described more fully in
Note 16Stock Compensation Plans. EME accounts for those plans using the intrinsic value method. Upon grant, no stock-based employee compensation cost is reflected in net income
(loss), 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 (loss) if EME had used the fair value accounting method.

Years Ended December 31,2003

2002

2001Net loss, as reported

$
(79
)
$
(68
)
$
(1,170
)Deduct: 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 loss

$
(80
)
$
(69
)
$
(1,171
)


132

---

New Accounting Standards

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 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. As of
January 1, 2003, EME recorded a $9 million, after tax, decrease to net income as the cumulative effect of the adoption of SFAS No. 143.

EME
recorded a liability representing expected future costs associated with site reclamations, facilities dismantlement and removal of environmental hazards as follows:

Initial asset retirement obligation as of January 1, 2003

$
17Accretion expense


2Translation adjustments


3Balance of asset retirement obligation as of December 31, 2003

$
22


Had SFAS No. 143 been applied retroactively in the years ended December 31, 2002 and 2001, it would not have had a material effect
upon EME's results of operations. The pro forma liability for asset retirement obligation is not shown due to the immaterial impact on EME's consolidated balance sheet.

Statement of Financial Accounting Standards No. 145

In April 2002, the Financial Accounting Standards Board (FASB) 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. 149

In April 2003, the FASB issued Statement of Financial Accounting Standards No. 149, "Amendment of Statement 133 on Derivative Instruments and
Hedging Activities." This statement amends and clarifies financial accounting and reporting for derivative instruments and for hedging activities under SFAS No. 133. The amendment reflects
decisions made by the FASB and the Derivatives Implementation Group (DIG) process in connection with issues raised about the application of SFAS No. 133. Generally, the provisions of SFAS
No. 149 will be applied prospectively for contracts entered into or modified after June 30, 2003 and for hedging relationships designated

133

---

after
June 30, 2003. SFAS No. 149 provisions that resulted from the DIG process that became effective in fiscal quarters beginning before June 15, 2003 will continue to be applied
based upon their original effective dates. The adoption of this standard had no impact on EME's consolidated financial statements.

Statement of Financial Accounting Standards No. 150

Effective July 1, 2003, EME adopted Statement of Financial Accounting Standards No. 150, "Accounting for Certain Financial Instruments with
Characteristics of both Liabilities and Equity." SFAS No. 150 establishes standards for how to classify and measure certain financial instruments with characteristics of both liabilities and
equity. It requires that an issuer classify a financial instrument that is within its scope as a liability or asset, as appropriate. At July 1, 2003, EME's company-obligated mandatorily
redeemable securities and redeemable preferred stock were reclassified from the mezzanine equity section to the liability section of EME's consolidated balance sheet. Dividend payments on these
instruments are being recorded as interest expense commencing July 1, 2003 on EME's consolidated statements of income. Prior period financial statements are not permitted to be restated for
either of these changes. Therefore, there was no cumulative impact due to this accounting change incurred upon adoption. See disclosures regarding these preferred securities in
Note 13Preferred Securities and Junior Subordinated Debentures.

Emerging Issues Task Force No. 01-08

In May 2003, the Emerging Issues Task Force (EITF) reached a consensus on Issue No. 01-08, "Determining Whether an Arrangement Contains
a Lease," which provides guidance on how to determine whether an arrangement contains a lease that is within the scope of SFAS No. 13, "Accounting for Leases." A lease is defined as an
agreement conveying the right to use property, plant, or equipment (land and/or depreciable assets), usually for a stated period of time. The
guidance issued by the EITF could affect the classification of a power sales agreement that meets specific criteria, such as a power sales agreement for substantially all of the output from a power
plant to one customer. If a power sales agreement meets the guidance issued by the EITF, it would be accounted for as a lease subject to SFAS No. 13. The consensus is effective prospectively
for EME arrangements entered into or modified after June 30, 2003. The consensus had no impact on EME's consolidated financial statements.

Statement of Financial Accounting Standards Interpretation No. 45

In November 2002, the FASB 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 adoption of this standard had no impact on EME's consolidated financial statements. See disclosure regarding guarantees and indemnities in
Note 17Commitments and Contingencies.

Statement of Financial Accounting Standards Interpretation No. 46

In December 2003, the FASB re-issued Statement of Financial Accounting Standards Interpretation No. 46, "Consolidation of Variable
Interest Entities" (FIN 46). 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

134

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variable
interest entities. 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. 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. This interpretation is effective for special purpose entities as of December 31, 2003 and for all other entities
as of March 31, 2004.

Deconsolidation of Special Purpose Entities

In
accordance with FIN 46, EME deconsolidated the following two financing entities:



Variable Interest Entities

EME
has concluded that Brooklyn Navy Yard Cogeneration Partners L.P. (Brooklyn) is a variable interest entity in which EME may be the primary beneficiary since EME expects to absorb the
majority of Brooklyn's losses, if any, and expects to receive a majority of Brooklyn's residual returns, if any. This determination is subject to further analysis of Brooklyn's long-term power sales
agreement (see discussion of power contracts below). On December 31, 2003, EME agreed to sell its 50% partnership interest in Brooklyn to a third party. Completion of the sale, currently
expected in the first quarter of 2004, is subject to closing conditions, including obtaining regulatory approval. If the sale is completed prior to March 31, 2004, EME will not be required to
consolidate this entity regardless of the results of the power contract analysis described above. If the sale is not completed by this date, EME may be required to consolidate Brooklyn at
March 31, 2004 based on the historical cost of the assets, liabilities and non-controlling interest. The consolidation of this entity would result in EME recording approximately a
$44 million, after tax, decrease to net income as the cumulative effect of consolidating this variable interest entity. This loss is primarily due to cumulative losses allocated to the other
50% partner in excess of their equity contributions. If this loss was recorded, it would be reversed in a subsequent period if the sale was completed after March 31, 2004.

135

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Guidance related to implementation of FIN 46 is still evolving. Under an interpretation of FIN 46, a long-term power contract may constitute a variable interest in an asset
that absorbs expected losses from the equity holders. If this interpretation were applied to EME's unconsolidated affiliates it could result in all of EME's unconsolidated affiliates related to
project investments being classified as variable interest entities, although the primary beneficiary may be the counterparties to the long-term contracts (including the counterparty to the
Brooklyn Navy Yard power and steam purchase agreement). EME maximum exposure to loss is generally limited to its investment in these entities.

Other Statement of Financial Accounting Standards No. 133 Guidance

In June 2003, the Derivative Implementation Group of the FASB under Statement No. 133 Implementation Issue Number C20 issued clarifying guidance
related to pricing adjustments in contracts that qualify under the normal purchases and normal sales exception under SFAS No. 133. This implementation guidance became effective on
October 1, 2003. The guidance had no impact on EME's consolidated financial statements.

Emerging Issues Task Force No. 03-11

In July 2003, the EITF reached a consensus on Issue No. 03-11, "Reporting Realized Gains and Losses on Derivative Instruments that are
Subject to FASB Statement No. 133, Accounting for Derivative Instruments and Hedging Activities, and Not Held for Trading Purposes." EITF Issue No. 03-11 provides guidance on
whether realized gains and losses on derivative contracts should be reported on a net or gross basis and concludes such classification is a matter of judgment that depends on the relevant facts and
circumstances. In analyzing the facts and circumstances, EITF Issue No. 99-19, "Reporting Revenue Gross as a Principal Versus Net as an Agent," should be considered. Gains and
losses on non-trading derivative instruments are recognized in net gains (losses) from price risk management and energy trading in the accompanying Consolidated Income Statements. The
consensus is effective prospectively for EME transactions or arrangements entered into or modified after September 30, 2003. The consensus had no impact on EME's consolidated financial
statements.

Note 3. Inventory

Inventory is stated at the lower of weighted average cost or market. Inventory at December 31, 2003 and December 31, 2002 consisted of the
following:

2003

2002Coal and fuel oil

$
90

$
111Spare parts, materials and supplies


76


65Total

$
166

$
176


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

136

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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.

During
the third quarter of 2002, 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 and accordingly, reported this amount as a cumulative change in accounting. Estimates of fair value were determined using comparable transactions. In accordance with SFAS
No. 3, "Reporting Accounting Changes in Interim Financial Statements," EME's financial statements for the first quarter of 2002 were restated to reflect the accounting change as of
January 1, 2002.

Based
on EME's annual evaluation of goodwill for 2003, 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 adjustment to impair goodwill at December 31, 2003 was necessary in accordance with SFAS No. 142.

Included
in "Other long-term assets" on EME's consolidated balance sheet at December 31, 2003 and 2002 are customer contracts with a gross carrying amount of
$104 million and $97 million, respectively, and accumulated amortization of $12 million and $5 million, respectively. The contracts have a weighted average amortization
period of 20 years. For the years ended December 31, 2003 and 2002, the amortization expense was $6 million and $5 million, respectively. Based on the current amount of
intangible assets subject to amortization, the estimated amortization expense for fiscal years 2004 through 2008 is $6 million each year.

Changes
in the carrying amount of goodwill, by segment, for the year ended December 31, 2003 are as follows:

Americas

Asia Pacific

Europe

TotalCarrying amount at December 31, 2002

$
2

$
384

$
274

$
660Goodwill resulting from an acquisition(1)





39





39Translation adjustments and other





138


30


168Carrying amount at December 31, 2003

$
2

$
561

$
304

$
867


---

The following table sets forth what net income would have been exclusive of goodwill amortization for the years ended December 31, 2003,
2002 and 2001.

Years Ended December 31,2003

2002

2001Reported net income (loss)

$
(79
)
$
(68
)
$
(1,170
)Add back: Goodwill amortization, net of tax








16Adjusted net income (loss)

$
(79
)
$
(68
)
$
(1,154
)


Note 5. Asset Impairment and Other Charges

During 2003, EME recorded asset impairment charges of $304 million, consisting of $245 million related to eight small peaking plants owned by its
indirect subsidiary, Midwest Generation, LLC (Midwest Generation), in Illinois and $53 million and $6 million to write-down the estimated net proceeds from the planned sale
of the Brooklyn Navy Yard and Gordonsville projects, respectively. The impairment charge related to the peaking plants in Illinois resulted from a revised long-term outlook for capacity
revenues from the peaking plants. The lower capacity revenue outlook is the result of a

137

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number
of factors, including higher long-term natural gas prices and the current generation overcapacity in the MAIN region market. The book value of these assets was written down from
$286 million to an estimated fair market value of $41 million. The estimated fair market value was determined based on discounting estimated future pretax cash flows using a 17.5%
discount rate.

During
2002, EME recorded asset impairment and other charges of $131 million, consisting of $61 million relating to the write-off of capitalized costs
associated with the termination of equipment purchase contracts with Siemens Westinghouse, $25 million related to the write-off of capitalized costs associated with the suspension
of the Powerton Station SCR major capital improvement project at the Illinois Plants, and $45 million from a settlement agreement that terminated the obligation to build additional generation
in Chicago.

During
2001, EME recorded asset impairment and other charges of $59 million, consisting of $34 million to write-down the estimated net proceeds from the planned
sale of the Commonwealth Atlantic, Gordonsville, Harbor and James River projects and $25 million related to the loss on the termination of a portion of EME's Master Turbine Lease.

Note 6. 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, 2002

$
(8
)
$
(198
)
$
(11
)
$
(217
)Current period change


153


39





192Balance at December 31, 2003

$
145

$
(159
)
$
(11
)
$
(25
)


---

The amount of commodity hedges included in unrealized gains (losses) on cash flow hedges, net of tax, at December 31, 2003, was a loss of
$77 million. The amount of interest rate hedges included in unrealized gains (losses) on cash flow hedges, net of tax, at December 31, 2003, was a loss of $82 million.

Unrealized
losses on commodity 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. These losses arise because
current forecasts of future electricity prices in these markets are greater than contract prices. Unrealized losses on interest rate hedges included those related to EME's share of interest rate swaps
of its unconsolidated affiliates, the Loy Yang B project and the Spanish Hydro project.

As
EME's hedged positions are realized, approximately $13 million, after tax, of the net unrealized losses on cash flow hedges at December 31, 2003 are expected to be
reclassified into earnings during the next 12 months. Management expects that when the hedged items are recognized in earnings, the net unrealized losses 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
13 years. Actual amounts ultimately reclassified into earnings over the next 12 months could vary materially from this estimated amount as a result of changes in market conditions.

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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, 2003 and 2002, MEHC recorded approximately $3 million, after tax, and $5 million, after tax, respectively, decrease to other
comprehensive income resulting from unrealized holding losses on these contracts.

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 net gains (losses) of approximately $13 million, $(2) million and $(1) million in 2003, 2002 and 2001, respectively, representing
the amount of the ineffective portion of the cash flow hedges, reflected in net gains (losses) from price risk management and energy trading in EME's consolidated income statement.

Note 7. 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 operates under
a 25-year build-rehabilitate-operate-transfer agreement with National Power Corporation for the 792 MW Caliraya-Botocan-Kalayaan (CBK) hydro electric complex located in the Republic of the
Philippines, which EME refers to as the CBK project. Financing for this $460 million project consisted of equity commitments of $117 million, of which EME's 50% share was
$59 million, and debt financing which is in place for the remainder of the cost for this project. The indebtedness incurred by CBK Power is non-recourse to EME.

Acquisition of a Controlling Interest in Contact Energy

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.

Acquisition of Taranaki Station

On March 3, 2003, Contact Energy, EME's 51% owned subsidiary, completed a transaction with NGC Holdings Ltd. to acquire the Taranaki Combined Cycle
power station and related interests. The Taranaki station is a 357 MW combined cycle, natural gas-fired plant located near Stratford, New Zealand. Consideration for the Taranaki station
consisted of a cash payment of approximately $275 million, which was initially financed with bridge loan facilities. The bridge loan facilities were subsequently repaid with proceeds from
Contact Energy's issuance of long-term U.S. dollar denominated notes.

139

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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.

The
table below summarizes additional acquisitions by EME or its wholly owned subsidiaries from 2001 through 2003.

Date

Acquisition

Percentage
Acquired

Purchase
PriceOil and GasDecember 23, 2003

Four Star Oil & Gas Company

1.3
%
$
3December 19, 2001

Four Star Oil & Gas Company

1.4
%
$
7


Dispositions

On December 31, 2003, EME agreed to sell its 50% partnership interest in Brooklyn Navy Yard Cogeneration Partners L.P. to a third party. Completion of the
sale, currently expected in the first quarter of 2004, is subject to closing conditions, including obtaining regulatory approval. Proceeds from the sale are expected to be approximately
$42 million. EME recorded an impairment charge of $53 million during the fourth quarter of 2003 related to the planned disposition of this investment.

On
December 12, 2003, EME agreed to sell 100% of its stock of Edison Mission Energy Oil & Gas, which in turn holds minority interests in Four Star Oil & Gas, to
Medicine Bow Energy Corporation. Following receipt of regulatory approvals and satisfaction of all other closing conditions, EME completed this sale on January 7, 2004. Proceeds from the sale
were approximately $100 million. EME expects to record a pre-tax gain on the sale of approximately $47 million during the first quarter of 2004.

On
December 12, 2003, EME completed the sale of its 40% interest in a development project in Thailand to a third party. Proceeds from the sale were $13 million to be paid
in two installments, the first of which, in the amount of $5 million, was received by EME on December 15, 2003. The remaining payment is payable in June 2004.

On
November 21, 2003, Gordonsville Energy Limited Partnership, in which EME owns a 50% interest, completed the sale of the Gordonsville cogeneration facility to Virginia Electric
and Power Company. Proceeds from the sale, including distribution of a debt service reserve fund, were $36 million. EME recorded an impairment charge of $6 million during the second
quarter of 2003 related to the planned disposition of this investment.

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 8Discontinued Operations. The loss from operations of Ferrybridge and Fiddler's Ferry in 2001 includes

140

---

$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.

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.

Note 8. 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 were
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
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 an administrative receiver over the assets of Lakeland Power Ltd. An administrative receiver was appointed to take control of the affairs of
Lakeland Power Ltd. and was given a wide range of powers (specified in the U.K. Insolvency Act), including authorizing the sale of the power plant. On May 14, 2003, a third party
completed the purchase of the Lakeland power plant from the administrative receiver for £24 million. The proceeds from the sale and existing cash were used to fund partial repayment
of the outstanding debt owed to secured creditors of the project.

EME
ceased to consolidate the activities of Lakeland Power Ltd. once the administrative receiver had been appointed. The consolidated financial statements have been restated to
conform to discontinued operations treatment for all historical periods presented. Lakeland Power Ltd.'s administrative receiver has filed a claim against Norweb Energi Ltd. for
termination of the power purchase agreement. To the extent that Lakeland Power Ltd. receives payment under its claim, such amounts will first be used to repay amounts due to creditors with any
residual amount distributed to EME's subsidiary that owns the outstanding shares of Lakeland Power Ltd. There is no assurance that there will be any cash available to distribute from the
ultimate resolution of this claim.

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.
The sale is 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

141

---

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 31,2003

2002

2001Total operating revenues

$
1

$
74

$
600Income (loss) before income taxes


2


(75
)

(2,000
)Income (loss) before accounting change


1


(57
)

(1,225
)Cumulative effect of change in accounting, net of income expense (benefit) of $2 million for 2001








6Income (loss) from operations of discontinued subsidiaries


1


(57
)

(1,219
)


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 being recorded through the income statement.

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.

The
discontinued operations balance sheet at December 31, 2003 and 2002 is comprised of current assets of $5 million and $4 million, respectively, other
long-term assets of $1 million and $6 million, respectively, and current liabilities of $1 million and $3 million, respectively.

Net
operating and capital loss carryforwards total approximately £900 million at December 31, 2003 and December 31, 2002. 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 for these tax loss carryforwards.

142

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Note 9. 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 $264 million at
December 31, 2003. 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:

2003

2002Domestic InvestmentsEquity investment

$
611

$
767Loans receivable


200


183Subtotal


811


950International InvestmentsEquity investment


796


695Total

$
1,607

$
1,645


EME's subsidiaries have provided loans or advances related to certain projects. Domestic loans at December 31, 2003 consist of the
following: a $135 million, 10% interest loan, due on demand; a $26 million, 5% interest promissory note, interest payable semiannually, due April 2008; and a $39 million,
12% interest loan, due on demand.

The
undistributed earnings of investments accounted for by the equity method were $283 million in 2003 and $275 million in 2002.

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

Years Ended December 31,2003

2002

2001Revenues

$
3,657

$
3,001

$
3,146Expenses


2,917


2,389


2,492Net income

$
740

$
612

$
654


December 31,2003

2002Current assets

$
1,658

$
1,866Noncurrent assets


7,475


7,311Total assets

$
9,133

$
9,177Current liabilities

$
1,114

$
2,849Noncurrent liabilities


6,104


4,604Equity


1,915


1,724Total liabilities and equity

$
9,133

$
9,177


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

143

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As
explained in Note 2Summary of Significant Accounting Policies, EME is currently evaluating the impact of the provisions of FIN 46. It is possible that some
of the equity investments held by EME may be consolidated if the investments are deemed to be variable interest entities and EME is the primary beneficiary.

Virtually
all of these investments have operations and maintenance contracts, fuel supply arrangements and power sales contracts that will influence the determination of the entity's
status as a variable interest entity and which party is the primary beneficiary.

The
following table presents, as of December 31, 2003, 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 Affiliate |  | Location              |  | Investment |     | Ownership
Interest |    | Operating Status
|------------------------ |  | --------------------- |  | ---------- | --- | ------------------ | -- | ----------------
|Paiton                   |  | East Java, Indonesia  |  | $          | 565 |                    | 40 | %               
|EcoEléctrica             |  | Peñuelas, Puerto Rico |  |            | 282 |                    | 50 | %               
|Watson                   |  | Carson, CA            |  |            | 93  |                    | 49 | %               
|Sunrise                  |  | Fellows, CA           |  |            | 88  |                    | 50 | %               
|ISAB                     |  | Sicily, Italy         |  |            | 76  |                    | 49 | %               
|March Point              |  | Anacortes, WA         |  |            | 64  |                    | 50 | %               
|Sycamore                 |  | Bakersfield, CA       |  |            | 57  |                    | 50 | %               
|Four Star                |  | Houston, TX           |  |            | 52  |                    | 38 | %               
|Midway-Sunset            |  | Fellows, CA           |  |            | 51  |                    | 50 | %               
|Kern River               |  | Bakersfield, CA       |  |            | 42  |                    | 50 | %               

During December 2003, EME purchased additional shares in its oil and gas investment (Four Star Oil & Gas Company) for
$3 million, increasing its interest from 37.20% to 38.48%. During December 2001, EME purchased additional shares in Four Star Oil & Gas Company for $7 million, increasing
its interest from 35.84% to 37.20%.

Note 10. Property, Plant and Equipment

Property, plant and equipment consist of the following:

December 31,2003

2002Buildings, plant and equipment

$
4,889

$
3,451Emission allowances


1,305


1,305Civil works


2,453


2,776Construction in progress


37


77Capitalized leased equipment


1


418,685


7,650Less accumulated depreciation and amortization


1,263


888Net property, plant and equipment

$
7,422

$
6,762


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.

144

---

Note 11. Financial Instruments

Management Plans for Refinancing $693 Million Debt Maturity at Edison Mission Midwest Holdings

MEHC's consolidated debt at December 31, 2003 was $7.4 billion, including $693 million of debt maturing on December 15, 2004 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 $693 million debt due in
December 2004. Edison Mission Midwest Holdings plans to refinance the $693 million debt obligation prior to its expiration in December 2004. Management believes that Edison
Mission Midwest Holdings will be able to refinance the debt maturing in December 2004 through a combination of borrowings in the bank and capital markets. Completion of this refinancing is
subject to a number of uncertainties, including the availability of new credit from the capital and bank markets. Accordingly, there is no assurance that Edison Mission Midwest Holdings will be able
to 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 31,2003

2002Other short-term obligations

$
52

$
78Weighted-average interest rate


5.32
%

6.13
%


At December 31, 2003, EME had available $145 million of borrowing capacity under a $145 million revolving credit facility
that expires in September 2004 (Tranche B). At December 31, 2003, other short-term borrowings consisted of several promissory notes due January 2004 through
March 2004 that relate to the Contact Energy project.

At
December 31, 2002, other short-term borrowings consisted of several promissory notes due January 2003 through March 2003, which relates to the Contact
Energy project.

EME's
recourse debt to recourse capital ratio:

|Financial Ratio                         |  | Covenant                    |  | Actual at
December 31, 2003 |   | Description                                                                                                                                       
|--------------------------------------- |  | --------------------------- |  | --------------------------- | - | --------------------------------------------------------------------------------------------------------------------------------------------------
|Recourse Debt to Recourse
Capital Ratio |  | Less than or equal to 67.5% |  | 59.8                        | % | Ratio of (a) senior recourse debt to (b) sum of (i) adjusted shareholder's equity as defined in the credit agreement,plus(ii) senior recourse
debt

At December 31, 2003, EME met the above financial covenant. In addition, EME met the interest coverage ratio pursuant to the EME corporate
facilities at December 31, 2003. The interest coverage ratio is based on cash received by EME, including tax-allocation payments, cash disbursements and interest paid.

145

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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, 2003, recourse debt to EME totaled $1.7 billion and non-recourse project debt totaled $4.5 billion. Long-term obligations consist of the
following:

December 31,2003

2002Corporate debt (with recourse to MEHC)MEHC (parent only)Senior Notes, net due 2008 (13.5%)

$
787

$
785Credit Agreement due 2006
(LIBOR+7.50% (8.66% at 12/31/03)


379


377RecourseEME (parent only)Senior Notes, netdue 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%+0.0098%) (6.28% at 12/31/03)


28


181Long-Term ObligationsAffiliate


78


78Non-recourse (unless otherwise noted)Due to EME Funding Corp.  Long-Term Obligation due 1997-2003 (6.77%)





47Due to EME Funding Corp.  Long-Term Obligation due 2004-2008 (7.33%)


190


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


83


84Edison Mission Midwest Holdings Co.Tranche A due 2003 (LIBOR+2.25%) (3.66% at 12/31/02)





911Tranche B due 2004 (LIBOR+2.00%) (3.25% at 12/31/03)


693


808Mission Energy Holdings International, Inc.Credit Agreement due 2006
(LIBOR+5.00%) (7.00% at 12/31/03)


796


Contact Energy projectMedium Term NoteUS$75 MM due 2013 (6.94% at 12/31/03)


76


75Medium Term NoteUS$25 MM due 2018 (7.13% at 12/31/03)


25


25Medium Term NoteUS$90 MM due 2010 (4.54% at 12/31/03)


92


Medium Term NoteUS$87 MM due 2014 (5.26% at 12/31/03)


89


Medium Term NoteUS$103 MM due 2015 (5.31% at 12/31/03)


105


Medium Term NoteUS$40 MM due 2018 (5.55% at 12/31/03)


41





146

---

Floating Rate NoteUS$50 MM due 2007
(LIBOR+0.8%) (5.36% at 12/31/03)


51


50Floating Rate NoteA$120 MM due 2007
(BBSW+0.95%) (5.36% at 12/31/03)


92


67Term Loan FacilityNZ$50 MM due 2004
(BKBM+0.45%) (5.36% at 12/31/03)


33


26Medium Term NoteNZ$70 MM due 2003 (7.25% at 12/31/02)





37CSFB Revolving Credit Facility due 2005
(BKBM+1.75%) (7.34% at 12/31/03)


187


150Doga projectFinance Agreement between Doga and OPIC due 2010 (11.2%)


62


70NCM Credit Agreement due 2010
(U.S. LIBOR+1.25%) (2.31% at 12/31/03)


23


26First Hydro plantsFirst Hydro Finance plc £400 MM Guaranteed Secured Bonds due 2021 (9%)


714


644£18 MM Credit Agreement due 2003
(Sterling LIBOR+0.55%+0.0103%) (4.74% at 12/31/02)





29Iberian Hy-Power plantsEuro dollar Project Finance Credit Facility due 2012 (EURIBOR+0.875%) (3.09% at 12/31/03)


43


43Euro dollar Subordinated Loan due 2008 (9.408%)


28


22Euro dollar Compagnie Générale Des Eaux due 2003
(non-interest bearing)recourse





30Euro dollar Banco Vitalicio due 2006 (6.17% at 12/31/03)


2


2Kwinana plantAustralian dollar Syndicated Project Facility Agreement due 2011 (BBR+1.3% to 1.4%) (5.99% at 12/31/03)


58


47Loy Yang B plantAustralian dollar Amortising Term Facility due 2017 (BBR+0.6% to 1.0%) (5.553% at 12/31/03)


502


382Australian dollar Interest Only Term Facility due 2012 (BBR+0.6% to 0.75%)
(5.553% at 12/31/03)


369


276Australian dollar Working Capital Facility due 2017 (BBR+0.6% to 1.0%)
(5.553% at 12/31/03)


8


6Amortising Cash Advance Facility due 2009
(BBR+3%) (8.078% at 12/31/03)


11


Amortising Loan Facility due 2009
(BBR+0.1%+3.25%) (8.178% at 12/13/03)


38





147

---

Valley Power plantAustralian dollar Amortising Facility due 2011 (BBR+1.55%) (6.795% at 12/31/03)

$
45

$
39Australian dollar Bullet Facility due 2007 (BBR+1.55%)
(6.795% at 12/31/03)


28


21Subtotal

$
7,353

$
7,124Current maturities of long-term obligations


(856
)

(1,090
)Total

$
6,497

$
6,034


MEHC Term Loan Put Option

The lenders under MEHC's $385 million term loan due in 2006 have the right to require MEHC to repurchase up to $100 million of principal amount at
par on July 2, 2004 (referred to as the "Term Loan Put-Option"). The Term Loan Put Option is exercised by the holders of the term loan with 90 days prior written notice.

Mission Energy Holdings International, Inc. Financing

On December 11, 2003, EME's subsidiary, Mission Energy Holdings International, Inc., received funding under a three-year,
$800 million secured loan from Citigroup, Credit Suisse First Boston, JPMorganChaseBank, and Lehman Brothers. Interest on this secured loan is based on LIBOR (with a LIBOR floor of 2%) plus 5%.
After payment of transaction expenses, a portion of the net proceeds from this financing was used to make an equity contribution of $550 million to Edison Mission Midwest Holdings which,
together with cash on hand, was used to repay Edison Mission Midwest Holdings' $781 million indebtedness due December 11, 2003. The remaining net proceeds from this financing were used
to make a deposit of cash collateral of approximately $67 million under the new letter of credit facility described below and to repay approximately $160 million of indebtedness of a
foreign subsidiary under the Coal and Capex facility guaranteed by EME. Mission Energy Holdings International owns substantially all of EME's international operations through its subsidiary, MEC
International B.V.

Long-term ObligationsAffiliates

During 1997, EME declared a dividend of $78 million to The Mission Group (now known as Edison Mission Group, Inc.) which was recorded as a note
payable due in June 2007 with interest at LIBOR
plus 0.275% (1.14% at December 31, 2003). The note was subsequently exchanged for two notes with the same terms and conditions and assigned to other subsidiaries of Edison International.

Coal and Capex Facility

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. During 2003, EME made total payments of approximately $160 million with proceeds from the
$800 million credit agreement entered into by Mission Energy Holdings International, Inc. EME plans to repay the borrowings outstanding at December 31, 2003 under the Coal and
Capex Facility from cash flows generated from EME's foreign subsidiaries at its maturity in 2004.

148

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Annual Maturities on Long-Term Debt

Annual maturities on long-term debt at December 31, 2003, for the next five years are summarized as follows:
2004$856 million; 2005$285 million; 2006$1,284 million; 2007$356 million; and 2008$1,276 million.

Standby Letters of Credit

As of December 31, 2003, standby letters of credit aggregated $145 million and were scheduled to expire as follows:
2004$93 million; 2005$13 million; and 2008 and thereafter $39 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 was $339 million at December 31, 2003 and $412 million at December 31, 2002. Included in restricted cash are debt service reserves of
$177 million and $159 million at December 31, 2003 and 2002, respectively, and collateral reserves of $145 million and $45 million at December 31, 2003 and
2002, respectively.

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 31,2003

2002InstrumentsNon-derivatives:Long-term receivables

$
6

$
6Long-term obligations


6,395


4,480Junior subordinated debentures


155


Company-obligated mandatorily redeemable security of partnership holding solely parent debentures





115Preferred securities subject to mandatory redemption


164


131


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 12. 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.

149

---

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 define risk tolerances for each EME regional business unit. Procedures exist which allow for monitoring of all commitments and
positions with regular reviews by a risk management committee. 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.

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 and April 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 2.84% and 3.04% at December 31, 2003 and 2002, respectively. Counterparties will pay MEHC interest at a weighted average variable rate based on LIBOR of 1.15% and
1.63% at December 31, 2003 and 2002, 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 6.39% and 6.91% at December 31, 2003 and 2002, 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 5.36% and 6.18% at December 31, 2003 and 2002,
respectively. Under the variable to fixed swap agreements, EME will pay counterparties interest at a weighted average fixed rate of 6.74% and 6.96% at December 31, 2003 and 2002, respectively.
Counterparties will pay EME interest at a weighted average variable rate of 5.07% and 5.10% at December 31, 2003 and 2002, 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 6.24% and 6.90%
at December 31, 2003 and 2002, 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,
collectively referred to as counterparties. Due to factors beyond EME's control, a number of formerly significant trading parties have completely withdrawn from the market or substantially reduced
their trading activities since the beginning of 2002, thereby potentially increasing exposure to the remaining counterparties. 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

150

---

markets
which may also increase EME's credit risk. 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 counterparties. Credit risk is measured by the loss that would be incurred if counterparties failed to perform
pursuant to the terms of their contractual obligations. EME measures, monitors and mitigates, to the extent possible, credit risk. To mitigate counterparty risk, master netting agreements are used
whenever possible and counterparties may be required to pledge collateral when deemed necessary. EME also takes other appropriate steps to limit or lower credit exposure. Processes have also been
established to determine
and monitor the creditworthiness of counterparties. EME manages the credit risk on the 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. A risk management committee regularly reviews the credit quality of EME's counterparties. Despite this, there can be no assurance that these efforts will be wholly successful in
mitigating credit risk or that collateral pledged will be adequate.

Exelon
Generation accounted for 22%, 41% and 43% of EME's consolidated operating revenues in 2003, 2002 and 2001, respectively. EME expects the percentage to be less in 2004 because a
smaller number of plants will be subject to contracts with Exelon Generation. Any failure of Exelon Generation to make payments under the power purchase agreements could adversely affect EME's results
of operations and financial condition.

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 8Discontinued Operations.

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 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, 2003 and 2002, 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.

151

---

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 31,2003

2002Derivatives:Interest rate:Interest rate swap/cap agreements

$
(34
)
$
(56
)Interest rate options


(1
)

(2
)Commodity price:Electricity


(126
)

(100
)Foreign currency forward exchange agreements


(2
)

Cross currency interest rate swaps


(91
)

(2
)


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 swaps 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

EME's risk management and trading operations are 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 and trading activities not related to EME's power plants or investments in energy projects. 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 Management."

The
fair value of the commodity financial instruments related to energy trading activities as of December 31, 2003 and 2002, are set forth below:

December 31, 2003

December 31, 2002Assets

Liabilities

Assets

LiabilitiesElectricity

$
104

$
11

$
109

$
15Other





1





2Total

$
104

$
12

$
109

$
17


Quoted market prices are used to determine the fair value of the financial instruments related to trading activities.

152

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Note 13. Preferred Securities and Junior Subordinated Debentures

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, 2003. 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, 2003. 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. As described in Note 2Summary of Significant Accounting Policies, EME no longer consolidates Mission Capital and includes the junior subordinated debentures in its
consolidated balance sheet.

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.

Preferred Securities Subject to Mandatory Redemption

During 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 with a dividend rate of 6.03%). The shares are redeemable in July 2006 at issuance price. At December 31, 2003, total accumulated dividends were approximately
$5 million. 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

153

---

in
Mission Energy Pacific Holdings (Pacific). Universal and Pacific are wholly owned subsidiaries of EME. Mission Contact Finance will call on 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 14. Income Taxes

Current and Deferred Taxes

The provision (benefit) for income taxes is comprised of the following:

Years Ended December 31,2003

2002

2001Continuing Operations:CurrentFederal

$
(106
)
$
(175
)
$
(44
)State


(46
)

(83
)

8Foreign


54


35


14Total current


(98
)

(223
)

(22
)DeferredFederal


(22
)

163


49State


2


28


31Foreign


33


12


8Total deferred


13


203


88Provision (benefit) for income taxes from continuing operations


(85
)

(20
)

66Discontinued operations


1


(17
)

(772
)Change in accounting


(4
)

(9
)

7Total

$
(88
)
$
(46
)
$
(699
)


154

---

The
components of income (loss) before income taxes and minority interest applicable to continuing operations, discontinued operations, and cumulative effect of change in accounting are
as follows:

Years Ended December 31,2003

2002

2001Continuing Operations:U.S.

$
(361
)
$
(164
)
$
41Foreign


244


174


82Total continuing operations


(117
)

10


123Discontinued operations


2


(75
)

(1,991
)Change in accounting


(13
)

(23
)

22Total

$
(128
)
$
(88
)
$
(1,846
)


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
or would not be subject to additional income taxes if repatriated. EME reviewed undistributed earnings of its international subsidiaries and concluded that no additional income taxes are required to
be provided since (1) its international holding company had negative retained earnings and negative accumulated earnings and profits for federal income tax purposes, (2) distributions
from lower tier international subsidiaries would either not be taxable or could be distributed without additional income taxes and (3) its international holding company had outstanding
indebtedness to domestic subsidiaries totaling $445 million at December 31, 2003 which could be repaid without incurring additional income taxes.

Variations
from the 35% federal statutory rate for income from continuing operations are as follows:

Years Ended December 31,2003

2002

2001Expected provision for federal income taxes

$
(41
)
$
4

$
43Increase (decrease) in the provision for taxes resulting from:State taxnet of federal deduction


(29
)

(36
)

22Dividends received deduction


(12
)

(5
)

(10
)Taxes payable under anti-deferral regimes


3


14


14Taxes on foreign operations at different rates


(6
)

(2
)

(5
)Other





5


2Provision (benefit) for income taxes

$
(85
)
$
(20
)
$
66Effective tax rate


73
%

(200
)%

54
%


155

---

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 were:

December 31,2003

2002Deferred tax assetsItems deductible for book not currently deductible for tax

$
1

$
78Loss carryforwards


161


81Deferred income


177


172Dividends in excess of equity earnings





8Other





4Subtotal


339


343Valuation allowance


(74
)

(22
)Total

$
265

$
321Deferred tax liabilitiesBasis differences

$
1,575

$
1,457Tax credits, net


13


18Price risk management


(51
)

25Other


22


2Total


1,559


1,502Deferred taxes and tax credits, net

$
1,294

$
1,181


Foreign
loss carryforwards, primarily Australian, total $487 million and $204 million at December 31, 2003 and 2002, respectively, with no expiration date. State
loss carryforwards for various states total $168 million and $230 million at December 31, 2003 and 2002, respectively, with various expiration dates. State capital loss
carryforwards total $23 million and $128 million at December 31, 2003 and 2002, respectively, and will expire in 2005.

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 15. 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.

156

---

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. 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 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, 2003 and 2002, the accumulated benefit obligations of the First Hydro and Edison Mission Limited plans, exceeded the related plan assets at the measurement dates.
In accordance with accounting standards, EME's consolidated balance sheets include an additional minimum liability, with corresponding charges to intangible assets and 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 exceed the accumulated benefit obligation.

The
expected contributions (all by the employer) for United States plans are approximately $13 million for the year ended December 31, 2004. This amount is subject to
change based on, among other things, the limits established for federal tax deductibility.

EME
uses a December 31 measurement date for all of its plans.

157

---

United States Plans

Information on plan assets and benefit obligations is shown below:

Years Ended December 31,2003

2002Change in projected benefit obligationProjected benefit obligation at beginning of year

$
104

$
77Service cost


14


13Interest cost


6


5Amendments





3Actuarial loss


2


9Benefits paid


(7
)

(3
)Projected benefit obligation at end of year

$
119

$
104Accumulated benefit obligation at end of year

$
90

$
77Change in plan assetsFair value of plan assets at beginning of year

$
39

$
41Actual return on plan assets


10


(5
)Employer contributions


11


6Benefits paid


(7
)

(3
)Fair value of plan assets at end of year

$
53

$
39Funded status

$
(66
)
$
(65
)Unrecognized net loss


23


29Unrecognized transition obligation


1


1Unrecognized prior service cost


2


2Recorded liability

$
(40
)
$
(33
)Additional detail of amounts recognized in balance sheets:Intangible asset

$


$
1Accumulated other comprehensive income





Pension plans with an accumulated benefit obligation in excess of plan assets:Projected benefit obligation

$
24

$
19Accumulated benefit obligation


14


12Fair value of plan assets





Weighted-average assumptions at end of year:Discount rate


6.00
%

6.50
%Rate of compensation increase


5.00
%

5.00
%


158

---

Components of pension expense are:

Years Ended December 31,2003

2002

2001Service cost

$
14

$
13

$
10Interest cost


6


5


4Expected return on plan assets


(4
)

(3
)

(3
)Net amortization and deferral


2


1


Total expense recognized

$
18

$
16

$
11Change in accumulated other comprehensive income








Weighted-average assumptions:Discount rate


6.50
%

7.00
%

7.25
%Rate of compensation increase


5.00
%

5.00
%

5.00
%Expected return on plan assets


8.50
%

8.50
%

8.50
%


Asset allocations for plans are:

December 31,Target for
20042003

2002United States equity

45
%
46
%
45
%Non-United States equity

25
%
26
%
25
%Private equity

4
%
3
%
3
%Fixed income

26
%
25
%
27
%


159

---

Foreign Plans

Information on plan assets and benefit obligations is shown below:

Years Ended December 31,2003

2002Change in projected benefit obligationBenefit obligation at beginning of year

$
66

$
114Service cost


4


2Interest cost


4


8Actuarial loss (gain)


12


(4
)Curtailment/settlement


2


(53
)Plan participants' contribution


1


1Benefits paid


(4
)

(2
)Projected benefit obligation at end of year

$
85

$
66Change in plan assetsFair value of plan assets at beginning of year

$
43

$
110Actual return on plan assets


16


(18
)Employer contributions


8


4Curtailment/settlement





(51
)Benefits paid


(4
)

(2
)Fair value of plan assets at end of year

$
63

$
43Funded status

$
(22
)
$
(23
)Unrecognized net loss


20


19Recorded asset (liability)

$
(2
)
$
(4
)Pension plans with an accumulated benefit obligation in excess of plan assets:Projected benefit obligation

$
73

$
58Accumulated benefit obligation


69


52Fair value of plan assets


53


37Weighted-average assumptions at end of year:Discount rate


5.50%


5.00  5.50%Rate of compensation increase


3.80  4.00%


3.50  4.00%


160

---

Components of pension expense are:

Years Ended December 31,2003

2002

2001Service cost

$
4

$
2

$
3Interest cost


4


8


6Expected return on plan assets


(5
)

(10
)

(7
)Net amortization and deferral





15


Curtailment/settlement


1





Total pension recognized

$
4

$
15

$
2Weighted-average assumptions:Discount rate


5.00  5.50%


4.00  6.00%


4.00  6.00%Rate of compensation increase


3.50  4.00%


3.50  4.00%


3.75  4.50%Expected return on plan assets


7.50  8.00%


8.00%


5.75  9.00%


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 15, 2006. 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.

On
December 8, 2003, President Bush signed the Medicare Prescription Drug, Improvement and Modernization Act of 2003. The Act authorized a federal subsidy to be provided to plan
sponsors for certain prescription drug benefits under Medicare. EME has elected to defer accounting for the effects of the Act until the earlier of the issuance of guidance by the Financial Accounting
Standards Board on how to account for the Act, or the remeasurement of plan assets and obligations subsequent to
January 31, 2004. Accordingly, any measures of the accumulated postretirement benefit obligation or net periodic postretirement benefit expense in the financial statements or this note do not
reflect the effects of the Act on EME's plan.

The
expected contributions (all by the employer) for the postretirement benefits other than pensions plan are $1 million for the year ended December 31, 2004. This amount
is subject to change based on, among other things, the Act referenced above and the impact of any benefit plan amendments.

EME
uses a December 31, measurement date.

161

---

Information
on plan assets and benefit obligations is shown below:

Years Ended December 31,2003

2002Change in benefit obligationBenefit obligation at beginning of year

$
56

$
118Service cost


2


5Interest cost


3


8Amendments


(14
)

Settlement





(71
)Actuarial loss (gain)


7


(3
)Benefits paid


(1
)

(1
)Benefit obligation at end of year

$
53

$
56Change in plan assetsFair value of plant assets at beginning of year

$


$
Employer contributions


1


1Benefits paid


(1
)

(1
)Fair value of plan assets at end of year

$


$
Funded status

$
(53
)
$
(56
)Unrecognized net loss


16


9Unrecognized prior service cost


(15
)

(2
)Recorded liability

$
(52
)
$
(49
)Assumed health care cost trend rates:Rate assumed for following year


12.00
%

9.75
%Ultimate rate


5.00
%

5.00
%Year ultimate rate reached


2010


2008Weighted-average assumptions at end of year:Discount rate


6.25
%

6.75
%


Expense components of postretirement benefits are:

Years Ended December 31,2003

2002

2001Service cost

$
2

$
5

$
5Interest cost


3


8


7Settlement





(71
)

Net amortization and deferral


(1
)




Total expense

$
4

$
(58
)
$
12Assumed health care cost trend rates:Current year


9.75
%

10.50
%

11.00
%Ultimate rate


5.00
%

5.00
%

5.00
%Year ultimate rate reached


2008


2008


2008Weighted-average assumptions:Discount rate


6.40
%

7.25
%

7.50
%


162

---

Increasing the health care cost trend rate by one percentage point would increase the accumulated obligation as of December 31, 2003, by
$11 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, 2003, by $9 million and annual aggregate service and interest costs by $1 million.

Description of Investment Strategies for United States Plans

The investment of plan assets is overseen by a fiduciary investment committee. Plan assets are invested using a combination of asset classes, and may have active
and passive investment strategies within asset classes. EME employs multiple investment management firms. Investment managers within each asset class cover a range of investment styles and approaches.
Risk is controlled through diversification among multiple asset classes, managers, styles, and securities. Plan, asset class and individual manager performance is measured against targets. EME also
monitors the stability of its investments managers' organizations.

Allowable
investment types include:



Permitted
ranges around asset class portfolio weights are plus or minus 5%. Where approved by the fiduciary investment committee, futures contracts are used for portfolio rebalancing and
to approach fully invested portfolio positions. Where authorized, a few of the plan's investment managers employ limited use of derivatives, including futures contracts, options, options on futures
and interest rate swaps in place of direct investment in securities to gain efficient exposure to markets. Derivatives are not used to leverage the plans or any portfolios.

Determination of the Expected Long-Term Rate of Return on Assets for United States Plans

The overall expected long term rate of return on assets assumption is based on the target asset allocation for plan assets, capital markets return forecasts for
asset classes employed, and active management excess return expectations.

Capital Markets Return Forecasts

The estimated total return for fixed income is based on an equilibrium yield for intermediate United States government bonds plus a premium for exposure to
non-government bonds in the broad fixed income market. The equilibrium yield is based on analysis of historic data and is consistent with experience over various economic environments. The
premium of the broad market over United States government bonds is a historic average premium. The estimated rate of return for equity is estimated to be a 3% premium over the estimated total return
of intermediate United States government bonds. This value is determined by combining estimates of real earnings growth, dividend yields and inflation, each of which was determined using historical
analysis. The rate of return for private equity is

163

---

estimated
to be a 5% premium over public equity, reflecting a premium for higher volatility and illiquidity.

Active Management Excess Return Expectations

For asset classes that are actively managed, an excess return premium is added to the capital market return forecasts discussed above.

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
2003, $6 million in 2002 and $6 million in 2001.

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 $15 thousand in 2003, $114 thousand in 2002 and $97 thousand in 2001.

EME
also sponsors a defined contribution plan for specified United Kingdom subsidiaries. Annual contributions are based on 10% to 20% of covered employees' salaries. Contribution expense
for the subsidiaries totaled approximately $3 million in 2003, $1 million in 2002 and $1 million in 2001.

Note 16. Stock Compensation Plans

Stock-Based Employee Compensation

In 1998, Edison International shareholders approved the Edison International Equity Compensation Plan, replacing the long-term incentive compensation
program that had been adopted by Edison International shareholders in 1992. The 1998 plan authorizes a limited annual number of Edison International common shares that may be issued in accordance with
plan awards to key EME employees. The annual authorization is cumulative, allowing subsequent issuance of previously unutilized awards. In May 2000, Edison International adopted an additional
plan, the 2000 Equity Plan, under which stock options, including the special options discussed below may be awarded.

Under
the 1992, 1998 and 2000 plans, options on 2,784,814 shares of Edison International common stock are outstanding as of December 31, 2003 to employees and former employees of
EME. 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 stock 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 2003 options include a dividend equivalent feature for the first five years of the option term. Dividend equivalents accumulate without
interest. 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.

164

---

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.

The
fair value for each option granted, reflecting the basis for the pro forma disclosures in Note 2, 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:

2003

2002

2001Expected life

10 years

7  10 years

7  10 yearsRisk-free interest rate

3.8% to 4.5%

4.7% to 6.1%

4.7% to 6.1%Expected dividend yield

1.8%

1.8%

3.3%Expected volatility

44% to 53%

18% to 54%

17% to 52%


The expected dividend yield above is computed using an average of the previous 12 quarters. The expected volatility above is computed on an
historical 36-month basis. The application of fair-value accounting to calculate the pro forma disclosures is not an indication of future income statement effects. The pro
forma disclosures do not reflect the effect of fair-value accounting on stock-based compensation awards granted prior to 1995.

The
weighted-average fair value of options granted during 2003, 2002 and 2001 was $7.31 per share option, $7.88 per share option and $3.88 per share option, respectively. The
weighted-average remaining life of options outstanding was 6 years as of December 31, 2003, 2002 and 2001.

A
summary of the status of Edison International's stock options granted to EME employees is as follows:

|                                             |  | Share
Options |   | Exercise Price   |  | Weighted
Exercise Price
|-------------------------------------------- |  | ------------- | - | ---------------- |  | -----------------------
|Outstanding, December 31, 2000               |  | 3,353,371     |   | $14.56  $29.34  |  | $                      
|Granted                                      |  | 649,768       |   | $  9.10  $15.25 |  | $                      
|Transferred to EME from Edison International |  | 1,327,105     |   | $14.56  $28.94  |  | $                      
|Forfeited                                    |  | (3,583,233    | ) | $  9.15  $29.34 |  | $                      
|                                             |  |               |   |                  |  |                        
|Outstanding, December 31, 2001               |  | 1,747,011     |   | $  9.10  $29.34 |  | $                      
|Granted                                      |  | 967,405       |   | $10.60  $18.73  |  | $                      
|Transferred from EME to Edison International |  | (22,046       | ) | $  9.15  $28.94 |  | $                      
|Forfeited                                    |  | (466,382      | ) | $  9.10  $29.34 |  | $                      
|Exercised                                    |  | (44,176       | ) | $15.18  $18.80  |  | $                      
|                                             |  |               |   |                  |  |                        
|Outstanding, December 31, 2002               |  | 2,181,812     |   | $  9.10  $28.94 |  | $                      
|Granted                                      |  | 1,020,910     |   | $11.88  $18.87  |  | $                      
|Transferred from EME to Edison International |  | (32,351       | ) | $  9.57  $28.94 |  | $                      
|Forfeited                                    |  | (315,788      | ) | $  9.57  $28.94 |  | $                      
|Exercised                                    |  | (69,769       | ) | $  9.10  $20.19 |  | $                      
|                                             |  |               |   |                  |  |                        
|Outstanding, December 31, 2003               |  | 2,784,814     |   | $  9.10  $28.94 |  | $                      
|                                             |  |               |   |                  |  |                        

The number of options exercisable and their weighted-average exercise prices at December 31, 2003, 2002 and 2001 were 863,116 at $19.26;
731,009 at $21.29 and 780,802 at $22.49, respectively.

165

---

Other Equity-Based Awards

For the years after 1999, a portion of the executive long-term incentives was awarded in the form of performance shares. Performance shares were
awarded in January 2001, January 2002 and January 2003. The performance shares vest December 31, 2003, December 31, 2004 and December 31, 2005, and are paid
out half in shares of Edison International common stock and half in cash. The number of shares that will be paid out from the 2002 and 2003 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 2001 performance share values are accrued ratably over a three-year
performance period. The 2002 and 2003 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 vested and were paid March 12, 2003 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, the first and second vesting dates
were in November 2002 and November 2003. 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%.

EME
measures compensation expense related to stock-based compensation by the intrinsic value method. Compensation expense recorded under the stock compensation program was approximately
$11 million, $4 million and $3 million for the years ended December 31, 2003, 2002 and 2001, respectively.

Phantom Stock Options

EME, as a part of the Edison International long-term incentive compensation program for senior management, issued phantom stock option performance
awards to key employees through 1999. In August 2000, all outstanding phantom stock options were exchanged for 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 $4 million, $2 million, and
$6 million in 2003, 2002 and 2001, respectively.

Note 17. Commitments and Contingencies

Capital Improvements

At December 31, 2003, EME's subsidiaries had firm commitments to spend approximately $80 million on construction and other capital investments
during 2004 through 2008. These expenditures are planned to be financed by existing subsidiary credit agreements and cash generated from these operations. The construction expenditures primarily
relate to the construction of a power plant in New Zealand by Contact Energy. The capital expenditures primarily relate to new plant and equipment primarily related to Midwest Generation and the
Contact Energy project.

166

---

Fuel Supply Contracts

At December 31, 2003, 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 $2.4 billion in the next five years summarized as
follows: 2004$729 million; 2005$688 million; 2006$475 million; 2007$311 million; and
2008$153 million.

Gas Transportation Agreements

At December 31, 2003, EME had a contractual commitment to transport natural gas. EME's share of the commitment to pay minimum fees under its gas
transportation agreement, which has a term of 15 years, is currently estimated to aggregate $35 million in the next five years, summarized as follows: 2004$7 million;
2005$7 million; 2006$7 million; 2007$7 million; and 2008$7 million.

Other Contractual Obligations

At December 31, 2003, Midwest Generation was party to a long-term power purchase contract with Calumet Energy Team LLC entered into as part of
the settlement agreement with Commonwealth Edison, which terminated Midwest Generation's obligation to build additional gas-fired generation in the Chicago area. The contract requires
Midwest Generation to pay a monthly capacity payment and gives Midwest Generation an option to purchase energy from Calumet Energy Team LLC at prices based primarily on operations and maintenance and
fuel costs.

EME
Homer City entered into a Coal Cleaning Agreement with Homer City Coal Processing Corporation to operate and maintain a coal cleaning plant owned by EME Homer City. Under the terms
of the agreement, EME Homer City is obligated to reimburse Homer City Coal Processing Corporation for the actual costs incurred in the operations and maintenance of the coal cleaning plant, a fixed
general and administrative service fee of approximately $260 thousand per year, and an operating fee that ranges from $.20 to $.35 per ton depending on the level of tonnage. The agreement
expired on August 31, 2002 and was renewed with the same terms through December 31, 2005, with a two-year extension option.

At
December 31, 2003, other contractual obligations are summarized as follows: 2004$11 million; 2005$10 million;
2006$4 million; 2007$4 million; and 2008$4 million.

Guarantees and Indemnities

Tax Indemnity Agreements

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 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.

Indemnities Provided as Part of the Acquisition of the Illinois Plants

In connection with the acquisition of the Illinois Plants, EME agreed to indemnify Commonwealth Edison with respect to environmental liabilities before and after
the date of sale as specified in the

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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 with Commonwealth Edison on February 20, 2003 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, 2003, Midwest Generation had $10 million recorded as a
liability related to this matter and had made $1 million in payments.

Indemnity Provided as Part of the Acquisition of the Homer City Facilities

In connection with the acquisition of the Homer City facilities, EME Homer City Generation L.P. (EME Homer City) agreed to indemnify the sellers with respect to
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 and does not have 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.

Indemnities Provided under Asset Sale Agreements

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 has 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. Not all indemnities under the asset sale agreements 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.

Guarantee of Brooklyn Navy Yard Contractor Settlement Payments

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 agreed to indemnify Brooklyn Navy Yard Cogeneration Partners, L.P. for any payments due under this settlement agreement,
which are scheduled through 2006. At December 31, 2003, EME recorded a liability of $14 million related to this indemnity.

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Guarantee of 50% of TM Star Fuel Supply Obligations

TM Star was formed for the limited purpose of selling natural gas to 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 Company. 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 Company, and, accordingly, no claims against this guarantee have been made. TM Star was merged
into March Point Cogeneration Company effective as of January 16, 2004, and this guarantee terminated by operation of law as of that date.

Capacity Indemnification Agreements

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 agreements terminate, 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, 2003, if payment were required, would be $181 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.

Bank Indemnity under a Letter of Credit Supporting ISAB Energy's Debt Service Reserve Account

EME agreed to indemnify its lenders under its credit facilities from amounts drawn on a $26 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.

Subsidiary Indemnity to Central Maine Power Company for Value of Points of Delivery

A subsidiary of EME agreed to indemnify Central Maine Power Company against decreases in the value of power deliveries by CL Eight, 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.

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Subsidiary Guarantees for Performance of Unconsolidated Affiliates

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.

Contingencies

Legal 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. 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 was not served with the complaint. On November 25, 2003, the plaintiffs filed a voluntary dismissal with
prejudice of this lawsuit. The dismissal was entered by the court on December 2, 2003.

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. On July 9, 2003, Judge Whaley of the U.S. District Court concluded the federal court lacked jurisdiction and remanded the case
to the originating San Francisco Superior Court. Defendants, including Sunrise Power Company, have stipulated to respond to the complaint thirty days after it is assigned to a specific court of the
San Francisco Superior Court. In December 2003, James Millar filed a First Amended Class Action and Representative Action Complaint which contains allegations similar to those in the earlier
complaint but also alleges a class action. One of the newly added parties has again removed the lawsuit to federal court, where it is currently pending (subject to remand). 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 new regulation contains, among other things, a requirement
that each generator obtain a generation

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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 new regulation allows the possibility of insertion of provisions in a new license which may
be 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. Doga complied with the new regulation's stipulation to apply for a new
generation license by June 2, 2003. The license has not been issued yet. 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 power producers in Turkey acting independently) filed a lawsuit in the Danistay, Turkey's high administrative court, against the Energy
Market Regulatory Authority seeking both an injunction and permanent invalidation of certain provisions of the new regulation on the grounds of the illegality and unconstitutionality of any new
license requirement that does not take into account the vested rights of a company operating pursuant to previously agreed terms of the Implementation Contract.

On
May 12, 2003, the Danistay rejected Doga's request for injunctive relief (as well as those of the other power companies with similar claims). On July 10, 2003, Doga
appealed the Danistay's ruling. Doga's appeal was heard by the General Council of the Administrative Chambers of Danistay on October 10, 2003 and was rejected. There are no further rights of
appeal against the decision regarding the injunction. The Danistay will continue to hear the merits of Doga's lawsuit. A decision is expected to be rendered late in 2004.

Supply Contract from NRG Power Marketing

A subsidiary of EME, Edison Mission Marketing and Trading (referred to as EMMT) and NRG Power Marketing, Inc. (referred to as NRG Power Marketing) are
parties to a contract pursuant to which NRG Power Marketing sells 217,000 MWhr of electricity annually to EMMT. EMMT then resells this electricity to an unconsolidated 25%-owned affiliate, CL Power
Sales Eight, L.L.C. (referred to as CL Eight). On May 14, 2003, NRG Power Marketing filed for protection under Chapter 11 of the United States Bankruptcy Code. On August 7, 2003, NRG
Power Marketing was successful in having the contract with EMMT rejected by the Bankruptcy Court in the Southern District of New York. EMMT had sought an order lifting the automatic stay so that EMMT
could bring a proceeding at the FERC to seek an order directing NRG Power Marketing to continue performing under the contract with EMMT; the Bankruptcy Court denied this motion. As a result, EMMT is
still obligated to provide electricity to CL Eight, but without the supply from NRG Power Marketing. EMMT is appealing both the contract rejection and the denial of its request to lift the automatic
stay to the U.S. District Court in the Southern District of New York. Briefs are being filed, but no dates for oral arguments in the appeals have been established.

EMMT
has entered into purchase agreements for a portion of the volumes due under the supply contract. Current market prices exceed the price which CL Eight is required to pay to EMMT for
the electricity delivered. To the extent EMMT suffers losses as a result of being required to resell such electricity for less than it paid to purchase it, EMMT and EME are indemnified by Peabody
Energy Corporation pursuant to the 2000 Purchase and Sale Agreement for the acquisition of Citizens Power LLC.

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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.

Environmental Matters and Regulations

Introduction

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, future
proceedings that may be initiated by environmental authorities, and settlements agreed to by other companies 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 and regulations require a lengthy and complex process for obtaining licenses, permits and approvals prior to construction, operation or modification of a
project or generating facility. 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 injunctive relief or penalties and fines imposed by regulatory authorities.

StateIllinois

Air Quality

In June 2001, Illinois passed legislation mandating the Illinois Environmental Protection Agency, or Illinois EPA, 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 EPA 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 EPA 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 has been required to 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 Illinois power plants. Beginning with the 2004 ozone season, Midwest Generation's facilities will become subject to the federally-mandated "NOx SIP Call"
regulation that will cap ozone-season NOx emissions within a 19-state region east of the Mississippi. This program provides for NOx allowance trading similar to the current SO2 (acid rain)
trading program already in effect. EME has already

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qualified
for early reduction allowances by reducing NOx emissions at various plants ahead of the imposed deadline. Additionally, the installation of emission control technology at certain plants has
demonstrated over-compliance at those individual plants with the pending NOx emission limitations. Finally, NOx emission trading will be utilized as needed to comply with any shortfall at
plants where installation of emission control technology has demonstrated reductions at levels short of the pending NOx limitations.

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. An upgraded use classification could result in more stringent limits being applied to wastewater discharges to the river from these
plants. One of the limitations for discharges to the river that could be made more stringent if the existing use classification is changed would be the temperature of the discharges from Joliet and
Will County. The Illinois EPA has also begun a review of the water quality standards for the Chicago River and Chicago Sanitary and Ship Canal which are adjacent to the Fisk and Crawford Stations.
Proposed changes to the existing standards have not been developed at this time. At this time no new standards have been proposed, so EME cannot estimate the financial impact of this review. However,
the cost of additional cooling water treatment, if required, could be substantial.

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 the Pennsylvania Department of Environmental Protection (PADEP) that it has
been included in the Quarterly Noncompliance Report submitted to the United States EPA. 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 meet with PADEP to discuss the drafting of a consent agreement to address the selenium issue and then instruct the contractor to make the
necessary improvements. 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.

Mercury Maximum Achievable Control Technology Determination

In December 2000, the United States Environmental Protection Agency (EPA) announced its intent to regulate mercury emissions and other hazardous air
pollutants from coal-fired electric power

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plants
under Section 112 of the Clean Air Act, and indicated that it would propose a rule to regulate these emissions by no later than December 15, 2003. On December 15, 2003, EPA
issued proposed rules for regulating mercury emissions from coal-fired power plants. EPA proposed two rule options for public comment: 1) regulate mercury as a hazardous air pollutant under
Clean Air Act Sec. 112(d); or 2) rescind EPA's December 2000 finding regarding a need to control coal power plant mercury emissions as a hazardous air pollutant, and instead, promulgate
a new "cap and trade" emissions regulatory program to reduce mercury emissions in two phases by years 2010 and 2018. On February 24, 2004, the EPA announced a Supplemental Notice of Proposed
Rulemaking that provides more details on their emissions cap and trade proposal for mercury. At this time, EPA anticipates finalizing the regulations in December, 2004, with controls required to be in
place by some time between the end of 2007 (if the technology-based standard is chosen) and 2010 (when Phase I of the cap and trade approach would be implemented if this approach is chosen).

Management's
preliminary estimate is that the mercury regulations may require EME to spend up to $300 million for capital improvements at its Homer City facilities in the
2006-2010 time frame, although the timing will depend on the which proposal is adopted. Until the mercury regulations are finalized, EME cannot fully evaluate the potential impact of these regulations
on the operations of all its
facilities. Additional capital costs related to these regulations could be required in the future and they could be material, depending upon the final standards adopted by the EPA.

National Ambient Air Quality Standards

New ambient air quality standards for ozone, coarse particulate matter and fine particulate matter were adopted by the EPA in July 1997. It is widely
understood that attainment of the fine particulate matter standard may require reductions in emissions of nitrogen oxides and sulfur dioxides. These standards were challenged in the courts, and on
March 26, 2002, the United States Court of Appeals for the District of Columbia Circuit upheld the EPA's revised ozone and fine particulate matter ambient air quality standards.

Because
of the delays resulting from the litigation over the new standards, the EPA's new schedule for implementing the ozone and fine particulate matter standards calls for designation
of attainment and non-attainment areas under the two standards in 2004. Once these designations are published, states will be required to revise their implementation plans to achieve
attainment of the revised standards. The revised SIPs are likely to require additional emission reductions from facilities that are significant emitters of ozone precursors and particulates.

In
December 2003, the EPA proposed rules that would require states to revise their SIPs to address alleged contributions to downwind areas that are not in attainment with the
revised standards for ozone and fine particulate matter. This proposed "Interstate Air Quality" rule is designed to be completed before states must revise their SIPs to address local reductions needed
to meet the new ozone and fine particulate matter standards. The proposed rule would establish a two-phase, regional cap and trade program for sulfur dioxide and nitrogen oxide. The
proposed rule would affect 27 states, including Illinois and Pennsylvania. The proposed rule would require sulfur dioxide emissions and nitrogen oxide emissions to be reduced in two phases (by 2010
and 2015), with emissions reductions for each pollutant of 65% by 2015. The EPA is expected to issue final rules in December 2004.

At
this time, EME cannot predict the emission reduction targets that the EPA will ultimately adopt or the specific timing for compliance with those targets. In addition, any additional
obligations on EME's facilities to further reduce their emissions of sulfur dioxide, nitrogen oxides and fine particulates to address local non-attainment with the 8-hour ozone
and fine particulate matter standards will not be known until the states revise their implementation plans. Depending upon the final standards that are adopted, EME may incur substantial costs or
financial impacts resulting from required capital improvements or operational changes.

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New Source Review Requirements

On November 3, 1999, the United States Department of Justice filed suit against a number of electric utilities, not including EME, for alleged violations
of the Clean Air Act's "new source review" (NSR) requirements related to modifications of air emissions sources at electric generating stations.

Several
utilities have reached formal agreements or agreements-in-principle with the United States to resolve alleged NSR violations. These settlements involved
installation of additional pollution controls, supplemental environment projects, and the payment of civil penalties. The agreements provided for a phased approach to achieving required emission
reductions over the next 10 to 15 years, and some called for the retirement or repowering of coal-fired generating units. The total cost of some of these settlements exceeded
$1 billion; the civil penalties agreed to by these utilities generally 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 these settlements have not been finalized. However, the Department of Justice review released in January 2002 concluded
"EPA has a reasonable basis for arguing that the enforcement actions are consistent with both the Clean Air Act and the Administrative Procedure Act." No change in the Department of Justice's position
regarding pending NSR legal actions has been announced as a result of EPA's proposed NSR reforms (discussed immediately below). In January 2004, EPA announced new enforcement actions against
several power generating facilities.

On
December 31, 2002, the EPA 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 plant-wide applicability limits. Although states, industry groups and environmental organizations have filed litigation challenging various aspects of
the rule, it became effective March 3, 2003. To date, the rule remains in effect, although the pending litigation could still result in changes to the final rule.

A
federal district court, ruling on a lawsuit filed by EPA, found on August 7, 2003, that the Ohio Edison Company violated requirements of the NSR within the Clean Air Act by
upgrading certain coal-fired power plants without first obtaining the necessary pre-construction permits. On August 26, 2003, another federal district court ruling in an
NSR enforcement action against Duke Energy Corporation, adopted a different interpretation of the NSR provisions that could limit liability for similar upgrade projects.

On
October 27, 2003, EPA issued a final rule revising its regulations to define more clearly a category of activities that are not subject to NSR requirements under the "routine
maintenance, repair and replacement" exclusion. This clearer definition of "routine maintenance, repair and replacement," would provide EME greater guidance in determining what investments can be made
at its existing plants to improve the safety, efficiency and reliability of its operations without triggering NSR permitting requirements, and might mitigate the potential impact of the Ohio Edison
decision. However, on December 24, 2003, the United States Court of Appeals for the D.C. Circuit blocked implementation of the "routine maintenance, repair and replacement" rule, pending
further judicial review.

Prior
to EME's purchase of the Homer City facilities, the EPA requested information under Section 114 of the Clean Air Act from the prior owners of the plant concerning physical
changes at the plant. This request was part of the EPA's industry-wide investigation of compliance by coal-fired plants with the Clean Air Act NSR requirements. On
February 21, 2003, Midwest Generation received a request for information under Section 114 regarding past operations, maintenance and physical changes at the Illinois coal plants from
the EPA. On July 28, 2003, Commonwealth Edison received a

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substantially
similar request for information from the EPA related to these same plants. Other than these requests for information, no NSR enforcement-related proceedings have been initiated by the
EPA with respect to any of EME's United States facilities.

EPA's
enforcement policy on alleged NSR violations is currently uncertain. These developments will continue to be monitored by EME to assess what implications, if any, they will have on
the operation of domestic power plants owned or operated by EME or its subsidiaries, or on EME's results of operations or financial position.

Clean Water ActCooling Water Intake Structures

On February 16, 2004, the Administrator of the EPA signed the final Phase II rule implementing Section 316(b) of the Clean Water Act establishing
standards for cooling water intake structures at existing electrical generating stations that withdraw more than 50 million gallons of water per day and use more than 25% of that water for
cooling purposes. The purpose of the regulation is to substantially reduce the number of aquatic organisms that are pinned against cooling water intake structures or drawn into cooling water systems.
EME is in the process of evaluating this regulation, which could have a material impact on some of EME's United States facilities.

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.

Environmental Remediation and Asbestos

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, natural resource damages, 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

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with
the remediation of 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. Midwest Generation has accrued approximately $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 costs for environmental activity where such expenditures could be reasonably estimated. 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. In addition, future remediation costs will be
affected by the nature and extent of contamination discovered at our sites that requires remediation. Given the prior history of the operations at its facilities, EME cannot be certain that the
existence or extent of all contamination at its sites has been fully identified. However, based on available information, 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.

Federal,
state and local laws, regulations and ordinances also govern the removal, encapsulation or disturbance of asbestos-containing materials when these materials are in poor
condition or in the event of construction, remodeling, renovation or demolition of a building. Those laws and regulations may impose liability for release of asbestos-containing materials and may
provide for the ability of third parties to seek recovery from owners or operators of these properties for personal injury associated with asbestos-containing materials. In connection with the
ownership and operation of its facilities, EME may be liable for these costs. EME has agreed to indemnify the sellers of the Illinois Plants and the Homer City facilities with respect to specified
environmental liabilities. See "Guarantees and Indemnities" for a discussion of these indemnities.

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.

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. To date, none have passed through Congress. In addition, there have been several petitions from states and other parties to compel
the EPA to regulate greenhouse gases under the Clean Air Act. The EPA denied on September 3, 2003, a petition by Massachusetts, Maine and Connecticut to compel EPA under the Clean Air Act to
require EPA to establish a national ambient air quality standard for carbon dioxide. Since that time, 11 states and other entities have filed suits against EPA in the United States Court of Appeals
for the D.C.

177

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Circuit
(D.C. Circuit), and, the D.C. Circuit has granted intervention requests from 10 states that support EPA's ruling. The D.C. Circuit has not yet ruled on this matter.

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 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 United Nations 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 mid-2004.

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. Currently, the
countries ratifying the Kyoto Protocol account for 44.2% of carbon dioxide emissions. Although Russia also indicated at the Johannesburg Summit in September 2002 its desire to ratify the
treaty, it stepped back from that position in late 2003 and has yet to set a date for ratification. Representing 17.4% of the developed world's greenhouse gas emissions, Russian ratification is
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,

178

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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.

Note 18. Lease Commitments

EME leases 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, 2003, are:

Years Ending December 31,

Operating
Leases2004

$
3192005


3642006


4452007


4812008


480Thereafter


4,569Total future commitments

$
6,658


Operating lease expense amounted to $240 million, $233 million and $163 million in 2003, 2002 and 2001, 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 $142 million in 2004, $152 million in 2005,
$152 million in 2006, $151 million in 2007, and $152 million in 2008. At December 31, 2003, the total remaining minimum lease payments are $3 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 2004,
$141 million in 2005, $185 million in 2006, $185 million in 2007, and $185 million in 2008. At December 31, 2003, the total remaining minimum lease payments are
$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.

179

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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 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 $50 million in 2004, $50 million in 2005, $90 million in 2006, $129 million in 2007, and $129 million in 2008. At December 31, 2003, the total
remaining minimum lease payments were $1.3 billion. See Note 23Subsequent Event.

Note 19. 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 $63 million, $53 million and $71 million in 2003, 2002 and 2001, respectively. Accounts payableaffiliates
associated with these administrative services totaled $3 million and $12 million at December 31, 2003 and 2002, respectively.

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 $152 million, $258 million and $36 million for 2003, 2002 and 2001, respectively. See
Note 14Income Taxes. Amounts included in Accounts receivableaffiliates associated with these tax benefits totaled $18 million and $30 million at
December 31, 2003 and 2002, 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 and may also earn an incentive compensation as set forth in the agreements. EME recorded revenues under the operation and maintenance agreements of
$24 million, $22 million and $24 million in 2003, 2002 and 2001, respectively. Accounts receivableaffiliates for Edison Mission Operation & Maintenance totaled
$6 million and $7 million at December 31, 2003 and 2002, respectively.

180

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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 $754 million, $548 million and
$983 million in 2003, 2002 and 2001, respectively.

Note 20. Supplemental Statements of Cash Flows Information

Years Ended December 31,2003

2002

2001Cash paidInterest (net of amount capitalized)

$
614

$
567

$
557Income taxes (receipts)

$
(118
)
$
(462
)
$
90Cash payments under plant operating leases

$
271

$
272

$
83Details of assets acquiredFair value of assets acquired

$
336

$
16

$
898Liabilities assumed


58





801Net cash paid for acquisitions

$
278

$
16

$
97


Note 21. 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 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.

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) under bilateral arrangements with domestic utilities and power marketers pursuant to short-term transactions or to the PJM and/or NYISO, or
(3) under three power purchase agreements with Exelon Generation Company, which began December 15, 1999 and expire on December 31, 2004. EME currently derives a significant source
of its revenues from the sale of energy and capacity to Exelon Generation under these power purchase agreements. EME's revenues from Exelon Generation were $708 million in 2003 and
$1.1 billion for each 2002 and 2001. This represents 22%, 41% and 43% of EME's consolidated revenues in 2003, 2002 and 2001, respectively. Exelon Generation revenues are included in the
Americas region shown below.

181

---

The
Loy Yang B power plant and the Valley Power Peaker power plant both located in Australia sell their electrical energy through a centralized electricity pool by entering into short
and/or long-term contracts to hedge against the volatility of price fluctuations in the pool. The First Hydro power plants located in the United Kingdom sell their electrical energy and
capacity through bilateral contracts of varying terms in the England and Wales wholesale electricity market. 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 |  
|---------------------------------------------------------------------------------- | ----------------------------- | -------- | ----- | ------------ | - | ------ | ----- | ---------------- | ----- | ----- | -
|2003                                                                               |                               |          |       |              |   |        |       |                  |       |       |  
|Operating revenues from consolidated subsidiaries                                  |                               | $        | 1,605 |              | $ | 1,003  |       | $                | 528   |       | $
|Net gains (losses) from price risk management and energy trading                   |                               |          | 48    |              |   | 6      |       |                  | (10   | )     |  
|                                                                                   |                               |          |       |              |   |        |       |                  |       |       |  
|                                                                                   | Total operating revenues      |          |       | 1,653        |   |        | 1,009 |                  |       | 518   |  
|                                                                                   |                               |          |       |              |   |        |       |                  |       |       |  
|Fuel, plant operations and transmission costs, and plant operating leases          |                               |          | 1,236 |              |   | 620    |       |                  | 389   |       |  
|Depreciation and amortization                                                      |                               |          | 149   |              |   | 101    |       |                  | 34    |       |  
|Asset impairment and other charges                                                 |                               |          | 304   |              |   |       |       |                  |      |       |  
|Administrative and general                                                         |                               |          | 46    |              |   | 16     |       |                  | 14    |       |  
|                                                                                   |                               |          |       |              |   |        |       |                  |       |       |  
|                                                                                   | Income (loss) from operations |          |       | (82          | ) |        | 272   |                  |       | 81    |  
|                                                                                   |                               |          |       |              |   |        |       |                  |       |       |  
|Equity in income from unconsolidated affiliates                                    |                               |          | 258   |              |   | 66     |       |                  | 44    |       |  
|Interest and other income                                                          |                               |          | 4     |              |   | (6     | )     |                  | (3    | )     |  
|Gain on sale of assets                                                             |                               |          |      |              |   | 13     |       |                  |      |       |  
|Interest expense                                                                   |                               |          | 6     |              |   | (120   | )     |                  | (79   | )     |  
|Dividends on preferred securities                                                  |                               |          |      |              |   | (4     | )     |                  |      |       |  
|                                                                                   |                               |          |       |              |   |        |       |                  |       |       |  
|                                                                                   | Total other income (expense)  |          |       | 268          |   |        | (51   | )                |       | (38   | )
|                                                                                   |                               |          |       |              |   |        |       |                  |       |       |  
|Income (loss) from continuing operations before income taxes and minority interest |                               | $        | 186   |              | $ | 221    |       | $                | 43    |       | $
|                                                                                   |                               |          |       |              |   |        |       |                  |       |       |  
|Identifiable assets                                                                |                               | $        | 3,748 |              | $ | 4,356  |       | $                | 1,972 |       | $
|Assets of discontinued operations                                                  |                               |          |      |              |   |       |       |                  | 6     |       |  
|Equity investments and advances                                                    |                               |          | 812   |              |   | 676    |       |                  | 119   |       |  
|                                                                                   |                               |          |       |              |   |        |       |                  |       |       |  
|                                                                                   | Total assets                  |          | $     | 4,560        |   | $      | 5,032 |                  | $     | 2,097 |  
|                                                                                   |                               |          |       |              |   |        |       |                  |       |       |  
|Additions to property and plant                                                    |                               | $        | 76    |              | $ | 46     |       | $                |      |       | $
|                                                                                   |                               |          |       |              |   |        |       |                  |       |       |  

182

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|2002                                                                               |                               |   |       |       |   |       |       |   |       |       |   |      |      |   |       |       
|---------------------------------------------------------------------------------- | ----------------------------- | - | ----- | ----- | - | ----- | ----- | - | ----- | ----- | - | ---- | ---- | - | ----- | ------
|Operating revenues from consolidated subsidiaries                                  |                               | $ | 1,564 |       | $ | 707   |       | $ | 452   |       | $ |     |      | $ | 2,723 |       
|Net gains (losses) from price risk management and energy trading                   |                               |   | 39    |       |   | (1    | )     |   | (9    | )     |   | (2   | )    |   | 27    |       
|                                                                                   |                               |   |       |       |   |       |       |   |       |       |  
|                                                                                   | Total operating revenues      |   |       | 1,603 |   |       | 706   |   |       | 443   |   |      | (2   | ) |       | 2,750 
|                                                                                   |                               |   |       |       |   |       |       |   |       |       |  
|Fuel, plant operations and transmission costs, and plant operating leases          |                               |   | 1,209 |       |   | 419   |       |   | 313   |       |   | 3    |      |   | 1,944 |       
|Depreciation and amortization                                                      |                               |   | 139   |       |   | 68    |       |   | 34    |       |   | 7    |      |   | 248   |       
|Long-term incentive compensation                                                   |                               |   |      |       |   |      |       |   |      |       |   | 2    |      |   | 2     |       
|Settlement of postretirement employee benefit liability                            |                               |   | (71   | )     |   |      |       |   |      |       |   |     |      |   | (71   | )     
|Asset impairment and other charges                                                 |                               |   | 131   |       |   |      |       |   |      |       |   |     |      |   | 131   |       
|Administrative and general                                                         |                               |   | 46    |       |   | 17    |       |   | 17    |       |   | 87   |      |   | 167   |       
|                                                                                   |                               |   |       |       |   |       |       |   |       |       |  
|                                                                                   | Income (loss) from operations |   |       | 149   |   |       | 202   |   |       | 79    |   |      | (101 | ) |       | 329   
|                                                                                   |                               |   |       |       |   |       |       |   |       |       |  
|Equity in income from unconsolidated affiliates                                    |                               |   | 207   |       |   | 36    |       |   | 40    |       |   |     |      |   | 283   |       
|Interest and other income                                                          |                               |   | 7     |       |   | 2     |       |   |      |       |   | 16   |      |   | 25    |       
|Gain on sale of assets                                                             |                               |   |      |       |   |      |       |   | 5     |       |   |     |      |   | 5     |       
|Interest expense                                                                   |                               |   | 16    |       |   | (92   | )     |   | (74   | )     |   | (461 | )    |   | (611  | )     
|Dividends on preferred securities                                                  |                               |   |      |       |   | (7    | )     |   |      |       |   | (14  | )    |   | (21   | )     
|                                                                                   |                               |   |       |       |   |       |       |   |       |       |  
|                                                                                   | Total other income (expense)  |   |       | 230   |   |       | (61   | ) |       | (29   | ) |      | (459 | ) |       | (319  
|                                                                                   |                               |   |       |       |   |       |       |   |       |       |  
|Income (loss) from continuing operations before income taxes and minority interest |                               | $ | 379   |       | $ | 141   |       | $ | 50    |       | $ | (560 | )    | $ | 10    |       
|                                                                                   |                               |   |       |       |   |       |       |   |       |       |  
|Identifiable assets                                                                |                               | $ | 4,233 |       | $ | 2,992 |       | $ | 2,038 |       | $ | 449  |      | $ | 9,712 |       
|Assets of discontinued operations                                                  |                               |   |      |       |   |      |       |   | 10    |       |   |     |      |   | 10    |       
|Equity investments and advances                                                    |                               |   | 950   |       |   | 580   |       |   | 115   |       |   |     |      |   | 1,645 |       
|                                                                                   |                               |   |       |       |   |       |       |   |       |       |  
|                                                                                   | Total assets                  |   | $     | 5,183 |   | $     | 3,572 |   | $     | 2,163 |   | $    | 449  |   | $     | 11,367
|                                                                                   |                               |   |       |       |   |       |       |   |       |       |  
|Additions to property and plant                                                    |                               | $ | 493   |       | $ | 56    |       | $ | 2     |       | $ | 3    |      | $ | 554   |       
|                                                                                   |                               |   |       |       |   |       |       |   |       |       |   |      |      |   |       |       

183

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|2001                                                                               |                               |   |       |       |   |       |       |   |       |       |   |      |      |   |       |       
|---------------------------------------------------------------------------------- | ----------------------------- | - | ----- | ----- | - | ----- | ----- | - | ----- | ----- | - | ---- | ---- | - | ----- | ------
|Operating revenues from consolidated subsidiaries                                  |                               | $ | 1,617 |       | $ | 464   |       | $ | 369   |       | $ | 3    |      | $ | 2,453 |       
|Net gains (losses) from price risk management and energy trading                   |                               |   | 35    |       |   | (4    | )     |   | 3     |       |   | 2    |      |   | 36    |       
|                                                                                   |                               |   |       |       |   |       |       |   |       |       |  
|                                                                                   | Total operating revenues      |   |       | 1,652 |   |       | 460   |   |       | 372   |   |      | 5    |   |       | 2,489 
|                                                                                   |                               |   |       |       |   |       |       |   |       |       |  
|Fuel, plant operations and transmission costs, and plant operating leases          |                               |   | 1,166 |       |   | 266   |       |   | 250   |       |   |     |      |   | 1,682 |       
|Depreciation and amortization                                                      |                               |   | 166   |       |   | 54    |       |   | 35    |       |   | 8    |      |   | 263   |       
|Long-term incentive compensation                                                   |                               |   |      |       |   |      |       |   |      |       |   | 6    |      |   | 6     |       
|Asset impairment and other charges                                                 |                               |   | 59    |       |   |      |       |   |      |       |   |     |      |   | 59    |       
|Administrative and general                                                         |                               |   | 46    |       |   | 12    |       |   | 15    |       |   | 101  |      |   | 174   |       
|                                                                                   |                               |   |       |       |   |       |       |   |       |       |  
|                                                                                   | Income (loss) from operations |   |       | 215   |   |       | 128   |   |       | 72    |   |      | (110 | ) |       | 305   
|                                                                                   |                               |   |       |       |   |       |       |   |       |       |  
|Equity in income from unconsolidated affiliates                                    |                               |   | 351   |       |   | 8     |       |   | 15    |       |   |     |      |   | 374   |       
|Interest and other income                                                          |                               |   | 8     |       |   |      |       |   | 7     |       |   | 24   |      |   | 39    |       
|Gain on sale of assets                                                             |                               |   | 43    |       |   | (2    | )     |   |      |       |   |     |      |   | 41    |       
|Gain on early extinguishment of debt                                               |                               |   | 10    |       |   |      |       |   |      |       |   |     |      |   | 10    |       
|Interest expense                                                                   |                               |   | (70   | )     |   | (73   | )     |   | (74   | )     |   | (407 | )    |   | (624  | )     
|Dividends on preferred securities                                                  |                               |   |      |       |   | (8    | )     |   |      |       |   | (14  | )    |   | (22   | )     
|                                                                                   |                               |   |       |       |   |       |       |   |       |       |  
|                                                                                   | Total other income (expense)  |   |       | 342   |   |       | (75   | ) |       | (52   | ) |      | (397 | ) |       | (182  
|                                                                                   |                               |   |       |       |   |       |       |   |       |       |  
|Income (loss) from continuing operations before income taxes and minority interest |                               | $ | 557   |       | $ | 53    |       | $ | 20    |       | $ | (507 | )    | $ | 123   |       
|                                                                                   |                               |   |       |       |   |       |       |   |       |       |  
|Identifiable assets                                                                |                               | $ | 3,742 |       | $ | 2,511 |       | $ | 1,759 |       | $ | 947  |      | $ | 8,959 |       
|Assets of discontinued operations                                                  |                               |   |      |       |   |      |       |   | 319   |       |   |     |      |   | 319   |       
|Equity investments and advances                                                    |                               |   | 1,166 |       |   | 563   |       |   | 101   |       |   |     |      |   | 1,830 |       
|                                                                                   |                               |   |       |       |   |       |       |   |       |       |  
|                                                                                   | Total assets                  |   | $     | 4,908 |   | $     | 3,074 |   | $     | 2,179 |   | $    | 947  |   | $     | 11,108
|                                                                                   |                               |   |       |       |   |       |       |   |       |       |  
|Additions to property and plant                                                    |                               | $ | 142   |       | $ | 67    |       | $ | 13    |       | $ | 20   |      | $ | 242   |       

Geographic Information

Foreign operating revenues and assets by country included in the table above are shown below.

Years Ended December 31,2003

2002

2001Operating revenuesAustralia

$
253

$
213

$
166New Zealand


756


493


294Total Asia Pacific

$
1,009

$
706

$
460United Kingdom

$
371

$
317

$
236Turkey


124


111


118Spain


23


15


18Total Europe

$
518

$
443

$
372


184

---

December 31,2003

2002

2001AssetsAustralia

$
1,687

$
1,264

$
1,152New Zealand


2,640


1,738


1,333Indonesia


601


550


535Other Asia Pacific


104


20


54Total Asia Pacific

$
5,032

$
3,572

$
3,074United Kingdom(1)

$
1,630

$
1,690

$
1,680Turkey


188


217


259Spain


145


117


136Italy


66


65


64Other Europe


68


74


40Total Europe

$
2,097

$
2,163

$
2,179


---

Note 22. Quarterly Financial Data (unaudited)

First(i)

Second

Third(i)

Fourth(i)

Total2003Operating revenues

$
683

$
715

$
1,014

$
769

$
3,181Operating income (loss)


35


(200
)(ii)

303


24


162Income (loss) from continuing operations before accounting change


(32
)

(188
)(ii)

176


(27
)

(71
)Discontinued operations, net





(3
)




4


1Net income (loss)


(41
)

(191
)

176


(23
)

(79
)First(i)

Second

Third(i)

Fourth(i)

Total2002Operating revenues

$
537

$
673

$
954

$
586

$
2,750Operating income (loss)


(13
)

73


251


18


329Income (loss) from continuing operations before accounting change


(63
)

(29
)

132


(37
)

3Discontinued operations, net


5


9


7


(78
)(iii)

(57
)Net income (loss)


(72
)

(20
)

139


(115
)(iii)

(68
)


---

Note 23. Subsequent Event

On March 10, 2004, Midwest Generation agreed in principle with the lease equity investor to terminate the Collins Station lease. The agreement in principle
sets forth specified conditions required

185

---

for
the termination, including Midwest Generation successfully borrowing funds to finance the repayment of Collins Station lease debt of $774 million and settlement of Midwest Generation's
termination liability with the lease equity investor. There is no assurance that the agreement in principle will result in termination of the Collins Station lease. If the termination occurs, Midwest
Generation will take title to the Collins Station and, subject to its contractual obligation to Exelon Generation, plans to subsequently abandon the Collins Station or sell it to a third party.

If
Midwest Generation completes the lease termination and subsequently abandons the Collins Station, EME expects to record a pretax loss of approximately $1 billion (approximately
$620 million after tax). This loss will reduce EME's net worth (using December 31, 2003) from $1.9 billion to approximately $1.3 billion. To avoid the possibility of
covenant defaults which could arise from a decline in net worth, EME plans to take the following actions before or simultaneously with the Collins Station lease termination:



If
Midwest Generation completes the termination of the Collins Station lease followed by abandonment or sale to a third party, EME anticipates that the termination payment would result
in a substantial income tax deduction. Because of these arrangements, EME does not expect that termination of the Collins Station lease will have a material adverse effect on its liquidity. If the
lease termination does not occur, the terms of the lease will remain in effect and Midwest Generation will seek to restructure the lease with the lease equity investor.

186

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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 11, 2004.

|Name, Position and Age                                                      |  | Director
Continuously
Since |  | Term
Expires |  | Position Held
Continuously
Since |  | Term
Expires
|--------------------------------------------------------------------------- |  | --------------------------- |  | ------------ |  | -------------------------------- |  | ------------
|John E. Bryson, 60
Director, Chairman of the Board                          |  | 2001                        |  | 2004         |  |                                 |  |            
|Frank B. Bilotta, 43
Director                                               |  | 2001                        |  | 2004         |  |                                 |  |            
|Bryant C. Danner, 66
Director                                               |  | 2001                        |  | 2004         |  |                                 |  |            
|Theodore F. Craver, Jr., 52
Director, Chief Executive Officer and President |  | 2001                        |  | 2004         |  | 2001                             |  | 2004        
|Barbara Mathews, 51
Secretary and Assistant General Counsel                 |  |                            |  |             |  | 2001                             |  | 2004        
|Kevin M. Smith, 45
Senior Vice President and Chief Financial Officer        |  |                            |  |             |  | 2001                             |  | 2004        
|Raymond W. Vickers, 61
Senior Vice President and General Counsel            |  |                            |  |             |  | 2001                             |  | 2004        

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

187

---

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.

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.

Audit Committee Financial Expert

The board of directors has determined that Mission Energy Holding Company has at least one audit committee financial expert (as defined in rules of the Securities
and Exchange Commission) serving on its audit committee. The name of the audit committee financial expert is Theodore F. Craver, Jr., who is not an independent director.

Code of Ethics for Senior Financial Officers

Mission Energy Holding Company has adopted a code of business conduct and ethics that applies to its principal executive officer, principal financial officer,
principal accounting officer or controller, or persons performing similar functions. The code of business conduct and ethics is posted under the heading "Corporate Governance" on the Internet website
maintained by Mission Energy Holding Company's parent at www.edisoninvestor.com. Any amendment to or waiver from a provision of the code of business conduct and ethics that must be disclosed under
rules and forms of the Securities and Exchange Commission will be disclosed at the same Internet website address within five business days following the date of the amendment or waiver.

188

---

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, 2003 and the Summary Compensation Table in the Executive Compensation section of Edison International's Proxy Statement relating to its 2004 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 2003, Mr. Bilotta received an annual fee of $3,500 for providing independent directorship services.

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 |  | Edison Mission Group Inc.
2244 Walnut Grove Avenue
Rosemead, California 91770 |  | 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, 2003 and the table entitled "Stock Ownership of
Directors and Executive Officers" of Edison International's Proxy Statement relating to its 2004 Annual Meeting of Shareholders, respectively, which are incorporated by reference.

ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS

Other Management Transactions

In July 1999, EME made an interest-free loan to Georgia R. Nelson, who at that time was Senior Vice President and President of Midwest Generation
EME, LLC, 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. The entire
note was paid in full in July 2003.

189

---

ITEM 14. PRINCIPAL ACCOUNTING FEES AND SERVICES

INDEPENDENT ACCOUNTANT FEES

The following table sets forth the aggregate fees billed to Mission Energy Holding Company (consolidated total including Mission Energy Holding Company and its
subsidiaries), for the fiscal years ended December 31, 2003 and December 31, 2002, by PricewaterhouseCoopers LLP and Arthur Andersen LLP:

|                       |                        | Year |           | Mission Energy Holding
Company and Subsidiaries
($000)
|---------------------- | ---------------------- | ---- | --------- | ------------------------------------------------------
|Audit Fees:(1)         |                        |      |           |                                                       
|                       | PricewaterhouseCoopers |      | 2003
2002 |                                                       
|                       | Arthur Andersen        |      | 2002      |                                                       
|Audit Related Fees:(2) |                        |      |           |                                                       
|                       | PricewaterhouseCoopers |      | 2003
2002 |                                                       
|                       | Arthur Andersen        |      | 2002      |                                                       
|Tax Fees:(3)           |                        |      |           |                                                       
|                       | PricewaterhouseCoopers |      | 2003
2002 |                                                       
|                       | Arthur Andersen        |      | 2002      |                                                       
|All Other Fees:        |                        |      |           |                                                       
|                       | PricewaterhouseCoopers |      | 2003
2002 |                                                       
|                       | Arthur Andersen        |      | 2002      |                                                       

---

The Edison International Audit Committee reviews with management and pre-approves all audit services to be performed by the
independent accountants and all non-audit services that are not prohibited and that require pre-approval under the Securities Exchange Act. The Edison International Audit
Committee's pre-approval responsibilities may be delegated to one or more Edison International Audit Committee members, provided that such delegate(s) presents any pre-approval
decisions to the Edison International Audit Committee at its next meeting. The independent auditors must assure that all audit and non-audit services provided to Mission Energy Holding
Company and its subsidiaries have been approved by the Edison International Audit Committee. During the fiscal year ended December 31, 2003, all services performed by the independent
accountants were pre-approved by the Edison International Audit Committee, regardless of whether the services required pre-approval under the Securities Exchange Act.

190

---



PART IV

ITEM 15. EXHIBITS, FINANCIAL STATEMENT SCHEDULES AND REPORTS ON FORM 8-K



PageInvestment in Unconsolidated Affiliates Financial Statements:California Power Group Combined Financial Statements as of December 31, 2003, 2002 and 2001

204Watson Cogeneration Company Financial Statements as of December 31, 2003, 2002 and 2001

221Four Star Oil & Gas Company Consolidated Financial Statements as of December 31, 2003, 2002 and 2001

231Midway-Sunset Cogeneration Company Financial Statements as of December 31, 2003, 2002 and 2001

248March Point Cogeneration Company Financial Statements as of December 31, 2003, 2002 and 2001

261EcoEléctrica Holdings, Ltd. and Subsidiaries Consolidated Financial Statements as of December 31, 2003, 2002 and 2001

274Gordonsville Energy, L.P. Financial Statements as of December 31, 2003, 2002 and 2001

293Brooklyn Navy Yard Cogeneration Partners, L.P. Financial Statements as of December 31, 2003, 2002 and 2001

305PT Paiton Energy Financial Statements as of December 31, 2003, 2002 and 2001

320Schedule ICondensed Financial Information of Parent

349Schedule IIValuation and Qualifying Accounts

352




191

---



Date of Report

Date Filed

Item(s) ReportedOctober 1, 2003

October 2, 2003

5October 28, 2003

October 29, 2003

5November 5, 2003

November 5, 2003

12
*December 11, 2003

December 12, 2003

5, 7


---

|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.                                                                                                                                                                                                                                                                                                                           
|2.7         |  | 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 Form 10-Q for the quarter
ended September 30, 2000.                                                                                                                                                                                                                                                                                                                                                                                            
|2.8         |  | Asset Purchase Agreement dated March 3, 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.                                                                                                                                                                                                                                                                                                                                                                                                                             
|            |  |                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                        

192

---

|2.9  |  | 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.                                                                                                                                                                                                                                                                                                  
|---- |  | ----------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
|2.10 |  | 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.                                                                                                  
|2.11 |  | 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, dated as of October 18, 2002.*                                                                                                                                                                                                                                                                                                                                                                                                                                             
|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 $800 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.
|     |  |                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                       

193

---

|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.                     
|------ |  | -------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
|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 4.2 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.                                                                                                                                                                 
|       |  |                                                                                                                                                                                                                                                                                                                                                                                                                                                                          

194

---

|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.                                                                                                                                                                                                                                                                                                                  
|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 Exhibit 4.12 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.                                                                                                                                                                                                                                                                                                            
|       |  |                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                            

195

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|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.                                                                                                                                                                                 
|------ |  | ------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
|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.                                                                                                                                                                                                     
|4.19   |  | 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.                                                                                                                                                                                                                                   
|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.                                                                                                                                                                                                                                                                                                               
|4.21   |  | 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.
|4.21.1 |  | 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.                                                                                                                                                                                                                                                                                           
|4.22   |  | 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.                                                                                                                                                                                                             
|4.22.1 |  | Schedule identifying substantially identical agreements to Open-End Mortgage, Security Agreement and Assignment of Rents constituting Exhibit 4.22 hereto, incorporated by reference to Exhibit 4.9.1 to the EME Homer City Generation L.P. Form 10-K for
the year ended December 31, 2003.                                                                                                                                                                                                                                                     
|       |  |                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                 

196

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|10.1   |  | 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 Registration Statement on Form 10 to the Securities and Exchange Commission on September 30, 1994 and amended by Amendment No. 1 thereto dated November 19, 1994 and Amendment No. 2 thereto dated
November 21, 1994 (as so amended, the "Form 10").
|------ |  | ---------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
|10.2   |  | 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.                                                                                                                                                                                                                                                                                                                               
|10.2.1 |  | 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.                                                                                                                                                                                            
|10.3   |  | 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.                                                                                                                                                                                                                                                                                                                                                                                                  
|10.4   |  | 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.                                                                                                                                                                                                                                                                                                                        
|10.5   |  | 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.                                                                                                                                                                                                                                                                     
|10.6   |  | 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.                                                                                                                                                                                                                                                                        
|10.7   |  | 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.                                                                                                                                                            
|10.8   |  | 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.                                                                                                                                                                                                                                                                                     
|10.9   |  | 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.                                                                                                                                                                                                                                                                 
|10.10  |  | Amended and Restated Guarantee and Collateral Agreement, dated as of December 7, 2001, made by EME Homer City Generation L.P. in favor of The Bank of New York as successor to United States Trust Company of New York, as Collateral Agent, incorporated
by reference to Exhibit 10.16.4 to EME Homer City Generation L.P.'s Form 10-K for the year ended December 31, 2001.                                                                                                                                                                            
|       |  |                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                          

197

---

|10.11   |  | 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.                                                                                                                                                                                                         
|------- |  | -------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
|10.12   |  | 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.
|10.13   |  | 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.                                                                                                                                                       
|10.13.1 |  | 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.                                                                                                                                                                                                         
|10.14   |  | 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.                                                                                                                                          
|10.14.1 |  | 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.                                                                                                                                                                                                                                                                  
|10.14.2 |  | 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.                                                                                                                                                                                                                                                                      
|10.15   |  | 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.                                                                                                                                          
|10.16   |  | 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.                                                                                                                                                                             
|10.17   |  | 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.                                                                                                                                                                                                                                 
|        |  |                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                              

198

---

|10.17.1 |  | 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.                                                                                                                                        
|------- |  | ------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
|10.17.2 |  | 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.                                                                                                  
|10.18   |  | 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.                                             
|10.19   |  | 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.                                                                                                                                                                
|10.20   |  | 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.
|10.20.1 |  | 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.                                                                            
|10.20.2 |  | 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.                                                                           
|10.21   |  | Credit Agreement, dated December 11, 2003, among Mission Energy Holdings International, Inc., Initial Lenders and Citicorp North America, Inc. as Administrative Agent, incorporated by reference to Exhibit 10.21 to Edison Mission Energy's Form 10-K
for the year ended December 31, 2003.                                                                                                         
|10.22** |  | Executive Supplemental Benefit Program as amended January 30, 1990, incorporated by reference to Exhibit 10.2 Edison International's Form 10-Q for the quarter ended September 30, 1999 (File No. 1-9936).                                                                                                                                                                                            
|10.23** |  | Executive Disability and Survivor Benefit Program effective January 1, 1994, incorporated by reference to Exhibit 10.22 to Edison International's Form 10-K for the year ended December 31, 1994 (File No. 1-9936).                                                                                                                                                                                   
|10.24** |  | Terms and conditions for 1993-1995 long-term compensation awards under the Officer Long-Term Incentive Compensation Plan, incorporated by reference to Exhibit 10.21.1 to Edison International's Form 10-K for the year ended December 31, 1995 (File No.
1-9936).                                                                                                                                    
|10.25** |  | Executive Grantor Trust Agreement dated August 1995, 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).                                                                                                                                                                                                           
|        |  |                                                                                                                                                                                                                                                                                                                                                                                                       

199

---

|10.25.1** |  | 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).                                             
|--------- |  | -------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
|10.26**   |  | Executive Deferred Compensation Plan as amended and restated January 1, 1998, incorporated by reference to Exhibit 10.2 to Edison International's Form 10-Q for the quarter ended March 31, 1998 (File No. 1-9936).                                          
|10.26.1** |  | Executive Deferred Compensation Plan Amendment No. 1 effective January 1, 2003, incorporated by reference to Exhibit 10.2 to Edison International's Form 10-Q for the quarter ended March 31, 1998 (File No. 1-9936).                                        
|10.27**   |  | Executive Retirement Plan as restated April 1, 1999, incorporated by reference to Exhibit 10.1 to Edison International's Form 10-Q for the quarter ended September 30, 1999 (File No. 1-9936).                                                               
|10.27.1** |  | 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).                                                                            
|10.27.2** |  | Executive Retirement Plan Amendment 2002-1 effective January 1, 2003, incorporated by reference to Exhibit 10.10.2 to Edison International's Form 10-K for the year ended December 31, 2002 (File No. 1-9936).                                               
|10.28**   |  | Estate and Financial Planning Program as amended April 23, 1999, incorporated by reference to Exhibit to Form 10-Q filed by Edison International for the quarter ended June 30, 1999 (File No 1-9936).                                                       
|10.29**   |  | Executive Incentive Compensation Plan effective January 1, 1997, incorporated by reference to Exhibit 10.12 to Edison International's Form 10-K for the year ended December 31, 1997 (File No. 1-9936).                                                      
|10.30**   |  | Officer Long-Term Incentive Compensation Plan as amended January 1, 1998, incorporated by reference to Exhibit 10.3 to Edison International's Form 10-Q for the quarter ended March 31, 1998 (File No. 1-9936).                                              
|10.31**   |  | Equity Compensation Plan as restated effective January 1, 1998, incorporated by reference to Exhibit 10.1 to Edison International's Form 10-Q for the quarter ended June 30, 1998 (File No. 1-9936).                                                         
|10.31.1** |  | Equity Compensation Plan Amendment No. 1 effective May 18, 2000, incorporated by reference to Exhibit 10.3 to Edison International's Form 10-Q for the quarter ended June 30, 2000 (File No. 1-9936).                                                        
|10.32**   |  | Option Gain Deferral Plan as restated September 15, 2000, incorporated by reference to Exhibit 10.25 to Edison International's Form 10-K for the year ended December 31, 2000 (File No. 1-9936).                                                             
|10.33**   |  | Terms and conditions for 1996 long-term compensation awards under the Officer Long-Term Incentive Compensation Plan, incorporated by reference to Exhibit 10.16.2 to Edison International's Form 10-K for the year ended December 31, 1996 (File No.
1-9936).
|10.34**   |  | Terms and conditions for 1997 long-term compensation awards under the Officer Long-Term Incentive Compensation Plan, incorporated by reference to Exhibit 10.16.3 to Edison International's Form 10-K for the year ended December 31, 1997 (File No.
1-9936).
|          |  |                                                                                                                                                                                                                                                              

200

---

|10.35** |  | Terms and conditions for 1998 long-term compensation awards under the Equity Compensation Plan, incorporated by reference to Exhibit 10.4 to Edison International's Form 10-Q for the quarter ended June 30, 1998 (File No. 1-9936).                              
|------- |  | ------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
|10.36** |  | Terms and conditions for 1999 long-term compensation awards under the Equity Compensation Plan, incorporated by reference to Exhibit 10.1 to Edison International's Form 10-Q for the quarter ended March 31, 1999 (File No. 1-9936).                             
|10.37** |  | Terms and conditions for 2000 basic long-term incentive compensation awards under the Equity Compensation Plan, as restated, incorporated by reference to Exhibit 10.2 to Edison International's Form 10-Q for the quarter ended March 31, 2000 (File No.
1-9936).
|10.38** |  | 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.                                                              
|10.39** |  | Terms and conditions for 2000 special stock option awards under the Equity Compensation Plan and 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).           
|10.40** |  | 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).   
|10.41** |  | Edison International 2000 Equity Plan, effective May 18, 2000, 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).                                                               
|10.42** |  | Option Gain Deferral Plan as restated September 15, 2000, incorporated by reference to Exhibit 10.27 to Edison International's Form 10-K for the year ended December 31, 2000 (File No. 1-9936).                                                                  
|10.43** |  | 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).                  
|10.44** |  | 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).                
|10.45** |  | 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).                                                      
|10.46** |  | 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).         
|10.47** |  | Terms of 2003 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, 2003 (File No.
1-9936).         
|10.48** |  | 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.                                                                    
|        |  |                                                                                                                                                                                                                                                                   

201

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|10.49** |  | 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.                                                    
|------- |  | ----------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
|10.50** |  | Terms and conditions for 2001 exchange offer deferred stock units under the Equity Compensation Plan, incorporated by reference to Attachment C of Exhibit (a)(1) to Edison International's Schedule TO-I dated October 26, 2001 (File No.
1-9936).                                           
|10.51** |  | 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).                                                                                         
|10.52** |  | 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.                                                           
|10.53** |  | 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).                                                                                                        
|10.54** |  | 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.                                                                    
|10.55** |  | Appendix A to the Edison International Affiliate Option Deferred Compensation Plan effective August 7, 2000, applicable to Edison Mission Energy employees in Singapore, incorporated by reference to Exhibit 10.55 to Edison Mission Energy's Form 10-K
for the year ended December 31, 2003.
|10.56   |  | Tax Allocation Agreement, dated July 2, 2001, by and between Mission Energy Holding Company and Edison Mission Energy, incorporated by reference to Exhibit 10.106 to Edison Mission Energy's Form 10-Q for the quarter ended September 30,
2002.                                             
|10.57   |  | 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.                                        
|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.*                                                                                                                                                                                                                                      
|31.1    |  | Certification of the Chief Executive Officer pursuant to Section 302 of the Sarbanes-Oxley Act.*                                                                                                                                                                                              
|31.2    |  | Certification of the Chief Financial Officer pursuant to Section 302 of the Sarbanes-Oxley Act.*                                                                                                                                                                                              
|32      |  | Statement Pursuant to 18 U.S.C. Section 1350.*                                                                                                                                                                                                                                                
|99.1    |  | Homer City Facilities Funds Flow From Operations for the twelve months ended December 31, 2003, incorporated by reference to Exhibit 99.1 to Edison Mission Energy's Form 10-K for the year ended December 31, 2003.                                                                          
|        |  |                                                                                                                                                                                                                                                                                               

202

---

|99.2 |  | Illinois Plants Funds Flow From Operations for the twelve months ended December 31, 2003, incorporated by reference to Exhibit 99.2 to Edison Mission Energy's Form 10-K for the year ended December 31, 2003.
|---- |  | --------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------

---

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 meet 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, 2003 pursuant to
Rule 3-09 of Regulation S-X.

203

---



Report of Independent Auditors

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 comprehensive 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, Sunrise Power Company, LLC, and Mission de las Estrellas, LLC (together, the California Power Group) at December 31, 2003 and 2002,
and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2003 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, the California Power Group changed the manner in which it accounts for asset retirement costs as of January 1, 2003.

PricewaterhouseCoopers
LLP

Los
Angeles, California
February 26, 2004

204

---



CALIFORNIA POWER GROUP  COMBINED BALANCE SHEETS  December 31, 2003 and 2002  (Amounts in thousands)

|                                                        |                                                    | 2003            |         | 2002  
|------------------------------------------------------- | -------------------------------------------------- | --------------- | ------- | ------
|Assets                                                  |                                                    |                 |         |       
|Current assets                                          |                                                    |                 |         |       
|                                                        | Cash and cash equivalents                          |                 | $       | 33,801
|                                                        | Restricted cash                                    |                 |         | 28,089
|                                                        | Trade receivables                                  |                 |         |       
|                                                        |                                                    | Related party   |         |       
|                                                        |                                                    | Other           |         |       
|                                                        | Inventories                                        |                 |         | 21,457
|                                                        | Fair value of gas swaps                            |                 |         | 12,190
|                                                        | Prepaid and other current assets                   |                 |         | 1,963 
|                                                        |                                                    |                 |         |       
|                                                        |                                                    |                 | 186,585 |       
|                                                        |                                                    |                 |         |       
|Property, plant and equipment, net                      |                                                    |                 | 627,020 |       
|                                                        |                                                    |                 |         |       
|Other assets                                            |                                                    |                 |         |       
|                                                        | Restricted cash                                    |                 |         | 30,404
|                                                        | Fair value of gas swaps, net of current portion    |                 |         | 10,651
|                                                        | Deferred financing costs, net                      |                 |         | 6,770 
|                                                        | Water entitlement, net                             |                 |         | 6,403 
|                                                        | Note receivable, net of current portion            |                 |         | 3,556 
|                                                        | Emission credits, net                              |                 |         | 2,664 
|                                                        |                                                    |                 |         |       
|                                                        |                                                    |                 | 60,448  |       
|                                                        |                                                    |                 |         |       
|                                                        |                                                    | $               | 874,053 |       
|                                                        |                                                    |                 |         |       
|Liabilities and Equity                                  |                                                    |                 |         |       
|Current liabilities                                     |                                                    |                 |         |       
|                                                        | Current portion of project financing loans payable |                 | $       | 33,338
|                                                        | Accounts payable                                   |                 |         |       
|                                                        |                                                    | Related party   |         |       
|                                                        |                                                    | Trade and other |         |       
|                                                        |                                                    |                 |         |       
|                                                        |                                                    |                 | 115,948 |       
|Project financing loans payable, net of current portion |                                                    |                 | 294,067 |       
|Long-term liabilities                                   |                                                    |                 | 235     |       
|Asset retirement obligation                             |                                                    |                 | 15,355  |       
|                                                        |                                                    |                 |         |       
|                                                        |                                                    |                 | 425,605 |       
|Commitments and contingencies (Notes 7 and 8)           |                                                    |                 |         |       
|Equity                                                  |                                                    |                 | 448,448 |       
|                                                        |                                                    |                 |         |       
|                                                        |                                                    | $               | 874,053 |       
|                                                        |                                                    |                 |         |       

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

205

---

CALIFORNIA POWER GROUP  COMBINED STATEMENTS OF COMPREHENSIVE INCOME  Years Ended December 31, 2003, 2002 and 2001  (Amounts in thousands)

|                                                                              |                                                    | 2003 |         | 2002    |   | 2001    |        
|----------------------------------------------------------------------------- | -------------------------------------------------- | ---- | ------- | ------- | - | ------- | -------
|Operating revenues                                                            |                                                    |      |         |         |   |         |        
|                                                                              | Sales of energy                                    |      | $       | 618,350 |   | $       | 441,321
|                                                                              | Sales of steam                                     |      |         | 160,715 |   |         | 113,823
|                                                                              |                                                    |      |         |         |   |         |        
|                                                                              |                                                    |      | 779,065 |         |   | 555,144 |        
|                                                                              |                                                    |      |         |         |   |         |        
|Operating expenses                                                            |                                                    |      |         |         |   |         |        
|                                                                              | Fuel expense                                       |      |         | 417,723 |   |         | 245,011
|                                                                              | Other operating expenses                           |      |         | 42,290  |   |         | 70,685 
|                                                                              | Administration and general expenses                |      |         | 11,101  |   |         | 11,817 
|                                                                              | Depreciation, amortization and accretion           |      |         | 29,002  |   |         | 22,884 
|                                                                              |                                                    |      |         |         |   |         |        
|                                                                              |                                                    |      | 500,116 |         |   | 350,397 |        
|                                                                              |                                                    |      |         |         |   |         |        
|                                                                              | Income from operations                             |      |         | 278,949 |   |         | 204,747
|                                                                              |                                                    |      |         |         |   |         |        
|Other income (expense)                                                        |                                                    |      |         |         |   |         |        
|                                                                              | Interest and other income                          |      |         | 707     |   |         | 6,097  
|                                                                              | Interest expense                                   |      |         | (7,118  | ) |         | (520   
|                                                                              |                                                    |      |         |         |   |         |        
|                                                                              |                                                    |      | (6,411  | )       |   | 5,577   |        
|                                                                              |                                                    |      |         |         |   |         |        
|Income before change in accounting principle                                  |                                                    |      | 272,538 |         |   | 210,324 |        
|                                                                              |                                                    |      |         |         |   |         |        
|Cumulative effect of change in accounting for asset retirement costs (Note 2) |                                                    |      | (9,156  | )       |   |        |        
|                                                                              |                                                    |      |         |         |   |         |        
|Net income                                                                    |                                                    |      | 263,382 |         |   | 210,324 |        
|                                                                              |                                                    |      |         |         |   |         |        
|Other comprehensive income                                                    |                                                    |      |         |         |   |         |        
|                                                                              | Unrealized holding gain arising during the period  |      |         | 7,072   |   |         |       
|                                                                              | Reclassification adjustment included in net income |      |         | 8,038   |   |         |       
|                                                                              |                                                    |      |         |         |   |         |        
|                                                                              |                                                    |      | 15,110  |         |   |        |        
|                                                                              |                                                    |      |         |         |   |         |        
|Comprehensive income                                                          |                                                    | $    | 278,492 |         | $ | 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  Years Ended December 31, 2003, 2002 and 2001  (Amounts in thousands)

|                                     |                                                                              | 2003                                                |                             | 2002     |        | 2001    |         
|------------------------------------ | ---------------------------------------------------------------------------- | --------------------------------------------------- | --------------------------- | -------- | ------ | ------- | --------
|Cash flows from operating activities |                                                                              |                                                     |                             |          |        |         |         
|                                     | Net income                                                                   |                                                     | $                           | 263,382  |        | $       | 210,324 
|                                     | Adjustments to reconcile net income to cash provided by operating activities |                                                     |                             |          |        |         |         
|                                     |                                                                              | Cumulative effect of change in accounting principle |                             |          | 9,156  |         |         
|                                     |                                                                              | Unrealized loss (gain) on derivative instruments    |                             |          | 7,564  |         |         
|                                     |                                                                              | Depreciation, amortization and accretion            |                             |          | 29,002 |         |         
|                                     |                                                                              | Changes in assets and liabilities:                  |                             |          |        |         |         
|                                     |                                                                              |                                                     | Changes in restricted cash  |          |        | (57,948 | )       
|                                     |                                                                              |                                                     | Trade and other receivables |          |        | (11,226 | )       
|                                     |                                                                              |                                                     | Inventories                 |          |        | (1,077  | )       
|                                     |                                                                              |                                                     | Prepaid and other assets    |          |        | (1,039  | )       
|                                     |                                                                              |                                                     | Other assets                |          |        | (8,401  | )       
|                                     |                                                                              |                                                     | Accounts payable            |          |        | 13,786  |         
|                                     |                                                                              |                                                     | Unearned revenue            |          |        |        |         
|                                     |                                                                              |                                                     | Long-term liabilities       |          |        | (134    | )       
|                                     |                                                                              |                                                     |                             |          |        |         |         
|                                     | Cash provided by operating activities                                        |                                                     |                             | 243,065  |        |         | 421,372 
|                                     |                                                                              |                                                     |                             |          |        |         |         
|Cash flows from investing activities |                                                                              |                                                     |                             |          |        |         |         
|                                     | Capital expenditures, net                                                    |                                                     |                             | (95,939  | )      |         | (109,554
|                                     |                                                                              |                                                     |                             |          |        |         |         
|Cash flows from financing activities |                                                                              |                                                     |                             |          |        |         |         
|                                     | Proceeds from issuance of long term debt                                     |                                                     |                             | 345,000  |        |         |        
|                                     | Loan repayments                                                              |                                                     |                             | (27,495  | )      |         | (10,100 
|                                     | Debt issuance costs                                                          |                                                     |                             | (7,053   | )      |         |        
|                                     | Issuance of note receivable, net                                             |                                                     |                             | (3,822   | )      |         |        
|                                     | Contributions from partners                                                  |                                                     |                             | 93,984   |        |         | 67,850  
|                                     | Distributions to partners                                                    |                                                     |                             | (550,430 | )      |         | (408,200
|                                     |                                                                              |                                                     |                             |          |        |         |         
|                                     | Cash (used for) provided by financing activities                             |                                                     |                             | (149,816 | )      |         | (350,450
|                                     |                                                                              |                                                     |                             |          |        |         |         
|Cash and cash equivalents            |                                                                              |                                                     |                             |          |        |         |         
|                                     | Net (decrease) increase                                                      |                                                     |                             | (2,690   | )      |         | (38,632 
|                                     | Beginning of year                                                            |                                                     |                             | 36,491   |        |         | 75,123  
|                                     |                                                                              |                                                     |                             |          |        |         |         
|                                     | End of year                                                                  |                                                     | $                           | 33,801   |        | $       | 36,491  
|                                     |                                                                              |                                                     |                             |          |        |         |         
|Supplemental cash flow information:  |                                                                              |                                                     |                             |          |        |         |         
|                                     | Cash paid during the year for interest                                       |                                                     | $                           | 3,359    |        | $       | 557     
|                                     | Contributed property, plant and equipment                                    |                                                     |                             |         |        |         |        

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

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CALIFORNIA POWER GROUP  COMBINED STATEMENTS OF CHANGES IN EQUITY  December 31, 2003, 2002 and 2001  (Amounts in thousands)

|                              |                            | Edison Mission
Energy affiliates |         | Chevron Texaco
affiliates |   | Total   |         
|----------------------------- | -------------------------- | -------------------------------- | ------- | ------------------------- | - | ------- | --------
|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 |         
|                              | Cash distributions         |                                  |         | (275,215                  | ) |         | (275,215
|                              | Cash contributions         |                                  |         | 46,992                    |   |         | 46,992  
|                              | Net income                 |                                  |         | 131,691                   |   |         | 131,691 
|                              | Other comprehensive income |                                  |         | 7,555                     |   |         | 7,555   
|                              |                            |                                  |         |                           |   |         |         
|Balances at December 31, 2003 |                            | $                                | 245,839 |                           | $ | 202,609 |         
|                              |                            |                                  |         |                           |   |         |         

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

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CALIFORNIA POWER GROUP  NOTES TO COMBINED FINANCIAL STATEMENTS  December 31, 2003, 2002 and 2001

1.     Organization

General

Edison Mission Energy ("EME"), an indirect wholly-owned non-utility subsidiary of Edison International ("EIX"), and ChevronTexaco Corporation
("Chevron") jointly own six cogeneration projects, one power project and a purchasing entity located in California:



The
eight 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 2007) 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 to 38 megawatts ("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 a subsidiary of Chevron and/or Aera Energy, LLC ("Aera") for use in oil recovery operations.

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Eastside Cogeneration Projects

Kern River and Sycamore (together, the "Eastsides") each own and operate 300 MW natural gas-fired cogeneration facilities 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 was constructed in two phases. The first phase achieved commercial operation on June 29,
2001, and consisted of a 320 MW simple-cycle peaking facility. Phase II, which achieved commercial operation on June 1, 2003, converted the facility to a 585 MW combined cycle facility, which
consists of an additional steam turbine generator and two heat recovery steam generators. Sunrise sells electric energy to the California Department of Water Resources ("CDWR") for resale to electric
consumers in California. Income or loss is allocated equally between the members.

Estrellas

Estrellas is a Delaware limited liability company established on March 28, 2001 and assigned to Sunrise at formation. Estrellas was formed for the purpose
of purchasing equipment, primarily for related party entities. Estrellas receives a sales tax rebate under a Location Agreement with the City of Shafter. The Location Agreement provides Estrellas a
sales tax rebate on the dollar volume of equipment sales transacted in Shafter.

Subsidiaries
of EME and Chevron reorganized Estrellas as a separate Delaware limited liability company on June 27, 2003. This reorganization had no impact on the combined
financial statements.

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.

Restricted Cash

Sunrise's financing agreement requires Sunrise to maintain escrow accounts. The funds in these restricted accounts will be maintained until such time that the
terms of the financing agreement are fully satisfied (Note 4). All restricted cash accounts earn interest at the current market rate. Upon authorization from certain parties to the financing,
funds from the restricted accounts may be used for items other than their designated purpose.

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Inventories

Inventories primarily consist of spare parts for the operation of the generation facilities. Inventories are stated at the lower of the weighted average cost or
market.

Risk Management

The Westsides utilize gas swap agreements to mitigate their exposure to fluctuations in gas prices (Note 6).

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.

Deferred Financing Costs

All legal and financing fees associated with project financing were deferred and are being amortized over the respective terms of the financings. Deferred
financing costs are presented net of accumulated amortization of $283,000 and $1,151,000 at December 31, 2003 and 2002, respectively. Amortization expense was approximately $350,000, $108,000
and $108,000 in 2003, 2002 and 2001, respectively.

Water Entitlement

During 2003, Sunrise underwrote the West Kern Water District's ("WKWD") purchase of 6,500 acre-feet of annual State Water Project entitlement from the
Berrenda Mesa Water District for $6,500,000. The WKWD dedicated the entitlement to Sunrise to mitigate the California Energy Commission's requirement that Sunrise secure
out-of-basin water supplies for its power generation needs. The water entitlement expires in 2032 and is being amortized over the useful life of Sunrise's facility. The water
entitlement is presented net of accumulated amortization of $97,000 at December 31, 2003. Amortization expense was approximately $97,000 in 2003.

Note Receivable

The WKWD did not have the necessary physical facilities to provide, transport and measure the water service delivery requested by Sunrise after the completion of
Phase 2. As a result, Sunrise constructed necessary facilities and improvements together with certain upgrades for the benefit of the WKWD to provide water service delivery to Sunrise. As part of the
water district improvements, Sunrise provided cash contributions on WKWD's behalf in exchange for a $3,900,000 promissory note. The note matures in 2013, bears interest at 9% and is payable in monthly
installments of $50,000. Payments are made through credits to Sunrise's water bills. The fair value of the note is calculated

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using
current interest rates. The fair value approximates the carrying value of $3,822,000 at December 31, 2003.

Emission Credits

During 2001, Sunrise purchased $1,900,000 of emission credits, including $1,200,000 from subsidiaries of Chevron. The remaining emission credits were purchased in
prior years by the Cogeneration Partnerships from several unrelated parties. All emission credits are amortized on a straight-line basis over their estimated useful lives. Emission credits
are presented net of accumulated amortization of $1,550,000 and $1,383,000 at December 31, 2003 and 2002, respectively. Amortization expense was approximately $167,000, $125,000 and $125,000 in
2003, 2002 and 2001, respectively.

Revenues

Revenue and related costs are recorded as electricity and steam are generated or services are provided.

Income Taxes

The California Power Group includes partnerships and limited liability companies 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.

Recent Accounting Pronouncements

Accounting for Asset Retirement Obligations

On January 1, 2003, the California Power Group adopted Statement of Financial Accounting Standards ("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 terms. As of January 1, 2003,
the California Power Group recognized a liability of $14,540,000 for asset retirement obligations. The cumulative effect of a change in accounting principle from unrecognized accretion and
depreciation expense is a loss of $9,200,000. If SFAS 143 had been adopted on January 1, 2001, the pro forma effect of the accounting change on the income statement would have resulted
in a decrease in net income of $900,000 and $1,000,000 during the years ended December 31, 2002 and 2001, respectively. The liability as of January 1, 2002 would have been $13,770,000.

During
the current year, the California Power Group recognized accretion expense of $815,000 associated with its asset retirement obligation. There were no other changes to the asset
retirement obligation. This accretion expense is classified as part of Depreciation, amortization and accretion.

Accounting for Derivative Instruments and Hedging Activities

On January 1, 2001, the California Power Group adopted 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

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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 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. In April 2003, the
Financial Accounting Standards Board issued SFAS No. 149,Amendment of Statement 133 on Derivative Instruments and Hedging Activities.SFAS 149 changed the guidance related to the application of the normal purchases and normal sales exception to electricity contracts. This change had no impact on the designation of the
California Power Group's electricity contracts as normal.

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 (Note 6).

Reclassifications

Certain prior year accounts have been reclassified to conform to the current year presentation.

3.     Property, Plant and Equipment

Property, plant and equipment consist of the following (amounts in thousands):

2003

2002Operating facilities

$
887,409

$
666,853Other property and equipment


25,642


18,974913,051


685,827Accumulated depreciation


(287,247
)

(257,281
)Construction work in progress


1,216


124,724$
627,020

$
553,270


Depreciation expense was approximately $27,573,000, $22,652,000, and $19,994,000 in 2003, 2002 and 2001, respectively.

4.     Project Financing Loans Payable

Project financing loans payable consist of the following (amounts in thousands):

2003

2002Sunrise

$
327,405

$
Coalinga





3,020Salinas River





3,500Sargent Canyon





3,380$
327,405

$
9,900


In September 2003, Sunrise entered into a $345,000,000 project financing loan payable with the Bank of New York as the administrative
agent. Half of the financing was provided by a syndicate of fourteen unrelated lenders with the remaining amount from Chevron Capital Corporation, a wholly-

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owned
subsidiary of Chevron. The project financing loan payable for Sunrise is repaid in semi-annual installments on the last day of April and October based on a percentage of the unpaid
principal, with the final payment of $22,908,000 due on October 31, 2011. The loan bears interest at 7.09% per annum, which is paid semi-annually with the principal payment.

The
Sunrise project financing loan payable is secured by substantially all the assets of Sunrise and places certain restrictions on cash, capital distributions and permitted investments.
As of December 31, 2003, pledged assets total approximately $375,900,000. In addition, Sunrise is required to maintain on deposit in escrow accounts an amount equal to the next principal
payment and six months interest, an amount equal to contractual obligations and $500,000 for major maintenance.

The
Sunrise project financing loan payable currently contains various restrictive covenants covering ratios relating to restricted cash, restrictions on distributions, use of proceeds
and other customary covenants. For the year ended December 31, 2003, Sunrise was in compliance with all the covenants under the project financing loan payable.

Fair value

The carrying amount of the Sunrise project financing loan payable approximates fair value based on the borrowing rates currently available to Sunrise for
long-term debt with similar terms and maturities.

Other Project Financing

The final installment on the project financing loans payable for Coalinga, Salinas River and Sargent Canyon was repaid on May 30, 2003. The loans payable
bore interest at the current Eurodollar market rate plus 1.2% per annum which was payable periodically throughout the year.

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

SteamCounterparty

Termination

Counterparty

TerminationKern River

SCE

08/09/2005

Chevron affiliates

06/01/2005Sycamore

SCE

12/31/2007

Chevron affiliates

12/31/2007Coalinga

PG&E

03/05/2007

Chevron and Aera

03/05/2007Mid-Set

PG&E

05/19/2004

Chevron affiliates

3/25 and 5/19/2004Salinas River

PG&E

03/06/2007

Aera

03/06/2007Sargent Canyon

PG&E

02/22/2007

Aera

02/22/2007Sunrise

CDWR

06/30/2012

Not applicable


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 partnerships would be required

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to
repay certain capacity payments to SCE. Under these provisions, as of December 31, 2003, the Eastsides have a total obligation of $50,991,000. 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.

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 and $28,517,000 to TEPI under this agreement during the years ended December 31, 2002 and 2001,
respectively. As a result of the termination of the TEPI agreement, effective December 6, 2002, Kern River increased the contract capacity dedicated to SCE under the PGA from 274 MW to 280 MW.
On July 1, 2003 the dedicated contract capacity was further increased from 280 MW to 290 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 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, 2003, 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 partnerships would be required to repay certain capacity payments to PG&E. Under these provisions, as of
December 31, 2003, the Westsides have a total obligation of $13,607,000. 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
$41,200,000 due to the Westsides. 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. In January 2003, Sunrise agreed to restructure the
second phase of the CDWR PPA which will extend through June 30, 2012. Under the terms of the amended agreement, Sunrise receives capacity payments at a rate of $170.60 per kilowatt year.
Sunrise is also eligible for summer and annual availability bonuses. During the years ended December 31, 2003 and 2002, Sunrise received availability bonuses totaling $6,234,000 and $4,359,000,
respectively. In addition, Sunrise is compensated for the number of times the plant is started, which is at the discretion of the State of California. Sunrise is paid a variable operation and
maintenance payment of $3.00 per megawatt hour based on net electrical output delivered to the CDWR. During the years ended December 31, 2003 and 2002, Sunrise received operation and
maintenance payments totaling $4,492,000 and $915,000, respectively.

Sunrise
has no firm contracts for fuel supply. Prior to October 1, 2003, Sunrise procured fuel on CDWR's behalf. CDWR reimbursed 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

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for
the generation of electricity on behalf of CDWR. The fuel costs and related CDWR reimbursements are presented in the Combined Statement of Comprehensive Income as Fuel expense and Sales of energy,
respectively. Effective October 1, 2003, a third party now procures fuel for Sunrise and all fuel costs are paid directly by CDWR.

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:



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.

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.

Westsides

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 derivative 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 were recorded as part of
Fuel expense in the Statements of Comprehensive Income. As of January 1, 2003, management designated the contracts as cash flow hedges; therefore, during 2003 and on a go forward basis gains or
losses associated with the effective portion of the hedges will be recorded in other comprehensive income. The ineffective portion of the cash flow hedges is recorded directly in the income statement.
The Westsides recorded income of $473,000 related to ineffectiveness during the year ended December 31, 2003. In addition, the Westsides recorded expense of $8,038,000 related to the
recognition of unrealized gains recognized in prior years. During the year ending December 31, 2004, the Westsides expect to reclassify $12,190,000 of gains into earnings.

216

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Fair value

In assessing the fair value of the Westsides' commodity derivative instruments, management 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, and other factors. The fair market value 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.

Eastsides and Sunrise

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 not responsible for the
procurement of fuel; therefore, Sunrise is not exposed to price risk associated with gas purchases.

7.     Related Party Operating Agreements

Operating expenses include the following amounts paid to related parties (amounts in thousands):

2003

2002

2001Fuel expenseTexaco Natural Gas, Inc.

$
412,920

$
240,840

$
442,243Edison Mission Marketing & Trading, Inc.


4,803


4,171


14,635Other operations and maintenance expenseEdison Mission Operations and Maintenance, Inc.


13,367


11,783


10,611Mission and affiliates


1,213


934


901Chevron (land lease)


167


157


147Other


134


84


84Administrative and generalChevron USA


6,347


7,094


6,820Texaco Power and Gasification Holdings Inc.


932


527


262$
439,883

$
265,590

$
475,703


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 $2,244,000, $2,998,000 and $3,110,000 for the years ended December 31, 2003, 2002 and 2001, respectively.

Sunrise
was party to an Energy Service Agreement with Edison Mission Marketing & Trading, Inc. ("EMMT"), a wholly-owned subsidiary of EME, whereby EMMT, among other
services, is to purchase and/or nominate fuel for and related transportation to the Sunrise facility. EMMT received a fixed service fee of $0.005 per MMBtu of fuel gas supplied to Sunrise, subject to
escalation as defined by the agreement. This service function was terminated effective October 1, 2003 and fuel management responsibilities were assumed by the CDWR.

217

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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 $930,000, $926,000 and $901,000 for the years ended
December 31, 2003, 2002 and 2001, respectively.

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 $43,300,000. 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 optionsKern River

04/30/2009

Kern River can extend indefinitelyMid-Set

07/15/2006

Mid-Set has the option to extend at any timeSalinas River

08/01/2008

Parties may agree to up to 15 one year extensionsSunrise

11/30/2025

Sunrise has a one-time option to extend for 25 yearsSycamore

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 have 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.

218

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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 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 of 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 will each assume responsibility for one-half of the former Mid-Set 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 responsible for 9,500 MMBtu per day of firm capacity at a demand cost of $0.28 per MMBtu. The
capacity was brokered to a third party at full cost recovery through November 1, 2003. The capacity was subsequently brokered to a third party for the period of November 2003 through
October 31, 2004 at a cost recovery level of $0.10 per MMBtu. The Eastsides incurred an expense related to the brokered capacity totaling $588,000 during the year ended December 31,
2003.There was no deficit in 2001, 2002 and through November 2003.

Firm Transportation Agreement

Sunrise previously held an agreement with the Kern River Gas Transmission Company effective May 2003 and extending for 15 years thereafter, for the
right to firm transportation capacity of 85,000 MMBtu per day of natural gas on the Kern River Gas Transmission pipeline between the Rockies-Opal and the Sunrise facility. The
transportation rates paid by Sunrise were in accordance with Kern River Gas Transmission's tariff schedule filed with the FERC. The reservation fee under the tariff for 15 year expansion
capacity is currently $0.447 per MMBtu of gas. CDWR reimbursed Sunrise for all costs associated with the agreement from May 1, 2003 to September 1, 2003. The agreement was assigned to
CDWR effective September 1, 2003 and Sunrise no longer has any responsibility or liability under the 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 June 28, 2019. 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

219

---

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% during the peak period and 97.3% during the off-peak
period. There is a $3,000,000 cap on the incentive and availability fees. During 2003, Sunrise made an $870,000 bonus payment to GEI for the 2003 and 2002 contract periods.

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 (amounts in thousands):

2003

2002

2001Southern California Edison

$
419,948

$
299,549

$
525,299Affiliates of Chevron


137,555


105,477


124,993California Department of Water Resources


110,023


48,485


48,121Pacific Gas & Electric Company


88,379


87,313


114,303Aera Energy, LLC


23,160


14,320


21,981$
779,065

$
555,144

$
834,697


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; however, all past due amounts
have now been repaid. Although PG&E is still under Chapter 11 bankruptcy protection, the California Power Group has no past due amounts from any of its counterparties.

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 dependent upon the California Power Group's ability to enter into new contracts at terms that would allow it to operate profitability. In accordance with
its policy for testing impairment of long-lived assets (Note 2), management periodically evaluates the expected viability of the plants subsequent to the expiration of the purchase
power agreements.

In
January 2004, the California Public Utilities Commission adopted a new Energy Procurement Framework for the state's investor owned utilities, including PG&E and SCE. The
framework includes provisions to extend qualifying facilities contracts expiring prior to 2005 for five years. The framework does not address pricing or other specific terms of the proposed contracts.
Management is currently evaluating the impact of these provisions and its other operational options at the conclusion of the contract lives. Based on these evaluations and discussions with its
counterparties, 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.

220

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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, 2003 and 2002, and the related statements of income, partners'
capital, and cash flows for each of the three years ended December 31, 2003. 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, 2003 and
2002, and the results of its operations and cash flows for each of the three years ended December 31, 2003, in conformity with accounting principles generally accepted in the United States.

|                                          |  |  |  | 
|----------------------------------------- |  |  |  | 
|Ernst & Young LLP                         |  |  |  | 
|Los Angeles, California
February 24, 2004 |  |  |  | 

221

---



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
|                                        | Interest payable           |                                                 
|                                        |                            |                                                 
|Total current liabilities               |                            |                                                 
|Long-term debt:                         |                            |                                                 
|                                        | Camino Energy Company      |                                                 
|                                        | Atlantic Richfield Company |                                                 
|Partners' capital                       |                            |                                                 
|                                        |                            |                                                 
|Total liabilities and partners' capital |                            | $                                               
|                                        |                            |                                                 

See
accompanying notes.

222

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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                   |                                   
|               | 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.

223

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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, 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 
|                             | Capital distributions |                       |         | (50,806                       | ) |                             | (2,074 | )     |        
|                             | Net income            |                       |         | 48,978                        |   |                             | 2,000  |       |        
|                             |                       |                       |         |                               |   |                             |        |       |        
|Balance at December 31, 2003 |                       | $                     | 64,701  |                               | $ | 2,642                       |        | $     | 64,701 
|                             |                       |                       |         |                               |   |                             |        |       |        

See
accompanying notes.

224

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WATSON COGENERATION COMPANY  STATEMENTS OF CASH FLOWS

|                                                                                  |                                              | Year ended December 31                           |         
|--------------------------------------------------------------------------------- | -------------------------------------------- | ------------------------------------------------ | --------
|
|
|Operating activities                                                              |                                              |                                                  |         
|Net income                                                                        |                                              | $                                                | 99,956  
|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                                         |                                              |                                                  | 108,485 
|Investing activities                                                              |                                              |                                                  |         
|Additions to property, plant and equipment                                        |                                              |                                                  | (3,751  
|                                                                                  |                                              |                                                  |         
|Net cash used in investing activities                                             |                                              |                                                  | (3,751  
|Financing activities                                                              |                                              |                                                  |         
|Distributions to partners                                                         |                                              |                                                  | (103,686
|                                                                                  |                                              |                                                  |         
|Net cash used in financing activities                                             |                                              |                                                  | (103,686
|                                                                                  |                                              |                                                  |         
|Net increase (decrease) in cash and cash equivalents                              |                                              |                                                  | 1,048   
|Cash and cash equivalents at beginning of year                                    |                                              |                                                  | 3,672   
|                                                                                  |                                              |                                                  |         
|Cash and cash equivalents at end of year                                          |                                              | $                                                | 4,720   
|                                                                                  |                                              |                                                  |         
|Supplemental information                                                          |                                              |                                                  |         
|Interest paid                                                                     |                                              | $                                                | 2,687   

See
accompanying notes.

225

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WATSON COGENERATION COMPANY  NOTES TO FINANCIAL STATEMENTS  December 31, 2003

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. CPC was
terminated effective at the close of business December 31, 2002, and all agreements were assigned back to 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.

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.

Inventories

Inventories are comprised of materials and supplies, and are stated at their lower of average cost or market.

226

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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.

New Accounting Pronouncements

Financial Accounting Standards Board (FASB) Statement No. 149

In April 2003, the FASB issued Statement No. 149, "Amendment of Statement 133 on Derivative Instruments and Hedging Activities." Statement
No. 149 reflects decisions made by the FASB and its Derivatives Implementation Group in connection with issues raised about the application of Statement No. 133. Generally, changes
resulting from Statement No. 149 apply to contracts entered into or modified after June 30, 2003, and for hedging relationships designated after June 30, 2003. The initial
adoption of Statement No. 149 had no material impact on the Company's results of operations and financial position.

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. Statement No. 143 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 was adopted beginning January 1,
2003. Adoption of Statement No. 143 had no impact on the Company's financial statements.

FIN 45

In November 2002, FASB issued Interpretation No. 45, "Guarantor's Accounting and Disclosure Requirements for Guarantees, Including Indirect
Guarantees of Indebtedness of OthersAn Interpretation of FASB Statements No. 5, 57 and 107" (FIN 45).Under FIN 45, issuers of
certain types of guarantees must recognize a liability based on the fair value of the guarantee issued, even when the likelihood of making payments is remote. In addition, FIN 45 requires increased
disclosures for specific types of guarantees. FIN 45's initial recognition requirements apply only to guarantees issued or modified after December 31, 2002. The Company does not anticipate any
material impact on its future results of operations or financial condition as a result of recording newly issued or modified guarantees at fair value.

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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 WCC recorded interest income of approximately $1,497,000, on the outstanding receivables.
Subsequent to March 2002, WCC no longer charged interest to SCE on its outstanding balance.

4.    Property, Plant and Equipment

Property, plant and equipment consists of the following:

2003

2002(In Thousands)Plant

$
304,304

$
298,847Construction-in-progress


1,239


2,532Other


5,747


5,747311,290


307,126Less accumulated depreciation


(169,482
)

(158,298
)$
141,808

$
148,828


Depreciation expense amounted to approximately $12,747,000, $10,472,000 and $9,973,000 for 2003, 2002 and 2001, respectively.

5.    Intangible Assets

Intangible assets, net of accumulated amortization of approximately $24,167,000 and $21,430,000 at December 31, 2003 and 2002, 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, $2,737,000 and $2,334,000 for 2003, 2002 and 2001, respectively. Amortization for the next four years is estimated at $2,737,000 per year and approximately $684,000 in 2008.

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

228

---

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. 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.

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 $191,000,000, $121,000,000 and $208,000,000 during 2003, 2002 and 2001, respectively.

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.

229

---

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 $50,168,000 and $40,584,000 at December 31, 2003 and 2002, 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.

11.    Commitments

WCC has entered into several multi-year contracts with gas turbine parts suppliers. The parts subject to these agreements are scheduled to be
delivered from 2004 through 2007. The total value of these contracts is approximately $21,632,000. Early termination of the agreements could result in a cancellation charge.

230

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Report of Independent Auditors

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, 2003 and 2002, and the results of their operations and their cash flows
for each of the three years in the period ended December 31, 2003, 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.

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.

As
described in Note 11 to the financial statements, the Company changed its method of accounting for asset retirement obligations as of January 1, 2003.

/s/
PricewaterhouseCoopers LLP

Houston,
Texas
February 27, 2004

231

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FOUR STAR OIL & GAS COMPANY  CONSOLIDATED BALANCE SHEETS  December 31, 2003 and 2002

|                                                          |                                                                                                                                                                                                                                                                                                                                       | 2003                           |                                            | 2002 |   
|--------------------------------------------------------- | ------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------- | ------------------------------ | ------------------------------------------ | ---- | --
|
|Assets                                                    |                                                                                                                                                                                                                                                                                                                                       |                                |                                            |      |   
|Current assets:                                           |                                                                                                                                                                                                                                                                                                                                       |                                |                                            |      |   
|                                                          | Cash and cash equivalents                                                                                                                                                                                                                                                                                                             |                                | $                                          | 36   |   
|                                                          | Accounts receivable:                                                                                                                                                                                                                                                                                                                  |                                |                                            |      |   
|                                                          |                                                                                                                                                                                                                                                                                                                                       | Trade                          |                                            |      | 2 
|                                                          |                                                                                                                                                                                                                                                                                                                                       | Related parties and affiliates |                                            |      | 35
|                                                          | Other receivables                                                                                                                                                                                                                                                                                                                     |                                |                                            | 2    |   
|                                                          | Other current assets                                                                                                                                                                                                                                                                                                                  |                                |                                            | 5    |   
|                                                          | Income tax receivable                                                                                                                                                                                                                                                                                                                 |                                |                                            | 8    |   
|                                                          |                                                                                                                                                                                                                                                                                                                                       |                                |                                            |      |   
|                                                          |                                                                                                                                                                                                                                                                                                                                       |                                | Total current assets                       |      |   
|                                                          |                                                                                                                                                                                                                                                                                                                                       |                                |                                            |      |   
|Properties, plant and equipment                           |                                                                                                                                                                                                                                                                                                                                       |                                | 920                                        |      |   
|Less-accumulated depreciation, depletion and amortization |                                                                                                                                                                                                                                                                                                                                       |                                | (656                                       | )    |   
|                                                          |                                                                                                                                                                                                                                                                                                                                       |                                |                                            |      |   
|                                                          |                                                                                                                                                                                                                                                                                                                                       |                                | Net properties, plant and equipment        |      |   
|                                                          |                                                                                                                                                                                                                                                                                                                                       |                                |                                            |      |   
|Deferred charges and other assets                         |                                                                                                                                                                                                                                                                                                                                       |                                |                                           |      |   
|                                                          |                                                                                                                                                                                                                                                                                                                                       |                                |                                            |      |   
|                                                          |                                                                                                                                                                                                                                                                                                                                       |                                | Total assets                               |      | $ 
|                                                          |                                                                                                                                                                                                                                                                                                                                       |                                |                                            |      |   
|Liabilities and Stockholders' Equity                      |                                                                                                                                                                                                                                                                                                                                       |                                |                                            |      |   
|Current liabilities:                                      |                                                                                                                                                                                                                                                                                                                                       |                                |                                            |      |   
|                                                          | Accounts payable and accrued liabilities                                                                                                                                                                                                                                                                                              |                                | $                                          | 12   |   
|                                                          | Related party and affiliate payables                                                                                                                                                                                                                                                                                                  |                                |                                            | 33   |   
|                                                          | Taxes payable                                                                                                                                                                                                                                                                                                                         |                                |                                            | 5    |   
|                                                          |                                                                                                                                                                                                                                                                                                                                       |                                |                                            |      |   
|                                                          |                                                                                                                                                                                                                                                                                                                                       |                                | Total current liabilities                  |      |   
|Note payable to affiliate                                 |                                                                                                                                                                                                                                                                                                                                       |                                | 104                                        |      |   
|                                                          |                                                                                                                                                                                                                                                                                                                                       |                                |                                            |      |   
|Deferred credits and other non-current obligations        |                                                                                                                                                                                                                                                                                                                                       |                                | 26                                         |      |   
|                                                          |                                                                                                                                                                                                                                                                                                                                       |                                |                                            |      |   
|Deferred income taxes                                     |                                                                                                                                                                                                                                                                                                                                       |                                | 50                                         |      |   
|                                                          |                                                                                                                                                                                                                                                                                                                                       |                                |                                            |      |   
|Commitments and contingencies (Note 10)                   |                                                                                                                                                                                                                                                                                                                                       |                                |                                            |      |   
|Stockholders' equity:                                     |                                                                                                                                                                                                                                                                                                                                       |                                |                                            |      |   
|                                                          | Preferred stock, $1.00 par value, 400 Class A shares authorized, 96 shares issued and outstanding at December 31, 2003 and 2002; 400 Class B authorized, 300 shares issued and outstanding at December 31, 2003 and
2002                                                                                                              |                                |                                            |     |   
|                                                          | Common stock, $1.00 par value, 1,000 Class A shares authorized, issued and outstanding at December 31, 2003 and 2002; 2,000 Class B shares authorized, 373 shares issued and outstanding at December 31, 2003 and 2002,
respectively; 1,000 Class C shares authorized, 25 shares issued and outstanding at December 31, 2003 and 2002 |                                |                                            |     |   
|                                                          | Additional paid-in capital                                                                                                                                                                                                                                                                                                            |                                |                                            | 29   |   
|Retained earnings                                         |                                                                                                                                                                                                                                                                                                                                       |                                | 93                                         |      |   
|                                                          |                                                                                                                                                                                                                                                                                                                                       |                                |                                            |      |   
|                                                          |                                                                                                                                                                                                                                                                                                                                       |                                | Total stockholders' equity                 |      |   
|                                                          |                                                                                                                                                                                                                                                                                                                                       |                                |                                            |      |   
|                                                          |                                                                                                                                                                                                                                                                                                                                       |                                | Total liabilities and stockholders' equity |      | $ 
|                                                          |                                                                                                                                                                                                                                                                                                                                       |                                |                                            |      |   

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

232

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FOUR STAR OIL & GAS COMPANY  CONSOLIDATED STATEMENTS OF INCOME  Years Ended December 31, 2003, 2002 and 2001

|                                                                      |                                          | 2003     |     | 2002 |    | 2001 |    
|--------------------------------------------------------------------- | ---------------------------------------- | -------- | --- | ---- | -- | ---- | ---
|
|Revenues:                                                             |                                          |          |     |      |    |      |    
|                                                                      | Crude oil                                |          | $   | 49   |    | $    | 45 
|                                                                      | Natural gas                              |          |     | 223  |    |      | 139
|                                                                      | Natural gas liquids                      |          |     | 37   |    |      | 24 
|                                                                      | Gain on sale of capital assets           |          |     | 10   |    |      |   
|                                                                      | Other                                    |          |     |     |    |      | 27 
|                                                                      |                                          |          |     |      |    |      |    
|                                                                      |                                          |          | 319 |      |    | 235  |    
|                                                                      |                                          |          |     |      |    |      |    
|Costs and expenses:                                                   |                                          |          |     |      |    |      |    
|                                                                      | Operating expenses                       |          |     | 35   |    |      | 47 
|                                                                      | General and administrative expenses      |          |     | 14   |    |      | 14 
|                                                                      | Depreciation, depletion and amortization |          |     | 37   |    |      | 44 
|                                                                      | Impairment of oil and gas properties     |          |     | 3    |    |      | 7  
|                                                                      | Taxes other than income taxes            |          |     | 28   |    |      | 19 
|                                                                      |                                          |          |     |      |    |      |    
|                                                                      |                                          |          | 117 |      |    | 131  |    
|                                                                      |                                          |          |     |      |    |      |    
|Operating income                                                      |                                          |          | 202 |      |    | 104  |    
|Other income (expense):                                               |                                          |          |     |      |    |      |    
|                                                                      | Interest expense                         |          |     | (3   | )  |      | (7 
|                                                                      | Interest income and other                |          |     |     |    |      | 6  
|                                                                      |                                          |          |     |      |    |      |    
|Income before income taxes                                            |                                          |          | 199 |      |    | 103  |    
|                                                                      |                                          |          |     |      |    |      |    
|Provision (benefit) for income taxes:                                 |                                          |          |     |      |    |      |    
|                                                                      | Federal:                                 |          |     |      |    |      |    
|                                                                      |                                          | Current  |     |      | 73 |      |    
|                                                                      |                                          | Deferred |     |      | 1  |      |    
|                                                                      | State and local:                         |          |     |      |    |      |    
|                                                                      |                                          | Current  |     |      | 6  |      |    
|                                                                      |                                          |          |     |      |    |      |    
|                                                                      |                                          |          | 80  |      |    | 31   |    
|                                                                      |                                          |          |     |      |    |      |    
|Net income before cumulative effect of change in accounting principle |                                          |          | 119 |      |    | 72   |    
|                                                                      |                                          |          |     |      |    |      |    
|Cumulative effect of change in accounting principle (net of tax)      |                                          |          | 9   |      |    |     |    
|                                                                      |                                          |          |     |      |    |      |    
|Net income                                                            |                                          | $        | 110 |      | $  | 72   |    
|                                                                      |                                          |          |     |      |    |      |    

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

233

---



FOUR STAR OIL & GAS COMPANY  CONSOLIDATED STATEMENTS OF STOCKHOLDERS' EQUITY  Years Ended December 31, 2003, 2002 and 2001

|                           |  | Common shares |  | Preferred shares |  |    |  |      |   |     |  |   |   |  |  
|-------------------------- |  | ------------- |  | ---------------- |  | -- |  | ---- | - | --- |  | - | - |  | -
|
|
|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 |  |   |  |  |  
|Dividends paid             |  |              |  |                 |  |   |  |     |   |    |  |   |  |  |  
|Net income                 |  |              |  |                 |  |   |  |     |   |    |  |   |  |  |  
|                           |  |               |  |                  |  |    |  |      |   |     |  |   |   |  |  
|Balance, December 31, 2003 |  | 1,000         |  | 373              |  | 25 |  | 96   |   | 300 |  | $ |  |  | $
|                           |  |               |  |                  |  |    |  |      |   |     |  |   |   |  |  

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

234

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FOUR STAR OIL & GAS COMPANY  CONSOLIDATED STATEMENTS OF CASH FLOWS  Years Ended December 31, 2003, 2002 and 2001

|                                                  |                                                                            | 2003                                           |                                                    | 2002                                                |     | 2001 |     
|------------------------------------------------- | -------------------------------------------------------------------------- | ---------------------------------------------- | -------------------------------------------------- | --------------------------------------------------- | --- | ---- | ----
|
|Cash flows from operating activities:             |                                                                            |                                                |                                                    |                                                     |     |      |     
|                                                  | Net income                                                                 |                                                | $                                                  | 110                                                 |     | $    | 72  
|                                                  | Reconciliation of net income to net cash provided by operating activities: |                                                |                                                    |                                                     |     |      |     
|                                                  |                                                                            | Reversal of provision for plug and abandonment |                                                    |                                                     |    |      |     
|                                                  |                                                                            | Depreciation, depletion and amortization       |                                                    |                                                     | 37  |      |     
|                                                  |                                                                            | Impairment of oil and gas properties           |                                                    |                                                     | 3   |      |     
|                                                  |                                                                            | Asset retirement obligation, net               |                                                    |                                                     | 9   |      |     
|                                                  |                                                                            | Deferred income taxes and other                |                                                    |                                                     | 1   |      |     
|                                                  |                                                                            | Gain on sales of capital assets                |                                                    |                                                     | (10 | )    |     
|                                                  |                                                                            | Changes in assets and liabilities:             |                                                    |                                                     |     |      |     
|                                                  |                                                                            |                                                | Accounts receivabletrade, net                     |                                                     |     | 1    |     
|                                                  |                                                                            |                                                | Accounts receivablerelated parties and affiliates |                                                     |     | 11   |     
|                                                  |                                                                            |                                                | Other receivables                                  |                                                     |     | 5    |     
|                                                  |                                                                            |                                                | Other current assets                               |                                                     |     | (1   | )   
|                                                  |                                                                            |                                                | Deferred charges and other assets                  |                                                     |     |     |     
|                                                  |                                                                            |                                                | Accounts payable and accrued liabilities           |                                                     |     | 5    |     
|                                                  |                                                                            |                                                | Related party and affiliate payables               |                                                     |     | (21  | )   
|                                                  |                                                                            |                                                | Taxes payable, net                                 |                                                     |     | (13  | )   
|                                                  |                                                                            |                                                |                                                    |                                                     |     |      |     
|                                                  |                                                                            |                                                |                                                    | Net cash provided by operating activities           |     |      | 137 
|                                                  |                                                                            |                                                |                                                    |                                                     |     |      |     
|Cash flows from investing activities:             |                                                                            |                                                |                                                    |                                                     |     |      |     
|                                                  |                                                                            | Capital expenditures                           |                                                    |                                                     | (12 | )    |     
|                                                  |                                                                            | Proceeds from property sales                   |                                                    |                                                     | 13  |      |     
|                                                  |                                                                            |                                                |                                                    |                                                     |     |      |     
|                                                  |                                                                            |                                                |                                                    | Net cash provided by (used in) investing activities |     |      | 1   
|                                                  |                                                                            |                                                |                                                    |                                                     |     |      |     
|Cash flows from financing activities:             |                                                                            |                                                |                                                    |                                                     |     |      |     
|                                                  |                                                                            | Dividends paid                                 |                                                    |                                                     | (58 | )    |     
|                                                  |                                                                            | Loan principal repayment to affiliate          |                                                    |                                                     | (65 | )    |     
|                                                  |                                                                            |                                                |                                                    |                                                     |     |      |     
|                                                  |                                                                            |                                                |                                                    | Net cash used in financing activities               |     |      | (123
|                                                  |                                                                            |                                                |                                                    |                                                     |     |      |     
|Increase (decrease) in cash and cash equivalents  |                                                                            |                                                | 15                                                 |                                                     |     | (2   | )   
|Cash and cash equivalents, beginning of year      |                                                                            |                                                | 21                                                 |                                                     |     | 23   |     
|                                                  |                                                                            |                                                |                                                    |                                                     |     |      |     
|Cash and cash equivalents, end of year            |                                                                            | $                                              | 36                                                 |                                                     | $   | 21   |     
|                                                  |                                                                            |                                                |                                                    |                                                     |     |      |     
|Supplemental disclosure of cash flow information: |                                                                            |                                                |                                                    |                                                     |     |      |     
|                                                  | Cash flows from operating activities include the following cash payments:  |                                                |                                                    |                                                     |     |      |     
|                                                  |                                                                            | Income taxes                                   |                                                    | $                                                   | 93  |      | $   
|                                                  |                                                                            | Interest                                       |                                                    |                                                     | 4   |      |     

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

235

---



FOUR STAR OIL & GAS COMPANY  NOTES TO CONSOLIDATED FINANCIAL STATEMENTS  December 31, 2003 and 2002

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 its 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% of its interest in Four Star to Edison Mission Energy (Mission
Energy). Four Star was an 80% 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, 2003, Texaco's (now ChevronTexaco's) ownership interest in Four Star was reduced to 67.1%.

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.

In
July 2003, FrontStreet FourStar LLP purchased 3.6% of all voting common stock, representing 2.8% ownership interest.

In
December 2003, Mission Energy purchased 18 additional shares of common stock. As a result of this stock transaction Mission Energy's voting interest increased 1.3% and
ownership interest increased 1%.

As
of December 31, 2003 and 2002, the ownership interests in Four Star were as follows:

2003

2002FrontStreet FourStar LLP

2.8
%
Chevron U.S.A. (CUSA)

32.8
%
36.6
%ChevronTexaco Global Energy Inc. (CTGEI)

24.3
%
24.3
%Edison Mission Energy (Mission Energy)

20.0
%
19.0
%Four Star Oil & Gas Holdings Company (owned jointly by CTGEI and Mission Energy)

20.1
%
20.1
%100.0
%
100.0
%


236

---

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 gas production from properties in which ChevronTexaco has an interest with other producers are generally recognized on the entitlement basis.

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

The Company follows the successful efforts method of accounting for its oil and gas exploration and production operations. All costs for development wells,
related plant and equipment, proved mineral interests in oil and gas properties and related asset retirement obligation (ARO) assets are capitalized.

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.

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.

237

---

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 the extent or manner of use of or physical change in an asset. Impaired assets are written down to their estimated fair values, generally their discounted
future net before-tax cash flows. For proved oil and gas properties, the Company generally
performs the impairment review on an individual field basis. As a result, the Company recorded impairment charges of $3 million, $7 million, and $7 million in 2003, 2002 and 2001,
respectively, due to downward reserve revisions.

Long-lived
assets that are held for sale are evaluated for possible impairment by comparing the carrying value with the fair value less the cost to sell. If the net book
value exceeds the sales value, the asset is considered impaired resulting in an adjustment to the lower value.

Effective
January 1, 2003, the Company implemented Financial Accounting Standards Board Statement (SFAS) No. 143,Accounting for Asset Retirement
Obligations(FAS 143) in which the fair value of a liability for an asset retirement obligation is recorded as an asset and a liability when there is a legal obligation
associated with the retirement of a long-term asset and the liability can be reasonably estimated. See also Note 11 relating to asset retirement obligations, which includes
additional information on the Company's adoption of FAS 143. Previously, for oil and gas producing properties, a provision was made through depreciation expense for anticipated abandonment and
restoration costs at the end of the property's useful life.

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,Accounting for the Impairment or Disposal of Long-Lived Assets(FAS 144). Actual results could differ from those estimates.

Reclassifications

Certain previously reported amounts have been reclassified to conform to current-year presentation. Such reclassifications 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(FAS 133), did not have a material effect on the Company's financial position as the Company has no derivatives as of December 31, 2003, 2002 and 2001, except for its physical sale
contracts, which qualify as normal sales. The Company adopted FAS 133 as of January 1, 2001.

238

---

New Accounting Pronouncements

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. On December 17, 2003, the FASB issued FIN 46-R, which not only included amendments in FIN 46, but also required
application of the interpretation to all affected entities no later than March 31, 2004 for calendar-year companies. However, prior to this requirement, companies must apply the
interpretation to special purpose entities by December 31, 2003. The adoption of FIN 46-R as it relates to special-purpose entities did not have a material impact on the Company's
results of operations, financial position or liquidity, and the Company expects a similar impact upon its adoption of the interpretation as of March 31, 2004.

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 by means of a monthly fixed fee and a monthly unit fee (variable with production), as described below.

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 remained in effect until November 30, 2003. Beginning December 1, 2003, the rate was adjusted to $613,267 and this rate will remain in effect until November 30, 2004. An
aggregate amount of fixed fee of $7.2 million, $7.2 million and $7.0 million 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, 2003, 2002 and 2001, respectively.

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
$6.1 million, $6.8 million and $7.7 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, 2003, 2002 and 2001, respectively. The unit fee is adjusted to actual production within 90 days after contract period ending November 30,
2003. Four Star paid CUSA a monthly unit fee of $507,627 for fiscal year 2003. The new contract period started December 1, 2003 and will end November 1, 2004.

Pursuant
to the contractual agreement described in Note 10, certain tax benefits and liabilities of the Company are assumed by ChevronTexaco.

239

---

The
following table summarizes sales to affiliates during 2003, 2002 and 2001. The Company makes no purchases from its affiliates.

2003

2002

2001(in millions)Dynegy

$
11.7

$
87.6

$
Texaco Natural Gas Inc.


57.3


70.6


252.2CUSA


219.3


39.6


Equilon Enterprise LLC(1)








46.3Total

$
288.3

$
197.8

$
298.5


---

4. Properties, Plant and Equipment

In 2002, Four Star purchased the San Juan LLC 1999 property for $11.6 million. In 2003, Four Star sold certain properties for $13.1 million,
resulting in an approximate $10 million pre-tax gain on the sale.

5. Note Payable to Affiliate

In September 1999, Four Star entered into a loan agreement with Texaco Inc. The outstanding balance on the loan agreement was $104 million,
$169 million and $239 million at December 31, 2003, 2002 and 2001. The loan bears interest at LIBOR plus one percent and matures on December 31, 2005. The interest rate was
2.2%, 2.4% and 3.4% at December 31, 2003, 2002 and 2001, respectively. Interest expense during 2003, 2002 and 2001, was $3 million, $7 million and $13 million,
respectively. Four Star pays ChevronTexaco 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, exceeds the amount of the revised borrowing base, Four Star must repay such excess
to Texaco Inc. in four equal quarterly installments. Throughout 2003, 2002 and 2001, Four Star's borrowing base exceeded the outstanding loan balance, thus no principal payments were due. As of
December 31, 2003, the Company's borrowing base under the agreement was $377 million.

Four
Star elected to pre-pay $65 million and $70 million of the note in 2003 and 2002, respectively. Four Star has the right, subject to certain conditions, to
prepay the note in whole or in part prior to the maturity date of December 31, 2005.

6. Concentration of Credit Risk

Substantially all of the Company's accounts receivable at December 31, 2003 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, 2003, 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(FAS 109). Under FAS No. 109, deferred income taxes are determined utilizing a liability approach. This method gives consideration to the future tax consequences associated with
differences

240

---

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, 2003, 2002 and 2001, were as follows (in millions):

2003

2002

2001Deferred tax liabilities related to oil and gas properties

$
(50
)
$
(54
)
$
(57
)Net deferred tax liability

$
(50
)
$
(54
)
$
(57
)


There are differences between income taxes computed using the statutory rate of 35 percent and the Company's effective income tax rates
(40 percent in 2003, 29 percent in 2002 and 29 percent in 2001), primarily as a result of a prior period adjustment in 2003 and the availability to the Company of certain tax
credits in 2002 and 2001. Reconciliations of income taxes computed using the statutory rate to the Company's effective tax rates are as follows (in millions):

2003

2002

2001Income taxes computed at the statutory rate

$
69

$
36

$
64Section 29 tax credits





(7
)

(7
)Other, net


4


2


(3
)Prior period adjustment


7





Provision for income taxes

$
80

$
31

$
54


The prior period adjustment relates to certain excess tax depreciation reported in prior years. The Company has reported the correction to the IRS
as part of the ongoing tax return audit process.

8. Stockholders' Equity

In 1995, Four Star created four additional classes of stock: Class A common (voting), Class B common (voting), Class C common
(non-voting) 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, 2003 and 2002, Mission Energy owned 24.25 and
22.94 percent of all voting common stock outstanding, respectively. Four Star Oil and Gas Holdings Company (owned jointly by CTGEI and Mission Energy) owned 26.22 percent of all voting
common stock in the Company as of December 31, 2003.

In
2003, FrontStreet FourStar LLC purchased and owns 3.6% of all voting common stock outstanding.

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.

241

---

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. FAS 143Asset Retirement Obligations

The Company adopted Financial Accounting Standards Board Statement No. 143,Accounting for Asset Retirement
Obligations(FAS 143), effective January 1, 2003. This new accounting standard applies to the retirement of tangible long-lived assets in which the
fair value of a liability for an asset retirement obligation is recorded when there is a legal obligation associated with the retirement of a long-lived asset and the liability can be
reasonably estimated. Obligations associated with the retirement of these assets require recognition in certain circumstances of: (1) the present value of a liability and offsetting asset for
an asset retirement obligation, (2) the subsequent accretion of that liability and depreciation of the asset, and (3) the periodic review of the ARO liability estimates and discount
rates. FAS 143 primarily affects the company's accounting for oil and gas producing assets and differs in several respects from previous accounting under FAS 19, Financial Accounting and Reporting by Oil and Gas
Producing Companies.

In
the first quarter 2003, the company recorded a net after-tax charge of $9.4 million for the cumulative effect of the adoption of FAS 143. The
cumulative-effect adjustment also increased the following balance sheet categories: "Properties, plant and equipment," $11.4 million; "Deferred credits and other noncurrent obligations,"
$25.5 million; "Noncurrent deferred income taxes" decreased by $4.7 million.

Other
than the cumulative-effect net charge, the effect of the new accounting standard on net income in 2003 was not materially different from what the result would have been under
FAS 19 accounting. Included in "Depreciation, depletion and amortization" were $0.1 million related to the depreciation of the ARO asset and $0.9 million related to the accretion
of the ARO liability.

There
would have been no material impact on the Company net income for 2002 and 2001 if the provisions of FAS 143 had been applied in those periods.

Prior
to the implementation of FAS 143, the company had recorded a provision for abandonment that was part of "Accumulated depreciation, depletion and amortization." Upon
implementation of FAS 143, the provision for abandonment was reversed and ARO liability was recorded. The amount of

242

---

the
abandonment reserve at the end of each year and the proforma ARO liability were as follows (in millions):

2003

2002

2001ARO liability (FAS 143) at January 1

$
25.5

$
24.4

$
23.2ARO liability (FAS 143) at December 31


26.1


25.5


24.4Abandonment provision (FAS 19) at December 31





11.4


10.3


The following table indicates the changes to the company's before-tax asset retirement obligations in 2003 (in millions):

2003Balance January 1

Cumulative impact of the accounting change

25.5Liabilities incurred in the current year

Liabilities settled in the current year

(0.3
)Accretion expense in the current period

0.9Balance at December 31

26.1


12. Accounting for Mineral Interest Investments

The Securities and Exchange Commission (SEC) has questioned certain companies in the oil and gas and mining industries as to the proper accounting for, and
reporting of, acquired contractual mineral interests under FASB Statement No. 141,Business Combinations(FAS 141) and FASB Statement
No. 142,Goodwill and Intangible Assets(FAS 142). These accounting standards became effective for the Company on July 1, 2001 and
January 1, 2002, respectively.

At
issue is whether such mineral interest costs should be classified on the balance sheet as part of "Properties, plant and equipment" or as "Intangible asset." The Company will continue
to classify these costs as "Properties, plant and equipment" and apportion them to expense in future periods under the Company's existing accounting policy until authoritative guidance is provided.

For
Four Star, the net book values of this category of acquired contractual mineral interest costs at December 31, 2003 and 2002 were $96.8 million and
$111.2 million, respectively. If reclassification of these balances becomes necessary, the Company's statements of income and cash flows would not be affected. However, additional disclosures
related to intangible assets would be required as prescribed under the associated accounting standards.

13. Subsequent Events

On January 1, 2004, CUSA converted 153 shares of Preferred B stock to Common B stock. On January 6, 2004, CUSA sold 5 shares of common stock to
FrontStreet FourStar LLC.

On
January 7, 2004, Medicine Bow Energy Corporation purchased all the outstanding equity interest of Edison Mission Energy Oil & Gas (EMOG) from Edison Mission Fuel.
Coincident with the closing of this acquisition, Medicine Bow formed a wholly owned subsidiary, MBOW Four Star Corporation, and merged EMOG and MBOW Four Star Corporation. MBOW Four Star Corporation
is the surviving corporation and effectively owns 30% of the Company.

14. 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

243

---

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 future net cash flows related to proved reserves, and changes in estimated discounted future net cash flows.



2003

2002

2001(millions of dollars)Exploration

$


$
2

$
Property acquisitions





12


Development


12


13


42Total costs incurred

$
12

$
27

$
42


---



2003

2002

2001(millions of dollars)Unproved properties

$
1

$
1

$
1Proved properties and related producing assets


900


939


906Other uncompleted projects


7


15


27ARO asset


12





Gross capitalized costs


920


955


934Unproved properties valuation








1Proved producing properties


644


662


618ARO asset depreciation


12





Future abandonment and restoration





11


10Accumulated provisions


656


673


629Net capitalized costs

$
264

$
282

$
305


244

---





The Company's results of operations from oil and gas producing activities for the years 2003, 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.

2003

2002

2001(million of dollars)Revenues from net production:Sales

$
309

$
208

$
303Total


309


208


303Production expenses


(49
)

(61
)

(51
)Taxes other than on income


(28
)

(19
)

(25
)Proved producing properties: depreciation, depletion and abandonment provision


(36
)

(44
)

(38
)Accretion expenses


(1
)




Other income (expense)


7


20


7Results before income taxes


202


104


196Income tax expense


(80
)

(31
)

(54
)Results of producing operations

$
122

$
73

$
142




2003

2002

2001Average sales prices:Liquids, per barrel

$
26.25

$
19.80

$
21.55Natural gas, per thousand cubic feet


4.14


2.48


3.58Average production costs, per barrel


4.10


4.86


3.65




The Company's estimated net proved underground oil and gas reserves and changes thereto for the years 2003, 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.

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.

245

---

"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)(millions of barrels)

(millions of cubic feet)Reserves at December 31, 2000

28

503,855Changes attributable to:Revisions

(3
)
51,827Extensions and discoveries



17,320Sales



(21
)Production

(3
)
(61,611
)Reserves at December 31, 2001

22

511,370Changes attributable to:Revisions

3

5,772Extensions and discoveries



2,756Sales



Purchases



24,072Production

(4
)
(56,057
)Reserves at December 31, 2002

21

487,913Changes attributable to:Revisions

2

(26,854
)Extensions and discoveries



3,523Sales



(3,978
)Purchases



Production

(3
)
(53,184
)Reserves at December 31, 2003

20

407,420


---



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 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

246

---

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.

2003

2002

2001(millions of dollars)Future cash inflows from production

$
2,701

$
2,088

$
1,454Future production and development costs


(701
)

(743
)

(655
)Future income taxes


(723
)

(463
)

(273
)Undiscounted future net cash flows


1,277


882


526Ten percent midyear annual discount for timing of estimated cash flows


(506
)

(332
)

(190
)Standardized measure of discounted future net cash flows

$
771

$
550

$
336




2003

2002

2001(millions of dollars)Present value at January 1

$
550

$
336

$
1,679Sales and transfers of oil and gas produced, net of production costs


(217
)

(130
)

(256
)Development costs incurred





13


42Purchases of reserves





20


Sales of reserves


(11
)




Extensions, discoveries and improved recovery, less related costs


16


4


9Revisions of previous quantity estimates


(101
)

45


27Net change in prices, development and production costs


600


344


(2,147
)Accretion of discount


76


45


257Net change in income tax


(142
)

(127
)

725Net change for the year


221


214


(1,343
)Present value at December 31

$
771

$
550

$
336


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."

247

---



Report of Independent Auditors

To
the Management Committee of
Midway-Sunset Cogeneration Company:

In
our opinion, the accompanying balance sheets 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, 2003 and December 31, 2002, and the results of its operations and its 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 Partnership'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
explained in Note 2 to the financial statements, effective January 1, 2003, the Partnership changed its method of accounting for asset retirement obligations in
accordance with SFAS No. 143, "Accounting for Asset Retirement Obligations."

PricewaterhouseCoopers
LLP

Los
Angeles, California
March 10, 2004

248

---



MIDWAY-SUNSET COGENERATION COMPANY  BALANCE SHEETS  December 31, 2003 and 2002

|                                                |                                           | 2003                                   |            | 2002      
|----------------------------------------------- | ----------------------------------------- | -------------------------------------- | ---------- | ----------
|Assets                                          |                                           |                                        |            |           
|Current assets:                                 |                                           |                                        |            |           
|                                                | Cash and cash equivalents                 |                                        | $          | 5,938,922 
|                                                | Accounts receivable                       |                                        |            | 59,561,248
|                                                | Inventory                                 |                                        |            | 2,996,279 
|                                                |                                           |                                        |            |           
|                                                |                                           | Total current assets                   |            |           
|Plant and equipment, net                        |                                           |                                        | 81,796,936 |           
|Other assets:                                   |                                           |                                        |            |           
|                                                | Emission offsets, net                     |                                        |            | 1,866,666 
|                                                | Deposits                                  |                                        |            | 166,874   
|                                                |                                           |                                        |            |           
|                                                |                                           | Total assets                           |            | $         
|                                                |                                           |                                        |            |           
|Liabilities and Partners' Equity                |                                           |                                        |            |           
|Current liabilities:                            |                                           |                                        |            |           
|                                                | Accounts payable to affiliates and others |                                        | $          | 48,081,415
|                                                |                                           |                                        |            |           
|                                                |                                           | Total current liabilities              |            |           
|Long term asset retirement obligation liability |                                           |                                        | 1,348,780  |           
|                                                |                                           |                                        |            |           
|                                                |                                           | Total liabilities                      |            |           
|                                                |                                           |                                        |            |           
|Commitments and contingencies (Note 10)         |                                           |                                        |            |           
|Partners' equity:                               |                                           |                                        |            |           
|                                                | San Joaquin Energy Company                |                                        |            | 51,448,365
|                                                | Aera Energy LLC                           |                                        |            | 51,448,365
|                                                |                                           |                                        |            |           
|                                                |                                           | Total partners' equity                 |            |           
|                                                |                                           |                                        |            |           
|                                                |                                           | Total liabilities and partners' equity |            | $         
|                                                |                                           |                                        |            |           

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

249

---

MIDWAY-SUNSET COGENERATION COMPANY  STATEMENTS OF INCOME  For the Years Ended December 31, 2003, 2002 and 2001 (unaudited)

|                                                                                    |                                    | 2003                       |            | 2002        |             | 2001      
|----------------------------------------------------------------------------------- | ---------------------------------- | -------------------------- | ---------- | ----------- | ----------- | ----------
|
|Revenues:                                                                           |                                    |                            |            |             |             |           
|                                                                                    | Sales of electricity to affiliates |                            | $          | 131,448,226 |             | $         
|                                                                                    | Sales of electricity to others     |                            |            | 2,972,476   |             |           
|                                                                                    |                                    |                            |            |             |             |           
|                                                                                    |                                    | Total sales of electricity |            |             | 134,420,702 |           
|                                                                                    | Sales of steam to affiliate        |                            |            | 45,332,699  |             |           
|                                                                                    | Interest and other income          |                            |            | 99,054      |             |           
|                                                                                    |                                    |                            |            |             |             |           
|                                                                                    |                                    | Total revenues             |            |             | 179,852,455 |           
|                                                                                    |                                    |                            |            |             |             |           
|Expenses:                                                                           |                                    |                            |            |             |             |           
|                                                                                    | Fuel                               |                            |            | 123,513,376 |             |           
|                                                                                    | Maintenance and operations         |                            |            | 4,110,644   |             |           
|                                                                                    | Contract labor                     |                            |            | 5,418,825   |             |           
|                                                                                    | Property taxes                     |                            |            | 1,919,815   |             |           
|                                                                                    | Write-off of development costs     |                            |            |            |             |           
|                                                                                    | Depreciation and amortization      |                            |            | 7,986,451   |             |           
|                                                                                    | Loss/(gain) on disposal of asset   |                            |            | 193,264     |             |           
|                                                                                    | Interest expense                   |                            |            | 109,449     |             |           
|                                                                                    |                                    |                            |            |             |             |           
|                                                                                    |                                    | Total expense              |            |             | 143,251,824 |           
|Income from operations                                                              |                                    |                            | 36,600,631 |             |             | 28,809,578
|Cumulative effect of change in accounting for asset retirement obligations (Note 2) |                                    |                            | 1,037,201  |             |             |          
|                                                                                    |                                    |                            |            |             |             |           
|                                                                                    |                                    | Net income                 |            | $           | 35,563,430  |           
|                                                                                    |                                    |                            |            |             |             |           

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  December 31, 2003, 2002 and 2001 (unaudited)

|                                       |                    | San Joaquin
Energy
Company |            | Aera Energy
LLC |   | Total      |            
|-------------------------------------- | ------------------ | -------------------------- | ---------- | --------------- | - | ---------- | -----------
|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 |            
|                                       | Net income         |                            |            | 17,781,715      |   |            | 17,781,715 
|                                       | Cash distributions |                            |            | (17,500,000     | ) |            | (17,500,000
|                                       |                    |                            |            |                 |   |            |            
|Balance, December 31, 2003             |                    | $                          | 51,448,365 |                 | $ | 51,448,365 |            
|                                       |                    |                            |            |                 |   |            |            

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, 2003, 2002 and 2001 (unaudited)

|                                                     |                                                                                   | 2003                                                            |                                           | 2002        |            | 2001        |            
|---------------------------------------------------- | --------------------------------------------------------------------------------- | --------------------------------------------------------------- | ----------------------------------------- | ----------- | ---------- | ----------- | -----------
|
|Cash flows from operating activities:                |                                                                                   |                                                                 |                                           |             |            |             |            
|                                                     | Net income                                                                        |                                                                 | $                                         | 35,563,430  |            | $           | 28,809,578 
|                                                     | Adjustments to reconcile net income to net cash provided by operating activities: |                                                                 |                                           |             |            |             |            
|                                                     |                                                                                   | Depreciation and amortization                                   |                                           |             | 7,986,451  |             |            
|                                                     |                                                                                   | Loss (gain) on disposal of asset                                |                                           |             | 193,264    |             |            
|                                                     |                                                                                   | Write-off of development costs                                  |                                           |             |           |             |            
|                                                     |                                                                                   | Cumulative effect of change in accounting (Note 2)              |                                           |             | 1,037,201  |             |            
|                                                     |                                                                                   | Decrease (increase) in accounts receivable                      |                                           |             | 174,779    |             |            
|                                                     |                                                                                   | Decrease (increase) in inventory                                |                                           |             | 178,731    |             |            
|                                                     |                                                                                   | Decrease (increase) in deposits                                 |                                           |             | 333,975    |             |            
|                                                     |                                                                                   | (Decrease) increase in accounts payable to affiliates and other |                                           |             | (3,201,288 | )           |            
|                                                     |                                                                                   | Increase (decrease) in other liabilities                        |                                           |             | 488,443    |             |            
|                                                     |                                                                                   |                                                                 |                                           |             |            |             |            
|                                                     |                                                                                   |                                                                 | Net cash provided by operating activities |             |            | 42,754,986  |            
|                                                     |                                                                                   |                                                                 |                                           |             |            |             |            
|Cash flows from investing activities:                |                                                                                   |                                                                 |                                           |             |            |             |            
|                                                     | Capital expenditures                                                              |                                                                 |                                           | (4,482,968  | )          |             | (760,522   
|                                                     | Proceeds from sale of equipment                                                   |                                                                 |                                           | 37,323      |            |             | 5,000      
|                                                     |                                                                                   |                                                                 |                                           |             |            |             |            
|                                                     |                                                                                   |                                                                 | Net cash used in investing activities     |             |            | (4,445,645  | )          
|                                                     |                                                                                   |                                                                 |                                           |             |            |             |            
|Cash flows from financing activities:                |                                                                                   |                                                                 |                                           |             |            |             |            
|                                                     | Cash distributions                                                                |                                                                 |                                           | (35,000,000 | )          |             | (81,000,000
|                                                     |                                                                                   |                                                                 |                                           |             |            |             |            
|                                                     |                                                                                   |                                                                 | Net cash used in financing activities     |             |            | (35,000,000 | )          
|                                                     |                                                                                   |                                                                 |                                           |             |            |             |            
|Net increase (decrease) in cash and cash equivalents |                                                                                   |                                                                 | 3,309,341                                 |             |            | (7,456,174  | )          
|Cash and cash equivalents, beginning of year         |                                                                                   |                                                                 | 2,629,581                                 |             |            | 10,085,755  |            
|                                                     |                                                                                   |                                                                 |                                           |             |            |             |            
|Cash and cash equivalents, end of year               |                                                                                   | $                                                               | 5,938,922                                 |             | $          | 2,629,581   |            
|                                                     |                                                                                   |                                                                 |                                           |             |            |             |            

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

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MIDWAY-SUNSET COGENERATION COMPANY  NOTES TO FINANCIAL STATEMENTS  December 31, 2003, 2002 and 2001 (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 (i) SWEPI LP and (ii) Shell Onshore
Ventures, Inc. (affiliates of Shell Oil Company) and (iii) 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 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


Capitalized Interest

Interest incurred on funds borrowed by the Partnership to finance plant construction was capitalized. Capitalization of interest was discontinued when the plant
was 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.

Derivative Instruments and Hedging Activities

Under FASB 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 did not either meet the definition of a derivative or could apply the normal purchase and normal sale
exception defined in FAS 133. Accordingly, accrual accounting is used consistent with the pre-adoption of FAS 133.

Revenue Recognition

Revenue is recognized as billable under the provisions of three power purchase agreements which have varying terms of approximately seven 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.

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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 capitalized project development costs associated with a planned plant
expansion project during the period January 2000 through June 2002. In July 2002, a decision was made to discontinue funding of the expansion project. Capitalized development
costs associated with the expansion project totaling $3,388,089 were expensed in 2002.

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. On January 1, 2003, the Partnership recorded a $1,037,201 decrease to net income as the cumulative effect of adoption of SFAS No. 143.

The
Partnership recorded a liability representing expected future costs associated with site reclamation, facilities dismantlement and removal of environmental hazards as follows:

Initial asset retirement obligation as of January 1, 2003

$
1,239,331Accretion expense


109,449Balance of asset retirement obligation as of December 31, 2003

$
1,348,780


Had SFAS No. 143 been applied retroactively in the years ended December 31, 2002 and 2001, it would not have had a material effect
upon the Partnership's results.

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 adoption of SFAS No. 145 on January 1, 2003, did not 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

255

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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 adoption of SFAS
No. 146 did not have a material effect on its financial position or the results of operations.

Statement of Financial Accounting Standards No. 149

In April 2003, the Financial Accounting Standards Board (FASB) issued Statement of Financial Accounting Standards No. 149, "Amendment of Statement
133 on Derivative Instruments and Hedging Activities." This statement amends and clarifies financial accounting and reporting for derivative instruments and for hedging activities under SFAS
No. 133. The amendment reflects decisions made by the FASB and the Derivatives Implementation Group (DIG) process in connection with issues raised about the application of SFAS No. 133.
Generally, the provisions of SFAS No. 149 will be applied
prospectively for contracts entered into or modified after June 30, 2003 and for hedging relationships designated after June 30, 2003. SFAS No. 149 provisions that resulted from
the DIG process that became effective in fiscal quarters beginning before June 15, 2003 will continue to be applied based upon their original effective dates. The adoption of this standard had
no impact on the Partnership's financial statements.

Statement of Financial Accounting Standards No. 150

Effective July 1, 2003, the Partnership adopted Statement of Financial Accounting Standards No. 150, "Accounting for Certain Financial Instruments
with Characteristics of both Liabilities and Equity." SFAS No. 150 establishes standards for how to classify and measure certain financial instruments with characteristics of both liabilities
and equity. It requires that an issuer classify a financial instrument that is within its scope as a liability or asset, as appropriate. The adoption of this standard had no impact on the
Partnership's financial statements.

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.

Statement of Financial Accounting Standards Interpretation No. 46

In December 2003, the FASB issued Statement of Financial Accounting Standards Interpretation No. 46, "Consolidation of Variable Interest Entities."
This interpretation of Accounting Research Bulletin No. 51, "Consolidated Financial Statements," addresses consolidation of variable interest entities by business enterprises that are the
primary beneficiaries. 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. This interpretation is effective on March 31, 2004. The
Partnership does not expect the adoption of this standard will have a material impact on its financial statements.

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3. Accounts Receivable

Accounts receivable consists of the following at December 31, 2003 and 2002:

2003

2002Accounts receivable from affiliates:SCE

$
15,202,053

$
14,641,191Aera


7,435,073


7,044,875Other affiliates


323,719


293,15522,960,845


21,979,221Accounts receivable from others


36,600,403


37,756,806$
59,561,248

$
59,736,027


4. Inventory

Inventory consists of the following at December 31, 2003 and 2002:

2003

2002Natural gas

$
405,796

$
791,267Materials and spare parts


2,590,483


2,383,743$
2,996,279

$
3,175,010


5. Plant and Equipment

Plant and equipment consists of the following at December 31, 2003 and 2002:

2003

2002Power plant facilities

$
159,870,405

$
156,080,240Capitalized interest


8,769,831


8,769,831Furniture and office equipment


1,357,270


1,171,097Construction in process


197,288


221,018170,194,794


166,242,186Less: accumulated depreciation and amortization


(88,397,858
)

(80,884,316
)$
81,796,936

$
85,357,870


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, 2003 and 2002:

2003

2002Cost

$
7,000,000

$
7,000,000Less: Accumulated amortization


(5,133,334
)

(4,783,334
)$
1,866,666

$
2,216,666


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Deposits

The partnership is required to maintain deposits with the Automated Power Exchange and the California Independent System Operator ("CAISO") to ensure monthly
liquidity requirements as a scheduling coordinator. Deposits totaled $166,874 and $500,000 at December 31, 2003, and December 31, 2002, respectively.

7. Accounts Payable

Accounts payable consists of the following at December 31, 2003 and 2002:

2003

2002Accounts payable to affiliates:Aera Energy LLC

$
43,376

$
5,381,833Edison Mission Operations and Maintenance


301,175


315,115San Joaquin Energy Company


143,679


171,008488,230


5,867,956Accounts payable to others


47,593,185


45,414,747$
48,081,415

$
51,282,703


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.

Power Purchase Agreements

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 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. SCE also pays the Partnership for firm capacity based upon a contracted amount per kilowatt year, as determined in the Power Purchase Agreement.

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. Payment of the $12 million is to be made in 27 equal monthly installments, which can be offset against

258

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monthly
payments due from Aera for energy purchases. At December 31, 2003 and December 31, 2002 current payables related to this agreement were $0 and $5,333,333, respectively.

The
Partnership recognized total electricity sales to affiliates of $131,448,226, $95,266,858 and $173,853,446 in 2003, 2002 and 2001, respectively, under these contracts. The
Partnership has a payable of $34,671,687 to SCE which is wholly offset by a receivable from the California Power Exchange. For further discussion of this situation refer to Note 9. Receivable
from California Power Exchange.

Steam Sale and Purchase Agreement

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 8,
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 $45,332,699, $30,633,411 and $60,860,800 of steam in 2003, 2002 and 2001, 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.

Operation and Maintenance Agreement

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 $3,027,699, $3,032,198 and $3,088,614 which included annual fees earned by EMOM of
$336,000 in 2003, 2002 and 2001, respectively, which are included in contract labor in the accompanying statements of income.

Other Agreements

Under the terms of the Partnership Agreement, including a Gas Management Services 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 $350,583, $310,961 and $357,526
in 2003, 2002 and 2001, respectively.

Under
the terms of a Financial Services Agreement, San Joaquin provides certain financial, accounting and other services for an annual fee of $125,000 in 2003, 2002 and 2001.

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. Receivable from California Power Exchange

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 during the period in which SCE's financial condition had deteriorated as a result of the California energy 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 March 26, 2001. SCE agreed to a payment schedule
based on the occurrence of certain events, the first

259

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of
which occurred with the execution of the agreement. SCE paid $5,686,281 (10 percent of the stipulated amount) 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 it to pay its debts in a timely manner. 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 $36,062,476 included in Accounts Receivable as of December 31, 2003, by the California Power Exchange ("PX") for power sold into the California ISO during
2000 and 2001. The PX filed for bankruptcy in 2001. The PX, upon receiving funds from its debtors, is expected to pay the Partnership an amount adjusted for wind down charges. The Partnership will
then pro-rate the receipt and reimburse the following parties on a pro rata basis for the following: SCE $34,671,687, PG&E $868,803, 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 PG&E 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 2003, 2002 and 2001.

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 $2,089,742, $2,046,330 and $1,199,680 of electricity in 2003, 2002 and 2001, respectively, under this agreement which is included within sales of electricity to others in
the accompanying statements of income.

The
Partnership reimburses third parties for the procurement of fuel gas. The Partnership incurred costs of $114,650,896, $73,216,746 and $158,662,356 for fuel gas purchases in 2003,
2002 and 2001, 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.

260

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Report of Independent Auditors

To
the Management Committee of
March Point Cogeneration Company

In
our opinion, the accompanying balance sheets 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 at December 31, 2003 and December 2002, and the results of its operations and its 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 Partnership'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.

PricewaterhouseCoopers
LLP

Los
Angeles, California
February 25, 2004

261

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MARCH POINT COGENERATION COMPANY  BALANCE SHEETS  December 31, 2003 and 2002

|                                               |                                           | 2003                     |                                        | 2002      
|---------------------------------------------- | ----------------------------------------- | ------------------------ | -------------------------------------- | ----------
|Assets                                         |                                           |                          |                                        |           
|Current assets                                 |                                           |                          |                                        |           
|                                               | Cash and cash equivalents                 |                          | $                                      | 7,366,000 
|                                               | Receivables                               |                          |                                        |           
|                                               |                                           | Equilon and subsidiaries |                                        |           
|                                               |                                           | Puget Sound Energy       |                                        |           
|                                               |                                           | Other                    |                                        |           
|                                               | Current portion of escrow account         |                          |                                        | 936,000   
|                                               | Inventory                                 |                          |                                        | 2,435,000 
|                                               |                                           |                          |                                        |           
|                                               |                                           |                          | Total current assets                   |           
|                                               |                                           |                          |                                        |           
|Operating facility and equipment, at cost, net |                                           |                          | 83,467,000                             |           
|                                               |                                           |                          |                                        |           
|Other assets                                   |                                           |                          |                                        |           
|                                               | Deferred loan fees, net                   |                          |                                        | 86,000    
|                                               | Escrow account, net of current portion    |                          |                                        |          
|                                               | Gas purchase agreement at fair value      |                          |                                        | 50,779,000
|                                               |                                           |                          |                                        |           
|                                               |                                           |                          | Total other assets                     |           
|                                               |                                           |                          |                                        |           
|                                               |                                           |                          | Total assets                           |           
|                                               |                                           |                          |                                        |           
|Liabilities and Partners' Equity               |                                           |                          |                                        |           
|Current liabilities                            |                                           |                          |                                        |           
|                                               | Current portion of project financing loan |                          | $                                      | 13,724,000
|                                               | Working capital loan                      |                          |                                        | 5,000,000 
|                                               | Payables                                  |                          |                                        |           
|                                               |                                           | Related parties          |                                        |           
|                                               |                                           | Trade and other payables |                                        |           
|                                               |                                           |                          |                                        |           
|                                               |                                           |                          | Total current liabilities              |           
|                                               |                                           |                          |                                        |           
|Commitments and contingencies (Note 6)         |                                           |                          |                                        |           
|Project financing loan, net of current portion |                                           |                          |                                       |           
|Partners' equity                               |                                           |                          | 129,223,000                            |           
|                                               |                                           |                          |                                        |           
|                                               |                                           |                          | Total liabilities and partners' equity |           
|                                               |                                           |                          |                                        |           

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

262

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MARCH POINT COGENERATION COMPANY  STATEMENTS OF INCOME AND COMPREHENSIVE INCOME  For the Years Ended December 31, 2003, 2002 and 2001 (unaudited)

|                                  |                                                                          | 2003                              |   | 2002        |            | 2001 |           
|--------------------------------- | ------------------------------------------------------------------------ | --------------------------------- | - | ----------- | ---------- | ---- | ----------
|
|Operating revenues                |                                                                          |                                   |   |             |            |      |           
|                                  | Sales of energy to Puget Sound Energy                                    |                                   | $ | 64,903,000  |            | $    | 66,893,000
|                                  | Sales of steam to Equilon                                                |                                   |   | 13,699,000  |            |      | 13,884,000
|                                  | Sales of natural gas                                                     |                                   |   |            |            |      |          
|                                  |                                                                          |                                   |   |             |            |      |           
|                                  |                                                                          | Total operating revenues          |   |             | 78,602,000 |      |           
|                                  |                                                                          |                                   |   |             |            |      |           
|Operating expenses                |                                                                          |                                   |   |             |            |      |           
|                                  | Fuel expense                                                             |                                   |   | 45,975,000  |            |      | 31,830,000
|                                  | Plant and other operating expenses                                       |                                   |   | 6,184,000   |            |      | 7,909,000 
|                                  | Depreciation and amortization                                            |                                   |   | 4,783,000   |            |      | 4,813,000 
|                                  | General and administrative expenses                                      |                                   |   | 315,000     |            |      | 363,000   
|                                  |                                                                          |                                   |   |             |            |      |           
|                                  |                                                                          | Total operating expenses          |   |             | 57,257,000 |      |           
|                                  |                                                                          |                                   |   |             |            |      |           
|                                  |                                                                          | Income from operations            |   |             | 21,345,000 |      |           
|                                  |                                                                          |                                   |   |             |            |      |           
|Other expense (income)            |                                                                          |                                   |   |             |            |      |           
|                                  | Interest and other income                                                |                                   |   | (417,000    | )          |      | (400,000  
|                                  | Interest expense                                                         |                                   |   | 638,000     |            |      | 1,240,000 
|                                  |                                                                          |                                   |   |             |            |      |           
|                                  |                                                                          | Total other expense               |   |             | 221,000    |      |           
|                                  |                                                                          |                                   |   |             |            |      |           
|                                  |                                                                          | Net income                        |   |             | 21,124,000 |      |           
|                                  |                                                                          |                                   |   |             |            |      |           
|Other comprehensive income (loss) |                                                                          |                                   |   |             |            |      |           
|                                  | Cumulative effect on prior years of change in accounting for derivatives |                                   |   |            |            |      |          
|                                  | Unrealized gain (loss) arising during the period                         |                                   |   | 31,291,000  |            |      | (958,000  
|                                  | Reclassification adjustment included in net income                       |                                   |   | (10,823,000 | )          |      | (1,788,000
|                                  |                                                                          |                                   |   |             |            |      |           
|                                  |                                                                          | Other comprehensive income (loss) |   |             | 20,468,000 |      |           
|                                  |                                                                          |                                   |   |             |            |      |           
|                                  |                                                                          | Comprehensive income              |   | $           | 41,592,000 |      | $         
|                                  |                                                                          |                                   |   |             |            |      |           

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

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MARCH POINT COGENERATION COMPANY  STATEMENTS OF PARTNERS' EQUITY  For the Years Ended December 31, 2003, 2002, and 2001 (unaudited)

|                                          |  | Equilon
Enterprises
LLC |            | Texaco
March Point
Holdings Inc. |   | San Juan
Energy
Company |   | Total |           
|----------------------------------------- |  | ----------------------- | ---------- | -------------------------------- | - | ----------------------- | - | ----- | ----------
|Balances at December 31, 2000 (unaudited) |  | $                       | 13,911,000 |                                  | $ | 14,023,000              |   | $     | 27,934,000
|Allocation of comprehensive income        |  |                         | 8,936,000  |                                  |   | 9,008,000               |   |       | 17,943,000
|Distributions                             |  |                         | (3,200,000 | )                                |   | (3,225,000              | ) |       | (6,425,000
|                                          |  |                         |            |                                  |   |                         |   |       |           
|Balances at December 31, 2001 (unaudited) |  |                         | 19,647,000 |                                  |   | 19,806,000              |   |       | 39,452,000
|Allocation of comprehensive income        |  |                         | 8,037,000  |                                  |   | 8,101,000               |   |       | 16,138,000
|Distributions                             |  |                         | (3,050,000 | )                                |   | (3,075,000              | ) |       | (6,125,000
|                                          |  |                         |            |                                  |   |                         |   |       |           
|Balances at December 31, 2002             |  |                         | 24,634,000 |                                  |   | 24,832,000              |   |       | 49,465,000
|Allocation of comprehensive income        |  |                         | 10,356,000 |                                  |   | 10,440,000              |   |       | 20,796,000
|Distributions                             |  |                         | (2,814,000 | )                                |   | (2,836,000              | ) |       | (5,650,000
|                                          |  |                         |            |                                  |   |                         |   |       |           
|Balances at December 31, 2003             |  | $                       | 32,176,000 |                                  | $ | 32,436,000              |   | $     | 64,611,000
|                                          |  |                         |            |                                  |   |                         |   |       |           

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

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MARCH POINT COGENERATION COMPANY  STATEMENTS OF CASH FLOWS  For the Years Ended December 31, 2003, 2002 and 2001 (unaudited)

|                                                 |                                                                                  | 2003                               |                                                      | 2002        |           | 2001        |            
|------------------------------------------------ | -------------------------------------------------------------------------------- | ---------------------------------- | ---------------------------------------------------- | ----------- | --------- | ----------- | -----------
|
|Cash flows from operating activities             |                                                                                  |                                    |                                                      |             |           |             |            
|                                                 | Net income                                                                       |                                    | $                                                    | 21,124,000  |           | $           | 35,022,000 
|                                                 | Adjustments to reconcile net income to net cash provided by operating activities |                                    |                                                      |             |           |             |            
|                                                 |                                                                                  | Depreciation and amortization      |                                                      |             | 4,783,000 |             |            
|                                                 |                                                                                  | Loss on disposal of equipment      |                                                      |             | 9,000     |             |            
|                                                 |                                                                                  | Ineffectiveness of cash flow hedge |                                                      |             | (715,000  | )           |            
|                                                 | Changes in operating assets and liabilities                                      |                                    |                                                      |             |           |             |            
|                                                 |                                                                                  | Receivables                        |                                                      |             | (136,000  | )           |            
|                                                 |                                                                                  | Inventory                          |                                                      |             | (399,000  | )           |            
|                                                 |                                                                                  | Payables                           |                                                      |             | 135,000   |             |            
|                                                 |                                                                                  |                                    |                                                      |             |           |             |            
|                                                 |                                                                                  |                                    | Net cash provided by operating activities            |             |           | 24,801,000  |            
|                                                 |                                                                                  |                                    |                                                      |             |           |             |            
|Cash flows from investing activities             |                                                                                  |                                    |                                                      |             |           |             |            
|                                                 | Additions to operating facility and equipment, net                               |                                    |                                                      | (420,000    | )         |             | (839,000   
|                                                 |                                                                                  |                                    |                                                      |             |           |             |            
|Cash flows from financing activities             |                                                                                  |                                    |                                                      |             |           |             |            
|                                                 | Proceeds from working capital loan                                               |                                    |                                                      | 5,000,000   |           |             | 5,000,000  
|                                                 | Payment on project financing loan                                                |                                    |                                                      | (13,684,000 | )         |             | (13,035,000
|                                                 | Payment on working capital loan                                                  |                                    |                                                      | (5,000,000  | )         |             | (5,000,000 
|                                                 | Proceeds from escrow account                                                     |                                    |                                                      | 684,000     |           |             | 652,000    
|                                                 | Distributions to partners                                                        |                                    |                                                      | (11,300,000 | )         |             | (12,250,000
|                                                 |                                                                                  |                                    |                                                      |             |           |             |            
|                                                 |                                                                                  |                                    | Net cash used in financing activities                |             |           | (24,300,000 | )          
|                                                 |                                                                                  |                                    |                                                      |             |           |             |            
|                                                 |                                                                                  |                                    | Net increase (decrease) in cash and cash equivalents |             |           | 81,000      |            
|Cash and cash equivalents                        |                                                                                  |                                    |                                                      |             |           |             |            
|Beginning of year                                |                                                                                  |                                    | 7,285,000                                            |             |           | 7,599,000   |            
|                                                 |                                                                                  |                                    |                                                      |             |           |             |            
|End of year                                      |                                                                                  | $                                  | 7,366,000                                            |             | $         | 7,285,000   |            
|                                                 |                                                                                  |                                    |                                                      |             |           |             |            
|Supplemental disclosure of cash flow information |                                                                                  |                                    |                                                      |             |           |             |            
|Cash payments for interest                       |                                                                                  | $                                  | 590,000                                              |             | $         | 1,428,000   |            

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

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MARCH POINT COGENERATION COMPANY  NOTES TO FINANCIAL STATEMENTS  December 31, 2003 and 2002

1. Nature of Operations

March Point Cogeneration Company (the "Partnership") is a general partnership between Texaco March Point Holdings Inc. ("TMPHI"), an indirect wholly-owned
subsidiary of ChevronTexaco Corporation ("Chevron"), San Juan Energy Company ("SJEC"), an indirect wholly-owned subsidiary of Edison International ("Edison") and Equilon Enterprises LLC (Equilon), a
subsidiary of Shell Oil Products US. The Partnership was organized under California law on July 28, 1989. During the years ended December 31, 2003, 2002 and 2001 (unaudited), the SJEC,
TMPHI and Equilon ownership ratios were 50%, 25.1% and 24.9%, 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 producing 60 megawatts and 156,000 pounds per hour.

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 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

The Partnership considers short-term temporary cash investments with an original maturity of three months or less to be cash equivalents. The carrying
amount of cash and cash equivalents approximates fair value because of the short maturity of these instruments. The short-term investments are held by Chevron on behalf of the Partnership.

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Inventory

The Partnership's inventory consists of spare parts, materials and supplies and is valued at the lower of average cost or market.

Operating Facility and Equipment

The Facility and related 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. The Facility and related equipment are being depreciated on a straight-line basis, over 30 years, the estimated life of the
Facility. Computer equipment is depreciated on a straight-line basis, over 3 years and other property and equipment is depreciated over 5 years.

Expenditures
for maintenance, repairs and renewals are expensed as incurred. Expenditures for additions and improvements are capitalized. The operating facility requires major
maintenance, including inspections and overhauls, on a periodic basis. These costs are also expensed 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 to be measured by the amount that the carrying amount
of the assets exceeds the fair value of the assets.

Deferred Loan Fees

All legal and financial fees associated with the Loan and Credit Agreement (Note 4) were deferred and are being amortized, using the effective interest
method, over the term of the loan. Deferred loan fees are presented net of accumulated amortization of $1,953,000 and $1,886,000 at December 31, 2003 and 2002, respectively. Amortization
expense was approximately $67,000, $109,000 and $147,000 in 2003, 2002 and 2001 (unaudited), respectively.

Revenue Recognition

Revenue is recognized as the product being sold is delivered.

Income Taxes

The Partnership's income is included in the income tax returns of the partners. Therefore, no provision (benefit) for income taxes has been included in the
accompanying financial statements.

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.

In
assessing the fair value of the Partnership's derivative instruments, the Partnership uses a variety of methods and assumptions that are based on market conditions and risks existing
at each valuation date. The fair value of the commodity contracts considers quoted market prices, time value, volatility of the underlying commodities and other factors. The value may not be
representative of actual gains and

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losses
that will be recorded when these instruments mature due to future fluctuations in the markets in which they are traded.

Risk Management and Hedging Activities

The Partnership's primary market risk exposures arise from fluctuations in the price of natural gas. Management manages these risks in part by entering into
forward natural gas purchase contracts.

Effective
January 1, 2001 the Partnership adopted Financial Accounting Standards Board Statement No. 133 ("SFAS 133"),Accounting for
Derivative Instruments and Hedging Activities. 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 Partnership's energy and capacity sales commitments qualify for the normal purchases and normal sales exception provided by SFAS 133 and related
guidance issued by the Derivatives Implementation Group ("DIG"). 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. In April 2003, the Financial Accounting Standards Board
issued SFAS No. 149 ("SFAS 149"),Amendment of Statement 133 on Derivative Instruments and Hedging Activities.SFAS 149 changed the
guidance related to the application of the normal purchases and normal sales exception to electricity contracts. This change had no impact on the designation of the Partnership's electricity contracts
as normal. Management also determined that the Partnership's steam sales do not meet the definition of a derivative and are, therefore, not subject to the requirements of the standard.

The
Partnership has entered into a long-term agreement to purchase natural gas from TM Star Fuel Company ("TM Star"), a general partnership between Texaco Cogeneration Fuel
Company, an indirect wholly owned subsidiary of Chevron, and Southern Sierra Gas Company, an affiliate of Edison. As of the date of adoption of SFAS 133, management accounted for this contract
as a normal purchase. However, as a result of subsequent interpretations by the DIG, management determined that the contract does not qualify for the normal purchase exception because the price of
fuel purchased under the agreement is indexed to a broad inflation index; therefore, the price paid is not "clearly and closely related" to the cost of natural gas. Management has designated this
contract as a cash flow hedge (Note 5). As of July 1, 2001, the Partnership recorded an asset of $24,584,000 (unaudited) and a related increase in other comprehensive income as the
cumulative effect of adoption of the DIG interpretation.

New Accounting Pronouncements

On January 1, 2003, the Partnership adopted Financial Accounting Standards Board Statement No. 143 ("SFAS 143"), Accounting for Asset Retirement
Obligations, which requires entities to record the fair value of a liability for an asset retirement obligation (ARO) 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. In accordance with its site lease agreement (Note 5), the Partnership is required to restore the site or
transfer ownership of the Facility to the lessor at the termination of the lease. The lessor can decline to accept ownership, thereby requiring site restoration. Although the Partnership could be

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required
to restore the site, management believes that this is remote, due to the isolated location and the other needs for the facility and equipment. Therefore, no asset retirement obligation was
recorded upon adoption of SFAS 143. Management will continue to assess this exposure.

3. Operating Facility and Equipment

The Operating Facility and Equipment consists of the following:

2003

2002Operating facility

$
133,576,000

$
133,109,000Other property and equipment


2,766,000


2,639,000136,342,000


135,748,000Accumulated depreciation


(53,258,000
)

(48,588,000
)Construction in progress


383,000


612,000$
83,467,000

$
87,772,000


Depreciation expense was approximately $4,716,000, $4,704,000 and $4,674,000 in 2003, 2002 and 2001 (unaudited), respectively.

4. 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% in 2003 and 2002, or at the base rate, per
annum. The interest rate on the outstanding loan balances at December 31, 2003 and 2002 was 2.47% and 2.73%, 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.

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 balance outstanding. The balance of the escrow account as of December 31, 2003 and 2002 was $936,000 and $1,620,000, respectively.

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5. Related-Party Transactions

Operating expenses include the following amounts incurred to related parties:

2003

2002

2001(unaudited)Fuel expenseTM Star

$
21,456,000

$
20,782,000

$
21,897,000Equilon


11,455,000


11,875,000


13,697,000Plant and other operating expensesEquilon and subsidiaries


1,407,000


2,020,000


1,834,000Chevron and subsidiaries


1,309,000


1,281,000


1,281,000$
35,627,000

$
35,958,000

$
38,709,000


Construction, Operating and Other Costs

Edison, Equilon, and Chevron as well as their affiliates and subsidiaries are reimbursed for design, construction, operation and other costs incurred on behalf of
the Partnership.

Land Lease

The Partnership entered into a 20-year land lease with Chevron on January 3, 1991, which has been assigned to Equilon. Costs incurred under the
land lease for 2003, 2002 and 2001 (unaudited) were nominal.

Fuel Sales and Purchase Agreements

TM Star Contract

The Partnership has a long-term agreement to purchase gas from TM Star. 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 ($2.50 per MMBtu as of December 31, 2003). 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 (Note 6), or the written mutual consent of the parties. The agreement
may be extended thereafter, on a yearly basis, upon mutual written consent.

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 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
sulfur distillate fuel purchases from Equilon, which totaled $2,576,000 during the year ended December 31, 2001 (unaudited).

Cash Flow Hedge

As discussed in Note 2, 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 sheets. Amounts deferred in accumulated other comprehensive income are

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reclassified
into earnings as fuel is purchased under the TM Star agreement. During the years ended December 31, 2003, 2002 and 2001 (unaudited), $715,000, $14,228,000 and $847,000 of income
representing hedge ineffectiveness was recorded as a reduction of fuel expenses, respectively.

Equilon Refinery Fuels Supply Agreement

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.

Under
typical operating conditions, approximately 80% 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% 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.

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.

Related Parties Payables

The related parties payables balances consist of the following:

2003

2002Equilon and subsidiaries

$
2,518,000

$
2,502,000Chevron and subsidiaries


222,000


215,000TM Star


1,827,000


1,800,000Total related parties payables

$
4,567,000

$
4,517,000


6. 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

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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 termination clauses 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, 2003, the Partnership would be liable for approximately $129,561,000. 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.

Credit Risk

The Partnership is exposed to credit risk related to potential nonperformance by the counterparties to its energy and steam sales. The Partnership's revenues are
concentrated with Puget Sound Energy and Equilon. Sales to Puget Sound Energy comprised 83%, 83% and 82% of total revenues during each of the years ended December 31, 2003, 2002 and 2001
(unaudited), respectively. Sales to Equilon comprised 17%, 17% and 16% of total revenues during each of the years ended December 31, 2003, 2002 and 2001 (unaudited), respectively. Due to this
concentration of credit risk, the Partnership's liquidity could be impacted by financial difficulties experienced by Puget Sound Energy and Equilon.

The
Partnership is also exposed to credit risk related to potential nonperformance by the counterparties to its fuel purchases. The Partnership's purchases are concentrated with TM Star.
Fuel purchases from TM Star comprised 46%, 45% and 41% of fuel expenses during each of the years ended December 31, 2003, 2002 and 2001 (unaudited), respectively.

7. Subsequent Event

During 2003, the Partnership entered into a Merger Agreement with TM Star. The merger was consummated on January 16, 2004. Under the terms of the
agreement, the Partnership is the surviving partnership and TM Star ceased to exist. The percentage ownership of the Partnership remains unchanged under the new entity structure. However, due to
differences in ownership between TM Star and the Partnership, a subsidiary of Chevron made a capital contribution to TM Star and TM Star made a payment to Equilon in the amount of $3,968,000. There
was no other cash exchanged as a result of the merger.

TM
Star's sole business was comprised of the fuel supply agreement with the Partnership and three fuel purchase agreements with outside suppliers. As a result of the merger, the gas
supply agreement with TM Star was terminated and the Partnership acquired TM Star's three fuel purchase agreements. There were no other assets or liabilities transferred as of the purchase date. Key
terms of these new contracts include the following:

Counterparty

Daily Quantity

Expiration

Pricing

Price as of
12/31/2003Barrett Resources Corporation ("Barrett")

5,000 MMBtu

June 30, 2011

Effective 1993, $1.80 per MMBtu adjusted annually by the GDP

$2.21 per MMBtuCanwest Gas Supply Inc. ("Canwest")

10,000 MMBtu

March 31, 2008

Effective 1993, $1.83 per MMBtu adjusted annually by the GDP

$2.71 per MMBtuTexaco Exploration and Production ("TEPI")

2,500 MMBtu

December 31, 2007

Effective 1992, $1.80 per MMBtu adjusted annually by the GDP

$2.22 per MMBtu


272

---

TEPI is an indirect wholly owned subsidiary of Chevron. After the contract expiration dates, the Barrett and Canwest contracts will automatically
extend on a year-to-year basis until cancelled by either party with written notice as required by the contract. The TEPI contract may be extended on an annual basis with
written agreement by both parties.

The
contracts are accounted for as derivatives in accordance with SFAS 133. As of the acquisition date, the fair value of the contracts was $44,326,000, which is $11,891,000 lower
than the $56,218,000 value of the cancelled TM Star contract. The difference in value will be accounted for as an adjustment to Partners' equity. Management has designated the gas supply agreements as
cash flow hedges of the Partnership's exposure to fluctuations in the price of natural gas. As a result of this designation, future changes in the fair value associated with the effective portion of
the hedges will be recorded in other comprehensive income. Any hedge ineffectiveness will be included in Fuel expense as part of the Statements of Income.

As
the cancelled contract was previously accounted for as a cash flow hedge (Note 5), amounts related to the cancelled TM Star contract that were recorded in accumulated other
comprehensive income will be recognized into income over the period that the underlying purchase of gas is expected to occur. It is expected that within the next twelve months, losses of approximately
$1,056,000 will be reclassified from accumulated other comprehensive income to earnings.

Amendment to Loan and Credit Agreement

As an incentive to the Partnership's lenders to grant consents and waivers to the Loan and Credit Agreement (Note 4) with regards to the merger, the
Partnership agreed to additional debt covenants. The additional covenants restrict distributions to the owners until the Partnership fully funds a debt service reserve account with an amount equal to
all scheduled payments of principal, interest and fees due for the coming six months. Distributions are also restricted unless the Partnership maintains a debt service coverage ratio, as defined, of
greater than or equal to 1.4. The Partnership is currently deferring distributions until such restrictions are met.

273

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Report of Independent Auditors

To
the Board of Directors of
EcoEléctrica Holdings, Ltd. and Subsidiaries

In
our opinion, the accompanying consolidated balance sheets and the related consolidated statements of income, comprehensive income, 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, 2003 and 2002, and the
results of its operations and its 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.

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
January 27, 2004

274

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ECOELÉCTRICA HOLDINGS, LTD. AND SUBSIDIARIES  CONSOLIDATED BALANCE SHEETS  December 31, 2003 and 2002

|                                           |                                                                                                                      | 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 2003 and 2002 |                            
|                                           |                                                                                                                      | Insurance claims                                                         |                            
|                                           |                                                                                                                      | Other, including amounts due from affiliates of $119 in 2002             |                            
|                                           | Note from Puerto Rico Electric Power Authority                                                                       |                                                                          |                            
|                                           | Inventories                                                                                                          |                                                                          |                            
|                                           | Prepaid expenses                                                                                                     |                                                                          |                            
|                                           |                                                                                                                      |                                                                          |                            
|                                           |                                                                                                                      |                                                                          | Total current assets       
|                                           |                                                                                                                      |                                                                          |                            
|Noncurrent Assets                          |                                                                                                                      |                                                                          |                            
|                                           | Restricted cash                                                                                                      |                                                                          |                            
|                                           | Note from Puerto Rico Electric Power Authority                                                                       |                                                                          |                            
|                                           | Property, plant and equipment, net                                                                                   |                                                                          |                            
|                                           | Debt issue costs, net                                                                                                |                                                                          |                            
|                                           | Deferred tax asset                                                                                                   |                                                                          |                            
|                                           |                                                                                                                      |                                                                          |                            
|                                           |                                                                                                                      |                                                                          | Total noncurrent assets    
|                                           |                                                                                                                      |                                                                          |                            
|Total assets                               |                                                                                                                      | $                                                                        | 813,609                    
|                                           |                                                                                                                      |                                                                          |                            
|Liabilities and Stockholders' 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                          |                                                                                                                      |                                                                          | 750,726                    
|                                           |                                                                                                                      |                                                                          |                            
|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 $4,295 and $5,704 in 2003 and 2002, respectively |                                                                          |                            
|                                           | Retained earnings                                                                                                    |                                                                          |                            
|                                           |                                                                                                                      |                                                                          |                            
|Total stockholders' equity                 |                                                                                                                      |                                                                          | 62,883                     
|                                           |                                                                                                                      |                                                                          |                            
|Total liabilities and stockholders' equity |                                                                                                                      | $                                                                        | 813,609                    
|                                           |                                                                                                                      |                                                                          |                            

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

275

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ECOELÉCTRICA HOLDINGS, LTD. AND SUBSIDIARIES  CONSOLIDATED STATEMENTS OF INCOME  For the Years Ended December 31, 2003, 2002 and 2001

|                                   |                                             | Years Ended December 31, |        
|---------------------------------- | ------------------------------------------- | ------------------------ | -------
|
|
|
|Revenues                           |                                             | $                        | 232,979
|                                   |                                             |                          |        
|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                    |                          |        
|                                   |                                             |                          |        
|                                   |                                             |                          | 171,767
|                                   |                                             |                          |        
|Operating income                   |                                             |                          | 61,212 
|                                   |                                             |                          |        
|Other (income) expense:            |                                             |                          |        
|                                   | Interest expense                            |                          |        
|                                   | Interest income                             |                          |        
|                                   | Other                                       |                          |        
|                                   |                                             |                          |        
|                                   |                                             |                          | 42,195 
|                                   |                                             |                          |        
|Income before income tax provision |                                             |                          | 19,017 
|Deferred income tax provision      |                                             |                          | (1,452 
|                                   |                                             |                          |        
|Net income                         |                                             | $                        | 17,565 
|                                   |                                             |                          |        

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

276

---



ECOELÉCTRICA HOLDINGS, LTD. AND SUBSIDIARIES  CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME  For the Years Ended December 31, 2003, 2002 and 2001

|                                   |                                                                                                                                               | Years Ended December 31, |       
|---------------------------------- | --------------------------------------------------------------------------------------------------------------------------------------------- | ------------------------ | ------
|
|
|
|Net income                         |                                                                                                                                               | $                        | 17,565
|                                   |                                                                                                                                               |                          |       
|Other comprehensive income (loss): |                                                                                                                                               |                          |       
|                                   | Cumulative effect on prior years of change in the method of accounting for interest rate protection agreements                                |                          |       
|                                   | Unrealized gain (loss) on interest rate protection agreements, net of deferred income tax of $4,295 and $5,704 in 2003 and 2002, respectively |                          |       
|                                   | Reclassification adjustment for losses included in net income                                                                                 |                          |       
|                                   |                                                                                                                                               |                          |       
|                                   |                                                                                                                                               |                          | 18,720
|                                   |                                                                                                                                               |                          |       
|Comprehensive income (loss)        |                                                                                                                                               | $                        | 36,285
|                                   |                                                                                                                                               |                          |       

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

277

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ECOELÉCTRICA HOLDINGS, LTD. AND SUBSIDIARIES  CONSOLIDATED STATEMENTS OF CHANGES IN STOCKHOLDERS' EQUITY  For the Years Ended December 31, 2003, 2002 and 2001

|                                         |                                                                                                                     | Common Stock
Class A |   | Common Stock
Class B |   |   |     |   |   |   |   |   |       
|---------------------------------------- | ------------------------------------------------------------------------------------------------------------------- | -------------------- | - | -------------------- | - | - | --- | - | - | - | - | - | ------
|
|
|
|
|Balance at January 1, 2001 (unaudited)   |                                                                                                                     | 100                  |   | $                    |  |   | 100 |   | $ |  |   | $ | 67,000
|                                         | Net income                                                                                                          |                      |  |                      |   |  |     |  |   |   |  |   |       
|                                         | Cumulative effect to January 1, 2001, of change in the method of accounting for interest rate protection agreements |                      |  |                      |   |  |     |  |   |   |  |   |       
|                                         | Unrealized loss on interest rate protection agreements                                                              |                      |  |                      |   |  |     |  |   |   |  |   |       
|                                         |                                                                                                                     |                      |   |                      |   |   |     |   |   |   |   |   |       
|Balance at December 31, 2001 (unaudited) |                                                                                                                     | 100                  |   |                      |  |   | 100 |   |   |  |   |   | 67,000
|                                         | Net income                                                                                                          |                      |  |                      |   |  |     |  |   |   |  |   |       
|                                         | Unrealized loss on interest rate protection agreements, net of tax of $5,704                                        |                      |  |                      |   |  |     |  |   |   |  |   |       
|                                         |                                                                                                                     |                      |   |                      |   |   |     |   |   |   |   |   |       
|Balance at December 31, 2002             |                                                                                                                     | 100                  |   |                      |  |   | 100 |   |   |  |   |   | 67,000
|                                         | Net income                                                                                                          |                      |  |                      |   |  |     |  |   |   |  |   |       
|                                         | Unrealized gain on interest rate protection agreements, net of tax of $4,295                                        |                      |  |                      |   |  |     |  |   |   |  |   |       
|                                         |                                                                                                                     |                      |   |                      |   |   |     |   |   |   |   |   |       
|Balance at December 31, 2003             |                                                                                                                     | 100                  |   | $                    |  |   | 100 |   | $ |  |   | $ | 67,000
|                                         |                                                                                                                     |                      |   |                      |   |   |     |   |   |   |   |   |       

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

278

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ECOELÉCTRICA HOLDINGS, LTD. AND SUBSIDIARIES  CONSOLIDATED STATEMENTS OF CASH FLOWS  For the Years Ended December 31, 2003, 2002 and 2001

|                                                                                  |                                                                            | 2003                                     |                                           | 2002    |         | 2001   |       
|--------------------------------------------------------------------------------- | -------------------------------------------------------------------------- | ---------------------------------------- | ----------------------------------------- | ------- | ------- | ------ | ------
|
|
|Cash flow from operating activities:                                              |                                                                            |                                          |                                           |         |         |        |       
|Net income                                                                        |                                                                            | $                                        | 17,565                                    |         | $       | 10,636 |       
|                                                                                  |                                                                            |                                          |                                           |         |         |        |       
|Adjustments to reconcile net income to net cash provided by operating activities: |                                                                            |                                          |                                           |         |         |        |       
|                                                                                  | Depreciation and amortization                                              |                                          |                                           | 32,993  |         |        | 31,952
|                                                                                  | Provision for doubtful accounts                                            |                                          |                                           | 1,740   |         |        | 2,231 
|                                                                                  | Deferred income tax provision                                              |                                          |                                           | 1,452   |         |        | 1,209 
|                                                                                  | Loss on disposal of fixed assets                                           |                                          |                                           | 12      |         |        |      
|                                                                                  | Changes in operating assets and liabilities that increase (decrease) cash: |                                          |                                           |         |         |        |       
|                                                                                  |                                                                            | Receivables                              |                                           |         | (13,645 | )      |       
|                                                                                  |                                                                            | Inventories                              |                                           |         | 4,603   |        |       
|                                                                                  |                                                                            | Prepaid expenses                         |                                           |         | (1,347  | )      |       
|                                                                                  |                                                                            | Accounts payable and accrued liabilities |                                           |         | 5,274   |        |       
|                                                                                  |                                                                            | Subordinated accrued interest payable    |                                           |         | 6,756   |        |       
|                                                                                  |                                                                            |                                          |                                           |         |         |        |       
|                                                                                  |                                                                            |                                          | Total adjustments                         |         |         | 37,838 |       
|                                                                                  |                                                                            |                                          |                                           |         |         |        |       
|                                                                                  |                                                                            |                                          | Net cash provided by operating activities |         |         | 55,403 |       
|                                                                                  |                                                                            |                                          |                                           |         |         |        |       
|Cash flow from investing activities:                                              |                                                                            |                                          |                                           |         |         |        |       
|                                                                                  | Capital expenditures                                                       |                                          |                                           | (23,257 | )       |        | (6,901
|                                                                                  | Restricted cash                                                            |                                          |                                           | (5,762  | )       |        | (8,561
|                                                                                  | Proceeds from sale of fixed assets                                         |                                          |                                           | 3       |         |        |      
|                                                                                  |                                                                            |                                          |                                           |         |         |        |       
|                                                                                  |                                                                            | Net cash used in investing activities    |                                           |         | (29,016 | )      |       
|                                                                                  |                                                                            |                                          |                                           |         |         |        |       
|Cash flow from financing activities:                                              |                                                                            |                                          |                                           |         |         |        |       
|                                                                                  | Payments of principal on loans payable                                     |                                          |                                           | (18,695 | )       |        | (8,915
|                                                                                  | Payments of principal on subordinated debt                                 |                                          |                                           |        |         |        | (2,128
|                                                                                  | Draws on loans payable                                                     |                                          |                                           |        |         |        |      
|                                                                                  | Payments on working capital facilities                                     |                                          |                                           |        |         |        |      
|                                                                                  |                                                                            |                                          |                                           |         |         |        |       
|                                                                                  |                                                                            | Net cash used in financing activities    |                                           |         | (18,695 | )      |       
|Net increase (decrease) in cash and cash equivalents                              |                                                                            |                                          | 7,692                                     |         |         | (6,871 | )     
|Cash and cash equivalents, beginning of the year                                  |                                                                            |                                          | 10,025                                    |         |         | 16,896 |       
|                                                                                  |                                                                            |                                          |                                           |         |         |        |       
|Cash and cash equivalents, end of the year                                        |                                                                            | $                                        | 17,717                                    |         | $       | 10,025 |       
|                                                                                  |                                                                            |                                          |                                           |         |         |        |       
|Supplemental cash flow information:                                               |                                                                            |                                          |                                           |         |         |        |       
|                                                                                  | Interest paid                                                              |                                          | $                                         | 40,221  |         | $      | 48,477
|                                                                                  |                                                                            |                                          |                                           |         |         |        |       
|                                                                                  | Income tax paid                                                            |                                          | $                                         |        |         | $      |      
|                                                                                  |                                                                            |                                          |                                           |         |         |        |       

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

279

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ECOELÉCTRICA HOLDINGS, LTD. AND SUBSIDIARIES  NOTES TO CONSOLIDATED FINANCIAL STATEMENTS  December 31, 2003, 2002 and 2001 (unaudited)

1. Organization

EcoEléctrica Holdings, Ltd. ("Holdings" or "the Company"), a Cayman Islands company, is the 99% limited partner of
EcoEléctrica, L.P. (the "Partnership") and owns 100% of EcoEléctrica, Ltd., also a Cayman Islands company, which is the 1% general partner of
EcoEléctrica, L.P. Holdings is 50% owned by Edison Mission Energy del Caribe, a Cayman Islands company 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 Buenergía Gas & Power Ltd. ("Buenergía"), a Cayman Islands
company, which in turn is wholly-owned by Invergas Puerto Rico, S.A., a subsidiary of Gas Natural SDG, S.A. ("GN").

EcoEléctrica,
L.P. (the "Partnership") 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 auxiliary assets (the "Plant") in the Commonwealth of Puerto Rico. The electricity generated is sold to the Puerto Rico Electric Power Authority ("PREPA"), a Commonwealth of Puerto Rico
government instrumentality and one of the largest electric utilities in the United States and its territories, among municipal electric utilities.

On
October 30, 2003 GN purchased Enron's share in Buenergía for $177 million in an auction conducted by the Federal Bankruptcy Court, District of New York.
As part of this purchase GN guaranteed the Partnership's Operations and Fuel Management Agreement and the LPG Storage and Services Agreement described in Note 3, in addition to assuming certain
other guarantees and obligations.

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.



The accompanying consolidated financial statements, which include Holdings and its subsidiaries EcoEléctrica, 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.



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.



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.

280

---



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. The fair value of interest rate swaps is determined based on dealer quotes, generally the counterparty, or discounted cash flow
models considering the current rate offered on similar instruments.



For the purpose 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.



Revenue billed is recorded as a current account receivable net of amounts in dispute with PREPA based on management's estimate of realizability.



Inventories are stated at the lower of cost (determined on a first-in, first-out basis) or market.



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 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 the same nature, generally 1.5 to 3 years) while regular maintenance
is expensed as incurred. When property is retired or sold, the cost and the related accumulated depreciation are removed from the accounts and any resulting gain or loss is credited or charged to
operations.



Holdings and its consolidated subsidiaries evaluate their long-lived assets considering continued operating losses or significant and
long-term changes in industry or operating 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 2003, 2002 and 2001.

281

---



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 taxes, the
Partnership recognizes deferred tax assets and liabilities for the expected future tax consequences attributable to differences between tax bases 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 enactment of changes in the tax law or rates. A valuation allowance is recognized
for any deferred tax asset which, based on management's evaluation, is more likely than not that some portion or all of the deferred tax asset will not be realized.



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).



The Partnership recognizes all derivatives as either assets or liabilities in the statement of financial position and measures 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 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 as a component of the stockholders' equity net of related deferred taxes, through "Other Comprehensive
Loss."

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.



Statement of Financial Accounting Standards (SFAS) No. 143,"Accounting for Asset
Retirement Obligations,"addresses accounting and reporting for legal obligations associated with the retirement of tangible long-lived
assets and the associated asset retirement costs. This statement became effective for fiscal years beginning after June 15, 2002. The adoption of this statement did not have a significant
effect in Holdings financial statements.

SFAS No. 146, "Accounting for Costs Associated with Exit or Disposal Activities,"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 did not have a significant effect in Holdings financial statements.

SFAS No. 149, "Amendment of Statement 133 on Derivative Instruments and Hedging Activities,"amends and clarifies financial
accounting and reporting for derivative instruments, including certain

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derivative
instruments embedded in other contracts (collectively referred to as derivatives) and for hedging activities under SFAS No. 133, "Accounting for Derivative Instruments and Hedging
Activities." SFAS No. 149 (1) clarifies under what circumstances a contract with an initial net investment meets the characteristic of a derivative discussed in paragraph 6(b) of
SFAF No. 133, (2) clarifies when a derivative contains a financing component, (3) amends the definition of an underlying to conform it to language used in Financial Accounting
Standards Interpretation (FIN) No. 45, "Guarantor's Accounting and Disclosure Requirements for Guarantees, Including Indirect Guarantees of Indebtedness of Others", and (4) amends
certain other existing pronouncements. Those changes will result in more consistent reporting of contracts as either derivatives or hybrid instruments. SFAS No. 149 is effective for contracts
entered into or modified after June 30, 2003, with certain exceptions, and for hedging relationships designated after June 30, 2003. In addition, except for certain situations, all
provisions of this Statement are to be applied prospectively. The adoption of SFAS No. 149 did not have an impact in Holdings' financial condition or results of operations.

SFAS No. 150, "Accounting for Certain Financial Instruments with Characteristics of Both Liabilities and Equity,"establishes how
an issuer classifies and measures certain financial instruments with characteristics of both liabilities and equity. It requires that an issuer classify certain financial instruments, including some
previously classified as equity, as a liability (or an asset in some
circumstances) because the financial instrument embodies an obligation of the issuer. Specifically, SFAS No. 150 requires that financial instruments issued in the form of shares that are
mandatorily redeemable, financial instruments that embody an obligation to repurchase the issuer's equity shares or are indexed to such an obligation, or financial instruments that embody an
unconditional obligation or a conditional obligation that can be settled in certain ways, be classified as liabilities. SFAS No. 150 is effective for financial instruments entered into or
modified after May 31, 2003. The adoption of SFAS No. 150 did not have an impact in Holdings' financial statements.

FIN No. 45, "Guarantor's Accounting and Disclosure Requirements for Guarantees, Including Indirect Guarantees of Indebtness of
Others,"requires a guarantor to recognize, at the inception of a guarantee, a liability for the fair value of the obligation undertaken in issuing the guarantee. The
provisions for initial recognition and measurement were effective on a prospective basis for guarantees that were issued or modified after December 31, 2002. The adoption of this interpretation
did not have a material impact in Holdings' financial statements.

FIN No. 46, "Consolidation of Variable Interest Entities,"as revised in December 2003, applies to variable interest
entities that are commonly referred to as special-purpose entities for periods ending after December 15, 2003 and for all other types of variable interest entities for periods ending after
March 15, 2004. It requires the consolidation of a variable interest entity (as defined) by its primary beneficiary. Primary beneficiaries are those companies that are subject to a majority of
the risk of loss or entitled to receive a majority of the variable interest entity's residual returns, or both. The adoption of the Statement will not have a significant effect on Holdings' financial
statements.

3. Agreements



On March 10, 1995, the Partnership and PREPA entered into a power purchase contract (the PPA) under which PREPA is required 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 maintains a minimum working capital of $20 million by the end of the third year after the COD and thereafter. A portion of the minimum
working capital

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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, 2003, 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, 2003, 2002 and 2001 were as follows (in thousands):

2003

2002

2001Energy

$
105,673

$
116,500

$
101,960Capacity


127,306


127,932


131,477$
232,979

$
244,432

$
233,437




The Partnership entered into an Administrative Services Agreement as of October 31, 1997, with EME (Administrative Manager), 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 $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 $905,000, $876,000 and $1,386,000 for the years ended December 31, 2003,
2002, 2001.



The Partnership has entered into an Operation, Maintenance and Fuel Management Agreement dated as of October 31, 1997 (the OMF Agreement) with EI Puerto
Rico Operations Inc. (OMF Manager), an indirect 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. This Agreement was transferred to GN as part of the acquisition of the Enron participation in Buenergía.

The
Partnership agreed to pay the OMF Manager certain reimbursable costs, 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 $1,520,000, $1,201,000 and $885,000
for the years ended December 31, 2003, 2002 and 2001, respectively.



The Partnership entered into an LPG Storage and Service Agreement (the Agreement) dated as of October 31, 1997, with the ProCaribe Division of the Protane
Corporation (ProCaribe), an indirect wholly-owned subsidiary of Enron. 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 CPI
as compared to the January 1, 1997 index. ProCaribe provided services and charged reimbursable incremental costs to the Partnership under the Agreement amounting to approximately $702,000,
$817,000 and $625,000 for the years ended December 31, 2003, 2002 and 2001.

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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 during the year
ended December 31, 2001. During 2002 ProCaribe purchased LPG from the Partnership for approximately $118,800. In September 2003, the assets of ProCaribe were acquired by Terminal
Acquisition Company (TAC), a subsidiary of Empire Gas Company, a Puerto Rico Corporation. As result of the acquisition TAC assumed the obligations under the LPG Storage and Services Agreement.



The Partnership entered into an 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 supply of LNG, 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, and availability demand charges regardless of actual LNG deliveries. Commodity and demand charges from Tractebel for the years ended
December 31, 2003, 2002 and 2001 were as follows (in thousands):

2003

2002

2001Commodity

$
79,267

$
89,589

$
82,447Demand


23,452


25,546


16,936$
102,719

$
115,135

$
99,383


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 provided 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.

On
April 8, 2003, the Partnership and Tractebel signed a second Letter Agreement that amended the LNG supply agreement for the year 2004. This Letter Agreement provides for 100%
supply of LNG to the Partnership, a thirty eight (38) cents commodity price reduction and the elimination of the commodity surcharge, all for the year 2004.



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 subordinated indebtness account shall be used for principal payments on the notes payable to GN and EME. 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 into 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

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Security
Letter of Credit. The Guarantee reserve is a cash deposit with a surety 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 interruption. The fuel supply interruption reserve should increase on a quarterly basis as established in the Credit Agreement (Note 10).

Effective
September 2003, the Lenders agreed that a cash reserve for income tax payments was not necessary until actual income tax payments are made. The Partnership agreed to
convert the income tax reserve to an insurance reserve. The insurance reserve is for $3 million and should be used by the
Partnership to cover the costs of uninsured events related to damages to the combustion turbines caused by transition pieces. This insurance reserve should be reduced to $500,000 upon signing of the
Operations, Parts and Services Agreement currently being negotiated with the manufacturer of the equipment.

As
of December 31, 2003 and 2002 the balances of the reserves were as follows (in thousands):

2003

2002Current portion:Interest reserve

$
34

$
59Principal reserve


2


25Major maintenance reserve


599


2,323Construction reserve





1,409Distribution reserve


2


4,490Subordinated indebtedness


9,525


Collateral reserve


3,480


2,282Guarantee reserve


559


500$
14,201

$
11,088Non-current portion:Insurance reserve

$
3,006

$
2,696Fuel management reserve


4,824


2,485$
7,830

$
5,181


286

---





The Partnership entered into interest rate swap agreements to fix the interest rates on its loans payable. Interest rate swaps are agreements to exchange interest
rate payment streams based on a notional principal amount. The fair value of interest rates 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.

As
of December 31, 2003 and 2002, the Partnership had outstanding interest rate swap agreements, with notional amounts of approximately $450,400,000 and $464,421,000,
respectively. The weighted average rate paid and received on these agreements was 6.383% and 1.23237% in 2003 and 6.383% and 1.90237% in 2002. The net interest rate differentials paid, recorded as
adjustments to interest expense, amounted to approximately $23,801,900 for the year ended December 31, 2003 and approximately $21,287,000 for the year ended December 31, 2002. No hedge
ineffectiveness has been recognized because this hedge is deemed to be 100% effective.

At
December 31, 2003 and 2002, the Interest Rate Protection Agreements mature as follows:

|               |  |            |  |            |  | 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, 2003 and 2002 was $61,354,000 and $81,483,000. As of December 31, 2003 and 2002, the loss deferred in
accumulated other comprehensive income expected to be reclassified to income within the next year amounts to $21,712,000 and $23,100,000, respectively.

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 interpretation of various contract provisions. The largest 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, 2003 and 2002, $28,257,000 and $20,903,000 of the receivables from PREPA were under dispute for which a bad debt allowance of $7,392,000
and $5,698,000 has been provided based on management's estimate of realizability.

5. Insurance Claims Receivable

During 2002, the Partnership suffered losses due to several mechanical failures on its combustion turbines. The Partnership filed claims related to year 2002
under the property damage policy. One of the claims was related to failures in the combustion turbine stator and transition pieces of turbine #2,

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---

for
which a claim of approximately $1,764,000 was recorded as of December 31, 2003. A second claim was filed due to failures in the combustion turbine transition pieces of turbine #1 for
approximately $1,916,000. As of December 31, 2003, $352,000 were collected on these claims. As these claims have been settled with the insurance company for the amount recorded, management
believes that no reserve is necessary.

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 2003 and 2002, due to the fact that the 3%
exceeded the LIBOR rate.

7. Inventories

As of December 31, 2003 and 2002, inventories consist of the following (in thousands):

2003

2002Liquefied natural gas (LNG)

$
11,838

$
5,786Liquefied petroleum gas (LPG)


2,570


2,779Fuel oil No. 2


3,852


4,006Spare parts and supplies, including $13,481, of inventory in transit in 2002


19,063


29,353$
37,323

$
41,924


8. Property, Plant and Equipment

As of December 31, property, plant and equipment consist of the following:

Estimated
Useful Lives

2003

2002(in years)

(in thousands)Machinery and equipment

35

$
447,846

$
447,442LNG and LPG facilities and equipment

22 - 50


209,264


209,064Buildings

30


18,556


18,556Major maintenance expenditures

1.5 - 3


51,649


29,447Fuel oil facilities

50


2,945


2,945Furniture and fixtures

10


557


557Leasehold improvements

4


28


Vehicles and equipment

3


246


272731,091


708,283Less: Accumulated depreciation and amortization




(97,215
)

(66,902
)633,876


641,381Land and land improvements




5,350


5,350Construction in progress




993


571$
640,219

$
647,302


9. Working Capital Facilities

As of December 31, 2000, the Partnership had drawn $48,000,000 under the Working Capital facilities to fund the ongoing working capital needs, primarily
fuel expenses, which were not expected

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---

to
match the timing of the Partnership's revenues on a monthly basis. This working capital facility consists of two lines of 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 GN. Both lines of credit of $9,000,000 were paid in full during 2001.

Draws
on the Working Capital facility of $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 a 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, the $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 10). The $30,000,000 Working Capital facilities mature on June 15, 2005, has a commitment fee of .375%, and bears interest at LIBOR (1.8125% and
1.40%, at December 31, 2003 and 2002, respectively) 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 is
comprised of the following:

|                      |                | Maturity |               | Commitment
Fee |       | Interest
Over |              | Rate
LIBOR |       | 2003 |         | 2002   
|--------------------- | -------------- | -------- | ------------- | -------------- | ----- | ------------- | ------------ | ---------- | ----- | ---- | ------- | -------
|Term Loans:           |                |          |               |                |       |               |              |            |       |      |         |        
|                      | Tranche A Loan |          | June 15, 2016 |                | 0.375 | %             | Construction |            | 1.125 | %    | $       | 467,630
|                      | 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   |                |          |               |                |       |               |              |            |       |      | 575,390 |        
|Less: current portion |                |          |               |                |       |               |              |            |       |      | 20,527  |        
|                      |                |          |               |                |       |               |              |            |       |      |         |        
|                      |                |          |               |                |       |               |              |            |       | $    | 554,863 |        
|                      |                |          |               |                |       |               |              |            |       |      |         |        

Future
maturities of long-term debt are as follows:

Year(In thousands)2004

$
20,5272005


22,6322006


24,9112007


27,3622008


30,160Thereafter


449,798$
575,390


The
construction loans were due 18 months after the Phase I Basic Term-Out date of June 15, 2000. The Phase I and II construction loans were converted to term
loans on September 20, 2001. Quarterly amortization payments for Tranche A commenced in September 2002 and will commence for Tranche B in the first quarter of the 17th
year, respectively, after the Basic Term-Out date. The balance

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on
the loan facility was collateralized by the Partnership's assets and bears interest at LIBOR (1.8125% at December 31, 2003) plus 1.750%, payable quarterly.

11. Subordinated Notes and Accrued Interest PayableEME and GN

EME and Enron Development Corp. (EDC), an indirect wholly-owned subsidiary of Enron, and certain of their affiliates incurred costs on behalf of the Partnership
during the construction phase. These costs were recorded as part ofProperty, plant and equipmentwith corresponding amounts recorded as Subordinated notesandAccrued interest payableto EME and EDC. The note payable to EDC was
transferred to GN as part of the acquisition of the Enron participation in Buenergía. As of December 31, 2003 and 2002 outstanding principal and interests were as follows (in
thousands):

|                                                            |  | 2003 |        | 2002
|----------------------------------------------------------- |  | ---- | ------ | ----
|Subordinated notes payableEdison Mission Energy            |  | $    | 20,000 |     
|Subordinated notes payableGas Natural SDG, S.A.            |  |      | 12,000 |     
|Subordinated accrued interest payableEdison Mission Energy |  |      | 18,531 |     
|Subordinated accrued interest payableGas Natural SDG, S.A. |  |      | 10,054 |     
|                                                            |  |      |        |     
|                                                            |  | $    | 60,585 |     
|                                                            |  |      |        |     

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) was 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. In the event that debt service coverage ratios in any one of the three years prior to the 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. Otherwise, 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 years 1-5 and LIBOR plus 2.35% during years 6-10. As of
December 31, 2003 and 2002, no amounts have been drawn under this facility.

13. PREPA Letter of Credit Facility

Pursuant to the terms of the PPA, the Partnership has provided an operating security instrument 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 6). The operating security was issued when the Plant commenced commercial operations and will mature on December 15, 2007. The
obligation with PREPA to replenish any amount 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 of 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

290

---

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, 2003 and 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, 2003 and 2002, the letter of credit issued has been escalated to approximately
$13,569,000 and $12,414,000 (net of the $5 million note receivable from PREPA), for which $3,359,000 and $2,233,000 was posted as cash collateral which is presented, including interest, as
non-currentRestricted cashin the accompanying balance sheet at December 31, 2003 and 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 1.125% 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, 2003 and 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 provisions of the Puerto Rico Industrial Incentives Act of 1998, as
amended. This exemption 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 provisions, the Partnership shall have the option to deduct the total costs incurred after January 1, 1998 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 2003 and 2002. 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:

|                                                  |  | 2003 |        | 2002 |       | 2001 |  
|------------------------------------------------- |  | ---- | ------ | ---- | ----- | ---- | -
|
|Income tax provision at the statutory rate of 39% |  | $    | (7,417 | )    | (39.0 | )    | $
|Exemption on industrial development income        |  |      | 6,087  |      | 32.0  |      |  
|Other                                             |  |      | (122   | )    | (0.6  | )    |  
|                                                  |  |      |        |      |       |      |  
|Income tax provision                              |  | $    | (1,452 | )    | (7.6  | )    | $
|                                                  |  |      |        |      |       |      |  

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The
components of deferred income tax liabilities or assets as of December 31 are as follows (in thousands):

2003

2002Deferred tax assets (liabilities):Construction and installation costs

$
(4,328
)
$
(2,755
)Allowance for doubtful accounts


520


399Net deferred tax liability

$
(3,808
)
$
(2,356
)


The
deferred tax asset of $4,295,000 and $5,704,000 at December 31, 2003 and 2002 relates exclusively to unrealized losses on interest rate swaps agreements included in 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 2003, 2002 and 2001 amounted to approximately $71,000, $54,000 and $41,000, respectively, which is
expensed as salaries and related benefits.

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 to leases and
to legal and administrative procedures.



The Partnership leases its administrative office facilities under an operating lease agreement expiring in August 2006. During 2003, 2002 and 2001 rental
expense was approximately $123,000, $123,000 and $110,000, 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

Amount2004

$
802005


802006


54$
214




The Partnership is involved in various legal and administrative actions, generally related to its operations. Management believes that, based on advice from its
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.

*
* * * * * * *

292

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Report of Independent Auditors

To
the Management Committee of
Gordonsville Energy, L.P.:

In
our opinion, the accompanying balance sheets 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, 2003 and December 31, 2002, and the results of its operations and its 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 Partnership'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.

PricewaterhouseCoopers
LLP

Los
Angeles, California
March 10, 2004

293

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GORDONSVILLE ENERGY, L.P.  BALANCE SHEETS  December 31, 2003 and 2002

|                                       |                                    | 2003                                   |         | 2002     
|-------------------------------------- | ---------------------------------- | -------------------------------------- | ------- | ---------
|Assets                                 |                                    |                                        |         |          
|Current assets:                        |                                    |                                        |         |          
|                                       | Cash and cash equivalents          |                                        | $       | 1,864,249
|                                       | Accounts receivable                |                                        |         | 90,344   
|                                       | Inventory                          |                                        |         |         
|                                       | Prepaid and other                  |                                        |         |         
|                                       |                                    |                                        |         |          
|                                       |                                    | Total current assets                   |         |          
|                                       |                                    |                                        |         |          
|Property, plant and equipment, net     |                                    |                                        |        |          
|Other assets:                          |                                    |                                        |         |          
|                                       | Deferred financing costs, net      |                                        |         |         
|                                       | Debt service and other reserves    |                                        |         | 11,811   
|                                       |                                    |                                        |         |          
|                                       |                                    | Total assets                           |         | $        
|                                       |                                    |                                        |         |          
|Liabilities and Partners' Equity       |                                    |                                        |         |          
|Current liabilities:                   |                                    |                                        |         |          
|                                       | Current portion of long-term debt  |                                        | $       |         
|                                       | Accounts payable                   |                                        |         | 1,322,967
|                                       | Interest payable                   |                                        |         |         
|                                       | Liability under interest rate swap |                                        |         |         
|                                       |                                    |                                        |         |          
|                                       |                                    | Total current liabilities              |         |          
|Long-term debt, net of current portion |                                    |                                        |        |          
|                                       |                                    |                                        |         |          
|                                       |                                    | Total liabilities                      |         |          
|                                       |                                    |                                        |         |          
|Commitments and contingencies (Note 9) |                                    |                                        |         |          
|Partners' equity                       |                                    |                                        | 643,437 |          
|                                       |                                    |                                        |         |          
|                                       |                                    | Total liabilities and partners' equity |         | $        
|                                       |                                    |                                        |         |          

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

294

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GORDONSVILLE ENERGY, L.P.  STATEMENTS OF INCOME AND COMPREHENSIVE INCOME  For the Years Ended December 31, 2003, 2002 and 2001 (unaudited)

|                                                                                     |                                   | 2003                     |            | 2002       |            | 2001       |           
|------------------------------------------------------------------------------------ | --------------------------------- | ------------------------ | ---------- | ---------- | ---------- | ---------- | ----------
|
|Operating Revenues:                                                                  |                                   |                          |            |            |            |            |           
|                                                                                     | Sales of capacity and electricity |                          | $          | 37,692,997 |            | $          | 40,296,940
|                                                                                     | Sales of steam                    |                          |            |           |            |            | 9,997     
|                                                                                     | Interest income                   |                          |            | 152,677    |            |            | 311,416   
|                                                                                     |                                   |                          |            |            |            |            |           
|                                                                                     |                                   | Total operating revenues |            |            | 37,845,674 |            |           
|                                                                                     |                                   |                          |            |            |            |            |           
|Operating Expenses:                                                                  |                                   |                          |            |            |            |            |           
|                                                                                     | Operations and maintenance        |                          |            | 13,534,186 |            |            | 12,611,865
|                                                                                     | General and administrative        |                          |            | 7,311,536  |            |            | 3,191,946 
|                                                                                     | Depreciation and amortization     |                          |            | 8,749,698  |            |            | 7,181,522 
|                                                                                     | Interest expense                  |                          |            | 12,408,137 |            |            | 7,677,463 
|                                                                                     |                                   |                          |            |            |            |            |           
|                                                                                     |                                   | Total operating expenses |            |            | 42,003,557 |            |           
|                                                                                     |                                   |                          |            |            |            |            |           
|Operating (loss) income                                                              |                                   |                          | (4,157,883 | )          |            | 9,955,557  |           
|Other Income:                                                                        |                                   |                          |            |            |            |            |           
|                                                                                     | Gain on sale of assets            |                          |            | 6,605,446  |            |            |          
|                                                                                     |                                   |                          |            |            |            |            |           
|Income before change in accounting principle                                         |                                   |                          | 2,447,563  |            |            | 9,955,557  |           
|Cumulative effect on prior years of change in accounting for major maintenance costs |                                   |                          |           |            |            |           |           
|                                                                                     |                                   |                          |            |            |            |            |           
|                                                                                     |                                   | Net income               |            |            | 2,447,563  |            |           
|Other comprehensive income (loss)                                                    |                                   |                          | 8,868,554  |            |            | (5,324,299 | )         
|                                                                                     |                                   |                          |            |            |            |            |           
|                                                                                     |                                   | Comprehensive income     |            | $          | 11,316,117 |            | $         
|                                                                                     |                                   |                          |            |            |            |            |           

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

295

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GORDONSVILLE ENERGY, L.P.  STATEMENTS OF CHANGES IN PARTNERS' EQUITY  December 31, 2003, 2002 and 2001 (unaudited)

|                                       |  | Madison
Energy
Company |             | Rapidan
Energy
Company |   | Calpine
Gordonsville
Inc. |   | Accumulated
Other
Comprehensive
Loss |             | Total |  
|-------------------------------------- |  | ---------------------- | ----------- | ---------------------- | - | ------------------------- | - | ------------------------------------ | ----------- | ----- | -
|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  |       |  
|Capital distributions                  |  |                        | (35,952,325 | )                      |   | (736,782                  | ) |                                      | (37,289,108 | )     |  
|Net income                             |  |                        | 1,199,306   |                        |   | 24,475                    |   |                                      | 1,223,782   |       |  
|Other comprehensive income             |  |                        |            |                        |   |                          |   |                                      |            |       |  
|                                       |  |                        |             |                        |   |                           |   |                                      |             |       |  
|Balance, December 31, 2003             |  | $                      | 612,284     |                        | $ | 9,434                     |   | $                                    | 21,719      |       | $
|                                       |  |                        |             |                        |   |                           |   |                                      |             |       |  

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

296

---

GORDONSVILLE ENERGY, L.P.  STATEMENTS OF CASH FLOWS  For the Years Ended December 31, 2003, 2002 and 2001 (unaudited)

|                                                     |                                                                                   | 2003                                                |           | 2002        |              | 2001       |            
|---------------------------------------------------- | --------------------------------------------------------------------------------- | --------------------------------------------------- | --------- | ----------- | ------------ | ---------- | -----------
|
|Cash flows from operating activities:                |                                                                                   |                                                     |           |             |              |            |            
|                                                     | Net income:                                                                       |                                                     | $         | 2,447,563   |              | $          | 9,955,557  
|                                                     | Adjustments to reconcile net income to net cash provided by operating activities: |                                                     |           |             |              |            |            
|                                                     |                                                                                   | Gain on sale of assets                              |           |             | (6,605,446   | )          |            
|                                                     |                                                                                   | Depreciation and amortization                       |           |             | 8,749,698    |            |            
|                                                     | Changes in assets and liabilities:                                                |                                                     |           |             |              |            |            
|                                                     |                                                                                   | Decrease (increase) in accounts receivables         |           |             | 7,289,563    |            |            
|                                                     |                                                                                   | (Increase) decrease in inventory                    |           |             | (1,593,267   | )          |            
|                                                     |                                                                                   | Decrease in non-current spares                      |           |             |             |            |            
|                                                     |                                                                                   | Decrease (increase) in prepaid and other            |           |             | 263,336      |            |            
|                                                     |                                                                                   | Decrease in accounts payable                        |           |             | (218,983     | )          |            
|                                                     |                                                                                   | Decrease in interest payable                        |           |             | (587,141     | )          |            
|                                                     | Cumulative effect on prior years of change in accounting principle                |                                                     |           |            |              |            |           
|                                                     |                                                                                   |                                                     |           |             |              |            |            
|                                                     |                                                                                   | Net cash provided by operating activities           |           |             | 9,745,323    |            |            
|                                                     |                                                                                   |                                                     |           |             |              |            |            
|Cash flows from investing activities:                |                                                                                   |                                                     |           |             |              |            |            
|                                                     | Sale of assets                                                                    |                                                     |           | 146,992,751 |              |            |           
|                                                     | Capital expenditures                                                              |                                                     |           |            |              |            | (118,645   
|                                                     |                                                                                   |                                                     |           |             |              |            |            
|                                                     |                                                                                   | Net cash provided by (used in) investing activities |           |             | 146,992,751  |            |            
|                                                     |                                                                                   |                                                     |           |             |              |            |            
|Cash flows from financing activities:                |                                                                                   |                                                     |           |             |              |            |            
|                                                     | Decrease (increase) in debt service reserves                                      |                                                     |           | 10,324,024  |              |            | (6,179     
|                                                     | Capital distributions                                                             |                                                     |           | (73,978,215 | )            |            | (4,250,000 
|                                                     | Repayment of long-term debt                                                       |                                                     |           | (94,018,294 | )            |            | (12,742,704
|                                                     |                                                                                   |                                                     |           |             |              |            |            
|                                                     |                                                                                   | Net cash used in financing activities               |           |             | (157,672,485 | )          |            
|                                                     |                                                                                   |                                                     |           |             |              |            |            
|Net (decrease) increase in cash and cash equivalents |                                                                                   |                                                     | (934,411  | )           |              | (1,051,886 | )          
|Cash and cash equivalents, beginning of year         |                                                                                   |                                                     | 2,798,660 |             |              | 3,850,546  |            
|                                                     |                                                                                   |                                                     |           |             |              |            |            
|Cash and cash equivalents, end of year               |                                                                                   | $                                                   | 1,864,249 |             | $            | 2,798,660  |            
|                                                     |                                                                                   |                                                     |           |             |              |            |            
|Supplemental disclosure of cash flow information:    |                                                                                   |                                                     |           |             |              |            |            
|                                                     | Cash paid for interest                                                            |                                                     | $         | 12,995,278  |              | $          | 7,723,065  
|                                                     |                                                                                   |                                                     |           |             |              |            |            

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

297

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GORDONSVILLE ENERGY, L.P.  NOTES TO FINANCIAL STATEMENTS  December 31, 2003, 2002 and 2001 (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 commenced commercial operations on June 1, 1994 and consisted of two natural gas and oil-fired combustion turbine generators ("Units"). The Facility was
designed to produce approximately 240 megawatts of dependable peaking capacity.

Facility Sale and Repayment of Debt

On November 21, 2003 substantially all of the Facility assets including inventory were sold to Virginia Electric and Power Company. The proceeds from the
sale totaling approximately $147 million were used to repay project debt, terminate an interest rate swap agreement, settle a partnership option arrangement, and terminate a waste water
contract. The remaining proceeds were distributed to the partners. Prior to the sale date, the Facility sold 100 percent of its electric energy to Virginia Electric and Power Company for resale
to its customers under two long-term power purchase agreements, each with an initial term of 30 years. The Facility also provided 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. Both agreements were terminated concurrent with the asset sale. 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.

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 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.

298

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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 used 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 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.

Until
November 21, 2003 the Partnership was a party to an interest rate swap agreement with a bank to reduce the potential impact of increases in interest rates on
floating-rate long-term debt (see Note 7) that qualified for hedge accounting. The derivative hedged approximately $89,778,000 of long-term debt that matured
in 2009. The partnership paid $6,377,313 to terminate the swap on November 21, 2003. Including the termination fee, net interest expense was impacted by ($9,778,943), ($3,794,759), and
($1,350,811) in 2003, 2002, and 2001 respectively, to reflect the effects of the cash flow hedge.

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.

299

---

Major Maintenance

Certain 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 application of SFAS No. 143 had no impact on the Partnership's financial statements in 2003.

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 application of SFAS No. 143 had no impact on the Partnership's financial statements in 2003.

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 application of SFAS No. 143 had no impact on the Partnership's financial statements in 2003.

Statement of Financial Accounting Standards No. 149

In April 2003, the Financial Accounting Standards Board (FASB) issued Statement of Financial Accounting Standards No. 149, "Amendment of Statement
133 on Derivative Instruments and Hedging Activities." This statement amends and clarifies financial accounting and reporting for derivative

300

---

instruments
and for hedging activities under SFAS No. 133. The amendment reflects decisions made by the FASB and the Derivatives Implementation Group (DIG) process in connection with issues
raised about the application of SFAS No. 133. Generally, the provisions of SFAS No. 149 will be applied prospectively for contracts entered into or modified after June 30, 2003
and for hedging relationships designated after June 30, 2003. SFAS No. 149 provisions that resulted from the DIG process that became effective in fiscal quarters beginning before
June 15, 2003 will continue to be applied based upon their original effective dates. The adoption of this standard had no impact on the Partnership's financial statements.

Statement of Financial Accounting Standards No. 150

Effective July 1, 2003, the Partnership adopted Statement of Financial Accounting Standards No. 150, "Accounting for Certain Financial Instruments
with Characteristics of both Liabilities and Equity." SFAS No. 150 establishes standards for how to classify and measure certain financial instruments with characteristics of both liabilities
and equity. It requires that an issuer classify a financial instrument that is within its scope as a liability or asset, as appropriate. The adoption of this standard had no impact on the
Partnership's financial statements.

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 application of SFAS No. 143 had
no impact on the Partnership's financial statements in 2003.

Statement of Financial Accounting Standards Interpretation No. 46

In December 2003, the FASB issued Statement of Financial Accounting Standards Interpretation No. 46, "Consolidation of Variable Interest Entities."
This interpretation of Accounting Research Bulletin No. 51, "Consolidated Financial Statements," addresses consolidation of variable interest entities by business enterprises that are the
primary beneficiaries. 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. This interpretation is effective on March 31, 2004. The
Partnership does not expect the adoption of this standard will have a material impact on its financial statements.

3. Inventory

Inventory consists of the following at December 31, 2003 and 2002:

2003

2002Fuel oil




$
3,241,006Natural gas





123,185Spare parts





470,044$


$
3,834,235


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4. Property, Plant and Equipment

Property, plant and equipment consist of the following at December 31, 2003 and 2002:

2003

2002Power plant facilities




$
196,717,472Interconnection facility





3,250,000Furniture and office equipment





813,423


200,780,895Less: Accumulated depreciation





(59,907,792
)Property, plant and equipment, net

$


$
140,873,103


5. Other Assets

Deferred Financing Costs

Deferred financing costs consist of legal fees and closing costs incurred by the Partnership in obtaining its financing and were being amortized over the term of
the Facility's financing arrangement of 15 years. The costs were fully amortized in 2003 since the debt was repaid in full. Amortization expense was $2,724,498 for 2003 and $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 at December 31, 2002.

Debt Service Reserve

The debt service reserve is an interest bearing account required by a bank under the terms of the financing agreement. The Partnership was 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.

6. Accounts Payable

Accounts payable consists of the following at December 31, 2003 and 2002:

2003

2002Accounts payable to affiliates:Rapidan Energy Company

$
55,990

$
6,432Edison Mission Operations and Maintenance, Inc. (EMOM)


926,055


886,091982,045


892,523Accounts payable to others


340,922


702,059$
1,322,967

$
1,594,582


7. 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 provided 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 were due semiannually through

302

---

June 1,
2009. On November 21, 2003 the debt was fully repaid and the commitment of the banks terminated. The Agreement had placed certain restrictions on capital distributions and
further provided 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 had also
provided 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. In addition, substantially all of the assets of the
Partnership had been pledged as collateral for the Agreement.

Amounts
outstanding under the Agreement had born interest at variable Eurodollar Rates or Base Rates, as defined in the Agreement, at the option of the Partnership, and were payable in
varying installments. The Partnership had elected to pay Eurodollar interest rates specified as LIBOR, plus a margin of 1.25 percent, which was to escalate to 1.875 percent over the term
of the loan. Interest paid under the Agreement for the years ended December 31, 2003, 2002 and 2001 was $2,373,985, $3,659,837 and $7,624,042, 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 involved 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. The Swap had an initial notional principal amount of $146,500,000 ($83,343,000 at November 20, 2003), which was to decrease over the term of
the swap and expire 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. The
Partnership made a payment of $6,377,313 on November 21, 2003 to terminate the Swap agreement

The
Partnership made swap payments, including the termination fee of $10,098,422 and $3,772,125 during 2003 and 2002, respectively. Amounts paid under the swap have been reflected in
interest expense.

8. 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 prior to the sale. The Partnership paid for direct costs of these services, plus an increment to cover overhead and
benefits. EMOM could 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 $4,087,623, $2,348,631 and $2,540,784, which included $178,080, $200,000 and $200,000 of incentive compensation, during 2003, 2002 and 2001, respectively. The Agreement was mutually
terminated on November 21, 2003.

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 $754,235, $1,018,215 and $259,707 during 2003, 2002 and 2001, respectively.

9. 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 provided for an initial term
of 30 years from the commencement of

303

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commercial
operations, with an option to renew the lease for an additional 10 years. Annual rental payments under the lease were $200,000 during the initial lease term, with annual increases
for inflation.

In
accordance with the provisions of the site lease, the Partnership had arranged for a $10,000 letter of credit to provide assurance about plant maintenance during the term of the site
lease. The Partnership had also provided the town of Gordonsville with a $300,000 letter of credit, which could 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.

The
site lease was assigned to the purchaser of the Facility on November 21, 2003. After the assignment, the Partnership no longer has any obligation under the lease agreement.

Power Purchase Agreements

In October 1992, the Partnership entered into two Power Purchase Agreements for the sale to Virginia Electric and Power Company of the net electrical
output and dependable capacity from each of the Facility's two Units. The agreements were effective for the 30-year period commencing June 1, 1994, with options for 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. The Power Purchase Agreements
were mutually terminated on November 21, 2003.

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. The agreement was mutually terminated on November 21, 2003.

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 was mutually terminated on November 21, 2003.

304

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Report of Independent Auditors

To
the Management Committee of
Brooklyn Navy Yard Cogeneration Partners, L.P.:

In
our opinion, the accompanying balance sheets 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, 2003 and December 31, 2002, and the results of its operations and its 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 Partnership'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.

|                                       |  | 
|-------------------------------------- |  | 
|PricewaterhouseCoopers LLP             |  | 
|                                       |  | 
|Los Angeles, California
March 10, 2004 |  | 

305

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BROOKLYN NAVY YARD COGENERATION PARTNERS, L.P.  BALANCE SHEETS  December 31, 2003 and 2002

|                                                |                                                                                                                        | 2003                          |                                        | 2002        |           
|----------------------------------------------- | ---------------------------------------------------------------------------------------------------------------------- | ----------------------------- | -------------------------------------- | ----------- | ----------
|Assets                                          |                                                                                                                        |                               |                                        |             |           
|Current assets:                                 |                                                                                                                        |                               |                                        |             |           
|                                                | Cash and cash equivalents                                                                                              |                               | $                                      | 12,316,030  |           
|                                                | Accounts receivable, net of allowance for doubtful accounts of $467,000 as of December 31, 2003 and 2002, respectively |                               |                                        | 18,105,619  |           
|                                                | Inventory                                                                                                              |                               |                                        | 6,917,785   |           
|                                                | Deposits                                                                                                               |                               |                                        | 7,733,728   |           
|                                                | Prepaids and other                                                                                                     |                               |                                        | 1,310,446   |           
|                                                |                                                                                                                        |                               |                                        |             |           
|                                                |                                                                                                                        |                               | Total current assets                   |             |           
|                                                |                                                                                                                        |                               |                                        |             |           
|Construction in progress                        |                                                                                                                        |                               |                                       |             |           
|Plant and equipment, net                        |                                                                                                                        |                               | 407,206,128                            |             |           
|Deferred costs, net                             |                                                                                                                        |                               | 12,543,851                             |             |           
|Restricted cash                                 |                                                                                                                        |                               | 2,192,604                              |             |           
|                                                |                                                                                                                        |                               |                                        |             |           
|                                                |                                                                                                                        |                               | Total assets                           |             | $         
|                                                |                                                                                                                        |                               |                                        |             |           
|Liabilities and Partners' Equity                |                                                                                                                        |                               |                                        |             |           
|Current liabilities:                            |                                                                                                                        |                               |                                        |             |           
|                                                | Current portion of long-term debt                                                                                      |                               | $                                      | 4,520,000   |           
|                                                | Working capital facility                                                                                               |                               |                                        | 2,000,000   |           
|                                                | Interest and fees payable:                                                                                             |                               |                                        |             |           
|                                                |                                                                                                                        | Long-term debt and other      |                                        |             | 6,116,979 
|                                                |                                                                                                                        | Mission Energy New York, Inc. |                                        |             | 45,029,830
|                                                | Accounts payable                                                                                                       |                               |                                        | 15,284,398  |           
|                                                | Accounts payableaffiliates                                                                                            |                               |                                        | 16,016,485  |           
|                                                | Accrued expenses and other                                                                                             |                               |                                        | 4,690,278   |           
|                                                |                                                                                                                        |                               |                                        |             |           
|                                                |                                                                                                                        |                               | Total current liabilities              |             |           
|                                                |                                                                                                                        |                               |                                        |             |           
|Long-term debt, net of current portion          |                                                                                                                        |                               | 393,880,000                            |             |           
|Loans payable to Mission Energy New York, Inc.  |                                                                                                                        |                               | 90,461,186                             |             |           
|Payable to Contractor                           |                                                                                                                        |                               | 9,751,000                              |             |           
|Other deferred liabilities                      |                                                                                                                        |                               | 5,999,884                              |             |           
|                                                |                                                                                                                        |                               |                                        |             |           
|                                                |                                                                                                                        |                               | Total liabilities                      |             |           
|                                                |                                                                                                                        |                               |                                        |             |           
|Commitments and contingencies (Notes 11 and 14) |                                                                                                                        |                               |                                        |             |           
|Partners' equity:                               |                                                                                                                        |                               |                                        |             |           
|                                                | Mission Energy New York, Inc.                                                                                          |                               |                                        | (49,832,903 | )         
|                                                | B-41 Associates, L.P.                                                                                                  |                               |                                        | (75,590,946 | )         
|                                                |                                                                                                                        |                               |                                        |             |           
|                                                |                                                                                                                        |                               | Total partners' equity                 |             |           
|                                                |                                                                                                                        |                               |                                        |             |           
|                                                |                                                                                                                        |                               | Total liabilities and partners' equity |             | $         
|                                                |                                                                                                                        |                               |                                        |             |           

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

306

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BROOKLYN NAVY YARD COGENERATION PARTNERS, L.P.  STATEMENTS OF OPERATIONS  For the Years Ended December 31, 2003, 2002 and 2001 (unaudited)

|          |                               | 2003 |                | 2002        |   | 2001       
|--------- | ----------------------------- | ---- | -------------- | ----------- | - | -----------
|
|Revenues: |                               |      |                |             |   |            
|          | Energy revenue                |      | $              | 135,512,203 |   | $          
|          | Steam revenue                 |      |                | 52,184,240  |   |            
|          | Peaking gas revenue           |      |                | 7,078,048   |   |            
|          | Other revenue                 |      |                | 7,308,039   |   |            
|          | Interest income               |      |                | 235,155     |   |            
|          |                               |      |                |             |   |            
|          |                               |      | Total revenues |             |   | 202,317,685
|          |                               |      |                |             |   |            
|Expenses: |                               |      |                |             |   |            
|          | Operations and maintenance    |      |                | 166,056,140 |   |            
|          | General and administrative    |      |                | 12,379,919  |   |            
|          | Depreciation and amortization |      |                | 14,745,625  |   |            
|          | Interest expense              |      |                | 38,655,685  |   |            
|          | Loss on sale of asset         |      |                |            |   |            
|          |                               |      |                |             |   |            
|          |                               |      | Total expenses |             |   | 231,837,369
|          |                               |      |                |             |   |            
|          |                               |      | Net loss       |             | $ | 29,519,684 
|          |                               |      |                |             |   |            

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

307

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BROOKLYN NAVY YARD COGENERATION PARTNERS, L.P.  STATEMENTS OF CHANGES IN PARTNERS' EQUITY  December 31, 2003, 2002 and 2001 (unaudited)

|                                                |  | Mission
Energy
New York, Inc. |             | B-41
Associates
L.P. |   | Total       |  
|----------------------------------------------- |  | ----------------------------- | ----------- | -------------------- | - | ----------- | -
|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 | )
|Contribution from Mission Energy New York, Inc. |  |                               | 32,551,000  |                      |   |            |  
|Receivable from Mission Energy New York, Inc.   |  |                               | (12,551,000 | )                    |   |            |  
|Net loss                                        |  |                               | (14,759,842 | )                    |   | (14,759,842 | )
|                                                |  |                               |             |                      |   |             |  
|Balance, December 31, 2003                      |  | $                             | (49,832,903 | )                    | $ | (75,590,946 | )
|                                                |  |                               |             |                      |   |             |  

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, 2003, 2002 and 2001 (unaudited)

|                                                     |                                                                                 | 2003                                         |                                                   | 2002                                                |            | 2001        |            
|---------------------------------------------------- | ------------------------------------------------------------------------------- | -------------------------------------------- | ------------------------------------------------- | --------------------------------------------------- | ---------- | ----------- | -----------
|
|Cash flows from operating activities:                |                                                                                 |                                              |                                                   |                                                     |            |             |            
|                                                     | Net loss                                                                        |                                              | $                                                 | (29,519,684                                         | )          | $           | (28,576,852
|                                                     | Adjustments to reconcile net loss to net cash provided by operating activities: |                                              |                                                   |                                                     |            |             |            
|                                                     |                                                                                 | Loss on sale of asset                        |                                                   |                                                     |           |             |            
|                                                     |                                                                                 | Depreciation and amortization                |                                                   |                                                     | 14,745,625 |             |            
|                                                     |                                                                                 | Provision for doubtful accounts              |                                                   |                                                     |           |             |            
|                                                     |                                                                                 | Changes in operating assets and liabilities: |                                                   |                                                     |            |             |            
|                                                     |                                                                                 |                                              | Decrease (increase) in accounts receivable        |                                                     |            | 1,785,834   |            
|                                                     |                                                                                 |                                              | Decrease (increase) in inventory                  |                                                     |            | 1,295,063   |            
|                                                     |                                                                                 |                                              | Decrease (increase) in deposits                   |                                                     |            | 9,276,263   |            
|                                                     |                                                                                 |                                              | Increase in prepaids and other                    |                                                     |            | (35,261     | )          
|                                                     |                                                                                 |                                              | Increase in interest and fees payable             |                                                     |            | 12,840,429  |            
|                                                     |                                                                                 |                                              | (Decrease) increase in accounts payable           |                                                     |            | (6,605,057  | )          
|                                                     |                                                                                 |                                              | (Decrease) increase in accrued expenses and other |                                                     |            | (7,970,160  | )          
|                                                     |                                                                                 |                                              | Increase (decrease) in deferred liabilities       |                                                     |            | 1,072,438   |            
|                                                     |                                                                                 |                                              | (Decrease) increase in other liabilities          |                                                     |            | (2,800,000  | )          
|                                                     |                                                                                 |                                              |                                                   |                                                     |            |             |            
|                                                     |                                                                                 |                                              |                                                   | Net cash (used in) provided by operating activities |            |             | (5,914,510 
|                                                     |                                                                                 |                                              |                                                   |                                                     |            |             |            
|Cash flows from investing activities:                |                                                                                 |                                              |                                                   |                                                     |            |             |            
|                                                     | Capital expenditures                                                            |                                              |                                                   | 129,686                                             |            |             | (4,299,997 
|                                                     | Capital expendituresContractor                                                 |                                              |                                                   |                                                    |            |             | (32,551,000
|                                                     | Proceeds from sale of assets                                                    |                                              |                                                   |                                                    |            |             | 108,501    
|                                                     | (Increase) decrease in restricted cash                                          |                                              |                                                   | (1,828,548                                          | )          |             | 2,181,907  
|                                                     |                                                                                 |                                              |                                                   |                                                     |            |             |            
|                                                     |                                                                                 |                                              |                                                   | Net cash (used in) provided by investing activities |            |             | (1,698,862 
|                                                     |                                                                                 |                                              |                                                   |                                                     |            |             |            
|Cash flows from financing activities:                |                                                                                 |                                              |                                                   |                                                     |            |             |            
|                                                     | Borrowings from working capital facility                                        |                                              |                                                   | 2,000,000                                           |            |             |           
|                                                     | Repayments to working capital facility                                          |                                              |                                                   | (2,500,000                                          | )          |             | (2,500,000 
|                                                     | Contributions from partner                                                      |                                              |                                                   | 20,000,000                                          |            |             |           
|                                                     | Repayment of long-term debt                                                     |                                              |                                                   | (2,780,000                                          | )          |             | (1,080,000 
|                                                     |                                                                                 |                                              |                                                   |                                                     |            |             |            
|                                                     |                                                                                 |                                              |                                                   | Net cash provided by (used in) financing activities |            |             | 16,720,000 
|                                                     |                                                                                 |                                              |                                                   |                                                     |            |             |            
|Net increase (decrease) in cash and cash equivalents |                                                                                 |                                              | 9,106,628                                         |                                                     |            | (11,603,576 | )          
|Cash and cash equivalents, beginning of period       |                                                                                 |                                              | 3,209,402                                         |                                                     |            | 14,812,978  |            
|                                                     |                                                                                 |                                              |                                                   |                                                     |            |             |            
|Cash and cash equivalents, end of period             |                                                                                 | $                                            | 12,316,030                                        |                                                     | $          | 3,209,402   |            
|                                                     |                                                                                 |                                              |                                                   |                                                     |            |             |            
|Supplemental disclosure of cash flow information:    |                                                                                 |                                              |                                                   |                                                     |            |             |            
|                                                     | Cash paid during the year for interest                                          |                                              | $                                                 | 25,605,091                                          |            | $           | 25,526,683 
|                                                     |                                                                                 |                                              |                                                   |                                                     |            |             |            

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, 2003, 2002 and 2001 (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 one million 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 10), 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

Certain prior year reclassifications have been made to conform to the current year financial statement presentation.

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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Deposits

Deposits consist of revenues that are used to repay principal, interest and other costs due under the Collateral Agency and Intercreditor Agreement (see
Note 10).

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.

Maintenance

Expenditures for minor maintenance, repairs, and minor renewals are charged to operations as incurred. Expenditures for additions, improvements and replacements
are capitalized. Estimated costs for scheduled maintenance events are accrued for on a straight-line basis over the expected operating interval between each like event.

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.

Revenue Recognition

Revenue is recognized as billable based on established prices as defined under Energy Sales Agreements which have terms of 40 years (see Note 11).

Derivative Instruments and Hedging Transactions

Under SFAS No. 133, as amended, all derivatives instruments are recognized in the balance sheet at 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 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.

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

311

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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 adoption of this standard had no impact on the Partnership's financial statements.

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 adoption of this standard had no impact on the Partnership's financial statements.

Statement of Financial Accounting Standards No. 149.

In April 2003, the Financial Accounting Standards Board (FASB) issued Statement of Financial Accounting Standards No. 149, "Amendment of Statement
133 on Derivative Instruments and Hedging Activities." This statement amends and clarifies financial accounting and reporting for derivative instruments and for hedging activities under SFAS
No. 133. The amendment reflects decisions made by the FASB and the Derivatives Implementation Group (DIG) process in connection with issues raised about the application of SFAS No. 133.
Generally, the provisions of SFAS No. 149 will be applied prospectively for contracts entered into or modified after June 30, 2003 and for hedging relationships designated after
June 30, 2003. SFAS No. 149 provisions that resulted from the DIG process that became effective in fiscal quarters beginning before June 15, 2003 will continue to be applied based
upon their original effective dates. The adoption of this standard had no impact on the Partnership's financial statements.

Statement of Financial Accounting Standards No. 150.

Effective July 1, 2003, the Partnership adopted Statement of Financial Accounting Standards No. 150, "Accounting for Certain Financial Instruments
with Characteristics of both Liabilities and Equity." SFAS No. 150 establishes standards for how to classify and measure certain financial instruments with characteristics of both liabilities
and equity. It requires that an issuer classify a

312

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financial
instrument that is within its scope as a liability or asset, as appropriate. The adoption of this standard had no impact on the Partnership's financial statements.

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 adoption of this standard had no impact
on the Partnership's financial statements

Statement of Financial Accounting Standards Interpretation No. 46

In December 2003, the FASB issued Statement of Financial Accounting Standards Interpretation No. 46, "Consolidation of Variable Interest Entities."
This interpretation of Accounting Research Bulletin No. 51, "Consolidated Financial Statements," addresses consolidation of variable interest entities by business enterprises that are the
primary beneficiaries. 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. This interpretation is effective on March 31, 2004. The
Partnership does not expect the adoption of this standard will have a material impact on its financial statements.

3. Accounts Receivable

Accounts receivable at December 31, 2003 and 2002 consists of the following:

2003

2002Mission Energy New York, Inc.

$
1,211,302

$
431,055Accounts receivable from others


17,361,317


19,927,398Total accounts receivable


18,572,619


20,358,453Allowance for doubtful accounts


(467,000
)

(467,000
)$
18,105,619

$
19,891,453


4. Inventory

Inventory at December 31, 2003 and 2002 consists of the following:

2003

2002Fuel oil

$
1,483,063

$
2,434,040Natural gas


1,994,915


2,610,104Spare parts


3,439,807


3,168,704$
6,917,785

$
8,212,848


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5. Plant and Equipment

Plant and equipment at December 31, 2003 and 2002 consists of the following assets:

2003

2002Plant

$
497,544,748

$
493,416,895Equipment


1,000,224


957,763Accumulated depreciation


(91,338,844
)

(77,243,114
)Plant and equipment, net

$
407,206,128

$
417,131,544


6. Restricted Cash

Restricted cash consists of long-term funds used for the payment of maintenance expense, funds to maintain the letter of credit deficit due to
currency translation and other miscellaneous deposits. Restricted cash as of December 31, 2003 and 2002 are as follows:

2003

2002Maintenance fund

$
782,830

$
271,509Cash collateral escrow fund


1,318,382


Other deposits


91,392


92,547Total restricted cash

$
2,192,604

$
364,056


7. Deferred Costs

Deferred costs as of December 31, 2003 and 2002 consisted of the following:

2003

2002Deferred financing costs

$
14,142,589

$
14,142,589Accumulated amortization


(3,524,502
)

(3,031,809
)Net deferred financing costs


10,618,087


11,110,780Deferred fuel costs


3,000,000


3,000,000Accumulated amortization


(1,074,236
)

(917,031
)Net deferred fuel costs


1,925,764


2,082,969Total deferred costs

$
12,543,851

$
13,193,749


Deferred financing costs consist of legal fees and closing costs incurred by the Partnership in obtaining its financing (see Note 10).
These costs are being amortized using the effective interest method over the life of the related debt.

Deferred
fuel costs include a $3 million advance payment required under a long-term fuel supply agreement (see Note 11). These costs are being amortized over the term
of the fuel supply agreement, beginning March 1, 1997.

8. 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 the loans payable to partner approximates fair value due to
the variable interest rate feature. The fair

314

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value
of the long-term debt at December 31, 2003 and 2002 was approximately $389,125,000 and $379,080,000, respectively (see Note 10).

9. 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 (10.00 percent at December 31, 2003), compounded daily. MENY may, at its discretion, reduce
the rate of interest charged for the Partner loans. Through the years ended December 31, 2003 and 2002, 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, 2003 and 2002 was $90,461,186, and is subordinate to the long-term debt discussed in Note 10. For the years ended
December 31, 2003, 2002 and 2001, the Partnership recorded interest expense related to the Partner loans of $12,891,998, $11,665,320 and $11,135,879, respectively.

10. 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 million 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.

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

315

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than
unassigned project contract interests, which include the Site Lease discussed in Note 11 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, date 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 11) and its debt service requirements. The
Partnership had nine letters of credit outstanding totaling $68,834,914 and $71,520,662 as of December 31, 2003 and 2002, respectively. As of December 31, 2003 and 2002, the Partnership
had $5 million and $10 million available under a working capital facility. Amounts drawn under the working capital facility were $2 million and $2.5 million at
December 31, 2003 and 2002, respectively. Amounts outstanding under the working capital facility bear interest at LIBOR (1.69 percent and 1.42 percent at December 31, 2003
and 2002, respectively) plus a margin 3.75 percent and 0.6 percent at December 31, 2003 and 2002, respectively. The current $5 million working capital facility matures on
December 17, 2005.

At
December 31, 2003, the future maturities of the debt are as follows:

Year Ending December 31,2004

$
6,520,0002005


3,690,0002006


4,950,0002007


5,930,0002008


4,930,000Thereafter


374,380,000400,400,000


11. 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 escalate annually beginning on January 1,
1997. For the year ended December 31, 2003, 2002 and 2001, the partnership incurred $1,209,369, $1,131,599 and $1,076,847, respectively, in rent expense. The total future lease payments due are
as follows:

Year Ending December 31,2004

$
561,9382005


603,6062006


598,6582007


627,9122008


658,080Thereafter


43,817,665$
46,867,859


316

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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 one million 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.

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 million 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.

317

---

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.

12. 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
years ended December 31, 2003, 2002 and 2001, reimbursements paid or payable to MENY totaled $1,906,681, $2,075,321 and $1,094,102, respectively and to B-41 totaled $78,510,
$246,463 and $141,727, 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 of
gross revenue in 2003 and 2002, respectively, as defined in the Partnership Agreement. Royalty and general partner management fees for the years ended December 31, 2003, 2002 and 2001 totaled
$8,083,301, $6,111,703 and $8,704,667, respectively. The fees were not paid in 2003 and 2002 and are included in the accounts payable to affiliates.

13. York Bankruptcy

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.

318

---

A
default occurred on the $150 million 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.

14. 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 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 the present value of the settlement, which was approximately $32 million, and recorded a corresponding increase to property,
plant and equipment as part of the cost to complete construction of the cogeneration facilities. The Partnership imputes interest on the present value of the settlement during the period
January 2003 through January 2007. The imputed interest is reflected as interest expense and as an increase in the liability due to the contractor. EME has indemnified the Partnership
for payments due under the settlement agreement. In January 2003 and 2004, the Partnership received $20 million and $4 million, respectively from EME under the terms of the
indemnity. The funds received from EME were used to pay the contractor and reduce the corresponding liability.

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 interest in connection with unpaid gas importation taxes. The tax audit adjustment relates to natural gas purchased by the Facility during the
period December 1, 1996 through November 30, 1999. The $7,300,000 in tax and interest is based on the audit adjustment plus an estimate of tax and interest through the
December 2004 sunset date of the tax. The Partnership's management believes the Partnership is exempt from the gas importation tax requirement. On May 28, 2002 the assessment was
finalized and issued. On August 16, 2002, a petition was filed with the New York State Division of Tax Appeals. A hearing was held on May 22 and 23, 2003 before an Administrative Law
Judge (ALJ) regarding Brooklyn Navy Yard's appeal. The decision of the ALJ is pending. The Partnership is unable to predict the outcome of this matter. Accordingly the Partnership has not recorded any
expense in connection with the disputed gas importation tax.

319

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Independent Auditor's Report

No.:
L.03 - 1694 - 04/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 2003 and 2002, 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 2003. 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 2003 and 2002,
and the results of its operations and its cash flows for each of the years in the three-year period ended 31 December 2003, in conformity with accounting principles generally
accepted in the United States of America.

As
discussed in Note 2j 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 T. Siddharta Public Accountant License No. 98.1.0192

Jakarta,
23 January 2004.

320

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PT PAITON ENERGY  BALANCE SHEETS  31 December 2003 and 2002  (In thousands of U.S. Dollars, except per share amounts)

|                         |                               | Note                 |              | 2003      |         | 2002     
|------------------------ | ----------------------------- | -------------------- | ------------ | --------- | ------- | ---------
|ASSETS                   |                               |                      |              |           |         |          
|CURRENT ASSETS           |                               |                      |              |           |         |          
|                         | CASH AND CASH EQUIVALENTS     |                      | 2b,3         |           | 64,217  |          
|                         | RESTRICTED CASH               |                      | 9            |           | 27,358  |          
|                         | ACCOUNTS RECEIVABLE           |                      |              |           | 78,768  |          
|                         | FUEL INVENTORY AND SUPPLIES   |                      | 2d,5         |           | 22,882  |          
|                         | PREPAYMENTS AND OTHER         |                      |              |           | 13,028  |          
|                         |                               |                      |              |           |         |          
|                         |                               | TOTAL CURRENT ASSETS |              |           |         | 206,253  
|PLANT AND EQUIPMENT, net |                               | 2e,6                 |              | 1,870,750 |         | 1,921,248
|                         |                               |                      |              |           |         |          
|OTHER ASSETS             |                               |                      |              |           |         |          
|                         | DEFERRED TAX ASSETS, net      |                      | 2n,13        |           |        |          
|                         | RESTRICTED CASH               |                      | 9            |           | 133,002 |          
|                         | LONG-TERM RECEIVABLE          |                      | 2m,4         |           | 450,470 |          
|                         | DEFERRED CHARGES, net         |                      | 2g,7         |           | 242,341 |          
|                         | DEFERRED FINANCING COSTS, net |                      | 2h           |           | 13,407  |          
|                         | PREPAYMENTS AND OTHER         |                      |              |           | 2,917   |          
|                         |                               |                      |              |           |         |          
|                         |                               | TOTAL OTHER ASSETS   |              |           |         | 842,137  
|                         |                               |                      |              |           |         |          
|                         |                               |                      | TOTAL ASSETS |           |         |          
|                         |                               |                      |              |           |         |          

See
Notes to the Financial Statements, which form an integral part of these financial statements.

321

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PT PAITON ENERGY  BALANCE SHEETS (Continued)  31 December 2003 and 2002  (In thousands of U.S. Dollars, except per share amounts)

|                                     |                                                 | Note                                                               |                                            | 2003    |           | 2002      |          
|------------------------------------ | ----------------------------------------------- | ------------------------------------------------------------------ | ------------------------------------------ | ------- | --------- | --------- | ---------
|LIABILITIES AND SHAREHOLDERS' EQUITY |                                                 |                                                                    |                                            |         |           |           |          
|CURRENT LIABILITIES                  |                                                 |                                                                    |                                            |         |           |           |          
|                                     | ACCOUNTS PAYABLE TO RELATED PARTIES             |                                                                    |                                            |         | 111,296   |           | 180,243  
|                                     | TAXES PAYABLE                                   |                                                                    |                                            |         | 6,368     |           | 2,891    
|                                     | ACCRUED FINANCE COSTS                           |                                                                    |                                            |         | 68,286    |           | 26,253   
|                                     | OTHER LIABILITIES                               |                                                                    |                                            |         | 19,438    |           | 62,614   
|                                     | CURRENT MATURITIES OF LONG-TERM LOANS           |                                                                    | 2i,9,15                                    |         | 140,851   |           | 140,851  
|                                     |                                                 |                                                                    |                                            |         |           |           |          
|                                     |                                                 | TOTAL CURRENT LIABILITIES                                          |                                            |         |           | 346,239   |          
|                                     |                                                 |                                                                    |                                            |         |           |           |          
|NON-CURRENT LIABILITIES              |                                                 |                                                                    |                                            |         |           |           |          
|                                     | DEFERRED TAX LIABILITY, net                     |                                                                    | 2n,13                                      |         | 42,705    |           |         
|                                     | LONG-TERM LOANS                                 |                                                                    | 2i,9,15                                    |         | 2,061,117 |           | 2,228,488
|                                     | ACCRUED FINANCE COSTS                           |                                                                    |                                            |         |          |           | 28,239   
|                                     | OTHER LIABILITIES                               |                                                                    |                                            |         |          |           | 7,143    
|                                     | DERIVATIVE FINANCIAL INSTRUMENTS                |                                                                    | 2j,10                                      |         | 72,915    |           | 98,296   
|                                     |                                                 |                                                                    |                                            |         |           |           |          
|                                     |                                                 | TOTAL NON-CURRENT LIABILITIES                                      |                                            |         |           | 2,176,737 |          
|                                     |                                                 |                                                                    |                                            |         |           |           |          
|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30,600 shares in 2003 and 25,000 shares in 2002 |                                            |         |           | 306,000   |          
|                                     |                                                 | Paid in advance                                                    |                                            |         |           |          |          
|                                     |                                                 |                                                                    |                                            |         |           |           |          
|                                     |                                                 |                                                                    |                                            | 306,000 |           | 306,000   |          
|                                     | SHARE PREMIUM                                   |                                                                    |                                            |         | 7,000     |           | 7,000    
|                                     | ACCUMULATED OTHER COMPREHENSIVE LOSS            |                                                                    |                                            |         | (51,041   | )         | (68,807  
|                                     | RETAINED EARNINGS                               |                                                                    |                                            |         | 134,205   |           | 48,006   
|                                     |                                                 |                                                                    |                                            |         |           |           |          
|                                     |                                                 | TOTAL SHAREHOLDERS' EQUITY                                         |                                            |         |           | 396,164   |          
|                                     |                                                 |                                                                    |                                            |         |           |           |          
|                                     |                                                 |                                                                    | TOTAL LIABILITIES AND SHAREHOLDERS' EQUITY |         |           |           | 2,919,140
|                                     |                                                 |                                                                    |                                            |         |           |           |          

See
Notes to the Financial Statements, which form an integral part of these financial statements.

322

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PT PAITON ENERGY  STATEMENTS OF INCOME  Years Ended 31 December 2003, 2002 and 2001  (In thousands of U.S. Dollars, except per share amounts)

|                                                    |                                            | Note  |  | 2003     |          | 2002     |          | 2001     |         
|--------------------------------------------------- | ------------------------------------------ | ----- |  | -------- | -------- | -------- | -------- | -------- | --------
|REVENUES:                                           |                                            | 2c    |  |          |          |          |          |          |         
|                                                    | Net dependable capacity                    |       |  |          | 371,353  |          | 359,757  |          | 224,924 
|                                                    | Net electrical output                      |       |  |          | 113,665  |          | 91,416   |          | 43,003  
|                                                    |                                            |       |  |          |          |          |          |          |         
|                                                    |                                            |       |  | 485,018  |          | 451,173  |          | 267,927  |         
|                                                    |                                            |       |  |          |          |          |          |          |         
|OPERATING EXPENSES:                                 |                                            |       |  |          |          |          |          |          |         
|                                                    | Fuel                                       |       |  |          | (99,162  | )        | (79,338  | )        | (42,350 
|                                                    | Plant operations                           |       |  |          | (39,124  | )        | (27,173  | )        | (13,574 
|                                                    | Depreciation and amortization              |       |  |          | (58,340  | )        | (83,115  | )        | (80,981 
|                                                    | General, administrative and other          |       |  |          | (17,186  | )        | (59,936  | )        | (31,095 
|                                                    |                                            |       |  |          |          |          |          |          |         
|                                                    |                                            |       |  | (213,812 | )        | (249,562 | )        | (168,000 | )       
|                                                    |                                            |       |  |          |          |          |          |          |         
|OPERATING INCOME                                    |                                            |       |  | 271,206  |          | 201,611  |          | 99,927   |         
|                                                    |                                            |       |  |          |          |          |          |          |         
|OTHER INCOME (EXPENSES):                            |                                            |       |  |          |          |          |          |          |         
|                                                    | Interest income                            |       |  |          | 47,437   |          | 47,938   |          | 3,012   
|                                                    | Gain (loss) on foreign currency exchange   |       |  |          | 645      |          | (2,158   | )        | 134     
|                                                    | Interest expense and other financing costs |       |  |          | (193,857 | )        | (154,607 | )        | (193,611
|                                                    | Other income                               |       |  |          | 61       |          | 40       |          | 89      
|                                                    |                                            |       |  |          |          |          |          |          |         
|                                                    |                                            |       |  | (145,714 | )        | (108,787 | )        | (190,376 | )       
|                                                    |                                            |       |  |          |          |          |          |          |         
|INCOME (LOSS) BEFORE TAX                            |                                            |       |  | 125,492  |          | 92,824   |          | (90,449  | )       
|INCOME TAX (EXPENSE) BENEFIT                        |                                            | 2n,13 |  | (39,293  | )        | (28,573  | )        | 25,849   |         
|                                                    |                                            |       |  |          |          |          |          |          |         
|NET INCOME (LOSS)                                   |                                            |       |  | 86,199   |          | 64,251   |          | (64,600  | )       
|                                                    |                                            |       |  |          |          |          |          |          |         
|Weighted-average shares of common stock outstanding |                                            |       |  | 27,624   |          | 25,000   |          | 25,000   |         
|Basic earnings (loss) per share                     |                                            |       |  | 3,120    |          | 2,570    |          | (2,584   | )       

See
Notes to the Financial Statements, which form an integral part of these financial statements.

323

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PT PAITON ENERGY  STATEMENTS OF COMPREHENSIVE INCOME  Years Ended 31 December 2003, 2002 and 2001  (In thousands of U.S. Dollars, except per share amounts)

|                                               |                                                                                                                                                              | 2003    |        | 2002    |         | 2001     |        
|---------------------------------------------- | ------------------------------------------------------------------------------------------------------------------------------------------------------------ | ------- | ------ | ------- | ------- | -------- | -------
|Net income (loss)                              |                                                                                                                                                              | 86,199  |        | 64,251  |         | (64,600  | )      
|                                               |                                                                                                                                                              |         |        |         |         |          |        
|Other comprehensive income (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 1,340, USD 15,421, and USD 9,767 for 2003, 2002 and 2001, respectively        |         | (3,126 | )       | (35,982 | )        | (22,791
|                                               | Reclassification adjustment for losses included in net income (loss), net of tax of USD 8,954 USD 9,244, and USD 6,513 for 2003, 2002 and 2001, respectively |         | 20,892 |         | 21,570  |          | 15,198 
|                                               |                                                                                                                                                              |         |        |         |         |          |        
|Other comprehensive income (loss)              |                                                                                                                                                              | 17,766  |        | (14,412 | )       | (54,395  | )      
|                                               |                                                                                                                                                              |         |        |         |         |          |        
|COMPREHENSIVE INCOME (LOSS)                    |                                                                                                                                                              | 103,965 |        | 49,839  |         | (118,995 | )      
|                                               |                                                                                                                                                              |         |        |         |         |          |        

See
Notes to the Financial Statements, which form an integral part of these financial statements.

324

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PT PAITON ENERGY  STATEMENTS OF CHANGES IN SHAREHOLDERS' EQUITY  Years Ended 31 December 2003, 2002 and 2001  (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 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                    |        
|                            | Net income for the year    |               |  |               |  |                                      |        |                             | 86,199  |                            | 86,199 
|                            | Other comprehensive income |               |  |               |  |                                      | 17,766  |                             |        |                            | 17,766 
|                            |                            |               |   |               |   |                                      |         |                             |         |                            |        
|Balance at 31 December 2003 |                            | 306,000       |   | 7,000         |   | (51,041                              | )       | 134,205                     |         | 396,164                    |        
|                            |                            |               |   |               |   |                                      |         |                             |         |                            |        

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 2003, 2002 and 2001  (In thousands of U.S. Dollars, except per share amounts)

|                                                     |                                                                                          | 2003                                                         |                                     | 2002     |         | 2001    |        
|---------------------------------------------------- | ---------------------------------------------------------------------------------------- | ------------------------------------------------------------ | ----------------------------------- | -------- | ------- | ------- | -------
|CASH FLOWS FROM OPERATING ACTIVITIES:                |                                                                                          |                                                              |                                     |          |         |         |        
|                                                     | Net income (loss)                                                                        |                                                              | 86,199                              |          | 64,251  |         | (64,600
|                                                     | Adjustments to reconcile net income (loss) to net cash provided by operating activities: |                                                              |                                     |          |         |         |        
|                                                     |                                                                                          | Depreciation and amortization                                |                                     | 58,339   |         | 83,115  |        
|                                                     |                                                                                          | (Gain) loss on retirement or disposal of plant and equipment |                                     | (26      | )       | 3,553   |        
|                                                     |                                                                                          | Provision for deferred income taxes                          |                                     | 39,293   |         | 28,573  |        
|                                                     |                                                                                          | Changes in assets and liabilities:                           |                                     |          |         |         |        
|                                                     |                                                                                          |                                                              | Accounts receivable                 |          | 7,236   |         | (53,940
|                                                     |                                                                                          |                                                              | Fuel inventory and supplies         |          | 1,684   |         | (16,123
|                                                     |                                                                                          |                                                              | Prepayments and other               |          | (2,048  | )       | (618   
|                                                     |                                                                                          |                                                              | Taxes payable and other liabilities |          | (46,842 | )       | 32,705 
|                                                     |                                                                                          |                                                              | Accounts payable to related parties |          | (68,947 | )       | 7,071  
|                                                     |                                                                                          |                                                              | Accrued finance costs               |          | 45,457  |         | (910   
|                                                     |                                                                                          |                                                              |                                     |          |         |         |        
|                                                     |                                                                                          | NET CASH PROVIDED BY OPERATING ACTIVITIES                    |                                     | 120,345  |         | 147,677 |        
|                                                     |                                                                                          |                                                              |                                     |          |         |         |        
|CASH FLOWS FROM INVESTING ACTIVITIES:                |                                                                                          |                                                              |                                     |          |         |         |        
|                                                     | Additions to restricted bank accounts                                                    |                                                              | (160,360                            | )        |        |         |       
|                                                     | Acquisition of fixed assets                                                              |                                                              | (3,837                              | )        | (2,046  | )       | (2,813 
|                                                     | Proceeds from sale of fixed assets                                                       |                                                              | 2,571                               |          | 50      |         |       
|                                                     |                                                                                          |                                                              |                                     |          |         |         |        
|                                                     |                                                                                          | NET CASH USED IN INVESTING ACTIVITIES                        |                                     | (161,626 | )       | (1,996  | )      
|                                                     |                                                                                          |                                                              |                                     |          |         |         |        
|CASH FLOWS FROM FINANCING ACTIVITIES:                |                                                                                          |                                                              |                                     |          |         |         |        
|                                                     | Proceeds from long-term loans                                                            |                                                              |                                    |          |        |         | 46,980 
|                                                     | Repayment of long-term loans                                                             |                                                              | (126,989                            | )        | (20,000 | )       |       
|                                                     | Proceeds from subordinated loans                                                         |                                                              | 15,882                              |          |        |         |       
|                                                     | Repayment of subordinated loans                                                          |                                                              | (8,790                              | )        |        |         |       
|                                                     | Payment of financing costs                                                               |                                                              | (8,316                              | )        |        |         |       
|                                                     | Proceeds from financing costs refunded                                                   |                                                              |                                    |          |        |         | 1,858  
|                                                     |                                                                                          |                                                              |                                     |          |         |         |        
|                                                     |                                                                                          | NET CASH (USED IN) PROVIDED BY FINANCING ACTIVITIES          |                                     | (128,213 | )       | (20,000 | )      
|                                                     |                                                                                          |                                                              |                                     |          |         |         |        
|Net (decrease) increase in cash and cash equivalents |                                                                                          | (169,494                                                     | )                                   | 125,681  |         | 72,156  |        
|Cash and cash equivalents at beginning of year       |                                                                                          | 233,711                                                      |                                     | 108,030  |         | 35,874  |        
|                                                     |                                                                                          |                                                              |                                     |          |         |         |        
|Cash and cash equivalents at end of year             |                                                                                          | 64,217                                                       |                                     | 233,711  |         | 108,030 |        
|                                                     |                                                                                          |                                                              |                                     |          |         |         |        
|Supplemental cash flow disclosures:                  |                                                                                          |                                                              |                                     |          |         |         |        
|                                                     | Cash paid for interest                                                                   |                                                              | 135,963                             |          | 155,517 |         | 186,965
|                                                     | Cash paid for income taxes                                                               |                                                              | 4,025                               |          |        |         |       
|                                                     | 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 2003, 2002 and 2001  (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 30 February 1999, and published in Supplement No. 4853 to State Gazette No. 64 of 10 August 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 2003, 2002 and 2001, 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

Revenues
in 2003 were recognized upon the availability of net dependable capacity and the delivery of net electrical output to PT PLN (Persero) ("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 based upon plant availability. PLN is obligated to pay for net electrical output as it is delivered.

Revenues
for the year ended 31 December 2001 represent the amounts billed to PLN under the Phases I, II and III Interim Agreements, and for the year ended 31 December 2002
under the Binding Term Sheet for energy delivered in 2001 and 2002, respectively, plus the recoverable value of arrearages

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relating
to capacity charges and fixed operating costs under the PPA which therefore had 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:

2003

2002 and 2001Plant assets and facilities

38 years

30 yearsFurniture and equipment

4 years

4 years


Effective 1 January 2003, the Company changed its accounting estimates relating to depreciation. The estimated useful lives for plant
assets and facilities were extended by eight years. The change was made
as a result of the amendment of the PPA, the term for which was extended to 31 December 2040. The extension of the term of the PPA, as amended, results in the Company being able to utilize the
plant for an additional eight years. The Company believes that the plant assets and facilities economic useful lives are greater than 38 years from 1 January 2003, based on the existing
plant design. As a result of the change, 2003 depreciation expense decreased by USD 21,788.

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 held for use 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.

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 38 years in 2003 and 30 years in 2002 and 2001.

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Effective
1 January 2003, the Company changed its accounting estimates relating to amortization of the Special Facilities. The estimated useful lives for the Special Facilities
were extended by eight years. The change was made as a result of the amendment of the PPA, the term for which was extended to 31 December 2040. The extension of the term of the PPA, as amended,
results in the Company being able to utilize the Special Facilities for an additional eight years. As a result of the change, 2003 amortization expense decreased by USD 2,845.

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 recorded as interest expense.

i.Debt restructuring

In
2003, the Company restructured its senior debt facilities involving only the modification of terms. The restructured debt has been accounted for in accordance with SFAS No. 15,
"Accounting by Debtors and Creditors for Troubled Debt Restructurings." See Note 15.

j.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 for 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 counter-parties defaults. 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 Hedging Activities" and SFAS No. 138, "Accounting for Certain
Derivative Instruments and Certain Hedging Activities, an amendment of SFAS 133." SFAS Nos. 133, as amended requires 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.

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 or cash flows of hedged items. When it is determined that a derivative is not highly effective as a hedge

329

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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.

k.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.

l.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 currencies other than United States Dollars 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.

m.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. Amortization of the discount is reported as interest income in the statement of income.

n.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.

330

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o.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.

p.New accounting standards

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 2003, and accordingly the adoption of the standard did not have an effect on the Company's financial statements.

Effective
1 January 2003, the Company adopted 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 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. The
adoption of this standard had no impact 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 are applied in fiscal years beginning after 15 May 2002. The provisions of the Statement related to Statement No. 13 were effective for transactions occurring
after 15. May 2002. The adoption of this standard had no effect on the Company's financial statements.

In
June 2002, the FASB issued SFAS No. 146, "Accounting for Costs Associated with Exit or Disposal Activities." The standard requires that liabilities for costs associated
with exit or disposal activities initiated after 31 December 2002 be recognized when incurred, rather than at the date of a commitment to an exit or disposal plan. The Company adopted this
standard effective 1 January 2003. The adoption of this standard had no effect on the Company's financial statements.

In
December 2002, FASB Statement No. 148, "Accounting for Stock-Based CompensationTransition and Disclosure, an amendment of FASB Statement No. 123, was
issued. This Statement amends FASB Statement No. 123, "Accounting for Stock-Based Compensation, to provide alternative methods of transition for a voluntary change to the fair value method of
accounting for stock-based employee compensation. In addition, Statement 148 amends the disclosure requirements of Statement 123 to require prominent disclosures in both annual and interim
financial statements. The Company does not have stock-based compensation and therefore the adoption of the standard had no effect on the Company's financial statements.

In
April 2003, the FASB issued SFAS No. 149, "Amendment of Statement 133 on Derivative Instruments and Hedging Activities." This statement amends and clarifies financial
accounting and reporting for derivative instruments and for hedging activities under SFAS No. 133. The amendment reflects decisions made by the FASB and the Derivatives Implementation Group
(DIG) process in connection with issues raised about the application of SFAS No. 133. Generally, the provisions of SFAS

331

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No. 149
are applied prospectively for contracts entered into or modified after 30 June 2003 and for hedging relationships designated after 30 June 2003. SFAS No. 149
provisions that resulted from the DIG process that became effective in fiscal quarters beginning before 15 June 2003 will continue to be applied based upon their original effective dates. The
adoption of this standard had no impact on the Company's financial statements.

In
May 2003, the FASB issued SFAS No. 150, "Accounting for Certain Financial Instruments with Characteristics of both Liabilities and Equity." This statement establishes
standards for the classification and measurement of certain financial instruments with characteristics of both liabilities and equity. It requires that an issuer classify a financial instrument that
is within its scope as a liability or asset, as appropriate. SFAS No. 150 is effective for all freestanding financial instruments entered into or modified after 31 May 2003; otherwise,
it is effective at the beginning of the first interim period beginning after 15 June 2003. The adoption of this standard had no impact on the Company's financial statements.

In
December 2003, SFAS No. 132 (revised), "Employers' Disclosures about Pensions and Other Postretirement Benefits", was issued. SFAS No.132 (revised) prescribes employers'
disclosures about pension plans and other postretirement benefit plans; it does not change the measurement or recognition of those plans. The statement retains and revises the disclosure requirements
contained in the original SFAS No.132. It also requires additional disclosures about the assets, obligations, cash flows, and net periodic benefit cost of defined benefit pension plans and other
postretirement benefit plans. The Statement generally is effective for fiscal years ending after 15 December 2003.

In
November 2002, the FASB issued FASB 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 31 December 2002. The adoption of this standard had no impact on the
Company's financial statements.

In
December 2003, the FASB issued FASB Interpretation ("FIN") No. 46 (revised December 2003), "Consolidation of Variable Interest Entities ("VIEs")," which addresses how a
business enterprise should evaluate whether it has a controlling financial interest in an entity through means other than voting rights and accordingly should consolidate the entity. FIN 46R replaces
FASB Interpretation No. 46, "Consolidation of Variable Interest Entities," which was issued in January 2003. The Company will be required to apply FIN 46R to variable interests in VIEs created
after 31 December 2003. For variable interests in VIEs created before 1 January 2004, the Interpretation will be applied beginning on 1 January 2005. For any VIEs that must be
consolidated under FIN 46R that were created before 1. January 2004, the assets, liabilities and non-controlling interests of the VIE initially would be measured at their carrying
amounts with any difference between the net amount added to the balance sheet and any previously recognized interest being recognized as the cumulative effect of an accounting change. If determining
the carrying amounts is not practicable, fair value at the date FIN 46R first applies may be used to measure the assets, liabilities and non-controlling interest of the VIE. The Company
does not believe that this new standard will have a material effect on the Company's financial statements.

332

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3. Cash and Cash Equivalents

2003

2002Cash on hand

4

3Cash in banks

51,172

231,758Call deposits

13,041

1,95064,217

233,711


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 450,470 and USD 453,270 at 31 December 2003 and 2002, respectively. The Company billed restructuring settlement payments aggregating USD
48,000 in both 2003 and 2002. Interest income recognized on this long-term receivable totaled USD 45,200 and USD 45,466 in 2003 and 2002, respectively.

2003

2002Total restructuring settlement payments

1,344,000

1,392,000Less: unamortized discount

(893,530
)
(938,730
)Long-term receivable less unamortized discount

450,470

453,270


5. Fuel Inventory and Supplies

2003

2002Coal inventory

15,106

19,528Fuel oil inventory

111

68Supplies

7,665

4,97022,882

24,566


6. Plant and Equipment

a.Plant and equipment are comprised of the following:

2003Beginning
balance

Additions

Retirements &
disposals

Ending
balanceAt cost:Plant assets and facilities

2,168,798

2,334

(2,874
)
2,168,258Furniture and equipment

7,603

1,503

(155
)
8,9512,176,401

3,837

(3,029
)
2,177,209Accumulated depreciation:Plant assets and facilities

(249,835
)
(50,530
)
330

(300,035
)Furniture and equipment

(5,318
)
(1,260
)
154

(6,424
)(255,153
)
(51,790
)
484

(306,459
)Net book value

1,921,248

(47,953
)
(2,545
)
1,870,750


333

---

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


b.Depreciation charged to operating expenses amounted to USD 51,790, USD 73,721, and USD 71,588 in 2003, 2002 and
2001, respectively.

c.Effective 1 January 2003, the Company changed its accounting estimates relating to depreciation of plant assets and
facilities. See Note 2e.

d.Substantially all of the Company's assets have been pledged as collateral for the repayment of long-term
loans. See Note 9.

7. Deferred Charges

2003

2002Special facilities costs deferred

281,814

281,814Less accumulated amortization

(39,473
)
(32,924
)Net deferred charges

242,341

248,890


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.

Effective
1 January 2003, the Company changed its accounting estimates relating to amortization of the Special Facilities. See Note 2g. Amortization charged to operating
expenses amounted to USD 6,549, USD 9,394, and USD 9,393 in 2003, 2002 and 2001, respectively.

8. Related Party Transactions

a.Advanced costs

Certain
costs were incurred by related parties on behalf of, and charged to the Company. These costs aggregated approximately USD 4,246, USD 3,813, and USD 2,454 in 2003, 2002 and 2001,
respectively.

334

---

b.Certain other transactions with related parties are also discussed in Note 9 and Note 14.

9. Long-Term Loans

Long-term loans were comprised as follows:

2003

2002Senior Debt FacilitiesUSEXIM Facility



507,882USEXIM Facilitytranche A

339,265

USEXIM Facilitytranche B

101,907

JBIC Facilitytranche A

496,300

506,398JBIC Facilitytranche B

253,308

337,603OPIC Facility



197,480OPIC Facilitytranche A

49,717

OPIC Facilitytranche B

134,403

1,374,900

1,549,363Senior Debt Funding Loan

180,000

180,000Subordinated LoansEdison Mission Energy Asia Pte., Ltd.

176,004

176,004Paiton Power Financing B.V.

143,018

143,018Capital Indonesia Power I C.V.

54,978

54,978374,000

374,000Series B Subordinated LoansEdison Mission Energy Asia Pte., Ltd.

128,506

137,296Paiton Power Financing B.V.

104,421

92,949Capital Indonesia Power I C.V.

40,141

35,731273,068

265,976Total

2,201,968

2,369,339Current maturities of long-term loans

(140,851
)
(140,851
)Non-current portion

2,061,117

2,228,488


Senior Debt Facilities

On 14 February 2003, the Company entered into a certain second amended and restated common agreement (the "Common Agreement"), 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"), Wells Fargo Bank Minnesota, N.A. (as the Commercial Bank Tranche A Facility Agent), ING Capital LLC (as the USEXIM Construction Facility Agent), JP Morgan Chase Bank
(as the Trustee), Wells Fargo Bank Minnesota, N.A. (as the Indenture Trustee), Mizuho Corporate Bank, Ltd. (as the Collateral Agent) and JP Morgan Chase Bank (as Intercreditor Agent).

The
principal effect of the Common Agreement is to establish certain uniform terms which are applicable to all 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

335

---

lenders
who were to provide an aggregate of USD 1,820,000. The senior debt facilities are comprised of variable-rate-based loans and fixed-rate-based
loans. 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.

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 payments coincide with the scheduled principal payments dates. Repayment of the loan principal was originally 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 1999, 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 agreed 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 included 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 continued 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. See Note 15.

In
addition, pursuant to the terms of Section 8.3 of the Common Agreement, the lenders waived all defaults, Events of Default and Potential Events of Default existing under the
Financing Documents as of February 13, 2003. No interest was incurred in 2003, 2002 or 2001.

As
discussed in Note 15, on 14 February 2003, the Company and its lenders executed the Second Amended and Restated Common Agreement. The terms and conditions of the
Company's senior debt facilities pursuant to the provisions of the Second Amended and Restated Common Agreement can be summarized as follows:

a.     USEXIM

USEXIM A

USEXIM BPrincipal Outstanding

USD 380,911

USD 126,971Period

15 February 2003 - 15 November 2013

15 February 2003 - 15 November 2011Interest

Fixed rate 7.5% p.a.

Fixed rate 7.5% p.a.


b.     JBIC

JBIC A

JBIC BPrincipal Outstanding

USD 506,398

USD 337,603Period

15 February 2003 - 15 November 2013

15 February 2003 - 15 November 2011Interest

LIBOR plus margin

LIBOR plus margin


336

---

c.     OPIC

OPIC A

OPIC BPrincipal Outstanding

USD 52,799

USD 144,681Period

15 February 2003 - 15 November 2013

15 February 2003 - 15 November 2013Interest

Fixed rate 7.5% p.a.

Three-month Treasury Bill-based OPIC-guaranteed paper plus margin


Pursuant to the debt restructuring, the Company is required to allocate funds into restricted bank accounts for which use is restricted. The
accounts are restricted as to use for taxes, plant maintenance, debt service and settlement of fuel supply and EPC liabilities (the "Restructuring Settlements Account"). The balances of these
respective accounts as of 31 December 2003 were as follows:

Tax Payment Account

494Debt Service Account

26,112Restructuring Settlements Account

752Current

27,358Major Maintenance Reserve Account

6,045Debt Service Reserve Account

126,957Non-current

133,002Total

160,360


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 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. Principal payments on the Bonds commence in 2008, and the Bonds mature in 2014.

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 passu
basis 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

337

---

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 Company incurred interest of USD 47,609 for the period from 1 April to 31 December 2003. The Subordinated Lenders cancelled the Company's
interest obligation for the three-month period ended 31 March 2003 and for the years ended 31 December 2002 and 2001 on or before the commencement of each of the respective periods.

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. No interest was incurred in 2003, 2002, or
2001.

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 2003:

2004

140,8512005

140,8512006

140,8512007

140,8512008

153,001Thereafter

1,519,1752,235,580


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 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. At 31
December 2003, LIBOR was 1.2% 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 amounts vary over the calculation periods; however, they were intended to correspond with anticipated borrowing levels over the period of the long-term financing. All interest
rate swap agreements continue to be fully effective after the restructuring of debt discussed in Note 15.

In
accordance with SFAS No. 133, as amended, the Company recorded a liability for the loss on these interest rate swap agreements of USD 72,915 and USD 98,296, before income
taxes, as of 31 December 2003 and 2002, 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 72,915 at 31 December 2003 include approximately USD 25,675 that is expected to be reclassified into earnings in 2004.

338

---



Under
the agreements, the aggregate notional amount was at its highest level (approximately USD 1,100,000) in 1999. At 31 December 2003, the total notional amount subject
to the swap agreements totaled approximately USD 361,666, 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 creditworthy counterparties whose credit quality are 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 2003:

Notional
amount

Maturity
date

Pay swap
rate

Fair market
value at
31 December 2003Interest rate swap

116,250

15/08/2011

8.965
%
(23,304
)Interest rate swap

116,250

15/08/2011

9.035
%
(23,608
)Interest rate swap

64,583

15/08/2011

8.980
%
(12,985
)Interest rate swap

64,583

15/08/2011

8.995
%
(13,018
)361,666





(72,915
)


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, restricted cash, accounts receivable, and accounts payable to related partiesthe carrying amounts approximate fair value because of the short
duration 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.

339

---

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 creditworthiness of the swap counterparties.

2003

2002Carrying
amount

Estimated
fair value

Carrying
amount

Estimated
fair valueFinancial assets:Cash and cash equivalents

64,217

64,217

233,711

233,711Restricted cash

160,360

160,360



Accounts receivable

78,768

78,768

83,204

83,204Long-term receivable

450,470

450,470

453,270

453,270Financial liabilities:Accounts payable to related parties

(111,296
)
(111,296
)
(180,243
)
(180,243
)Long-term loans

(2,201,968
)
(2,190,768
)
(2,369,339
)
(2,238,788
)Interest rate swap contracts

(72,915
)
(72,915
)
(98,296
)
(98,296
)


12. Share Capital

The Company's authorized share capital as of 31 December 2003 and 2002 amounts to USD 306,000 (30,600 shares at par value of USD 10,000 per share),
of which USD 306,000 (30,600 shares) and USD 250,000 (25,000 shares) at 31 December 2003 and 2002, respectively, have been issued to and paid-up by the following
shareholders:

31 December 2003Shareholders

Number of
shares

Par value

%MEC Indonesia, B.V.

12,240

122,400

40.00Paiton Power Investment Co. Ltd.

9,945

99,450

32.50Capital Indonesia Power I C.V.

3,825

38,250

12.50PT Batu Hitam Perkasa

4,590

45,900

15.0030,600

306,000

100.00


31 December 2002Issued and paid-up
share capitalShareholders

Number of
shares

Par value

Paid in advance
for shares to
be issuedMEC 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


A circular resolution of the shareholders of the Company dated 10 April 2003 approved the increase of issued and paid-up share
capital of the Company from USD 250,000 to USD 306,000. The

340

---

circular
resolution was effected by deed of notary public Popie Savitri Martosuhardjo Pharmanto SH, dated 23 May 2003, No. 78.

A
circular resolution of the shareholders of the Company dated 4 June 2003 approved the transfer of 3,060 shares owned by PT Batu Hitam Perkasa to MEC Indonesia, B.V. (1,440
shares), Paiton Power Investment Co. Ltd. (1,170 shares) and Capital Indonesia Power I C.V. (450 shares). The circular resolution was effected by deed of notary public Popie Savitri
Martosuhardjo Pharmanto SH, dated 4 July 2003, No. 12. The deed was approved by the Capital Investment Coordination Board under No. 29/III/PMA2004 on 14 January 2004
and the contemplated transfers were effected on 21 January 2004. The composition of shareholders at 31 December 2003 presented above does not reflect these transfers of shares, as the
effective date of the transfer occurred subsequent to year end.

13. Income Tax

Income tax (expense) benefit attributable to income (loss) from operations consists of:

2003

2002

2001Current





Deferred

(39,293
)
(28,573
)
25,849(39,293
)
(28,573
)
25,849


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:

2003

2002

2001Indonesian income tax (expense) benefit at statutory rate

(37,648
)
(27,847
)
27,135Items not deductible for tax purposes

(1,645
)
(726
)
(1,286
)(39,293
)
(28,573
)
25,849


The items that give rise to significant portions of the deferred tax assets and deferred tax liability at 31 December 2003 and 2002 are
presented below:

2003

2002Deferred tax assets:Derivative financial instruments

21,874

29,489Accrued liabilities

2,143

12,929Deferred financing costs

4,934

1,667Net operating loss carryforwards

6,118

18,536Net deferred tax assets

35,069

62,621Deferred tax liability:Fixed assets and deferred charges, principally due to differences in depreciation and capitalized interest

(77,774
)
(58,418
)Deferred tax (liability) assets, net

(42,705
)
4,203


At 31 December 2003, the Company had tax loss carryforwards totaling approximately USD 20,393 which will all expire in 2006.
Realization of the Company's deferred tax assets is dependent upon its profitable operations. Although realization is not assured, the Company believes that it is more likely

341

---

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 its 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 remote 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 (as amended as of 28 June 2002, the "PPA"), 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.

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 19 as of 31 December 2003) annually for the right to use the site.

Upon
commercial operation of the Project, the Company is obligated to make available to PLN the net electrical output of the Project's plant facilities, which output will be purchased by
PLN at amounts determined under certain formulae set forth in the PPA. 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, 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, 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, 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

342

---

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 completion of discussions to amend and restructure the original PPA (prior to its amendment), PLN and the Company entered into various interim agreements,
under which 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 for the PPAA, thus,
effecting the amendments to the original PPA. 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.

Under
the PPA, as amended, the Company is to be paid for capacity and energy charges, as well as a monthly 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 is obligated to 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 was
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 the 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
FCCP 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

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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. Under the GSA, the Company must pay all amounts owing under the GSA prior to payments of the subordinated debt or dividends. In 2003, the Company paid the Contractor USD 78,429 comprising
partial payments of FCCP of USD 53,228 and interest of USD 25,201. The accompanying financial statements include amounts due to the Contractor aggregating USD 102,850 and USD 177,164 as of
31 December 2003 and 2002, respectively.

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 is obligated to provide the operation, maintenance and repair services necessary for the production and delivery of electrical energy by the plant.
Commencing from Operational Acceptance of the Plant, the Company shall to pay to or receive from the Operator an incentive fee or a performance shortfall amount to the excess or shortage of Actual
Availability Factor ("AFa") over Projected Availability Factor ("AFpm") under the PPA for the relevant contract year.

On
22 April 2003, the Company and EMOMI entered into the Amendment to O&M Agreement. Under the Amendment, the Company agreed to modify the incentive fee and to effect certain
modifications to the agreement.

As
compensation for the services, the Operator is paid 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 base fees of USD 3,649, USD 3,595, and USD 3,502 by the Operator in 2003, 2002 and 2001, respectively. The Company was billed incentive
fees totalling USD 10,527 and USD 1,533 in 2003 and 2002, respectively. No incentive fees were incurred nor were performance shortfall amounts received in 2001.

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 billion (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, 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, as amended on 21 December 1999, was entered by and among the Company, BHP, PT Adaro Indonesia ("Adaro"),
PT

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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 proceed with the stayed arbitration and further to assert 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. 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. The Company paid BHP USD 10,250 on 30 December 2002 and the remaining USD 5,975 in 2003.

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. The Company paid IBT USD 15,957 on 31 October 2003 and
USD 5,472 on 31 December 2003. The accompanying financial statements include amounts due to IBT of USD 7,143 and USD 28,572 as of 31 December 2003 and 2002, respectively.

The
Company and LDA entered into the LDA Settlement Agreement dated 4 December 2001, as amended as of 31 January 2002. Under the agreement, the Company shall pay to LDA an
aggregate principal amount of USD 13,000 as the Termination Payment. Interest is payable on the aggregate unpaid principal amount of termination payment at LIBOR plus 1.5% per annum beginning on 31
January 2003. In 2003, the Company paid the full amount of the termination payment and the related interest.

On
20 December 2002, the Company entered into Primary Supply Contracts (the "Contracts") with PT Adaro Indonesia and PT Kideco Jaya Agung (the "fuel suppliers"). Under the
Contracts, 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 coal take in any year. The Contracts are valid until 31 December 2006 and can be extended for up to two additional consecutive terms
of five years.

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, 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 dismissing all claims. On 23 April 2002, the PLN Labor Union registered its appeal against the decision of the District Court to the
High Court. All the appeals are pending at the High Court, however, no steps have been undertaken by the PLN Labor Union to pursue its appeal.

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 if the appeal proceeds. 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.

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15. Debt Restructuring

As discussed in Note 9, the Company had violated certain covenants on its loans and the Company was in default under the terms of financing agreements with
Senior Lenders, and the Common Agreement.
On 14 February 2003, the Company completed its debt restructuring negotiations with its lenders. In connection with the successful completion of these negotiations, the Company executed the
Common Agreement between the Company and its lenders. The Company has accounted for the debt restructuring as a troubled debt restructuring in accordance with SFAS No. 15, on the basis that the
Company was experiencing financial difficulty through PLN's failure to pay according to the original terms of the PPA, and the Senior Lenders granted a concession to the Company. This concession is in
the form of the effective borrowing rate on the restructured debt being less than the effective rate on the debt immediately prior to restructuring. Further, under the Common Agreement and the related
Facility Credit Agreements, the original maturities of each of the senior debt facilities were lengthened. The carrying amount of the senior debt facilities at the time of restructuring amounted to
approximately USD 1,501,889. The Company did not recognize a gain on the debt restructuring as the total payments of principal and interest over the remaining term of the debt exceeded the carrying
amount of the senior debt facilities.

In
accordance with the provisions of SFAS No. 15, the deferred financing costs of USD 75,225 and accrued finance costs of USD 27,751 relating to levelizing of interest rates under
the terms of the Common Agreement at the time of the restructuring were adjusted to the outstanding loan balances for purposes of financial statement presentation. The effective interest rates
applicable to each of the facilities are the discount rate that equates the present value of the future cash payments specified by the new terms with the carrying amount of the payable. Certain debt
restructuring costs qualified for deferral totalling USD 8,316. All other costs were expensed in the period incurred.

16. 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 economic difficulties including liquidity problems, volatility in prices, and significant slowdowns in business
activity. The economic 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 operations. 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 which was an event of default under 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.

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In
December 2002, the PPA was amended as discussed in Note 14a. PLN has paid all invoices and all Restructuring Settlement Payments for 2003 and 2002, on time, as required
and in accordance with the billing procedures agreed in the amended PPA.

As
discussed in Notes 9 and 15, 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
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 2004.

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.

17. Liquidity

The Company's management has undertaken a detailed analysis of the cash flows of the Company for the twelve months ended 31 December 2004. 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 and President |  | March 12, 2004
|Controller or Principal Accounting Officer:       |  |                                       |  |               
|/s/MARK C. CLARKEMark C. Clarke                   |  | Controller                            |  | March 12, 2004
|Majority of Board of Directors:                   |  |                                       |  |               
|/s/JOHN E. BRYSONJohn E. Bryson                   |  | Director, Chairman of the Board       |  | March 12, 2004
|/s/BRYANT C. DANNERBryant C. Danner               |  | Director                              |  | March 12, 2004
|/s/THEODORE F. CRAVER, JR.Theodore F. Craver, Jr. |  | Director                              |  | March 12, 2004

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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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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                                                   |  | $                        | (1,678  
|                                                                     |  |                          |         
|Operating loss                                                       |  |                          | (1,678  
|Equity in income from continuing operations of subsidiaries          |  |                          | 18,628  
|Equity in income (loss) from discontinued operations of subsidiaries |  |                          | 1,008   
|Interest expense and other                                           |  |                          | (157,732
|                                                                     |  |                          |         
|Loss before income taxes                                             |  |                          | (139,774
|Benefit for income taxes                                             |  |                          | (61,115 
|                                                                     |  |                          |         
|Net loss                                                             |  | $                        | (78,659 
|                                                                     |  |                          |         

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SCHEDULE I

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           |                                           | $                        | 47,764 
|Net cash provided by financing activities           |                                           |                          |       
|Net cash provided by (used in) investing activities |                                           |                          | 14,703 
|                                                    |                                           |                          |        
|Net increase in cash and cash equivalents           |                                           |                          | 62,467 
|Cash and cash equivalents at beginning of period    |                                           |                          | 87,210 
|                                                    |                                           |                          |        
|Cash and cash equivalents at end of period          |                                           | $                        | 149,677
|                                                    |                                           |                          |        
|Other Cash Flow Data:                               |                                           |                          |        
|                                                    | Cash dividends received from subsidiaries |                          | $      
|                                                    |                                           |                          |        

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MISSION ENERGY HOLDING COMPANY AND SUBSIDIARIES  VALUATION AND QUALIFYING ACCOUNTS  (In thousands)

|                             |                                    | Additions
|---------------------------- | ---------------------------------- | ---------
|
|Year Ended December 31, 2003 |                                    |          
|                             | Allowance for doubtful accounts(1) |          
|Year Ended December 31, 2002 |                                    |          
|                             | Allowance for doubtful accounts(1) |          
|Year Ended December 31, 2001 |                                    |          
|                             | Allowance for doubtful accounts(1) |          

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