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UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549


FORM 10-K

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

For the fiscal year ended December 31, 2002

Commission File Number 333-68632


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

Delaware   95-4867576
(State or other jurisdiction of incorporation
or organization)
  (I.R.S. Employer Identification No.)

2600 Michelson Drive, Suite 1700
Irvine, California

 

 
92612
(Address of principal executive offices)   (Zip Code)

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


        Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. YES ý NO o

        Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K is not contained herein, and will not be contained, to the best of registrant's knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K. ý

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

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

DOCUMENTS INCORPORATED BY REFERENCE

        Portions of the following documents listed below have been incorporated by reference into the parts of this report so indicated.

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




TABLE OF CONTENTS

 
   
  Page
    PART I    
Item 1.   Business   1
Item 2.   Properties   28
Item 3.   Legal Proceedings   29
Item 4.   Submission of Matters to a Vote of Security Holders   31

 

 

PART II

 

 
Item 5.   Market for Registrant's Common Equity and Related Stockholder Matters   32
Item 6.   Selected Financial Data   33
Item 7.   Management's Discussion and Analysis of Results of Operations and Financial Condition   34
Item 7a.   Quantitative and Qualitative Disclosures about Market Risk   116
Item 8.   Financial Statements and Supplementary Data   117
Item 9.   Changes in and Disagreements with Accountants on Accounting and Financial Disclosure   117

 

 

PART III

 

 
Item 10.   Directors and Executive Officers of the Registrant   195
Item 11.   Executive Compensation   196
Item 12.   Security Ownership of Certain Beneficial Owners and Management   197
Item 13.   Certain Relationships and Related Transactions   197
Item 14.   Controls and Procedures   197

 

 

PART IV

 

 
Item 15.   Exhibits, Financial Statement Schedules and Reports on Form 8-K   199
    Signatures   366
    Certifications   367


PART I

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

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


ITEM 1. BUSINESS

The Company

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

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

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

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

Forward-Looking Statements

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

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

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

Description of Business

Electric Power Industry

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

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

Competition and Market Condition Generally

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

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

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

Segment Information

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

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Regional Overview of Business Segments

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

Power Plants

  Location
  Primary Electric Purchaser(2)
  Type of
Facility(3)

  Ownership Interest
  Electric Capacity (in MW)
  Net Electric Capacity (in MW)
American Bituminous(1)   West Virginia   MPC   Waste Coal   50 % 80   40
Brooklyn Navy Yard   New York   CE   Cogeneration/EWG   50 % 286   143
Coalinga(1)   California   PG&E   Cogeneration   50 % 38   19
EcoEléctrica(1)   Puerto Rico   PREPA   Cogeneration   50 % 540   270
Gordonsville(1)   Virginia   VEPCO   Cogeneration/EWG   50 % 240   120
Homer City(1)   Pennsylvania   Pool   EWG   100 % 1,884   1,884
Illinois Plants (12 plants)(1)   Illinois   EG   EWG   100 % 9,287   9,287
Kern River(1)   California   SCE   Cogeneration   50 % 300   150
March Point I   Washington   PSE   Cogeneration   50 % 80   40
March Point II   Washington   PSE   Cogeneration   50 % 60   30
Mid-Set(1)   California   PG&E   Cogeneration   50 % 38   19
Midway-Sunset(1)   California   SCE   Cogeneration   50 % 225   112
Salinas River(1)   California   PG&E   Cogeneration   50 % 38   19
Sargent Canyon(1)   California   PG&E   Cogeneration   50 % 38   19
Sunrise—Phase 1(1)   California   CDWR   EWG   50 % 320   160
Sycamore(1)   California   SCE   Cogeneration   50 % 300   150
Watson   California   SCE   Cogeneration   49 % 385   189
                   
 
  Total Americas                   14,139   12,651
                   
 

(1)
Plant is operated under contract by an EME operations and maintenance subsidiary (partially owned plants) or plant is operated directly by an EME subsidiary (wholly owned plants).

(2)
Electric purchaser abbreviations are as follows:

CDWR   California Department of Water Resources   PREPA   Puerto Rico Electric Power Authority
CE   Consolidated Edison Company of New York, Inc.   PSE   Puget Sound Energy, Inc.
EG   Exelon Generation Company   SCE   Southern California Edison Company
MPC   Monongahela Power Company   VEPCO   Virginia Electric & Power Company
PG&E   Pacific Gas & Electric Company        
Pool   Regional electricity trading market        
(3)
All the cogeneration plants are gas-fired facilities. All the exempt wholesale generator (EWG) plants are gas-fired facilities, except for the Homer City facilities and six of the Illinois Plants, which use coal.

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

Power Plants

  Location
  Primary
Electric
Purchaser(2)

  Ownership
Interest

  Electric
Capacity (in MW)

  Net Electric
Capacity (in MW)

Europe:                    
Derwent(1)   England   SSE   33 % 214   71
Doga(1)   Turkey   TEAS   80 % 180   144
First Hydro (2 plants)(1)   Wales   Various   100 % 2,088   2,088
Iberian Hy-Power I (5 plants)(1)   Spain   FECSA   100 %(4) 43 (6) 39
Iberian Hy-Power II (13 plants)(1)   Spain   FECSA   100 % 43 (6) 43
ISAB   Italy   GRTN   49 % 518   254
Italian Wind (13 plants)   Italy   GRTN   50 % 303   152
               
 
  Total Europe               3,389   2,791
               
 
Asia Pacific:                    
Contact Energy (10 plants)   New Zealand   Pool   51% (5) 2,302   1,064
Caliraya(1)   Philippines   NPC   50 % 22   11
Kalayaan I(1)   Philippines   NPC   50 % 363   182
Kwinana(1)   Australia   WP   70 % 116   81
Loy Yang B(1)   Australia   Pool(3)   100 % 1,000   1,000
Paiton(1)   Indonesia   PLN   40 % 1,230   492
Tri Energy   Thailand   EGAT   25 % 700   175
Valley Power Peaker(1)   Australia   Pool   80 % 300   241
               
 
  Total Asia Pacific               6,033   3,246
               
 
  Total International               9,422   6,037
               
 

(1)
Plant is operated under contract by an EME operations and maintenance subsidiary (partially owned plants) or plant is operated directly by an EME subsidiary (wholly owned plants).

(2)
Electric purchaser abbreviations are as follows:

 
   
   
   
EGAT   Electricity Generating Authority of Thailand   Pool   Electricity trading market for Australia and New Zealand
FECSA   Fuerzas Electricas de Cataluma, S.A.   SSE   Scottish and Southern Electric plc.
GRTN   Gestore Rete Transmissione Nazionale   TEAS   Turkiye Elektrik Urehm A.S.
NPC   National Power Corp.   WP   Western Power
PLN   PT PLN        
(3)
Sells to the pool with a long-term contract with the State Electricity Commission of Victoria.

(4)
Minority interest in three power plants.

(5)
Minority interest in one power plant.

(6)
Total nameplate rating of all generators shown. Actual maximum operating capacity may be reduced by streamflows.

Americas

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

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Illinois Plants

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

        The Illinois Plants include the following:

Plant or Site

  Location
  Leased/
Owned

  Type
  Megawatts
Electric Generating Facilities                
Collins Station(1)   Grundy County, Illinois   leased   oil/gas   2,698
Crawford Station   Chicago, Illinois   owned   coal   542
Fisk Station   Chicago, Illinois   owned   coal   326
Joliet Unit 6   Joliet, Illinois   owned   coal   314
Joliet Units 7 and 8   Joliet, Illinois   leased   coal   1,044
Powerton Station   Pekin, Illinois   leased   coal   1,538
Waukegan Station   Waukegan, Illinois   owned   coal   789
Will County Station(1)   Romeoville, Illinois   owned   coal   1,092

Peaking Units

 

 

 

 

 

 

 

 
Crawford   Chicago, Illinois   owned   oil/gas   121
Fisk   Chicago, Illinois   owned   oil/gas   163
Joliet   Joliet, Illinois   owned   oil/gas   101
Waukegan   Waukegan, Illinois   owned   oil/gas   92
Calumet   Chicago, Illinois   owned   oil/gas   129
Bloom   Chicago Heights, Illinois   owned   oil/gas   45
Electric Junction   Aurora, Illinois   owned   oil/gas   159
Lombard   Lombard, Illinois   owned   oil/gas   64
Sabrooke   Rockford, Illinois   owned   oil/gas   70
               
        Total   9,287
               

(1)
Beginning in January 2003, operations at Collins Station Units 4 and 5 (1,060 megawatts (MW)) and at Will County Station Units 1 and 2 (310 MW) were suspended pending improvement in market conditions.

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

Power Purchase Agreements

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

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

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

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

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

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Coal-Fired Units

 
   
  Summer(1)
Capacity Charge
($ per MW Month)

  Non-Summer(1)
Capacity Charge
($ per MW Month)

  Energy Prices
($/MWhr)

Generating Unit

  Unit Size
(MW)

  2003
  2004
  2003
  2004
  2003
  2004
Committed Units                            
  Waukegan Unit 7   328   11,000   11,000   1,375   1,375   17.0   17.0
  Crawford Unit 8   326   11,000   11,000   1,375   1,375   17.0   17.0
  Will County Unit 4   520   11,000   11,000   1,375   1,375   17.0   17.0
  Joliet Unit 8   522   11,000   11,000   1,375   1,375   17.0   17.0
   
                       
    1,696                        
Option Units(2)                            
  Waukegan Unit 6   100   21,300   21,300   2,663   2,663   20.0   20.0
  Waukegan Unit 8   361   21,300   21,300   2,663   2,663   20.0   20.0
  Fisk Unit 19   326   21,300   21,300   2,663   2,663   20.0   20.0
  Crawford Unit 7   216   21,300   21,300   2,663   2,663   20.0   20.0
  Will County Unit 3   262   21,300   21,300   2,663   2,663   20.0   20.0
   
                       
    1,265                        
Released Units(3)                            
  Will County Unit 1(4)   156                        
  Will County Unit 2(4)   154                        
  Joliet Unit 6   314                        
  Joliet Unit 7   522                        
  Powerton Unit 5   769                        
  Powerton Unit 6   769                        
   
                       
    2,684                        
   
                       
    5,645                        
   
                       

(1)
"Summer" months are June, July, August and September, and "Non-Summer" months are the remaining months in the year.

(2)
Option units refer to those units for which Exelon Generation has exercised its right to purchase capacity and energy during 2003 under the terms of the power purchase agreement. Exelon Generation continues to have a similar option related to these units for 2004.

(3)
Released units refer to those option units for which Exelon Generation has not exercised its right to purchase capacity and energy during 2003, and which are thus released from the terms of the power purchase agreement. Since January 1, 2003, the price for energy and capacity from these units has been based upon either the terms of new bilateral contracts or prices received from forward and spot market sales.

(4)
Operations currently suspended.

        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

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

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

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

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


Collins Station

 
   
  Summer(1)
Capacity Charge
($ per MW Month)

  Non-Summer(1)
Capacity Charge
($ per MW Month)

  Energy Prices
($/MWhr)

Generating Unit

  Unit Size
(MW)

  2003
  2004
  2003
  2004
  2003
  2004
Option Units(2)                            
  Collins Unit 1   554   8,333   8,333   2,083   2,083   33   34
  Collins Unit 3   530   8,333   8,333   2,083   2,083   33   34
   
                       
    1,084                        
Released Units(3)                            
  Collins Unit 2   554                        
  Collins Unit 4(4)   530                        
  Collins Unit 5(4)   530                        
   
                       
    1,614                        
   
                       
    2,698                        
   
                       

(1)
"Summer" months are June, July, August and September, and "Non-Summer" months are the remaining months in the year.

(2)
Option units refer to those units for which Exelon Generation has exercised its right to purchase capacity and energy during 2003 under the terms of the power purchase agreement. Exelon Generation continues to have a similar option related to these units for 2004.

(3)
Released units refer to those generating units for which Exelon Generation has exercised its right to terminate the power purchase agreement, and which are thus released from the terms of the power purchase agreement. Since January 1, 2003, the price for energy and capacity from these units has been based upon either the terms of new bilateral contracts or prices received from forward and spot market sales.

(4)
Operations currently suspended.

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

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

11


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

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

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


Peaking Units

 
   
  Summer(1)
Capacity Charge
($ per MW Month)

  Non-Summer(1)
Capacity Charge
($ per MW Month)

  Energy Prices
($/MWhr)

Generating Unit

  Unit Size
(MW)

  2003
  2004
  2003
  2004
  2003
  2004
Option Units(2)   694   9,500   9,500   1,500   1,500   55 - 90   60 - 95
Released Units(3)   250                        
   
                       
    944                        
   
                       

(1)
"Summer" months are June, July, August and September, and "Non-Summer" months are the remaining months in the year.

(2)
Option units refer to those units for which Exelon Generation has exercised its right to purchase capacity and energy during 2003 under the terms of the power purchase agreement. Exelon Generation continues to have a similar option related to these units for 2004.

(3)
Released units refer to those peaking units for which Exelon Generation has exercised its right to terminate the power purchase agreement, and which are thus released from the terms of the power purchase agreement. Since January 1, 2003 related to 113 MW and since January 1, 2002 related to 137 MW, the price for energy and capacity from these units has been based upon either the terms of new bilateral contracts or prices received from forward and spot market sales.

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

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

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

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

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

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

13



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

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

Homer City Facilities

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

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

Major Investments in California Cogeneration Plants

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

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

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

14



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

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

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

Other Americas Power Plants

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

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

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

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

15



Other Small Investments in Energy Projects

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

Investment in Four Star Oil & Gas Company

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

Asia Pacific

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

Australia

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

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

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

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New Zealand

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

Plant

  Type
  Megawatts
New Plymouth   Gas thermal   464
Clyde   Hydro   432
Otahuhu B   Natural gas   372
Roxbugh   Hydro   320
Oakey(1)   Natural gas   300
Wairakei   Geothermal   165
Ohaaki   Geothermal   104
Poihipi   Geothermal   55
Otahuhu A   Natural gas   45
Te Rapa   Natural gas   45
       
        2,302
       

(1)
Located in Australia. The plant has a total capacity of 300 MW in which Contact Energy owns a 25% share (75 MW). EME owns a 12.8% share (38 MW) through its 51.2% ownership interest in Contact Energy.

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

Indonesia

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

Philippines

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

17



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

Thailand

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

Europe

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

United Kingdom

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

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

Italy

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

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

18



Spain

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

Turkey

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

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

Discontinued Operations

Lakeland Project

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

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

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

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

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

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Ferrybridge and Fiddler's Ferry Plants

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

Price Risk Management and Trading Activities

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

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

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

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

20



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

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

        EME's merchant power plants and energy trading activities expose EME to commodity price risks. Commodity price risks are actively monitored to ensure compliance with EME's risk management policies. Policies are in place which limit the amount of total net exposure EME may enter into at any point in time. Procedures exist which allow for monitoring of all commitments and positions with regular reviews by a risk management committee. EME performs a "value at risk" analysis in its daily business to measure, monitor and control its overall market risk exposure. The use of value at risk allows management to aggregate overall commodity risk, compare risk on a consistent basis and identify the drivers of the risk. Value at risk measures the possible loss over a given time interval, under normal market conditions, at a given confidence level. Given the inherent limitations of value at risk and relying on a single risk measurement tool, EME supplements this approach with the use of stress testing and worst-case scenario analysis, as well as stop loss limits and counterparty credit exposure limits. Despite this, there can be no assurance that all risks have been accurately identified, measured and/or mitigated.

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

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Seasonality

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

Regulatory Matters

General

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

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

U.S. Federal Energy Regulation

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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Recent Foreign Regulatory Matters

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

Transmission of Wholesale Power

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

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

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

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

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

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

Retail Competition

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

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

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Environmental Matters and Regulations

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

Employees

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

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

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


ITEM 2. PROPERTIES

        MEHC's principal office is in Irvine, California.

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

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

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Description of Properties

Plant

  Business
Segment

  Location
  Interest
In Land

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


ITEM 3. LEGAL PROCEEDINGS

Brooklyn Navy Yard Project

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

EcoEléctrica Potential Environmental Proceeding

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

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

Regulatory Developments Affecting Sunrise Power Company

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

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

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

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Paiton Labor Suit

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

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


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

        Inapplicable.

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PART II

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

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

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

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

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

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ITEM 6. SELECTED FINANCIAL DATA

 
  Years Ended December 31,
 
 
  2002
  2001(1)
  2000
  1999
  1998
 
 
  (in millions)

 
INCOME STATEMENT DATA                                
Operating revenues   $ 2,750   $ 2,488   $ 2,189   $ 981   $ 607  
Operating expenses     2,421     2,184     1,783     887     475  
   
 
 
 
 
 
Operating income     329     304     406     94     132  
Equity in income from unconsolidated affiliates     283     374     267     244     189  
Interest expense     (633 )   (647 )   (584 )   (323 )   (184 )
Interest and other income     31     92     55     50     49  
   
 
 
 
 
 
Income from continuing operations before income taxes and minority interest     10     123     144     65     186  
Provision (benefit) for income taxes     (20 )   67     76     (45 )   64  
Minority interest     (27 )   (22 )   (3 )        
   
 
 
 
 
 
Income from continuing operations     3     34     65     110     122  
Income (loss) from operations of discontinued foreign subsidiaries (including loss on disposal of $1.1 billion in 2001), net of tax     (57 )   (1,219 )   38     34     10  
   
 
 
 
 
 
Income (loss) before accounting change     (54 )   (1,185 )   103     144     132  
Cumulative effect of change in accounting, net of tax     (14 )   15     22     (14 )    
   
 
 
 
 
 
Net income (loss)   $ (68 ) $ (1,170 ) $ 125   $ 130   $ 132  
   
 
 
 
 
 

(1)
In the fourth quarter of 2002, EME adopted SFAS No. 145, "Rescission of FASB Statements No. 4, 44 and 64, Amendment of FASB Statement No. 13, and Technical Corrections," 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.

 
  As of December 31,
 
  2002
  2001
  2000
  1999
  1998
 
  (in millions)

BALANCE SHEET DATA                              
Assets   $ 11,367   $ 11,108   $ 15,017   $ 15,534   $ 5,158
Current liabilities     1,835     962     2,357     1,439     321
Long-term obligations     6,034     6,845     5,252     6,147     2,279
Preferred securities of subsidiaries     281     254     327     477     150
Shareholder's equity     736     717     2,948     3,068     958

33



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

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

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

GENERAL

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


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

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

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

Current Developments

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

34



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

EME's Situation

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

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

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

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

35



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

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

Disposition of Investments in Energy Plants

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

36




RESULTS OF OPERATIONS

CONSOLIDATED OPERATING RESULTS

Net Income Summary

        Net income is comprised of the following components:

 
  Years Ended December 31,
 
  2002
  2001
  2000
 
  (in millions)

Mission Energy Holding Company:                  
Loss from continuing operations   $ (93 ) $ (49 ) $

Edison Mission Energy and its Consolidated Subsidiaries:

 

 

 

 

 

 

 

 

 
Income from continuing operations     96     83     65
Income (loss) from discontinued operations     (57 )   (1,219 )   38
Cumulative changes in accounting     (14 )   15     22
   
 
 
Net Income (loss)   $ (68 ) $ (1,170 ) $ 125
   
 
 

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

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

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

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

37



Operating Revenues

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

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

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

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

38



Operating Expenses

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

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

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

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

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

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

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

39



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

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

Other Income (Expense)

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

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

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

Project

  Gross Proceeds
  EME's Partnership
Interest Sold

  Date
Nevada Sun-Peak   $ 11   50 % December 5, 2001
Saguaro     67   50   September 20, 2001
Hopewell     27   25   June 29, 2001
Kwinana     12   30   August 16, 2000
Auburndale     22   50   June 30, 2000

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

40



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

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

Income Taxes

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

Minority Interest

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

Discontinued Operations

Lakeland Project

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

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

41



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

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

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

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

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

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

 
  Years Ended December 31,
 
 
  2002
  2001
  2000
 
 
  (in millions)

 
Operating revenues   $ 74   $ 82   $ 92  
Operating expenses(1)     145     57     67  
   
 
 
 
Operating income (loss)     (71 )   25     25  
Interest expense     (3 )   (5 )   (7 )
Interest and other income     1     1     1  
   
 
 
 
Income (loss) before income taxes     (73 )   21     19  
Provision (benefit) for income taxes     (17 )   6     5  
   
 
 
 
Income (loss) from operations   $ (56 ) $ 15   $ 14  
   
 
 
 

(1)
The year ended December 31, 2002 includes an impairment charge of $92 million discussed above.

Ferrybridge and Fiddler's Ferry Project

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

42



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

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

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

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

Cumulative Effect of Change in Accounting Principle

Discussion of Initial Adoption of SFAS No. 142

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

Accounting for Derivatives and SFAS No. 133

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

43



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

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

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

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

Accounting for Major Maintenance Costs

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

44



REGIONAL OPERATING RESULTS

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

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

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

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

Americas

 
  Years Ended December 31,
 
 
  2002
  2001
  2000
 
 
  (in millions)

 
Operating Revenues from Consolidated Subsidiaries                    
  Illinois Plants   $ 1,150   $ 1,090   $ 1,119  
  Homer City     389     494     422  
  Other     25     33     30  
   
 
 
 
    $ 1,564   $ 1,617   $ 1,571  
   
 
 
 
Income (Loss) before Taxes and Minority Interest (Earnings)                    
  Consolidated operations                    
  Illinois Plants     232     103     47  
  Homer City     37     126     60  
  Charges related to cancellation of turbine orders/leases     (61 )   (25 )    
  Other     39     29     72  
  Unconsolidated affiliates                    
  Big 4 projects     94     206     121  
  Four Star Oil & Gas     20     86     (44 )
  Sunrise     16     14      
  March Point     18     8     10  
  Other     28     56     64  
  Regional overhead     (44 )   (46 )   (27 )
   
 
 
 
    $ 379   $ 557   $ 303  
   
 
 
 

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Illinois Plants

 
  Years Ended December 31,
 
 
  2002
  2001
  2000
 
Statistics—Coal-Fired Generation                    
  Generation (in GWhr)     27,574     26,627     27,117  
  Availability     84.8 %   82.9 %   79.6 %
  Forced outage rate     6.5 %   9.5 %   9.8 %
  Average realized energy price/MWh   $ 16.89   $ 16.06   $ 15.43  
  Capacity revenues (in millions)   $ 601   $ 583   $ 576  

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

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

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

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

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

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

Homer City

 
  Years Ended December 31,
 
 
  2002
  2001
  2000
 
Statistics                    
  Generation (in GWhr)     12,111     12,922     11,796  
  Availability     76.8 %   87.4 %   80.2 %
  Forced outage rate     16.0 %   4.5 %   6.1 %
  Average realized energy price/MWh   $ 28.70   $ 33.07   $ 31.63  
  Capacity revenues (in millions)   $ 41   $ 67   $ 49  

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

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

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Charges Related to Cancellation of Turbine Orders/Leases

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

Big 4 Projects

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

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

Four Star Oil & Gas

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

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

Sunrise

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

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March Point

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

Other

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

Regional G&A

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

Asia Pacific

 
  Years Ended December 31,
 
 
  2002
  2001
  2000
 
 
  (in millions)

 
Operating Revenues from Consolidated Subsidiaries                    
  Contact Energy   $ 494   $ 297   $  
  Loy Yang B     157     129     144  
  Other     56     38     40  
   
 
 
 
    $ 707   $ 464   $ 184  
   
 
 
 
Income (Loss) before Taxes and Minority Interest (Earnings)                    
  Consolidated operations                    
  Contact Energy(1)     61     45     (15 )
  Loy Yang B     52     11     22  
  Other     12     13     20  
  Unconsolidated affiliates                    
  Paiton     23     (5 )   (3 )
  Other     6          
  Regional overhead     (13 )   (11 )   (16 )
   
 
 
 
    $ 141   $ 53   $ 8  
   
 
 
 

(1)
Income before taxes of Contact Energy represents both EME's 51% ownership and the ownership of minority interest holders on a calendar year basis. The interests of minority shareholders in the after-tax earnings of Contact Energy are reflected in a separate line item in the consolidated statements of income. See "—Consolidated Operating Results—Minority Interest." Contact Energy is a public company in New Zealand and provides shareholders' financial results in accordance with New Zealand accounting standards for its fiscal year ended September 30.

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Contact Energy

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

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

Loy Yang B

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

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

Paiton Energy

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

Other

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

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Regional G&A

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

Europe(1)

 
  Years Ended December 31,
 
 
  2002
  2001
  2000
 
 
  (in millions)

 
Operating Revenues from Consolidated Subsidiaries                    
  First Hydro   $ 317   $ 233   $ 333  
  Doga(2)     111     118     99  
  Other     24     18     18  
   
 
 
 
    $ 452   $ 369   $ 450  
   
 
 
 
Income (Loss) before Taxes and Minority Interest (Earnings)                    
  Consolidated operations                    
  First Hydro     20     10     115  
  Doga     17     11     8  
  Other     2     4     6  
  Unconsolidated affiliates                    
  ISAB     31     9     (9 )
  Other     3     5     2  
  Regional overhead     (23 )   (19 )   (19 )
   
 
 
 
    $ 50   $ 20   $ 103  
   
 
 
 

(1)
The results of Lakeland and Ferrybridge and Fiddler's Ferry are not included in this table since the operations are classified as discontinued operations for all historical periods presented. For more information on Lakeland and Ferrybridge and Fiddler's Ferry, see "—Consolidated Operating Results—Discontinued Operations."

(2)
Income before taxes of Doga represents both EME's 80% ownership and the ownership of minority interest holders on a calendar year basis. The interests of minority shareholders in the after-tax earnings of Doga are reflected in a separate line item in the consolidated statements of income. See "—Consolidated Operating Results—Minority Interest."

First Hydro

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

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

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

Doga

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

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

ISAB

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

Other

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

Regional G&A

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

Critical Accounting Policies and Estimates

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

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Derivative Financial Instruments and Hedging Activities

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

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

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

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

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

Impairment

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

53



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

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

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

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

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

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

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

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

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

Off-Balance Sheet Financing

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

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

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

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

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

Income Taxes

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

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

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

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LIQUIDITY AND CAPITAL RESOURCES

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

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

Mission Energy Holding Company's Liquidity

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

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

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

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

Edison Mission Energy's Credit Ratings

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

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

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

        As a result of these rating actions, EME has:

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

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

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

Downgrade of Edison Mission Midwest Holdings

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

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

S&P Rating
  Moody's Rating
  Cost of Borrowing
Margin

  Cash Trap

 
   
  (based on LIBOR)

   
BBB- or higher   Baa3 or higher   150   No cash trap
        BB+             Ba1   225   50% of excess cash flow trapped until six month debt service reserve is funded
        BB             Ba2   275   100% of excess cash flow trapped
        BB-             Ba3   325   100% of excess cash flow trapped
        B+             B1   325   100% cash sweep by lenders to repay debt (i.e., 100% of excess cash flow trapped and used to repay debt)

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

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

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Downgrade of Edison Mission Marketing & Trading

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

Edison Mission Energy's Liquidity

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

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

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

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

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

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

Discussion of Historical Cash Flow

Cash Flows From Operating Activities

        Net cash provided by (used in) operating activities:

 
  Years Ended December 31,
 
  2002
  2001
  2000
 
  (in millions)

Continuing operations   $ 866   $ (4 ) $ 655
Discontinued operations     54     (113 )   10
   
 
 
    $ 920   $ (117 ) $ 665
   
 
 

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

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

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

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

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

Cash Flows From Financing Activities

        Net cash provided by (used in) financing activities:

 
  Years Ended December 31,
 
 
  2002
  2001
  2000
 
 
  (in millions)

 
Continuing operations   $ (296 ) $ (182 ) $ (994 )
Discontinued operations     (19 )   (1,085 )   211  
   
 
 
 
    $ (315 ) $ (1,267 ) $ (783 )
   
 
 
 

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

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

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

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

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

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

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

Cash Flows From Investing Activities

        Net cash provided by (used in) investing activities:

 
  Years Ended December 31,
 
 
  2002
  2001
  2000
 
 
  (in millions)

 
Continuing operations   $ (305 ) $ (50 ) $ 760  
Discontinued operations     1     926     (42 )
   
 
 
 
    $ (304 ) $ 876   $ 718  
   
 
 
 

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

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

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

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

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Historical Distributions Received By Edison Mission Energy

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

 
  Years Ended
December 31,

 
  2002
  2001
 
  (in millions)

Distributions from Consolidated Operating Projects:            
  Edison Mission Midwest Holdings (Illinois Plants)   $   $ 75
  EME Homer City Generation L.P. (Homer City facilities)(1)         121
  First Hydro Holdings (First Hydro project)         52
  Holding companies of other consolidated operating projects     94    

Distributions from Non-Consolidated Operating Projects:

 

 

 

 

 

 
  Edison Mission Energy Funding Corp. (Big 4 Projects)(2)     137     129
  Four Star Oil & Gas Company     21     61
  Holding companies of other non-consolidated operating projects     99     32
   
 
Total Distributions   $ 351   $ 470
   
 

(1)
Distributions during 2001 were made from Edison Mission Holdings Co., a holding company which indirectly owns 100% of EME Homer City Generation L.P.

(2)
The Big 4 projects are comprised of investments in the Kern River project, Midway-Sunset project, Sycamore project and Watson project. Distributions do not include either capital contributions made during the California energy crisis or the subsequent return of such capital. Distributions reflect the amount received by EME after debt service payments by Edison Mission Energy Funding Corp.

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

        Partially offset by:

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Restricted Assets of EME's Subsidiaries

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

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

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

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

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

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

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

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

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

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

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

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

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

Other Matters Related to Distributions from Subsidiaries or Affiliates

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

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

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

Mission Energy Holding Company's Interest Coverage Ratio

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

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

 
   
  December 31, 2001
 
 
  December 31,
2002

  Actual
  Pro Forma
Adjustments(1)

  Pro
Forma

 
 
  (in millions)

 
Funds Flow From Operations:                          
  Edison Mission Energy   $ 691   $ 499         $ 499  
  Less: Operating cash flow from unrestricted subsidiaries     (16 )              
  Add: Outflows of funds from operations of projects sold     2     103           103  
  Mission Energy Holding     7     5   $ 5     10  
   
 
 
 
 
    $ 684   $ 607   $ 5   $ 612  
   
 
 
 
 

Interest Expense:

 

 

 

 

 

 

 

 

 

 

 

 

 
  Edison Mission Energy   $ 293   $ 305         $ 305  
  Edison Mission Energy—affiliate debt     2     3           3  
  Mission Energy Holding interest expense     159     82   $ 80     162  
  Less: Interest savings on projects sold         (4 )         (4 )
   
 
 
 
 
    $ 454   $ 386   $ 80   $ 466  
   
 
 
 
 

Interest Coverage Ratio

 

 

1.51

 

 

1.57

 

 

 

 

 

1.31

 
   
 
       
 

(1)
The pro forma adjustments assume the issuance of the 13.5% senior secured notes and the term loan occurred on January 1, 2001 with the proceeds invested during the six-month period at approximately 3%.

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

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

Ability of Edison Mission Energy to Pay Dividends

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

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

Edison Mission Energy's Interest Coverage Ratio

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

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

 
  December 31,
2002

  December 31,
2001

 
 
  (in millions)

 
Funds Flow from Operations:              
  Operating Cash Flow(1) from Consolidated Operating Projects(2):              
    Illinois Plants(3)   $ 294   $ 201  
    Homer City     51     175  
    Ferrybridge and Fiddler's Ferry     (2 )   (104 )
    First Hydro     47     46  
  Other consolidated operating projects     160     64  
  Price risk management and trading     16     28  
  Distributions from non-consolidated Big 4 projects(4)     137     129  
  Distributions from other non-consolidated operating projects     120     94  
  Interest income     8     9  
  Operating expenses     (139 )   (143 )
   
 
 
    Total funds flow from operations     692     499  
   
 
 
Interest Expense:              
  From obligations to unrelated third parties     178     189  
  From notes payable to Midwest Generation     115     116  
   
 
 
    Total interest expense     293     305  
   
 
 
Interest Coverage Ratio     2.36     1.64  
   
 
 

(1)
Operating cash flow is defined as revenues less operating expenses, foreign taxes paid and project debt service. Operating cash flow does not include capital expenditures or the difference between cash payments under EME's long-term leases and lease expenses recorded in EME's income statement. EME expects its cash payments under its long-term power plant leases to be higher than its lease expense through 2014.
(2)
Consolidated operating projects are entities of which EME owns more than a 50% interest and, thus, include the operating results and cash flows in its consolidated financial statements. Non-consolidated operating projects are entities of which EME owns 50% or less and which EME accounts for on the equity method.
(3)
Distribution to EME of funds flow from operations of the Illinois Plants is currently restricted. See "—Edison Mission Energy's Credit Ratings—Downgrade of Edison Mission Midwest Holdings."
(4)
The Big 4 projects are comprised of investments in the Kern River project, Midway-Sunset project, Sycamore project and Watson project.

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

Edison Mission Energy Recourse Debt to Recourse Capital Ratio

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

Financial Ratio

  Covenant
  Actual at
December 31, 2002

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

Discussion of Recourse Debt to Recourse Capital Ratio

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

 
  December 31,
2002

  December 31,
2001

 
 
  (in millions)

 
Recourse Debt(1)              
  Corporate Credit Facilities   $ 140   $ 204  
  Senior Notes     1,600     1,700  
  Guarantee of termination value of Powerton/Joliet operating leases     1,452     1,432  
  Coal and Capex Facility     182     251  
  Other     30     46  
   
 
 
  Total Recourse Debt to EME   $ 3,404   $ 3,633  
   
 
 
Adjusted Shareholder's Equity(2)   $ 2,066   $ 2,039  
   
 
 
Recourse Capital(3)   $ 5,470   $ 5,672  
   
 
 
Recourse Debt to Recourse Capital Ratio     62.2 %   64.1 %
   
 
 

(1)
Recourse debt means senior direct obligations of EME or obligations related to indebtedness or rental expenses of one of its subsidiaries for which EME has provided a guarantee.

(2)
Adjusted shareholder's equity is defined as the sum of total shareholder's equity and equity preferred securities, less changes in accumulated other comprehensive gain or loss after December 31, 1999.

(3)
Recourse capital is defined as the sum of adjusted shareholder's equity and recourse debt.

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

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

Edison Mission Energy's Subsidiary Financing Plans

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

Edison Mission Midwest Holdings

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

Amount
  Due Date

(in millions)

   
$ 911   December 2003
  808   December 2004

   
$ 1,719    

   

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

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Sunrise Project Financing

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

Intercompany Tax-Allocation Payments

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

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Contractual Obligations, Commitments and Contingencies

Contractual Obligations

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

 
  Payments Due by Period
   
Contractual Obligations

   
  2003
  2004
  2005
  2006
  2007
  Thereafter
  Total
 
  (in millions)

Long-term debt (excluding EME)   $   $ 100   $   $ 285   $   $ 777   $ 1,162
EME's long-term debt     1,090     1,109     239     89     307     3,128     5,962
Operating lease obligations (including EME)     341     319     362     444     481     5,057     7,004
EME's Chicago In-City obligation     22     2     2     2     1     7     36
EME's fuel supply contracts     605     487     453     366     226     1,060     3,197
EME's gas transportation agreements     8     16     16     16     15     166     237
   
 
 
 
 
 
 
Total Contractual Cash Obligations   $ 2,066   $ 2,033   $ 1,072   $ 1,202   $ 1,030   $ 10,195   $ 17,598
   
 
 
 
 
 
 

Sale-Leaseback Commitments

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

Chicago In-City Obligation

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

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

Fuel Supply Contracts

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

Gas Transportation Agreements

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

Other Commercial Commitments

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

 
  Amount of Commitments Per Period
   
Commercial Commitments

  Total
Amounts
Committed

  2003
  2004
  2005
  2006
  2007
  Thereafter
 
  (in millions)

Standby letters of credit   $ 135   $ 35   $   $   $   $ 1   $ 171
Firm commitment for asset purchase     2                         2
Firm commitments to contribute project equity     75                         75
Capital improvements at EME's project subsidiaries     38                         38
   
 
 
 
 
 
 
Total Commercial Commitments   $ 250   $ 35   $   $   $   $ 1   $ 286
   
 
 
 
 
 
 

Firm Commitment for Asset Purchase

Projects

  Local Currency
  U.S. Currency
 
   
  (in millions)

Italian Wind and Expansion(i)   2 million Euro   $ 2

(i)
The Italian Wind projects are a series of power projects that are in operation in Italy. EME's wholly owned subsidiary owns a 50% interest. The final purchase payments are expected to be

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Firm Commitments to Contribute Project Equity

Projects

  U.S. Currency
 
  (in millions)

CBK(i)   $ 37
Italian Wind Expansion(ii)   $ 2
Sunrise(iii)   $ 36

(i)
CBK is a 760 MW hydroelectric power project under construction in the Philippines. At December 31, 2002, 385 megawatts have been commissioned and are operational. A wholly owned subsidiary of EME owns a 50% interest. Equity was initially expected to be contributed through December 2003 commencing after full drawdown of the project's debt facility, which had been scheduled for late 2002. During the fourth quarter of 2002, EME prepaid $11 million of the equity contribution as a result of a failure by the contractor responsible for engineering, procurement and construction of the project to provide additional security for liquidated damages. EME has obtained a waiver from lenders for the contractor's default, but expects that equity will be fully contributed before the project is able to draw upon the remaining loan commitment. In addition, as a result of Moody's credit downgrade, EME posted a letter of credit to support the remaining portion of this obligation. For more information on Moody's rating actions, see "—Liquidity and Capital Resources—Edison Mission Energy's Credit Ratings." In addition to these equity infusions, the project sponsors funded a special draw in December 2001 (EME's share of which was $10 million), as a one-time adjustment to the construction payment schedule and loan drawdown schedule agreed among the project, the sponsors and the contractor.
(ii)
The Italian Wind expansion project is a 20 MW wind project that commenced commercial operation in the fourth quarter of 2002 and is located in Sardinia, Italy, adjacent to an existing Italian Wind project site. A wholly owned subsidiary of EME owns a 50% interest. Equity is to be contributed during the first quarter of 2003.
(iii)
The Sunrise project, located in Fellows, California, consists of two phases: Phase 1, a simple-cycle gas-fired facility (320 MW) that commenced commercial operation in June 2001; and Phase 2, conversion to a combined-cycle gas-fired facility (bringing the plant to a total capacity of 560 MW) currently scheduled to be completed in July 2003. A wholly owned subsidiary of EME owns a 50% interest. Equity will be contributed to fund the construction of Phase 2. The amount set forth in the above table assumes the partners will contribute equity for the entire construction cost.

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

Contingencies

Paiton Project

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

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

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

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

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

BHP Fuel Supply Agreement Arbitration

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

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

Brooklyn Navy Yard Project

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

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ISAB Project

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

Regulatory Developments Affecting Sunrise Power Company

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

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

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

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

Regulatory Developments Affecting Doga Project

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

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

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

Federal Income Taxes

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

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

Guarantees and Indemnities

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

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

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

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

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

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

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

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

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

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

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

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

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

Litigation

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

Contingent Obligations to Contribute Project Equity

Projects

  Local Currency
  U.S. Currency
 
   
  (in millions)

Paiton(i)     $ 5
ISAB(ii)   37 million Euro   $ 39

(i)
Contingent obligations to contribute additional project equity were based on events principally related to insufficient cash flow to cover interest on project debt and operating expenses, specified partner obligations or events of default. EME's obligation to contribute contingent equity did not exceed $141 million. As of December 31, 2002, $113 million had been contributed as project equity and $23 million deposited with the loan trustee to provide for further contributions if called for. The figure above represented EME's remaining unfunded commitments. As part of the restructuring of the project's debt completed in February 2003, the obligation to contribute project equity was terminated.
(ii)
ISAB is a 518 MW integrated gasification combined cycle power plant near Siracusa in Sicily, Italy. A wholly owned subsidiary of EME owns a 49% interest. Commercial operations commenced in April 2000. Contingent obligations to contribute additional equity to the project related specifically to an agreement to provide equity assurances to the project's lenders depending on the outcome of the contractor claim arbitration. The arbitration was settled, and consequently, there is no further obligation to contribute project equity.

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

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Off-Balance Sheet Transactions

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

Investments Accounted for Under the Equity Method

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

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

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

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

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

Sale-Leaseback Transactions

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

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

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

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

Power Station(s)

  Acquisition
Price

  Equity
Investor

  Equity Investment
in Owner/Lessor

  Amount of
Lessor Debt

  Maturity
Date of
Lessor Debt

 
  (in millions)

Collins   $ 860   PSEG   $ 117   $ 774   (i)
Powerton/Joliet     1,367   PSEG/Citicapital     238     333.5
813.5
  2009
2016
Homer City     1,591   GECC     798     300
530
  2019
2026

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

(i)
The owner/lessor under the Collins lease issued notes in the amount of the lessor debt to Midwest Funding LLC, a funding vehicle created and controlled by the owner/lessor. These notes mature in January 2014 and are referred to as the lessor notes. Midwest Funding LLC, in turn, entered into a commercial paper and loan facility with a group of banks pursuant to which it borrowed the funds required for its purchase of the lessor notes. These borrowings are currently scheduled to mature in December 2004 and are referred to as the lessor borrowings.

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

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

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

Parent Company Obligations to Midwest Generation

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

Years Ending December 31,

  Amount
 
  (in millions)

2003   $ 1
2004     1
2005     2
2006     3
2007     3
Thereafter     1,357
   
Total   $ 1,367
   

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

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MARKET RISK EXPOSURES

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

Commodity Price Risk

        EME's merchant power plants and energy trading activities expose EME to commodity price risks. Commodity price risks are actively monitored to ensure compliance with EME's risk management policies. Policies are in place which limit the amount of total net exposure EME may enter into at any time. Procedures exist which allow for monitoring of all commitments and positions with regular reviews by a risk management committee. EME performs a "value at risk" analysis in its daily business to measure, monitor and control its overall market risk exposure. The use of value at risk allows management to aggregate overall commodity risk, compare risk on a consistent basis and identify the drivers of the risk. Value at risk measures the possible loss over a given time interval, under normal market conditions, at a given confidence level. Given the inherent limitations of value at risk and relying on a single risk measurement tool, EME supplements this approach with the use of stress testing and worst-case scenario analysis, as well as stop loss limits and counterparty credit exposure limits. Despite this, there can be no assurance that all risks have been accurately identified, measured and/or mitigated.

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

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

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

Americas

Illinois Plants

        Electric power generated at the Illinois Plants is currently sold under three power purchase agreements between EME's wholly owned subsidiary, Midwest Generation, and Exelon Generation Company, under which Exelon Generation purchases capacity and has the right to purchase energy generated by the Illinois Plants. The agreements, which began on December 15, 1999 and have a term of up to five years, provide for capacity and energy payments. Exelon Generation is obligated to make a capacity payment for the plants under contract and an energy payment for the electricity produced by these plants and taken by Exelon Generation. The capacity payments provide the revenue for fixed charges, and the energy payments compensate the Illinois Plants for variable costs of production.

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

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

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

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

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

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


Into ComEd*

 
  2003
  2004
Date

  On-Peak
  Off-Peak
  24-Hr
  On-Peak
  Off-Peak
  24-Hr
January 31, 2002   $ 27.26   $ 18.34   $ 22.56   $ 28.72   $ 19.09   $ 23.65
February 28, 2002     28.96     18.50     23.48     31.30     19.25     24.99
March 31, 2002     32.50     19.85     25.56     34.31     21.35     27.20
April 30, 2002     32.55     19.05     25.65     33.55     20.05     26.65
May 31, 2002     30.85     17.31     23.71     32.30     19.18     25.38
June 30, 2002     29.54     16.88     22.50     30.98     19.38     24.53
July 31, 2002     28.64     16.90     22.37     30.09     18.90     24.11
August 30, 2002     28.75     17.00     22.47     30.20     19.25     24.34
September 30, 2002     29.16     15.92     22.09     30.61     18.17     23.96
October 31, 2002     29.01     15.62     21.85     30.46     17.62     23.59
November 27, 2002     29.11     15.32     21.74     31.38     17.32     23.86
December 31, 2002     29.98     15.58     22.29     32.25     18.14     24.71

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Into Cinergy**

 
  2003
  2004
Date

  On-Peak
  Off-Peak
  24-Hr
  On-Peak
  Off-Peak
  24-Hr
January 31, 2002   $ 28.38   $ 18.77   $ 23.32   $ 29.85   $ 19.52   $ 24.41
February 28, 2002     30.30     18.75     24.25     32.64     19.50     25.75
March 31, 2002     33.82     20.15     26.33     35.63     21.65     27.97
April 30, 2002     34.03     19.75     26.73     35.03     20.75     27.73
May 31, 2002     31.74     18.88     24.96     33.97     20.75     27.00
June 30, 2002     31.08     18.25     23.95     32.50     20.75     25.97
July 31, 2002     29.34     18.25     23.41     32.00     20.25     25.72
August 30, 2002     29.63     18.00     23.41     31.60     20.25     25.54
September 30, 2002     30.56     17.50     23.59     32.18     19.75     25.54
October 31, 2002     30.64     17.14     23.43     32.35     19.14     25.30
November 27, 2002     30.59     17.02     23.35     32.00     19.02     25.07
December 31, 2002     31.73     16.69     23.70     32.88     19.25     25.60

(1)
On-peak refers to the hours of the day between 7:00 a.m. and 11:00 p.m. Monday through Friday. All other hours of the week are referred to as off-peak.

*
Source: Prices were obtained by gathering publicly available broker quotes and adjusted for historical basis differences between ComEd and Cinergy.

**
Source: Prices were obtained by gathering publicly available broker quotes.

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

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

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

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

Homer City Facilities

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

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

 
  24-Hour PJM
Historical Energy Prices*

 
  2002
  2001
  2000
January   $ 20.52   $ 36.66   $ 23.15
February     20.62     29.53     23.84
March     24.27     35.05     21.97
April     25.68     34.58     23.79
May     21.98     28.64     28.41
June     24.98     26.61     23.06
July     30.01     30.21     23.53
August     30.40     43.99     29.01
September     29.00     22.44     25.12
October     27.64     21.95     29.20
November     25.18     19.58     30.68
December     27.33     19.66     44.63
   
 
 
Yearly Average   $ 25.63   $ 29.07   $ 27.20
   
 
 

*
Energy prices were calculated at the Homer City busbar (delivery point) using historical hourly prices provided on the PJM-ISO web-site.

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

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

 
  24-Hour PJM
Forward Energy Prices*

 
  2003
  2004
January 31, 2002   $ 25.48   $ 26.31
February 28, 2002     27.11     27.59
March 31, 2002     29.69     29.66
April 30, 2002     29.19     28.81
May 31, 2002     28.40     28.24
June 30, 2002     27.96     28.09
July 31, 2002     27.94     28.43
August 30, 2002     28.10     28.17
September 30, 2002     29.00     28.99
October 31, 2002     29.11     29.17
November 27, 2002     29.67     29.24
December 31, 2002     31.87     30.18

*
Energy prices were obtained by gathering publicly available broker quotes at PJM West (delivery point).

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

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

Europe

United Kingdom

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

        The new electricity trading arrangements provide for, among other things, the establishment of a range of voluntary short-term power exchanges and brokered markets operating from a year or more in advance to 1 hour prior to a trading period of one-half hour; a balancing mechanism to enable the system operator to balance generation and demand and resolve any transmission constraints; a mandatory settlement process for recovering imbalances between contracted and metered volumes with strong incentives for being in balance; and a Balancing and Settlement Code Panel to oversee governance of the balancing mechanism. The grid operator retains the right under the new market

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

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

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

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

Asia Pacific

Australia

        The Loy Yang B plant and the Valley Power Peaker project sell electrical energy through a centralized electricity pool, which provides for a system of generator bidding, central dispatch and a settlements system based on a clearing market for each half-hour of every day. The National Electricity Market Management Company, operator and administrator of the pool, determines a system marginal price each half-hour. To mitigate exposure to price volatility of the electricity traded into the pool, the Loy Yang B plant and the Valley Power Peaker project have entered into a number of financial hedges. The State Hedge agreement with the State Electricity Commission of Victoria is a long-term contractual arrangement based upon a fixed price commencing May 8, 1997 and terminating October 31, 2016. The State Government of Victoria, Australia guarantees the State Electricity

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

New Zealand

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

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

Credit Risks

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

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

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

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

S&P Credit Rating

  December 31, 2002
 
  (in millions)

A or higher   $ 45
A-     37
BBB+     24
BBB     27
BBB-     2
Below investment grade     2
   
Total   $ 137
   

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

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

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

Interest Rate Risk

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

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

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

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

Foreign Exchange Rate Risk

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

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

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

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

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

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

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

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Non-Trading Derivative Financial Instruments

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

 
  December 31,
2002

  December 31,
2001

 
Derivatives:          
  Interest rate:          
    Interest rate swap/cap agreements   (56 ) (37 )
    Interest rate options   (2 ) (1 )
  Commodity price:          
    Electricity   (100 ) (74 )
    Natural gas     (8 )
  Foreign currency forward exchange agreements     (1 )
  Cross currency interest rate swaps   (2 ) 28  

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

 
  Total
Fair Value

  Maturity
<1 year

  Maturity
1 to 3
years

  Maturity
4 to 5
years

  Maturity
>5 years

 
Prices actively quoted   $ (10 ) $ (10 ) $   $   $  
Prices based on models and other valuation methods     (90 )   3     (7 )   (13 )   (73 )
   
 
 
 
 
 
Total   $ (100 ) $ (7 ) $ (7 ) $ (13 ) $ (73 )
   
 
 
 
 
 

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

Energy Trading Derivative Financial Instruments

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

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

 
  December 31, 2002
  December 31, 2001
 
  Assets
  Liabilities
  Assets
  Liabilities
Electricity   $ 109   $ 15   $ 7   $ 5
Other         2     2     2
   
 
 
 
Total   $ 109   $ 17   $ 9   $ 7
   
 
 
 

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

 
  Fair Value
  Fair Value After 10%
Adverse Price Change

 
Electricity   $ 94   $ 93  
Other     (2 )   (2 )
   
 
 
Total   $ 92   $ 91  
   
 
 

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

Fair value of trading contracts at January 1, 2002   $ 2  
Purchase of power sales agreement     80  
Net gains from energy trading activities     42  
Amount realized from energy trading activities     (32 )
   
 
Fair value of trading contracts at December 31, 2002   $ 92  
   
 

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

 
  Total
Fair Value

  Maturity
<1 year

  Maturity
1 to 3
years

  Maturity
4 to 5
years

  Maturity
>5 years

Prices actively quoted   $ (1 ) $ (1 ) $   $   $
Prices based on models and other valuation methods     93     (3 )   4     7     85
   
 
 
 
 
Total   $ 92   $ (4 ) $ 4   $ 7   $ 85
   
 
 
 
 

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

 
  Years Ended December 31,
 
  2002
  2001
  2000
Operating Revenues                  
Unrealized gains (losses), net   $ 10   $ (12 ) $ 12
Realized gains, net     32     22     50
   
 
 
Total   $ 42   $ 10   $ 62
   
 
 

Risk Factors

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

EME is subject to extensive government regulation.

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

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

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

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

Environmental Matters and Regulations

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

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

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

State—Illinois

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

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

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

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

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State—Pennsylvania

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

Federal—United States of America

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

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

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

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

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

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

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

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

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

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

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

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

        On November 3, 1999, the United States Department of Justice filed suit against a number of electric utilities for alleged violations of the Clean Air Act's new source review, or NSR, requirements related to modifications of air emissions sources at electric generating stations located in the southern and midwestern regions of the United States. Several states have joined these lawsuits. In addition, the United States Environmental Protection Agency has also issued administrative notices of violation alleging similar violations at additional power plants owned by some of the same utilities named as defendants in the Department of Justice lawsuit, as well as other utilities, and also issued an administrative order to the Tennessee Valley Authority for similar violations at certain of its power plants. The Environmental Protection Agency has also issued requests for information pursuant to the Clean Air Act to numerous other electric utilities, including the prior owners of the Homer City facilities, seeking to determine whether these utilities also engaged in activities that may have been in violation of the Clean Air Act's NSR requirements.

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

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

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

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

International

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

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

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

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

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

• Australia   • Spain
• Indonesia   • Thailand
• Italy   • Turkey
• New Zealand   • United Kingdom
• Philippines   • United States

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

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

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

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

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

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

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

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

New Accounting Standards

Statement of Financial Accounting Standards No. 133

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

EITF Issue No. 02-03 Related to Energy Contracts

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

Statement of Financial Accounting Standards No. 142

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

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

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

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

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

 
  Americas
  Asia Pacific
  Europe
  Total
 
 
  (in millions)

 
Carrying amount at December 31, 2001   $ 25   $ 360   $ 247   $ 632  
Impairment losses     (23 )           (23 )
Intangibles reclassed to other assets         (77 )       (77 )
Translation adjustments and other         101     27     128  
   
 
 
 
 
Carrying amount at December 31, 2002   $ 2   $ 384   $ 274   $ 660  
   
 
 
 
 

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

 
  Years Ended December 31,
 
  2002
  2001
  2000
 
  (in millions)

Reported net income (loss)   $ (68 ) $ (1,170 ) $ 125
Add back: Goodwill amortization, net of tax         16     10
   
 
 
Adjusted net income (loss)   $ (68 ) $ (1,154 ) $ 135
   
 
 

Statement of Financial Accounting Standards No. 143

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

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Statement of Financial Accounting Standards No. 145

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

Statement of Financial Accounting Standards No. 146

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

Statement of Financial Accounting Standards Interpretation No. 45

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

Statement of Financial Accounting Standards Interpretation No. 46

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

115


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

Recent Development

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


ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

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

116




ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA

Financial Statements:    
  Report of Independent Accountants   118
  Consolidated Statements of Income (Loss) for the years ended December 31, 2002, 2001 and 2000   119
  Consolidated Balance Sheets at December 31, 2002 and 2001   120
  Consolidated Statements of Shareholder's Equity for the years ended December 31, 2002, 2001 and 2000   122
  Consolidated Statements of Comprehensive Income (Loss) for the years ended December 31, 2002, 2001 and 2000   123
  Consolidated Statements of Cash Flows for the years ended December 31, 2002, 2001 and 2000   124
  Notes to Consolidated Financial Statements   125


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

        None.

117




MISSION ENERGY HOLDING COMPANY AND SUBSIDIARIES
REPORT OF INDEPENDENT ACCOUNTANTS

To the Board of Directors of Mission Energy Holding Company:

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

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

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

PricewaterhouseCoopers LLP

Los Angeles, California
March 25, 2003

118



MISSION ENERGY HOLDING COMPANY AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF INCOME (LOSS)

(In thousands)

 
  Years Ended December 31,
 
 
  2002
  2001
  2000
 
Operating Revenues                    
  Electric revenues   $ 2,679,344   $ 2,411,544   $ 2,169,209  
  Net gains (losses) from price risk management and energy trading     27,498     36,241     (17,339 )
  Operation and maintenance services     42,881     40,652     37,478  
   
 
 
 
    Total operating revenues     2,749,723     2,488,437     2,189,348  
   
 
 
 
Operating Expenses                    
  Fuel     943,639     814,531     767,635  
  Plant operations and transmission costs     765,138     706,697     522,742  
  Plant operating leases     205,904     133,317     87,740  
  Operation and maintenance services     28,958     26,465     28,135  
  Depreciation and amortization     247,486     263,646     272,233  
  Long-term incentive compensation     1,702     5,959     (55,952 )
  Settlement of postretirement employee benefit liability     (70,654 )        
  Asset impairment and other charges     130,863     59,055      
  Administrative and general     167,270     174,227     160,879  
   
 
 
 
    Total operating expenses     2,420,306     2,183,897     1,783,412  
   
 
 
 
  Operating income     329,417     304,540     405,936  
   
 
 
 
Other Income (Expense)                    
  Equity in income from unconsolidated affiliates     282,932     374,096     266,876  
  Interest and other income     25,491     39,438     29,793  
  Gain on sale of assets     4,934     41,313     25,756  
  Gain on early extinguishment of debt         10,094      
  Interest expense     (611,521 )   (624,340 )   (551,575 )
  Dividends on preferred securities     (21,176 )   (22,271 )   (32,075 )
   
 
 
 
    Total other income (expense)     (319,340 )   (181,670 )   (261,225 )
   
 
 
 
  Income from continuing operations before income taxes and minority interest     10,077     122,870     144,711  
  Provision (benefit) for income taxes     (20,156 )   66,258     75,985  
  Minority interest     (27,159 )   (22,157 )   (3,183 )
   
 
 
 
Income From Continuing Operations     3,074     34,455     65,543  
Income (loss) from operations of discontinued foreign subsidiaries (including loss on disposal of $1.1 billion in 2001), net of tax (Note 7)     (57,329 )   (1,219,253 )   37,904  
   
 
 
 
Income (Loss) Before Accounting Change     (54,255 )   (1,184,798 )   103,447  
Cumulative effect of change in accounting, net of tax (Note 2)     (13,986 )   15,146     21,805  
   
 
 
 
Net Income (Loss)   $ (68,241 ) $ (1,169,652 ) $ 125,252  
   
 
 
 

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

119



MISSION ENERGY HOLDING COMPANY AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEETS

(In thousands)

 
  December 31,
 
  2002
  2001
Assets            
Current Assets            
  Cash and cash equivalents   $ 734,374   $ 355,829
  Accounts receivable—trade, net of allowance of $13,113 in 2002 and $14,603 in 2001     296,193     306,125
  Accounts receivable—affiliates     41,478     263,516
  Assets under price risk management and energy trading     33,742     64,729
  Inventory     176,437     167,406
  Prepaid expenses and other     169,312     95,278
   
 
    Total current assets     1,451,536     1,252,883
   
 
Investments in Unconsolidated Affiliates     1,645,253     1,829,940
   
 
Property, Plant and Equipment     7,649,791     6,705,779
  Less accumulated depreciation and amortization     888,060     603,267
   
 
    Net property, plant and equipment     6,761,731     6,102,512
   
 
Other Assets            
  Long-term receivables     6,243     264,784
  Goodwill     659,837     631,735
  Deferred financing costs     90,187     127,627
  Long-term assets under price risk management and energy trading     112,571     2,998
  Restricted cash and other     628,870     576,010
   
 
    Total other assets     1,497,708     1,603,154
   
 
Assets of Discontinued Operations     10,273     319,271
   
 
Total Assets   $ 11,366,501   $ 11,107,760
   
 

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

120



MISSION ENERGY HOLDING COMPANY AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEETS

(In thousands)

 
  December 31,
 
 
  2002
  2001
 
Liabilities and Shareholder's Equity              
Current Liabilities              
  Accounts payable—affiliates   $ 12,985   $ 11,968  
  Accounts payable and accrued liabilities     451,032     428,925  
  Liabilities under price risk management and energy trading     45,494     23,681  
  Interest payable     152,231     150,964  
  Short-term obligations     77,551     168,241  
  Current portion of long-term incentive compensation     5,508     6,170  
  Current maturities of long-term obligations     1,089,918     172,369  
   
 
 
    Total current liabilities     1,834,719     962,318  
   
 
 
Long-Term Obligations Net of Current Maturities     6,033,775     6,844,733  
   
 
 
Long-Term Deferred Liabilities              
  Deferred taxes and tax credits     1,180,900     897,331  
  Deferred revenue     454,438     427,485  
  Long-term incentive compensation     29,486     39,331  
  Long-term liabilities under price risk management and energy trading     169,219     170,506  
  Other     219,703     266,742  
   
 
 
    Total long-term deferred liabilities     2,053,746     1,801,395  
   
 
 
Liabilities of Discontinued Operations     3,024     184,418  
   
 
 
Total Liabilities     9,925,264     9,792,864  
   
 
 
Minority Interest     423,844     344,092  
   
 
 
Preferred Securities of Subsidiaries              
  Company-obligated mandatorily redeemable security of partnership holding solely parent debentures     150,000     150,000  
  Subject to mandatory redemption     131,225     103,950  
   
 
 
  Total preferred securities of subsidiaries     281,225     253,950  
   
 
 
Commitments and Contingencies (Notes 10, 11, 16 and 17)              
Shareholder's Equity              
  Common stock, $.01 par value; 1,000 shares authorized; 1,000 shares issued and outstanding          
  Additional paid-in capital     2,218,285     2,216,125  
  Retained deficit     (1,265,171 )   (1,196,644 )
  Accumulated other comprehensive loss     (216,946 )   (302,627 )
   
 
 
Total Shareholder's Equity     736,168     716,854  
   
 
 
Total Liabilities and Shareholder's Equity   $ 11,366,501   $ 11,107,760  
   
 
 

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

121



MISSION ENERGY HOLDING COMPANY AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF SHAREHOLDER'S EQUITY

(In thousands)

 
  Additional
Paid-in
Capital

  Retained
Earnings

  Accumulated
Other
Comprehensive
Income

  Shareholder's
Equity

 
Balance at December 31, 1999   $ 2,693,536   $ 364,434   $ 10,507   $ 3,068,477  
  Net income         125,252         125,252  
  Other comprehensive loss             (157,255 )   (157,255 )
  Cash dividends to parent         (88,000 )       (88,000 )
  Stock option price appreciation on options exercised         (290 )       (290 )
   
 
 
 
 
Balance at December 31, 2000     2,693,536     401,396     (146,748 )   2,948,184  
  Net loss         (1,169,652 )       (1,169,652 )
  Other comprehensive loss             (155,879 )   (155,879 )
  Cash dividends to parent     (479,331 )   (428,388 )       (907,719 )
  Other stock transactions, net     1,920             1,920  
   
 
 
 
 
Balance at December 31, 2001     2,216,125     (1,196,644 )   (302,627 )   716,854  
  Net loss         (68,241 )       (68,241 )
  Other comprehensive income             85,681     85,681  
  Stock option price appreciation on options exercised         (286 )       (286 )
  Capital contributions from parent     600             600  
  Other stock transactions, net     1,560             1,560  
   
 
 
 
 
Balance at December 31, 2002   $ 2,218,285   $ (1,265,171 ) $ (216,946 ) $ 736,168  
   
 
 
 
 

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

122



MISSION ENERGY HOLDING COMPANY AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (LOSS)

(In thousands)

 
  Years Ended December 31,
 
 
  2002
  2001
  2000
 
Net Income (Loss)   $ (68,241 ) $ (1,169,652 ) $ 125,252  
Other comprehensive income (expense), net of tax:                    
  Foreign currency translation adjustments:                    
    Foreign currency translation adjustments, net of income tax expense (benefit) of $3,775, $(1,349) and $(3,934) for 2002, 2001 and 2000, respectively     124,762     (50,710 )   (157,255 )
    Reclassification adjustments for sale of investment in a foreign subsidiary         64,065      
  Minimum pension liability adjustment     (10,603 )        
  Unrealized gains (losses) on derivatives qualified as cash flow hedges:                    
    Cumulative effect of change in accounting for derivatives, net of income tax expense (benefit) of $5,562 and $(124,400) for 2002 and 2001, respectively     6,357     (245,745 )    
    Other unrealized holding gains (losses) arising during period, net of income tax expense of $5,752 and $62,500 for 2002 and 2001, respectively     (34,501 )   60,082      
    Reclassification adjustments included in net income (loss), net of income tax benefit of $3,722 and $7,800 for 2002 and 2001, respectively     (334 )   16,429      
   
 
 
 
Other comprehensive income (expense)     85,681     (155,879 )   (157,255 )
   
 
 
 
Comprehensive Income (Loss)   $ 17,440   $ (1,325,531 ) $ (32,003 )
   
 
 
 

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

123



MISSION ENERGY HOLDING COMPANY AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF CASH FLOWS

(In thousands)

 
  Years Ended December 31,
 
 
  2002
  2001
  2000
 
Cash Flows From Operating Activities                    
  Income (loss) from continuing operations, after accounting change, net   $ (10,912 ) $ 49,601   $ 87,348  
  Adjustments to reconcile income (loss) to net cash provided by (used in) operating activities:                    
    Equity in income from unconsolidated affiliates     (282,932 )   (374,096 )   (266,876 )
    Distributions from unconsolidated affiliates     337,553     235,915     226,221  
    Depreciation and amortization     247,486     263,646     272,233  
    Amortization of discount on obligations     4,054     7,072     66,376  
    Deferred taxes and tax credits     203,486     88,347     256,003  
    Gain on sale of assets     (4,934 )   (41,313 )   (25,756 )
    Asset impairment and other charges     130,863     59,055      
    Cumulative effect of change in accounting, net of tax     13,986     (15,146 )   (21,805 )
    Settlement of postretirement employee benefit liability     (70,654 )        
  Changes in operating assets and liabilities:                    
    Decrease (increase) in accounts receivable     250,296     109,440     (365,751 )
    Decrease (increase) in inventory     (5,936 )   (44,582 )   55,791  
    Decrease in prepaid expenses and other     2,355     19,177     10,570  
    Increase (decrease) in accounts payable and accrued liabilities     3,119     (410,283 )   397,222  
    Increase in interest payable     144,643     80,617     5,244  
    Increase (decrease) in long-term incentive compensation     524     (2,077 )   (108,747 )
    Decrease (increase) in net assets under risk management     (20,850 )   14,854     36,614  
  Other operating, net     (75,608 )   (43,670 )   30,851  
   
 
 
 
      866,539     (3,443 )   655,538  
  Operating cash flow from discontinued operations     53,876     (113,101 )   9,670  
   
 
 
 
    Net cash provided by (used in) operating activities     920,415     (116,544 )   665,208  
   
 
 
 
Cash Flows From Financing Activities                    
  Borrowing on long-term debt and lease swap agreements     440,149     3,477,772     2,767,747  
  Payments on long-term debt agreements     (576,746 )   (1,709,918 )   (3,217,412 )
  Short-term financing and lease swap agreements, net     (123,721 )   (788,641 )   (331,648 )
  Contributions from parent     600          
  Cash dividends     (36,806 )   (907,719 )   (88,000 )
  Funds provided to discontinued operations         (108,646 )    
  Issuance of preferred securities         103,467      
  Redemption of preferred securities         (164,560 )   (124,650 )
  Financing costs         (83,607 )    
   
 
 
 
      (296,524 )   (181,852 )   (993,963 )
  Financing cash flow from discontinued operations     (18,504 )   (1,085,498 )   210,917  
   
 
 
 
    Net cash used in financing activities     (315,028 )   (1,267,350 )   (783,046 )
   
 
 
 
Cash Flows From Investing Activities                    
  Investments in and loans to energy projects     (40,324 )   (294,219 )   (173,163 )
  Purchase of common stock of acquired companies     (15,987 )   (97,225 )   (109,077 )
  Purchase of generating stations             (16,895 )
  Purchase of power sales agreement     (80,084 )        
  Capital expenditures     (554,450 )   (241,242 )   (330,509 )
  Proceeds from sale-leaseback transactions         782,000     1,667,000  
  Proceeds from return of capital and loan repayments     87,855     44,900     13,735  
  Proceeds from sale of interest in projects     48,843     185,545     35,546  
  Increase in restricted cash     (4,625 )   (461,266 )   (59,213 )
  Investments in other assets     253,352     18,448     (264,723 )
  Other, net         13,013     (2,813 )
   
 
 
 
      (305,420 )   (50,046 )   759,888  
  Investing cash flow from discontinued operations     1,480     926,350     (41,771 )
   
 
 
 
    Net cash provided by (used in) investing activities     (303,940 )   876,304     718,117  
   
 
 
 
Effect of exchange rate changes on cash     24,739     (20,084 )   (36,109 )
Effect on cash from de-consolidation of subsidiary     (26,927 )        
   
 
 
 
Net increase (decrease) in cash and cash equivalents     299,259     (527,674 )   564,170  
Cash and cash equivalents at beginning of period     435,191     962,865     398,695  
   
 
 
 
Cash and cash equivalents at end of period     734,450     435,191     962,865  
Cash and cash equivalents classified as part of discontinued operations     (76 )   (79,362 )   (371,826 )
   
 
 
 
Cash and cash equivalents of continuing operations   $ 734,374   $ 355,829   $ 591,039  
   
 
 
 

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

124



MISSION ENERGY HOLDING COMPANY AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Dollars in millions)

Note 1. General

Organization

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

Note 2. Summary of Significant Accounting Policies

Consolidations

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

Management's Use of Estimates

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

Cash Equivalents

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

125



Investments

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

Property, Plant and Equipment

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

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

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

Furniture and office equipment   3-11 years
Building, plant and equipment   3-100 years
Emission allowances   25-40 years
Civil works   40-100 years
Leasehold 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

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

Capitalized Interest

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

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

 
  Years Ended December 31,
 
 
  2002
  2001
  2000
 
Interest incurred   $ 616   $ 638   $ 566  
Interest capitalized     (4 )   (14 )   (14 )
   
 
 
 
    $ 612   $ 624   $ 552  
   
 
 
 

Income Taxes

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

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

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Maintenance Accruals

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

Project Development Costs

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

Deferred Financing Costs

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

Derivative Instruments and Hedging Activities

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

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

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

Discussion of Initial Adoption of SFAS No. 133

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

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

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

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

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

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

Revenue Recognition

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

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Energy Trading

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

Translation of Foreign Financial Statements

        Assets and liabilities of most foreign operations are translated at end of period rates of exchange, and the income statements are translated at the average rates of exchange for the year. Gains or losses from translation of foreign currency financial statements are included in comprehensive income in shareholder's equity. Gains or losses resulting from foreign currency transactions are normally included in other income in the consolidated statements of income. Foreign currency transaction gains/(losses) amounted to $(8) million, $7 million and $13 million for 2002, 2001 and 2000, respectively.

Stock-based Compensation

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

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

 
  Years Ended December 31,
 
 
  2002
  2001
  2000
 
Net income (loss), as reported   $ (68 ) $ (1,170 ) $ 125  
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 income (loss)   $ (69 ) $ (1,171 ) $ 124  
   
 
 
 

New Accounting Standards

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

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

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

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

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

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

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

Note 3. Inventory

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

 
  2002
  2001
Coal and fuel oil   $ 111   $ 110
Spare parts, materials and supplies     65     57
   
 
Total   $ 176   $ 167
   
 

Note 4. Goodwill and Intangible Assets

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

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

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

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

 
  Americas
  Asia Pacific
  Europe
  Total
 
Carrying amount at December 31, 2001   $ 25   $ 360   $ 247   $ 632  
Impairment losses     (23 )           (23 )
Intangibles reclassed to other assets         (77 )       (77 )
Translation adjustments and other         101     27     128  
   
 
 
 
 
Carrying amount at December 31, 2002   $ 2   $ 384   $ 274   $ 660  
   
 
 
 
 

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

 
  Years Ended December 31,
 
  2002
  2001
  2000
Reported net income (loss)   $ (68 ) $ (1,170 ) $ 125
Add back: Goodwill amortization, net of tax         16     10
   
 
 
Adjusted net income (loss)   $ (68 ) $ (1,154 ) $ 135
   
 
 

Note 5. Accumulated Other Comprehensive Income (Loss)

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

 
  Currency
Translation
Adjustments

  Unrealized
Gains (Losses)
on Cash Flow
Hedges

  Minimum Pension
Liability
Adjustment(1)

  Accumulated Other
Comprehensive Income (Loss)

 
Balance at December 31, 2001   $ (133 ) $ (169 ) $   $ (302 )
Current period change     125     (29 )   (11 )   85  
   
 
 
 
 
Balance at December 31, 2002   $ (8 ) $ (198 ) $ (11 ) $ (217 )
   
 
 
 
 

(1)
The minimum pension liability adjustment is discussed under Note 14—Employee Benefit Plans—Pension Plans.

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

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

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

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

Note 6. Acquisitions and Dispositions

Acquisitions

Acquisition of Interest in CBK Power Co. Ltd.

        In February 2001, EME completed the acquisition of a 50% interest in CBK Power Co. Ltd. in exchange for $20 million. CBK Power has entered into a 25-year build-rehabilitate-transfer-and-operate agreement with National Power Corporation related to the 760 MW Caliraya-Botocan-Kalayaan (CBK) hydroelectric project located in the Philippines. Financing for this $460 million project comprises equity commitments of $117 million, of which EME's 50% share is $58.5 million, and debt financing which is in place for the remainder of the cost for this project. As of December 31, 2002, EME has made equity contributions of $21 million. For a more detailed discussion of the commitment to contribute project equity, refer to "—Commitments and Contingencies—Firm Commitments to Contribute Project Equity."

Acquisition of Sunrise Project

        On November 17, 2000, EME completed a transaction with Texaco Power & Gasification Holdings Inc. to purchase a proposed 560 MW gas-fired combined cycle project to be located in Kern County, California, referred to as the Sunrise project. The acquisition included all rights, title and interest held by Texaco Power & Gasification in the Sunrise project, except that Texaco Power & Gasification had an option to repurchase at cost a 50% interest in the project prior to its commercial operation, which commenced on June 27, 2001. On June 25, 2001, Texaco Power & Gasification exercised its option and repurchased a 50% interest for $84 million. As part of EME's acquisition of the Sunrise project, EME also: (i) acquired from Texaco Power & Gasification two gas turbines for the project and (ii) granted Texaco Power & Gasification an option to acquire a 50% interest in 1,000 MW of future power plant projects EME designates. The Sunrise project consists of two phases, with Phase 1, a single-cycle gas-fired facility (320 MW), completed on June 27, 2001, and Phase 2,

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

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

Acquisition of Trading Operations of Citizens Power LLC

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

Acquisition of Interest in Italian Wind Project

        On March 15, 2000, EME completed a transaction with UPC International Partnership CV II to acquire Edison Mission Wind Power Italy B.V., formerly known as Italian Vento Power Corporation Energy 5 B.V., which owns a 50% interest in a series of power projects that are in operation or under development in Italy. All the projects use wind to generate electricity from turbines which is sold under fixed-price, long-term tariffs. At December 31, 2002, 303 MW had been commissioned and are operational. The total purchase price was 47 million Euro dollars, with equity contribution obligations of up to 17 million Euro dollars. As of December 31, 2002, EME's payments in respect of these projects included $53 million toward the purchase price and $16 million, which funded EME's entire equity contribution obligation.

Acquisition of Interest in Contact Energy

        On May 14, 1999, EME completed a transaction with the New Zealand government to acquire 40% of the shares of Contact Energy Limited. The remaining 60% of Contact Energy's shares were sold in a New Zealand and overseas public offering, resulting in widespread ownership among the citizens of New Zealand and offshore investors. These shares are publicly traded on stock exchanges in New Zealand and Australia. Contact Energy owns and operates hydroelectric, geothermal and natural gas fired power generating plants primarily in New Zealand with a total current generating capacity of 2,302 MW.

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

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

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

Accounting Treatment of Acquisitions

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

Pro Forma Data

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

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

Date

  Acquisition
  Percentage
Acquired

  Purchase Price
Oil and Gas              
December 19, 2001   Four Star Oil & Gas Company   1.4 % $ 7
July 28, 2000   Four Star Oil & Gas Company   1.7 %   1
May 15, 2000   Four Star Oil & Gas Company   1.7 %   2

Dispositions

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

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

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

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

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

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

Note 7. Discontinued Operations

Lakeland Project

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

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

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

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

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

Ferrybridge and Fiddler's Ferry Plants

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

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

        Summarized results of discontinued operations are as follows:

 
  Years Ended December 31,
 
 
  2002
  2001
  2000
 
Total operating revenues   $ 74   $ 600   $ 785  
Income (loss) before income taxes     (75 )   (2,000 )   39  
Income (loss) before accounting change     (57 )   (1,225 )   42  
Cumulative effect of change in accounting, net of income expense (benefit) of $2 million and $(2) million for 2001 and 2000, respectively         6     (4 )
Income (loss) from operations of discontinued foreign subsidiary     (57 )   (1,219 )   38  

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

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

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

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

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

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

 
  December 31,
 
  2002
  2001
Cash and cash equivalents   $   $ 79
Accounts receivable—trade, net of allowance of $2 million in 2002 and $1 million in 2001     1     95
Other current assets     3     2
   
 
  Total current assets     4     176
   
 
Net property, plant and equipment         135
Other assets     6     8
   
 
  Total long-term assets     6     143
   
 
Assets of discontinued operations   $ 10   $ 319
   
 
Accounts payable and accrued liabilities   $ 3   $ 59
Interest payable         6
Current maturities of long-term obligations         18
   
 
  Total current liabilities     3     83
   
 
Long-term obligations net of current maturities         62
Deferred taxes and tax credits         39
   
 
Liabilities of discontinued operations   $ 3   $ 184
   
 

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

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Note 8. Investments in Unconsolidated Affiliates

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

 
  2002
  2001
Domestic Investments            
  Equity investment   $ 767   $ 994
  Loans receivable     183     173
   
 
    Subtotal     950     1,167
   
 
International Investments            
  Equity investment     695     663
   
 
    Total   $ 1,645   $ 1,830
   
 

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

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

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

 
  Years Ended December 31,
 
  2002
  2001
  2000
Revenues   $ 51   $ 24   $
Expenses     14     3    
   
 
 
  Net income   $ 37   $ 21   $
   
 
 

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  December 31,
 
  2002
  2001
Current assets   $ 18   $ 7
Noncurrent assets     451     311
   
 
  Total assets   $ 469   $ 318
   
 
Current liabilities   $ 29   $ 16
Noncurrent liabilities     324     242
Equity     116     60
   
 
  Total liabilities and equity   $ 469   $ 318
   
 

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

 
  Years Ended December 31,
 
  2002
  2001
  2000
Revenues   $ 2,949   $ 3,123   $ 2,854
Expenses     2,374     2,490     2,245
   
 
 
  Net income   $ 575   $ 633   $ 609
   
 
 
 
  December 31,
 
  2002
  2001
Current assets   $ 1,847   $ 2,139
Noncurrent assets     6,861     7,116
   
 
  Total assets   $ 8,708   $ 9,255
   
 
Current liabilities   $ 2,820   $ 1,884
Noncurrent liabilities     4,280     5,364
Equity     1,608     2,007
   
 
  Total liabilities and equity   $ 8,708   $ 9,255
   
 

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

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

Unconsolidated Affiliates

  Location
  Investment
  Ownership
Interest

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

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

Disclosure Requirements under FIN 46

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

Note 9. Property, Plant and Equipment

        Property, plant and equipment consist of the following:

 
  December 31,
 
  2002
  2001
Buildings, plant and equipment   $ 3,451   $ 3,741
Emission allowances     1,305     1,305
Civil works     2,776     1,342
Construction in progress     77     130
Capitalized leased equipment     41     188
   
 
      7,650     6,706
Less accumulated depreciation and amortization     888     603
   
 
  Net property, plant and equipment   $ 6,762   $ 6,103
   
 

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

Note 10. Financial Instruments

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

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

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

Short-Term Obligations

 
  December 31,
 
 
  2002
  2001
 
Citibank, N.A. Credit Agreement   $   $ 80  
Other short-term obligations     78     88  
   
 
 
  Total   $ 78   $ 168  
   
 
 
Weighted-average interest rate     6.13 %   7.3 %

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

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

        EME's recourse debt to recourse capital ratio:

Financial Ratio

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

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

Long-Term Obligations

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

 
  December 31,
 
 
  2002
  2001
 
Corporate debt (with recourse to MEHC)              
Mission Energy Holding Company (parent only)              
  Senior Notes, net due 2008 (13.5%)   $ 785   $ 783  
    Credit Agreement due 2004 (LIBOR+7.50%) (9.29% at 12/31/02)     98     97  
    Credit Agreement due 2006 (LIBOR+7.50%) (9.29% at 12/31/02)     279     278  

Corporate debt (with recourse to EME)

 

 

 

 

 

 

 
Edison Mission Energy (parent only)              
  Senior Notes, net              
    due 2002 (8.125%)         100  
    due 2008 (10.0%)     400     400  
    due 2009 (7.73%)     597     597  
    due 2011 (9.875%)     600     600  

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

 

 

181

 

 

252

 

Long-Term Obligations—Affiliate

 

 

78

 

 

78

 

Non-recourse (unless otherwise noted)

 

 

 

 

 

 

 
Edison Mission Energy Funding Corp.              
  Series A Notes, net due 1997-2003 (6.77%)     47     91  
  Series B Bonds, net due 2004-2008 (7.33%)     189     189  

EME CP Holdings Co.

 

 

 

 

 

 

 
  Note Purchase Agreement due 2015 (7.31%)     84      

Edison Mission Midwest Holdings Co.

 

 

 

 

 

 

 
  Tranche A due 2003 (LIBOR+2.25%) (3.66% at 12/31/02)     911     911  
  Tranche B due 2004 (LIBOR+2.00%) (3.41% at 12/31/02)     808     808  

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Contact Energy project

 

 

 

 

 

 

 
  Medium Term Note—US$75 MM due 2013 (6.94% at 12/31/02)     75     79  
  Medium Term Note—US$25 MM due 2018 (7.13% at 12/31/02)     25     26  
  Floating Rate Note—US$50 MM due 2007 (2.21% at 12/31/02)     50     50  
  Floating Rate Note—A$120 MM due 2007 (5.78% at 12/31/02)     67     62  
  Medium Term Note—NZ$70 MM due 2003 (7.25% at 12/31/02)     37     29  
  Term Loan Facility—NZ$50 MM due 2004 (6.43% at 12/31/02)     26     21  
  CSFB Revolving Credit Facility due 2005 (BKBM+1.75%) (7.71% at 12/31/02)     150     118  

Doga project

 

 

 

 

 

 

 
  Finance Agreement between Doga and OPIC due 2010 (U.S. Treasury Note+3.75%) (11.2% at 12/31/02)     70     78  
  NCM Credit Agreement due 2010 (U.S. LIBOR+1.25%) (3.28% at 12/31/02)     26     29  

First Hydro plants

 

 

 

 

 

 

 
  First Hydro Finance plc £400 MM Guaranteed Secured Bonds due 2021 (9%)     644     582  
  £18 MM Credit Agreement due 2003 (Sterling LIBOR+0.55%+0.0103%) (4.74% at 12/31/02)     29     26  

Iberian Hy-Power plants

 

 

 

 

 

 

 
  Euro dollar Project Finance Credit Facility due 2012 (EURIBOR+0.75%) (3.64% at 12/31/02)     43     49  
  Euro dollar Subordinated Loan due 2003 (9.408%)     22     7  
  Euro dollar Compagnie Générale Des Eaux due 2003 (non-interest bearing)—recourse     30     23  
  Euro dollar Banco Vitalicio due 2006 (6.17% at 12/31/02)     2      

Kwinana plant

 

 

 

 

 

 

 
  Australian dollar Syndicated Project Facility Agreement due 2012 (BBR+1.3%) (6.37% at 12/31/02)     47     44  

Loy Yang B plant

 

 

 

 

 

 

 
  Australian dollar Amortising Term Facility due 2017 (BBR+0.6% to 1.1%) (5.532% at 12/31/02)     382     354  
  Australian dollar Interest Only Term Facility due 2012 (BBR+0.6% to 0.85%) (5.532% at 12/31/02)     276     251  
  Australian dollar Working Capital Facility due 2017 (BBR+0.6% to 1.1%) (5.532% at 12/31/02)     6     5  

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Valley Power plant

 

 

 

 

 

 

 
  Australian dollar Amortising Facility due 2011 (BBR+1.55%) (6.438% at 12/31/02)     39      
  Australian dollar Bullet Facility due 2007 (BBR+1.55%) (6.438% at 12/31/02)     21      
   
 
 
Subtotal   $ 7,124   $ 7,017  
Current maturities of long-term obligations     (1,090 )   (172 )
   
 
 
Total   $ 6,034   $ 6,845  
   
 
 

Bond Financing of First Hydro

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

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

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

Long-term Obligations—Affiliates

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

Financing of the Ferrybridge and Fiddler's Ferry Plants

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

Annual Maturities on Long-Term Debt

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

Restricted Cash

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

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

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

Fair Values of Non-Derivative Financial Instruments

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

 
  December 31,
 
  2002
  2001
Instruments            
Non-derivatives:            
  Long-term receivables   $ 6   $ 265
  Long-term obligations     4,480     6,991
  Preferred securities subject to mandatory redemption     246     258

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

Note 11. Risk Management and Derivative Financial Instruments

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

Commodity Price Risk Management

        EME's merchant power plants and energy trading activities expose EME to commodity price risks. Commodity price risks are actively monitored to ensure compliance with EME's risk management policies. Policies are in place which limit the amount of total net exposure EME may enter into at any time. Procedures exist which allow for monitoring of all commitments and positions with regular reviews by a risk management committee. EME performs a "value at risk" analysis in its daily business to measure, monitor and control its overall market risk exposure. The use of value at risk allows management to aggregate overall commodity risk, compare risk on a consistent basis and identify the drivers of the risk. Value at risk measures the possible loss over a given time interval, under normal market conditions, at a given confidence level. Given the inherent limitations of value at risk and relying on a single risk measurement tool, EME supplements this approach with the use of stress testing and worst-case scenario analysis, as well as stop loss limits and counterparty credit exposure limits. Despite this, there can be no assurance that all risks have been accurately identified, measured and/or mitigated.

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Interest Rate Risk Management

        MEHC has mitigated the risk of interest rate fluctuations associated with the $385 million term loan due 2006 by arranging for variable rate financing with interest rate swaps. Swaps covering interest accrued from January 2, 2002 to January 2, 2003 expired on January 2, 2003. Subsequently, MEHC entered into swaps that cover interest accrued from January 2, 2003 to July 2, 2004. Under MEHC's variable to fixed swap agreements, MEHC will pay counterparties interest at a weighted average fixed rate of 3.04% and 2.76% at December 31, 2002 and 2001, respectively. Counterparties will pay MEHC interest at a weighted average variable rate based on LIBOR of 1.63% and 1.98% at December 31, 2002 and 2001, respectively.

        Interest rate changes affect the cost of capital needed to operate EME's projects and the lease costs under the Collins Station lease. EME has mitigated the risk of interest rate fluctuations by arranging for fixed rate financing or variable rate financing with interest rate swaps, interest rate options or other hedging mechanisms for a number of EME's project financings. EME has entered into several interest rate swap agreements under which the maturity date of the swaps occurs prior to the final maturity of the underlying debt.

        Under EME's fixed to variable swap agreements, the fixed interest rate payments are at a weighted average rate of 6.91% and 5.97% at December 31, 2002 and 2001, respectively. Variable rate payments under EME's corporate agreements were based on six-month LIBOR capped at 9% at December 31, 2001. Variable rate payments pertaining to EME's foreign subsidiary agreements are based on an equivalent interest rate benchmark to LIBOR. The weighted average rate applicable to these agreements was 6.18% and 2.80% at December 31, 2002 and 2001, respectively. Under the variable to fixed swap agreements, EME will pay counterparties interest at a weighted average fixed rate of 6.96% and 7.12% at December 31, 2002 and 2001, respectively. Counterparties will pay EME interest at a weighted average variable rate of 5.10% and 4.76% at December 31, 2002 and 2001, respectively. The weighted average variable interest rates are based on LIBOR or equivalent interest rate benchmarks for foreign denominated interest rate swap agreements. Under EME's interest rate options, the weighted average strike interest rate was 6.90% and 6.76% at December 31, 2002 and 2001, respectively.

Credit Risk

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

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EME. Further, EME would be exposed to the risk of non-payment of accounts receivable accrued for products delivered prior to the time such counterparty defaulted.

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

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

        EME's contracted power plants and the plants owned by unconsolidated affiliates in which EME owns an interest, sell power under long-term power purchase agreements. Generally, each plant sells its output to one counterparty. Accordingly, a default by a counterparty under a long-term power purchase agreement, including a default as a result of a bankruptcy, would likely have a material adverse affect on the operations of such power plant. During 2002, the counterparty to the Lakeland project power purchase agreement filed a notice of disclaimer of its power purchase agreement with the project ultimately resulting in an impairment of $77 million, after tax. See Note 7—Discontinued Operations. The Big 4 projects sell power to Southern California Edison, which is currently non-investment grade. Southern California Edison was adversely affected by the California energy crisis and during that time defaulted on its long-term power purchase agreements with each of the Big 4 projects. It has since repaid the past due amounts, with interest. If Southern California Edison again defaults on its long-term power purchase agreements with each of the Big 4 projects, it would have a material adverse effect on the related project.

Foreign Exchange Rate Risk

        Fluctuations in foreign currency exchange rates can affect, on a U.S. dollar equivalent basis, the amount of EME's equity contributions to, and distributions from, its international projects. At times, EME has hedged a portion of its current exposure to fluctuations in foreign exchange rates through financial derivatives, offsetting obligations denominated in foreign currencies, and indexing underlying project agreements to U.S. dollars or other indices reasonably expected to correlate with foreign exchange movements. In addition, EME has used statistical forecasting techniques to help assess

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foreign exchange risk and the probabilities of various outcomes. EME cannot provide assurances, however, that fluctuations in exchange rates will be fully offset by hedges or that currency movements and the relationship between certain macroeconomic variables will behave in a manner that is consistent with historical or forecasted relationships.

        At December 31, 2002 and 2001, EME had outstanding foreign currency forward exchange contracts entered into to hedge identifiable foreign currency commitments associated with transactions in the ordinary course of business and cross currency interest rate swap contracts entered into in the ordinary course of business. The periods of the contracts correspond to the periods of the hedged transactions.

Non-Trading Derivative Financial Instruments

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

 
  December 31,
 
 
  2002
  2001
 
Derivatives:          
  Interest rate:          
    Interest rate swap/cap agreements   (56 ) (37 )
    Interest rate options   (2 ) (1 )
  Commodity price:          
    Electricity   (100 ) (74 )
    Natural gas     (8 )
  Foreign currency forward exchange agreements     (1 )
  Cross currency interest rate swaps   (2 ) 28  

        In assessing the fair value of EME's non-trading derivative financial instruments, EME uses a variety of methods and assumptions that are based on market conditions and risk existing at each balance sheet date. The fair value of the commodity price contracts considers quoted market prices, time value, volatility of the underlying commodities and other factors.

        The fair value of the electricity rate swap agreements (included under commodity price-swaps) entered into by the Loy Yang B plant and the First Hydro plant has been estimated by discounting the future cash flows on the difference between the average aggregate contract price per MW and a forecasted market price per MW, multiplied by the amount of MW sales remaining under contract.

Energy Trading

        On September 1, 2000, EME acquired the trading operations of Citizens Power LLC. As a result of this acquisition, EME has expanded its operations beyond the traditional marketing of its electric power to include trading of electricity and fuels. In conducting EME's trading activities, EME seeks to generate profit from price volatility of electricity and fuels by buying and selling these commodities in wholesale markets. EME generally balances forward sales and purchases contracts and manages its exposure through a value at risk analysis as described further below. EME also conducts price risk

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management activities with third parties not related to EME's power plants or investments in energy projects, including the restructuring of power sales and power supply agreements.

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

 
  December 31, 2002
  December 31, 2001
 
  Assets
  Liabilities
  Assets
  Liabilities
Electricity   $ 109   $ 15   $ 7   $ 5
Other         2     2     2
   
 
 
 
Total   $ 109   $ 17   $ 9   $ 7
   
 
 
 

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

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

 
  Years Ended December 31,
 
  2002
  2001
  2000
Operating Revenues                  
Unrealized gains (losses), net   $ 10   $ (12 ) $ 12
Realized gains, net     32     22     50
   
 
 
Total   $ 42   $ 10   $ 62
   
 
 

Note 12. Preferred Securities

        Company-Obligated Mandatorily Redeemable Securities of Partnership Holding Solely Parent Debentures.    In November 1994, Mission Capital, L.P., a limited partnership of which EME is the sole general partner, issued 3.5 million 9.875% Cumulative Monthly Income Preferred Securities, Series A at a price of $25 per security and invested the proceeds in 9.875% junior subordinated deferrable interest debentures due 2024 which were issued by EME in November 1994. The Series A securities are redeemable at the option of Mission Capital, in whole or in part, with mandatory redemption in 2024 at a redemption price of $25 per security, plus accrued and unpaid distributions. No securities have been redeemed as of December 31, 2002. During August 1995, Mission Capital issued 2.5 million 8.5% Cumulative Monthly Income Preferred Securities, Series B at a price of $25 per security and invested the proceeds in 8.5% junior subordinated deferrable interest debentures due 2025 which were issued by EME in August 1995. The Series B securities are redeemable at the option of Mission Capital, in whole or in part, with mandatory redemption in 2025 at a redemption price of $25 per security, plus accrued and unpaid distributions. No securities have been redeemed as of December 31, 2002. EME issued a guarantee in favor of the holders of the preferred securities, which guarantees the payments of distributions declared on the preferred securities, payments upon a liquidation of Mission Capital and payments on redemption with respect to any preferred securities called for redemption by Mission Capital.

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        EME has the right from time to time to extend the interest payment period on its junior subordinated deferrable interest debentures to a period not exceeding 60 consecutive months, at the end of which all accrued and unpaid interest will be paid in full. If EME does not make interest payments on its junior subordinated debentures, it is expected that Mission Capital will not declare or pay distributions on its cumulative monthly income preferred securities. During an extension period, EME may not do any of the following:

        Furthermore, so long as any preferred securities remain outstanding, EME will not be able to declare or pay, directly or indirectly, any dividend on, or purchase, acquire or make a distribution or liquidation payment with respect to, any of EME's common stock if at such time (i) EME shall be in default with respect to EME's payment obligations under the guarantee, (ii) there shall have occurred any event of default under the subordinated indenture, or (iii) EME shall have given notice of its selection of the extended interest payment period described above and such period, or any extension thereof, shall be continuing.

        Subject to Mandatory Redemption.    During June 1999, Edison Mission Energy Taupo Limited, a New Zealand corporation, an indirect, wholly owned affiliate of EME, issued $84 million of Class A Redeemable Preferred Shares (16,000 shares at a price of 10,000 New Zealand dollars per share). The dividend rate ranged from 6.19% to 6.86%. The shares were redeemable in June 2003 at 10,000 New Zealand dollars per share. From July through November 1999, Edison Mission Energy Taupo issued $125 million of retail redeemable preferred shares (240 million shares at a price of one New Zealand dollar per share). The dividend rate ranged from 5.00% to 6.37%. The shares were redeemable at one New Zealand dollar per share in June 2001 (64 million), June 2002 (43 million), and June 2003 (133 million).

        On July 2, 2001, the Class A Redeemable Preferred Shares were redeemed at 10,000 New Zealand dollars per share and the retail redeemable preferred shares were redeemed at one New Zealand dollar per share from the existing holders. Funding for the redemption of the shares was provided by a NZ$400 million credit facility scheduled to mature in July 2005.

        From June through October 2001, Mission Contact Finance Limited issued $104 million of Redeemable Preferred Shares (250 million shares at a price of one New Zealand dollar per share). The dividend rate is 6.03%. The shares are redeemable in July 2006 at one New Zealand dollar per share. Mission Contact Finance Limited is a special purpose company established by Mission Energy Universal Holdings (Universal) to raise funds from the public and other institutional subscribers, to be used by it to subscribe for redeemable preferred shares in Mission Energy Pacific Holdings (Pacific). Universal and Pacific are wholly owned subsidiaries of EME. Mission Contact Finance will call on

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Pacific to redeem Pacific's Redeemable Preferred Shares held by Mission Contact Finance as and when necessary to provide it with the funds required to redeem the Mission Contact Finance Redeemable Preferred Shares. The redemption of the shares can be accelerated if Mission Contact Finance exercises its option under the terms of the issue of the shares to redeem all or part of the shares, at its discretion, by giving 45 days' irrevocable notice to the holders. Events of default will result in automatic redemption. Optional early redemption may occur if the holders pass an extraordinary resolution to redeem the shares if Mission Contact Finance or Pacific ceases to be a subsidiary of EME, or in the case of failure by Pacific to comply with the terms of the security trust deed. The Mission Contact Finance Redeemable Preferred Shares rank ahead of the ordinary shares in Mission Contact Finance for payment of amounts due on the shares. The holders of the shares have a shared indirect security interest, through a security trustee, in all of the ordinary shares of Contact Energy held by Pacific. The Security Trust Deed secures a limited recourse guarantee by Pacific of Mission Contact Finance's payment obligations to holders of the redeemable preferred shares. Mission Contact Finance may not, without the security trustee's prior written consent, make any distribution after an enforcement event (primarily a payment default) has occurred which remains unremedied.

Note 13. Income Taxes

Current and Deferred Taxes

        Income tax expense includes the current tax liability from operations and the change in deferred income taxes during the year. The components of the net accumulated deferred income tax liability for continuing operations were:

 
  December 31,
 
 
  2002
  2001
 
Deferred tax assets              
  Items deductible for book not currently deductible for tax   $ 78   $ 92  
  Loss carryforwards     81     93  
  Deferred income     172     179  
  Dividends in excess of equity earnings     8     8  
  Other     4     4  
   
 
 
  Subtotal     343     376  
  Valuation allowance     (22 )   (25 )
   
 
 
    Total   $ 321   $ 351  
   
 
 

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  December 31,
 
  2002
  2001
Deferred tax liabilities            
  Basis differences   $ 1,457   $ 1,228
  Tax credits, net     18     19
  Price risk management     25     1
  Other     2    
   
 
    Total     1,502     1,248
   
 
Deferred taxes and tax credits, net   $ 1,181   $ 897
   
 

        Foreign loss carryforwards, primarily Australian, total $204 million and $197 million at December 31, 2002 and 2001, respectively, with no expiration date. State loss carryforwards for various states total $230 million and $202 million at December 31, 2002 and 2001, respectively, with various expiration dates. State capital loss carryforwards total $128 million and $186 million at December 31, 2002 and 2001, respectively, and will expire in 2005.

        The components of income (loss) before income taxes and minority interest applicable to continuing operations are as follows:

 
  Years Ended December 31,
 
  2002
  2001
  2000
U.S.   $ (164 ) $ 41   $ 2
Foreign     174     82     143
   
 
 
  Total   $ 10   $ 123   $ 145
   
 
 

        United States income taxes have not been provided on unrepatriated foreign earnings of approximately $515 million and $483 million at December 31, 2002 and 2001, respectively. EME does not provide for federal income taxes or tax benefits on the undistributed earnings or losses of its international subsidiaries because such earnings are reinvested indefinitely. If EME repatriated all of its undistributed earnings in the form of dividends or otherwise, EME would be subject to both U.S. income taxes and withholding taxes in various international jurisdictions. Determination of the related amount of unrecognized deferred U.S. income tax liability is not practicable because of the complexities associated with its hypothetical calculation. In addition, foreign income taxes have not been provided on unrepatriated foreign earnings from a different foreign jurisdiction of approximately $75 million and $54 million at December 31, 2002 and 2001, respectively.

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        The provision (benefit) for income taxes applicable to continuing operations is comprised of the following:

 
  Years Ended December 31,
 
 
  2002
  2001
  2000
 
Current                    
  Federal   $ (175 ) $ (44 ) $ (206 )
  State     (83 )   8     (20 )
  Foreign     35     14     46  
   
 
 
 
    Total current   $ (223 ) $ (22 ) $ (180 )
   
 
 
 
Deferred                    
  Federal   $ 163   $ 49   $ 213  
  State     28     31     38  
  Foreign     12     8     5  
   
 
 
 
    Total deferred     203     88     256  
   
 
 
 
Provision (benefit) for income taxes   $ (20 ) $ 66   $ 76  
   
 
 
 

        The components of the deferred tax provision from continuing operations, which arise from tax credits and timing differences between financial and tax reporting, are presented below:

 
  Years Ended December 31,
 
 
  2002
  2001
  2000
 
Basis differences and tax credit amortization   $ 139   $ (11 ) $ 282  
Loss carryforwards     6     29     (28 )
Deferred income     7     4     3  
State tax deduction     6     (7 )   (5 )
Items deductible for book and tax in different accounting periods     12     41     45  
Price risk management     24     39     (39 )
Other     9     (7 )   (2 )
   
 
 
 
  Total deferred provision   $ 203   $ 88   $ 256  
   
 
 
 

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

 
  Years Ended December 31,
 
 
  2002
  2001
  2000
 
Expected provision for federal income taxes   $ 4   $ 43   $ 51  
Increase (decrease) in the provision for taxes resulting from:                    
  State tax—net of federal deduction     (36 )   22     12  
  Dividends received deduction     (5 )   (10 )   (11 )
  Taxes payable under anti-deferral regimes     14     14     6  
  Taxes on foreign operations at different rates     (13 )   (14 )   (4 )
  Non-utilization of foreign losses     11     9     16  
  Other     5     2     6  
   
 
 
 
  Total provision (benefit) for income taxes   $ (20 ) $ 66   $ 76  
  Effective tax rate     (200 )%   54 %   53 %

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

Note 14. Employee Benefit Plans

        United States employees of EME are eligible for various benefit plans of Edison International. Several of EME's Australian, United Kingdom and Spanish subsidiaries also participate in their own respective defined benefit pension plans. MEHC has no full-time employees.

Pension Plans

        Defined benefit pension plans (some with cash balance features) cover employees who fulfill minimum service and other requirements.

        Ferrybridge and Fiddler's Ferry employees joined a separate defined benefit pension plan utilized by some of the employees of First Hydro and Edison Mission Energy Limited during the first quarter of 2000. Amounts for the year 2000 are included in the table below. Pension expense for Ferrybridge and Fiddler's Ferry totaled $1.5 million for the year 2000 and is included in the table below. On December 21, 2001, the Ferrybridge and Fiddler's Ferry plants were sold to two wholly owned subsidiaries of American Electric Power. American Electric Power hired EME's employees upon completion of the purchase and was required, pursuant to the asset purchase agreement, to set up a pension plan similar to EME's by March 31, 2002. All of EME's former employees transferred to the new plan as of December 20, 2002. Pursuant to SFAS No. 88, "Employers' Accounting for Settlements and Curtailments of Defined Benefit Pension Plans and for Termination Benefits," EME recorded a

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curtailment gain of approximately $10 million related to the cessation of future benefits for EME's former employees in 2001. The curtailment gain reduced actuarial losses incurred during the year and, therefore, did not impact EME's pension expense.

        At December 31, 2002, the accumulated benefit obligation of the defined benefit pension plan utilized by First Hydro and Edison Mission Energy Limited employees exceeded the market value of the pension plan assets at the measurement date. Pursuant to SFAS No. 87, "Employers' Accounting for Pensions" and SFAS No. 132, "Employers' Disclosures about Pensions and Postretirement Benefits," EME recorded an additional minimum liability of approximately $11 million as a reduction to shareholder's equity through a charge to accumulated other comprehensive income. The charge to accumulated other comprehensive income would be restored through shareholder's equity in future periods to the extent the fair value of the plan assets exceeded the accumulated benefit obligation.

        Information on plan assets and benefit obligations is shown below:

 
  Years Ended December 31,
 
 
  2002
  2001
  2002
  2001
 
 
  U.S. Plans

  Non U.S. Plans

 
Change in Benefit Obligation                          
  Benefit obligation at beginning of year   $ 77   $ 67   $ 114   $ 126  
  Service cost     13     10     2     3  
  Interest cost     5     4     8     6  
  Amendments     3              
  Actuarial loss (gain)     9     (1 )   (4 )   (21 )
  Curtailment/settlement             (53 )    
  Plan participants' contribution             1     2  
  Benefits paid     (3 )   (3 )   (2 )   (2 )
   
 
 
 
 
    Benefit obligation at end of year   $ 104   $ 77   $ 66   $ 114  
   
 
 
 
 
Change in Plan Assets                          
  Fair value of plan assets at beginning of year   $ 41   $ 36   $ 110   $ 123  
  Actual return on plan assets     (5 )   (2 )   (18 )   (19 )
  Employer contributions     6     10     4     7  
  Curtailment/settlement             (51 )    
  Plan participants' contribution                 1  
  Benefits paid     (3 )   (3 )   (2 )   (2 )
   
 
 
 
 
    Fair value of plan assets at end of year   $ 39   $ 41   $ 43   $ 110  
   
 
 
 
 
Funded Status   $ (65 ) $ (36 ) $ (23 ) $ (4 )
Unrecognized net loss (gain)     29     11     19     10  
Unrecognized net obligation     1     1          
Unrecognized prior service cost     2     (1 )        
   
 
 
 
 
Pension asset (liability)   $ (33 ) $ (25 ) $ (4 ) $ 6  
   
 
 
 
 

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  Years Ended December 31,
 
  2002
  2001
  2002
  2001
 
  U.S. Plans

  Non U.S. Plans

Discount rate   6.50%   7.00%   5.00 - 5.50%   4.00 - 6.00%
Rate of compensation increase   5.00%   5.00%   3.50 - 4.00%   3.50 - 4.00%
Expected return on plan assets   8.50%   8.50%   7.50 - 8.00%   8.00%

        The projected benefit obligation, accumulated benefit obligation, and fair value of plan assets for the pension plans with accumulated benefit obligations in excess of plan assets were $88 million, $71 million and $51 million, respectively, as of December 31, 2002. As of December 31, 2001, the fair value of plan assets exceeded the accumulated benefit obligations for all pension and postretirement benefit plans.

        Components of pension expense were:

 
  Years Ended December 31,
 
 
  2002
  2001
  2000
  2002
  2001
  2000
 
 
  U.S. Plans

  Non U.S. Plans

 
Service cost   $ 13   $ 10   $ 11   $ 2   $ 3   $ 3  
Interest cost     5     4     4     8     6     7  
Expected return on plan assets     (3 )   (3 )   (3 )   (10 )   (7 )   (7 )
Net amortization and deferral     1             15          
   
 
 
 
 
 
 
Total pension expense   $ 16   $ 11   $ 12   $ 15   $ 2   $ 3  
   
 
 
 
 
 
 

Postretirement Benefits Other Than Pensions

        Most United States non-union employees retiring at or after age 55 with at least 10 years of service are eligible for postretirement health and dental care, life insurance and other benefits. Eligibility depends on a number of factors, including the employee's hire date.

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

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        Information on plan assets and benefit obligations is shown below:

 
  Years Ended December 31,
 
 
  2002
  2001
 
Change in Benefit Obligation              
  Benefit obligation at beginning of year   $ 118   $ 120  
  Service cost     5     5  
  Interest cost     8     7  
  Settlement     (71 )    
  Actuarial loss (gain)     (3 )   (14 )
  Benefits paid     (1 )    
   
 
 
  Benefit obligation at end of year   $ 56   $ 118  
   
 
 
Change in Plan Assets              
  Fair value of plant assets at beginning of year   $   $  
  Employer contributions     1      
  Benefits paid     (1 )    
   
 
 
    Fair value of plan assets at end of year   $   $  
   
 
 
Funded status   $ (56 ) $ (118 )
Unrecognized net loss (gain)     9     1  
Unrecognized prior service cost     (2 )   (2 )
   
 
 
Recorded liability   $ (49 ) $ (119 )
   
 
 
Discount rate     6.75 %   7.25 %
Expected return on plan assets     na     8.20 %

        The components of postretirement benefits other than pensions expense were:

 
  Years Ended December 31,
 
  2002
  2001
  2000
Service cost   $ 5   $ 5   $ 5
Interest cost     8     7     8
Settlement     (71 )      
   
 
 
Net expense   $ (58 ) $ 12   $ 13
   
 
 

        The assumed rate of future increases in the per-capita cost of health care benefits is 9.75% for 2003, gradually decreasing to 5.0% for 2008 and beyond. Increasing the health care cost trend rate by one percentage point would increase the accumulated obligation as of December 31, 2002, by $12 million and annual aggregate service and interest costs by $1 million. Decreasing the health care cost trend rate by one percentage point would decrease the accumulated obligation as of December 31, 2002, by $10 million and annual aggregate service and interest costs by $1 million.

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Employee Stock Plans

        A 401(k) plan is maintained to supplement eligible United States employees' retirement income. The plan received contributions from EME of $6 million in 2002, $6 million in 2001 and $5 million in 2000.

        Doga employees are included in a separate government scheme, Pension Plan of Social Security Institution. The plan is administered by the officers of the Turkish Government. Contributions to the plan are based on a percentage of compensation for the covered employees and are assessed by the Ministry of Labor and Social Security. The plan is substantially funded at the end of each month. Pension expense recorded by Doga was $114 thousand in 2002, $97 thousand in 2001 and $114 thousand in 2000.

        EME also sponsors a defined contribution plan for specified United Kingdom subsidiaries. Annual contributions are based on ten percent of covered employees' salaries. Contribution expense for the subsidiaries totaled approximately $1 million in 2002, 2001 and 2000.

Note 15. Stock Compensation Plans

Stock Options

        Under the Edison International Equity Compensation Plan, shares of Edison International common stock may be issued pursuant to plan awards to key EME employees in various forms, including the exercise of stock options. In May 2000, Edison International adopted an additional plan, the 2000 Equity Plan under which stock options, including the special options discussed below may be awarded. Under these programs, there are currently outstanding at December 31, 2002 to employees and former employees of EME, options on 2,181,812 shares of Edison International common stock. MEHC has no full-time employees.

        Each option may be exercised to purchase one share of Edison International common stock, and is exercisable at a price equivalent to the fair market value of the underlying stock at the date of grant. Options generally expire 10 years after the date of grant, and vest over a period of up to five years.

        Edison International stock options awarded prior to 2000 include a dividend equivalent feature. Dividend equivalents on options issued after 1993 and prior to 2000 are accrued to the extent dividends are declared on Edison International Common Stock, and are subject to reduction unless certain performance criteria are met. Only a portion of the 1999 Edison International stock option awards included a dividend equivalent feature. The liability and associated expense is accrued each quarter for the dividend equivalents for each option year. At the end of the performance measurement period, the expense and related liability is adjusted accordingly. Upon exercise, the dividends are paid out and the associated liability is reduced on EME's consolidated balance sheet.

        Options issued after 1997 generally have a four-year vesting period. The special options granted in 2000 vest over five years in 25% increments beginning May 2002. Earlier options had a three-year vesting period with one-third of the total award vesting annually. If an option holder retires, dies, is terminated by the company, or is terminated while permanently and totally disabled (qualifying event) during the vesting period, the unvested options will vest on a pro rata basis.

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        The fair value for each option granted during 2002, 2001 and 2000, reflecting the basis for the pro forma disclosures, was determined on the date of grant using the Black-Scholes option-pricing model.

        The following assumptions were used in determining fair value through the model:

 
  2002
  2001
  2000
Expected life   7-10 years   7-10 years   7-10 years
Risk-free interest rate   4.7% to 6.1%   4.7% to 6.1%   4.7% to 6.0%
Expected volatility   18% to 54%   17% to 52%   17% to 46%

        The application of fair-value accounting to calculate the pro forma disclosures is not an indication of future income statement effects. The recognition of dividend equivalents results in no dividends assumed for purposes of fair-value determination. The pro forma disclosures do not reflect the effect of fair-value accounting on stock-based compensation awards granted prior to 1995.

Other Equity-Based Awards

        For years after 1999, a portion of the executive long-term incentives was awarded in the form of performance shares. The 2000 performance shares were restructured as retention incentives in December 2000, which pay as a combination of Edison International common stock and cash if the executive remains employed at the end of the performance period. The performance period ended December 31, 2001, for half of the award, and ends on December 31, 2002, for the remainder. Additional performance shares were awarded in January 2001 and January 2002. The 2001 performance shares vest December 31, 2003, half in shares of Edison International common stock and half in cash. The 2002 performance shares vest December 31, 2004; also half in shares of common stock and half in cash. The number of shares that will be paid out from the 2002 performance share awards will depend on the performance of Edison International common stock relative to the stock performance of a specified group of peer companies.

        The 2000 and 2001 performance shares and deferred stock unit values are accrued ratably over a three-year performance period. The 2002 performance shares will be valued based on Edison International's stock performance relative to the stock performance of other such entities. In March 2001, deferred stock units were awarded as part of a retention program. These vest and were paid March 12, 2003. The deferred stock units are payable on the vesting date in shares of Edison International common stock.

        In October 2001, a stock option retention exchange offer was extended offering holders of Edison International stock options granted in 2000 the opportunity to exchange those options for a lesser number of deferred stock units. The exchange ratio was based on the Black-Scholes value of the options and the stock price at the time the offer was extended. The exchange took place in November 2001; the options that participants elected to exchange were cancelled, and deferred stock units were issued. Approximately three options were cancelled for each deferred stock unit issued. Twenty-five percent of the deferred stock units will vest and be paid in Edison International common stock per year over four years, with the first vesting and payment date in November 2002. The following assumptions were used in determining fair value through the Black-Scholes option-pricing model: expected life: 8-9 years; risk-free interest rate: 5.10%; expected volatility: 52%.

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        EME measures compensation expense related to stock-based compensation by the intrinsic value method. Compensation expense recorded under the stock compensation program was approximately $4 million, $3 million and $1 million for the years ended December 31, 2002, 2001 and 2000, respectively.

        The weighted-average fair value of options granted during 2002, 2001 and 2000 was $7.88 per share option, $3.88 per share option and $5.63 per share option, respectively. The weighted-average remaining life of options outstanding was 6 years as of December 31, 2002 and 2001 and 8 years as of December 31, 2000.

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

 
  Share
Options

  Exercise Price
  Weighted
Exercise Price

Outstanding, December 31, 1999   479,071   $ 14.56 - $29.34   $ 23.84
Granted   2,550,660   $ 20.06 - $28.13   $ 21.84
Transferred to EME from Edison International   514,750   $ 14.56 - $28.13   $ 23.68
Forfeited   (147,518 ) $ 18.75 - $28.13   $ 24.58
Exercised   (43,592 ) $ 14.56 - $28.13   $ 19.01
   
           
Outstanding, December 31, 2000   3,353,371   $ 14.56 - $29.34   $ 22.31
Granted   649,768   $ 9.10 - $15.25   $ 9.78
Transferred to EME from Edison International   1,327,105   $ 14.56 - $28.94   $ 20.16
Forfeited   (3,583,233 ) $ 9.15 - $29.34   $ 20.79
   
           
Outstanding, December 31, 2001   1,747,011   $ 9.10 - $29.34   $ 19.07
Granted   967,405   $ 10.60 - $18.73   $ 18.61
Transferred from EME to Edison International   (22,046 ) $ 9.15 - $28.94   $ 21.33
Forfeited   (466,382 ) $ 9.10 - $29.34   $ 20.09
Exercised   (44,176 ) $ 15.18 - $18.80   $ 16.75
   
           
Outstanding, December 31, 2002   2,181,812   $ 9.10 - $28.94   $ 18.60
   
           

        The number of options exercisable and their weighted-average exercise prices at December 31, 2002, 2001 and 2000 were 731,009 at $21.29, 780,802 at $22.49 and 562,662 at $21.55, respectively.

Phantom Stock Options

        EME, as a part of the Edison International long-term incentive compensation program, issued phantom stock option performance awards to key employees from 1994 through 1999. Each phantom stock option could be exercised to realize any appreciation in the value of one hypothetical share of EME stock over its exercise price. Compensation expense was recognized during the period that the employee had the right to receive this appreciation. Exercise prices for EME's phantom stock were escalated on an annually compounded basis over the grant price by 9%. The value of the phantom stock was recalculated annually as determined by a formula linked to the value of EME's portfolio of investments less general and administrative costs. The options had a 10-year term with one-third of the

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total award vesting in each of the first three years of the award term, for all awards prior to 1998. For options awarded in 1998 and 1999, one-fourth of the total award vested in each of the first four years of the award term. In August 2000, all outstanding phantom stock options were cancelled and replaced with a combination of cash and stock equivalent units relating to Edison International common stock in accordance with the EME Affiliate Option Exchange Offer.

        Compensation expense recorded with respect to phantom stock options was $2 million, $6 million and $4 million (before the $60 million adjustment referred to below) in 2002, 2001 and 2000, respectively.

        Due to the lower valuation of the exchange offer, compared to the values previously accrued, the liability for accrued incentive compensation was reduced by approximately $60 million in the third quarter of 2000.

Note 16. Commitments and Contingencies

Firm Commitment for Asset Purchase

Projects

  Local Currency
  U.S. Currency
Italian Wind and Expansion(i)   2 million Euro   $ 2

(i)
The Italian Wind projects are a series of power projects that are in operation in Italy. EME's wholly owned subsidiary owns a 50% interest. The final purchase payments are expected to be made during the first quarter of 2003. The Italian Wind expansion project is a 20 MW wind project in operation in Sardinia, Italy, adjacent to an existing Italian Wind project site.

Firm Commitments to Contribute Project Equity

Projects

  U.S. Currency
CBK(i)   $ 37
Italian Wind Expansion(ii)   $ 2
Sunrise(iii)   $ 36

(i)
CBK is a 760 MW hydroelectric power project under construction in the Philippines. At December 31, 2002, 385 megawatts have been commissioned and are operational. A wholly owned subsidiary of EME owns a 50% interest. Equity was initially expected to be contributed through December 2003 commencing after full drawdown of the project's debt facility, which had been scheduled for late 2002. During the fourth quarter of 2002, EME prepaid $11 million of the equity contribution as a result of a failure by the contractor responsible for engineering, procurement and construction of the project to provide additional security for liquidated damages. EME has obtained a waiver from lenders for the contractor's default, but expects that equity will be fully contributed before the project is able to draw upon the remaining loan commitment. In addition, as a result of Moody's credit downgrade, EME posted a letter of credit to support the remaining portion of this obligation. In addition to these equity infusions, the project sponsors funded a

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(ii)
The Italian Wind expansion project is a 20 MW wind project that commenced commercial operation in the fourth quarter of 2002 and is located in Sardinia, Italy, adjacent to an existing Italian Wind project site. A wholly owned subsidiary of EME owns a 50% interest. Equity is to be contributed during the first quarter of 2003.

(iii)
The Sunrise project, located in Fellows, California, consists of two phases: Phase 1, a simple-cycle gas-fired facility (320 MW) that commenced commercial operation in June 2001; and Phase 2, conversion to a combined-cycle gas-fired facility (bringing the plant to a total capacity of 560 MW) currently scheduled to be completed in July 2003. A wholly owned subsidiary of EME owns a 50% interest. Equity will be contributed to fund the construction of Phase 2. The amount set forth in the above table assumes the partners will contribute equity for the entire construction cost.

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

Chicago In-City Obligation

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

        As a result of this agreement with Commonwealth Edison, Midwest Generation recorded a loss of $45 million during the fourth quarter of 2002. The loss was determined by the sum of: (a) the present value of the cash payments to both Commonwealth Edison and Calumet Energy Team LLC (capacity

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payments), less (b) the fair market value of the option to purchase power under the replacement contract with Calumet Energy Team LLC. As a result of the agreement with Commonwealth Edison, Midwest Generation is no longer obligated to build the additional gas-fired generation.

Fuel Supply Contracts

        At December 31, 2002, EME's subsidiaries had contractual commitments to purchase and/or transport coal and fuel oil. Based on the contract provisions, which consist of fixed prices, subject to adjustment clauses in some cases, these minimum commitments are currently estimated to aggregate $2,137 million in the next five years summarized as follows: 2003—$605 million; 2004—$487 million; 2005—$453 million; 2006—$366 million; and 2007—$226 million.

Gas Transportation Agreements

        At December 31, 2002, EME had contractual commitments to transport natural gas beginning the later of May 1, 2003 or the first day that expansion capacity is available for transportation services. In June 2001, EME entered into an agreement with Texaco Power & Gasification Holdings, Inc. for the purpose of committing, and eventually assigning, one of the contracts to the Sunrise project. In this agreement, Texaco Power & Gasification Holdings, Inc. has agreed to assume 50% of EME's liabilities under the specified contract until its formal assignment to the Sunrise project. EME's share of the commitment to pay minimum fees under these agreements, which have a term of 15 years, is currently estimated to aggregate $71 million in the next five years, summarized as follows: 2003—$8 million; 2004—$16 million; 2005—$16 million; 2006—$16 million; and 2007—$15 million.

Contingencies

Paiton Project

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

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

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

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extended to take into account the effect upon the project of the lower cash flow resulting from the restructured electricity tariff. The initial principal repayment under the new amortization schedule was made on February 18, 2003. Distributions from the project to shareholders are not anticipated to commence until 2006. As a condition to the making of the loans by Export-Import Bank of the United States, all commercial disputes related to the project were settled without a material effect on EME. EME believes that it will ultimately recover its investment in the project.

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

BHP Fuel Supply Agreement Arbitration

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

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

Brooklyn Navy Yard Project

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

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ISAB Project

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

Regulatory Developments Affecting Sunrise Power Company

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

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

        On May 15, 2002, Sunrise Power Company was served with a complaint filed in the Superior Court of the State of California, City and County of San Francisco, by James M. Millar, "individually, and on behalf of the general public and as a representative taxpayer suit" against sellers of long-term power to

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the California Department of Water Resources, including Sunrise Power Company. The lawsuit alleges that the defendants, including Sunrise Power Company, engaged in unfair and fraudulent business practices by knowingly taking advantage of a manipulated power market to obtain unfair contract terms. The lawsuit seeks to enjoin enforcement of the "unfair and oppressive terms and conditions" in the contracts, as well as restitution by the defendants of excessive monies obtained by the defendants. Plaintiffs in several other class action lawsuits pending in Northern California have filed petitions seeking to have the Millar lawsuit consolidated with those lawsuits. The defendants in the Millar lawsuit and other class action suits removed all the lawsuits to the U.S. District Court, Northern District of California, and filed a motion to stay all proceedings pending final resolution of the jurisdictional issue. Various plaintiffs have filed pleadings opposing the removal and requesting that the matters be remanded to state court. The motions are still pending. EME believes that the outcome of this litigation will not have a material adverse effect on its consolidated financial position or results of operations.

Regulatory Developments Affecting Doga Project

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

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

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

Guarantees and Indemnities

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

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

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

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

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

        In connection with the sale of assets, EME has provided indemnities to the purchasers for taxes imposed with respect to operations of the asset prior to the sale, and EME or its subsidiaries have

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

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

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

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

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

        A subsidiary of EME has indemnified Central Maine Power Company against decreases in the value of power deliveries by CL Power Sales Eight, L.L.C., an unconsolidated affiliate, to Central Maine Power as a result of the implementation of a location-based pricing system in the New England Power Pool. The indemnity has the same term as a power supply agreement between Central Maine Power and CL Eight, which runs through December 2016. It is not possible to determine potential differences in values between the various points of delivery in New England Power Pool at this time. Due to the nature of this indemnity, a maximum potential liability cannot be determined. To the extent EME's subsidiary would be required to make a payment under this indemnity, it and EME are indemnified by Peabody Energy Corporation pursuant to the 2000 Purchase and Sale Agreement for the acquisition of Citizens Power LLC. EME's subsidiary has not recorded a liability related to this indemnity.

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

Litigation

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

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Contingent Obligations to Contribute Project Equity

Projects

  Local Currency
  U.S. Currency
Paiton(i)     $ 5
ISAB(ii)   37 million Euro   $ 39

(i)
Contingent obligations to contribute additional project equity were based on events principally related to insufficient cash flow to cover interest on project debt and operating expenses, specified partner obligations or events of default. EME's obligation to contribute contingent equity did not exceed $141 million. As of December 31, 2002, $113 million had been contributed as project equity and $23 million deposited with the loan trustee to provide for further contributions if called for. The figure above represented EME's remaining unfunded commitments. As part of the restructuring of the project's debt completed in February 2003, the obligation to contribute project equity was terminated.
(ii)
ISAB is a 518 MW integrated gasification combined cycle power plant near Siracusa in Sicily, Italy. A wholly owned subsidiary of EME owns a 49% interest. Commercial operations commenced in April 2000. Contingent obligations to contribute additional equity to the project related specifically to an agreement to provide equity assurances to the project's lenders depending on the outcome of the contractor claim arbitration. The arbitration was settled, and consequently, there is no further obligation to contribute project equity.

        EME is not aware of any other significant contingent obligations to contribute project equity.

Environmental Matters and Regulations

        EME is subject to environmental regulation by federal, state and local authorities in the United States and foreign regulatory authorities with jurisdiction over projects located outside the United States. EME believes that it is in substantial compliance with environmental regulatory requirements and that maintaining compliance with current requirements will not materially affect its financial position or results of operation. However, possible future developments, such as the promulgation of more stringent environmental laws and regulations, and future proceedings that may be initiated by environmental authorities, could affect the costs and the manner in which EME conducts its business and could cause it to make substantial additional capital expenditures. There is no assurance that EME would be able to recover these increased costs from its customers or that EME's financial position and results of operations would not be materially adversely affected.

        Typically, environmental laws require a lengthy and complex process for obtaining licenses, permits and approvals prior to construction and operation of a project. Meeting all the necessary requirements can delay or sometimes prevent the completion of a proposed project as well as require extensive modifications to existing projects, which may involve significant capital expenditures. If EME fails to

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comply with applicable environmental laws, it may be subject to penalties and fines imposed against EME by regulatory authorities.

State—Illinois

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

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

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

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

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State—Pennsylvania

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

Federal—United States of America

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

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

        National Ambient Air Quality Standards.    A new ambient air quality standard was adopted by the Environmental Protection Agency in July 1997 to address emissions of fine particulate matter. It is widely understood that attainment of the fine particulate matter standard may require reductions in nitrogen oxides and sulfur dioxides, although, under the time schedule announced by the Environmental Protection Agency when the new standard was adopted, non-attainment areas were not to have been designated until 2002 and control measures to meet the standard were not to have been

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identified until 2005. In May 1999, the United States Court of Appeals for the District of Columbia Circuit held that Section 109(b)(1) of the Clean Air Act, the section of the Clean Air Act requiring the promulgation of national ambient air quality standards, as interpreted by the Environmental Protection Agency, was an unconstitutional delegation of legislative power. The Court of Appeals remanded both the fine particulate matter standard and the revised ozone standard to allow the Environmental Protection Agency to determine whether it could articulate a constitutional application of Section 109(b)(1). On February 27, 2001, the Supreme Court, in Whitman v. American Trucking Associations, Inc., reversed the Circuit Court's judgment on this issue and remanded the case back to the Court of Appeals to dispose of any other preserved challenges to the particulate matter and ozone standards. On March 26, 2002, the District of Columbia Circuit, on remand, held that the revised ozone and fine particulate matter ambient air quality standards were neither arbitrary nor capricious. Further action by the EPA with respect to the implementation of the revised ozone standard and the promulgation of a new coarse particulate matter standard is required pursuant to the first District of Columbia Circuit opinion and the Supreme Court's decision in Whitman v. American Trucking Associations, Inc.

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

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

        Comprehensive Environmental Response, Compensation, and Liability Act.    Under various federal, state and local environmental laws and regulations, a current or previous owner or operator of any facility, including an electric generating facility, may be required to investigate and remediate releases or threatened releases of hazardous or toxic substances or petroleum products located at that facility, and may be held liable to a governmental entity or to third parties for property damage, personal injury and investigation and remediation costs incurred by these parties in connection with these releases or

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threatened releases. Many of these laws, including the Comprehensive Environmental Response, Compensation and Liability Act of 1980, commonly referred to as CERCLA, as amended by the Superfund Amendments and Reauthorization Act of 1986, impose liability without regard to whether the owner knew of or caused the presence of the hazardous substances, and courts have interpreted liability under these laws to be strict and joint and several. The cost of investigation, remediation or removal of these substances may be substantial. In connection with the ownership and operation of EME's facilities, EME may be liable for these costs.

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

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

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

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

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Justice took place on January 15, 2003. EME expects settlement discussions will continue during the first half of 2003.

        On November 3, 1999, the United States Department of Justice filed suit against a number of electric utilities for alleged violations of the Clean Air Act's new source review, or NSR, requirements related to modifications of air emissions sources at electric generating stations located in the southern and midwestern regions of the United States. Several states have joined these lawsuits. In addition, the United States Environmental Protection Agency has also issued administrative notices of violation alleging similar violations at additional power plants owned by some of the same utilities named as defendants in the Department of Justice lawsuit, as well as other utilities, and also issued an administrative order to the Tennessee Valley Authority for similar violations at certain of its power plants. The Environmental Protection Agency has also issued requests for information pursuant to the Clean Air Act to numerous other electric utilities, including the prior owners of the Homer City facilities, seeking to determine whether these utilities also engaged in activities that may have been in violation of the Clean Air Act's NSR requirements.

        To date, several utilities have reached formal agreements with the United States (or reached agreements-in-principle) to resolve alleged NSR violations. All of the settlements have included the installation of additional pollution controls, supplemental environment projects, and the payment of civil penalties. Some of the settlements have also included the retirement or repowering of coal-fired generating units. The agreements provide for a phased approach to achieving required emission reductions over the next 10 to 15 years. The total cost of some of these settlements exceeds $1 billion; the civil penalties agreed to by these utilities range between $1 million and $10 million. Because of the uncertainty created by the Bush administration's review of the NSR regulations and NSR enforcement proceedings, some of the settlements referred to above have not been finalized. However, in January 2002, the Department of Justice completed its review and concluded that "the EPA has a reasonable basis for arguing that the enforcement actions are consistent with both the Clean Air Act and the Administrative Procedure Act." Accordingly, the Department of Justice has continued to prosecute NSR enforcement cases against electric utilities, with some cases scheduled for trial in 2003.

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

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

International

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

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

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

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

• Australia   • Spain
• Indonesia   • Thailand
• Italy   • Turkey
• New Zealand   • The United Kingdom
• Philippines   • The United States

        All of the countries, with the exception of Indonesia, the Philippines and Thailand, are classified as Annex 1 or "developed" countries and are subject to national greenhouse gas emission reduction

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targets during the period of 2008-2012 (e.g., Phase 1). Each nation is actively developing policies and measures meant to assist it with meeting the individual national emission targets as set out within the Kyoto Protocol.

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

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

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

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

        The United States has indicated that it will support a decision to take international action on mercury at the Global Ministerial Environment Forum. However, the United States has further stated that it does not support negotiation of a legally-binding convention at this time. In general, the United States approach: 1) agrees that there is sufficient evidence of adverse impacts of mercury to warrant international action; 2) urges countries to take actions within the context of their national circumstances to identify exposed populations and to reduce anthropogenic emissions of mercury; 3) recommends the establishment of a "Mercury Program" within UNEP, 4) recommends coordination between UNEP and other international organizations that work on mercury issues such as the World Health Organization; and 5) asks countries to make voluntary contributions to support efforts of the Mercury Program under UNEP.

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

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Note 17. Lease Commitments

        MEHC and EME lease office space, property and equipment under noncancelable lease agreements that expire in various years through 2063.

        Future minimum payments for operating leases at December 31, 2002, are:

Years Ending December 31,

  Operating
Leases

2003   $ 341
2004     319
2005     362
2006     444
2007     481
Thereafter     5,057
   
Total future commitments   $ 7,004
   

        Operating lease expense amounted to $233 million, $163 million and $122 million in 2002, 2001 and 2000, respectively.

Sale-Leaseback Transactions

        On December 7, 2001, a subsidiary of EME completed a sale-leaseback of EME's Homer City facilities to third-party lessors for an aggregate purchase price of $1.6 billion, consisting of $782 million in cash and assumption of debt (the fair value of which was $809 million). Under the terms of the 33.67-year leases, EME's subsidiary is obligated to make semi-annual lease payments on each April 1 and October 1. If a lessor intends to sell its interest in the Homer City facilities, EME has a right of first refusal to acquire the interest at fair market value. Minimum lease payments (included in the table above) are $174 million in 2003, $142 million in 2004, $152 million in 2005, $152 million in 2006 and $151 million in 2007. At December 31, 2002, the total remaining minimum lease payments are $3.2 billion. Lease costs will be levelized over the terms of the leases. The gain on the sale of the facilities has been deferred and is being amortized over the term of the leases.

        On August 24, 2000, a subsidiary of EME completed a sale-leaseback of EME's Powerton and Joliet power facilities located in Illinois to third-party lessors for an aggregate purchase price of $1.4 billion. Under the terms of the leases (33.75 years for Powerton and 30 years for Joliet), EME's subsidiary makes semi-annual lease payments on each January 2 and July 2, which began January 2, 2001. EME guarantees its subsidiary's payments under the leases. If a lessor intends to sell its interest in the Powerton or Joliet power facility, EME has a right of first refusal to acquire the interest at fair market value. Minimum lease payments (included in the table above) are $97 million in 2003, $97 million in 2004, $141 million in 2005, $185 million in 2006, and $185 million in 2007. At December 31, 2002, the total remaining minimum lease payments are $2.2 billion. Lease costs of these power facilities will be levelized over the terms of the respective leases. The gain on the sale of the power facilities has been deferred and is being amortized over the term of the leases.

        In connection with the acquisition of the Illinois Plants, EME assigned the right to purchase the Collins gas and oil-fired power plant to third-party lessors. The third-party lessors purchased the Collins Station for $860 million and entered into leases of the plant with EME. The leases, which are being

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accounted for as operating leases, have an initial term of 33.75 years with payments due on a quarterly basis. The base lease rent includes both a fixed and variable component; the variable component of which is impacted by movements in defined short-term interest rate indexes. Under the terms of the leases, EME may request a lessor, at its option, to refinance the lessor's debt, which if completed would impact the base lease rent. If a lessor intends to sell its interest in the Collins Station, EME has a first right of refusal to acquire the facility at fair market value. Minimum lease payments (included in the table above) are $40 million in 2003, $52 million in 2004, $50 million in 2005, $90 million in 2006 and $129 million in 2007. At December 31, 2002, the total remaining minimum lease payments were $1.4 billion.

Note 18. Related Party Transactions

        Specified administrative services such as payroll and employee benefit programs, all performed by Edison International or Southern California Edison Company employees, are shared among all affiliates of Edison International, and the costs of these corporate support services are allocated to all affiliates, including MEHC. Costs are allocated based on one of the following formulas: percentage of time worked, equity in investment and advances, number of employees, or multi-factor (operating revenues, operating expenses, total assets and number of employees). In addition, services of Edison International or Southern California Edison employees are sometimes directly requested by MEHC and these services are performed for MEHC's benefit. Labor and expenses of these directly requested services are specifically identified and billed at cost. MEHC believes the allocation methodologies utilized are reasonable. MEHC made reimbursements for the cost of these programs and other services, which amounted to $53 million, $71 million and $65 million in 2002, 2001 and 2000, respectively. Accounts payable—affiliates associated with these administrative services totaled $12 million at December 31, 2002 and 2001.

        MEHC participates in the insurance program of Edison International, including property, general liability, workers compensation and various other specialty policies. MEHC's insurance premiums are generally based on MEHC's share of risk related to each policy. In connection with the property insurance program, a portion of the risk is reinsured by a captive insurance subsidiary of Edison International. Under these reinsurance policies, MEHC is entitled to receive a premium refund to the extent that MEHC's loss experience is less than estimated.

        MEHC records accruals for tax liabilities and/or tax benefits which are settled quarterly according to a series of tax-allocation agreements as described in Note 2. Under these agreements, MEHC recognized tax benefits applicable to continuing operations of $258 million, $36 million and $226 million for 2002, 2001 and 2000, respectively. See Note 13—Income Taxes. Amounts included in Accounts receivable—affiliates associated with these tax benefits totaled $30 million and $254 million at December 31, 2002 and 2001, respectively.

        Edison Mission Operation & Maintenance, Inc., an indirect, wholly owned affiliate of EME, has entered into operation and maintenance agreements with partnerships in which EME has a 50% or less ownership interest. Pursuant to the negotiated agreements, Edison Mission Operation & Maintenance is to perform all operation and maintenance activities necessary for the production of power by these partnerships' facilities. The agreements continue until terminated by either party. Edison Mission Operation & Maintenance is paid for all costs incurred with operating and maintaining such facilities

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and may also earn an incentive compensation as set forth in the agreements. EME recorded revenues under the operation and maintenance agreements of $22 million, $24 million and $28 million in 2002, 2001 and 2000, respectively. Accounts receivable—affiliates for Edison Mission Operation & Maintenance totaled $7 million and $6 million at December 31, 2002 and 2001, respectively.

        Specified EME subsidiaries have ownership in partnerships that sell electricity generated by their project facilities to Southern California Edison Company and others under the terms of long-term power purchase agreements. Sales by these partnerships to Southern California Edison Company under these agreements amounted to $548 million, $983 million and $716 million in 2002, 2001 and 2000, respectively.

Note 19. Supplemental Statements of Cash Flows Information

 
  Years Ended December 31,
 
 
  2002
  2001
  2000
 
Cash paid                    
  Interest (net of amount capitalized)   $ 567   $ 557   $ 539  
  Income taxes (receipts)   $ (462 ) $ 90   $ (51 )
Details of assets acquired                    
  Fair value of assets acquired   $ 16   $ 898   $ 523  
  Liabilities assumed         801     397  
   
 
 
 
Net cash paid for acquisitions   $ 16   $ 97   $ 126  
   
 
 
 

Note 20. Business Segments

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

        Electric power and steam generated in the United States is sold primarily under (1) long-term contracts, with terms of 15 to 30 years, to domestic electric utilities and industrial steam users, (2) through a centralized power pool, or (3) under three power purchase agreements with Commonwealth Edison, which assigned its rights and obligations under these power purchase agreements to Exelon Generation Company, which began December 15, 1999 and have a term of up to five years. EME currently derives a significant source of its revenues from the sale of energy and capacity to Exelon Generation Company under these power purchase agreements. EME's revenues from Commonwealth Edison were $1.1 billion for each of the years ended December 31, 2002, 2001 and 2000, respectively. This represents 41%, 43% and 49% of EME's consolidated revenues in 2002, 2001 and 2000, respectively. Commonwealth Edison revenues are included in the Americas region shown below.

        The Loy Yang B power plant and the Valley Power Peaker power plant both located in Australia sell their energy and capacity production through a centralized power pool by entering into short and/or long-term contracts to hedge against the volatility of price fluctuations in the pool. The First

189



Hydro power plants located in the United Kingdom sell their energy and capacity production by entering into physical bilateral contracts with various counterparties. Other electric power generated overseas is sold under short and/or long-term contracts to either electricity companies, electricity buying groups or electric utilities located in the country where the power is generated. Intercompany transactions have been eliminated in the following segment information.

 
  Americas
  Asia
Pacific

  Europe
  Corporate/
Other

  Total
 
2002                                
Operating revenues from consolidated subsidiaries   $ 1,564   $ 707   $ 452   $   $ 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  

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  Americas
  Asia
Pacific

  Europe
  Corporate/
Other

  Total
 
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  

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  Americas
  Asia
Pacific

  Europe
  Corporate/
Other

  Total
 
2000                                
Operating revenues from consolidated subsidiaries   $ 1,571   $ 184   $ 450   $ 1   $ 2,206  
Net gains (losses) from price risk management and energy trading     (17 )               (17 )
   
 
 
 
 
 
  Total operating revenues     1,554     184     450     1     2,189  
   
 
 
 
 
 
Fuel, plant operations and transmission costs, and plant operating leases,     1,132     61     213         1,406  
Depreciation and amortization     189     38     37     8     272  
Long-term incentive compensation                 (56 )   (56 )
Administrative and general     25     16     16     104     161  
   
 
 
 
 
 
  Income (loss) from operations     208     69     184     (55 )   406  
   
 
 
 
 
 
Equity in income from unconsolidated affiliates     257     16     (5 )   (1 )   267  
Interest and other income     5     (2 )   4     23     30  
Gain on sale of assets     17     9             26  
Interest expense     (184 )   (66 )   (80 )   (222 )   (552 )
Dividends on preferred securities         (18 )       (14 )   (32 )
   
 
 
 
 
 
  Total other income (expense)     95     (61 )   (81 )   (214 )   (261 )
   
 
 
 
 
 
Income (loss) from continuing operations before income taxes and minority interest   $ 303   $ 8   $ 103   $ (269 ) $ 145  
   
 
 
 
 
 
Identifiable assets   $ 5,607   $ 1,409   $ 1,773   $ 567   $ 9,356  
Assets of discontinued operations             3,574         3,574  
Equity investments and advances     952     1,049     86         2,087  
   
 
 
 
 
 
  Total assets   $ 6,559   $ 2,458   $ 5,433   $ 567   $ 15,017  
   
 
 
 
 
 
Additions to property and plant   $ 294   $ 4   $ 17   $ 15   $ 330  

        During 2002, MEHC changed its presentation of segment performance by presenting the measure of profit or loss for each reportable segment as income (loss) from continuing operations before income taxes and minority interest compared to income (loss) from operations as reported in 2001 and 2000.

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Geographic Information

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

 
  Years Ended December 31,
 
  2002
  2001
  2000
Operating revenues                  
  Australia   $ 213   $ 166   $ 184
  New Zealand     493     294    
   
 
 
Total Asia Pacific   $ 706   $ 460   $ 184
   
 
 
  United Kingdom   $ 317   $ 236   $ 333
  Turkey     111     118     99
  Spain     15     18     18
   
 
 
Total Europe   $ 443   $ 372   $ 450
   
 
 
 
  December 31,
 
  2002
  2001
  2000
Assets                  
  Australia   $ 1,264   $ 1,152   $ 1,217
  New Zealand     1,738     1,333     686
  Indonesia     550     535     531
  Other Asia Pacific     20     54     24
   
 
 
Total Asia Pacific   $ 3,572   $ 3,074   $ 2,458
   
 
 
  United Kingdom(1)   $ 1,690   $ 1,680   $ 4,933
  Turkey     217     259     231
  Spain     117     136     144
  Italy     65     64     54
  Other Europe     74     40     71
   
 
 
Total Europe   $ 2,163   $ 2,179   $ 5,433
   
 
 

(1)
Includes assets of discontinued operations.

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Note 21. Quarterly Financial Data (unaudited)

        Amounts reported below are different from those previously reported on Form 10-Q because the results of Lakeland have been classified as discontinued operations for all historical periods presented and the reclassification of equity in income of unconsolidated affiliates from operating revenues to other income (expense). For more information on Lakeland, see Note 7—Discontinued Operations.

2002

  First(i)
  Second
  Third(i)
  Fourth(i)
  Total
 
Operating revenues   $ 537   $ 673   $ 954   $ 586   $ 2,750  
Operating income (loss)     (13 )   73     251     18     329  
Income (loss) from continuing operations before accounting change     (63 )   (29 )   132     (37 )   3  
Discontinued operations, net     5     9     7     (78 )(ii)   (57 )
Net income (loss)     (72 )   (20 )   139     (115 )(ii)   (68 )
2001

  First(i)
  Second
  Third(i)
  Fourth(i)
  Total
 
Operating revenues   $ 482   $ 585   $ 924   $ 497   $ 2,488  
Operating income (loss)     22     79     300     (96 )(iv)   305  
Income (loss) from continuing operations before accounting change     (15 )   37     138     (126 )(iv)   34  
Discontinued operations, net     23     (37 )   (1,204 )(iii)   (1 )   (1,219 )
Net income (loss)     8         (1,050 )(iii)   (128 )   (1,170 )

(i)
Reflects EME's seasonal pattern, in which the majority of earnings from domestic projects are recorded in the third quarter of each year and higher electric revenues from specified international projects are recorded during the winter months of each year.

(ii)
Reflects asset impairment charges of $77 million, after tax, and a provision for bad debts of $1 million, after tax, required to write down the carrying amount of the Lakeland plant and related claims under the power sales agreement to its fair market value.

(iii)
Reflects asset impairment charges of $1.2 billion, after tax, required to write down the carrying amount of the Ferrybridge and Fiddler's Ferry plants to their estimated fair value less cost to sell and related currency adjustments in connection with the sale of the plants.

(iv)
Reflects asset impairment charges of $10 million required to write down EME's investment to the estimated net proceeds from the planned sale of the Commonwealth Atlantic, Gordonsville and Harbor projects and a loss on the termination of a portion of EME's Master Turbine Lease of $25 million.

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PART III

ITEM 10. DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANT

Positions with Mission Energy Holding Company

        Listed below are MEHC's current directors and executive officers and their ages and positions as of March 27, 2003.

Name, Position and Age

  Director
Continuously
Since

  Term
Expires

  Position Held
Continuously
Since

  Term
Expires

John E. Bryson, 59
    Director, Chairman of the Board
  2001   2003    

Frank B. Bilotta, 42
    Director

 

2001

 

2003

 


 


Bryant C. Danner, 65
    Director

 

2001

 

2003

 


 


Theodore F. Craver, Jr., 51
    Director, Chief Executive Officer and President

 

2001

 

2003

 

2001

 

2003

Barbara Mathews, 50
    Secretary and Assistant General Counsel

 


 


 

2001

 

2003

Kevin M. Smith, 45
    Senior Vice President and Chief Financial Officer

 


 


 

2001

 

2003

Raymond W. Vickers, 60
    Senior Vice President and General Counsel

 


 


 

2001

 

2003

Business Experience

        Below is a description of the principal business experience during the past five years of each of the individuals named above and the name of each public company in which any director named above is a director.

        Mr. Bryson has 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. Bilotta has been director of Mission Energy Holding Company since June 2001 and serves as Mission Energy Holding Company's independent director. Mr. Bilotta has over 16 years of diversified accounting and legal experience with an emphasis in asset-backed securities. Prior to joining Global Securitization Services in September of 2000, Mr. Bilotta served as senior vice president at Lord Securities Corporation. He also served as an independent director on a variety of structured finance

195



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. Danner has 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. Craver has been director, chief executive officer and president of Mission Energy Holding Company since June 2001. Mr. Craver has been director of Edison Mission Energy since January 2001. Since January 2002, Mr. Craver has been executive vice president of Edison International. Mr. Craver has been senior vice president, chief financial officer, and treasurer of Edison International since January 2000. Mr. Craver has been chairman of the board and chief executive officer of Edison Enterprises since September 1999. Mr. Craver served as senior vice president and treasurer of Edison International from February 1998 to January 2000. Mr. Craver served as senior vice president and treasurer of Southern California Edison from February 1998 to September 1999. Mr. Craver served as vice president and treasurer of Edison International and Southern California Edison from September 1996 to February 1998.

        Ms. Mathews has 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. Smith has 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. Vickers has been senior vice president and general counsel of Mission Energy Holding Company since June 2001. Mr. Vickers has been senior vice president and general counsel of Edison Mission Energy since March 1999. Prior to joining Edison Mission Energy, Mr. Vickers was a partner with the law firm of Skadden, Arps, Slate, Meagher & Flom LLP concentrating on international business transactions, particularly cross-border capital markets and investment transactions, project implementation and finance.


ITEM 11. EXECUTIVE COMPENSATION

        MEHC officers receive compensation from EME or Edison International and receive no compensation from MEHC. For information concerning the chief executive officer and four most highly paid executive officers, other than the chief executive officer, of EME and Edison International, see Item 11 of EME's Form 10-K for the year ended December 31, 2002 and the Summary Compensation Table in the Executive Compensation section of Edison International's Proxy Statement relating to its 2003 Annual Meeting of Shareholders, respectively, which are incorporated by reference.

Compensation of Directors

        MEHC's directors do not receive any compensation for serving on its board of directors or attending meetings, thereof, except that MEHC's independent director, Frank B. Bilotta, receives customary compensation. During 2002, Mr. Bilotta received an annual fee of $3,500 for providing independent directorship services.

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ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT

Certain Beneficial Owners

        Set forth below is certain information regarding each person who is known to MEHC to be the beneficial owner of more than five percent of MEHC's common stock.

Title of Class

  Name and Address
of Beneficial Owner

  Amount and Nature of
Beneficial Ownership

  Percent of Class
 
Common Stock, no par value   The Mission Group
18101 Von Karman Avenue,
Suite 1700
Irvine, California 92612
  1,000 shares held directly and with exclusive voting and investment power   100 %

        For information concerning the number of equity securities of Edison International beneficially owned by all directors and executive officers of EME and Edison International, individually and as a group, see Item 12 of EME's Form 10-K for the year ended December 31, 2002 and the table entitled "Stock Ownership of Directors and Executive Officers" of Edison International's Proxy Statement relating to its 2003 Annual Meeting of Shareholders, respectively, which are incorporated by reference.


ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS

        Effective August 1, 2002, Edison International entered into a consulting agreement with Mr. Heller. Pursuant to the agreement, Mr. Heller agreed to provide consulting services in connection with Edison International's business affairs with which he became familiar while employed by Edison International or any of its affiliates. For such services, Edison International paid a retainer of $100,000 in 2002 and agreed to pay $200 per hour for up to 40 hours monthly for the first six months of the contract, and for up to 20 hours monthly for the second six months. No additional amounts were paid for hourly services in 2002.

Other Management Transactions

        In July 1999, EME made an interest-free loan to Georgia R. Nelson, who at that time was senior vice president of EME and president of Midwest Generation in the amount of $179,800 in exchange for a note executed by Ms. Nelson and payable to EME 365 days following the conclusion of her assignment in Chicago, Illinois.


ITEM 14. CONTROLS AND PROCEDURES

        Under the Sarbanes-Oxley Act of 2002 and implementing rules and regulations adopted by the Securities and Exchange Commission (SEC), MEHC must maintain disclosure controls and procedures. The term "disclosure controls and procedures" is defined in the SEC's regulations to mean, as applied to MEHC, controls and other procedures that are designed to ensure that information required to be disclosed by MEHC in reports filed with the SEC is recorded, processed, summarized, and reported within the time frames specified in the SEC's rules and forms. Disclosure controls and procedures include, without limitation, controls and procedures designed to ensure that information required to be disclosed by MEHC in its SEC reports is accumulated and communicated to MEHC's management, including its Chief Executive Officer and its Chief Financial Officer, as appropriate to allow timely decisions regarding disclosure. The SEC's regulations also require MEHC to carry out evaluations, under the supervision and with the participation of MEHC's management, including its Chief Executive Officer and its Chief Financial Officer, of the effectiveness of the design and operation of MEHC's disclosure controls and procedures. These evaluations must be carried out within the 90-day period prior to the filing date of certain reports, including this annual report on Form 10-K.

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        The Chief Executive Officer and the Chief Financial Officer of MEHC have evaluated the effectiveness of the design and operation of MEHC's disclosure controls and procedures as of March 20, 2003. They have concluded that those disclosure controls and procedures, as of the evaluation date, were effective in ensuring that information required to be disclosed by MEHC in its reports filed with the SEC was (1) accumulated and communicated to MEHC's management, as appropriate to allow timely decisions regarding disclosure, and (2) recorded, processed, summarized, and reported within the time frames specified in the SEC's rules and forms.

        The Chief Executive Officer and the Chief Financial Officer of MEHC also have concluded that there were no significant changes in MEHC's internal controls or in other factors that could significantly affect those controls subsequent to the date of their evaluation, including any corrective actions with regard to significant deficiencies and material weaknesses.

198




PART IV

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

        (a)  (1) List of Financial Statements

        See Index to Consolidated Financial Statements at Item 8 of this report.

        The following items are filed as a part of this report pursuant to Item 14(d) of Form 10-K:

 
  Page
Investment in Unconsolidated Affiliates Financial Statements:    
  California Power Group Combined Financial Statements as of December 31, 2002, 2001 and 2000   212
  Watson Cogeneration Company Financial Statements as of December 31, 2002, 2001 and 2000   229
  CPC Cogeneration LLC Financial Statements as of December 31, 2002, 2001 and 2000   239
  Four Star Oil & Gas Company Consolidated Financial Statements as of December 31, 2002, 2001 and 2000   246
  Midway-Sunset Cogeneration Company Financial Statements as of December 31, 2002, 2001 and 2000   262
  March Point Cogeneration Company Financial Statements as of December 31, 2002, 2001 and 2000   276
  EcoEléctrica Holdings, Ltd. and Subsidiaries Consolidated Financial Statements as of December 31, 2002, 2001 and 2000   288
  Gordonsville Energy, L.P. Financial Statements as of December 31, 2002, 2001 and 2000   309
  Brooklyn Navy Yard Cogeneration Partners, L.P. Financial Statements as of December 31, 2002, 2001 and 2000   322
  PT Paiton Energy Financial Statements as of December 31, 2002, 2001 and 2000   338
Schedule I—Condensed Financial Information of Parent   369
Schedule II—Valuation and Qualifying Accounts   372

        All other schedules have been omitted since the required information is not present in amounts sufficient to require submission of the schedule, or because the required information is included in the consolidated financial statements or notes thereto.

        The registrant filed the following reports on Form 8-K during the quarter ended December 31, 2002.

Date of Report

  Date Filed
  Item(s) Reported
October 1, 2002   October 3, 2002   5
November 19, 2002   November 27, 2002   5

199



Exhibit No.


 

Description

2.1   Agreement for the sale and purchase of shares in First Hydro Limited, dated December 21, 1995, between PSB Holding Limited and First Hydro Finance Plc, incorporated by reference to Exhibit 2.1 to Edison Mission Energy's Form 8-K dated December 21, 1995.

2.2

 

Transaction Implementation Agreement, dated March 29, 1997, between The State Electricity Commission of Victoria, Edison Mission Energy Australia Limited, Loy Yang B Power Station Pty Ltd, Loy Yang Power Limited, The Honorable Alan Robert Stockdale, Leanne Power Pty Ltd and Edison Mission Energy, incorporated by reference to Exhibit 2.2 to Edison Mission Energy's Form 8-K dated May 22, 1997.

2.3

 

Stock Purchase and Assignment Agreement, dated December 23, 1998, between KES Puerto Rico, L.P., KENETECH Energy Systems, Inc., KES Bermuda, Inc. and Edison Mission Energy del Caribe for the (i) sale and purchase of KES Puerto Rico, L.P.'s shares in EcoEléctrica Holdings Ltd.; (ii) assignment of KENETECH Energy Systems' rights and interests in that certain Project Note from the Partnership; and (iii) assignment of KES Bermuda, Inc.'s rights and interests in that certain Administrative Services Agreement dated October 31 1997, incorporated by reference to Exhibit 2.3 to Edison Mission Energy's Form 10-K for the year ended December 31, 1998.

2.4

 

Asset Purchase Agreement, dated August 1, 1998, between Pennsylvania Electric Company, NGE Generation, Inc., New York State Electric & Gas Corporation and Mission Energy Westside, Inc., incorporated by reference to Exhibit 2.4 to Edison Mission Energy's Form 10-K for the year ended December 31, 1998.

2.5

 

Asset Sale Agreement, dated March 22, 1999, between Commonwealth Edison Company and Edison Mission Energy as to the Fossil Generating Assets, incorporated by reference to Exhibit 2.5 to Edison Mission Energy's Form 10-K for the year ended December 31, 1998.

2.6

 

Agreement for the Sale and Purchase of Shares in Contact Energy Limited, dated March 10, 1999, between Her Majesty the Queen in Right of New Zealand, Edison Mission Energy Taupo Limited and Edison Mission Energy, incorporated by reference to Exhibit 2.6 to the Edison Mission Energy's Form 10-Q for the quarter ended March 31, 1999.

2.9

 

Purchase and Sale Agreement, dated May 10, 2000, between Edison Mission Energy, P & L Coal Holdings Corporation and Gold Fields Mining Corporation, incorporated by reference to Exhibit 2.9 to Edison Mission Energy's 10-Q for the quarter ended September 30, 2000.

2.10

 

Asset Purchase Agreement dated 3 March 2000 between MEC International B.V. and UPC International Partnership CV II, incorporated by reference to Exhibit 10.80 to Edison Mission Energy's Form 10-Q for the quarter ended March 31, 2000.

2.11

 

Stock Purchase Agreement, dated November 17, 2000 between Mission Del Sol, LLC and Texaco Inc., incorporated by reference to Exhibit 2.11 to Edison Mission Energy's Form 10-K for the year ended December 31, 2000.

2.12

 

Agreement relating to the sale and purchase of the business carried on at Fiddler's Ferry Power Station, Warrington, Cheshire, dated October 6, 2001, among Edison First Power Limited, AEP Energy Services UK Generation Limited, AEPR Global Holland Holding BV, and American Electric Power Company, Inc., incorporated by reference to Exhibit 2.12 to Edison Mission Energy's Form 8-K dated December 21, 2001.

 

 

 

200



2.13

 

Agreement relating to the sale and purchase of the business carried on at Ferrybridge "C" Power Station, Knottingley, West Yorkshire, dated October 6, 2001, among Edison First Power Limited, AEP Energy Services UK Generation Limited, AEPR Global Holland Holding BV, and American Electric Power Company, Inc., incorporated by reference to Exhibit 2.13 to Edison Mission Energy's Form 8-K dated December 21, 2001.

3.1

 

Amended and Restated Certificate of Incorporation, as amended, of Mission Energy Holding Company, incorporated by reference to Exhibit 3.1 to Mission Energy Holding Company's Registration Statement on Form S-4 to the Securities and Exchange Commission on August 29, 2001.

3.2

 

By-laws of Mission Energy Holding Company, incorporated by reference to Exhibit 3.2 to Mission Energy Holding Company's Registration Statement on Form S-4 to the Securities and Exchange Commission on August 29, 2001.

3.3

 

Certificate of Incorporation of Edison Mission Energy dated August 14, 2001, incorporated by reference to Exhibit 3.1 to Edison Mission Energy's Form 8-K dated October 26, 2001.

3.4

 

By-Laws of Edison Mission Energy, dated August 15, 2001, incorporated by reference to Exhibit 3.2 to Edison Mission Energy's Form 8-K dated October 26, 2001.

4.1

 

Indenture, dated as of July 2, 2001, by and between Mission Energy Holding Company and Wilmington Trust Company with respect to $900 million aggregate principal amount of 13.50% Senior Secured Notes due 2008, incorporated by reference to Exhibit 4.1 to Mission Energy Holding Company's Registration Statement on Form S-4 to the Securities and Exchange Commission on August 29, 2001.

4.2

 

Registration Rights Agreement, dated as of July 2, 2001, by and between Mission Energy Holding Company and Goldman, Sachs & Co., incorporated by reference to Exhibit 4.2 to Mission Energy Holding Company's Registration Statement on Form S-4 to the Securities and Exchange Commission on August 29, 2001.

4.3

 

Indenture Escrow and Security Agreement, dated as of July 2, 2001, by and among Mission Energy Holding Company, Wilmington Trust Company, as Trustee, and Wilmington Trust Company, as Indenture Escrow Agent, incorporated by reference to Exhibit 4.3 to Mission Energy Holding Company's Registration Statement on Form S-4 to the Securities and Exchange Commission on August 29, 2001.

4.4

 

Amended and Restated Credit Agreement, dated as of July 3, 2001, by and among Mission Energy Holding Company, the lenders party thereto from time to time, Goldman Sachs Credit Partners L.P., as sole Lead Arranger, as Administrative Agent and as Term Loan Collateral Agent, and Lehman Commercial Paper Inc., as Syndication Agent, incorporated by reference to Exhibit 4.4 to Mission Energy Holding Company's Registration Statement on Form S-4 to the Securities and Exchange Commission on August 29, 2001.

4.5

 

Loan Escrow and Security Agreement, dated as of July 2, 2001, by and among Mission Energy Holding Company, Goldman, Sachs & Co., as Collateral Agent, Goldman Sachs Credit Partners L.P., as Administrative Agent, and Wilmington Trust Company, as Loan Escrow Agent, incorporated by reference to Exhibit 4.5 to Mission Energy Holding Company's Registration Statement on Form S-4 to the Securities and Exchange Commission on August 29, 2001.

 

 

 

201



4.6

 

Pledge and Security Agreement, dated as of July 2, 2001, by and among Mission Energy Holding Company, Goldman Sachs Credit Partners L.P., as Administrative Agent, and Wilmington Trust Company, as Trustee and Joint Collateral Agent, incorporated by reference to Exhibit 4.6 to Mission Energy Holding Company's Registration Statement on Form S-4 to the Securities and Exchange Commission on August 29, 2001.

4.7

 

Indenture, dated as of August 10, 2001, among Edison Mission Energy and The Bank of New York as Trustee, incorporated by reference to Exhibit 4.1 to Edison Mission Energy's Registration Statement on Form S-4 to the Securities and Exchange Commission on August 29, 2001.

4.7.1

 

Form of 10% Senior Note due 2008 (included in Exhibit 4.1) to Edison Mission Energy's Registration Statement on Form S-4 to the Securities and Exchange Commission on August 29, 2001).

4.8

 

Registration Rights Agreement, dated as of August 7, 2001, among Edison Mission Energy, Credit Suisse First Boston Corporation, BMO Nesbitt Burns Corp., Salomon Smith Barney Inc., SG Cowen Securities Corporation, TD Securities (USA) Inc. and Westdeutsche Landesbank Girozentrale (Düsseldorf), incorporated by reference to Exhibit 4.2 to Edison Mission Energy's Registration Statement on Form S-4 to the Securities and Exchange Commission on August 29, 2001.

4.9

 

Indenture, dated as of April 5, 2001, among Edison Mission Energy and United States Trust Company of New York as Trustee, incorporated by reference to Exhibit 4.20 to Edison Mission Energy's and Midwest Generation LLC's Registration Statement on Form S-4 to the Securities and Exchange Commission on April 20, 2001.

4.9.1

 

Form of 9.875% Senior Note due 2011 (included in Exhibit 4.1 to Edison Mission Energy's Registration Statement on Form S-4 to the Securities and Exchange Commission on April 24, 2001).

4.10

 

Registration Rights Agreement, dated as of April 2, 2001, among Edison Mission Energy and Credit Suisse First Boston Corporation and Westdeutsche Landesbank Girozentrale (Düsseldorf) as representatives of the Initial Purchasers, incorporated by reference to Exhibit 4.2 to Edison Mission Energy's Registration Statement on Form S-4 to the Securities and Exchange Commission on April 24, 2001.

4.11

 

Guarantee, dated as of August 17, 2000, made by Edison Mission Energy, as Guarantor in favor of Powerton Trust I, as Owner Lessor, incorporated by reference to Exhibit 4.9 to Edison Mission Energy's and Midwest Generation LLC's Registration Statement on Form S-4 to the Securities and Exchange Commission on April 20, 2001.

4.11.1

 

Schedule identifying substantially identical agreement to Guarantee constituting Exhibit 4.11 hereto, incorporated by reference to Exhibit 4.9.1 to Edison Mission Energy's and Midwest Generation LLC's Registration Statement on Form S-4 to the Securities and Exchange Commission on April 20, 2001.

4.12

 

Guarantee, dated as of August 17, 2000, made by Edison Mission Energy, as Guarantor in favor of Joliet Trust I, as Owner Lessor, incorporated by reference to Exhibit 4.10 to Edison Mission Energy's and Midwest Generation LLC's Registration Statement on Form S-4 to the Securities and Exchange Commission on April 20, 2001.

4.12.1

 

Schedule identifying substantially identical agreement to Guarantee constituting Exhibit 4.12 hereto, incorporated by reference to Exhibit 4.10.1 to Edison Mission Energy's and Midwest Generation LLC's Registration Statement on Form S-4 to the Securities and Exchange Commission on April 20, 2001.

 

 

 

202



4.13

 

Registration Rights Agreement, dated as of August 17, 2000, among Edison Mission Energy, Midwest Generation, LLC and Credit Suisse First Boston Corporation and Lehman Brothers Inc., as representatives of the Initial Purchasers, incorporated by reference to Exhibit 4.11 to Edison Mission Energy's and Midwest Generation LLC's Registration Statement on Form S-4 to the Securities and Exchange Commission on April 20, 2001.

4.14

 

Participation Agreement (T1), dated as of August 17, 2000, by and among, Midwest Generation, LLC, Powerton Trust I, as the Owner Lessor, Wilmington Trust Company, as the Owner Trustee, Powerton Generation I, LLC, as the Owner Participant, Edison Mission Energy, United States Trust Company of New York, as the Lease Indenture Trustee, and United States Trust Company of New York, as the Pass Through Trustees, incorporated by reference to Edison Mission Energy's and Midwest Generation LLC's Registration Statement on Form S-4 to the Securities and Exchange Commission on April 20, 2001.

4.14.1

 

Schedule identifying substantially identical agreement to Participation Agreement constituting Exhibit 4.14 hereto, incorporated by reference to Exhibit 4.12.1 to Edison Mission Energy's and Midwest Generation LLC's Registration Statement on Form S-4 to the Securities and Exchange Commission on April 20, 2001.

4.15

 

Participation Agreement (T1), dated as of August 17, 2000, by and among, Midwest Generation, LLC, Joliet Trust I, as the Owner Lessor, Wilmington Trust Company, as the Owner Trustee, Joliet Generation I, LLC, as the Owner Participant, Edison Mission Energy, United States Trust Company of New York, as the Lease Indenture Trustee and United States Trust Company of New York, as the Pass Through Trustees, incorporated by reference to Exhibit 4.13 to Edison Mission Energy's and Midwest Generation LLC's Registration Statement on Form S-4 to the Securities and Exchange Commission on April 20, 2001.

4.15.1

 

Schedule identifying substantially identical agreement to Participation Agreement constituting Exhibit 4.15 hereto, incorporated by reference to Exhibit 4.13.1 to Edison Mission Energy's and Midwest Generation LLC's Registration Statement on Form S-4 to the Securities and Exchange Commission on April 20, 2001.

4.16

 

Copy of the Global Debenture representing Edison Mission Energy's 97/8% Junior Subordinated Deferrable Interest Debentures, Series A, Due 2024, incorporated by reference to Exhibit 4.1 to Edison Mission Energy's Form 10-K for the year ended December 31, 1994.

4.17

 

Conformed copy of the Indenture, dated as of November 30, 1994, between Edison Mission Energy and The First National Bank of Chicago, as Trustee, incorporated by reference to Exhibit 4.2 to Edison Mission Energy's Form 10-K for the year ended December 31, 1994.

4.17.1

 

First Supplemental Indenture, dated as of November 30, 1994, to Indenture dated as of November 30, 1994 between Edison Mission Energy and The First National Bank of Chicago, as Trustee, incorporated by reference to Exhibit 4.2.1 to Edison Mission Energy's Form 10-K for the year ended December 31, 1994.

4.17.2

 

Second Supplemental Indenture, dated as of August 8, 1995, to Indenture dated as of November 30, 1994 between Edison Mission Energy and The First National Bank of Chicago, as Trustee, incorporated by reference to Exhibit 4.11.2 to Edison Mission Energy's Registration Statement on Form S-4 to the Securities and Exchange Commission on August 29, 2001.

 

 

 

203



4.18

 

Indenture, dated as of June 28, 1999, between Edison Mission Energy and The Bank of New York, as Trustee, incorporated by reference to Exhibit 4.1 to Edison Mission Energy's Registration Statement on Form S-4 to the Securities and Exchange Commission on February 18, 2000.

4.18.1

 

First Supplemental Indenture, dated as of June 28, 1999, to Indenture dated as of June 28, 1999, between Edison Mission Energy and The Bank of New York, as Trustee, incorporated by reference to Exhibit 4.2 to Edison Mission Energy's Registration Statement on Form S-4 to the Securities and Exchange Commission on February 18, 2000.

4.20

 

Promissory Note ($499,450,800), dated as of August 24, 2000, by Edison Mission Energy in favor of Midwest Generation, LLC, incorporated by reference to Exhibit 4.5 to Edison Mission Energy's Form 10-K for the year ended December 31, 2000.

4.20.1

 

Schedule identifying substantially identical agreements to Promissory Note constituting Exhibit 4.20 hereto, incorporated by reference to Exhibit 4.14 to Edison Mission Energy's Form 10-K for the year ended December 31, 2000.

4.22

 

Participation Agreement, dated as of December 7, 2001, among EME Homer City Generation L.P., Homer City OL1 LLC, as Facility Lessor and Ground Lessee, Wells Fargo Bank Northwest National Association, General Electric Capital Corporation, The Bank of New York as the Security Agent, The Bank of New York as Lease Indenture Trustee, Homer City Funding LLC and The Bank of New York as Bondholder Trustee, incorporated by reference to Exhibit 4.4 to the EME Homer City Generation L.P. Form 10-K for the year ended December 31, 2001.

4.22.1

 

Schedule identifying substantially identical agreements to Participation Agreement constituting Exhibit 4.22 hereto, incorporated by reference to Exhibit 4.4.1 to the EME Homer City Generation L.P. Form 10-K for the year ended December 31, 2001.

4.23

 

Open-End Mortgage, Security Agreement and Assignment of Rents, dated as of December 7, 2001, among Homer City OLI LLC, as the Owner Lessor to The Bank of New York, as Security Agent and Mortgagee, incorporated by reference to Exhibit 4.9 to the EME Homer City Generation L.P. Form 10-K for the year ended December 31, 2001.

10.1

 

Registration Rights Agreement, dated as of June 23, 1999, between Edison Mission Energy and the Initial Purchasers specified therein, incorporated by reference to Exhibit 10.1 to Edison Mission Energy's Registration Statement on Form S-4 to the Securities and Exchange Commission on February 18, 2000.

10.8

 

Power Purchase Contract between Southern California Edison Company and Arco Petroleum Products Company (Watson Refinery), incorporated by reference to Exhibit 10.8 to Edison Mission Energy's Form 10.

10.9

 

Power Supply Agreement between State Electricity Commission of Victoria, Loy Yang B Power Station Pty. Ltd. and the Company Australia Pty. Ltd., as managing partner of the Latrobe Power Partnership, dated December 31, 1992, incorporated by reference to Exhibit 10.9 to Edison Mission Energy's Form 10.

10.10

 

Power Purchase Agreement between P.T. Paiton Energy Company as Seller and Perusahaan Umum Listrik Negara as Buyer, dated February 12, 1994, incorporated by reference to Exhibit 10.10 to Edison Mission Energy's Form 10.

10.10.1

 

Amendment to Power Purchase Agreement between P.T. Paiton Energy (formerly known as P.T. Paiton Energy Company) as Seller and P.T. PLN (Persero) (as successor to Perusahaan Umum Listrik Negara) as Buyer, dated as of June 28, 2002, incorporated by reference to Exhibit 10.10.1 to Edison Mission Energy's Form 10-Q for the quarter ended June 30, 2002.

 

 

 

204



10.11

 

Amended and Restated Power Purchase Contract between Southern California Energy Company and Midway-Sunset Cogeneration Company, dated May 5, 1988, incorporated by reference to Exhibit 10.11 to Edison Mission Energy's Form 10.

10.12

 

Parallel Generation Agreement between Kern River Cogeneration Company and Southern California Energy Company, dated January 6, 1984, incorporated by reference to Exhibit 10.12 to Edison Mission Energy's Form 10.

10.13

 

Parallel Generation Agreement between Kern River Cogeneration (Sycamore Project) Company and Southern California Energy Company, dated December 18, 1984, incorporated by reference to Exhibit 10.13 to Edison Mission Energy's Form 10.

10.16

 

Amended and Restated Ground Lease Agreement between Texaco Refining and Marketing Inc. and March Point Cogeneration Company, dated August 21, 1992, incorporated by reference to Exhibit 10.16 to Edison Mission Energy's Form 10.

10.16.1

 

Amendment No. 1 to Amended and Restated Ground Lease Agreement between Texaco Refining and Marketing Inc. and March Point Cogeneration Company, dated August 21, 1992, incorporated by reference to Exhibit 10.16 to Edison Mission Energy's Form 10.

10.17

 

Memorandum of Agreement between Atlantic Richfield Company and Products Cogeneration Company, dated September 17, 1987, incorporated by reference to Exhibit 10.17 to Edison Mission Energy's Form 10.

10.18

 

Memorandum of Ground Lease between Texaco Producing Inc. and Sycamore Cogeneration Company, dated January 19, 1987, incorporated by reference to Exhibit 10.18 to Edison Mission Energy's Form 10.

10.19

 

Amended and Restated Memorandum of Ground Lease between Getty Oil Company and Kern River Cogeneration Company, dated November 14, 1984, incorporated by reference to Exhibit 10.19 to Edison Mission Energy's Form 10.

10.20

 

Memorandum of Lease between Sun Operating Limited Partnership and Midway-Sunset Cogeneration Company, incorporated by reference to Exhibit 10.20 to Edison Mission Energy's Form 10.

10.21

 

Executive Supplemental Benefit Program, incorporated by reference to Exhibits to Forms 10-K filed by SCEcorp (File No. 1-2313).

10.22

 

1981 Deferred Compensation Agreement, incorporated by reference to Exhibits to Forms 10-K filed by SCEcorp (File No. 1-2313).

10.23

 

1985 Deferred Compensation Agreement for Executives, incorporated by reference to Exhibits to Forms 10-K filed by SCEcorp (File No. 1-2313).

10.24

 

1987 Deferred Compensation Plan for Executives, incorporated by reference to Exhibits to Forms 10-K filed by SCEcorp (File No. 1-2313).

10.25

 

1988 Deferred Compensation Plan for Executives, incorporated by reference to Exhibits to Forms 10-K filed by SCEcorp (File No. 1-2313).

10.26

 

1989 Deferred Compensation Plan for Executives, incorporated by reference to Exhibits to Forms 10-K filed by SCEcorp (File No. 1-9936).

10.27

 

1990 Deferred Compensation Plan for Executives, incorporated by reference to Exhibits to Forms 10-K filed by SCEcorp (File No. 1-9936).

10.28

 

Annual Deferred Compensation Plan for Executives, incorporated by reference to Exhibits to Forms 10-K filed by SCEcorp (File No. 1-9936).

 

 

 

205



10.29

 

Executive Retirement Plan for Executives, incorporated by reference to Exhibits to Forms 10-K filed by SCEcorp (File No. 1-2313).

10.31

 

Estate and Financial Planning Program for Executive Officers, incorporated by reference to Exhibits to Forms 10-K filed by SCEcorp (File No 1-9936).

10.32

 

Letter Agreement with Edward R. Muller, incorporated by reference to Exhibit 10.32 to Edison Mission Energy's Form 10.

10.34

 

Conformed copy of the Guarantee Agreement dated as of November 30, 1994, incorporated by reference to Exhibit 10.34 to Edison Mission Energy's Form 10.

10.35

 

Indenture of Lease between Brooklyn Navy Yard Development Corporation and Cogeneration Technologies, Inc., dated as of December 18, 1989, incorporated by reference to Exhibit 10.35 to Edison Mission Energy's Form 10-K for the year ended December 31, 1994.

10.35.1

 

First Amendment to Indenture of Lease between Brooklyn Navy Yard Development Corporation and Cogeneration Technologies, Inc., dated November 1, 1991, incorporated by reference to Exhibit 10.35.1 to Edison Mission Energy's Form 10-K for the year ended December 31, 1994.

10.35.2

 

Second Amendment to Indenture of Lease between Brooklyn Navy Yard Development Corporation and Cogeneration Technologies, Inc., dated June 3, 1994, incorporated by reference to Exhibit 10.35.2 to Edison Mission Energy's Form 10-K for the year ended December 31, 1994.

10.35.3

 

Third Amendment to Indenture of Lease between Brooklyn Navy Yard Development Corporation and Cogeneration Technologies, Inc., dated December 12, 1994, incorporated by reference to Exhibit 10.35.3 to Edison Mission Energy's Form 10-K for the year ended December 31, 1994.

10.37

 

Amended and Restated Limited Partnership Agreement of Mission Capital, L.P., dated as of November 30, 1994, incorporated by reference to Exhibit 10.37 to Edison Mission Energy's Form 10-K for the year ended December 31, 1994.

10.38

 

Action of General Partner of Mission Capital, L.P. creating the 97/8% Cumulative Monthly Income Preferred Securities, Series A, dated as of November 30, 1994, incorporated by reference to Exhibit 10.38 to Edison Mission Energy's Form 10-K for the year ended December 31, 1994.

10.39

 

Action of General Partner of Mission Capital, L.P., creating the 81/2% Cumulative Monthly Income Preferred Securities, Series B, dated as of August 8, 1995, incorporated by reference to Exhibit 10.39 to Edison Mission Energy's Form 10-Q for the quarter ended June 30, 1995.

10.40

 

Power Purchase Contract between ISAB Energy, S.r.l. as Seller and Enel, S.p.A. as Buyer, dated June 9, 1995, incorporated by reference to Exhibit 10.40 to Edison Mission Energy's Form 10-Q for the quarter ended June 30, 1995.

10.41

 

£400 million Barclays Bank Plc Credit Agreement, dated December 18, 1995, incorporated by reference to Exhibit 10.41 to Edison Mission Energy's Form 8-K, dated December 21, 1995.

10.45

 

Power Purchase Agreement between National Power Corporation and San Pascual Cogeneration Company International B.V., dated September 10, 1997, incorporated by reference to Exhibit 10.45 to Edison Mission Energy's Form 10-K for the year ended December 31, 1997.

 

 

 

206



10.46

 

Power Purchase Agreement between Gulf Power Generation Co., LTD., and Electricity Generating Authority of Thailand, dated December 22, 1997, incorporated by reference to Exhibit 10.46 to Edison Mission Energy's Form 10-K for the year ended December 31, 1997.

10.49

 

Equity Support Guarantee by Edison Mission Energy, dated December 23, 1998, in favor of ABN AMRO Bank N.V., and the Chase Manhattan Bank to guarantee certain equity funding obligations of EcoEléctrica Ltd. and EcoEléctrica Holdings Ltd. pursuant to EcoEléctrica Ltd.'s Credit Agreement dated as of October 31, 1997, incorporated by reference to Exhibit 10.49 to Edison Mission Energy's Form 10-K for the year ended December 31, 1998.

10.50

 

Master Guarantee and Support Instrument by Edison Mission Energy, dated December 23, 1998, in favor of ABN AMRO Bank N.V., and the Chase Manhattan Bank to guarantee the availability of funds to purchase fuel for the EcoEléctrica project pursuant to EcoEléctrica Ltd.'s Credit Agreement dated as of October 31, 1997 and Intercreditor Agreement dated as of October 31, 1997, incorporated by reference to Exhibit 10.50 to Edison Mission Energy's Form 10-K for the year ended December 31, 1998.

10.51

 

Guarantee Assumption Agreement from Edison Mission Energy, dated December 23, 1998, under which Edison Mission Energy assumed all of the obligations of KENETECH Energy Systems, Inc. to Union Carbide Caribe Inc., under the certain Guaranty dated November 25, 1997, incorporated by reference to Exhibit 10.51 to Edison Mission Energy's Form 10-K for the year ended December 31, 1998.

10.52

 

Transition Power Purchase Agreement, dated August 1, 1998, between New York State Electric & Gas Corporation and Mission Energy Westside, Inc, incorporated by reference to Exhibit 10.52 to Edison Mission Energy's Form 10-K for the year ended December 31, 1998.

10.54

 

Guarantee, dated August 1, 1998, between Edison Mission Energy, Pennsylvania Electric Company, NGE Generation, Inc. and New York State Electric & Gas Corporation, incorporated by reference to Exhibit 10.54 to Edison Mission Energy's Form 10-K for the year ended December 31, 1998.

10.58.2

 

Amended and Restated Security Deposit Agreement, dated as of December 7, 2001, among EME Homer City Generation L.P. and The Bank of New York as Collateral Agent, incorporated by reference to Exhibit 10.18.2 to the EME Homer City Generation L.P. Form 10-K for the year ended December 31, 2001.

10.60.4

 

Intercompany Loan Subordination Agreement, dated March 18, 1999, among Edison Mission Holdings Co., Edison Mission Finance Co., Homer City Property Holdings, Inc., Chestnut Ridge Energy Co., Mission Energy Westside, Inc., EME Homer City Generation L.P. and United States Trust Company of New York, incorporated by reference to Exhibit 10.60.3 to Amendment No. 2 of Edison Mission Holdings Co.'s Registration Statement on Form S-4 to the Securities and Exchange Commission on February 29, 2000.

10.64

 

Coal and Capex Facility Agreement, dated July 16, 1999 between EME Finance UK Limited, Barclay's Capital and Credit Suisse First Boston, The Financial Institutions named as Banks, and Barclays Bank PLC as Facility Agent, incorporated by reference to Exhibit 10.64 to Edison Mission Energy's Form 10-Q for the quarter ended September 30, 1999.

 

 

 

207



10.64.1

 

Amendment One to Coal and Capex Facility Agreement, dated as of May 29, 2001, by and among Edison Mission Energy Finance UK Limited and Barclays Bank PLC, as Facility Agent, incorporated by reference to Exhibit 10.64.1 to Edison Mission Energy's Form 10-Q for the quarter ended June 30, 2001.

10.65

 

Guarantee by Edison Mission Energy dated July 16, 1999 supporting the Coal and Capex Facility Agreement (Facility Agreement) issued by Barclays Bank PLC to secure EME Finance UK Limited obligations pursuant to the Facility Agreement, incorporated by reference to Exhibit 10.65 to Edison Mission Energy's Form 10-Q for the quarter ended September 30, 1999.

10.65.1

 

Amendment One to Guarantee by Edison Mission Energy supporting the Facility Agreement, dated as of August 17, 2000, incorporated by reference to Exhibit 10.65.1 to Edison Mission Energy's Form 10-K for the year ended December 31, 2000.

10.65.2

 

Amendment Two to Guarantee by Edison Mission Energy Supporting the Facility Agreement, dated as of May 29, 2001, incorporated by reference to Exhibit 10.65.2 to Edison Mission Energy's Form 10-Q for the quarter ended June 30, 2001.

10.75

 

Exchange and Registration Rights Agreement, dated as of May 27, 1999, by and among the Initial Purchasers named therein, the Guarantors named therein and Edison Mission Holdings Co., incorporated by reference to Exhibit 10.1 to Edison Mission Holdings Co.'s Registration Statement on Form S-4 to the Securities and Exchange Commission on December 3, 1999.

10.76

 

Agreement among Edward R. Muller, Edison International and Edison Mission Energy concerning the terms of Mr. Muller's employment separation, incorporated by reference to Exhibit 10.76 to Edison Mission Energy's Form 10-Q for the quarter ended March 31, 2000.

10.77

 

Agreement By and Between S. Linn Williams and Edison Mission Energy dated February 5, 2000, incorporated by reference to Exhibit 10.77 to Edison Mission Energy's Form 10-Q for the quarter ended March 31, 2000.

10.78

 

Form of Agreement for 2000 Employee Awards under the Equity Compensation Plan, incorporated by reference to Exhibit 10.78 to Edison Mission Energy's Form 10-Q for the quarter ended March 31, 2000.

10.79

 

Resolution regarding the computation of disability and survivor benefits prior to age 55 for Alan J. Fohrer, incorporated by reference to Exhibit 10.79 to Edison Mission Energy's Form 10-Q for the quarter ended March 31, 2000.

10.81

 

Edison International 2000 Equity Plan, incorporated by reference to Exhibit 10.1 to Edison International's Form 10-Q for the quarter ended June 30, 2000 (File No. 1-9936).

10.82

 

Form of Agreement for 2000 Employee Awards under the 2000 Equity Plan, incorporated by reference to Exhibit 10.2 to Edison International's Form 10-Q for the quarter ended June 30, 2000 (File No. 1-9936).

10.83

 

Amendment No. 1 to the Edison International Equity Compensation Plan (as restated January 1, 1998), incorporated by reference to Exhibit 10.4 to Edison International's Form 10-Q for the quarter ended June 30, 2000 (File No. 1-9936).

10.86

 

Power Purchase Agreement (Crawford, Fisk, Waukegan, Will County, Joliet and Powerton Generating Stations), dated as of December 15, 1999, between Commonwealth Edison Company and Midwest Generation, LLC, incorporated by reference to Exhibit 10.86 to Edison Mission Energy's Form 10-K for the year ended December 31, 2000.

 

 

 

208



10.87

 

Power Purchase Agreement (Collins Generating Station), dated as of December 15, 1999, between Commonwealth Edison Company and Midwest Generation, LLC, incorporated by reference to Exhibit 10.87 to Edison Mission Energy's Form 10-K for the year ended December 31, 2000.

10.87.1

 

Amendment No. 1 to the Power Purchase Agreement, dated July 12, 2000, between Commonwealth Edison Company and Midwest Generation, LLC, incorporated by reference to Exhibit 10.87.1 to Edison Mission Energy's Form 10-K for the year ended December 31, 2000.

10.87.2

 

Amended and Restated Power Purchase Agreement (Collins Generating Station), dated as of September 13, 2000, between Commonwealth Edison Company and Midwest Generation, LLC, incorporated by reference to Exhibit 10.87.2 to Edison Mission Energy's Form 10-K for the year ended December 31, 2000.

10.88

 

Power Purchase Agreement (Crawford, Fisk, Waukegan, Calumet, Joliet, Bloom, Electric Junction, Sabrooke and Lombard Peaking Units), dated as of December 15, 1999, between Commonwealth Edison Company and Midwest Generation, LLC, incorporated by reference to Exhibit 10.88 to Edison Mission Energy's Form 10-K for the year ended December 31, 2000.

10.90

 

Reimbursement Agreement, dated as of August 17, 2000, between Edison Mission Energy and Midwest Generation, LLC, incorporated by reference to Exhibit 10.90 to Edison Mission Energy's Form 10-K for the year ended December 31, 2000.

10.92

 

Credit Agreement, dated as of September 13, 2001, among Edison Mission Energy, Certain Commercial Lending Institutions, Citicorp USA, Inc., as Administrative Agent, and Citibank, N.A. as Issuing Agent, incorporated by reference to Exhibit 10.92 to Amendment No. 1 of Edison Mission Energy's Registration Statement on Form S-4 to the Securities and Exchange Commission on September 27, 2001.

10.92.1

 

Amendment One to Credit Agreement, dated as of November 14, 2001, by and among Edison Mission Energy, Certain Commercial Lending Institutions and Citicorp USA, Inc., as Administrative Agent, incorporated by reference to Exhibit 10.92.1 to Edison Mission Energy's Form 10-Q for the quarter ended September 30, 2002.

10.92.2

 

Amendment Two to Credit Agreement, dated as of September 17, 2002, by and among Edison Mission Energy, Certain Commercial Lending Institutions and Citicorp USA, Inc., as Administrative Agent, incorporated by reference to Exhibit 10.92.2 to Edison Mission Energy's Form 10-Q for the quarter ended September 30, 2002.

10.93

 

Edison Mission Energy Exchange Offer Circular, dated as of July 3, 2000, incorporated by reference to Exhibit 10.93 to Edison Mission Energy's Form 10-K for the year ended December 31, 2001.

10.94

 

Edison Mission Energy Option Exchange Offer Summary of Deferred Compensation Alternatives, dated as of July 3, 2000, incorporated by reference to Exhibit 10.94 to Edison Mission Energy's Form 10-K for the year ended December 31, 2001

10.95

 

Executive Retirement Plan Amendment 2001-1, incorporated by reference to Exhibit 10.1 to Edison International's Form 10-Q for the quarter ended March 31, 2001 (File No. 1-9936).

10.96

 

Restatement of Terms of 2000 basic long-term incentive awards under the Equity Compensation Plan or the 2000 Equity Plan, incorporated by reference to Exhibit 10.2 to Edison International's Form 10-Q for the quarter ended March 31, 2001 (File No. 1-9936).

 

 

 

209



10.97

 

Terms of 2001 basic long-term incentive awards under the Equity Compensation Plan or the 2000 Equity Plan, incorporated by reference to Exhibit 10.3 to Edison International's Form 10-Q for the quarter ended March 31, 2001 (File No. 1-9936).

10.98

 

Terms of 2001 special long-term incentive awards under the Equity Compensation Plan or the 2000 Equity Plan, incorporated by reference to Exhibit 10.4 to Edison International's Form 10-Q for the quarter ended March 31, 2001 (File No. 1-9936).

10.99

 

Terms of 2001 retention incentives under the Equity Compensation Plan, incorporated by reference to Exhibit 10.5 to Edison International's Form 10-Q for the quarter ended March 31, 2001 (File No. 1-9936).

10.100

 

Executive Severance Plan as adopted effective January 1, 2001, incorporated by reference to Exhibit 10.34 to Edison International's Form 10-K for the year ended December 31, 2001 (File No. 1-9936).

10.101

 

Terms of 2002 stock option and performance share awards under the Equity Compensation Plan or the 2000 Equity Plan, incorporated by reference to Exhibit 10.1 to Edison International's Form 10-Q for the quarter ended March 31, 2002 (File No. 1-9936).

10.102

 

Executive Grantor Trust Agreement, incorporated by reference to Exhibit 10.12 to Edison International's Form 10-K for the year ended December 31, 1995 (File No. 1-9936).

10.102.1

 

Executive Grantor Trust Agreement Amendment 2002-1, effective May 14, 2002, incorporated by reference to Exhibit 10.3 to Edison International's Form 10-Q for the quarter ended June 30, 2002 (File No. 1-9936).

10.103

 

Director Grantor Trust Agreement, incorporated by reference to Exhibit 10.10 to Edison International's Form 10-K for the year ended December 31, 1995 (File No. 1-9936).

10.103.1

 

Director Grantor Trust Agreement Amendment 2002-1, effective May 14, 2002, incorporated by reference to Exhibit 10.4 to Edison International's Form 10-Q for the quarter ended June 30, 2002 (File No. 1-9936).

10.104

 

Separation Agreement by and between William J. Heller and Edison Mission Energy effective July 31, 2002, incorporated by reference to Exhibit 10.104 to Edison Mission Energy's Form 10-Q for the quarter ended September 30, 2002.

10.105

 

Consulting Agreement with William J. Heller, incorporated by reference to Exhibit 10.2 to Edison International's Form 10-Q for the quarter ended September 30, 2002 (File No. 1-9936).

10.106

 

Amended and Restated Tax-Allocation Agreement, dated September 10, 1996, among The Mission Group and its first-tier subsidiaries, incorporated by reference to Exhibit 10.106 to Mission Energy Holding Company's Form 10-A for the quarter ended September 30, 2002.

10.107

 

Administrative Agreement Re Tax-Allocation Payments, dated July 2, 2002, among Edison International and subsidiary parties, incorporated by reference to Exhibit 10.107 to Edison Mission Energy's Form 10-Q for the quarter ended September 30, 2002.

10.108

 

Performance and Retention Incentive Agreement between Thomas R. McDaniel and Edison Mission Energy, incorporated by reference to Exhibit 10.108 to Edison Mission Energy's Form 10-K for the year ended December 31, 2002.

18.1

 

Preferability Letter Regarding Change in Accounting Principle for Major Maintenance Costs, incorporated by reference to Exhibit 18.1 to Edison Mission Energy's Form 10-Q for the quarter ended March 31, 2000.

21

 

List of Subsidiaries of Mission Energy Holding Company.*

 

 

 

210



99.1

 

Homer City Facilities Funds Flow From Operations for the twelve months ended December 31, 2002, incorporated by reference to Exhibit 99.1 to Edison Mission Energy's Form 10-K for the year ended December 31, 2002.

99.2

 

Illinois Plants Funds Flow From Operations for the twelve months ended December 31, 2002, incorporated by reference to Exhibit 99.2 to Edison Mission Energy's Form 10-K for the year ended December 31, 2002.

99.3

 

Statement Pursuant to 18 U.S.C. Section 1350.*

*
Filed herewith.

(d)
Financial Statement Schedules

        The financial statements referred to in (a)(2) above represent the entities, or a combination of those entities, that are Investments in Unconsolidated Affiliates, which were 50% or less owned by EME and that met the requirements of Rule 3-09 of Regulation S-X. Financial statements with respect to ISAB Energy S.r.l. which meets the definition of a foreign business as defined in Rule 1-02(i) of Regulation S-X to be filed by amendment not later than six months after December 31, 2002 pursuant to Rule 3-09 of Regulation S-X.

211



REPORT OF INDEPENDENT ACCOUNTANTS

To the Board of Directors of
Edison Mission Energy and ChevronTexaco Corporation:

        In our opinion, the accompanying combined balance sheets and the related combined statements of income, cash flows and changes in equity present fairly, in all material respects, the combined financial position of Kern River Cogeneration Company, Sycamore Cogeneration Company, Coalinga Cogeneration Company, Mid-Set Cogeneration Company, Salinas River Cogeneration Company, Sargent Canyon Cogeneration Company, and Sunrise Power Company, LLC (together, the California Power Group) at December 31, 2002 and 2001, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2002 in conformity with accounting principles generally accepted in the United States of America. These financial statements are the responsibility of the California Power Group's management; our responsibility is to express an opinion on these financial statements based on our audits. We conducted our audits of these statements in accordance with auditing standards generally accepted in the United States of America, which require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, and evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.

        As discussed in Note 2 to the financial statements, on January 1, 2000, the California Power Group changed its method of accounting for major maintenance activities.

PricewaterhouseCoopers LLP

Los Angeles, California
February 24, 2003

212




CALIFORNIA POWER GROUP

COMBINED BALANCE SHEETS

(Amounts in thousands)

 
  As of December 31,
 
  2002
  2001
Assets
Current Assets            
  Cash and cash equivalents   $ 36,986   $ 76,123
  Trade receivables:            
  —Related party     59,200     244,078
  —Other     18,659     58,857
  Inventories     20,380     15,114
  Fair value of gas swaps     8,830    
  Prepaid and other current assets     658     1,032
   
 
      144,713     395,204
Property, plant and equipment, net     553,270     466,368
Fair value of gas swaps, net of current portion     6,465    
Other assets     1,047     1,282
   
 
    $ 705,495   $ 862,854
   
 
Liabilities and Equity
Current Liabilities:            
  Current portion of project financing loans payable   $ 9,900   $ 10,100
  Accounts payable:            
  —Related party     58,505     51,422
  —Trade and other     10,319     9,392
  Fair value of gas swaps         2,014
  Unearned revenue         20,284
   
 
      78,724     93,212
Project financing loans payable, net of current portion         9,900
Long-term liabilities     369     453
Fair value of gas swaps, net of current portion         2,861
   
 
      79,093     106,426
Commitments and Contingencies (Notes 7 and 8)            
Equity     626,402     756,428
   
 
    $ 705,495   $ 862,854
   
 

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

213



CALIFORNIA POWER GROUP

COMBINED STATEMENTS OF INCOME

(Amounts in thousands)

 
  Year ended December 31,
 
 
  2002
  2001
  2000
 
Operating Revenues                    
  Sales of energy   $ 441,321   $ 716,240   $ 498,397  
  Sales of steam     113,823     118,457     136,332  
   
 
 
 
      555,144     834,697     634,729  
   
 
 
 
Operating Expenses                    
  Fuel expense     245,011     456,878     399,681  
  Other operating expenses     71,118     44,901     28,815  
  Administrative and general expenses     11,817     11,184     8,946  
  Depreciation and amortization     22,884     20,226     17,360  
   
 
 
 
      350,830     533,189     454,802  
   
 
 
 
  Income from operations     204,314     301,508     179,927  
   
 
 
 
Other Income (Expense)                    
  Interest and other income     6,530     17,644     2,071  
  Interest expense     (520 )   (1,680 )   (3,249 )
   
 
 
 
      6,010     15,964     (1,178 )
   
 
 
 
Income before change in accounting principle     210,324     317,472     178,749  
   
 
 
 
Cumulative effect of change in accounting for major maintenance costs (Note 2)             16,785  
   
 
 
 
Net income   $ 210,324   $ 317,472   $ 195,534  
   
 
 
 

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

214



CALIFORNIA POWER GROUP

COMBINED STATEMENTS OF CASH FLOWS

(Amounts in thousands)

 
  Year Ended December 31,
 
 
  2002
  2001
  2000
 
Cash flows from operating activities:                    
  Net income   $ 210,324   $ 317,472   $ 195,534  
  Adjustments to reconcile income to cash from operating activities                    
    Cumulative effect of change in accounting principle             (16,785 )
    Unrealized (gain) loss on derivative instruments     (20,170 )   4,875      
    Depreciation and amortization     22,884     20,226     17,361  
    Changes in assets and liabilities:                    
      Trade and other receivables     225,076     (151,166 )   (95,712 )
      Inventories     (5,266 )   (7,048 )   6,925  
      Prepaids and other assets     374     (1,032 )    
      Other assets     3     (52 )    
      Accounts payable     8,010     (62,036 )   60,393  
      Unearned revenue     (20,284 )   20,284      
      Long-term liabilities     (84 )   (143 )   (96 )
   
 
 
 
  Cash provided by operating activities     420,867     141,380     167,620  
   
 
 
 
Cash flows from investing activities:                    
  Capital expenditures, net     (109,554 )   (189,916 )   (1,073 )
   
 
 
 
Cash flows from financing activities:                    
  Loan repayments     (10,100 )   (15,220 )   (11,580 )
  Contributions from partners     67,850     365,788      
  Distributions to partners     (408,200 )   (246,050 )   (157,950 )
   
 
 
 
  Cash (used for) provided by financing activities     (350,450 )   104,518     (169,530 )
   
 
 
 
Cash and cash equivalents                    
  Net increase     (39,137 )   55,982     (2,983 )
  Beginning of year     76,123     20,141     23,124  
   
 
 
 
  End of year   $ 36,986   $ 76,123   $ 20,141  
   
 
 
 
Supplemental Cash Flow Information:                    
  Cash paid during the year for interest   $ 557   $ 1,498   $ 3,773  
   
 
 
 
  Contributed property, plant and equipment   $   $ 164,248   $  
   
 
 
 

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

215



CALIFORNIA POWER GROUP

COMBINED STATEMENTS OF EQUITY

(Amounts in thousands)

 
  Edison Mission
Energy affiliates

  Chevron Texaco
affiliates

  Total
 
Balances at December 31, 1999   $ 162,432   $ 119,202   $ 281,634  
Cash distributions     (78,975 )   (78,975 )   (157,950 )
Net income     97,767     97,767     195,534  
   
 
 
 
Balances at December 31, 2000     181,224     137,994     319,218  
Cash distributions     (123,025 )   (123,025 )   (246,050 )
Cash contributions     182,894     182,894     365,788  
Net income     158,736     158,736     317,472  
   
 
 
 
Balances at December 31, 2001     399,829     356,599     756,428  
Cash distributions     (204,100 )   (204,100 )   (408,200 )
Cash contributions     33,925     33,925     67,850  
Net income     105,162     105,162     210,324  
   
 
 
 
Balances at December 31, 2002   $ 334,816   $ 291,586   $ 626,402  
   
 
 
 

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

216



CALIFORNIA POWER GROUP

NOTES TO COMBINED FINANCIAL STATEMENTS

NOTE 1: ORGANIZATION

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

        The seven projects are together referred to as the California Power Group. The six cogeneration projects are together referred to as the Cogeneration Partnerships.

Principles of combination

        These combined financial statements include the accounts of the California Power Group. The financial statements include substantial transactions with related parties. All significant intercompany transactions and balances have been eliminated. The combined financial statements have been prepared for purposes of EME's compliance with certain requirements of the Securities and Exchange Commission.

Nature of Operations

        The Cogeneration Partnerships were organized under California law during the period from 1983 to 1989 to design, construct, own and operate cogeneration facilities for the purpose of selling steam for use in oil field operations and providing electric energy under long-term contracts with two regulated utilities in California. The Cogeneration Partnerships are organized as general partnerships between subsidiaries of EME and Chevron. The income or loss from each of the projects is allocated equally to the partners. Each of the partnerships shall terminate on the latter of the date the steam and electric contracts expire (from 2004 through 2008) or the date the individual partnership elects to cease operations, unless terminated at an earlier date pursuant to the general partnership agreement.

Westside Cogeneration Projects

        Coalinga, Mid-Set, Salinas River and Sargent Canyon (together, the Westsides) each own and operate natural gas-fired cogeneration facilities, ranging in size from 36 MWs to 38 MWs. The Westsides sell electric energy to Pacific Gas & Electric Company (PG&E) for resale to its retail electric customers. The plants also sell steam to Chevron and/or Aera Energy, LLC (Aera) for use in oil recovery operations.

217



Eastside Cogeneration Projects

        Kern River and Sycamore (together, the Eastsides) each own and operate a 300 megawatt (MW) natural gas-fired cogeneration facility located in Kern County, California. The Eastsides sell electric energy to Southern California Edison Company (SCE), a wholly-owned subsidiary of EIX, for resale to its retail electric customers, and sell steam to a subsidiary of Chevron for use in its enhanced oil recovery operations in the Kern River oil field. Prior to July 1, 2002, the Eastsides also sold electric energy to Chevron for use in its Kern River oil field operations.

Sunrise

        Subsidiaries of EME and Chevron organized Sunrise as a Delaware limited liability company on May 29, 2001 to complete construction of, own and operate a gas-fired electric generation facility located in Kern County, California. The facility is being constructed in two phases. The first phase achieved commercial operation on June 29, 2001, and consists of a 320 MW simple-cycle peaking facility. During the second phase, the facility will be converted to a 580 MW combined cycle facility. Management expects the second phase to be completed by August 1, 2003. Sunrise sells electric energy to the California Department of Water Resources (CDWR) for resale to electric consumers in California.

        Sunrise will terminate on the latter of 2011 or the date it elects to cease operations. Income or loss are allocated equally between the members.

NOTE 2: SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

Use of Estimates

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

Cash and cash equivalents

        Cash and cash equivalents include cash on hand and highly liquid investments with original maturities of three months or less. The carrying amount of cash and cash equivalents approximates fair value because of the short maturity of these instruments.

Inventories

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

Risk management

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

218



Property, plant and equipment

        Property, plant and equipment are stated at cost. The plant balance includes all costs incurred prior to commercial operation of the plants, net of revenue earned during the pre-commission phase. Depreciation is calculated on a straight-line basis. The operating facilities and related equipment are depreciated over their estimated useful lives, ranging from 27 to 30 years.

        Normal repairs for maintenance and minor replacements that do not improve or extend the lives of the assets are charged to expense as incurred.

Impairment of long-lived assets

        Long-lived assets are reviewed for impairment whenever events or changes in circumstances indicate that the carrying amount of an asset may not be fully recoverable. Recoverability of assets to be held and used is measured by a comparison of the carrying amount of the assets to their fair value, which is normally determined through analysis of the future net cash flows expected to be generated by the assets. If such assets are considered to be impaired, the impairment to be recognized is measured by the amount that the carrying amount of the assets exceeds the fair value of the assets.

Revenues

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

        As a result of July 31, 2001 agreements to amend the related purchase power agreements (see Note 5), SCE paid Kern River and Sycamore one month in advance for services to be provided in the following month. The advance payments were trued up the following month based on actual deliveries and gas prices. SCE stopped paying in advance after all past due amounts were paid in March 2002. Prepaid amounts as of December 31, 2001 are reflected as unearned revenue in the accompanying financial statements.

Income taxes

        The California Power Group includes partnerships and a limited liability corporation and its income is included in the income tax returns of the partners and members. Therefore, no provision (benefit) for income taxes has been included in the accompanying financial statements.

Major maintenance accrual

        The operating facilities require major maintenance, including inspections and overhauls, on a periodic basis. These costs are expensed as incurred.

        Through December 31, 1999, the Cogeneration Partnerships accrued for major maintenance costs during the period between turnarounds (referred to as the "accrue in advance" accounting method). In March 2000, the Cogeneration Partnerships voluntarily decided to change their accounting policy to record major maintenance costs as an expense when incurred. This change in accounting policy is considered preferable based on guidance provided by the Securities and Exchange Commission. In accordance with Accounting Principles Board Opinion No. 20, Accounting Changes, the Cogeneration

219



Partnerships recorded a $16.8 million increase in income as the cumulative effect of change in the accounting for major maintenance costs.

Recent accounting pronouncements

        On January 1, 2001, the California Power Group adopted Statement of Financial Accounting Standards (SFAS) No. 133, Accounting for Derivative Instruments and Hedging Activities, as amended. Under SFAS 133, all derivative instruments, except those meeting specific exceptions, are recognized in the balance sheet at their fair value. Changes in fair value are recognized immediately in earnings unless specific hedge accounting criteria are met. For derivatives that qualify for hedge accounting, depending on the nature of the hedge, changes in fair value are either offset by changes in the fair value of the hedged assets, liabilities or firm commitments through earnings, or recognized in other comprehensive income until the hedged item is recognized in earnings.

        Management has determined that the California Power Group's energy and capacity sales commitments and physical gas purchases qualify for the normal purchases and normal sales exception provided by SFAS 133 and related guidance issued by the Derivatives and Implementation Group. This exception applies to physical sales and purchases of power or fuel where it is probable that physical delivery will occur, the pricing provisions are clearly and closely related to the contracted prices and the SFAS 133 documentation requirements are met. Management also determined that the Cogeneration Partnership's steam sales do not meet the definition of a derivative and are, therefore, not subject to the requirements of the standard. During 2001, the Westsides entered into certain gas swaps that are subject to the requirements of SFAS 133 (see Note 6).

        On January 1, 2003, the California Power Group adopted SFAS No. 143, Accounting for Asset Retirement Obligations, which requires entities to record the fair value of a liability for an asset retirement obligation in the period in which it is incurred. When the liability is initially recorded, the entity capitalizes the cost by increasing the carrying amount of the related long-lived asset. Over time, the liability is increased to its present value each period, and the capitalized cost is depreciated over the useful life of the related asset. Upon settlement of the liability, an entity either settles the obligation for its recorded amount or incurs a gain or loss upon settlement. Under certain of its leases, the California Power Group is legally required to dismantle and remove the operating facilities at the end of the lease term. As of January 1, 2003, the California Power Group recognized a liability of $16.3 million for asset retirement obligations. The cumulative effect of a change in accounting principle from unrecognized accretion and depreciation expense is a loss of $11.2 million.

        In November 2002, the Financial Accounting Standards Board issued SFAS Interpretation No. 45, Guarantor's Accounting and Disclosure Requirements for Guarantees, Including Indirect Guarantees of Indebtedness of Others. This interpretation established reporting requirements to be made by a guarantor about its obligations under certain guarantees that it has issued. It also clarifies that a guarantor is required to recognize, at the inception of a guarantee, a liability for the fair value of the obligation undertaken in issuing the guarantee. The initial recognition and initial measurement provisions of this interpretation are applicable on a prospective basis to guarantees issued or modified after December 31, 2002. The California Power Group does not anticipate the adoption of this standard will have a significant effect on their financial position or the results of operations.

220



NOTE 3: PROPERTY, PLANT AND EQUIPMENT

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

 
  As of December 31,
 
 
  2002
  2001
 
Operating facilities   $ 666,853   $ 669,988  
Other property and equipment     18,974     17,397  
   
 
 
      685,827     687,385  
Accumulated depreciation     (257,281 )   (234,641 )
Construction work in progress     124,724     13,624  
   
 
 
    $ 553,270   $ 466,368  
   
 
 

        Depreciation expense was approximately $22,652,000, $19,994,000 and $17,108,000 in 2002, 2001 and 2000, respectively.

NOTE 4: PROJECT FINANCING LOANS PAYABLE

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

 
  As of December 31,
 
  2002
  2001
Coalinga   $ 3,020   $ 6,140
Salinas River     3,500     7,000
Sargent Canyon     3,380     6,860
   
 
    $ 9,900   $ 20,000
   
 

        The project financing loans payable are repaid in semi-annual equal installments of $5,050,000 on the last day of February and August, with the final payment of $4,850,000 due on May 30, 2003. The loans payable bear interest at the current Eurodollar market rate plus 1.2% per annum which is payable periodically throughout the year. The interest rate was 2.99% and 3.47% at December 31, 2002 and 2001, respectively. The carrying amount of Project financing loans payable approximates fair value based on the borrowing rates currently available to the partnerships for long-term debt with similar terms and maturities.

        The project financing loans payable are secured by substantially all of the assets of Coalinga, Salinas River, and Sargent Canyon and place certain restrictions on capital distributions and permitted investments. As of December 31, 2002, pledged assets total approximately $71.4 million. In addition, Coalinga, Salinas River, and Sargent Canyon are required to maintain on deposit in an escrow account an amount equal to six months interest expense at an assumed market rate of 10% computed on the then outstanding balance and 5% of the loan balance. The monies on deposit in the escrow account earn interest at the current market rate.

221



NOTE 5: SALES AGREEMENTS

        The California Power Group has entered into agreements for the sale of contract capacity and net energy and steam generated by the facilities as follows:

 
  Energy and Capacity
  Steam
 
  Counterparty
  Termination
  Counterparty
  Termination
Kern River   SCE   08/09/2005   Chevron affiliates   06/01/2005
Sycamore   SCE   12/31/2007   Chevron affiliates   12/31/2007
Coalinga   PG&E   03/05/2007   Chevron and Aera   03/05/2007
Mid-Set   PG&E   05/19/2004   Chevron affiliates   3/25 and 5/19/2004
Salinas River   PG&E   03/06/2007   Aera   03/06/2007
Sargent Canyon   PG&E   02/22/2007   Aera   02/22/2007
Sunrise   CDWR   06/31/2012   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 partnership would be required to repay certain capacity payments to SCE. Under these provisions, as of December 31, 2002, the Eastsides have a total obligation of $69,239,000. Management has no reason to believe that either one of the Eastsides will terminate the PGA or fail to meet the performance requirements during the remaining term.

        On July 31, 2001, the Eastsides and SCE entered into agreements to resolve issues associated with SCE's failure to pay amounts owed to the Eastsides. In accordance with the terms of the agreements, all past due amounts (amounting to approximately $230.4 million) were repaid on March 12, 2002.

        Prior to July 1, 2002, Kern River had an agreement to sell contract capacity and net energy to Texaco Exploration and Production Inc. (TEPI), a wholly-owned subsidiary of Chevron. This agreement was terminated as of July 1, 2002. Kern River sold $5,974,000, $28,517,000 and $20,760,000 to TEPI under this agreement during the years ended December 31, 2002, 2001 and 2000, respectively. As a result of the termination of the TEPI agreement, effective December 6, 2002, Kern River amended the agreement with SCE to increase minimum contract capacity from 274 MW to 280 MW. The additional capacity payments will be calculated at a rate of $143/kW-year.

Westsides

        The Westsides each have Power Purchase Agreements (PPA) with PG&E for the sale of contract capacity and net energy. Under the terms of the agreements, prior to October 1, 2001, payments for energy were based on an SRAC rate calculated based on PG&E's 1995 average price with an

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adjustment to reflect the monthly changes in spot natural gas prices at the California border. As a result of July 31, 2001 amendments to the PPAs, effective October 1, 2001, the energy price was changed to a fixed price for the remaining term of the contracts. The fixed price will be adjusted based on the amounts of energy delivered during on-peak hours. As of December 31, 2002, the average fixed energy price was $53.70 per megawatt hour (MWh).

        PG&E also pays the Westsides for firm capacity based on a contracted amount per kilowatt year, as defined in the PPAs. In the event one of the Westsides unilaterally terminates its PPA prior to the termination date or fail to meet certain performance requirements, the partnership would be required to repay certain capacity payments to PG&E. Under these provisions, as of December 31, 2002, the Westsides have a total obligation of $17,674,000. Management has no reason to believe that any of the Westsides will terminate its PPA or fail to meet the performance requirements during the remaining term.

        On April 6, 2001, PG&E filed a Chapter 11 bankruptcy petition. On February 14, 2002, the bankruptcy court approved an agreement for the payment of past due amounts totaling $3.5 million due to the Eastsides. The agreement required the immediate payment of accrued interest and payment of the outstanding balance with interest in equal monthly payments ending January 31, 2003. PG&E made the final payment when due on January 31, 2003.

Sunrise

        Sunrise has a Power Purchase Agreement with CDWR (the CDWR PPA) for the sale of contract capacity and associated energy. The CDWR PPA is contracted in two phases pending the conversion of the simple-cycle facility to a combined-cycle facility. In January 2003, Sunrise agreed to restructure the second phase of the CDWR PPA. The initial term of the CDWR PPA will remain in effect until the commencement of commercial operation of phase two. The second phase will extend through June 30, 2012. Under the terms of the amended agreement, Sunrise will receive capacity payments at a rate of $170.60 per kilowatt year. Sunrise is also compensated for the number of times the plant is started, which is at the discretion of the State of California.

        Sunrise has no firm contracts for fuel supply. CDWR reimburses Sunrise for all costs, expenses and charges incurred by Sunrise for fuel management, procurement, transportation, storage and delivery of fuel used by the Sunrise facility for the generation of electricity on behalf of CDWR. The fuel costs and CDWR reimbursement of fuel costs are presented in the Combined Statement of Income as Fuel costs and Sales of energy, respectively.

Steam Sales

        The counterparties to the steam sales agreements pay a steam fuel charge based on the quantity and quality of steam delivered during the month. Pricing for the steam varies as follows:

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        The prices also generally include a processing charge per MMBTu as defined in the agreements. The amount of steam sold under these agreements is expected to be sufficient for the Cogeneration Partnerships to continue to maintain qualifying facility status.

NOTE 6: PRICE RISK MANAGEMENT

        The Cogeneration Partnerships are exposed to price risk associated with the purchase of natural gas for the cogeneration facilities. Market risk arises from the potential change in the value of financial instruments and physical commodities based on fluctuations in commodity prices and bases. Market risk is also affected by changes in the volatility and liquidity in markets in which these instruments are traded.

        The Westsides manage approximately 55% of their exposure to fluctuations in the price of natural gas through the use of natural gas swap agreements. Effective November 1, 2001, the Westsides entered into 24,000 MMBtu per day forward fixed natural gas contacts purchased on the NYMEX exchange with basis swaps at Permian, Southern California Border and San Juan in an attempt to mitigate price variability through May 31, 2004 (Mid-Set) and September 30, 2006 (Sargent Canyon, Salinas River and Coalinga). Under the agreements, the Westsides make or receive payment on a specific quantity of natural gas based on the differential between a specified fixed price and the market price of gas at Permian, Southern California Border or San Juan. The gains and losses related to these hedging instruments will offset fluctuations in the Westsides natural gas costs.

        Prior to January 1, 2003, the gas swap agreements were not formally designated as cash flow hedges; therefore, unrealized gains or losses on the gas swaps are recorded as part of Fuel expense in the Statements of Income. Effective January 1, 2003, management has designated the contracts as cash flow hedges; therefore, on a go forward basis gains or losses associated with the effective portion of the hedges will be recorded in other comprehensive income. The fair market value of derivative financial instruments is determined through dealer quotes and may not be representative of the actual gains or losses that will be recorded when these instruments mature due to future fluctuations in the markets in which they are traded.

        Under the terms of their parallel generation agreements, the Eastsides receive payments for energy based on a formula that is indexed to the Southern California Border spot price of natural gas. This pricing formula reduces the Eastsides' exposure to changes in gas prices. Under the terms of its power purchase agreement, Sunrise is reimbursed for fuel costs; therefore, Sunrise is not exposed to price risk associated with gas purchases.

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NOTE 7: RELATED PARTY OPERATING AGREEMENTS

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

 
  For the years ended December 31,
 
  2002
  2001
  2000
Fuel expense                  
  Texaco Natural Gas, Inc.   $ 240,840   $ 442,243   $ 399,681
  Edison Mission Marketing & Trading, Inc.     4,171     14,635    
Other operations and maintenance expense                  
  Edison Mission Operations and Maintenance, Inc.     11,783     10,611     10,256
  Mission and affiliates     1,228     1,219     1,385
  Chevron (land leases)     157     147     131
  Other     84     84     84
Administrative and general                  
  Chevron USA     7,094     6,820     6,312
  Texaco Power and Gasification Holdings Inc     527     262    
   
 
 
    $ 265,884   $ 476,021   $ 417,849
   
 
 

Fuel Management Agreements

        The Cogeneration Partnerships have entered into fuel management agreements with Texaco Natural Gas, Inc. (TNGI), a wholly-owned subsidiary of Chevron, whereby TNGI procures gas on a spot basis for the partnerships, seeking the lowest possible price balanced with the need for secure supply. The agreements continue until the termination of the related power purchase agreements. TNGI receives a fixed service fee per MMBtu of fuel gas supplied to the Cogeneration Partnerships, subject to escalation as defined by the agreements. The Cogeneration Partnerships paid service fees of approximately $2,998,000, $3,110,000 and $2,924,000 as of December 31, 2002, 2001 and 2000, respectively.

        Sunrise is party to an agreement with Edison Mission Marketing & Trading, Inc. (EMMT), a wholly-owned subsidiary of EME, whereby EMMT is to purchase and/or nominate fuel for and related transportation to the Sunrise facility. The term of this agreement shall remain in effect until terminated by either party with sixty days prior written notice. EMMT receives a fixed service fee of $0.005 per MMBtu of fuel gas supplied to Sunrise, subject to escalation as defined by the agreement.

Operations and Maintenance Agreements

        The members of the California Power Group have entered into agreements with Edison Mission Operation and Maintenance, Inc. (EMOM), a wholly-owned subsidiary of EME, whereby EMOM performs all operations and maintenance activities necessary for the production of electricity and steam. The agreements will continue until terminated by either party (the Sunrise agreement requires ninety day prior written notice). EMOM is paid for all costs incurred in connection with operating and maintaining the facilities and may earn incentive compensation as set forth in the agreements. Amounts paid to EMOM by the California Power Group under these agreements included incentive compensation of $926,000, $901,000 and $1,084,000 for the years ended December 31, 2002, 2001 and 2000, respectively.

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Emission Credits

        As part of their initial capital contribution, subsidiaries of Chevron contributed their rights to certain emission offset credits to Kern River, Sycamore and Mid-Set. EME contributed cash equal to the agreed upon fair value for the credits of $43.3 million. The emission credits have been accounted for at their historical cost of $0 in the accompanying financial statements.

Land Leases

        Certain of the entities in the California Power Group have entered into long-term land leases with Chevron as follows:

 
  Termination date
  Renewal options
Kern River   04/30/2009   Kern River can extend indefinitely
Mid-Set   07/15/2006   Mid-Set has the option to extend at any time
Salinas River   08/01/2008   Parties may agree to up to 15 one year extensions
Sunrise   11/30/2025   Sunrise has a one-time option to extend for 25 years
Sycamore   01/18/2019   None

        Lease payments are indexed to fluctuations in the gross domestic product as defined in the agreements. In addition, the Sunrise lease is subject to a 3% annual increase and Chevron may charge Sunrise additional amounts for property taxes or government assessments.

Engineering and Administrative Agreements

        The Cogeneration Partnerships has agreements with Texaco Inc., a wholly-owned subsidiary of Chevron, whereby Texaco Inc. shall perform work consisting of engineering and administrative activities required for operation of the Cogeneration Partnerships. Under the terms of the agreement, Texaco Inc. is paid for all costs incurred in connection with the engineering and administration of the Cogeneration Partnerships. The agreements shall remain in effect until terminated by either party. Effective November 1, 2002, the rights and obligations of these agreements were assigned to Chevron USA.

        Sunrise has an agreement with Texaco Power and Gasification Holdings Inc. (TPGHI), a wholly-owned subsidiary of Chevron, whereby TPGHI performs all engineering and administrative activities required by the Sunrise facility. Under the terms of the agreement, TPGHI is paid for all costs incurred in connection with engineering and administrating the Sunrise facility. The agreement became effective June 25, 2001 and shall remain in effect until terminated by either party with ninety days prior written notice.

NOTE 8: COMMITMENTS AND CONTINGENCIES

Ship or Pay

        Pursuant to the terms of the Security of Supply Agreement (the Security Agreement) dated December 1, 1994, the Eastsides and Mid-Set agreed to underwrite a portion of firm transportation capacity that had been obtained by TNGI from El Paso Gas Pipeline Company (El Paso) under an agreement dated February 15, 1989 (the El Paso Agreement) and from Mojave Pipeline Company (Mojave) under an agreement dated February 15, 1989 (the Mojave Agreement). The terms of the El Paso and Mojave Agreements extend to April 1, 2007. Under the original terms of the Security

226


Agreement, the Eastsides and Mid-Set are required to transport the lesser of 75% of each facility's annual fuel gas requirement or 52,012,500 MMBtu under the terms of the El Paso and Mojave Agreements or to pay the reservation portion of the transportation fee under each of the transportation agreements to meet the volumetric commitment. The reservation fees under the two transportation agreements total $0.64 per MMBtu.

        As a consequence of a capacity reallocation program on the El Paso system mandated by the Federal Energy Regulatory Commission (FERC) in 2002, the volume obligations of the Eastsides and Mid-Set under the Security Agreement with respect to the El Paso Agreement were modified. Effective November 1, 2002, the volumetric obligations were revised such that Kern River and Sycamore are each financially responsible for 38,986 MMBtu per day or capacity and Mid-Set is financially responsible for 6,000 MMBtu per day of capacity. The Mid-Set obligation expires on May 1, 2004, at which time Kern River and Sycamore each assume responsibility for one-half of the Mid-Set former obligation. The Kern River obligation extends to August 9, 2005 and the Sycamore obligation extends to April 1, 2007.

        On July 20, 1990, the Eastsides agreed to accept and underwrite a portion of Chevron's transportation agreement between Chevron and Northwest Pipeline Company extending through the term of the Eastsides sales agreements with SCE. Under the terms of the agreement, the Eastsides are required to transport 3,558,750 MMBtu annually. The Eastsides would be required to pay $0.30 per deficit MMBtu for failure to transport the required quantity of natural gas on the pipeline. There was no such deficit in 2002, 2001 or 2000. During 2002, all of the Eastsides obligations were brokered to third parties.

Firm Transportation Agreement

        Sunrise has an agreement with the Kern River Gas Transmission Company effective May 2003 and extending for 15 years thereafter, for the right to firm transportation of 85,000 MMBtu per day of natural gas on the Kern River Gas Transmission Sunrise's pipeline between the Rockies-Opal and the Sunrise facility. The transportation rates paid by Sunrise will be in accordance with Kern River Gas Transmission Sunrise's tariff schedule filed with the FERC. The reservation fee under the tariff for expansion capacity is currently estimated to be $0.051 per MMBtu of gas. CDWR will reimburse Sunrise for all costs associated with the agreement during the term of the Power Purchase Agreement.

Long-term Service Agreement

        Sunrise has a long-term service agreement with General Electric International, Inc. (GEI), a wholly owned affiliate of General Electric, to help manage the costs of major maintenance repairs. The agreement terminates on December 21, 2020. Under the terms of the agreement, GEI provides planned and unplanned major maintenance services and materials. Sunrise pays an annual fee of $250,000 plus a variable fee based on fired hours and factored starts. All fees are subject to escalations based on the consumer price index. Sunrise also pays for materials priced at a 15% discount to GE's list price and services based on time and materials, discounted at 7%. GE earns an incentive fee based on the availability of the turbines and is required to pay Sunrise if the turbines do not attain an annual availability factor of 97.5%. There is a $3 million cap on the incentive and availability fees.

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Engineering, Procurement and Construction Agreement

        Sunrise has a cost plus construction contract with an independent third-party to engineer, design, furnish, install and provide test services to place into operation a conversion of the simple-cycle facility to a combined-cycle facility. The contract provides financial incentives to the contractor for completing the project on a timely basis, below budget and for exceeding certain performance targets. The contract also includes termination penalties of up to $10 million for which performance has been guaranteed by EME and TPGHI. Sunrise incurred $170.2 million related to the services provided by the contractor through December 31, 2002, which was capitalized in property, plant and equipment at year-end. As of December 31, 2002, management believes the remaining portion of the combined-cycle facility will cost approximately $47.5 million.

Credit Risk

        The California Power Group is exposed to credit risk related to potential nonperformance by counter parties to its energy and capacity and steam sales. The California Power Group's sales are concentrated among five primary counter parties:

 
  For the years ended December 31,
 
  2002
  2001
  2001
 
  (in thousands)

Southern California Edison Company   $ 299,549   $ 525,299   $ 387,576
Pacific Gas & Electric Company     87,313     114,303     90,061
California Department of Water Resources     48,485     48,121    
Aera Energy, LLC     14,320     21,981     22,435
Affiliates of Chevron     105,477     124,993     134,657
   
 
 
    $ 555,144   $ 834,697   $ 634,729
   
 
 

        Due to the concentration of credit risk, the California Power Group's liquidity could be impacted by financial difficulties experienced by its counter parties. As a result of the energy crisis in California, SCE and PG&E suspended payment of amounts due to the Cogeneration Partnerships in December 2000. PG&E is still under Chapter 11 bankruptcy protection and SCE is below investment grade. However, all past due amounts have now been paid.

Operational Risks

        The depreciable lives of the operating facilities exceed the term of the related power purchase agreements. The viability of the facilities subsequent to the expiration of the power purchase agreements is uncertain and is dependent on the market price of power, the cost to produce power compared to more efficient plants and the ability to sell steam at an economic rate to the steam hosts. In accordance with its policy for testing impairment of long-lived assets (see Note 2), management periodically evaluates the expected viability of the plants subsequent to the expiration of the purchase power agreements. Management currently believes that the useful lives are appropriate and that the facilities will continue to operate profitably subsequent to the expiration of the respective purchase power agreements. However, if management subsequently determines that the plants will not be able to operate profitably beyond the term of the purchase power agreements, management will accelerate depreciation of the plants and an impairment charge may be required.

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REPORT OF INDEPENDENT AUDITORS

The Management Committee of
Watson Cogeneration Company

        We have audited the accompanying balance sheets of Watson Cogeneration Company (the Company) as of December 31, 2002 and 2001, and the related statements of income, partners' capital, and cash flows for each of the three years ended December 31, 2002. These financial statements are the responsibility of the Company's management. Our responsibility is to express an opinion on these financial statements based on our audits.

        We conducted our audits in accordance with auditing standards generally accepted in the United States. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.

        In our opinion, the financial statements referred to above present fairly, in all material respects, the financial position of Watson Cogeneration Company at December 31, 2002 and 2001, and the results of its operations and cash flows for each of the three years ended December 31, 2002 in conformity with accounting principles generally accepted in the United States.

/s/  ERNST & YOUNG LLP      

Long Beach, California
February 7, 2003

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WATSON COGENERATION COMPANY

BALANCE SHEETS

 
  December 31,
 
  2002
  2001
 
  (In Thousands)

Assets            
Current assets:            
  Cash and cash equivalents   $ 3,672   $ 23,732
  Receivables:            
    Southern California Edison Company     23,337     135,334
    BP West Coast Products LLC     6,851     3,567
    CPC Cogeneration LLC     1,706     1,206
    Other receivables     18     411
  Inventories     7,256     5,854
  Prepaid expenses     2,674     2,571
   
 
Total current assets     45,514     172,675
Property, plant and equipment, net     148,828     156,715
Intangible assets, net     14,370     17,107
   
 
Total assets   $ 208,712   $ 346,497
   
 
Liabilities and partners' capital            
Current liabilities:            
  Accounts payable   $ 2,476   $ 3,399
  Payables:            
    Southern California Edison Company     150     143
    BP West Coast Products LLC and BP Energy Company     15,907     7,434
  Advance payments from Southern California Edison         8,926
  Interest payable     672     672
   
 
Total current liabilities     19,205     20,574
Long-term debt:            
  Camino Energy Company     26,329     26,329
  Atlantic Richfield Company     27,404     27,404
Partners' capital     135,774     272,190
   
 
Total liabilities and partners' capital   $ 208,712   $ 346,497
   
 

See accompanying notes.

230



WATSON COGENERATION COMPANY

STATEMENTS OF INCOME

 
  Year ended December 31,
 
  2002
  2001
  2000
 
  (In Thousands)

Revenues:                  
  Sales:                  
    BP West Coast Products LLC   $ 57,416   $ 121,413   $ 82,505
    Southern California Edison Company     160,590     285,411     213,680
    CPC Cogeneration LLC     16,596     36,519     23,613
  Interest income     1,758     8,650     907
   
 
 
Total revenues     236,360     451,993     320,705
Expenses:                  
  Fuel purchases from BP West Coast Products LLC and BP Energy Company     117,658     204,466     150,448
  Fuel transportation costs—Southern California Edison Company     6,139     5,433     9,462
  Fuel other         79,502     33,255
  Other operating     11,794     19,178     14,300
  Depreciation and amortization     13,209     12,307     11,736
  Personnel compensation and other benefits—BP West Coast Products LLC     7,311     6,499     5,702
  Property taxes     5,244     5,045     4,728
  Interconnection fee to Southern California Edison Company     1,559     1,559     1,597
  Services fees to BP West Coast Products LLC     1,394     1,362     1,425
  Interest     2,687     5,535     2,687
  Miscellaneous expenses     2,781     1,813     1,304
   
 
 
Total expenses     169,776     342,699     236,644
   
 
 
Net income   $ 66,584   $ 109,294   $ 84,061
   
 
 

See accompanying notes.

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WATSON COGENERATION COMPANY

STATEMENTS OF PARTNERS' CAPITAL

 
  Camino
Energy
Company

  Products
Cogeneration
Company

  Carson
Cogeneration
Company

  Total
 
 
  (In Thousands)

 
Balance at December 31, 1999   $ 80,279   $ 3,277   $ 80,279   $ 163,835  
  Capital distribution     (40,670 )   (1,660 )   (40,670 )   (83,000 )
  Net income     41,190     1,681     41,190     84,061  
   
 
 
 
 
Balance at December 31, 2000     80,799     3,298     80,799     164,896  
  Capital distributions     (980 )   (40 )   (980 )   (2,000 )
  Net income     53,554     2,186     53,554     109,294  
   
 
 
 
 
Balance at December 31, 2001     133,373     5,444     133,373     272,190  
  Capital distributions     (99,470 )   (4,060 )   (99,470 )   (203,000 )
  Net income     32,626     1,332     32,626     66,584  
   
 
 
 
 
Balance at December 31, 2002   $ 66,529   $ 2,716   $ 66,529   $ 135,774  
   
 
 
 
 

See accompanying notes.

232



WATSON COGENERATION COMPANY

STATEMENTS OF CASH FLOWS

 
  Year ended December 31,
 
 
  2002
  2001
  2000
 
 
  (In Thousands)

 
Operating activities                    
Net income   $ 66,584   $ 109,294   $ 84,061  
Adjustments to reconcile net income to net cash provided by operating activities:                    
  Depreciation and amortization     13,209     12,307     11,736  
  Changes in operating assets and liabilities:                    
    Receivables     108,606     (65,842 )   (48,187 )
    Inventories     (1,403 )   2,499     (25 )
    Prepaid expenses     (103 )   (497 )   (5 )
    Accounts payable     (923 )   (3,290 )   (2,877 )
    Affiliate payables     8,480     (36,581 )   38,709  
    Advance payments from Southern California Edison     (8,926 )   8,926      
   
 
 
 
Net cash provided by operating activities     185,524     26,816     83,412  

Investing activities

 

 

 

 

 

 

 

 

 

 
Additions to property, plant and equipment     (2,584 )   (4,185 )   (2,496 )
   
 
 
 
Net cash used in investing activities     (2,584 )   (4,185 )   (2,496 )
   
 
 
 

Financing activities

 

 

 

 

 

 

 

 

 

 
Distributions to partners     (203,000 )   (2,000 )   (83,000 )
   
 
 
 
Net cash used in financing activities     (203,000 )   (2,000 )   (83,000 )
   
 
 
 
Net (decrease) increase in cash and cash equivalents     (20,060 )   20,631     (2,084 )
Cash and cash equivalents at beginning of year     23,732     3,101     5,185  
   
 
 
 
Cash and cash equivalents at end of year   $ 3,672   $ 23,732   $ 3,101  
   
 
 
 

Supplemental information

 

 

 

 

 

 

 

 

 

 
Interest paid   $ 2,687   $ 5,535   $ 2,687  

See accompanying notes.

233



WATSON COGENERATION COMPANY

NOTES TO FINANCIAL STATEMENTS

DECEMBER 31, 2002

1.    General

        Watson Cogeneration Company (WCC) is a general partnership among Products Cogeneration Company (PCC), a wholly owned subsidiary of Atlantic Richfield Company, a wholly owned subsidiary of BP America Inc. (BP); Carson Cogeneration Company (CCC), a wholly owned subsidiary of CH-Twenty, Inc., a majority-owned subsidiary of Atlantic Richfield Company, and Camino Energy Company (CEC), a wholly owned subsidiary of Edison Mission Energy, a wholly owned subsidiary of Mission Energy Holding Company, a wholly owned subsidiary of The Mission Group, a wholly owned non-utility subsidiary of Edison International, the parent holding company of Southern California Edison Company (SCE). PCC, CCC and CEC own 2%, 49% and 49% of the partnership, respectively. The WCC partnership agreement provides for its termination at the termination of the power purchase agreement with SCE in 2008, unless otherwise extended by the partners.

        WCC was organized under California law in 1986 to design, construct, own and operate a cogeneration facility (Facility), which became fully operational in 1988. WCC, which operates in one business segment, produces and sells electric energy to SCE for resale to its customers, produces and sells electric energy to CPC Cogeneration LLC (CPC), a limited liability company, owned by PCC, CCC and CEC 2%, 49% and 49%, respectively. CPC sells power to BP West Coast Products LLC (BPWCP), pursuant to a Power Purchase and Sale Agreement, which was assigned to CPC from WCC. WCC also produces and sells steam to BPWCP for use at its Carson refinery, and purchases water and fuel gas from BPWCP's Carson refinery. CPC was terminated effective at the close of business December 31, 2002.

        PCC serves as the managing partner. Insurance coverage is provided by PCC and CEC. WCC reimburses PCC's affiliate BPWCP for personnel compensation and other benefits for operating and maintaining the Facility. Additionally, BPWCP provides other ancillary services to the partnership under a services contract for a fee.

        The Facility is located on the property of the Carson Refinery of BPWCP. The right to use the property, the refinery infrastructure, and other related rights were contributed by PCC to WCC at its formation. The rights expire in 2008.

        The results of WCC's operations and its financial position may be significantly different without its relationships with its partners.

2.    Summary of Significant Accounting Policies

Cash and Cash Equivalents

        Cash and cash equivalents include highly liquid investments with original maturities of less than 90 days.

Revenue Recognition

        Electrical energy and steam revenue and related costs are recognized upon transmission to the customer.

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Inventories

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

Property, Plant and Equipment

        Property, plant and equipment are stated at cost and are depreciated over the estimated useful lives on a straight-line basis with asset lives ranging from five to 30 years.

Intangible Assets

        Intangible assets are recorded at cost and are amortized on a straight-line basis over 20 years.

Repair and Maintenance

        Repair and maintenance costs, including turnarounds, which are incurred in connection with planned major maintenance activities at the cogeneration facility, are expensed when incurred.

Reclassifications

        Certain reclassifications were made to the 2001 amounts to conform to the 2002 presentation.

New Accounting Pronouncements

FASB Statement No. 144

        In October 2001, the FASB issued SFAS No. 144, Accounting for the Impairment or Disposal of Long-Lived Assets, which establishes one accounting model to be used for long-lived assets to be disposed of by sale and broadens the presentation of discontinued operations to include more disposal transactions. SFAS No. 144 supersedes SFAS No. 121, Accounting for the Impairment of Long-Lived Assets and for Long-Lived Assets to Be Disposed Of, and the accounting and reporting provisions of Accounting Principle Board (APB) Opinion No. 30. SFAS No. 144 was effective for fiscal years beginning after December 15, 2001. The adoption of SFAS No. 144 in January 2002 did not have a material impact on the Company's consolidated financial position or results of operations, and we do not expect any impact in the foreseeable future.

FASB Statement No. 143

        In June 2001, the FASB issued Statement No. 143, Accounting for Asset Retirement Obligations. Statement No. 143 requires entities to record the fair value of a liability for an asset retirement obligation when an existing law or contract requires that the obligation be settled. The statement requires that the amount recorded as a liability be capitalized by increasing the carrying amount of the related long-lived asset. Subsequent to initial measurement, the liability is accreted to the ultimate amount anticipated to be paid, and is also adjusted for revisions to the timing or amount of estimated cash flows. The capitalized cost is depreciated over the useful life of the related asset. Upon settlement of the liability, an entity either settles the obligation for its recorded amount or incurs a gain or loss upon settlement. Statement No. 143 will be effective for financial statements beginning January 1, 2003,

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with earlier application encouraged. The Company is currently evaluating the impact of adopting this statement.

Estimates

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

3.    Southern California Edison Company

        The receivable from SCE at December 31, 2001, represents amounts due for power sales for the period from November 30, 2000 to March 25, 2001. During August 2001, an advance payment agreement was reached between SCE and WCC, whereby SCE must pay WCC for power purchases in advance. The outstanding receivables balance from November 2000 to March 2001 and accrued interest was paid by SCE in March 2002. In 2002 and 2001 WCC recorded interest income of approximately $1,497,000 and $7,821,000, respectively, on the outstanding receivables. Subsequent to March 2002, WCC no longer charged interest to SCE on their outstanding balance.

4.    Property, Plant and Equipment

        Property, plant and equipment consists of the following:

 
  2002
  2001
 
 
  (In Thousands)

 
Plant   $ 298,847   $ 314,995  
Construction-in-progress     2,532     2,370  
Other     5,747     5,150  
   
 
 
      307,126     322,515  
Less accumulated depreciation     (158,298 )   (165,800 )
   
 
 
    $ 148,828   $ 156,715  
   
 
 

        Depreciation expense amounted to approximately $10,472,000, $9,973,000, and $10,609,000 for 2002, 2001, and 2000, respectively.

5.    Intangible Assets

        Intangible assets, net of accumulated amortization of approximately $21,430,000 and $18,693,000 at December 31, 2002 and 2001, respectively, consist of outside boundary limit facilities, refinery infrastructure, environmental permits, and land use, which was contributed to the partnership at its formation. Amortization expense was approximately $2,737,000, $2,334,000, and $1,127,000 for 2002, 2001 and 2000, respectively. Amortization for the next five years is estimated at $2,737,000 per year.

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6.    Related Party Debt

        The related party debt matures in 2008 and payments of interest only, at a rate of 5%, are due semiannually on April 1 and October 1.

        During the year ended December 31, 2001, WCC borrowed and repaid $1,420,000, $34,790,000, and $34,790,000 from PCC, CCC, and CEC, respectively. The borrowings accrued interest at LIBOR plus 3% per annum. WCC paid approximately $2,848,000 in interest on these borrowings, during the year ended December 31, 2001, which is included in interest expense.

7.    Significant Contracts

Power Purchase Contract with SCE

        Under the terms of the Power Purchase Contract with SCE (SCE Power Purchase Contract), WCC has contracted to sell power generated by the Facility, but not sold to BPWCP, to SCE at contract rates recognized by the Public Utilities Commission of the State of California. The SCE Power Purchase Contract is for a period, which ends in 2008.

Power, Steam, Fuel, and Water Contracts with BP Affiliates

        WCC entered into a Power Purchase and Sale Agreement with BPWCP (as successor to Atlantic Richfield Company), which was assigned, via an Assignment Agreement, to CPC following CPC's formation. The agreement contains provisions to sell power generated by the Facility to BPWCP's Carson refinery under terms similar to the SCE Power Purchase Contract. Under the terms of the Water and Steam Purchase and Sale Agreement with BPWCP, WCC contracted to sell steam generated by the Facility to, and to purchase water from, BPWCP's Carson refinery.

        In addition, WCC and CPC agreed to enter into an Energy Sales Agreement (ESA) under which WCC sells power to CPC. The assignment of the Power Purchase and Sale Agreement and the consummation of the ESA has not had a material effect on the companies.

        CPC was terminated effective at the close of business December 31, 2002. Upon the termination of CPC, the Assignment Agreement was terminated thereby restoring the Power Purchase and Sale Agreement as a contract between WCC and BPWCP. At the same time, the Energy Sales Agreement between WCC and CPC was terminated, as well as the Services Agreement between WCC and CPC.

Interconnection Facilities Agreement

        Under the terms of an Interconnection Facilities Agreement, WCC shall pay a monthly charge to SCE, as defined in the contract, for a portion of the Interconnection Facilities, which are owned, operated and maintained by SCE.

Other

        WCC has entered into water and fuel (natural gas, refinery gas, butane and chemicals) purchase agreements with BP West Coast Products LLC and BP Energy Company. WCC purchases under these agreements amounted to approximately $122,000,000, $208,000,000, and $154,000,000 during 2002, 2001, and 2000, respectively.

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        WCC reimburses PCC's affiliate BPWCP for personnel compensation and other benefits for operating and maintaining the Facility. Additionally, BPWCP provides other ancillary services to the partnership under a services contract for a fee.

8.    Income Taxes

        Income taxes are not recorded by the partnership since the net income or loss is allocated to the partners and included in their respective income tax returns.

9.    Fair Value of Financial Instruments

        The fair value of WCC's long-term debt was estimated based on current rates of the same or similar issues. The fair value of the long-term debt was approximately $40,584,000 and $44,300,000 at December 31, 2002 and 2001, respectively.

10.  Concentrations of Credit Risk

        WCC invests its cash primarily in deposits with major banks. Certain deposits may, at times, be in excess of federally insured limits. WCC has not incurred losses related to such cash balances.

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REPORT OF INDEPENDENT AUDITORS

The Management Committee of
CPC Cogeneration LLC

        We have audited the accompanying balance sheets of CPC Cogeneration LLC (the Company) as of December 31, 2002 and 2001, and the related statements of income, members' equity, and cash flows for each of the three years ended December 31, 2002. These financial statements are the responsibility of the Company's management. Our responsibility is to express an opinion on these financial statements based on our audits.

        We conducted our audits in accordance with auditing standards generally accepted in the United States. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.

        In our opinion, the financial statements referred to above present fairly, in all material respects, the financial position of CPC Cogeneration LLC at December 31, 2002 and 2001, and the results of its operations and its cash flows for each of the three years ended December 31, 2002 in conformity with accounting principles generally accepted in the United States.

/s/  ERNST & YOUNG LLP      

Long Beach, California
January 31, 2003

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CPC COGENERATION LLC
(A LIMITED LIABILITY COMPANY)

BALANCE SHEETS

 
  December 31
 
  2002
  2001
 
  (In Thousands)

Assets            
Current assets:            
  Cash and cash equivalents   $ 975   $ 3,059
  Receivable from BP West Coast Products LLC     3,538     3,146
   
 
Total current assets     4,513     6,205
   
 
Total assets   $ 4,513   $ 6,205
   
 

Liabilities and members' equity

 

 

 

 

 

 
Current liabilities:            
  Payable to Watson Cogeneration Company   $ 1,706   $ 1,205
   
 
Total current liabilities     1,706     1,205

Members' equity

 

 

2,807

 

 

5,000
   
 
Total liabilities and members' equity   $ 4,513   $ 6,205
   
 

See accompanying notes.

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CPC COGENERATION LLC
(A LIMITED LIABILITY COMPANY)

STATEMENTS OF INCOME

 
  Year ended December 31
 
  2002
  2001
  2000
 
  (In Thousands)

Revenues:                  
  Sales:                  
    BP West Coast Products LLC   $ 37,027   $ 65,247   $ 46,566
  Interest income     44     221     133
   
 
 
Total revenues     37,071     65,468     46,699

Expenses:

 

 

 

 

 

 

 

 

 
  Purchases from Watson Cogeneration Company     16,596     36,519     23,613
  Other     24     23     12
   
 
 
Total expenses     16,620     36,542     23,625
   
 
 
Net income   $ 20,451   $ 28,926   $ 23,074
   
 
 

See accompanying notes.

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CPC COGENERATION LLC
(A LIMITED LIABILITY COMPANY)

STATEMENTS OF MEMBERS' EQUITY

 
  Camino
Energy
Company

  Products
Cogeneration
Company

  Carson
Cogeneration
Company

  Total
 
 
  (In Thousands)

 
Balance December 31, 1999   $   $   $   $  
  Distributions     (8,330 )   (340 )   (8,330 )   (17,000 )
  Net income     11,306     462     11,306     23,074  
   
 
 
 
 
Balance at December 31, 2000     2,976     122     2,976     6,074  
  Distributions     (14,700 )   (600 )   (14,700 )   (30,000 )
  Net income     14,173     580     14,173     28,926  
   
 
 
 
 
Balance at December 31, 2001     2,449     102     2,449     5,000  
  Distributions     (11,095 )   (454 )   (11,095 )   (22,644 )
  Net income     10,021     409     10,021     20,451  
   
 
 
 
 
Balance at December 31, 2002   $ 1,375   $ 57   $ 1,375   $ 2,807  
   
 
 
 
 

See accompanying notes.

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CPC COGENERATION LLC
(A LIMITED LIABILITY COMPANY)

STATEMENTS OF CASH FLOWS

 
  December 31
 
 
  2002
  2001
  2000
 
 
  (In Thousands)

 
Operating activities                    
Net income   $ 20,451   $ 28,926   $ 23,074  
Changes in operating assets and liabilities:                    
  Net change in receivable from BP West Coast Products LLC.     (392 )   5,554     (8,700 )
  Net change in payable to Watson Cogeneration Company     501     (3,974 )   5,179  
   
 
 
 
Net cash provided by operating activities     20,560     30,506     19,553  

Financing activities

 

 

 

 

 

 

 

 

 

 
Distributions to partners     (22,644 )   (30,000 )   (17,000 )
   
 
 
 
Net cash used in financing activities     (22,644 )   (30,000 )   (17,000 )
   
 
 
 
Net (decrease) increase in cash and cash equivalents     (2,084 )   506     2,553  
Cash and cash equivalents at beginning of year     3,059     2,553      
   
 
 
 
Cash and cash equivalents at end of year   $ 975   $ 3,059   $ 2,553  
   
 
 
 

See accompanying notes.

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CPC COGENERATION LLC
(A LIMITED LIABILITY COMPANY)

NOTES TO FINANCIAL STATEMENTS

DECEMBER 31, 2002

1.    General

        CPC Cogeneration LLC (CPC), a limited liability company, was formed December 23, 1999, by Products Cogeneration Company (PCC), a wholly owned subsidiary of Atlantic Richfield Company, a wholly owned subsidiary of BP America Inc. (BP); Carson Cogeneration Company (CCC), a wholly owned subsidiary of CH-Twenty, Inc., a majority-owned subsidiary of Atlantic Richfield Company, and Camino Energy Company (CEC), a wholly owned subsidiary of Edison Mission Energy, a wholly owned subsidiary of Mission Energy Holding Company, a wholly owned subsidiary of The Mission Group, a wholly owned non-utility subsidiary of Edison International, the parent holding company of Southern California Edison Company. PCC, CCC and CEC own 2%, 49% and 49% of CPC and Watson Cogeneration Company (WCC), respectively.

        WCC is a California general partnership that operates a cogeneration facility (Facility), which became fully operational in 1988. Upon the creation of CPC, WCC executed an Assignment Agreement, which effectively assigned the Power Purchase and Sale Agreement with BP West Coast Products LLC (BPWCP), as successor to Atlantic Richfield Company, from WCC to CPC. Under the terms of that assignment, CPC assumed WCC's obligations to sell power to BPWCP's Carson Refinery. In addition, WCC and CPC entered into an Energy Sales Agreement (ESA) under which WCC sells power to CPC on negotiated terms, and also entered into a Services Agreement, under which WCC provides, for compensation, various services to CPC.

        CPC was terminated effective at the close of business December 31, 2002. Effective upon the termination of CPC the Assignment Agreement was terminated thereby restoring the Power Purchase and Sale Agreement as a contract between WCC and BPWCP. At the same time, the Energy Sales Agreement between WCC and CPC was terminated, as well as the Services Agreement between WCC and CPC. CPC's receivables and payables as of December 31, 2002 will be collected and paid, respectively, and the remaining cash and cash equivalents will be distributed to its members in 2003.

        The results of CPC's operations and financial position may be significantly different without its relationship with WCC and its members.

2.    Summary of Significant Accounting Policies

Cash and Cash Equivalents

        Cash and cash equivalents include highly liquid investments with original maturities of less than 90 days.

Revenue Recognition

        CPC recognizes revenue upon providing power.

Estimates

        The preparation of financial statements in conformity with accounting principles generally accepted in the United States requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosures of contingent assets and liabilities at the date of the

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financial statements and the reported amounts of revenues and expenses during the reporting period. Actual results could differ from those estimates.

3.    Income Taxes

        Income taxes are not recorded by the CPC, since the net income or loss is allocated to the members and included in their respective income tax returns.

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REPORT OF INDEPENDENT ACCOUNTANTS

To the Stockholders of
Four Star Oil & Gas Company

        In our opinion, the accompanying consolidated balance sheets and the related consolidated statements of income, stockholders' equity and cash flows present fairly, in all material respects, the financial position of Four Star Oil & Gas Company (the Company) and its subsidiary at December 31, 2002 and 2001 and the results of their operations and their cash flows for the years then ended, in conformity with accounting principles generally accepted in the United States of America. These financial statements are the responsibility of the Company's management; our responsibility is to express an opinion on these financial statements based on our audits. We conducted our audits of these statements in accordance with auditing standards generally accepted in the United States of America, which require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management and evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion. The financial statements of the Company as of December 31, 2000 and for the year then ended were audited by other independent accountants who have ceased operations. Those independent accountants expressed an unqualified opinion on those statements in their report dated March 2, 2001.

        As described in Note 3 to the financial statements, the Company has significant transactions with affiliated companies. Because of these relationships, it is possible that the terms of these transactions are not the same as those that would result from transactions among wholly-unrelated parties.

/S/ PRICEWATERHOUSECOOPERS LLP

Houston, Texas
March 7, 2003

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FOUR STAR OIL & GAS COMPANY

CONSOLIDATED BALANCE SHEETS

DECEMBER 31, 2002 AND 2001

 
  2002
  2001
 
 
  (in millions, except share and per share amounts)

 
Assets              
Current assets:              
  Cash and cash equivalents   $ 21   $ 23  
  Accounts receivable:              
    Trade     3     6  
    Related parties and affiliates     46     35  
  Other receivables     7     22  
  Other current assets     4     2  
   
 
 
      Total current assets     81     88  
   
 
 
Properties, plant and equipment (successful-efforts method)     955     934  
Less—accumulated depreciation, depletion and amortization     (673 )   (629 )
   
 
 
      Net properties, plant and equipment     282     305  
   
 
 
Deferred charges and other assets     1     4  
   
 
 
      Total   $ 364   $ 397  
   
 
 
Liabilities and Stockholders' Equity              
Current liabilities:              
  Accounts payable and accrued liabilities   $ 7   $ 5  
  Related party and affiliate payables     54     31  
  Taxes payable     10     8  
   
 
 
      Total current liabilities     71     44  
   
 
 
Note payable to affiliate     169     239  
   
 
 
Deferred income taxes     54     57  
   
 
 
Commitments and contingencies (Note 10)              
Stockholders' equity:              
  Preferred stock, $1.00 par value. 400 Class A shares authorized, 96 shares and 230 shares issued and outstanding at December 31, 2002 and 2001, respectively; 400 Class B authorized, 300 shares issued and outstanding at December 31, 2002 and 2001          
  Common stock, $1.00 par value, 1,000 Class A shares authorized, issued and outstanding; 2,000 Class B shares authorized, 373 shares and 239 shares issued and outstanding at December 31, 2002 and 2001, respectively; 1,000 Class C shares authorized, 25 shares issued and outstanding at December 31, 2002 and 2001          
  Additional paid-in capital     29     57  
  Retained earnings     41      
   
 
 
    Total stockholders' equity     70     57  
   
 
 
    Total   $ 364   $ 397  
   
 
 

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

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FOUR STAR OIL & GAS COMPANY
CONSOLIDATED STATEMENTS OF INCOME
YEARS ENDED DECEMBER 31, 2002, 2001 AND 2000

 
  2002
  2001
  2000
 
 
  (in millions)

 
Revenues:                    
  Crude oil   $ 45   $ 46   $ 63  
  Natural gas     139     219     252  
  Natural gas liquids     24     38     7  
  Other     27     14     18  
   
 
 
 
      235     317     340  
   
 
 
 
Costs and expenses:                    
  Operating expenses     47     38     35  
  General and administrative expenses     14     13     10  
  Depreciation, depletion and amortization     44     38     42  
  Impairment of oil and gas properties     7     7     25  
  Taxes other than income taxes     19     25     28  
   
 
 
 
      131     121     140  
   
 
 
 
Operating income     104     196     200  
Other income (expense):                    
  Interest expense     (7 )   (13 )   (18 )
  Interest income and other     6     1     1  
   
 
 
 
Income before income taxes     103     184     183  
   
 
 
 
Provision (benefit) for income taxes:                    
  Federal:                    
    Current     36     45     46  
    Deferred     (4 )   3     6  
  State and local:                    
    Current     (1 )   6     4  
   
 
 
 
      31     54     56  
   
 
 
 
Net income   $ 72   $ 130   $ 127  
   
 
 
 

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

248


FOUR STAR OIL & GAS COMPANY
CONSOLIDATED STATEMENTS OF STOCKHOLDERS' EQUITY
YEARS ENDED DECEMBER 31, 2002, 2001 AND 2000

 
  Common shares
  Preferred shares
   
   
   
   
   
 
 
  Class A
  Class B
  Class C
  Class A
  Class B
  Common stock
  Preferred stock
  Paid-in capital
  Retained earnings
  Total stockholders' equity
 
 
  (in millions, except share amounts)

 
Balance, December 31, 1999   1,000   159   25   310   300   $   $   $ 90   $ 25   $ 115  
Dividends paid                           (144 )   (144 )
Stock conversion     80     (80 )                      
Net income                           127     127  
   
 
 
 
 
 
 
 
 
 
 
Balance, December 31, 2000   1,000   239   25   230   300             90     8     98  
Dividends paid                       (33 )   (138 )   (171 )
Stock conversion     134     (134 )                      
Net income                           130     130  
   
 
 
 
 
 
 
 
 
 
 
Balance, December 31, 2001   1,000   373   25   96   300             57         57  
Dividends paid                       (28 )   (31 )   (59 )
Net income                           72     72  
   
 
 
 
 
 
 
 
 
 
 
Balance, December 31, 2002   1,000   373   25   96   300   $   $   $ 29   $ 41   $ 70  
   
 
 
 
 
 
 
 
 
 
 

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

249


FOUR STAR OIL & GAS COMPANY
CONSOLIDATED STATEMENTS OF CASH FLOWS
YEARS ENDED DECEMBER 31, 2002, 2001 AND 2000

 
  2002
  2001
  2000
 
 
  (in millions)

 
Cash flows from operating activities:                    
  Net income   $ 72   $ 130   $ 127  
  Reconciliation of net income to net cash provided by operating activities:                    
    Reversal of provision for plug and abandonment         (2 )    
    Depreciation, depletion and amortization     44     38     42  
    Impairment of oil and gas properties     7     7     25  
    Deferred income taxes and other     (3 )   3     4  
    Changes in assets and liabilities:                    
      Accounts receivable—trade, net     3     8     (9 )
      Accounts receivable—related parties and affiliates     (11 )   28     (46 )
      Other receivables     15     (15 )    
      Other current assets     (2 )        
      Deferred charges and other assets     3          
      Accounts payable and accrued liabilities     2     (10 )   3  
      Related party and affiliate payables     23     14     10  
      Taxes payable     2         7  
   
 
 
 
        Net cash provided by operating activities     155     201     163  
   
 
 
 
Cash flows from investing activities:                    
    Capital expenditures     (28 )   (25 )   (21 )
    Proceeds from property sales             6  
   
 
 
 
        Net cash used in investing activities     (28 )   (25 )   (15 )
   
 
 
 
Cash flows from financing activities:                    
    Dividends paid     (59 )   (171 )   (144 )
    Loan principal repayment to affiliate     (70 )        
   
 
 
 
        Net cash used in financing activities     (129 )   (171 )   (144 )
   
 
 
 
Increase (decrease) in cash and cash equivalents     (2 )   5     4  
Cash and cash equivalents, beginning of year     23     18     14  
   
 
 
 
Cash and cash equivalents, end of year   $ 21   $ 23   $ 18  
   
 
 
 
Supplemental disclosure of cash flow information:                    
    Cash flows from operating activities include the following cash payments:                    
      Income taxes   $ 15   $ 62   $ 41  
      Interest     7     13     18  

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

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FOUR STAR OIL & GAS COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

DECEMBER 31, 2002 AND 2001

1.    Basis of Presentation and Description of the Company

        Four Star Oil and Gas Company is a subsidiary of ChevronTexaco that explores for and produces crude oil, natural gas and natural gas liquids. The use in this report of the term "Texaco" refers solely to Texaco Inc., a Delaware corporation, and its consolidated subsidiaries or to subsidiaries and affiliates either individually or collectively.

        In 1984, Texaco acquired all of the outstanding common stock of Four Star Oil & Gas Company (Four Star or the Company) for $10.2 billion. At the time of acquisition, Four Star was an integrated petroleum and natural gas company involved in the exploration for and production, transportation, refining and marketing of crude oil and petroleum products. The acquisition was accounted for as a purchase, and the Four Star assets and liabilities were recorded at fair market value. In 1989, Texaco sold 20 percent of its interest in Four Star to Edison Mission Energy (Mission Energy). Four Star was an 80 percent owned subsidiary of Texaco from December 31, 1989 through December 31, 1991. As a result of a series of stock transactions occurring between January 1, 1992 and December 31, 2002, Texaco's ownership interest in Four Star was reduced to 71%.

        In October 2001, the merger between Texaco and Chevron Corporation was approved and ChevronTexaco Corporation (ChevronTexaco) became the ultimate parent of Texaco Inc. Texaco Inc.'s investment in Four Star was transferred to ChevronTexaco Global Energy Inc. as part of a restructuring agreement dated November 1, 2001. Texaco Exploration and Production Inc. (TEPI), a wholly-owned subsidiary of Texaco Inc., was absorbed into Chevron U.S.A. (CUSA), a wholly-owned subsidiary of ChevronTexaco, as part of a legal restructuring in May 2002. CUSA operates and manages the majority of Four Star's operations under the terms of a service agreement.

        As of December 31, 2002 and 2001, the ownership interests in Four Star were as follows:

 
  2002
  2001
 
Chevron U.S.A. (CUSA)   36.6 % 36.6 %
ChevronTexaco Global Energy Inc. (CTGEI)   24.3 % 24.3 %
Edison Mission Energy (Mission Energy)   19.0 % 19.0 %
Four Star Oil & Gas Holdings Company
(owned jointly by CTGEI and Mission Energy)
  20.1 % 20.1 %
   
 
 
    100.0 % 100.0 %
   
 
 

2.    Significant Accounting Policies

Principles of Consolidation

        The consolidated financial statements include the accounts of Four Star Oil & Gas Company (Four Star or the Company) and Mission Energy Methane, a wholly-owned subsidiary of Four Star. All significant intercompany accounts and transactions have been eliminated in consolidation.

Revenue Recognition

        Revenues associated with sales of crude oil, natural gas and other sources are recorded when title passes to the customer, net of royalties, discounts and allowances, as applicable. Revenues from natural

251



gas production from properties in which ChevronTexaco has an interest with other producers are generally recognized on the basis of delivery (sales method).

Cash and Cash Equivalents

        Highly liquid investments with a maturity of three months or less when purchased are generally considered to be cash equivalents.

Properties, Plant and Equipment and Depreciation, Depletion and Amortization

        The Company follows the successful efforts method of accounting for its oil and gas exploration and production operations.

        Lease acquisition costs related to properties held for oil and gas production are capitalized when incurred. Unproved properties with acquisition costs which are individually significant are assessed on a property-by-property basis, and a loss is recognized, by provision of a valuation allowance, when the assessment indicates an impairment in value. Unproved properties with acquisition costs which are not individually significant are generally aggregated, and the portion of such costs estimated to be nonproductive, based on historical experience, is amortized on an average holding period basis.

        Exploratory costs, excluding the costs of exploratory wells, are charged to expense as incurred. Costs of drilling exploratory wells, including stratigraphic test wells, are capitalized pending determination of whether the wells have found proved reserves which justify commercial development. If such reserves are not found, the drilling costs are charged to exploratory expenses. Intangible drilling costs applicable to productive wells and to development dry holes, as well as tangible equipment costs related to the development of oil and gas reserves, are capitalized.

        The costs of productive leaseholds and other capitalized costs related to production activities, including tangible and intangible costs, are amortized principally by field on the unit-of-production basis by applying the ratio of produced oil and gas to estimated recoverable total proved oil and gas reserves. Estimated future restoration and abandonment costs are taken into account in determining amortization and depreciation rates.

        Depreciation of properties, plant and equipment related to operations other than production is provided using the straight-line method, with depreciation rates based upon estimated useful lives applied to the cost of each class of property. The useful lives of such assets range from 3 to 20 years.

        Normal maintenance and repairs of properties, plant and equipment are charged to expense as incurred. Renewals, betterments and major repairs that materially extend the life of properties are capitalized, and the assets replaced, if any, are retired.

        When fixed capital assets representing complete units of property are disposed of, any profit or loss after accumulated depreciation and amortization is credited or charged to income.

        Long-lived assets, including proved oil and gas properties, are assessed for possible impairment by comparing their carrying values with the undiscounted future net before-tax cash flows. Events which can trigger assessments for possible impairments include write-downs of proved reserves based on field performance, significant decreases in the market value of an asset, and significant change in an asset.

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Impaired assets are written down to their estimated fair values, generally their discounted future net before-tax cash flows. As a result, the Company recorded impairment charges of $7 million, $7 million and $25 million in 2002, 2001 and 2000, respectively, due to downward reserve revisions.

Use of Estimates

        The preparation of financial statements in conformity with accounting principles generally accepted in the United States of America requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting period. The most significant estimates pertain to proved oil, NGL and gas reserve volumes and plug and abandonment costs as well as estimates relating to the calculation of impairments under SFAS No. 144. Actual results could differ from those estimates.

Reclassifications

        Certain previously reported amounts have been reclassified to conform to current-year presentation. Such reclassification had no effect on reported net income or shareholders' equity.

Income Taxes

        Deferred taxes result from temporary differences in the recognition of revenues and expenses for tax and financial reporting purposes and are calculated based upon cumulative book and tax differences in the balance sheet.

Derivatives

        The adoption of SFAS No. 133, "Accounting for Derivative Instruments and Hedging Activities," did not have a material effect on the Company's financial position as the Company has no derivatives as of December 31, 2002 and 2001, except for its physical sale contracts, which qualify as normal sales. The Company adopted SFAS 133 as of January 1, 2001.

New Accounting Pronouncements

        In June 2001, the FASB issued Statement No. 143, "Accounting for Asset Retirement obligations" (SFAS 143). This new standard was adopted effective January 1, 2003, and applies to legal obligations associated with the retirement of tangible long-lived assets. Adoption of SFAS 143 primarily affects the Company's accounting for oil and gas producing assets. SFAS 143 differs in several significant respects from current accounting under SFAS 19, "Financial Accounting and Reporting by Oil and Gas Producing Companies." Adoption of SFAS 143 affects future accounting and reporting of the assets, liabilities and expenses related to these obligations. In the first quarter 2003, the Company will report an after-tax loss of approximately $9.2 million for the cumulative effect of this change in accounting principle. The effect of adoption will also include an increase of total assets and total liabilities of $16.8 million and $26 million, respectively. Besides the cumulative-effect adjustment, the effect of the new accounting standard on net income in 2003 is not expected to be materially different from what the result would have been under SFAS 19 accounting.

253



        In April 2002, the FASB issued SFAS No. 145, Recession of FASB Statement No. 4, 44 and 64, Amendment of FASB Statement No. 13, and Technical Corrections. Application of the statement will be required in 2003. The Company does not expect adoption of SFAS No. 145 to have a significant impact on its financial statements.

        In July 2002, the FASB issued SFAS No. 146, Accounting for Exit or Disposal Activities. SFAS No. 146 address the recognition, measurement and reporting costs associated with exit and disposal activities when they are incurred rather than at the date of a commitment to an exit or disposal plan. SFAS No. 146 is to be applied prospectively to exit or disposal activities initiated after December 31, 2002.

        In December 2002, the FASB issued Interpretation No. 45 (FIN No. 45), Guarantor's Accounting and Disclosure Requirements. FIN No. 45 expands required disclosures for certain types of guarantees and recognition of a liability at fair value of such guarantees at the time of issuance. The disclosure requirements are effective for the Company's December 31, 2002 financial statements, while the fair value accounting requirements apply prospectively to guarantees issued or modified after December 31, 2002. The Company does not expect FIN No. 45 to have a significant effect on its financial statements.

        In January 2003, the FASB issued Interpretation No. 46, "Consolidation of Variable Interest Entities" (FIN No. 46). FIN No. 46 amended ARB 51, "Consolidated Financial Statements," and established standards for determining under what circumstances a variable interest entity (VIE) should be consolidated with its primary beneficiary. FIN No. 46 also requires disclosures about VIEs that the Company is not required to consolidate but in which it has a significant variable interest. The Company does not expect that adoption of FIN No. 46 will have a significant impact on the results of operations, financial position or liquidity.

Reclassifications

        Certain prior year amounts have been reclassified to conform with current year presentation.

3.    Related Party Transactions

        Four Star has various business transactions with ChevronTexaco and other ChevronTexaco subsidiaries and affiliates. These transactions principally involve sales by Four Star of crude oil, natural gas and natural gas liquids. In addition, ChevronTexaco charges Four Star for management, professional, technical and administrative services, as well as direct charges for exploration and production-related activities.

        Effective December 1, 1999, Four Star entered into a service agreement with TEPI for management, administrative, professional and technical services through November 1, 2004. During 2001, Four Star paid TEPI a monthly fixed fee of $579,785 through November 30, 2001. Four Star paid TEPI a monthly fixed fee of $597,634 from December 1, 2001 through April 30, 2002, and CUSA a monthly fixed fee of $597,634 from May 1, 2002 through November 30, 2002. Beginning December 1, 2002, the rate was adjusted to $603,034 and this rate will remain in effect until November 30, 2003. An aggregate amount of $7.2 million, $7.0 million and $6.8 million in service fees was included as a component of general and administrative and other operating expenses in the accompanying consolidated statement of income for the years ended December 31, 2002, 2001 and 2000, respectively.

254



        In addition, Four Star paid TEPI a monthly unit fee of $645,015 during the period from December 1, 2000 to November 30, 2001. On December 1, 2001, Four Star commenced payment of a monthly unit fee of $607,041. On May 1, 2002, TEPI was absorbed into CUSA as part of a legal restructuring agreement dated May 1, 2002. Total unit fees of $6.8 million, $7.7 million and $7.3 million are included as a component of general and administrative and other operating expenses in the accompanying consolidated statements of income for the years ended December 31, 2002, 2001 and 2000, respectively. The unit fee is adjusted to actual production within 90 days after contract period ending November 30, 2002.

        Pursuant to the contractual agreement described in Note 10, certain tax benefits and liabilities are assumed by ChevronTexaco.

        The following table summarizes sales to affiliates during 2002, 2001 and 2000. The Company makes no purchases from its affiliates.

 
  2002
  2001
  2000
 
  (in millions)

Dynegy   $ 87.6   $   $
Texaco Natural Gas Inc.     70.6     252.2     214.7
CUSA     39.6         .8
Bridgeline LLC—Texaco Pipeline             .5
Equilon Enterprises LLC(1)         46.3     70.7
   
 
 
Total   $ 197.8   $ 298.5   $ 286.7
   
 
 

(1)
Equilon Enterprise LLC was no longer considered as a related party to Four Star effective October 19, 2001.

4.    Properties, Plant and Equipment

        In 2000, Four Star sold $5.9 million of its properties for $6.3 million, resulting in an approximate $400,000 pretax gain on the sale. In 2002, Four Star purchased the San Juan LLC 1999 property for $11.6 million.

5.    Note Payable to Affiliate

        In September 1999, Four Star retired its loan facility with Chase Bank of Texas, N.A. and entered into a loan agreement with Texaco Inc. The outstanding balance on the loan agreement was $169 million and $239 million at December 31, 2002 and 2001. The loan bears interest at LIBOR plus one percent and matures on December 31, 2005. The interest rate was 2.4%, 3.4% and 7.0% at December 31, 2002, 2001 and 2000, respectively. Interest expense during 2002, 2001 and 1999, was $7 million, $13 million and $18 million, respectively. Four Star pays Texaco Inc. an annual facility fee and administrative fee of $50,000.

        The Company's borrowing base is redetermined annually each September 30 as set forth in the Four Star Oil & Gas Credit Agreement dated September 30, 1999. If the outstanding aggregate principal amount of the loan, excluding the amount of any debt permitted by the loan agreement,

255



exceeds the amount of the revised borrowing base, Four Star must repay such excess to Texaco Inc. in four equal quarterly installments. Throughout 2002 and 2001, Four Star's borrowing base exceeded the outstanding loan balance, thus no principal payments were due. As of December 31, 2002, the Company's borrowing base under the agreement was $268 million.

        Four Star elected to pre-pay $70 million of the note on December 31, 2002. Four Star has the right, subject to certain conditions, to prepay the note in whole or in part prior to the maturity date.

6.    Concentration of Credit Risk

        Substantially all of the Company's accounts receivable at December 31, 2002, result from sales to the Company's three largest customers, all of which are ChevronTexaco affiliates, as discussed in Note 3. The Company's credit policy and relatively short duration of receivables mitigate the risk of uncollected receivables. During each of the three years in the period ended December 31, 2002, the Company did not incur any credit losses on receivables.

7.    Income Taxes

        The Company accounts for income taxes in accordance with SFAS No. 109, "Accounting for Income Taxes". Under SFAS No. 109, deferred income taxes are determined utilizing a liability approach. This method gives consideration to the future tax consequences associated with utilization of energy tax credits and differences between financial accounting and tax bases of assets and liabilities. Such differences relate mainly to depreciable and depletable properties, intangible drilling costs and nonproductive leases.

        The composition of deferred tax assets and liabilities and the related tax effects at December 31, 2002, 2001 and 2000, were as follows (in millions):

 
  2002
  2001
  2000
 
Deferred tax assets related to energy tax credits   $   $   $ 4  
Deferred tax liabilities related to oil and gas properties     (54 )   (57 )   (58 )
   
 
 
 
Net deferred tax liability   $ (54 ) $ (57 ) $ (54 )
   
 
 
 

        There are differences between income taxes computed using the statutory rate of 35 percent and the Company's effective income tax rates (29 percent in 2002, 29 percent in 2001 and 31 percent in 2000), primarily as a result of certain tax credits available to the Company. Reconciliations of income taxes computed using the statutory rate to the Company's effective tax rates are as follows (in millions):

 
  2002
  2001
  2000
 
Income taxes computed at the statutory rate   $ 36   $ 64   $ 64  
Section 29 tax credits     (7 )   (7 )   (8 )
Other, net     2     (3 )    
   
 
 
 
Provision for income taxes   $ 31   $ 54   $ 56  
   
 
 
 

256


8.    Stockholders' Equity

        In 1995, Four Star created four additional classes of stock: Class A common (voting), Class B common (voting), Class C common (nonvoting) and preferred (Class A preferred and Class B preferred).

        In 1999, Texaco, TEPI, and Mission Energy entered into an agreement granting Mission Energy the option to purchase shares of Class A common stock or Class B common stock of Four Star (class determined by ChevronTexaco), provided that ChevronTexaco's aggregate ownership interest in the common stock at time of purchase shall not be reduced to less than 51 percent of all common stock outstanding at the time of purchase. The option expires on December 23, 2006. In 2001, the agreement was amended to replace Texaco with CTGEI. In 2002, TEPI was replaced by CUSA as part of a legal restructure agreement. As of December 31, 2002 and 2001, Mission Energy owned 23 percent of all voting common stock outstanding. Four Star Oil and Gas Holdings Company (owned jointly by CTGEI and Mission Energy) owned 26 percent of all voting common stock in the Company as of December 31, 2002.

        Each share of Class A preferred stock is entitled to receive cumulative cash dividends of $5,112 per share per annum, payable semiannually. Each share of Class B preferred stock is entitled to receive cumulative cash dividends of $2,250 per annum, payable semiannually.

9.    Fair Value of Financial Instruments

        The Company's financial instruments consist of cash and cash equivalents, short-term receivables and payables and long-term debt. The carrying amounts of such instruments approximate their fair market values due to the highly liquid nature of the short-term instruments and the floating interest rates associated with the long-term debt, which reflect market rates.

10.    Commitments and Contingencies

        ChevronTexaco has assumed any and all liabilities of Four Star incurred or attributable to periods prior to January 1, 1990, for state and federal income, windfall profit ad valorem or franchise taxes, and legal proceedings. In addition, ChevronTexaco has assumed certain of the tax liabilities of Four Star arising from January 1, 1990, to March 1, 1990, attributable to Four Star's status as a member of the Texaco tax consolidated group.

        In the opinion of the Company, while it is impossible to ascertain the ultimate legal and financial liability with respect to the above or other contingent liabilities, including lawsuits, claims, guarantees, federal taxes and federal regulations, the aggregate amount of any such liability is not anticipated to be material in relation to the financial position, cash flows or results of operations of the Company.

11.    Supplemental Information on Oil and Gas Producing Activities (Unaudited)

        In accordance with Statement of Financial Accounting Standards No. 69, "Disclosures About Oil and Gas Producing Activities" (FAS 69), this section provides supplemental information on oil and gas exploration and producing activities of the Company in seven separate tables. Tables I through IV provide historical cost information pertaining to costs incurred in exploration, property acquisitions and development; capitalized costs; and results of operations. Tables V through VII present information on the Company's estimated net proved reserve quantities, standardized measure of estimated discounted

257



future net cash flows related to proved reserves, and changes in estimated discounted future net cash flows.

Table I—Costs incurred in exploration, property acquisitions and development(1)

 
  2002
  2001
 
  (millions of dollars)

Exploration   $ 2   $
Property acquisitions     12    
Development     13     42
   
 
  Total costs incurred   $ 27   $ 42
   
 

(1)
Includes cost incurred whether capitalized or expensed. Excludes support equipment expenditures.

Table II—Capitalized costs related to oil and gas producing activities

 
  2002
  2001
 
  (millions of dollars)

Unproved properties   $ 1   $ 1
Proved properties and related producing assets     939     906
Other uncompleted projects     15     27
   
 
  Gross capitalized costs     955     934
   
 
Unproved properties valuation         1
Proved producing properties     662     618
Future abandonment and restoration     11     10
   
 
Accumulated provisions     673     629
   
 
Net capitalized costs   $ 282   $ 305
   
 

258


Table III—Results of operations for oil and gas producing activities

        The Company's results of operations from oil and gas producing activities for the years 2002 and 2001 are shown in the following table. In accordance with FAS No. 69, income taxes in Table III are based on statutory tax rates, reflecting allowable deductions and tax credits. Interest income and expense are excluded from the results reported in Table III.

 
  2002
  2001
 
 
  (millions of dollars)

 
Revenues from net production:              
  Sales   $ 203   $ 304  
   
 
 
    Total     203     304  
  Production expenses     (75 )   (48 )
Proved producing properties: depreciation, depletion and abandonment provision     (44 )   (38 )
Other income (expense)     20     (10 )
   
 
 
  Results before income taxes     104     208  
Income tax expense     (31 )   (61 )
   
 
 
Results of producing operations   $ 73   $ 147  
   
 
 

Table IV—Results of operations for oil and gas producing activities—unit prices and costs

 
  2002
  2001
Average sales prices:            
  Liquids, per barrel   $ 19.72   $ 21.61
  Natural gas, per thousand cubic feet     2.43     3.59
Average production costs, per barrel     5.93     3.31

Table V—Reserve quantity information

        The Company's estimated net proved underground oil and gas reserves and changes thereto for the years 2002 and 2001 are shown in the following table. Proved reserves are estimated by Company asset teams composed of earth scientists and reservoir engineers. These proved reserve estimates are reviewed annually by the Company's Reserves Advisory Committee to ensure that rigorous professional standards and the reserves definitions prescribed by the U.S. Securities and Exchange Commission are consistently applied throughout the Company.

        Proved reserves are the estimated quantities that geologic and engineering data demonstrate with reasonable certainty to be recoverable in future years from known reservoirs under existing economic and operating conditions. Due to the inherent uncertainties and the limited nature of reservoir data, estimates of underground reserves are subject to change as additional information becomes available.

259



        Proved reserves do not include additional quantities recoverable beyond the term of the lease or concession agreement or that may result from extensions of currently proved areas or from applying secondary or tertiary recovery processes not yet tested and determined to be economic.

        Proved developed reserves are the quantities expected to be recovered through existing wells with existing equipment and operating methods.

        "Net" reserves exclude royalties and interests owned by others and reflect contractual arrangements and royalty obligations in effect at the time of the estimate.

 
  Net proved
reserves of crude
oil condensate
and natural
gas liquids(1)

  Net proved
reserves of
natural gas(1)

 
 
  (millions of barrels)

  (millions of cubic feet)

 
Reserves at December 31, 2000   28   503,855  
Changes attributable to:          
  Revisions   (3 ) 51,827  
  Extensions and discoveries     17,320  
  Sales     (21 )
  Production   (3 ) (61,611 )
   
 
 
Reserves at December 31, 2001   22   511,370  
   
 
 
Changes attributable to:          
  Revisions   3   5,772  
  Extensions and discoveries     2,756  
  Sales      
  Purchases     24,072  
  Production   (4 ) (56,057 )
   
 
 
Reserves at December 31, 2002   21   487,913  
   
 
 

(1)
Proved reserves of oil condensate, natural gas liquids and natural gas are located entirely within the United States.

Table VI—Standardized measure of discounted future net cash flows related to proved oil and gas reserves

        The standardized measure of discounted future net cash flows, related to the preceding proved oil and gas reserves, is calculated in accordance with the requirements of FAS No. 69. Estimated future cash inflows from production are computed by applying year-end prices for oil and gas to year-end quantities of estimated net proved reserves. Future price changes are limited to those provided by contractual arrangements in existence at the end of each reporting year. Future development and production costs are those estimated future expenditures necessary to develop and produce year-end estimated proved reserves based on year-end cost indices, assuming continuation of year-end economic conditions. Estimated future income taxes are calculated by applying appropriate year-end statutory tax

260



rates. These rates reflect allowable deductions and tax credits and are applied to estimated future pretax net cash flows, less the tax basis of related assets. Discounted future net cash flows are calculated using ten percent midperiod discount factors. Discounting requires a year-by-year estimate of when future expenditures will be incurred and when reserves will be produced.

        The information provided does not represent management's estimate of the Company's expected future cash flows or value of proved oil and gas reserves. Estimates of proved reserve quantities are imprecise and change over time as new information becomes available. Moreover, probable and possible reserves, which may become proved in the future, are excluded from the calculations. The arbitrary valuation prescribed under FAS No. 69 requires assumptions as to the timing and amount of future development and production costs. The calculations are made as of December 31 each year and should not be relied upon as an indication of the Company's future cash flows or value of its oil and gas reserves.

 
  2002
  2001
 
 
  (millions of dollars)

 
Future cash inflows from production   $ 2,088   $ 1,454  
Future production and development costs     (97 )   (655 )
Future income taxes     (709 )   (273 )
   
 
 
Undiscounted future net cash flows     1,282     526  
Ten percent midyear annual discount for timing of              
estimated cash flows     (486 )   (190 )
   
 
 
Standardized measure of discounted future net cash flows   $ 796   $ 336  
   
 
 

Table VII—Changes in the standardized measure of discounted future net cash flows from proved reserves

 
  2002
  2001
 
 
  (millions of dollars)

 
Present value at January 1   $ 336   $ 1,679  
   
 
 
Sales and transfers of oil and gas produced, net of production costs     (130 )   (256 )
Development costs incurred     13     42  
Purchases of reserves     33      
Extensions, discoveries and improved recovery, less related costs     5     9  
Revisions of previous quantity estimates     (14 )   27  
Net changes in prices, development and production costs     786     (2,147 )
Accretion of discount     45     257  
Net change in income tax     (278 )   725  
   
 
 
  Net change for the year     460     (1,343 )
   
 
 
  Present value at December 31   $ 796   $ 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."

261



REPORT OF INDEPENDENT ACCOUNTANTS

To the Management Committee of
Midway-Sunset Cogeneration Company:

        In our opinion, the accompanying balance sheet as of December 31, 2002 and the related statements of income, partners' equity, and cash flows present fairly, in all material respects, the financial position of Midway-Sunset Cogeneration Company (a California general partnership) at December 31, 2002, and the results of its operations and its cash flows for the year then ended in conformity with accounting principles generally accepted in the United States of America. These financial statements are the responsibility of the Partnership's management; our responsibility is to express an opinion on these financial statements based on our audit. We conducted our audit of these statements in accordance with auditing standards generally accepted in the United States of America, which require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, and evaluating the overall financial statement presentation. We believe that our audit provides a reasonable basis for our opinion.

PricewaterhouseCoopers LLP

Los Angeles, California
March 14, 2003

262



MIDWAY-SUNSET COGENERATION COMPANY

BALANCE SHEETS

DECEMBER 31, 2002 AND 2001 (UNAUDITED)

 
  2002
  2001
 
   
  (unaudited)

Assets            
Current assets:            
  Cash and cash equivalents   $ 2,629,581   $ 10,085,755
  Accounts receivable     59,736,027     101,622,475
  Inventory     3,175,010     2,402,147
   
 
    Total current assets     65,540,618     114,110,377

Plant and equipment, net

 

 

85,357,870

 

 

95,446,717

Other assets:

 

 

 

 

 

 
  Emission offsets, net     2,216,666     2,566,666
  Deposits     500,849     2,500,000
   
 
    Total assets   $ 153,616,003   $ 214,623,760
   
 

Liabilities and Partners' Equity

 

 

 

 

 

 
Current liabilities:            
  Accounts payable to affiliates and others   $ 51,282,703   $ 54,766,698
   
 
    Total current liabilities     51,282,703     54,766,698

Payable to Aera Energy LLC

 

 


 

 

5,333,340
   
 
    Total liabilities     51,282,703     60,100,038
   
 

Commitments and contingencies (Note 10)

 

 

 

 

 

 

Partners' equity:

 

 

 

 

 

 
  San Joaquin Energy Company     51,166,650     77,261,861
  Aera Energy LLC     51,166,650     77,261,861
   
 
    Total partners' equity     102,333,300     154,523,722
   
 
    Total liabilities and partners' equity   $ 153,616,003   $ 214,623,760
   
 

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

263



MIDWAY-SUNSET COGENERATION COMPANY

STATEMENTS OF INCOME

FOR THE YEARS ENDED DECEMBER 31, 2002, 2001 (UNAUDITED) AND 2000 (UNAUDITED)

 
  2002
  2001
  2000
 
   
  (unaudited)

  (unaudited)

Revenues:                  
  Sales of electricity to affiliates   $ 95,266,858   $ 173,853,446   $ 121,654,339
  Sales of electricity to others     3,625,518     5,980,984     8,750,305
   
 
 
    Total sales of electricity     98,892,376     179,834,430     130,404,644
 
Sales of steam to affiliate

 

 

30,633,411

 

 

60,860,800

 

 

47,393,056
  Interest and other income     889,093     3,297,414     892,695
   
 
 
    Total revenues     130,414,880     243,992,644     178,690,395
   
 
 

Expenses:

 

 

 

 

 

 

 

 

 
  Fuel     79,458,882     165,750,451     122,374,272
  Maintenance and operations     3,818,742     3,814,656     3,677,202
  Contract labor     5,127,663     5,636,206     9,246,762
  Property taxes     2,005,646     1,847,456     1,749,715
  Write-off of development costs     3,388,089        
  Depreciation and amortization     7,808,401     11,294,963     10,452,286
  (Gain)/loss on disposal of asset     (2,121 )   912    
  Interest expense             60,348
   
 
 
    Total expenses     101,605,302     188,344,644     147,560,585
   
 
 
    Net income   $ 28,809,578   $ 55,648,000   $ 31,129,810
   
 
 

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

264



MIDWAY-SUNSET COGENERATION COMPANY

STATEMENTS OF CHANGES IN PARTNERS' EQUITY

FOR THE YEARS ENDED DECEMBER 31, 2002, 2001 (UNAUDITED) AND 2000 (UNAUDITED)

 
  San Joaquin
Energy
Company

  Aera Energy
LLC

  Total
 
Balance, December 31, 1999 (unaudited)   $ 54,872,956   $ 54,872,956   $ 109,745,912  
 
Net income

 

 

15,564,905

 

 

15,564,905

 

 

31,129,810

 
  Cash distributions     (8,000,000 )   (8,000,000 )   (16,000,000 )
   
 
 
 

Balance, December 31, 2000 (unaudited)

 

 

62,437,861

 

 

62,437,861

 

 

124,875,722

 
 
Net income

 

 

27,824,000

 

 

27,824,000

 

 

55,648,000

 
  Cash distributions     (13,000,000 )   (13,000,000 )   (26,000,000 )
   
 
 
 

Balance, December 31, 2001 (unaudited)

 

 

77,261,861

 

 

77,261,861

 

 

154,523,722

 
 
Net income

 

 

14,404,789

 

 

14,404,789

 

 

28,809,578

 
  Cash distributions     (40,500,000 )   (40,500,000 )   (81,000,000 )
   
 
 
 

Balance, December 31, 2002

 

$

51,166,650

 

$

51,166,650

 

$

102,333,300

 
   
 
 
 

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

265



MIDWAY-SUNSET COGENERATION COMPANY

STATEMENTS OF CASH FLOWS

FOR THE YEARS ENDED DECEMBER 31, 2002, 2001 (UNAUDITED) AND 2000 (UNAUDITED)

 
  2002
  2001
  2000
 
 
   
  (unaudited)

  (unaudited)

 
Cash flows from operating activities:                    
  Net income   $ 28,809,578   $ 55,648,000   $ 31,129,810  
  Adjustments to reconcile net income to net cash provided by operating activities:                    
    Depreciation and amortization     7,808,401     11,294,963     10,452,286  
    (Gain) loss on disposal of asset     (2,121 )   912      
    Write-off of development costs     3,388,089          
    Decrease (increase) in accounts receivable     41,886,448     (50,089,176 )   (33,333,770 )
    (Increase) decrease in inventory     (772,863 )   (35,098 )   749,430  
    Decrease (increase) in deposits     1,999,151     (2,500,000 )    
    (Decrease) increase in accounts payable to affiliates and other     (3,483,995 )   16,988,144     29,095,713  
    Decrease in interest payable             (65,847 )
    (Decrease) increase in other liabilities     (5,333,340 )   5,333,340      
   
 
 
 
      Net cash provided by operating activities     74,299,348     36,641,085     38,027,622  
   
 
 
 

Cash flows from investing activities:

 

 

 

 

 

 

 

 

 

 
  Capital expenditures     (760,522 )   (12,924,527 )   (11,948,675 )
  Proceeds from sale of equipment     5,000     12,999      
   
 
 
 
      Net cash used in investing activities     (755,522 )   (12,911,528 )   (11,948,675 )
   
 
 
 

Cash flows from financing activities:

 

 

 

 

 

 

 

 

 

 
  Repayment of long-term debt             (5,644,000 )
  Cash distributions     (81,000,000 )   (26,000,000 )   (16,000,000 )
  Repayment of long-term debt             282,200  
   
 
 
 
      Net cash used in financing activities     (81,000,000 )   (26,000,000 )   (21,361,800 )
   
 
 
 

Net decrease in cash and cash equivalents

 

 

(7,456,174

)

 

(2,270,443

)

 

4,717,147

 

Cash and cash equivalents, beginning of year

 

 

10,085,755

 

 

12,356,198

 

 

7,639,051

 
   
 
 
 

Cash and cash equivalents, end of year

 

$

2,629,581

 

$

10,085,755

 

$

12,356,198

 
   
 
 
 

Supplemental disclosure of cash flow information:

 

 

 

 

 

 

 

 

 

 
  Cash paid during the year for interest   $   $   $ 126,195  
   
 
 
 

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

266



MIDWAY-SUNSET COGENERATION COMPANY

NOTES TO FINANCIAL STATEMENTS

DECEMBER 31, 2002, 2001 (UNAUDITED) AND 2000 (UNAUDITED)

1. Organization and Operations

        Midway-Sunset Cogeneration Company (the "Partnership") is a California general partnership between San Joaquin Energy Company ("San Joaquin"), holding a 50 percent general partnership interest and Aera Energy LLC ("Aera"), a California limited liability company whose members are (1) SWEPI LP and (2) Shell Onshore Ventures, Inc. (affiliates of Shell Oil Company) and (3) Mobil California Exploration and Producing Asset Company (affiliate of ExxonMobil), holding a combined 50 percent general partnership interest. San Joaquin is a wholly owned subsidiary of Edison Mission Energy ("Mission"), an indirect wholly owned subsidiary of Edison International.

        The Partnership was organized to design, construct, own and operate a qualifying cogeneration facility (the "Facility"), as defined in the Public Utility Regulatory Policies Act of 1978 and the regulations promulgated thereunder, all as amended ("PURPA"), located in Kern County, California. The Facility currently sells most of the electricity generated by the facility to Southern California Edison Company ("SCE"), a wholly owned subsidiary of Edison International, for resale to its customers and sells all steam produced to Aera for use in its Midway-Sunset oil field operations. The Facility was certified as a "qualifying facility" under PURPA prior to the start of operations, and management believes they have fulfilled all requirements to receive continued "qualifying facility" status.

        The Facility consists of three combustion turbine generators producing electricity and steam sequentially using one fuel source. The Facility is designed to have the capacity of generating 228 megawatts of electricity and 1.2 million pounds of steam per hour.

        The Partnership, unless sooner dissolved or extended pursuant to the terms of the partnership agreement, will be dissolved on May 8, 2010.

2. Summary of Significant Accounting Policies

Use of Estimates in Financial Statements

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

Cash and Cash Equivalents

        The Partnership considers cash and cash equivalents to include cash and short-term investments with an original maturity of three months or less.

Inventory

        Inventory is stated at the lower of weighted average cost or market.

267



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 years
Capitalized interest   Up to 30 years
Furniture and office equipment   3 to 7 years

        At January 1, 2000 the Partnership changed the estimated useful life related to the hot gas portion of the three combustion turbine generators from 20 years to 12 years. The change resulted from management's intention to modify the existing turbines to increase efficiency and reduce emissions and to accurately reflect the true life of the hot gas path components. This modification is commonly referred to as Dry Low Nox.

Capitalized Interest

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

Major Maintenance

        Certain major pieces of equipment require major maintenance on a periodic basis. These costs are expensed as incurred.

Financial Instruments

        Financial instruments that potentially subject the Partnership to significant concentrations of credit or valuation risk consist principally of cash equivalents and accounts receivable.

        The carrying amounts, reported in the balance sheets for cash and cash equivalents, and accounts receivable, approximate fair value.

Revenue Recognition

        Revenue is recognized as billable under the provisions of three power purchase agreements which have varying terms of approximately four to twenty years. Electricity revenue is calculated based on power output and established prices, as defined in the power purchase agreements. Steam revenue is calculated based on steam output and established prices, as defined in the steam sale and purchase agreement. Revenue is also recognized as billable under the provisions of a steam sale and purchase agreement.

Income Taxes

        The Partnership is treated as a partnership for income tax purposes and the income or loss of the Partnership is included in the income tax returns of the individual partners. Accordingly, no recognition has been given to income taxes in the financial statements.

268



Project Development Costs

        The Partnership capitalizes project development costs as incurred. These costs consist of professional fees, salaries, permits and other directly related costs. The capitalized costs are amortized over the operational life of the project or charged to expense if management determines the costs to be unrecoverable. The Partnership has written off development costs of $3,388,089 in 2002. These costs were associated with the planned expansion of the project and were capitalized from 2000 through 2002. A decision was made in 2002 to discontinue funding of the expansion project and all associated costs were subsequently written off.

New Accounting Pronouncements

Statement of Financial Accounting Standards No. 133

        The Partnership adopted Financial Accounting Standards Board (FASB) Statement No. 133, "Accounting for Derivative Instruments and Hedging Transactions" (FAS 133), as amended by SFAS 138, "Accounting for Derivative Instruments and Hedging Transactions—an amendment of FASB Statement No. 133," effective January 1, 2001. Provisions in Statement No. 133, as amended, affect the accounting and disclosure of certain contractual arrangements and operations of the Partnership. Under Statement No. 133, as amended, all derivative instruments are recognized in the balance sheet at their fair values and changes in fair value are recognized immediately in earnings, unless the derivatives qualify as hedges of future cash flows or net investments. For derivatives qualifying as hedges of future cash flows, the effective portion of changes in fair value is recorded in equity until the related hedged items impact earnings. Any ineffective portion of a hedge is reported in earnings immediately. The Partnership reviewed the activities performed under its contracts and the respective terms and concluded that the contracts meet the Normal Purchases and Normal Sales Exception defined in FAS 133, which resulted in accrual accounting consistent with the pre-adoption of FAS 133.

Statement of Financial Accounting Standards No. 143

        Effective January 1, 2003, the Partnership adopted Statement of Financial Accounting Standards ("SFAS") No. 143, "Accounting for Asset Retirement Obligations." SFAS No. 143 requires entities to record the fair value of a liability for an asset retirement obligation in the period in which it is incurred. When the liability is initially recorded, the entity capitalizes a cost by increasing the carrying amount of the related long-lived asset. Over time, the liability is increased to its present value each period, and the capitalized cost is depreciated over the useful life of the related asset. Upon settlement of the liability, an entity either settles the obligation for its recorded amount or incurs a gain or loss upon settlement. The Partnership expects to record a cumulative effect adjustment effective January 1, 2003, that will decrease net income by $613,000.

Statement of Financial Accounting Standards No. 145

        In April 2002, the Financial Accounting Standards Board ("FASB") issued SFAS No. 145, "Rescission of FASB Statements No. 4, 44, and 64, Amendment of FASB Statement No. 13, and Technical Corrections," which supersedes previous guidance for reporting gains and losses from extinguishment of debt and accounting for leases, among other things, which is effective on January 1,

269



2003. The portion of the statement relating to the rescission of SFAS No. 4, "Reporting Gains and Losses from Extinguishment of Debt" requires that any gain or loss on extinguishment of debt that was classified as an extraordinary item that does not meet the unusual in nature and infrequent of occurrence criteria in APB Opinion No. 30, "Reporting the Results of Operations—Reporting the Effects of Disposal of a Segment of a Business, and Extraordinary, Unusual and Infrequently Occurring Events and Transactions" shall be reclassified. The Partnership does not anticipate that the adoption of SFAS No. 145 will have a material effect on its financial position or the results of operations.

Statement of Financial Accounting Standards No. 146

        Effective January 1, 2003, the Partnership adopted SFAS No. 146, "Accounting for Costs Associated with Exit or Disposal Activities." SFAS No. 146 requires that liabilities for costs associated with exit or disposal activities initiated after December 31, 2002 be recognized when incurred, rather than at the date of a commitment to an exit or disposal plan. The Partnership does not anticipate that the adoption of SFAS No. 146 will have a material effect on its financial position or the results of operations.

Statement of Financial Accounting Standards Interpretation No. 45

        In November 2002, the FASB issued SFAS Interpretation No. 45, "Guarantor's Accounting and Disclosure Requirements for Guarantees, Including Indirect Guarantees of Indebtedness of Others." This interpretation establishes reporting requirements to be made by a guarantor about its obligations under certain guarantees that it has issued. It also clarifies that a guarantor is required to recognize, at the inception of a guarantee, a liability for the fair value of the obligation undertaken in issuing the guarantee. The initial recognition and initial measurement provisions of this interpretation are applicable on a prospective basis to guarantees issued or modified after December 31, 2002. The Partnership does not anticipate that adoption of this standard will have a material effect on its financial position or the results of operations.

3. Accounts Receivable

        Accounts receivable consists of the following at December 31, 2002 and 2001:

 
  2002
  2001
Accounts receivable from affiliates:            
  SCE   $ 14,641,191   $ 55,563,403
  Aera     7,044,875     5,723,608
  Other affiliates     293,155     1,460,574
   
 
      21,979,221     62,747,585
Accounts receivable from others     37,756,806     38,874,890
   
 
    $ 59,736,027   $ 101,622,475
   
 

270


4. Inventory

        Inventory consists of the following at December 31, 2002 and 2001:

 
  2002
  2001
Fuel gas   $ 791,267   $ 84,891
Materials and spare parts     2,383,743     2,317,256
   
 
    $ 3,175,010   $ 2,402,147
   
 

5. Plant and Equipment

        Plant and equipment consists of the following at December 31, 2002 and 2001:

 
  2002
  2001
 
Power plant facilities   $ 156,080,240   $ 155,829,632  
Capitalized interest     8,769,831     8,769,831  
Furniture and office equipment     1,171,097     1,085,598  
Construction in process     221,018     3,223,561  
   
 
 
      166,242,186     168,908,622  
Less: accumulated depreciation and amortization     (80,884,316 )   (73,461,905 )
   
 
 
    $ 85,357,870   $ 95,446,717  
   
 
 

6. Other Assets

Emission Offsets

        Emission offsets contributed to the Partnership were valued at an amount agreed upon by the partners and are being amortized on a straight-line basis over a period of 20 years. Emission offsets consist of the following at December 31, 2002 and 2001:

 
  2002
  2001
 
Cost   $ 7,000,000   $ 7,000,000  
Less: Accumulated amortization     (4,783,334 )   (4,433,334 )
   
 
 
    $ 2,216,666   $ 2,566,666  
   
 
 

Deposits

        The partnership was required to maintain a deposit of $500,000 with the Automated Power Exchange at December 31, 2002. The Partnership was required to maintain a deposit with the Automated Power Exchange to ensure monthly liquidity requirements. The required deposit was reduced during 2002 as the Partnership became its own scheduling coordinator.

271



7. Accounts Payable

        Accounts payable consists of the following at December 31, 2002 and 2001:

 
  2002
  2001
Accounts payable to affiliates:            
  Aera Energy LLC   $ 5,381,833   $ 6,666,660
  Edison Mission Operations and Maintenance     315,115     257,876
  San Joaquin     171,008     234,408
   
 
      5,867,956     7,158,944
Accounts payable to others     45,414,747     47,607,754
   
 
    $ 51,282,703   $ 54,766,698
   
 

8. Related Party Transactions

        In addition to the related party transactions discussed in Notes 3, 7 and 9, the Partnership entered into certain contracts and agreements with San Joaquin, Aera and certain other related parties.

        Under the terms of a Power Purchase Agreement ("PPA"), SCE agreed to purchase up to 200 megawatts of the electric power generated by the Facility for a period of 20 years. SCE operates as a regulated utility and is a sister company of Mission. The Partnership is paid for energy based upon the price of SCE's avoided fuel costs, the quantity of kilowatts delivered and the incremental energy rate used to determine SCE's published avoided cost of energy. SCE also pays the Partnership for firm capacity based upon a contracted amount per kilowatt year, as determined in the Power Purchase Agreement.

        The Partnership and SCE signed an amendment to the PPA, which was approved by the California Public Utility Commission during 1999, which was effective as of October 14, 1996. The amendment contains energy pricing terms that maintain the intent of the PPA's original pricing terms. Energy payments will be based on an energy rate that is calculated using a Short Run Avoided Cost ("SRAC") based formula that contains a prescribed energy rate indexed to the Southern California Border Spot Price of natural gas. At such time as the California Public Utilities Commission issues an order determining that the California Power Exchange, or equivalent, is functioning properly, as defined in the amendment, the SRAC based energy rate will be compared to a price determined by taking 95 percent of the energy rate posted by the California Power Exchange. The higher of the two rates will be used to calculate energy payments due the Partnership.

        Effective April 30, 1997, the Partnership entered into an agreement with Aera to sell 9 megawatts of excess electric energy generated by the Facility. The terms of the agreement require Aera to pay for electric energy based on a formula defined in the agreement but provided for a rebate at the conclusion of the contract if cumulative payments exceeded a certain threshold. At December 31, 2001 the potential rebate was approximately $12 million.

        In January 2002, the original agreement was terminated effective October 1, 2001. The Partnership simultaneously entered into a new agreement with Aera to sell 18 megawatts of excess electric energy generated by the Facility, which expires on May 08, 2009. The new agreement, among other things, allows the Partnership to defer payment of the $12 million due Aera under the original agreement.

272



Payment of the $12 million is to be made in 27 equal monthly installments, which can be offset against monthly payments due from Aera for energy purchases. At December 31, 2002, the Partnership has $5,333,340 in current payables related to the new agreement. The new agreement also provides for San Joaquin to be paid a monthly power price adjustment fee, the cumulated total of which shall not exceed $12 million through the duration of the agreement.

        The Partnership recognized total electricity sales to affiliates of $95,266,858, $173,853,446 and $121,654,339 in 2002, 2001 and 2000, respectively, under these contracts.

        The Partnership has a payable of $34,977,715 to SCE which is wholly offset by a receivable from the California Power Exchange. For further discussion of this situation refer to Note 9. California Power Crisis.

        Under the terms of a Steam Sale and Purchase Agreement, Aera purchases 8.6 billion pounds of steam per year generated by the Facility through May 1, 2009. The Partnership is paid a steam fuel charge based upon the quantity and quality of steam delivered during the month, which is priced at the weighted average of the Partnership's cost of fuel and a processing charge per MMBtu, as defined in the Steam Sale and Purchase Agreement. The Partnership sold $30,633,411, $60,860,800 and $47,393,056 of steam in 2002, 2001 and 2000, respectively, under this agreement which is included within sales of steam in the accompanying statements of income. The quantity of steam sold under this agreement is sufficient for the Partnership to meet qualifying facility status.

        Under the terms of an Operation and Maintenance Agreement, employees of Edison Mission Operations and Maintenance, Inc. ("EMOM"), a wholly owned subsidiary of Mission, perform all necessary functions to operate and maintain the Facility. The Partnership pays for direct costs of these services, plus an increment to cover overhead and benefits. In addition, effective January 1992, the Agreement was amended to include payment to EMOM of certain annual fees. Pursuant to this Agreement, the Partnership incurred costs of $3,032,198, $3,088,614 and $6,045,133 which included annual fees earned by EMOM of $336,000 in 2002 and 2001, respectively and $3,099,900 in 2000, which are included in contract labor in the accompanying statements of income.

        Under the terms of the Partnership Agreement, employees of Aera perform services for the Partnership. The Partnership pays for direct costs of these services, plus an increment to cover overhead and benefits. Pursuant to this arrangement, the Partnership incurred costs of $310,961, $357,526 and $427,796 in 2002, 2001 and 2000, respectively.

        The Partnership entered into a Financial Services Agreement with San Joaquin whereby San Joaquin provides certain required financial, accounting and other services for an annual fee of $125,000 in 2002, 2001 and 2000.

        Under the terms of a Surface Lease Agreement, the Partnership leases approximately 13 acres of land from AERA, which serves as the Facility site. The initial term of the lease extends through October 1, 2009, with an annual rental, amended as of January 1998, of $1,450.

9. California Power Crisis

        In August of 2001, SCE and the Partnership agreed to a Stipulated amount of $56,862,811 for electric energy, capacity, and other charges covering past due amounts from November 1, 2000 through

273



March 26, 2001. SCE claimed non-payment stems from the undercollection in its tariff rates based on the full cost of providing service to their customers. The Partnership notified SCE that it was in breach of the Power Purchase Agreement ("PPA") as a result of the delinquent payments.

        On August 3, 2001, the Partnership and SCE entered into a written agreement to address the outstanding issues surrounding SCE's failure to pay past due amounts for energy deliveries from the past due period. SCE agreed to a payment schedule based on the occurrence of certain events, the first of which occurred with the execution of the agreement. SCE paid 10 percent of the stipulated amount $5,686,281 plus interest of $1,431,455 on August 9, 2001 and agreed to pay an additional 10 percent upon a legislative solution being reached which would restore SCE to creditworthiness and allow them to pay its debts in a timely manner.

        In return for SCE's agreement to the stipulated past due amounts and to an event determined payment schedule for the unpaid balance, the Partnership agreed to stay the litigation for a standstill period as specified in the agreement.

        On October 2, 2001, SCE and the California Public Utilities Commission ("CPUC") announced an agreement which was expected to allow SCE to eventually restore its creditworthiness. The CPUC agreed to freeze consumer rates despite a decline in the price of wholesale electricity.

        As part of the amendment signed December 2001, the Partnership agreed to forego the second 10% payment in favor of full payment prior May 31, 2002.

        On March 1, 2002 SCE paid the Partnership the adjusted balance of the stipulated amount including accrued interest at 7% amounting to approximately $52,469,549 in full settlement of their obligations.

        The Partnership is owed $36,451,347, included in Accounts Receivable, by the California Power Exchange ("PX") for power sold into the California ISO during 2000 and 2001. The PX, upon receiving funds from its debtors, will pay the Partnership an amount adjusted for wind down charges. The Partnership will then pro-rate the receipt and reimburse the following parties as follows: SCE $34,977,715, PG&E $876,472, included in accounts payable, for previous power sales. The partnership is obligated to reimburse SCE and PG&E, only if funds are received from the PX.

10. Commitments and Contingencies

        The Partnership has agreed to pay public utility maintenance and other fees during the term of the Interconnection contract for the transmission facilities used to transport the electric power generated to SCE, PG&E, and others. The Partnership incurred maintenance fees of $1,181,227 for these services in 2002, 2001 and 2000.

        Effective November 1989, the Partnership entered into a 20 year Power Purchase Agreement with PG&E, a public utility, whereby the utility agreed to purchase excess on-peak and partial peak electricity from the Facility. This excess electricity consists of the facility output less station use, Aera field use and the initial 200 megawatts generated for sale to SCE. Upon request by the utility, the Facility may deliver during off-peak and super off-peak periods. The Partnership sold $2,046,330, $1,199,680 and $3,069,219 of electricity in 2002, 2001 and 2000, respectively, under this agreement which is included within sales of electricity to others in the accompanying statements of income.

274



        Under the terms of a Gas Management Services Agreement, the Partnership reimburses a third party for the procurement of fuel gas for use in its operations through 2009, cancelable under certain terms defined in the agreement. The Partnership incurred costs related to this third party $52,267,451, $130,887,239 and $90,535,134 for fuel gas purchases in 2002, 2001 and 2000, respectively.

        The Partnership purchases the remainder of its natural gas requirements in the spot market. The Partnership may be exposed to fluctuations in the price of natural gas. However, fluctuations in the prices paid for natural gas are implicitly tied to the revenues received from power and steam under the various agreements.

275




REPORT OF INDEPENDENT ACCOUNTANTS

To the Management Committee of
March Point Cogeneration Company:

        In our opinion, the accompanying balance sheet as of December 31, 2002 and the related statements of income and comprehensive income, partners' equity, and cash flows present fairly, in all material respects, the financial position of March Point Cogeneration Company (a general partnership between Equilon Enterprises LLC, Texaco March Point Holdings Inc., and San Juan Energy Company) at December 31, 2002, and the results of its operations and its cash flows for the year then ended in conformity with accounting principles generally accepted in the United States of America. These financial statements are the responsibility of the Partnership's management; our responsibility is to express an opinion on these financial statements based on our audit. We conducted our audit of these statements in accordance with auditing standards generally accepted in the United States of America, which require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, and evaluating the overall financial statement presentation. We believe that our audit provides a reasonable basis for our opinion.

PricewaterhouseCoopers LLP

Los Angeles, California
January 10, 2003

276



MARCH POINT COGENERATION COMPANY

BALANCE SHEETS—DECEMBER 31, 2002 AND 2001 (unaudited)

 
  2002
  2001
 
   
  (unaudited)

Assets            
Current Assets:            
  Cash and cash equivalents   $ 7,285,083   $ 7,598,666
  Receivables:            
    Equilon and subsidiaries     2,824,510     2,688,572
    Puget Sound Energy     6,351,577     6,632,625
    Other     6,529     19,457
  Current portion of escrow account     934,215     901,730
  Inventory     2,036,776     2,156,122
   
 
      Total current assets     19,438,690     19,997,172
   
 
Operating Facility and Equipment, at cost, net of accumulated depreciation of $48,587,514 in 2002 and $43,931,211 in 2001     87,772,109     91,655,132
   
 

Other Assets:

 

 

 

 

 

 
  Deferred loan fees, net of accumulated amortization of $1,885,874 in 2002 and $1,777,184 in 2001     152,830     261,521
  Escrow account, net of current portion     686,220     1,370,435
  Gas purchase agreement at fair value     29,596,277     18,113,340
   
 
      Total other assets     30,435,327     19,745,296
   
 
      Total assets   $ 137,646,126   $ 131,397,600
   
 

Liabilities and Partners' Equity

 

 

 

 

 

 
Current Liabilities:            
  Current portion of project financing loan   $ 13,684,300   $ 13,034,600
  Working capital loan     5,000,000     5,000,000
  Amounts payable to Equilon and subsidiaries     2,502,017     2,052,190
  Amounts payable to Texaco and subsidiaries     214,731     223,933
  Trade and other payables (amount includes $1,799,549 and $1,789,207 payable to related parties in 2002 and 2001, respectively)     3,589,331     4,773,225
   
 
      Total current liabilities     24,990,379     25,083,948
   
 
Project Financing Loan, net of current portion     13,724,400     27,408,700
   
 

Partners' Equity:

 

 

 

 

 

 
  Equilon Enterprises LLC     24,633,904     19,647,332
  Texaco March Point Holdings Inc.     24,831,768     19,805,143
  San Juan Energy Company     49,465,675     39,452,477
   
 
      Total partners' equity     98,931,347     78,904,952
   
 
      Total liabilities and partners' equity   $ 137,646,126   $ 131,397,600
   
 

277



MARCH POINT COGENERATION COMPANY

STATEMENTS OF INCOME AND COMPREHENSIVE INCOME

FOR THE YEARS ENDED DECEMBER 31, 2002, 2001 (unaudited) AND 2000 (unaudited)

 
  2002
  2001
  2000
 
   
  (unaudited)

  (unaudited)

Revenues:                  
  Sales of energy to Puget Sound Energy   $ 66,892,786   $ 69,285,008   $ 67,622,428
  Sales of steam to Equilon     13,884,212     13,287,435     13,255,068
  Sales of natural gas         2,265,381     5,011,927
  Interest and other income     400,153     756,760     1,051,600
   
 
 
    Total revenues     81,177,151     85,594,584     86,941,023
   
 
 
Costs and Expenses:                  
  Plant and other operating expenses     39,738,925     59,006,492     58,240,450
  Depreciation and amortization     4,812,804     4,820,519     4,856,584
  General and administrative expenses     363,367     319,904     373,058
  Interest expense     1,240,284     2,826,691     4,877,378
   
 
 
    Total costs and expenses     46,155,380     66,973,606     68,347,470
   
 
 
  Income before change in accounting principle     35,021,771     18,620,978     18,593,553
   
 
 
  Cumulative effect on prior years of change in accounting major maintenance costs             7,778,649
   
 
 
    Net income     35,021,771     18,620,978     26,372,202
   
 
 
Other comprehensive income/(loss):                  
  Cumulative effect on prior years of change in accounting for derivatives         24,584,225    
  Unrealized holding gain/(loss) arising during the period     (957,635 )   (4,524,630 )  
  Reclassification adjustment included in net income     (1,787,741 )   (2,793,717 )  
   
 
 
    Total other comprehensive income/(loss)     (2,745,376 )   17,265,878    
   
 
 
    Comprehensive income   $ 32,276,395   $ 35,886,856   $ 26,372,202
   
 
 

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

278



MARCH POINT COGENERATION COMPANY

STATEMENTS OF PARTNERS' EQUITY

FOR THE YEARS ENDED DECEMBER 31, 2002, 2001 (unaudited), AND 2000 (unaudited)

 
  Equilon
Enterprises
LLC

  Texaco
March Point
Holdings Inc.

  San Juan
Energy
Company

  Total
 
Partners' Equity, December 31, 1999 (unaudited)   $ 9,660,177   $ 9,737,769   $ 19,397,948   $ 38,795,894  
Allocation of Comprehensive Income     6,566,678     6,619,423     13,186,101     26,372,202  
Distributions     (2,315,700 )   (2,334,300 )   (4,650,000 )   (9,300,000 )
   
 
 
 
 
Partners' Equity, December 31, 2000 (unaudited)     13,911,155     14,022,892     27,934,049     55,868,096  
Allocation of Comprehensive Income     8,935,827     9,007,601     17,943,428     35,886,856  
Distributions     (3,199,650 )   (3,225,350 )   (6,425,000 )   (12,850,000 )
   
 
 
 
 
Partners' Equity, December 31, 2001 (unaudited)     19,647,332     19,805,143     39,452,477     78,904,952  
Allocation of Comprehensive Income     8,036,822     8,101,375     16,138,198     32,276,395  
Distributions     (3,050,250 )   (3,074,750 )   (6,125,000 )   (12,250,000 )
   
 
 
 
 
Partners' Equity, December 31, 2002   $ 24,633,904   $ 24,831,768   $ 49,465,675   $ 98,931,347  
   
 
 
 
 

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

279



MARCH POINT COGENERATION COMPANY

STATEMENTS OF CASH FLOWS

FOR THE YEARS ENDED DECEMBER 31, 2002, 2001 (unaudited) AND 2000 (unaudited)

 
  2002
  2001
  2000
 
 
   
  (unaudited)

  (unaudited)

 
Cash Flows from Operating Activities:                    
  Net income   $ 35,021,771   $ 18,620,978   $ 26,372,202  
  Adjustments to reconcile net income to net cash provided by operating activities:                    
    Depreciation and amortization     4,812,804     4,820,519     4,856,584  
    Change in repair and maintenance liability, net             (8,112,399 )
    Loss on disposal of equipment     17,806     13,964     754  
    Ineffectiveness of cash flow hedge     (14,228,312 )   (847,461 )    
  Decrease/(increase) in receivables     158,038     6,067,095     (7,142,765 )
  Decrease/(increase) in inventories     119,346     (111,103 )   245,510  
  Increase/(decrease) in payables     (743,269 )   (5,165,583 )   6,399,657  
   
 
 
 
      Net cash provided by operating activities     25,158,184     23,398,409     22,619,543  
   
 
 
 
Cash Flows from Investing Activities:                    
  Additions to operating facility and equipment, net     (838,897 )   (580,020 )   (334,594 )
  Proceeds from sale of equipment         535      
   
 
 
 
      Net cash used in investing activities     (838,897 )   (579,485 )   (334,594 )
Cash Flows from Financing Activities:                    
  Proceeds from working capital loan     5,000,000     5,000,000     5,000,000  
  Payment on project financing loan     (13,034,600 )   (12,384,400 )   (12,384,400 )
  Payment on working capital loan     (5,000,000 )   (5,000,000 )   (5,000,000 )
  Proceeds from escrow account     651,730     619,220     619,220  
  Distributions to partners     (12,250,000 )   (12,850,000 )   (9,300,000 )
   
 
 
 
      Net cash used in financing activities     (24,632,870 )   (24,615,180 )   (21,065,180 )
   
 
 
 
(Decrease) in Cash and Cash Equivalents     (313,583 )   (1,796,256 )   1,219,769  
Cash and Cash Equivalents, beginning of year     7,598,666     9,394,922     8,175,153  
   
 
 
 
Cash and Cash Equivalents, end of year   $ 7,285,083   $ 7,598,666   $ 9,394,922  
   
 
 
 
Supplemental Disclosure of Cash Flow Information:                    
Cash paid during the period for interest   $ 1,427,835   $ 2,959,283   $ 5,306,920  
   
 
 
 

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

280



MARCH POINT COGENERATION COMPANY

NOTES TO FINANCIAL STATEMENTS

DECEMBER 31, 2002

1. NATURE OF OPERATIONS

        March Point Cogeneration Company (the Partnership) was organized under California law on July 28, 1989 as a general partnership between Texaco Anacortes Cogeneration Company (TACC), an indirect wholly-owned subsidiary of Texaco, Inc. and San Juan Energy Company (SJEC), an indirect wholly-owned subsidiary of Edison International (Edison). Effective January 1, 1998, Equilon Enterprises LLC (Equilon), a subsidiary of Shell Oil Products US, acquired 49.8 percent of TACC's 50 percent interest in the Partnership. On October 9, 2001 Texaco Inc. and Chevron Corp. merged to form ChevronTexaco Corp. During the year ended December 31, 2001, the partnership interest owned by TACC was acquired by Texaco March Point Holdings Inc. (TMPHI), an indirect wholly-owned subsidiary of ChevronTexaco Corp. This acquisition has been accounted for as a merger of companies under common control in which the historical ownership interest of TACC is presented as if historically owned by TMPHI. During the years ended December 31, 2002 and 2001 SJEC, TMPHI (TACC) and Equilon ownership ratios were 50 percent, 25.1 percent and 24.9 percent, respectively.

        The Partnership was organized to design, construct, own and operate a qualifying cogeneration facility (the Facility), as defined in the Public Utility Regulatory Policies Act of 1978 and the regulations promulgated thereunder, all as amended (PURPA), located in Skagit County, Washington. The Partnership currently sells all the electric energy generated by the facility to Puget Sound Energy, Inc. (Puget Sound Energy) for resale to its customers, and sells all steam produced to Equilon for use in its crude oil refining operations in its Puget Sound Refinery (PSR). The Facility was certified as a "qualifying facility" under PURPA prior to the start of operations, and management believes they have fulfilled all requirements to receive continued "qualifying facility" status.

        Partnership profit (loss) is allocated to the partners in proportion to their ownership percentages. The Partnership shall terminate, unless terminated at an earlier date pursuant to the general partnership agreement, on the latter of December 31, 2011 or the date the Partnership elects to cease operations.

        Construction of the Facility was done in two Phases (Phase I and Phase II). Phase I of the Facility consists of two gas combustion turbine-generators, which exhaust heat into two heat recovery steam generators (HRSG) producing electricity and steam sequentially using one fuel source. Phase II consists of one gas combustion turbine-generator, which exhausts heat into a HRSG, and a steam turbine-generator which accepts steam from Phase I and II to produce additional electricity. The Facility is designed to support the nominally rated production of 140 megawatts of electric energy and 476,000 pounds per hour of steam (exclusive of supplementary firing of the boilers), with Phase I nominally producing 80 megawatts and 320,000 pounds per hour and Phase II 60 megawatts and 156,000 pounds per hour.

2. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

Revenue Recognition

        Revenue is recognized as the product being sold is delivered.

Operating Facility and Equipment

        All costs (including interest and field overhead expenses) incurred during the construction and precommission phases of the Facility were capitalized as part of the cost of the Facility.

281



        The precommission phases were the periods starting with the testing of the turbines until the start of commercial operations for each phase.

        Revenues earned during the precommission phases were offset against the costs of the Facility. The Facility and related equipment are being depreciated on a straight-line basis, over 30 years, the estimated life of the Facility.

        Expenditures for maintenance, repairs and renewals are expensed as incurred. Expenditures for additions and improvements are capitalized.

Deferred Loan Fees

        All legal and financial fees associated with the Loan and Credit Agreement (see Note 3) were deferred and are being amortized, using the effective interest method, over the term of the loan.

Statements of Cash Flows

        For purposes of reporting cash flows, the Partnership considers short-term temporary cash investments with an original maturity of three months or less to be cash equivalents.

Change in Accounting Principle

        Effective January 1, 2001 the Partnership adopted Financial Accounting Standards Board Statement No. 133, Accounting for Derivative Instruments and Hedging Activities (SFAS 133). SFAS 133 establishes accounting and reporting standards requiring that derivative instruments be recorded on the balance sheet as either assets or liabilities measured at their fair value, unless the derivative meets a specific exception. SFAS 133 also requires that changes in a derivatives fair value be recognized currently in earnings unless specific hedge accounting criteria are met. The Partnership's Fuel Sale and Purchase Agreements and Power Purchase Agreements are considered derivatives under SFAS 133. As of the adoption of SFAS 133, the Partnership accounted for these contracts under the normal purchase and sale exception, which allows certain contracts to be accounted for using the accrual method of accounting. However, Derivatives Implementation Group Issue C11 (DIG Issue C11), which became effective July 1, 2001, precludes the TM Star Fuel Purchase Contract from continuing to qualify for the normal purchase and sale exception because the price of fuel purchased under the agreement is indexed to a broad inflation index and therefore the price paid is not viewed as being clearly and closely related to the gas being purchased. Subsequent to the implementation of DIG Issue C11, the Partnership accounted for the TM Star Fuel Purchase Contract as a cash flow hedge. As a result, the Partnership recorded an increase to Other Comprehensive Income of $24,584,225, reflecting the fair value of this contract as of July 1, 2001.

Use of Estimates

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

282



Fair Value of Financial Instruments

        The carrying amount of the short-term investments approximates fair value due to the short maturity of those instruments. The project financing loan payable and the working capital loan payable are variable interest rate loans and, based on the borrowing rates currently available to the Partnership for long-term debt with similar terms and maturities, the carrying amount of these loans approximates fair value.

Inventory

        The Partnership's inventory consists of spare parts, materials and supplies and is valued at the lower of average cost or market.

Income Taxes

        Income taxes are not recorded by the Partnership since the net income or loss allocated to the partners is included in their respective income tax returns.

3. LOAN AND CREDIT AGREEMENT

        On December 1, 1992, the Partnership entered into a Loan and Credit Agreement (the Agreement) with several banks for a combination of commitments, including a recurring $5 million short-term working capital loan, to extend loans aggregating up to $132 million (the Commitment). The Commitment of the banks to extend loans will be reduced on dates and by amounts specified in the Agreement through December 1, 2004 unless terminated earlier as provided for in the Agreement. The short-term working capital loan must be fully repaid for at least thirty consecutive days per year, but may be re-borrowed through December 1, 2004 unless terminated earlier. The Agreement places certain restrictions on capital distributions and permitted investments and further provides, among other things, that the Partnership pay a 0.375 percent commitment fee on the average daily balance of the unused portion of the Commitment. Amounts outstanding under the Agreement bear interest at the current Eurodollar market rate plus 1.30 percent and 1.30 percent in 2002 and 2001 (unaudited), respectively, or at the base rate, per annum. The interest rate on the outstanding loan balances at December 31, 2002 and 2001 was 1.43 percent and 3.53 percent, respectively. Substantially all of the assets of the Partnership are pledged as collateral for the Agreement. Interest is payable periodically throughout the year, as defined in the Agreement. The loan balance is payable in quarterly installments, with the final payment due on December 1, 2004. The debt paydown schedule, based upon the amount borrowed, at December 31, 2002 is as follows:

2003   $ 18,684,300
2004     13,724,400
   
    $ 32,408,700
   

        Throughout the term of the Agreement, the Partnership is required to maintain in an escrow account an amount equal to six months' interest expense, computed at ten percent of the aggregate

283



balance outstanding. The balance of the escrow account as of December 31, 2002 and 2001 (unaudited) was $1,620,435 and $2,272,165, respectively.

4. RELATED-PARTY TRANSACTIONS

Construction, Operating and Other Costs

        Edison, Equilon, and ChevronTexaco as well as their affiliates and subsidiaries are reimbursed for design, construction, operation and other costs incurred on behalf of the Partnership. The amounts incurred by Edison, Equilon, ChevronTexaco and their affiliates and subsidiaries for 2002, 2001 and 2000, which are not disclosed elsewhere, were as follows:

 
  2002
  2001
  2000
 
   
  (unaudited)

  (unaudited)

Equilon and subsidiaries   $ 141,703   $ 155,789   $ 176,153
ChevronTexaco and subsidiaries   $ 1,281,457   $ 1,281,035   $ 1,227,073

Land Lease

        The Partnership entered into a 20-year land lease with ChevronTexaco on January 3, 1991 which has been assigned to Equilon. Costs incurred under the land lease for 2002 and 2001 were nominal.

Fuel Sales and Purchase Agreements

        The Partnership has entered into long-term agreements for the purchase of fuel with TM Star Fuel Company (TM Star), a general partnership between Texaco Cogeneration Fuel Company, an indirect wholly owned subsidiary of ChevronTexaco, and Southern Sierra Gas Company, an affiliate of Edison.

        The daily contract quantity available under the TM Star agreement is 20,500 MMBtu per day. The price paid for gas under this contract consists of a transportation charge and a commodity charge, per MMBtu. Beginning January 1, 1993, the price paid for the commodity charge was $2.05 per MMBtu adjusted annually by the Gross Domestic Product Implicit Deflator (GDP), as defined ($2.44 per MMBtu as of December 31, 2002). The agreement also requires the Partnership to pay for the shortfall between the price received by TM Star and the contracted price of this agreement for any volume of gas, up to the daily contract quantity, not nominated by the Partnership. This agreement terminates on the earlier of December 31, 2011, the term of the power purchase agreement (see Note 5), or the written mutual consent of the parties. The agreement may be extended thereafter, on a yearly basis, upon mutual written consent. The amounts incurred under this agreement were $20,782,402, $21,896,518 and $20,345,704 for 2002, 2001 (unaudited) and 2000 (unaudited), respectively.

        As mentioned in Footnote 2 to these financial statements, the TM Star agreement is accounted for as a cash flow hedge. The fair value of the TM Star agreement is reflected as a Gas Purchase Agreement at Fair Value in the accompanying balance sheet. Amounts deferred in accumulated other comprehensive income are reclassified into earnings as fuel is purchased under the TM Star agreement. $14,228,312 and $847,462 of income representing hedge ineffectiveness was recorded as a reduction of plant and other operating expenses during the years ended December 31, 2002 and 2001 (unaudited), respectively. It is expected that within the next twelve months, gains of approximately $2,000,000 will be

284



reclassified from accumulated other comprehensive income to earnings. The movements of accumulated other comprehensive income during the years ended December 31, 2001 and 2002 were as follows:

Balance as of December 31, 2000 (unaudited)   $  
Cumulative effect on prior years of change in accounting for derivatives     24,584,225  
Unrealized holding loss arising during the period     (4,524,630 )
Reclassification adjustment included in net income     (2,793,717 )
   
 
Balance as of December 31, 2001 (unaudited)     17,265,878  
Unrealized holding loss arising during the period     (957,635 )
Reclassification adjustment included in net income     (1,787,741 )
   
 
Balance as of December 31, 2002   $ 14,520,502  
   
 

        Due to the significant increase in natural gas prices at the end of 2000 and beginning of 2001, the Partnership requested that TM Star re-market a portion of the natural gas it had under contract on the spot market. During December 2000 and January 2001, the Partnership received 80% of net profits from the re-marketing of the natural gas, after deduction of selling costs due to TM Star. Due to the sale of a portion of the natural gas, the Partnership replaced such raw material needs with low sulphur distillate fuel purchases from Equilon, which totaled $2,576,388 and $6,079,143 during the year ended December 31, 2001 (unaudited) and 2000 (unaudited).

        The Equilon Refinery Fuels Supply Agreement provides for a firm supply of manufactured refinery gas (MRG) from PSR to the Partnership. The Partnership must accept a minimum daily delivery of 10,000 MMBtu per day of MRG from Equilon in preference to other fuels. Additional interruptible MRG may be supplied at various volume tiers up to a final tier for total volumes over 16,000 MMBtu per day all as defined in the agreement. The pricing of MRG is based upon the weighted averages of the gas costs to the Partnership with discount factors applying to the various tiers, all as defined in the agreement. This agreement terminates on the earlier of December 31, 2011 or the mutual written consent of the parties. The amounts incurred under this agreement were $11,874,950, $11,121,031 (excluding Low Sulphur Distillate fuel purchases) and $9,365,674 for 2002, 2001 (unaudited) and 2000 (unaudited), respectively.

        Under typical operating conditions, approximately 80 percent of the Partnership's gas needs are procured under the aforementioned fixed price gas contracts. Fluctuations in the prices paid for gas under these contracts are implicitly tied to the revenues received for either power or steam. The Partnership purchases the remaining 20 percent of its gas needs on the spot market and thus may be exposed, in the short term, to fluctuations in the price of natural gas.

Operation and Maintenance Agreement

        The Partnership has an agreement with Equilon, whereby Equilon shall perform all operation and routine running maintenance activities necessary for the production of electrical energy and steam. The agreement will terminate August 20, 2012 or until terminated by either party. Equilon is paid for all costs incurred in connection with operating and maintaining the Facility. The amounts incurred under this agreement were $1,878,005, $1,678,067 and $1,501,605 for 2002, 2001 (unaudited) and 2000 (unaudited), respectively.

285



Steam Purchase and Sale Agreement

        The Partnership has entered into an agreement with Equilon, for the sale of steam generated by the Facility. The agreement terminates upon the earlier of December 31, 2011, or the mutual written agreement of the parties. Equilon pays the Partnership monthly for the steam delivered based upon the weighted average monthly cost of fuel gas and a steam discount and boiler efficiency factor, as defined in the agreement. Under this agreement, the purchases by Equilon are required to be sufficient for the Partnership to meet qualifying facility status.

5. COMMITMENTS AND CONTINGENCIES

Power Purchase Agreements

        The Partnership has entered into a Power Purchase Agreement with Puget Sound Energy for each phase of the Facility. The agreement for Phase I was executed and assigned to the Partnership on June 29, 1989. The agreement for Phase II was executed on December 27, 1990. These agreements will remain in effect until December 31, 2011. The Partnership provides, under the Phase I agreement, up to 90 megawatts of electrical output to Puget Sound Energy. For the Phase II agreement the Partnership provides approximately 60 megawatts of electrical output. Under Phase I and Phase II, the amount earned by the Partnership is based on the quantity of energy delivered times the sum of the individual variable rates (which are adjusted annually by the GDP) and the respective fixed rates (which differ during the summer or winter months).

        The Phase I and II agreements contain a termination clause which, upon the occurrence of certain events, could result in the Partnership paying a termination amount, as defined in the agreements to Puget Sound Energy. If an event of termination occurred as of December 31, 2002, the Partnership would be liable for approximately $140,190,000. Management has no reason to believe that the project will either terminate its performance or reduce its electric power producing capability during the term of the power contract in a manner which would result in the payment of a termination amount.

6. NEW ACCOUNTING PRONOUNCEMENTS

Statement of Financial Accounting Standards No. 143

        In August 2001, the Financial Accounting Standards Board issued Statement of Financial Accounting Standard No. 143, "Accounting for Asset Retirement Obligations," (SFAS No. 143) which became effective on January 1, 2003. SFAS No. 143 requires entities to record the fair value of a liability for an asset retirement obligation in the period in which it is incurred. When the liability is initially recorded, the entity capitalizes a cost by increasing the carrying amount of the related long-lived asset. Over time, the liability is increased to its present value each period, and the capitalized cost is depreciated over the useful life of the related asset. Upon settlement of the liability, an entity either settles the obligation for its recorded amount or incurs a gain or loss upon settlement. March Point does not expect the adoption of SFAS No. 143 to have a material impact on its financial statements.

286



Statement of Financial Accounting Standards Interpretation No. 46

        In January 2003, the Financial Accounting Standards Board issued Statement of Financial Accounting Standards Interpretation No. 46, "Consolidation of Variable Interest Entities" (FIN 46). This interpretation of Accounting Research Bulletin No. 51, "Consolidated Financial Statements," addresses consolidation by business enterprises of variable interest entities. The primary objective of the interpretation is to provide guidance on the identification of, and financial reporting for, entities over which control is achieved through means other than voting rights; such entities are known as variable-interest entities. This interpretation applies to variable interest entities created after January 31, 2003, and applies to variable interest entities in which the Partnership holds a variable interest that it acquired before February 1, 2003, beginning July 1, 2003. The Partnership does not expect this interpretation to have a material effect on its financial statements.

Statement of Financial Accounting Standards Interpretation No. 45

        In November 2002, the Financial Accounting Standards Board issued Statement of Financial Accounting Standards Interpretation No. 45, "Guarantor's Accounting and Disclosure Requirements for Guarantees, Including Indirect Guarantees of Indebtedness of Others." This interpretation establishes reporting requirements to be made by a guarantor about its obligations under certain guarantees that it has issued. It also clarifies that a guarantor is required to recognize, at the inception of a guarantee, a liability for the fair value of the obligation undertaken in issuing the guarantee. The initial recognition and initial measurement provisions of this interpretation are applicable on a prospective basis to guarantees issued or modified after December 31, 2002. The Partnership does not expect this interpretation to have a material effect on its financial statements.

287




REPORT OF INDEPENDENT ACCOUNTANTS

To the Board of Directors of
EcoEléctrica Holdings, Ltd. and Subsidiaries

        In our opinion, the accompanying consolidated balance sheet and the related consolidated statements of operations, comprehensive income (loss), changes in stockholders' equity, and cash flows present fairly, in all material respects, the financial position of EcoEléctrica Holdings, Ltd. and Subsidiaries (the "Company") as of December 31, 2002, and the results of its operations and its cash flows for the year then ended, in conformity with accounting principles generally accepted in the United States of America. These financial statements are the responsibility of the Company's management; our responsibility is to express an opinion on these financial statements based on our audit. We conducted our audit of these statements in accordance with auditing standards generally accepted in the United States of America, which require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, and evaluating the overall financial statement presentation. We believe that our audit provides a reasonable basis for our opinion.

        As further discussed in Note 2 to the accompanying financial statements, effective January 1, 2001, the Company changed its method of accounting for derivative instruments and hedging activities in accordance with Statement of Financial Accounting Standards No. 133, "Accounting for Derivative Instruments and Hedging Activities."

PricewaterhouseCoopers LLP

San Juan, Puerto Rico
February 7, 2003

CERTIFIED PUBLIC ACCOUNTANTS
(OF PUERTO RICO)
License No. 216 Expires Dec. 1, 2004
Stamp 1838523 of the P.R. Society of
Certified Public Accountants has been
affixed to the file copy of this report

288



ECOELÉCTRICA HOLDINGS, LTD. AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEETS

DECEMBER 31, 2002 AND 2001

 
  December 31,
 
 
  2002
  2001
 
 
   
  (unaudited)

 
 
  (in Thousands)

 
Assets              
Current Assets              
  Cash and cash equivalents   $ 10,025   $ 16,896  
  Current portion of restricted cash     11,088     6,161  
  Receivables:              
    Trade, net of allowance for doubtful accounts of $5,698 in 2002 and $3,467 in 2001     55,947     47,521  
    Insurance claim         12,100  
    Other, including amounts due from affiliates of $119 in 2002     347     1,131  
  Inventories     41,924     28,503  
  Prepaid expenses     1,713     581  
   
 
 
      Total current assets     121,044     112,893  
   
 
 
Noncurrent Assets              
  Restricted cash     5,181     1,547  
  Note and interest receivable from Puerto Rico Electric Power Authority     5,000     5,000  
  Property, plant and equipment, net     647,302     670,315  
  Debt issue cost, net     18,435     20,473  
  Deferred tax asset     5,704      
   
 
 
      Total noncurrent assets     681,622     697,335  
   
 
 
Total Assets   $ 802,666   $ 810,228  
   
 
 
Liabilities and Stockholder's Equity              
Current Liabilities              
  Current portion of loans payable   $ 18,695   $ 8,914  
  Accounts payable and accrued liabilities     14,315     29,269  
  Fair value of interest rate swap agreements     23,100     30,059  
   
 
 
      Total current liabilities     56,110     68,242  
   
 
 
Long-Term Liabilities              
  Working capital facilities     30,000     30,000  
  Loans payable     575,390     594,086  
  Deferred tax liability     2,356     1,147  
  Subordinated notes and accrued interest payable to affiliates     53,829     55,071  
  Fair value of interest rate swap agreements     58,383      
   
 
 
      Total long-term liabilities     719,958     680,304  
   
 
 
Total Liabilities     776,068     748,546  
   
 
 
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     67,000     67,000  
  Accumulated other comprehensive loss, net of deferred income tax of $5,704 in 2002     (75,779 )   (30,059 )
  Retained earnings     35,377     24,741  
   
 
 

Total Stockholders' Equity

 

 

26,598

 

 

61,682

 
   
 
 
Total Liabilities and Shareholder's Equity   $ 802,666   $ 810,228  
   
 
 

The accompanying notes are an integral part of these financial statements

289



ECOELÉCTRICA HOLDINGS, LTD. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF OPERATIONS

FOR THE YEARS ENDED DECEMBER 31, 2002, 2001 AND 2000

 
  Years Ended December 31,
 
 
  2002
  2001
  2000
 
 
   
  (unaudited)

 
 
  (in Thousands)

 
Revenues   $ 244,432   $ 233,437   $ 154,370  
Cost and operating expenses:                    
  Liquefied petroleum gas (LPG)     24     178     46,939  
  Liquefied natural gas (LNG)     115,135     99,383     37,647  
  Fuel oil No. 2     260     1,123     10,131  
  Depreciation and amortization     31,952     25,215     14,474  
  Salaries and related benefits     5,388     4,564     2,751  
  Technical and professional support     8,243     4,362     523  
  Repairs and maintenance     2,958     2,621     1,796  
  Utilities and communication     1,666     4,189     1,444  
  Provision for doubtful accounts     2,231     2,586     881  
  Insurance     5,573     2,031     830  
  Operations, maintenance and fuel management     1,201     885     818  
  Taxes other than income     3,125     1,210     772  
  LPG storage and service     817     625     734  
  Administrative services     876     1,386     486  
  Other operating expenses     3,978     1,948     955  
   
 
 
 
      183,427     152,306     121,181  
   
 
 
 
Operating income     61,005     81,131     33,189  
   
 
 
 

Other (income) expense:

 

 

 

 

 

 

 

 

 

 
  Interest expense     49,351     52,553     39,501  
  Interest income     (582 )   (734 )   (601 )
  Other expense     391     (3,575 )    
   
 
 
 
      49,160     48,244     38,900  
   
 
 
 
Income (loss) before income tax (provision) benefit     11,845     32,887     (5,711 )
Deferred income tax (provision) benefit     (1,209 )   (1,926 )   688  
   
 
 
 
Net income (loss)   $ 10,636   $ 30,961   $ (5,023 )
   
 
 
 

The accompanying notes are an integral part of these financial statements

290



ECOELÉCTRICA HOLDINGS, LTD. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (LOSS)

FOR THE YEARS ENDED DECEMBER 31, 2002, 2001 AND 2000

 
  Years Ended December 31,
 
 
  2002
  2001
  2000
 
 
   
  (unaudited)

 
 
  (in Thousands)

 
Net Income   $ 10,636   $ 30,961   $ (5,023 )

Other comprehensive loss:

 

 

 

 

 

 

 

 

 

 
  Cumulative effect on prior years of change in the method of accounting for interest rate protection agreements         (11,900 )    
 
Loss on interest rate protection agreements, net of deferred income tax of $5,704 in 2002:

 

 

 

 

 

 

 

 

 

 
    Unrealized holding loss arising during 2002     (65,517 )   (27,439 )    
    Reclassification adjustment for losses included in net income     19,797     9,280      
   
 
 
 
      (45,720 )   (30,059 )    
   
 
 
 
Comprehensive (loss) income   $ (35,084 ) $ 902   $ (5,023 )
   
 
 
 

The accompanying notes are an integral part of these financial statements

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ECOELÉCTRICA HOLDINGS, LTD. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF CHANGES IN STOCKHOLDERS' EQUITY

FOR THE YEARS ENDED DECEMBER 31, 2002, 2001 AND 2000

 
  Common
Stock
Class A
Shares

  Common
Stock
Class A
Amount

  Common
Stock
Class B
Shares

  Class B
Amount

  Additional
Paid-in
Capital

  Retained
Earnings

  Accumulated
Other
Comprehensive
Loss

  Total
 
 
  (in Thousands)

 
Balance at January 1, 2000 (unaudited)   100   $   100   $   $ 67,000   $ (1,197 ) $   $ 65,803  
  Net loss                     (5,023 )       (5,023 )
   
 
 
 
 
 
 
 
 
Balance at December 31, 2000 (unaudited)   100       100         67,000     (6,220 )       60,780  
  Net loss                     30,961         30,961  
  Cumulative effect to January 1, 2001, of change in the method of accounting for interest rate protection agreements                                     (11,900 )   (11,900 )
  Loss on interest rate protection agreements                         (18,159 )   (18,159 )
   
 
 
 
 
 
 
 
 
Balance at December 31, 2001 (unaudited)   100       100         67,000     24,741     (30,059 )   61,682  
  Net income                     10,636         10,636  
  Loss on interest rate protection agreements, net of tax of $5,704                         (45,720 )   (45,720 )
   
 
 
 
 
 
 
 
 
Balance at December 31, 2002   100   $   100   $   $ 67,000   $ 35,377   $ (75,779 ) $ 26,598  
   
 
 
 
 
 
 
 
 

The accompanying notes are an integral part of these financial statements

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ECOELÉCTRICA HOLDINGS, LTD. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF CASH FLOWS

FOR THE YEARS ENDED DECEMBER 31, 2002, 2001 AND 2000

 
  Years Ended December 31,
 
 
  2002
  2001
  2000
 
 
  (in Thousands)

 
Cash flow from operating activities:                    
  Net income   $ 10,636   $ 30,961   $ (5,023 )
   
 
 
 
Adjustments to reconcile net income to net cash provided by operating activities:                    
  Depreciation and amortization     31,952     25,215     14,474  
  Provision for doubtful accounts     2,231     2,586     881  
  Deferred income tax provision     1,209     1,926     (688 )
Changes in operating assets and liabilities that increase (decrease) cash:                    
  Receivables     2,227     (19,186 )   (32,056 )
  Inventories     (13,421 )   (10,495 )   (9,516 )
  Prepaid expenses     (1,132 )   (374 )   (207 )
  Accounts payable and accrued liabilities     (14,954 )   (16,250 )   (31,561 )
  Subordinated accrued interest payable     886     6,140     4,321  
   
 
 
 
      8,998     (10,438 )   (54,352 )
   
 
 
 
Net cash provided by (used in) operating activities     19,634     20,523     (59,375 )
   
 
 
 
Cash flow from investing activities:                    
  Capital expenditures     (6,901 )   (3,098 )   (61,594 )
  Restricted cash     (8,561 )   (7,708 )    
   
 
 
 
Net cash used in investing activities     (15,462 )   (10,806 )   (61,594 )
   
 
 
 
Cash flow from financing activities:                    
  Payments of principal on loans payable     (8,915 )       (67,000 )
  Payments of principal on subordinated debt     (2,128 )        
  Draws on loans payable         16,262     103,433  
  Draws on working capital facilities             18,000  
  Payments on working capital facilities         (18,000 )    
  Debt issue costs             (684 )
  Capital contribution from shareholders             67,000  
   
 
 
 
Net cash (used in) provided by financing activities     (11,043 )   (1,738 )   120,749  
   
 
 
 
Net (decrease) increase in cash and cash equivalents     (6,871 )   7,979     (220 )
Cash and cash equivalents, beginning of the year     16,896     8,917     9,137  
   
 
 
 
Cash and cash equivalents, end of the year   $ 10,025   $ 16,896   $ 8,917  
   
 
 
 
Supplemental cash flow information:                    
  Interest paid (net of $13,598 capitalized in 2000)   $ 48,477   $ 48,930   $ 38,247  
   
 
 
 
  Income tax paid   $   $   $  
   
 
 
 

The accompanying notes are an integral part of these financial statements

293



ECOELÉCTRICA HOLDINGS, LTD. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

DECEMBER 31, 2002, 2001 (UNAUDITED) AND 2000 (UNAUDITED)

1. Organization

        EcoElectrica Holdings, Ltd. (Holdings) is a Cayman Islands company that was formed to be the 99% limited partner of EcoElectrica, L.P. (the "Partnership") and to own 100% of EcoElectrica, Ltd., a Cayman Islands company, which is the 1% general partner of EcoElectrica, L.P. Holdings is 50% owned by Edison Mission Energy del Caribe, a Cayman Islands company limited by shares and an indirect wholly-owned subsidiary of Edison Mission Energy (EME), a California corporation, which is in turn wholly-owned by Edison International, and 50% owned by Buenergia Gas & Power Ltd., a Cayman Islands company limited by shares, which in turn in wholly-owned by Enron Corp. (Enron), an Oregon corporation.

        The Partnership, a development stage enterprise until March 21, 2000, is a Bermuda limited partnership formed on August 10, 1994, to develop, design, finance, construct, own and operate a combined-cycle natural gas-fired cogeneration facility of approximately 507 megawatts, a liquefied natural gas (LNG) import terminal and storage facility, a desalination facility and other auxillary assets (the Plant) in the Commonwealth of Puerto Rico. The electricity generated is sold to the Puerto Rico Electric Power Authority (PREPA), an instrumentality of the Commonwealth of Puerto Rico, and one of the largest electric utilities in the United States and its territories, among municipal electric utilities.

        The Power Plant (Phase I) was completed on March 14, 2000 and effective March 21, 2000, the Partnership commenced commercial operations. The LNG Terminal (Phase II) was completed on August 11, 2000.

2. Summary of Significant Accounting Policies

        The following is a summary of the accounting policies followed by Holdings in the preparation of the accompanying financial statements.

Basis of Presentation

        The accompanying consolidated financial statements, which include Holdings and its subsidiaries EcoElectrica, Ltd. and the Partnership, have been prepared in accordance with accounting principles generally accepted in the United States of America. All intercompany balances and transactions have been eliminated in consolidation.

Use of estimates

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

Revenue recognition

        Energy revenues derived from the conversion of fuel into electricity are recognized based on actual delivery of such converted electricity, in accordance with the power purchase contract between the Partnership and PREPA. Capacity revenues are recognized when earned.

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Fair Value of Financial Instruments

        The carrying amounts of cash and cash equivalents, restricted cash, receivables and accounts payable and accrued liabilities, approximate fair value because of the short maturity of these items. The estimated fair values of working capital facilities, loans payable and subordinated notes payable are based on quoted market values or on current interest rates offered for similar borrowings and approximate their carrying values.

        In addition, during 2000, Holdings derived a gain of approximately $5,400,000 on an LPG commodity swap. The gain on this commodity swap was recorded as a reduction of the commodity cost within the LPG caption of the accompanying statement of operations. No additional commodity swaps have been entered into by Holdings or its subsidiaries.

Statement of Cash Flows

        For purposes of reporting cash flows, Holdings and its consolidated subsidiaries consider all highly liquid investments with original maturities of three months or less to be cash equivalents.

Accounts Receivable

        Revenue billed is recorded as a current account receivable, including amounts in dispute with PREPA. An allowance for doubtful accounts is provided for amounts in dispute with PREPA based on management's estimate of realizability.

Inventories

        Inventories are stated at the lower of cost, determined on a first-in, first-out basis or market.

Interest during Construction

        Interest on borrowed funds was capitalized as part of Property, Plant and Equipment to the extent such interest was incurred on qualified capital expenditures. No interest was capitalized during 2002 and 2001.

Debt Issue Costs

        The Partnership capitalizes the costs incurred in connection with the issuance of debt. The capitalized debt issue costs are amortized over the term of the related debt.

Property, Plant and Equipment

        Property, plant and equipment are carried at cost (including capitalized interest) less accumulated depreciation and amortization. Depreciation and amortization are provided on a straight-line basis over the estimated useful lives of the respective assets. Major maintenance expenditures (overhauls) are capitalized and depreciated using the defer and amortize method over their estimated useful lives (the period of time from the initial overhaul to the next overhaul of same nature, 1.5-3 years) while minor maintenance is expensed as incurred. When property is retired or sold, the cost and the related

295



accumulated depreciation are removed from the accounts and any resulting gain or loss in credited or charged to operations.

Impairment of Long-Lived Assets

        Holdings and its consolidated subsidiaries evaluate their long-lived assets considering continued operating losses or significant and long-term changes in industry conditions as the primary indicators of potential impairment. An impairment is recognized when the future undiscounted cash flows of each asset is estimated to be insufficient to recover its carrying value. If such carrying value is not recoverable, the asset is written down to estimated fair value. Considerable management judgment is necessary to estimate future cash flows, accordingly, actual results could vary significantly from such estimates, requiring periodic revaluation based on current events or changes in circumstances. Based on these evaluations, there were no impairment adjustments to the carrying values of assets during 2002, 2001 and 2000.

Income Tax

        Holdings is treated as a limited partnership in the Cayman Islands for tax purposes and as such, is not a taxable entity in that jurisdiction. The Partnership is a Bermuda limited partnership, and as such, is not a taxable entity in the United States. Under Puerto Rico law, the Partnership is subject to local taxation. In accounting for income tax, the Partnership recognizes deferred tax assets and liabilities for the expected future tax consequences attributable to differences between tax basis of assets and liabilities and their reported amounts in the financial statements. In estimating future tax consequences, it considers all expected future events other than the enactment of changes in the tax law or rates. A valuation allowance is recognized for any deferred tax asset for which, based on management's evaluation, it is more likely that not that some portion or all of the deferred tax asset will not be realized.

Comprehensive Income (Loss)

        Comprehensive income (loss) includes net income and all changes to stockholders' equity during a period except those arising from transactions with shareholders. In addition to net income, the Partnership recognizes cash flow hedge gains or losses arising from interest rate swaps in other comprehensive income (loss).

Changes in Accounting Principles

        Effective January 1, 2001, the Partnership adopted Financial Accounting Standards Board Statement No. 133, "Accounting for Derivative Instruments and Hedging Activities," as amended by SFAS No. 138, "Accounting for Certain Derivative Instruments and Certain Hedging Activities". The implementation of these pronouncements resulted in the recognition of an "Accumulated Other Comprehensive Loss", a component of stockholders' equity, of approximately $11,900,000, related to interest rate swap agreements. Both, the power purchase contract with PREPA and the LNG supply agreement with Tractebel LNG North America, LLC, formerly CABOT LNG Corporation (refer to Note 3), are considered under either the normal purchase and sales exception under SFAS No. 138 or do not meet the definition of a derivative, therefore are accounted for on the accrual basis.

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        SFAS No. 133, as amended, requires an entity to recognize all derivatives as either assets or liabilities in the statement of financial position and to measure those instruments at fair value. If certain conditions are met, a derivative may be specifically designated as (a) a hedge of the exposure to changes in the fair value of a recognized asset or liability or an unrecognized firm commitment, (b) a hedge of the exposure to variable cash flows of a forecasted transaction, or (c) a hedge of the foreign currency exposure of a net investment in a foreign operation, an unrecognized firm commitment, an available-for-sale security, or a foreign-currency-denominated forecasted transaction. The accounting for changes in the fair value of a derivative depends on the intended use of the derivative and the resulting designation. The Partnership designated the interest rate swaps as a hedge of the cash flow from its variable rate loans. Accordingly, the fair value of the interest rate swap agreements is presented as a liability and a component of stockholders' equity net of related deferred taxes, through "Other Comprehensive Income (Loss)."

        SFAS No. 144 "Accounting for the Impairment or Disposal of Long-Lived Assets," was issued in August 2001. SFAS No. 144 addresses accounting and reporting for the impairment or disposal of long-lived assets by requiring that one accounting model be used for assets to be disposed of by sale, whether previously held and used or newly acquired, and by broadening the presentation of discontinued operations to include more disposal transactions. This statement is effective for fiscal years beginning after June 15, 2002. Holdings adopted this pronouncement in the first quarter of 2002. No assets have been impaired and/or disposed of as of December 31, 2002.

Recently Issued Accounting Standards

        SFAS No. 143, "Accounting for Asset Retirement Obligations," was issued in June 2001. SFAS No. 143 addresses accounting and reporting for legal obligations associated with the retirement of tangible long-lived assets and the associated asset retirement costs. This statement is effective for fiscal years beginning after June 15, 2002. The adoption of this statement will not have a significant effect on the consolidated financial statements of Holdings.

        Accounting for Costs Association with Exit or Disposal Activities.    In June 2002, the FASB issued SFAS No. 146, "Accounting for Costs Associated with Exit or Disposal Activities." SFAS No. 146 requires that a liability for a cost associated with an exit or disposal activity be recognized when the liability is incurred. The provisions of this statement are effective for exit or disposal activities that are initiated after December 31, 2002. The adoption of this statement will not have a significant effect on the consolidated financial statements of Holdings.

        Guarantor's Accounting and Disclosure Requirements for Guarantees.    In November 2002, the FASB issued interpretation ("FIN") No. 45 "Guarantees." This interpretation requires guarantor of certain types of guarantees to recognize, at the inception of the guarantee, a liability for the fair value of the obligation undertaken in issuing the guarantee. The provisions for initial recognition are effective for guarantees that are issued or modified after December 31, 2002. The adoption of FIN No. 45 will not have a material impact on the consolidated financial statements of Holdings.

        In January 2003, the FASB issued FIN No. 46, "Consolidation of Variable Interest Entities, an interpretation of ARB 51." This interpretation provides guidance on the identification of entities for which control is achieved through means other than through voting rights and how to determine when

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and which entities should be consolidated. The application of this interpretation is required in all financial statements initially issued after January 31, 2003. The adoption of FIN No. 46 will not have any impact on the consolidated financial statements of Holdings.

Reclassifications

        Certain reclassifications were made to the 2001 and 2000 financial statements to conform these with the 2002 presentation.

3. Agreements

Power Purchase Contract

        On March 10, 1995, the Partnership and PREPA entered into a power purchase contract (the PPA) under which PREPA is entitled to make energy and capacity payments to the Partnership commencing on March 21, 2000 (date in which the Partnership started commercial operations) (COD) and continuing for the 22-year term of the PPA (operating period). Energy payments are based on the actual output of electric power from the Plant and are intended to cover fuel costs. Capacity payments are intended to cover operating and maintenance costs, debt service, taxes and a return on investment.

        The PPA requires that the Partnership maintain a minimum working capital of $4 million on the COD, $8 million by the end of the first agreement year, $12 million by the end of the second year and $20 million by the end of the third year and thereafter. A portion of the minimum working capital requirement should be in cash deposited in a financial institution. The cash deposit should be reduced by any amount properly invoiced to PREPA under this agreement and not paid when due. As of December 31, 2002, amounts owed by PREPA to the Partnership exceed the cash deposit requirements.

        Energy and capacity revenues under the PPA for the years ended December 31, 2002, 2001, and 2000 were as follows (in thousands):

 
  2002
  2001
  2000
Energy   $ 116,500   $ 101,960   $ 66,427
Capacity     127,932     131,477     87,943
   
 
 
    $ 244,432   $ 233,437   $ 154,370
   
 
 

Construction Contracts

        On October 31, 1997, the Partnership entered into an amended and restated offshore design and supply contract (the Supply Contract) with Enron Equipment Procurement Company (Enron Procurement) and an amended and restated onshore construction contract (the Onshore Contract) with Enron Power I (Puerto Rico), Inc., both indirectly wholly owned subsidiaries of Enron Corp. Under the Supply Contract, Enron Procurement provided concept design, engineering and procurement services, and supplied power generating equipment to the Plant outside of Puerto Rico on fixed-price basis. Under the Onshore Contract, Enron Power I (Puerto Rico), Inc. provided detailed design, engineering and procurement services of materials sourced in Puerto Rico, and construction services for the Plant on a fixed-price basis. Expenditures under both contracts amounted to approximately $450,000,000.

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Administrative Services Agreement

        The Partnership entered into an Administrative Services Agreement as of October 31, 1997 with EME (Administrative Manger), to provide administrative and other support services in connection with the financing, construction and operation of the Plant.

        The Partnership agreed to pay the Administrative Manager all the reimbursable costs incurred plus administrative fees of $500,000 while the Plant was under construction and $42,000 per month (escalating from January 1, 1997, in accordance with the Puerto Rico Consumer Price Index (CPI)) during the operating period. The Partnership incurred charges under this agreement of $876,000, $1,386,000 and $486,000 for the years ended December 31, 2002, 2001 and 2000.

Operations, Maintenance and Fuels Management Agreement

        The Partnership has entered into an Operation, Maintenance and Fuels Management Agreement dated as of October 31, 1997 (the OMF Agreement) with El Puerto Rico Operations Inc. (OMF Manager), an indirectly wholly-owned subsidiary of Enron, for the management of the operations and maintenance of the Plant, as well as all aspects of the purchase, transportation, delivery and storage of fuel for the Plant.

        The Partnership agreed to pay the OMF Manager certain reimbursable costs, a Phase I start-up fee of $500,000 and monthly operating and fuel management fees of $42,000 and $29,000, respectively, (escalating from January 1, 1997, in accordance with the Puerto Rico CPI) during the operating period. The Partnership incurred charges under this agreement of approximately $1,201,000, $885,000 and $818,000 million for the years ended December 31, 2002, 2001 and 2000, respectively.

LPG Storage and Service Agreement

        The Partnership entered into a LPG Storage and Service Agreement (the Agreement) dated as of October 31, 1997, with ProCaribe Division of the Protane Corporation (ProCaribe), an indirect wholly owned subsidiary of Enron Corp. Under the Agreement, ProCaribe will act as a terminal operator mainly providing LPG unloading, storage and redelivery services to the Partnership. The Agreement, which term extends through December 31, 2020, sets forth an annual compensation for ProCaribe's services comprised of a base annual fee of $75,000, payable on a monthly basis, and reimbursable incremental costs, as defined in the Agreement. The base annual fee of $75,000 will be adjusted each January 1, according to the increase in the Puerto Rico Consumer Price Index as compared to the January 1, 1997 index. ProCaribe provided services and charged reimbursable incremental costs to EcoElectrica under the Agreement amounting to approximately $817,000, $625,000 and $734,000 for the years ended December 31, 2002, 2001 and 2000.

        In addition, the Agreement provides for the borrowing and lending of LPG to each other. ProCaribe borrowed from the Partnership LPG amounting to approximately $2,912,000 and $2,311,000 during the years ended December 31, 2001 and 2000. During 2002 ProCaribe purchased LPG from the Partnership for approximately $118,800.

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LNG Supply Agreement

        The Partnership entered into a LNG Supply Agreement with Tractebel LNG North America, LLC, (Tractebel), formerly CABOT LNG Corporation, whereby the Partnership is committed to purchase and Tractebel committed to supply, an annual contract supply of liquefied natural gas, as stipulated in the agreement, until September 2019. Charges under this agreement include a commodity charge on LNG supplied based on NYMEX and the Puerto Rico CPI, availability demand charges regardless of actual LNG deliveries. Commodity and demand charges from Tractebel for the years ended December 31, 2002, 2001 and 2000, were as follows (in thousands):

 
  2002
  2001
  2000
Commodity   $ 84,405   $ 79,128   $ 29,881
Demand     23,893     22,790     19,964
   
 
 
    $ 108,298   $ 101,918   $ 49,845
   
 
 

        On December 13, 2002, the Partnership and Tractebel signed a Letter Agreement that amended the LNG supply agreement for the year 2003 only. This Letter Agreement provides for 100% supply of LNG to the Partnership, a five (5) cents commodity price reduction and the elimination of the commodity surcharge, all for the year 2003 only. The Lenders were duly notified and did not oppose the execution of the agreement.

Depository Agreement

        On October 31, 1997, the Partnership entered into a depository and disbursement agreement (the Depository Agreement) with a financial institution as collateral and depository agent, whereby the depository agent will hold and administer monies deposited in the various accounts established at the financial institution as depository bank pursuant to the Depository Agreement. As part of the Depository Agreement, besides the cash accounts, the following cash reserves are required: an interest reserve, a principal reserve, a major maintenance reserve, a construction reserve, a distribution reserve, a collateral reserve, a guarantee reserve, an income tax reserve and a fuel supply interruption reserve. The amounts deposited in the Interest Reserve shall be applied to pay interest expenses. The Principal Reserve is a short-term reserve funded throughout each month of the quarter, to pay the corresponding principal installment due at the end of the quarter. The amount deposited in the Major Maintenance reserve account shall be applied to pay for expenditures by the Partnership for regularly scheduled (or reasonably anticipated) major maintenance of the Plant. The amounts deposited in the Construction Account shall be applied to completing certain construction punchlist items that were pending upon conversion of interim construction loans to term loans. The amounts deposited in the Distribution Reserve shall be used for payment of dividends to stockholders. The collateral reserve is a cash deposit reserve held as collateral for increases to the PREPA Operating Security Letter of Credit. The Guarantee reserve is a cash deposit with an insurance company as collateral for a bond in favor of PREPA that serve as a guarantee of a back feed power contract. The amounts deposited in the income tax reserve shall be applied to pay income tax. Amounts deposited in the fuel supply interruption reserve shall be used for payment of principal and interest on the debt in case there is a business

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interruption. The fuel supply interruption reserve should increase on a quarterly basis as established in the credit agreement. As of December 31, the balances of the reserves were as follows:

 
  2002
  2001
 
   
  (unaudited)

Current portion:            
  Interest reserve   $ 59   $
  Principal reserve     25    
  Major maintenance reserve     2,323     3,674
  Construction reserve     1,409     1,389
  Distribution reserve     4,490    
  Collateral reserve     2,282     1,098
  Guarantee reserve     500    
   
 
    $ 11,088   $ 6,161
   
 
Non-current portion:            
  Income tax reserve   $ 2,696   $
  Fuel management reserve     2,485     1,547
   
 
    $ 5,181   $ 1,547
   
 

        Interest, Principal, Major Maintenance, Construction, Distribution, Collateral and Guarantee Reserves are presented as Restricted Cash in the current assets section of the accompanying consolidated balance sheet. The income tax and the fuel reserve are presented as Restricted Cash in the non-current assets section.

Interest Rate Protection Agreement

        The Partnership enters into interest rate swap agreements to fix the interest rates on loans payable. Interest rate swaps are agreements to exchange interest rate payment streams based on a notional principal amount. The fair value of interest rate swaps is the estimated amount that the Partnership would receive or pay to terminate the swap agreements at the reporting date, taking into account current interest rates and the current credit worthiness of the swap counterparties.

        Under Interest Rate Protection Agreements with ABN AMRO and Banque Paribas, the Partnership contracted a fixed interest rate of 6.385% and 6.365% over approximately 77% of its outstanding long-term debt. The provisions of these agreements require payment by ABN AMRO and Banque Paribas to the Partnership for the excess of the current LIBOR rate over the fixed interest rate or for the Partnership to pay ABN AMRO and Banque Paribas for the difference between the fixed interest rate and the current LIBOR rate, if the latter is lower.

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        As of December 31, 2002, 2001 and 2000, the Partnership has outstanding interest rate swap agreements, with notional amount of approximately $464,421,000 (2001—$471,734,000). The weighted average rate paid and received on these agreements was 6.383% and 1.90237% in 2002, 6.385% and 3.483% in 2001; and 6.385% and 6.472% in 2000, respectively. The net interest rate differentials paid (received), recorded as adjustments to interest expense, amounted to approximately $21,287,000, $9,280,000 and ($414,000) for the years ended December 31, 2002, 2001 and 2000. No hedge ineffectiveness has been recognized because this hedge is deemed to be 100% effective.

        At December 31, 2002, the Interest Rate Protection Agreements mature as follows:

Counterparty

  Date
  Maturity
  Notional
Amount

 
   
   
  (million)

ABN AMRO   10/2/2000   12/15/2017   $ 45,797
ABN AMRO   12/29/2000   3/31/2016     199,185
Banque Paribas   12/15/1999   12/17/2017     192,499
Banque Paribas   10/2/2000   12/15/2017     26,940

        The fair value of the swap agreements liability at December 31, 2002 and 2001 was $81,483,000 and $30,059,000, respectively. As of December 31, 2002, the loss deferred in accumulated other comprehensive income expected to be reclassified within the next year amounts to $23,100,000.

4. Accounts Receivable

        Accounts Receivable include amounts past due from PREPA that started to accumulate since the beginning of commercial operations and continue to increase as monthly withholdings continue to be made. There are various reasons for the withholdings by PREPA, which are rooted in the interpretations of various contract provisions. The larges amount withheld relates to the interpretation of a base value in the Energy Payment formula. Management has been working with PREPA since the withholdings began, to achieve a successful resolution of these disputes, but no agreement has been reached. As of December 31, 2002 $20,903,000 (2001—$13,025,000) of the receivables from PREPA are under dispute for which a bad debt allowance of $5,698,000 (2001—$3,467,000) has been provided based on management's estimate of realizability.

5. Insurance Claims Receivable

        During 2000, the Partnership suffered losses due to several mechanical failures of its combustion turbines. The Partnership filed claims related to year 2000 under the business interruption, property damage and builders all-risk insurance policies. An insurance claims receivable of approximately $15,700,000, was recorded as of December 31, 2000, of which $14,000,000 were collected in 2001 and $1,700,000 were collected in 2002.

        During 2001, the Partnership filed claims for an additional $10,400,000 which was collected in full in 2002.

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6. Note and Interest Receivable from PREPA

        In December 1997, the Partnership made a $5,000,000 loan to PREPA (the PREPA Loan). This loan matures five years after the completion of construction and will be repaid in a single balloon payment in October 2004. Interest is accrued at LIBOR minus 3% and paid annually. No interest income was earned in year 2002, due to the fact that the 3% exceeded the LIBOR rate.

7. Inventories

        As of December 31, inventories consist of the following (in thousands):

 
  2002
  2001
 
   
  (unaudited)

Liquefied natural gas (LNG)   $ 5,786   $ 13,172
Liquefied petroleum gas (LPG)     2,779     3,039
Fuel oil No. 2     4,006     2,513
Spare parts and supplies, including $13,481, of inventory in transit in 2002     29,353     9,779
   
 
    $ 41,924   $ 28,503
   
 

8. Property, Plant and Equipment

        As of December 31, property, plant and equipment consist of the following:

 
  Estimated
Useful Lives

  2002
  2001
 
 
  (in years)

   
  (unaudited)

 
 
   
  (in Thousands)

 
Machinery and equipment   35   $ 447,144   $ 446,958  
LNG and LPG facilities and equipment   22–50     209,039     208,886  
Buildings   30     18,146     18,266  
Major maintenance expenditures   1.5–3     29,447     22,339  
Fuel oil facilities   50     2,946     2,942  
Furniture and fixtures   10     538     529  
Vehicles and equipment   3     167     207  
       
 
 
          707,427     700,127  
Less: Accumulated depreciation and amortization         (66,902 )   (36,989 )
       
 
 
          640,525     663,138  
Land and land improvements         5,350     5,389  
Construction in progress         1,427     1,788  
       
 
 
        $ 647,302   $ 670,315  
       
 
 

9. Working Capital Facilities

        As of December 31, 2000, the Partnership had drawn $48,000,000 under Working Capital Facilities to fund the ongoing working capital needs, primarily fuel expenses, which are not expected to match the timing of the Partnership's revenues on a monthly basis. These facilities consist of two lines of

303



credit of $9,000,000 and $30,000,000, respectively, payable to a financial institution and a line of credit of $9,000,000 payable to Enron LNG Power (Atlantic) Ltd., an indirectly wholly-owned subsidiary of Enron. Both lines of credit of $9,000,000 were paid in full during 2001.

        Draws on the Working Capital facilities of $9,000,000 and $30,000,000 are subject to a borrowing base tied to the fuel inventory and receivables from PREPA. Also up to $8,000,000 can be drawn and held in a segregated sub-account subject to lenders' lien to satisfy certain liquidity requirements in the PPA. The Working Capital facilities have an annual, five consecutive day clean-up feature, for amounts not considered current asset loans, as defined. This clean-up feature does not apply to the $8,000,000. To the extent that the Working Capital facilities are not refinanced or extended at its initial maturity date, $8,000,000 of Working Capital loans drawn to satisfy the PPA liquidity requirements may be amortized along with the Tranche A loans on a pro rata basis (see Note 8). The $30,000,000 Working Capital facilities mature on June 15, 2005, has a commitment fee of 0.375%, and bears interest at LIBOR (1.8125% at December 31, 2002) plus 1.125%.

10. Loans Payable

        In December 1997, the Partnership obtained a construction/term loan facility of approximately $614,000,000. As of December 31, loans payable comprised of the following:

 
  Maturity
  Commitment
Fee

  Interest
Over

  Rate
LIBOR

  2002
  2001
 
   
   
   
   
   
  (unaudited)
Term Loans:                            
  Tranche A Loan   June 15, 2016   0.375 % Construction   1.125 % $ 486,325   $ 495,240
  Tranche B Loan   June 15, 2018   0.375 % Years 1–5   1.375 %   107,760     107,760
            Years 6–10   1.750 %          
            Years 11–16   2.000 %          
            Years 16–18   2.500 %          
                   
 
Total loans payable                     594,085     603,000
Less: current portion                     18,695     8,914
                   
 
                    $ 575,390   $ 594,086
                   
 

        As of December 31, 2002, two installments in the amount of $4,457,000 each had been paid; future maturities of long-term debt are as follows:

Year

  (In thousands)
2003   $ 18,695
2004     20,528
2005     22,632
2006     24,911
2007     27,362
Thereafter     479,957
   
    $ 594,085
   

304


        The construction loans were due 18 months after the Phase I Basic Term-Out date of June 15, 2000. The Phase I and Phase II construction loans were converted to term loans on September 20, 2001. Quarterly amortization payments for Tranche A and Tranche B will commence in approximately 15 months and in the first quarter of the 17th year, respectively, after the Basic Term-Out date. The balance on the loan facility was collateralized by the Partnership's assets and bears interest at LIBOR (1.40% at December 31, 2002) plus 1.750% payable quarterly.

11. Subordinated Notes Payable

        EME and Enron Development Corp. (EDC), an indirectly wholly owned subsidiary of Enron, and certain of their affiliates incurred costs on behalf of the Partnership during the construction phase. These costs are recorded as part of Property, plant and equipment with corresponding amounts recorded as Subordinated notes payable and Accrued interest payable to EME and EDC which at December 31, are as follows:

 
  2002
  2001
 
   
  (unaudited)

Subordinated notes payable—Edison Mission Energy   $ 20,000   $ 22,064
Subordinated notes payable—Enron Development Corp.     12,000     12,064
Subordinated accrued interest payable—Edison Mission Energy     14,235     13,540
Subordinated accrued interest payable—Enron Development Corp.     7,594     7,403
   
 
    $ 53,829   $ 55,071
   
 

        The notes bear interest at the lesser of 12 percent compounded quarterly or the maximum non-usurious rate of interest under New York law. These amounts are subordinated to any amounts due under the Credit Facilities and can only be paid out of cash otherwise available for distribution to the partners. In November 8, 2002, $8,000,000 (including interest of $5,872,000) were paid to EME and EDC.

12. Debt Service Reserve Loan Facility

        The Partnership also obtained a $19 million Debt Service Reserve Loan Facility which acts as an alternative to a funded debt service reserve and is available to fund debt service shortfalls. Any draws on the Debt Service Reserve Loan Facility will be repaid out of all excess cash flow. In the event that debt service coverage ratios in any one of the three years prior to maturity of the Debt Service Reserve Loan Facility are less than 1.4, the facility will be fully drawn and deposited into a Debt Service Reserve Account, with the reimbursement obligation amortized on a pro rata basis with the Tranche A facility. Thereafter, any draws on the Debt Service Reserve Account will be replenished by all excess cash flow after debt service. The Debt Service Reserve Loan Facility matures 10 years after the completion of construction, has a commitment fee of 0.375%, bears interest at LIBOR plus 2.125% during year 1–5 and LIBOR plus 2.35% during years 6–10. As of December 31, 2002, no amounts have been drawn under this facility.

305



13. PREPA Letter of Credit Facility

        Pursuant to the terms of the PPA, the Partnership, has provided an operating security instrument after commercial operation in the form of a standby letter of credit from a financial institution. The facility may be drawn upon only if the Plant causes a breach under the PPA, up to a maximum of approximately $15,210,000. PREPA's ability to draw on the facility will be reduced by amounts outstanding under the PREPA Loan (see Note 5). The operating security was issued when the Plant commenced commercial operations and will mature December 15, 2007. The obligation with PREPA to replenish any amounts drawn on the facility is due within 90 days. The obligation with the financial institution for any amounts drawn on the facility prior to the first principal payment on the Tranche A Loan, is to repay in the same proportion and during the same periods as provided for in the Tranche A Loan amortization schedule. The obligation with the financial institution for any amounts drawn after the first principal payment date of the Tranche A Loan is to repay based on the remaining principal payment dates with the amortization percentage increased, on a pro rata basis, by the percentage attributable to each prior principal payment date. The facility has a commitment fee of 0.375% and bears interest at LIBOR plus 1.125% during years 1–5 of operations and LIBOR plus 1.375% during years 6–10 of operations. As of December 31, 2002, no amounts were outstanding under this facility.

        The Partnership is also required, pursuant to the terms of the PPA, to increase the letter of credit at a compound annual escalation rate of 7% throughout the remainder of the facility. However, as long as the Partnership achieves certain goals, no further escalation shall apply. As of December 31, 2002, the letter of credit issued has been escalated to approximately $12,414,000 (net of the $5 million note receivable from PREPA), for which $2,233,000 was posted as cash collateral which is presented, including interest, as non-current Restricted Cash in the accompanying consolidated balance sheet at December 31, 2002.

14. Fuel Performance Letter of Credit Facility

        Pursuant to the terms of the LNG Sales Contract entered into between Tractebel and the Partnership, the Partnership is required to purchase certain fuel requirements of the Plant from Tractebel. The Partnership, as required, has provided a standby letter of credit from a financial institution to Tractebel. The $30 million facility will mature December 15, 2007, has a commitment fee of 0.375%, bears interest at LIBOR plus 1.0% during construction, LIBOR plus 1.125% during years 1–5 of operations and LIBOR plus 1.375% during years 6–8 of operations. This facility will be used to secure the Partnership's ongoing liabilities to Tractebel in connection with periodic LNG purchases. As fuel expenses are the first expenses paid out of the Plant's operating account, the facility is not expected to be drawn. However, if drawn, reimbursement obligations will be due within 5 days and will be paid out of the operating account in the same priority order as fuel expenses. As of December 31, 2002, no amounts have been drawn under this facility.

15. Income Tax

        The Partnership is partially exempt from Puerto Rico income and property taxes under the provision of the Puerto Rico Industrial Incentives Act of 1987, as amended. This grant is effective for the twenty taxable years succeeding the year of commencement of commercial operations, and provides for a 7% flat rate for income tax and a 90% exemption from property taxes. Pursuant to the grant's provision, the Partnership shall have the option to deduct the total costs incurred after January 1, 1998,

306



in the purchase, acquisition, construction, and/or installation of facilities to be utilized in the cogeneration plant in the taxable year that the cost is incurred. The excess of this deduction over the Partnership's industrial development income (IDI) subject to the 7% tax rate for the taxable year in which the costs were incurred may be carried forward to offset such IDI in subsequent taxable years, until exhausted. As a result of this deduction, the Partnership's did not incur in a current income tax liability in 2002, 2001 and 2000. A deferred tax liability has been recognized for this deduction.

        The Partnership's effective tax rate differs from the applicable Puerto Rico statutory income tax rate due to the following:

 
  2002
Amount

  2002
%

  2001
Amount

  2001
%

  2000
Amount

  2000
%

 
 
   
   
  (unaudited)

   
  (unaudited)

   
 
Income tax benefit (provision) at the statutory rate of 39%   $ (4,620 ) (39.0 ) $ (12,826 ) (39.0 ) $ 4,342   39.0  
Exemption on industrial development income     3,790   32.0     10,524   32.0     (3,563 ) (32.0 )
Other     (379 ) (3.2 )   376   1.1     (91 ) (0.8 )
   
     
     
     
Income tax benefit (provision)   $ (1,209 ) (10.2 ) $ (1,926 ) (5.9 ) $ 688   6.2  
   
     
     
     

        The components of deferred income tax liabilities or assets as of December 31, 2002, is as follows (in thousands):

 
  2002
  2001
 
 
   
  (unaudited)

 
Deferred tax (liabilities) assets:              
  Construction and installation costs   $ (2,755 ) $ (1,390 )
  Allowance for doubtful accounts     399     243  
   
 
 
    Net deferred tax liability   $ (2,356 ) $ (1,147 )
   
 
 

        The deferred tax asset of $5,704 at December 31, 2002 relates exclusively to the other comprehensive loss.

16. Savings Plan

        Effective January 1, 1999, the Partnership established a savings plan for all eligible non-union employees of the Partnership. Participants may contribute from 1% to 10% of their annual pre-tax compensation up to a maximum of $8,000. The Partnership's matching contribution is 50% of the first 6% of a participant's annual contribution. Effective January 1, 2002, the Partnership agreed with the United Steel Workers of America to establish a savings plan for all eligible union employees with substantially the same provisions as the non-union plan. The Partnership's contribution to these plans during 2002, 2001 and 2000 amounted to approximately $54,000, $41,000 and $62,500, respectively, which is expensed as salaries and related benefits.

307



17. Commitments and Contingencies

        In addition to the commitments and contingencies disclosed in the other notes to the accompanying financial statements, following are some related leases and to legal and administrative procedures.

Leases

        The Partnership leases its administrative office facilities under an operating lease agreement expiring in August 2006. During 2002, 2001 and 2000, rental expense was approximately $123,000, $110,000 and $90,000, respectively, including basic rent plus a proportionate share of taxes, operating and maintenance expenses.

        Future minimum annual lease payments are as follows (in thousands):

Year

  Amount
2003   $ 80
2004     80
2005     80
2006     54
   
    $ 294
   

Contingencies

        During March 2000, the United States Environmental Protection Agency (the EPA) issued a Notice of Violation (NOV) and a Compliance Order (CO) to the Partnership in connection with alleged violations of the Clean Air Act. The Partnership is currently working with the EPA to address those issues and does not believe the NOV or CO will have a material adverse effect on its financial position or results of operations.

        The Partnership is involved in various other legal and administrative actions, generally related to its operations. Management believes that, based on advice from legal counsel, the outcome of such actions will not have a material adverse effect on the financial position or results of operations of the Partnership.

308



REPORT OF INDEPENDENT ACCOUNTANTS

To the Management Committee of
Gordonsville Energy, L.P.:

        In our opinion, the accompanying balance sheet as of December 31, 2002 and the related statements of income and comprehensive income, partners' equity, and cash flows present fairly, in all material respects, the financial position of Gordonsville Energy, L.P. (a Delaware limited partnership) at December 31, 2002, and the results of its operations and its cash flows for the year then ended in conformity with accounting principles generally accepted in the United States of America. These financial statements are the responsibility of the Partnership's management; our responsibility is to express an opinion on these financial statements based on our audit. We conducted our audit of these statements in accordance with auditing standards generally accepted in the United States of America, which require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, and evaluating the overall financial statement presentation. We believe that our audit provides a reasonable basis for our opinion.

        As explained in Note 2 to the financial statements, effective January 1, 2001, Gordonsville Energy, L.P. changed its method for accounting for major maintenance costs from "accrue in advance" method to expensing the costs as they are incurred and as explained in Note 3 effective January 1, 2001, Gordonsville Energy, L.P. adopted and implemented Statement of Financial Accounting Standards No. 133 and No. 138 related to the accounting for derivatives.

PricewaterhouseCoopers LLP

Los Angeles, California
March 14, 2003

309



GORDONSVILLE ENERGY, L.P.

BALANCE SHEETS

DECEMBER 31, 2002 AND 2001 (UNAUDITED)

 
  2002
  2001
 
   
  (unaudited)

Assets            

Current assets:

 

 

 

 

 

 
  Cash and cash equivalents   $ 2,798,660   $ 3,850,546
  Accounts receivable     7,379,907     6,387,536
  Inventory     3,834,235     4,648,774
  Prepaid and other     427,869     105,242
   
 
    Total current assets     14,440,671     14,992,098
   
 

Property, plant and equipment, net

 

 

140,873,103

 

 

147,511,382

Other assets:

 

 

 

 

 

 
  Deferred financing costs, net     2,724,497     3,149,095
  Debt service reserves     10,335,835     10,329,656
   
 
    Total assets   $ 168,374,106   $ 175,982,231
   
 

Liabilities and Partners' Equity

 

 

 

 

 

 

Current liabilities:

 

 

 

 

 

 
  Current portion of long-term debt   $ 13,477,860   $ 12,742,704
  Accounts payable     1,594,582     2,119,958
  Interest payable     587,141     632,743
  Liability under interest rate swap     8,868,554     3,544,255
   
 
    Total current liabilities     24,528,137     19,039,660

Long-term debt, net of current portion

 

 

80,540,434

 

 

94,018,294
   
 
    Total liabilities     105,068,571     113,057,954
   
 
Commitments and contingencies (Note 10)            
Partners' equity     63,305,535     62,924,277
   
 
   
Total liabilities and partners' equity

 

$

168,374,106

 

$

175,982,231
   
 

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

310



GORDONSVILLE ENERGY, L.P.

STATEMENTS OF INCOME AND COMPREHENSIVE INCOME

FOR THE YEARS ENDED DECEMBER 31, 2002, 2001 (UNAUDITED) AND 2000 (UNAUDITED)

 
  2002
  2001
  2000
 
   
  (unaudited)

  (unaudited)

Revenues:                  
  Sales of capacity and electricity   $ 40,296,940   $ 38,162,841   $ 42,256,949
  Sales of steam     9,997     9,383     14,414
  Interest income     311,416     694,157     993,517
   
 
 
    Total revenues     40,618,353     38,866,381     43,264,880
   
 
 
Expenses:                  
  Operations and maintenance     12,611,865     13,770,719     15,427,517
  General and administrative     3,191,946     2,309,907     2,105,954
  Depreciation and amortization     7,181,522     7,440,514     7,503,755
  Interest expense     7,677,463     8,450,798     9,363,725
   
 
 
    Total expenses     30,662,796     31,971,938     34,400,951
   
 
 
Income before change in accounting principle     9,955,557     6,894,443     8,863,929
Cumulative effect on prior years of change in accounting for major maintenance costs         844,809    
   
 
 
    Net income     9,955,557     7,739,252     8,863,929
Other comprehensive (loss) income     (5,324,299 )   (3,544,255 )  
   
 
 
    Comprehensive income (loss)   $ 4,631,258   $ 4,194,997   $ 8,863,929
   
 
 

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

311



GORDONSVILLE ENERGY, L.P.

STATEMENTS OF CHANGES IN PARTNERS' EQUITY

FOR THE YEARS ENDED DECEMBER 31, 2002, 2001 (UNAUDITED) AND 2000 (UNAUDITED)

 
  Madison
Energy
Company

  Rapidan
Energy
Company

  Calpine
Gordonsville
Inc.

  Accumulated
Other
Comprehensive
Loss

  Total
 
Balance, December 31, 1999 (unaudited)   $ 28,133,522   $ 574,153   $ 28,707,676   $   $ 57,415,351  
Capital distributions     (2,891,000 )   (59,000 )   (2,950,000 )       (5,900,000 )
Net income     4,343,325     88,639     4,431,965         8,863,929  
Other comprehensive income                      
   
 
 
 
 
 
Balance, December 31, 2000 (unaudited)     29,585,847     603,792     30,189,641         60,379,280  
Capital distributions     (808,500 )   (16,500 )   (825,000 )       (1,650,000 )
Net income     3,792,233     77,393     3,869,626         7,739,252  
Other comprehensive income                 (3,544,255 )   (3,544,255 )
   
 
 
 
 
 
Balance, December 31, 2001 (unaudited)     32,569,580     664,685     33,234,267     (3,544,255 )   62,924,277  
Capital distributions     (2,082,500 )   (42,500 )   (2,125,000 )       (4,250,000 )
Net income     4,878,223     99,556     4,977,778         9,955,557  
Other comprehensive income                 (5,324,299 )   (5,324,299 )
   
 
 
 
 
 
Balance, December 31, 2002   $ 35,365,303   $ 721,741   $ 36,087,045   $ (8,868,554 ) $ 63,305,535  
   
 
 
 
 
 

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

312



GORDONSVILLE ENERGY, L.P.

STATEMENTS OF CASH FLOWS

FOR THE YEARS ENDED DECEMBER 31, 2002, 2001 (UNAUDITED) AND 2000 (UNAUDITED)

 
  2002
  2001
  2000
 
 
   
  (unaudited)

  (unaudited)

 
Cash flows from operating activities:                    
  Net income:   $ 9,955,557   $ 7,739,252   $ 8,863,929  
  Adjustments to reconcile net loss to net cash provided by operating activities:                    
    Depreciation and amortization     7,181,522     7,440,514     7,503,755  
  Changes in assets and liabilities:                    
    (Increase) decrease in accounts receivables     (992,371 )   3,885,409     (3,965,584 )
    Decrease (increase) in inventory     814,539     (3,692,118 )   1,718,181  
    Decrease in non-current spares         735,080     1,604,534  
    (Increase) decrease in prepaid and other     (322,627 )   309,578     (152,387 )
    (Decrease) increase in accounts payable     (525,376 )   (264,983 )   959,965  
    (Decrease) increase in interest payable     (45,602 )   (227,209 )   21,787  
    Decrease in overhaul reserve             (877,167 )
  Cumulative effect on prior years of change in accounting principle         (844,809 )    
   
 
 
 
      Net cash provided by operating activities     16,065,642     15,080,714     15,677,013  
   
 
 
 
Cash flows from investing activities:                    
  Capital expenditures     (118,645 )   (136,443 )   (69,046 )
   
 
 
 
      Net cash used in investing activities     (118,645 )   (136,443 )   (69,046 )
   
 
 
 
Cash flows from financing activities:                    
  (Increase) decrease in debt service reserves     (6,179 )   (628,746 )   372,244  
  Capital distributions     (4,250,000 )   (1,650,000 )   (5,900,000 )
  Repayment of long-term debt     (12,742,704 )   (10,618,920 )   (10,537,236 )
   
 
 
 
      Net cash used in financing activities     (16,998,883 )   (12,897,666 )   (16,064,992 )
   
 
 
 
Net (decrease) increase in cash and cash equivalents     (1,051,886 )   2,046,605     (457,025 )
Cash and cash equivalents, beginning of year     3,850,546     1,803,941     2,260,966  
   
 
 
 
Cash and cash equivalents, end of year   $ 2,798,660   $ 3,850,546   $ 1,803,941  
   
 
 
 
Supplemental disclosure of cash flow information:                    
  Cash paid for interest   $ 7,723,065   $ 8,678,007   $ 9,341,938  
   
 
 
 

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

313



GORDONSVILLE ENERGY, L.P.

NOTES TO FINANCIAL STATEMENTS

DECEMBER 31, 2002, 2001 (UNAUDITED) AND 2000 (UNAUDITED)

1.    Organization and Operations

        Gordonsville Energy, L.P. (the "Partnership"), is a partnership among Rapidan Energy Company, a California corporation ("Rapidan"), holding a one percent general partnership interest; Madison Energy Company, a California corporation ("Madison"), holding a 49 percent limited partnership interest; and Calpine Gordonsville Inc., a Delaware corporation ("Calpine") holding a 50 percent general partnership interest. Rapidan and Madison are wholly owned subsidiaries of Edison Mission Energy ("EME"), an indirect wholly owned subsidiary of Edison International. Calpine Gordonsville Inc. is an indirect wholly owned subsidiary of Calpine Corporation.

        The Partnership was organized under Delaware law on January 16, 1992, to construct, own and operate an independent qualifying power facility (the "Facility"), as defined in the Public Utility Regulatory Policies Act of 1978 and the regulations promulgated there under, all as amended ("PURPA"), located near the Town of Gordonsville in Louisa County, Virginia. The Facility was certified as a "qualifying facility" under PURPA prior to the start of operations, and management believes it has fulfilled all requirements to receive continued "qualifying facility" status.

        The Facility sells 100 percent of its electric energy to a public utility for resale to its customers under two long-term power purchase agreements, each with an initial term of 30 years. The Facility also provides steam output to Rapidan Service Authority, a political subdivision of the commonwealth of Virginia, for use in treating wastewater generated by third-party industrial companies. The Partnership will terminate on December 31, 2050, unless sooner terminated pursuant to the limited partnership agreement, or upon the date the Partnership elects to cease operations, whichever occurs first.

        The Facility commenced commercial operations on June 1, 1994 and consists of two natural gas and oil-fired combustion turbine generators ("Units"). The Facility is designed to produce approximately 240 megawatts of dependable peaking capacity.

2.    Changes in Accounting Principles

        Through December 31, 2000 we have accrued for major maintenance costs during the period between turnarounds (referred to as "accrue in advance" accounting method). Such accounting policy has been widely used by independent power producers as well as several other industries. In March 2000, the U.S. Securities and Exchange Commission ("SEC") issued a letter to the Accounting Standards Executive Committee, stating its position that the SEC Staff does not believe it is appropriate to use an "accrue in advance" method for major maintenance costs as part of an existing project and to issue authoritative guidance by August 2000. Due to the position taken by the SEC Staff, we decided voluntarily to change our accounting policy so as to record major maintenance costs as an expense as incurred. Such change in accounting policy is considered preferable based on the recent guidance provided by the SEC. In accordance with Accounting Principles Board Opinion No. 20, "Accounting Changes", we have recorded $844,809, as a cumulative change in the accounting for major maintenance costs during the year ended December 31, 2001. Pro forma data has not been provided for prior periods, as the impact would not have been material.

314



3.    Summary of Significant Accounting Policies

Use of Estimates in Financial Statements

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

Cash and Cash Equivalents

        The Partnership considers cash and cash equivalents to include cash and short-term investments with original maturities of three months or less.

Inventory

        Inventory consists of spare parts, natural gas and fuel oil and is stated at the lower of weighted average cost or market.

Property, Plant and Equipment

        Property, plant and equipment are stated at cost. All costs, including interest and field overhead expenses, incurred during construction and the precommission phase of the Facility were capitalized as part of the cost of the Facility. Depreciation is computed on a straight-line basis over the following estimated useful lives:

Power plant facilities   Up to 30 years
Interconnection facility   30 years
Furniture and office equipment   5 to 7 years

Financial Instruments

        Financial instruments that potentially subject the Partnership to significant concentrations of credit or valuation risk consist principally of cash and cash equivalents, accounts receivable, debt service reserves, accounts payable, interest payable and long-term debt.

        The carrying amounts reported in the balance sheet for cash and cash equivalents, accounts receivable, debt service reserves, accounts payable and interest payable approximate fair market value due to their short maturity or their highly liquid nature. The carrying amount of the long-term debt approximates fair value due to repricing of interest rates associated with this instrument.

Derivative Instruments and Hedging Activities

        The Partnership uses interest rate swaps to manage its interest-rate exposure on debt. Effective January 1, 2001, the Partnership adopted the provisions of SFAS No. 133, Accounting for Derivative Instruments and Hedging, as amended by SFAS 138, Accounting for Certain Derivative Instruments and Certain Hedging Activities (collectively SFAS No. 133, as amended). These statements establish accounting and reporting standards for derivative instruments and hedging activities and require an

315



entity to recognize all derivatives in the statement of financial position and measure those instruments at fair value. Changes in the derivative instrument's fair value must be recognized in earnings unless specific hedge accounting criteria are met. Changes in fair value of derivative instruments that meet specific cash flow hedge accounting criteria are reported in other comprehensive income.

        At December 31, 2002 the Partnership was a party to an interest rate swap agreement with a bank to reduce the potential impact of the increases in interest rates on floating-rate long-term debt (see Note 8) that qualified for hedge accounting. This derivative hedged approximately $89,778,000 of long-term debt that matures in 2009. Net interest expense was impacted by ($3,794,759) and ($1,350,811) in 2002 and 2001, respectively, to reflect the effects of the cash flow hedge. The fair value of the interest rate swap at December 31, 2002 was ($8,868,554). As of December 31, 2002, $3,753,277 of losses relating to the interest rate swap were expected to be reclassified from accumulated other comprehensive income to income within the next 12 months.

Revenue Recognition

        Revenue is recognized under the provisions of the power purchase agreements. Revenue is calculated based on available capacity and electric power output using established prices, as defined in the power purchase agreements.

Major Maintenance

        Certain of major pieces of equipment require major maintenance on a periodic basis. These costs are expensed as incurred.

Income Taxes

        The Partnership is treated as a partnership for income tax purposes and the income or loss of the Partnership is included in the income tax returns of the individual partners. Accordingly, no recognition has been given to income taxes in the financial statements.

New Accounting Pronouncements

Statement of Financial Accounting Standards No. 143

        Effective January 1, 2003, the Partnership adopted Statement of Financial Accounting Standards ("SFAS") No. 143, "Accounting for Asset Retirement Obligations." SFAS No. 143 requires entities to record the fair value of a liability for an asset retirement obligation in the period in which it is incurred. When the liability is initially recorded, the entity capitalizes a cost by increasing the carrying amount of the related long-lived asset. Over time, the liability is increased to its present value each period, and the capitalized cost is depreciated over the useful life of the related asset. Upon settlement of the liability, an entity either settles the obligation for its recorded amount or incurs a gain or loss upon settlement. The Partnership does not believe it has an asset retirement obligation as defined under SFAS No. 143.

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Statement of Financial Accounting Standards No. 145

        In April 2002, the Financial Accounting Standards Board ("FASB") issued SFAS Standards No. 145, "Rescission of FASB Statements No. 4, 44, and 64, Amendment of FASB Statement No. 13, and Technical Corrections," which supersedes previous guidance for reporting gains and losses from extinguishment of debt and accounting for leases, among other things, which is effective on January 1, 2003. The portion of the statement relating to the rescission of SFAS No. 4, "Reporting Gains and Losses from Extinguishment of Debt" requires that any gain or loss on extinguishment of debt that was classified as an extraordinary item that does not meet the unusual in nature and infrequent of occurrence criteria in APB Opinion No. 30, "Reporting the Results of Operations—Reporting the Effects of Disposal of a Segment of a Business, and Extraordinary, Unusual and Infrequently Occurring Events and Transactions" shall be reclassified. The Partnership does not anticipate that the adoption of SFAS No. 145 will have a significant effect on their financial position or the results of operations.

Statement of Financial Accounting Standards No. 146

        Effective January 1, 2003, the Partnership adopted SFAS No. 146, "Accounting for Costs Associated with Exit or Disposal Activities." SFAS No. 146 requires that liabilities for costs associated with exit or disposal activities initiated after December 31, 2002 be recognized when incurred, rather than at the date of a commitment to an exit or disposal plan. The Partnership does not anticipate that the adoption of SFAS No. 146 will have a significant effect on their financial position or the results of operations.

Statement of Financial Accounting Standards Interpretation No. 45

        In November 2002, the FASB issued SFAS Interpretation No. 45, "Guarantor's Accounting and Disclosure Requirements for Guarantees, Including Indirect Guarantees of Indebtedness of Others." This interpretation establishes reporting requirements to be made by a guarantor about its obligations under certain guarantees that it has issued. It also clarifies that a guarantor is required to recognize, at the inception of a guarantee, a liability for the fair value of the obligation undertaken in issuing the guarantee. The initial recognition and initial measurement provisions of this interpretation are applicable on a prospective basis to guarantees issued or modified after December 31, 2002. The Partnership does not anticipate that adoption of this standard will have a significant effect on their financial position or the results of operations.

4.    Inventory

        Inventory consists of the following at December 31, 2002 and 2001:

 
  2002
  2001
 
   
  (unaudited)

Fuel oil   $ 3,241,006   $ 4,028,730
Natural gas     123,185    
Spare parts     470,044     620,044
   
 
    $ 3,834,235   $ 4,648,774
   
 

317


5.    Property, Plant and Equipment

        Property, plant and equipment consist of the following at December 31, 2002 and 2001:

 
  2002
  2001
 
 
   
  (unaudited)

 
Power plant facilities   $ 196,717,472   $ 196,598,826  
Interconnection facility     3,250,000     3,250,000  
Furniture and office equipment     813,423     813,424  
   
 
 
      200,780,895     200,662,250  
Less: Accumulated depreciation     (59,907,792 )   (53,150,868 )
   
 
 
  Property, plant and equipment, net   $ 140,873,103   $ 147,511,382  
   
 
 

6.    Other Assets

Deferred Financing Costs

        Deferred financing costs consist of legal fees and closing costs incurred by the Partnership in obtaining its financing and are being amortized over the term of the Facility's financing arrangement of 15 years. Amortization expense was $424,598 for 2002 and 2001, and is included in depreciation and amortization expense in the accompanying statements of income. Accumulated amortization of these costs were $3,644,459 and $3,219,861 at December 31, 2002 and 2001, respectively.

Debt Service Reserves

        Debt service reserves are interest bearing accounts required by a bank under the terms of the financing agreement. The Partnership is required to maintain a debt service account consisting of six months of interest at an assumed rate of 7.28 percent per annum on the aggregate amount of the project commitments, and the next scheduled principal payment.

7.    Accounts Payable

        Accounts payable consists of the following at December 31, 2002 and 2001:

 
  2002
  2001
 
   
  (unaudited)

Accounts payable to affiliates:            
  Rapidan Energy Company   $ 6,432   $ 33,660
  Edison Mission Operations and Maintenance, Inc. (EMOM)     886,091     865,894
   
 
      892,523     899,554
Accounts payable to others     702,059     1,220,404
   
 
    $ 1,594,582   $ 2,119,958
   
 

318


8.    Long-Term Debt

        On October 15, 1993, the Partnership entered into a Reimbursement and Loan Agreement (the "Agreement") with a bank for a combination of loans and letters of credit aggregating $222,719,000. The Agreement provides for construction financing loans aggregating $213,609,000. On August 10, 1995, the construction financing loans were converted to a term loan. After conversion, the Partnership borrowed an additional $13,873,000, of which amount $8,090,452 was used to fund the debt service reserve. Principal repayments ranging from $2,246,310 to $8,821,872 are due semiannually through June 1, 2009. The commitment of the banks to extend loans and letters of credit will be reduced on dates and by amounts specified in the Agreement. The Agreement places certain restrictions on capital distributions and further provides that the Partnership pay letter of credit, agency and commitment fees. At December 31, 2002, the Partnership had outstanding loans of $94,018,294. The Agreement also provides for available letters of credit not to exceed $9,110,000, of which $7,260,000 were issued and outstanding as of December 31, 2002 and 2001. In addition, substantially all of the assets of the Partnership are pledged as collateral for the Agreement.

        Amounts outstanding under the Agreement bear interest at variable Eurodollar Rates or Base Rates, as defined in the Agreement, at the option of the Partnership, and are payable in varying installments. The Partnership elected to pay Eurodollar interest rates specified as LIBOR (1.820 percent at December 31, 2002), plus a margin of 1.25 percent, which escalates to 1.875 percent over the term of the loan (1.625 percent at December 31, 2002). Interest paid under the Agreement for the years ended December 31, 2002, 2001 and 2000 was $3,659,837, $7,624,042 and $10,247,399, respectively.

        On October 1, 1993, the Partnership entered into an interest rate swap agreement (the "Swap") with a major financial institution to reduce the risk of interest rate changes on its debt. The Swap agreement involves exchanging the Partnership's floating Eurodollar market rate for a fixed 5.775 percent resulting in an effective rate of approximately 7.40 percent on the debt covered by the notional amount of the Swap at December 31, 2002. The Swap had an initial notional principal amount of $146,500,000 ($89,778,000 at December 31, 2002) which decreases over the term of the swap and expires on June 1, 2009. The notional amount of the Swap is used to measure the interest to be paid or received and does not represent the amount of exposure to loss. If the variable rate under the notional amount exceeds the fixed rate established by the swap agreement the Partnership could be exposed to the risk of higher interest costs in the event of non-performance by the counterparty. However, the Partnership does not anticipate non-performance by the counterparty.

        The Partnership made swap payments of $3,772,125 and $953,034 during 2002 and 2001, respectively. Amounts paid under the swap have been reflected in interest expense.

319



        At December 31, 2002, the future maturities of the debt are as follows:

Year Ending December 31,

   
2003   $ 13,477,860
2004     14,948,172
2005     12,906,072
2006     13,804,596
2007     14,458,078
Thereafter     24,423,516
   
    $ 94,018,294
   

9.    Related-Party Transactions

        Under the terms of the Operation and Maintenance Agreement, employees of Edison Mission Operation and Maintenance, Inc. ("EMOM"), a wholly owned subsidiary of EME, perform all necessary functions to operate and maintain the Facility. The Partnership pays for direct costs of these services, plus an increment to cover overhead and benefits. EMOM may also earn annual incentive compensation up to $200,000 based upon actual operating results compared to budgeted performance. Pursuant to this agreement, the Partnership incurred costs of $2,348,631, $2,540,784 and $2,524,015, which included $200,000 of incentive compensation, during 2002, 2001 and 2000, respectively.

        Under the terms of the Financial Services Agreement, Rapidan will perform certain required financial, accounting, tax, project management, legal, insurance and other services for the Partnership. Pursuant to this agreement, the Partnership incurred costs of $1,018,215, $259,707 and $308,918 during 2002, 2001 and 2000, respectively.

10.    Commitments and Contingencies

Site Lease

        The Partnership exercised an option to lease the plant site from the town of Gordonsville in January 1993. The lease agreement provides for an initial term of 30 years from the commencement of commercial operations, with an option to renew the lease for an additional 10 years. Annual rental payments under the lease are $200,000 during the initial lease term, with annual increases for inflation.

        In accordance with the provisions of the site lease, the Partnership has arranged a $10,000 letter of credit to provide assurance about plant maintenance during the term of the site lease. The Partnership has also provided the town of Gordonsville with a $300,000 letter of credit, which may be drawn upon the occurrence of certain events of default, as described in the site lease agreement. This default assurance letter of credit was arranged by an affiliate of Rapidan for the benefit of the Partnership.

Power Purchase Agreements

        In October 1992, the Partnership entered into two Power Purchase Agreements for the sale to a public utility of the net electrical output and dependable capacity from each of the Facility's two Units. The agreements are effective for the 30-year period commencing June 1, 1994, with options for

320



extension in 5-year periods. The pricing is based on a contractual formula that varies depending on capacity, electric output and other costs, as defined in the agreement.

        Under the Power Purchase Agreements, the Partnership must maintain a letter of credit of $6,960,000 for the term of the agreement to secure the public utility's interest in the Facility's future commercial operations.

Fuel Supply Agreements

        In July 1993, the Partnership entered into an agreement to purchase the majority of the Facility's summer fuel gas requirements from an unrelated party at a price defined in the agreement. Unless extended by mutual consent or earlier terminated pursuant to the terms of the agreement, the agreement will remain in effect for a 15-year period, commencing with the commercial operation date, as defined in the agreement. On July 1, 1999 another unrelated party purchased the stock of this fuel supplier and became the new fuel supplier for the Partnership.

        In July 1993, the Partnership entered into an agreement to purchase winter fuel gas from an unrelated party on an as-available basis, at a price defined in the agreement. Unless extended by mutual agreement or earlier terminated pursuant to the terms of the agreement, the agreement will remain in effect through the winter period of 2008.

321



REPORT OF INDEPENDENT ACCOUNTANTS

To the Management Committee of
Brooklyn Navy Yard Cogeneration Partners, L.P.:

        In our opinion, the accompanying balance sheet as of December 31, 2002 and the related statements of operations, partners' equity, and cash flows present fairly, in all material respects, the financial position of Brooklyn Navy Yard Cogeneration Partners, L.P. (a Delaware limited partnership) at December 31, 2002, and the results of its operations and its cash flows for the year then ended in conformity with accounting principles generally accepted in the United States of America. These financial statements are the responsibility of the Partnership's management; our responsibility is to express an opinion on these financial statements based on our audit. We conducted our audit of these statements in accordance with auditing standards generally accepted in the United States of America, which require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, and evaluating the overall financial statement presentation. We believe that our audit provides a reasonable basis for our opinion.

PricewaterhouseCoopers LLP

Los Angeles, California
March 14, 2003

322



BROOKLYN NAVY YARD COGENERATION PARTNERS, L.P.

BALANCE SHEETS

DECEMBER 31, 2002 AND 2001 (UNAUDITED)

 
  2002
  2001
 
 
   
  (unaudited)

 
Assets              
Current assets:              
  Cash and cash equivalents   $ 3,209,402   $ 14,812,978  
  Accounts receivable, net of allowance for doubtful accounts of $467,000 as of December 31, 2002 and 2001, respectively     19,891,453     10,916,555  
  Inventory     8,212,848     9,555,893  
  Prepaids and other     1,275,185     1,014,329  
   
 
 
      Total current assets     32,588,888     36,299,755  
   
 
 
Construction in progress     4,299,997      
Plant and equipment, net     417,131,544     400,845,461  
Deferred costs, net     13,193,749     13,854,832  
Deposits     17,374,047     10,825,338  
   
 
 
      Total assets   $ 484,588,225   $ 461,825,386  
   
 
 
Liabilities and Partners' Equity              
Current liabilities:              
  Current portion of long-term debt   $ 2,780,000   $ 1,080,000  
  Working capital facility     2,500,000     5,000,000  
  Interest and fees payable:              
    Long-term debt and other     6,168,548     6,188,582  
    Mission Energy New York, Inc.     32,137,832     20,472,512  
  Accounts payable     31,088,641     9,976,032  
  Accounts payable—affiliates     6,817,298     2,295,528  
  Accrued expenses and other     12,660,438     5,682,457  
   
 
 
      Total current liabilities     94,152,757     50,695,111  
   
 
 
Long-term debt, net of current portion     398,400,000     401,180,000  
Loans payable to Partner     90,461,186     90,461,186  
Payable to Contractor     12,551,000      
Other deferred liabilities     4,927,447     6,816,402  
   
 
 
      Total liabilities     600,492,390     549,152,699  
   
 
 
Commitments and contingencies (Notes 9 and 12)              
Partners' equity:              
  Mission Energy New York, Inc.     (55,073,061 )   (40,784,635 )
  B-41 Associates, L.P.     (60,831,104 )   (46,542,678 )
   
 
 
      Total partners' equity     (115,904,165 )   (87,327,313 )
   
 
 
      Total liabilities and partners' equity   $ 484,588,225   $ 461,825,386  
   
 
 

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

323



BROOKLYN NAVY YARD COGENERATION PARTNERS, L.P.

STATEMENTS OF OPERATIONS

FOR THE YEARS ENDED DECEMBER 31, 2002, 2001 (UNAUDITED) AND 2000 (UNAUDITED)

 
  2002
  2001
  2000
 
   
  (unaudited)

  (unaudited)

Revenues:                  
  Energy revenue   $ 103,847,813   $ 111,533,654   $ 112,118,755
  Steam revenue     31,666,098     47,971,766     49,497,116
  Peaking gas revenue     4,704,829     6,857,573     4,955,801
  Other revenue     11,736,327     7,732,910     7,553,681
  Interest income     411,202     1,403,722     1,898,478
   
 
 
    Total revenues     152,366,269     175,499,625     176,023,831
   
 
 
Expenses:                  
  Operations and maintenance     117,019,913     139,494,100     130,516,852
  General and administrative     9,933,368     12,369,142     3,002,298
  Depreciation and amortization     13,922,517     14,313,087     14,523,009
  Interest expense     37,172,341     36,663,602     35,876,294
  Loss on sale of asset     2,894,982        
   
 
 
    Total expenses     180,943,121     202,839,931     183,918,453
   
 
 
    Net loss   $ 28,576,852   $ 27,340,306   $ 7,894,622
   
 
 

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

324



BROOKLYN NAVY YARD COGENERATION PARTNERS, L.P.

STATEMENTS OF CHANGES IN PARTNERS' EQUITY

FOR THE YEARS ENDED DECEMBER 31, 2002, 2001 (UNAUDITED) AND 2000 (UNAUDITED)

 
  Mission Energy New York, Inc.
  B-41
Associates
L.P.

  Total
 
Balance, December 31, 1999 (unaudited)   $ (23,167,171 ) $ (28,925,214 ) $ (52,092,385 )
  Net loss     (3,947,311 )   (3,947,311 )   (7,894,622 )
   
 
 
 
Balance, December 31, 2000 (unaudited)     (27,114,482 )   (32,872,525 )   (59,987,007 )
  Net loss     (13,670,153 )   (13,670,153 )   (27,340,306 )
   
 
 
 
Balance, December 31, 2001 (unaudited)     (40,784,635 )   (46,542,678 )   (87,327,313 )
  Contribution from Mission Energy New York, Inc.     32,551,000         32,551,000  
  Receivable from Mission Energy New York, Inc.     (32,551,000 )       (32,551,000 )
  Net loss     (14,288,426 )   (14,288,426 )   (28,576,852 )
   
 
 
 
Balance, December 31, 2002   $ (55,073,061 ) $ (60,831,104 ) $ (115,904,165 )
   
 
 
 

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

325



BROOKLYN NAVY YARD COGENERATION PARTNERS, L.P.

STATEMENTS OF CASH FLOWS

FOR THE YEARS ENDED DECEMBER 31, 2002, 2001 (UNAUDITED) AND 2000 (UNAUDITED)

 
  2002
  2001
  2000
 
 
   
  (unaudited)

  (unaudited)

 
Cash flows from operating activities:                    
  Net loss   $ (28,576,852 ) $ (27,340,306 ) $ (7,894,622 )
  Adjustments to reconcile net loss to net cash provided by operating activities:                    
    Loss on sale of asset     2,894,982          
    Depreciation and amortization     13,922,517     14,313,087     14,680,214  
    Provision for doubtful accounts         467,000      
    Changes in assets and liabilities:                    
      (Increase) decrease in accounts receivable     (8,974,898 )   13,286,271     (11,114,382 )
      Decrease (increase) in inventory     1,343,045     (3,418,839 )   (1,463,084 )
      Increase in prepaids and other     (260,856 )   (144,056 )   (20,592 )
      Increase in interest and fees payable     11,645,286     3,111,021     10,264,221  
      Increase (decrease) in accounts payable     25,634,379     (8,696,233 )   7,639,394  
      Increase in accrued expenses and other     6,977,981     1,314,868     145,708  
      Decrease in deferred liabilities     (1,888,955 )   (580,041 )   (6,086,325 )
      Increase in other liabilities     12,551,000          
   
 
 
 
        Net cash provided by (used in) operating activities     35,267,629     (7,687,228 )   6,150,532  
   
 
 
 
Cash flows from investing activities:                    
  Capital expenditures     (4,299,997 )   (3,872,252 )   (641,502 )
  Capital expenditures Contractor     (32,551,000 )        
  Proceeds from sales of assets     108,501          
  (Increase) Decrease in deposits     (6,548,709 )   7,344,422     2,753,130  
   
 
 
 
        Net cash (used in) provided by investing activities     (43,291,205 )   3,472,170     2,111,628  
   
 
 
 
Cash flows from financing activities:                    
  (Repayments) Borrowings to/from working capital facility     (2,500,000 )   5,000,000      
  Repayment of long-term debt     (1,080,000 )   (1,340,000 )   (1,050,000 )
   
 
 
 
        Net cash (used in) provided by financing activities     (3,580,000 )   3,660,000     (1,050,000 )
   
 
 
 
Net (decrease) increase in cash and cash equivalents     (11,603,576 )   (555,058 )   7,212,160  
Cash and cash equivalents, beginning of period     14,812,978     15,368,036     8,155,876  
   
 
 
 
Cash and cash equivalents, end of period   $ 3,209,402   $ 14,812,978   $ 15,368,036  
   
 
 
 
Supplemental disclosure of cash flow information:                    
  Cash paid during the year for interest   $ 25,526,683   $ 33,552,581   $ 25,612,073  
   
 
 
 

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

326



BROOKLYN NAVY YARD COGENERATION PARTNERS, L.P.

NOTES TO FINANCIAL STATEMENTS

DECEMBER 31, 2002, 2001 (UNAUDITED) AND 2000 (UNAUDITED)

1.    Organization and Operations

        Brooklyn Navy Yard Cogeneration Partners, L.P. (the "Partnership") is a Delaware limited partnership formed pursuant to a limited partnership agreement dated October 19, 1992 by and between Mission Energy New York, Inc. ("MENY"), holding a 5 percent general partnership interest and a 45 percent limited partnership interest; and B-41 Associates, L.P. ("B-41"), holding a 5 percent general partnership interest and a 45 percent limited partnership interest. MENY is a wholly owned subsidiary of Edison Mission Energy ("EME"), an indirect wholly owned subsidiary of Edison International. B-41 is a majority owned subsidiary of York Research Corporation ("York").

        On November 1, 1997, MENY and B-41 entered into an Amended and Restated Limited Partnership Agreement (the "Partnership Agreement"). This agreement amended the determination of general partner management fees, certain special allocations of income and deductions and the prioritization of cash distributions.

        The Partnership was organized for the purpose of developing, leasing, acquiring, constructing, improving, equipping, owning, operating, installing and financing a natural gas-fired cogeneration facility (the "Facility") located in Brooklyn, New York. The Facility, which is powered by two natural gas and oil fired combustion turbine generators and two automatic extraction steam turbines, can produce a nominal output of 220 megawatts of electricity and up to 1,000,000 pounds of steam per hour. The Partnership currently sells substantially all of the Facility's electric and steam generating capacity and output to a public utility for resale to its customers under an energy sales agreement, which expires on October 31, 2036.

        The Facility is currently a qualifying facility ("QF") under the Public Utility Regulatory Policies Act of 1978, as amended, and the regulations promulgated thereunder by the Federal Energy Regulatory Commission. The documents executed in connection with the December 1997 debt refinancing (see Note 8), require the Facility to maintain a QF, an exempt wholesale generator ("EWG") or another similar entity status that is exempt under Public Utilities Holdings Company Act ("PUHCA").

2.    Summary of Significant Accounting Policies

Use of Estimates in Financial Statements

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

Cash and Cash Equivalents

        The Partnership considers cash and cash equivalents to include cash and short-term investments with original maturities of three months or less.

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Inventory

        Inventory consists of spare parts, natural gas and fuel oil. Natural gas and spare parts inventory are stated using the average cost valuation method. The LIFO method of inventory valuation is used for fuel oil.

Plant and Equipment

        Plant and equipment are stated at cost and are depreciated on a straight-line basis over the estimated useful lives of the assets. The useful life for the Facility is 39 years, and the useful lives for all other equipment and enhancements range from five to seven years.

Deferred Costs

        Deferred costs as of December 31, 2002 and 2001, consisted of the following:

 
  2002
  2001
 
 
   
  (unaudited)

 
Deferred financing costs   $ 14,142,589   $ 14,142,589  
Accumulated amortization     (3,031,809 )   (2,527,929 )
   
 
 
    Net deferred financing costs     11,110,780     11,614,660  
   
 
 
Deferred fuel costs     3,000,000     3,000,000  
Accumulated amortization     (917,031 )   (759,828 )
   
 
 
  Net deferred fuel costs     2,082,969     2,240,172  
   
 
 
  Total deferred costs   $ 13,193,749   $ 13,854,832  
   
 
 

        Deferred financing costs consist of legal fees and closing costs incurred by the Partnership in obtaining its financing. These costs are being amortized using the effective interest method over the life of the related debt (see Note 8).

        Deferred fuel costs include a $3,000,000 advance payment required under a long-term fuel supply agreement (see Note 9). These costs are being amortized over the term of the fuel supply agreement, beginning March 1, 1997.

Maintenance Accrual

        Estimated labor costs for scheduled maintenance events are accrued for on a straight-line basis over the expected operating interval between each like event. Expenditures for minor maintenance, repairs, and minor renewals are charged to operations as incurred. Expenditures for additions, improvements and replacements are capitalized.

Income Taxes

        The Partnership is a limited partnership, and the income or loss of the Partnership for income tax purposes is included in the income tax returns of the individual partners. Accordingly, no recognition has been given to Federal or state income taxes in the accompanying financial statements.

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Deposits

        Deposits consist of bond proceeds and revenues that are used to repay principal, interest and other costs due under the Collateral Agency and Intercreditor Agreement (see Note 8). Deposits and other assets as of December 31, 2002 and 2001 are as follows:

 
  2002
  2001
 
   
  (unaudited)

Maintenance fund   $ 271,509   $ 1,424,804
Tax-exempt indenture securities fund     4,421,510     4,421,510
Taxable indentures—interest fund     1,747,039     1,767,073
Taxable indentures—principal fund     695,000     270,000
Letter of credit reimbursement fund     172,343     171,230
Working capital reimbursement fund     9,000     6,250
Revenue fund         218,903
Operating fund     9,760,567     37,000
Water treatment fund         1,061,095
Solid waste disposal fund         799
Water usage fund     204,532     1,621
Distribution fund         1,385,787
Other deposits     92,547     59,266
   
 
  Total deposits   $ 17,374,047   $ 10,825,338
   
 

Revenue Recognition

        Revenue is recognized as billable under the provisions of the Energy Sales Agreement for energy and capacity (the "Energy Sales Agreement") with Consolidated Edison Company of New York, which has a term of 40 years. Revenue is calculated based on established prices, as defined in the Energy Sales Agreement.

New Accounting Pronouncements

Statement of Financial Accounting Standards No. 133

        The Partnership adopted Statement of Financial Accounting Standards ("SFAS") No. 133, "Accounting for Derivative Instruments and Hedging Transactions" as amended by SFAS No. 138, "Accounting for Derivative Instruments and Hedging Transactions—an amendment of SFAS No. 133," effective January 1, 2001. Provisions in SFAS No. 133, as amended, affect the accounting and disclosure of certain contractual arrangements and operations of the Partnership. Under SFAS No. 133, as amended, all derivatives instruments are recognized in the balance sheet as their fair values and changes in fair value are recognized immediately in earnings, unless the derivative qualifies as hedges of future cash flows or investments. For derivatives qualifying as hedges of future cash flows, the effective portion of changes in fair value is recorded in equity until the related hedge items impact earnings. Any ineffective portion of a hedge is reported in earnings immediately. The Partnership reviewed the activities performed under its contracts and the respective terms and concluded that the

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contracts meet the Normal Purchase Normal Sale exemption defined in SFAS No. 133, which resulted in accrual accounting consistent with the pre-adoption of SFAS No. 133.

Statement of Financial Accounting Standards No. 143

        Effective January 1, 2003, the Partnership adopted Statement of Financial Accounting Standards ("SFAS") No. 143, "Accounting for Asset Retirement Obligations." SFAS No. 143 requires entities to record the fair value of a liability for an asset retirement obligation in the period in which it is incurred. When the liability is initially recorded, the entity capitalizes a cost by increasing the carrying amount of the related long-lived asset. Over time, the liability is increased to its present value each period, and the capitalized cost is depreciated over the useful life of the related asset. Upon settlement of the liability, an entity either settles the obligation for its recorded amount or incurs a gain or loss upon settlement. The Partnership does not believe it has an asset retirement obligation as defined under SFAS No. 143.

Statement of Financial Accounting Standards No. 145

        In April 2002, the Financial Accounting Standards Board ("FASB") issued SFAS No. 145, "Rescission of FASB Statements No. 4, 44, and 64, Amendment of FASB Statement No. 13, and Technical Corrections," which supersedes previous guidance for reporting gains and losses from extinguishment of debt and accounting for leases, among other things, which is effective on January 1, 2003. The portion of the statement relating to the rescission of SFAS No. 4, "Reporting Gains and Losses from Extinguishment of Debt" requires that any gain or loss on extinguishment of debt that was classified as an extraordinary item that does not meet the unusual in nature and infrequent of occurrence criteria in APB Opinion No. 30, "Reporting the Results of Operations—Reporting the Effects of Disposal of a Segment of a Business, and Extraordinary, Unusual and Infrequently Occurring Events and Transactions" shall be reclassified. The Partnership does not anticipate that the adoption of SFAS No. 145 will have a significant effect on their financial position or the results of operations.

Statement of Financial Accounting Standards No. 146

        Effective January 1, 2003, the Partnership adopted SFAS No. 146, "Accounting for Costs Associated with Exit or Disposal Activities." SFAS No. 146 requires that liabilities for costs associated with exit or disposal activities initiated after December 31, 2002 be recognized when incurred, rather than at the date of a commitment to an exit or disposal plan. The Partnership does not anticipate that the adoption of SFAS No. 146 will have a significant effect on their financial position or the results of operations.

Statement of Financial Accounting Standards Interpretation No. 45

        In November 2002, the FASB issued SFAS Interpretation No. 45, "Guarantor's Accounting and Disclosure Requirements for Guarantees, Including Indirect Guarantees of Indebtedness of Others." This interpretation establishes reporting requirements to be made by a guarantor about its obligations under certain guarantees that it has issued. It also clarifies that a guarantor is required to recognize, at the inception of a guarantee, a liability for the fair value of the obligation undertaken in issuing the guarantee. The initial recognition and initial measurement provisions of this interpretation are

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applicable on a prospective basis to guarantees issued or modified after December 31, 2002. The Partnership does not anticipate that adoption of this standard will have a significant effect on their financial position or the results of operations.

3.    Accounts Receivable

        Accounts receivable at December 31, 2002 and 2001 consists of the following:

 
  2002
  2001
 
 
   
  (unaudited)

 
Mission Energy New York, Inc.   $ 431,055   $ 1,273,224  
Accounts receivable from others     19,927,398     10,110,331  
   
 
 
  Total accounts receivable     20,358,453     11,383,555  
Allowance for doubtful accounts     (467,000 )   (467,000 )
   
 
 
    $ 19,891,453   $ 10,916,555  
   
 
 

4.    Inventory

        Inventory at December 31, 2002 and 2001 consists of the following:

 
  2002
  2001
 
   
  (unaudited)

Fuel oil   $ 2,434,040   $ 2,593,285
Gas     2,610,104     3,755,101
Spare parts     3,168,704     3,207,507
   
 
    $ 8,212,848   $ 9,555,893
   
 

5.    Plant and Equipment

        Plant and equipment at December 31, 2002 and 2001 consists of the following assets:

 
  2002
  2001
 
 
   
  (unaudited)

 
Plant   $ 493,416,895   $ 464,325,703  
Equipment     957,763     977,262  
Accumulated depreciation     (77,243,114 )   (64,457,504 )
   
 
 
  Plant and equipment, net   $ 417,131,544   $ 400,845,461  
   
 
 

6.    Disclosures About Fair Value of Financial Instruments

        The balance sheet items cash and cash equivalents, accounts receivable, accounts payable and interest and fees payable are financial instruments which, due to their short maturity or their highly liquid nature, have fair market values which approximate their carrying values. The carrying amount of

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the loans payable to partner approximates fair value due to the variable interest rate feature. The fair value of the long-term debt at December 31, 2002 and 2001 was approximately $379,079,522 and $380,375,641, respectively (see Note 8).

7.    Loans Payable to Partner

        During the period from inception through December 31, 1997, the Partnership entered into various construction loans (the "Partner loans") with MENY. The interest rate on the Partner loans is variable based on the prime rate plus 6 percent (10.25 percent at December 31, 2002), compounded daily. MENY may, at its discretion, reduce the rate of interest charged for the Partner loans. Through the years ended December 31, 2002 and 2001, MENY has charged and the Partnership has expensed, interest at 10 percent. Principal and interest on the loan are payable with proceeds from long-term credit facilities or from revenues of the Partnership over five years commencing April 1, 1997. Any unpaid interest or principal after March 31, 2002 shall be payable in full from the first available cash flow after giving effect to other priority payments as defined in the Partnership Agreement. The remaining loan payable as of December 31, 2002 and 2001 was $90,461,186, and is subordinate to the long-term debt discussed in Note 8. For the years ended December 31, 2002, 2001 and 2000, the Partnership recorded interest expense related to the Partner loans of $11,665,320, $11,135,879 and $10,283,699, respectively.

8.    Long-Term Debt

        On December 17, 1997, the New York City Industrial Development Agency (the "Agency") issued Industrial Development Revenue Bonds (Brooklyn Navy Yard Cogeneration Partners, L.P. Project), of $31,960,000 principal amount 6.20 percent Term Bonds due October 1, 2022, $110,280,000 principal amount 5.65 percent Term Bonds due October 1, 2028, and $164,760,000 principal amount 5.75 percent Term Bonds due October 1, 2036 (collectively, the "Tax-Exempt Bonds") for the purpose of replacing Industrial Development Revenue Bonds issued in 1995, which were used to finance a portion of the costs of developing, leasing, acquiring, constructing, improving, equipping and installing the Facility. The Tax-Exempt Bonds were issued pursuant to a Tax-Exempt Indenture of Trust dated as of December 1, 1997. The principal of and premium, if any, and interest on the Tax-Exempt Bonds is payable from amounts received by the Agency pursuant to the Amended and Restated Lease Agreement dated as of December 1, 1997 between the Agency and the Partnership. The payment of principal and premium, if any, and interest on the Tax-Exempt Bonds is unconditionally guaranteed by the Partnership. Interest on the Tax-Exempt Bonds is payable semi-annually on each April 1 and October 1, commencing April 1, 1998. The principal is payable on varying maturity dates, but in no case before the full maturity of the bonds described below.

        Simultaneously with the issuance of the Tax-Exempt Bonds, the Partnership issued $100,000,000 principal amount of 7.42 percent Senior Secured Bonds due October 1, 2020 (the "Taxable Bonds"), together with the Tax-Exempt Bonds (collectively, the "1997 Bonds"). The principal of the Taxable Bonds is payable in semi-annual installments commencing April 1, 1998 and is secured by the Shared Collateral, as defined below, on a parity basis with the Tax-Exempt Bonds. The bond agreement contains certain restrictive covenants, which includes restrictions on capital distributions among other restrictions.

332


        The Partnership entered into a Collateral Agency and Intercreditor Agreement, dated December 1, 1997, which required the establishment of certain funds pursuant to the terms of the Intercreditor Agreement. Such funds are pledged as security for repayment of the 1997 Bonds. The payment of principal and interest on the 1997 Bonds is also secured by a lien on and security interest in substantially all of the Partnership's (i) personal property owned or leased, (ii) project contracts (other than unassigned project contract interests, which include the Site Lease discussed in Note 9 and the Partnership Agreement), (iii) revenues of the Partnership, (iv) permits and governmental approvals, and (v) so long as any of the Tax-Exempt Bonds are outstanding, all of the Agency's right, title and interest in and to the Amended Lease Agreement, except for the right to receive rental payments thereunder, and the Company Lease (collectively, the "Shared Collateral").

        Pursuant to the Reimbursement Agreement, dated December 1, 1997 with the Partnership, certain financial institutions have provided letters of credit for the account of the Partnership in connection with the Facility. These letters of credit secure the Partnership's obligations under various project contracts (see Note 9) and its debt service requirements. The Partnership had nine letters of credit outstanding totaling $71,520,662 and $67,944,976 as of December 31, 2002 and 2001, respectively. As of December 31, 2002 and 2001, the Partnership had $10,000,000 available under a working capital facility. Amounts drawn under the working capital facility were $2,500,000 and $5,000,000 at December 31, 2002 and 2001, respectively. Amounts outstanding under the working capital facility bear interest at LIBOR plus a margin of 0.6 percent (2.02 percent at December 31, 2002). The working capital facility matured on January 30, 2003. The Partnership secured a $5,000,000 working capital facility in January 2003, which matures on December 17, 2005.

        At December 31, 2002, the future maturities of the debt are as follows:

Year Ending December 31,

   
 
2003   $ 5,280,000  
2004     4,520,000  
2005     3,690,000  
2006     4,950,000  
2007     5,930,000  
Thereafter     379,310,000  
   
 
      403,680,000  
Less: current portion     (5,280,000 )
   
 
    $ 398,400,000  
   
 

9.    Commitments and Contingencies

Site Lease

        On June 3, 1994, the Partnership entered into a lease agreement, as amended, whereby the Partnership leases the real estate where the Facility is located through December 31, 2040. Under the terms of the lease agreement, the Partnership makes monthly rental payments in the amount of $20,612, which escalates annually beginning on January 1, 1997. For the year ended December 31, 2002,

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2001 and 2000, the partnership incurred $1,131,599, $1,076,847 and $1,120,561, respectively, in rent expense and total future lease payments due are as follows:

Year Ending December 31,

   
2003   $ 523,205
2004     561,938
2005     603,606
2006     598,658
2007     627,912
Thereafter     44,475,745
   
    $ 47,391,064
   

Energy Sales Agreements

        Under the terms of an Energy Sales Agreement, dated October 31, 1996, a public utility agreed to purchase electric and steam energy, up to a maximum of 286 megawatts of the electric energy and 1,000,000 pounds per hour of steam energy, generated by the Facility for a period of 40 years commencing on November 1, 1996 through October 31, 2036. The Partnership is paid for electric energy based upon the prices defined in the Energy Sales Agreement, the quantity of kilowatts delivered and the electric energy escalation factor, adjusted monthly by a weighted calculation of the GDPIPD and the average closing price of the New York Mercantile Exchange for Henry Hub ("NYMEX") gas deliveries. The public utility also pays the Partnership for firm electrical capacity based upon contracted amounts per kilowatt, as determined in the Energy Sales Agreement, adjusted annually by a GDPIPD for the previous calendar year.

        The Partnership is paid for steam energy based upon prices defined in the Energy Sales Agreement, and the quantity of pounds delivered. The public utility also pays the Partnership for firm steam capacity based upon contracted amounts per year, as determined in the Energy Sales Agreement, adjusted annually by a GDPIPD for the previous calendar year.

        The Partnership is paid for energy and steam conversions, as defined, upon request for such conversions by the public utility, based upon contracted prices and the quantity of kilowatts or pounds delivered.

        Under the terms of an Amended and Restated Energy Sales Agreement, dated April 29, 1994, a local not-for-profit development corporation ("Development Corp.") agreed to purchase all of their electric and steam energy requirements, up to a maximum of 10 megawatts of electric energy per year and 250 million pounds of steam per heating season, as defined, which began on March 1, 1999 and terminates on December 31, 2039. The Partnership is paid for electric and steam energy based upon a contracted percentage of the public utility's Tariff SC4-2, as published by the New York State Public Service Commission, and a contracted percentage of the Development Corp.'s avoided cost for steam, as adjusted monthly based upon percentage changes in the Brooklyn Union Gas Tariff 5B, respectively.

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Fuel Supply and Transportation Agreements

        Effective March 21, 1995, the Partnership entered into a gas purchase agreement, as amended, with a company whereby the Partnership has agreed to purchase approximately 55 percent of the Facility's daily fuel gas requirements commencing on April 1, 1996 through March 31, 2016, at prices defined in the agreement adjusted monthly based upon the average closing prices of the NYMEX and the quantity delivered. The agreement included an advance payment of $3,000,000 that is being amortized on a straight-line basis over the initial term of the agreement commencing on March 1, 1997.

        Effective October 1993, the Partnership entered into two gas purchase agreements, as amended, with two companies whereby the Partnership has agreed to purchase approximately 27 and 18 percent of the Facility's daily fuel requirements, at prices defined in the agreements, adjusted monthly based upon the average closing prices of the NYMEX and the quantity delivered, commencing on October 1, 1996 through September 30, 2016.

        In connection with the above gas purchase agreements, the Partnership entered into a firm transportation service contract with a company whereby the company agreed to transport to the fuel manager approximately 45 percent of the Facility's daily natural gas requirements commencing on October 1, 1996 through September 30, 2016. The Partnership pays for these services based upon prices defined in the firm transportation service contracts and published tariff rates.

        Effective September 25, 1996, the Partnership entered into a fuel management agreement, as amended and revised, with a company whereby the company agreed to manage and administer all fuel supply and transportation agreements from October 1, 1996 through September 30, 2017. Under the fuel management agreement, the Partnership pays a fixed monthly fee and a variable fee based on the quantity of fuel used in the Facility. The prices as defined in the fuel management agreement are to be adjusted annually by the GDPIPD.

        In conjunction with the fuel management agreement, the company released to the Partnership certain telescoped rights for the delivery to the fuel manager of approximately 55 percent of the daily fuel transportation from a transportation company. The Partnership pays the transportation company for transportation services based upon published gas tariff rates.

        In connection with the gas sales agreements and the firm transportation agreements noted above, the Partnership entered into a delivery agreement with a company whereby the company agreed to deliver to the Facility 100 percent of the daily natural gas requirements commencing on October 1, 1996 through November 30, 2011. The Partnership pays the company based upon prices defined in the delivery agreement.

Operation and Maintenance Agreement

        On March 26, 2002, the Partnership renewed an operation and maintenance agreement with a company to provide all necessary services to operate and maintain the Facility through December 31, 2005. Under the agreement, the Partnership agreed to reimburse the company for labor and certain other personnel costs and expenses and pay a monthly management fee adjusted annually by the GDPIPD. In addition, the agreement provides for an incentive fee.

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10.    Related Party Transactions

        MENY and B-41 have been or will be reimbursed for development, design, construction and other costs incurred on behalf of the Partnership. For the year ended December 31, 2002, 2001 and 2000, reimbursements paid or payable to MENY totaled $2,075,321, $1,094,102 and $901,651, respectively and to B-41 totaled $246,463, $141,727 and $268,814, respectively.

        Under the terms of the Partnership Agreement, the Partnership is charged a royalty fee and a general partner management fee by MENY and B-41 equal to 4 percent and 5 percent of gross revenue in 2002, 2001 and 2000, respectively, as defined in the Partnership Agreement. Royalty and general partner management fees for the year ended December 31, 2002, 2001 and 2000 totaled $6,111,703, $8,704,667 and $8,706,379, respectively.

11.    York Bankruptcies

        In March 2000, York filed a Form 8-K with the Securities and Exchange Commission indicating that an eighty-five percent owned subsidiary of York (the Subsidiary), engaged in natural gas marketing, filed a voluntary petition for Chapter 11 bankruptcy. Per the 8-K, certain liabilities of the Subsidiary and a number of contracts for the purchase and/or sale of natural gas have been guaranteed by York. On January 8, 2001, an agreement between York and the Subsidiary creditors was approved by the bankruptcy court. This agreement terminated due to a lack of funding by York. On December 20, 2001, certain Subsidiary creditors filed an involuntary bankruptcy petition against York. York filed a response to the petition on January 15, 2002, seeking to have it dismissed.

        A default occurred on the $150,000,000 12% Senior Secured Bonds due October 30, 2007 issued by York Power Funding (Cayman) Limited (the "Portfolio Bonds") when a scheduled interest and principal payment was not made in full on October 30, 2001. The Portfolio Bonds were guaranteed by York Research Corporation ("York") and certain of its subsidiaries and were secured by, among other things, York's operational power-generating projects.

        After settlement discussions with holders of the Portfolio Bonds, on June 7, 2002, York filed for a voluntary Chapter 11 bankruptcy. On October 31, 2002, the bankruptcy court entered an order approving York's First Amended Plan of Reorganization, as modified, and on November 14, 2002, the Plan became effective. Pursuant to the Plan, York's existing stock was cancelled, the holders of the Portfolio Bonds became the sole stockholders of York.

12.    Litigation

        In February 1997, the construction contractor of the Brooklyn Navy Yard cogeneration plant facilities asserted general monetary claims under the turnkey agreement against the Partnership, for damages in the amount of $137 million. The Partnership asserted general monetary claims against the contractor. In connection with a $407 million non-recourse project refinancing in 1997, EME agreed to indemnify the Partnership and its partners from all claims and costs arising from or in connection with the contractor litigation, which indemnity has been assigned to Partnership's lenders. During December 2002, the parties held mediation sessions and reached a settlement of all outstanding claims. A settlement agreement was executed on January 17, 2003, and all litigation has been dismissed. At December 31, 2002, the Partnership recorded a liability of $32 million related to the settlement agreement and recorded a corresponding increase to property, plant and equipment as part of the cost

336



to complete construction of the cogeneration facilities. EME has indemnified the Partnership for payments due under this settlement agreement which are scheduled through 2006. In January 2003, EME contributed $20 million to the Partnership under this indemnity.

        On March 14, 2002 the Partnership received notice from the New York State Department of Taxation and Finance of a proposed tax audit adjustment to the Partnership which if upheld would cause the partnership to owe $7,300,000 in tax and penalties in connection with unpaid gas importation taxes. The notice of proposed adjustment relates to natural gas purchased by the Facility during the period December 1, 1996 through November 30, 1999. The Partnership's management believes the Partnership is exempt from the gas importation tax requirement. The Partnership has engaged legal counsel and intends to vigorously defend against the proposed adjustment should it become a final assessment. The ultimate outcome of this matter is uncertain at this time.

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Independent Auditor's Report

No.: L.02 - 1694 - 03/US.

The Shareholders,
Board of Commissioners and Board of Directors
PT Paiton Energy:

        We have audited the accompanying balance sheets of PT Paiton Energy as of 31 December 2002 and 2001, and the related statements of income, comprehensive income, changes in shareholders' equity and cash flows for each of the years in the three-year period ended 31 December 2002. These financial statements are the responsibility of the Company's management. Our responsibility is to express an opinion on these financial statements based on our audits.

        We conducted our audits in accordance with auditing standards generally accepted in the United States of America. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.

        In our opinion, the financial statements referred to above present fairly, in all material respects, the financial position of PT Paiton Energy as of 31 December 2002 and 2001, and the results of its operations and its cash flows for each of the years in the three-year period ended 31 December 2002, in conformity with accounting principles generally accepted in the United States of America.

        As discussed in Notes 2i to the financial statements, the Company changed its method of accounting for derivative instruments and hedging activities effective 1 January 2001.

Siddharta Siddharta & Widjaja
Registered Public Accountants
License No. KEP-232/KM.6/2002

         Drs. Istata Taswin Siddharta
Public Accountant License No. 98.1.0192

Jakarta, 27 February 2003

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PT PAITON ENERGY

BALANCE SHEETS

31 DECEMBER 2002 AND 2001

(In thousands of U.S. Dollars, except per share amounts)

 
  Note
  2002
  2001
ASSETS            

CURRENT ASSETS

 

 

 

 

 

 
  CASH AND CASH EQUIVALENTS   2b,3   233,711   108,030
  ACCOUNTS RECEIVABLE       83,204   26,731
  FUEL INVENTORY AND SUPPLIES   2d,5   24,566   8,443
  PREPAYMENTS AND OTHER       10,280   8,965
       
 
    TOTAL CURRENT ASSETS       351,761   152,169
       
 
PLANT AND EQUIPMENT, net   2e,6   1,921,248   1,996,554
       
 

OTHER ASSETS

 

 

 

 

 

 
  DEFERRED TAX ASSETS, net   2m,13   4,203   26,599
  LONG-TERM RECEIVABLE   21,4   453,270   455,803
  DEFERRED CHARGES, net   2g,7   248,890   258,256
  DEFERRED FINANCING COSTS, net   2h   84,228   103,171
  PREPAYMENTS AND OTHER       3,617   4,314
       
 
    TOTAL OTHER ASSETS       794,208   848,143
       
 
      TOTAL ASSETS       3,067,217   2,996,866
       
 

See Notes to the Financial Statements, which form an integral part of these financial statements.

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PT PAITON ENERGY

BALANCE SHEETS (Continued)

31 DECEMBER 2002 AND 2001

(In thousands of U.S. Dollars, except per share amounts)

 
  Note
  2002
  2001
 
LIABILITIES AND SHAREHOLDERS' EQUITY              

CURRENT LIABILITIES

 

 

 

 

 

 

 
  ACCOUNTS PAYABLE TO RELATED PARTIES       180,243   176,146  
  TAXES PAYABLE       2,891   5,011  
  ACCRUED FINANCE COSTS       26,253   28,525  
  OTHER LIABILITIES       62,614   34,932  
  CURRENT MATURITIES OF LONG-TERM LOANS   9   140,851   1,569,363  
       
 
 
    TOTAL CURRENT LIABILITIES       412,852   1,813,977  
       
 
 

NON-CURRENT LIABILITIES

 

 

 

 

 

 

 
  LONG-TERM LOANS   9   2,228,488   817,002  
  ACCRUED FINANCE COSTS       28,239   45,820  
  OTHER LIABILITIES       7,143    
  DERIVATIVE FINANCIAL INSTRUMENTS   2i,10   98,296   77,707  
       
 
 
    TOTAL NON-CURRENT LIABILITIES       2,362,166   940,529  
       
 
 
COMMITMENTS AND CONTINGENCIES   14      
       
 
 

SHAREHOLDERS' EQUITY

 

 

 

 

 

 

 
  SHARE CAPITAL—par value of USD 10,000 per share   12          
    Authorized capital—30,600 shares              
    Issued and paid-up—25,000 shares       250,000   250,000  
    Paid in advance       56,000   56,000  
       
 
 
        306,000   306,000  
  SHARE PREMIUM       7,000   7,000  
  ACCUMULATED OTHER COMPREHENSIVE LOSS       (68,807 ) (54,395 )
  RETAINED EARNINGS (DEFICIT)       48,006   (16,245 )
       
 
 
    TOTAL SHAREHOLDERS' EQUITY       292,199   242,360  
       
 
 
      TOTAL LIABILITIES AND SHAREHOLDERS' EQUITY       3,067,217   2,996,866  
       
 
 

See Notes to the Financial Statements, which form an integral part of these financial statements.

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PT PAITON ENERGY

STATEMENTS OF INCOME

YEARS ENDED 31 DECEMBER 2002, 2001 AND 2000

(In thousands of U.S. Dollars, except per share amounts)

 
  Note
  2002
  2001
  2000
 
REVENUES:   2c              
  Net dependable capacity       359,757   224,924   359,296  
  Net electrical output       91,416   43,003   30,726  
       
 
 
 
        451,173   267,927   390,022  
       
 
 
 

OPERATING EXPENSES:

 

 

 

 

 

 

 

 

 
  Fuel       (79,338 ) (42,350 ) (34,554 )
  Plant operations       (27,173 ) (13,574 ) (11,899 )
  Depreciation and amortization       (83,115 ) (80,981 ) (80,127 )
  General, administrative and other       (59,936 ) (31,095 ) (16,356 )
       
 
 
 
        (249,562 ) (168,000 ) (142,936 )
       
 
 
 
OPERATING INCOME       201,611   99,927   247,086  
       
 
 
 

OTHER INCOME (EXPENSES):

 

 

 

 

 

 

 

 

 
  Interest income       47,938   3,012   1,357  
  (Loss) gain on foreign currency exchange       (2,158 ) 134   2,180  
  Interest expense and other financing costs       (154,607 ) (193,611 ) (189,259 )
  Other income (expense)       40   89   (18 )
       
 
 
 
        (108,787 ) (190,376 ) (185,740 )
       
 
 
 

INCOME (LOSS) BEFORE TAX

 

 

 

92,824

 

(90,449

)

61,346

 

INCOME TAX (EXPENSE) BENEFIT

 

2m,13

 

(28,573

)

25,849

 

(18,705

)
       
 
 
 
NET INCOME (LOSS)       64,251   (64,600 ) 42,641  
       
 
 
 

Weighted-average shares of common stock outstanding

 

 

 

25,000

 

25,000

 

25,000

 
Basic earnings (loss) per share       2,570   (2,584 ) 1,706  

See Notes to the Financial Statements, which form an integral part of these financial statements.

341



PT PAITON ENERGY

STATEMENTS OF COMPREHENSIVE INCOME

YEARS ENDED 31 DECEMBER 2002, 2001 AND 2000

(In thousands of U.S. Dollars, except per share amounts)

 
  2002
  2001
  2000
Net income (loss)   64,251   (64,600 ) 42,641
   
 
 

Other comprehensive loss, net of tax:

 

 

 

 

 

 
 
Cumulative effect of change in accounting for derivative financial instruments, net of tax benefit of USD 20,058

 


 

(46,802

)

 
Unrealized loss on derivative financial instruments, net of tax benefit of USD 15,421 and USD 9,767 for 2002 and 2001, respectively

 

(35,982

)

(22,791

)

 
Reclassification adjustment for losses included in net income (loss), net of tax of USD 9,244 and USD 6,513 for 2002 and 2001, respectively

 

21,570

 

15,198

 

   
 
 

Other comprehensive loss

 

(14,412

)

(54,395

)

   
 
 

COMPREHENSIVE INCOME (LOSS)

 

49,839

 

(118,995

)

42,641
   
 
 

See Notes to the Financial Statements, which form an integral part of these financial statements.

342



PT PAITON ENERGY

STATEMENTS OF CHANGES IN SHAREHOLDERS' EQUITY

YEARS ENDED 31 DECEMBER 2002, 2001 AND 2000

(In thousands of U.S. Dollars, except per share amounts)

 
  Share
capital

  Share
premium

  Accumulated
other
comprehensive
loss

  Retained
earnings
(deficit)

  Total
shareholders'
equity

 
Balance at 31 December 1999   306,000   7,000     5,714   318,714  
 
Net income for the year

 


 


 


 

42,641

 

42,641

 
   
 
 
 
 
 

Balance at 31 December 2000

 

306,000

 

7,000

 


 

48,355

 

361,355

 
 
Net loss for the year

 


 


 


 

(64,600

)

(64,600

)
 
Other comprehensive loss

 


 


 

(54,395

)


 

(54,395

)
   
 
 
 
 
 

Balance at 31 December 2001

 

306,000

 

7,000

 

(54,395

)

(16,245

)

242,360

 
 
Net income for the year

 


 


 


 

64,251

 

64,251

 
 
Other comprehensive loss

 


 


 

(14,412

)


 

(14,412

)
   
 
 
 
 
 

Balance at 31 December 2002

 

306,000

 

7,000

 

(68,807

)

48,006

 

292,199

 
   
 
 
 
 
 

See Notes to the Financial Statements, which form an integral part of these financial statements.

343



PT PAITON ENERGY

STATEMENTS OF CASH FLOWS

YEARS ENDED 31 DECEMBER 2002, 2001 AND 2000

(In thousands of U.S. Dollars, except per share amounts)

 
  2002
  2001
  2000
 
CASH FLOWS FROM OPERATING ACTIVITIES:              
  Net income (loss)   64,251   (64,600 ) 42,641  
  Adjustments to reconcile net income (loss) to net cash provided by (used in) operating activities:              
    Depreciation and amortization   83,115   80,981   80,127  
    Loss on retirement or disposal of plant and equipment   3,553      
    Provision for deferred income taxes   28,573   (25,849 ) 18,705  
    Non-cash interest expense   1,362   7,383   8,365  
    Changes in assets and liabilities:              
      Accounts receivable   (53,940 ) (8,622 ) (151,940 )
      Fuel inventory and supplies   (16,123 ) (434 ) (2,977 )
      Prepayments and other   (618 ) 6,127   1,710  
      Taxes payable and other liabilities   32,705   16,645   (98,262 )
      Accounts payable to related parties   7,071   14,920   (19,636 )
      Accrued finance costs   (2,272 ) (420 ) 976  
   
 
 
 
    NET CASH PROVIDED BY (USED IN) OPERATING ACTIVITIES   147,677   26,131   (120,291 )
   
 
 
 
CASH FLOWS FROM INVESTING ACTIVITIES:              
  Acquisition of fixed assets   (2,046 ) (2,813 ) (14,721 )
  Proceeds from sale of fixed assets   50      
   
 
 
 
    NET CASH USED IN INVESTING ACTIVITIES   (1,996 ) (2,813 ) (14,721 )
   
 
 
 
CASH FLOWS FROM FINANCING ACTIVITIES:              
  Proceeds from long-term loans     46,980    
  Repayment of long-term loans   (20,000 )    
  Advances provided by related parties       151,755  
  Proceeds from financing costs refunded     1,858    
   
 
 
 
    NET CASH (USED IN) PROVIDED BY FINANCING ACTIVITIES   (20,000 ) 48,838   151,755  
   
 
 
 
Net increase in cash and cash equivalents   125,681   72,156   16,743  
Cash and cash equivalents at beginning of year   108,030   35,874   19,131  
   
 
 
 
Cash and cash equivalents at end of year   233,711   108,030   35,874  
   
 
 
 
Supplemental cash flow disclosures:              
  Cash paid for interest   155,517   186,965   182,892  
  Conversion of advances provided by related parties to long-term loans     216,022    
  Conversion of accounts payable to related parties to long-term loans   2,974      

See Notes to the Financial Statements, which form an integral part of these financial statements.

344



PT PAITON ENERGY

NOTES TO THE FINANCIAL STATEMENTS

YEARS ENDED 31 DECEMBER 2002, 2001 AND 2000

(In thousands of U.S. Dollars, except per share amounts)

1. GENERAL

        a.    PT Paiton Energy (the "Company") is an Indonesian domiciled company located at Menara Batavia 8th floor, Jalan K.H. Mas Mansyur Kav. 126, Jakarta, which was established within the framework of Foreign Capital Investment Laws No. 1, 1967 and No. 11, 1970 by deed of notary public Sutjipto SH dated 11 February 1994, No. 64 with amendment effected by deed of the same notary public dated 11 January 1995, No. 56. These deeds were approved by the Minister of Justice under No. C2-1-682.HT.01.01.Th.95 on 6 February 1995. The Articles of Association were most recently amended by deed of the same notary public dated 20 November 1998, No. 50; this amendment changed the name of the Company and increased authorized capital. This deed was approved by the Minister of Justice under No. C-2340.HT.01.04.Th.99 on 3 February 1999.

        b.    In accordance with Article 3 of the Articles of Association, approval by the Capital Investment Coordination Board and the Power Purchase Agreement (the "PPA"), as amended, the Company's objective and purpose is to engage in any business and activity in the sector of electric power supply, and to build, own and operate a coal-fired power generating facility (the "Project") consisting of two units located in East Java.

2. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

        The accounting and reporting policies followed by the Company are in accordance with accounting principles generally accepted in the United States of America.

        The significant accounting policies, applied in the preparation of the financial statements for the years ended 31 December 2002, 2001 and 2000, were as follows:

a.    Basis of preparation of financial statements    

        The financial statements are presented in thousands of U.S. Dollars. The Company's functional and reporting currency is the U.S. Dollar as a majority of the Company's cash flows, selling prices, expenses and financing are denominated in U.S. Dollars. The statements of cash flows have been prepared under the indirect method.

b.    Cash and cash equivalents    

        The Company considers investments purchased with maturities of three months or less to be cash equivalents.

c.    Revenue recognition    

        In 2002, revenues were recognized upon the availability of net dependable capacity and the delivery of net electrical output to PT Perseroan Listrik Negara ("PLN"), the Indonesian Government owned electric utility company, and recorded on the basis of prices determined under certain formulae set forth in the PPA, as amended. See Note 14a. PLN is obligated to pay for net dependable capacity upon its availability. PLN is obligated to pay for net electrical output as it is delivered.

        Revenues for the years ended 31 December 2001 and 2000 represent the amounts billed to PLN under the Interim, Phases I, II and III Interim Agreements, and Binding Term Sheet for energy

345



delivered in the respective financial reporting period plus the estimated recoverable value of arrearages relating to capacity charges and fixed operating costs under the PPA which have not been paid by PLN.

d.    Fuel inventory    

        Fuel inventory is valued at the lower of cost or net realizable value. Cost is determined based on the weighted-average method.

e.    Plant and equipment    

        Plant and equipment are recorded at cost including interest on funds borrowed to finance construction of the Project. Depreciation is calculated on a straight-line basis over the following estimated useful lives:

Plant assets and facilities   30 years
Furniture and equipment   4 years

        Certain of the Company's plant assets and facilities require major maintenance on a periodic basis. These costs are expensed as incurred.

f.    Accounting for the impairment of long-lived assets    

        Statement of Financial Accounting Standards ("SFAS") No. 144, "Accounting for the Impairment or Disposal of Long-Lived Assets", provides a single accounting model for long-lived assets to be disposed of. The standard also changes the criteria for classifying an asset as held for sale; and broadens the scope of businesses to be disposed of that qualify for reporting as discontinued operations and changes the timing of recognizing losses on such operations. The Company adopted the standard on 1 January 2002. The adoption of the standard did not affect the Company's financial statements.

        In accordance with the standard, long-lived assets, such as property, plant, and equipment, and purchased intangibles subject to amortization, are reviewed for impairment whenever events or changes in circumstances indicate that the carrying amount of an asset may not be recoverable. Recoverability of assets to be held and used is measured by a comparison of the carrying amount of an asset to estimated undiscounted future cash flows expected to be generated by the asset. If the carrying amount of an asset exceeds its estimated future cash flows, an impairment charge is recognized by the amount by which the carrying amount of the asset exceeds the fair value of the asset. Assets to be disposed of would be separately presented in the balance sheet and reported at the lower of the carrying amount or fair value less costs to sell, and are no longer depreciated.

        The assets and liabilities of a disposed group classified as held for sale would be presented separately in the appropriate asset and liability sections of the balance sheet.

        Prior to the adoption of SFAS No. 144, the Company accounted for long-lived assets in accordance with SFAS No. 121, "Accounting for Impairment of Long-Lived Assets and for Long-Lived Assets to be Disposed Of."

346



g.    Deferred charges    

        Costs incurred for the design, construction and installation of the Special Facilities in accordance with the terms of the PPA are deferred and amortized on a straight-line basis over 30 years.

h.    Deferred financing costs    

        Costs incurred to obtain financing are deferred and are amortized as an adjustment to interest expense on a basis which approximates the effective interest rate method over the terms of the relating financing agreements. Periodic commitment fees incurred subsequent to obtaining financing are treated as interest. Accumulated amortization of these costs amounted to USD 82,450 and USD 63,507 at 31 December 2002 and 2001, respectively.

i.    Derivatives    

        The Company enters into interest rate swap agreements in its management of interest cost exposures. The interest rate swaps, which hedge interest rates on certain indebtedness involve the exchange of floating rate to fixed rate interest payment obligations over the life of the agreements without the exchange of the underlying notional amounts. The Company is exposed to loss if one or more of the counterparties default. Consequently, the Company's exposure to credit loss is significantly less than the contracted amount.

        On 1 January 2001, the Company adopted SFAS No. 133, "Accounting for Derivative Instruments and Certain Hedging Activities" and SFAS No. 138, "Accounting for Certain Derivative Instruments and Certain Hedging Activities, an Amendment of SFAS 133." SFAS Nos. 133 and 138 require that all derivative instruments be recorded on the balance sheet at their respective fair values.

        In accordance with the transition provisions of SFAS No. 133, the Company recorded a cumulative effect adjustment of USD 46,802, net of tax of USD 20,058 in accumulated other comprehensive loss to recognize at fair value all derivatives that are designated as cash-flow hedging instruments. See Note 10. Proforma comprehensive income or loss amounts for 2000 have not been presented as it was impractical to compute such amounts.

        On the date a derivative contract is entered into, the Company designates the derivative as either a hedge of the fair value of a recognized asset or liability or of an unrecognized firm commitment (fair value hedge), a hedge of a forecasted transaction or the variability of cash flows to be received or paid related to a recognized asset or liability (cash flow hedge), a foreign-currency fair-value or cash-flow hedge (foreign currency hedge), or a hedge of a net investment in a foreign operation. For all hedging relationships, the Company formally documents the hedging relationship and its risk-management objective and strategy for undertaking the hedge, the hedging instrument, the item, the nature of the risk being hedged, how the hedging instrument's effectiveness in offsetting the hedged risk will be assessed, and a description of the method of measuring ineffectiveness. This process includes linking all derivatives that are designated as fair-value, cash-flow, or foreign-currency hedges to specific assets and liabilities on the balance sheet or to specific firm commitments or forecasted transactions. The Company also formally assesses, both at the hedge's inception and on an ongoing basis, whether the derivatives that are used in hedging transactions are highly effective in offsetting changes in fair values

347



or cash flows of hedged items. When it is determined that a derivative is not highly effective as a hedge or that it has ceased to be a highly effective hedge, the Company discontinues hedge accounting prospectively.

        Changes in the fair value of a derivative that is highly effective and that is designated and qualifies as a fair-value hedge, along with the loss or gain on the hedged asset or liability or unrecognized firm commitment of the hedged item that is attributable to the hedged risk, are recorded in earnings. Changes in the fair value of a derivative that is highly effective and that is designated and qualifies as a cash-flow hedge are recorded in other comprehensive income to the extent that the derivative is effective as a hedge, until earnings are affected by the variability in cash flows of the designated hedged item. Changes in the fair value of derivatives that are highly effective as hedges and that are designated and qualify as foreign-currency hedges are recorded in either earnings or other comprehensive income, depending on whether the hedge transaction is a fair-value hedge or a cash-flow hedge. However, if a derivative is used as a hedge of a net investment in a foreign operation, its changes in fair value, to the extent effective as a hedge, are recorded in the cumulative translation adjustments account within other comprehensive income. The ineffective portion of the change in fair value of a derivative instrument that qualifies as either a fair-value hedge or a cash-flow hedge is reported in earnings. Changes in the fair value of derivative trading instruments are reported in current period earnings.

j.    Comprehensive income    

        Comprehensive income is defined as the change in equity (net assets) of a business enterprise during a period from transactions and other events and circumstances from non-owner sources. It includes all changes in equity during a period except those resulting from investments by owners and distributions to owners. For the Company, other comprehensive income (loss) consists of changes in the fair market value of derivatives.

k.    Foreign currency translation    

        The books and records of the Company are maintained in United States Dollars as permitted under the license granted by the Ministry of Finance of the Republic of Indonesia through letter No. KEP-194/PJ.42/1994 dated 29 September 1994. Transactions in Indonesian Rupiah and in currencies other than United States Dollars are translated at the rate of exchange prevailing at the date of the transaction. Monetary assets and monetary liabilities outstanding in Indonesian Rupiah and in other currencies at balance sheet date are translated into United States Dollars at rates prevailing as of that date. Realized and unrealized gains and losses arising from exchange rate fluctuations are reflected in the statement of income.

l.    Long-term receivable    

        The Company applies Accounting Principles Board (APB) Opinion No. 21, "Interest on Receivables and Payables," to account for its receivable for the restructuring settlement payments from PLN. The Company has reflected the present value of the restructuring settlement payments, based on a discount rate of 10%. Amortization of the discount is reported as interest income in the statement of income.

348


2. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (Continued)

m.    Income tax expense    

        Deferred taxes are provided based on the asset-liability method whereby deferred tax assets are recognized for deductible temporary differences, and operating loss and tax credit carryforwards, and deferred tax liabilities are recognized for taxable temporary differences. Temporary differences are the differences between the reported amounts of assets and liabilities and their tax bases. Deferred tax assets are reduced by a valuation allowance when, in the opinion of management, it is more likely than not that some portion or all of the deferred tax assets will not be realized. Deferred tax assets and liabilities are adjusted for the effects of changes in tax laws and rates on the date of enactment.

n.    Use of estimates    

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

o.    New accounting standards    

        In June 2001, the FASB issued SFAS No. 143, "Accounting for Asset Retirement Obligations," which is effective on 1 January 2003. The standard requires entities to record the fair value of a liability for an asset retirement obligation in the period in which it is incurred. When the liability is initially recorded, the entity capitalizes a cost by increasing the carrying amount of the related long-lived asset. Over time, the liability is increased to its present value each period, and the capitalized cost is depreciated over the useful life of the related asset. Upon settlement of the liability, an entity either settles the obligation for its recorded amount or incurs a gain or loss upon settlement. The Company has adopted this standard effective 1 January 2003. Management does not believe that the new standard will have a material effect on the Company's financial statements.

        Effective 1 January 2002, the Company adopted SFAS No. 142, "Goodwill and Other Intangible Assets." The Company did not have goodwill or intangible assets at any time during 2002, and accordingly the adoption of the standard did not have an effect on the Company's financial statements.

        In April 2002, the FASB issued SFAS No. 145, "Rescission of FASB Statements No. 4, 44, and 64, Amendment of FASB Statement No. 13, and Technical Corrections," which supersedes previous guidance for reporting gains and losses from extinguishment of debt and accounting for leases, among other things. The provisions of the Statement related to the rescission of Statement No. 4 is applied in fiscal years beginning after 15 May 2002. Earlier application of these provisions is encouraged. The provisions of the Statement related to Statement No. 13 were effective for transactions occurring after 15 May 2002, with early application encouraged. The adoption of this standard is not expected to have a material effect on the Company's financial statements.

        In July 2002, the FASB issued SFAS No. 146, "Accounting for Costs Associated with Exit or Disposal Activities," which is effective on 1 January 2003. The standard requires that liabilities for costs associated with exit or disposal activities initiated after 31 December 2002 be recognized when incurred,

349



rather than at the date of a commitment to an exit or disposal plan. Management does not expect this standard will have a material effect on the Company's financial statements.

        In November 2002, the FASB issued Interpretation No. 45, "Guarantor's Accounting and Disclosure Requirements for Guarantees, Including Indirect Guarantees of Indebtedness to Others, an interpretation of FASB Statements No. 5, 57 and 107 and a rescission of FASB Interpretation No. 34." This Interpretation elaborates on the disclosures to be made by a guarantor in its interim and annual financial statements about its obligations under guarantees issued. The Interpretation also clarifies that a guarantor is required to recognize, at inception of a guarantee, a liability for the fair value of the obligation undertaken. The initial recognition and measurement provisions of the Interpretation are applicable to guarantees issued or modified after 31 December 2002 and are not expected to have a material effect on the Company's financial statements. The disclosure requirements are effective for financial statements of interim or annual periods ending after 15 December 2002.

3. CASH AND CASH EQUIVALENTS

 
  2002
  2001
Cash on hand   3   3
Cash in banks   231,758   107,145
Time deposits     288
Call deposits   1,950   594
   
 
    233,711   108,030
   
 

4. LONG-TERM RECEIVABLE

        As discussed in Note 14a, the Company and PLN entered into the amendments to the PPA, which among other matters provides for restructuring settlement payments for the settlement of arrearages of amounts billed by the Company to PLN. The Company has reflected the present value of the restructuring settlement payments, based on a discount rate of 10%, as a long-term receivable totaling USD 453,270 and USD 455,803 at 31 December 2002 and 2001, respectively. In 2002, the Company received restructuring settlement payments aggregating USD 48,000 of which USD 2,534 was accounted for as collections of the receivables owed by PLN. The remainder totaling USD 45,466 was accounted for as interest income.

 
  2002

  2001
Total restructuring settlement payments   1,392,000   1,440,000
Less: unamortized discount   938,730   984,197
   
 
Long-term receivable less unamortized discount   453,270   455,803
   
 

350


5. FUEL INVENTORY AND SUPPLIES

 
  2002
  2001
Coal inventory   19,528   7,138
Fuel oil inventory   68   120
Supplies   4,970   1,185
   
 
    24,566   8,443
   
 

6. PLANT AND EQUIPMENT

        a.    Plant and equipment are comprised of the following:

 
  2002

 
 
  Beginning
balance

  Additions
  Retirements &
disposals

  Ending
balance

 
At cost:                  
  Plant assets and facilities   2,171,605   796   (3,603 ) 2,168,798  
  Furniture and equipment   6,513   1,222   (132 ) 7,603  
   
 
 
 
 
    2,178,118   2,018   (3,735 ) 2,176,401  
   
 
 
 
 

Accumulated 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

 
   
 
 
 
 
 
  2001
 
 
  Beginning
balance

  Additions
  Ending
Balance

 
At cost:              
  Plant assets and facilities   2,102,632   68,973   2,171,605  
  Furniture and equipment   5,421   1,092   6,513  
   
 
 
 
    2,108,053   70,065   2,178,118  
   
 
 
 

Accumulated depreciation:

 

 

 

 

 

 

 
  Plant assets and facilities   (106,983 ) (70,338 ) (177,321 )
  Furniture and equipment   (2,993 ) (1,250 ) (4,243 )
   
 
 
 
    (109,976 ) (71,588 ) (181,564 )
   
 
 
 

Net book value

 

1,998,077

 

(1,523

)

1,996,554

 
   
 
 
 

351


6. PLANT AND EQUIPMENT (Continued)

        b.    Depreciation charged to operating expenses amounted to USD 73,721, USD 71,588, and USD 70,686 in 2002, 2001 and 2000, respectively.

        c.    Substantially all of the Company's assets have been pledged as collateral for the repayment of long-term debt (see Note 9).

7. DEFERRED CHARGES

 
  2002
  2001
 
Special facilities costs deferred   281,814   281,786  
Less accumulated amortization   (32,924 ) (23,530 )
   
 
 
Net deferred charges   248,890   258,256  
   
 
 

        Deferred charges represent costs incurred for the design, construction and installation of the Special Facilities in accordance with the terms of the PPA. The Special Facilities constitute electrical interconnection facilities at the Paiton Complex, the expansion of the Paiton Complex's water intake and discharge canals and site preparation work at the Paiton Complex. The Company had the care, custody, and control and bore the risk of loss with respect to the Special Facilities until they were accepted by PLN in 1999.

        The Special Facilities recorded in these financial statements are owned by PLN; however, the Company has the right to use the Special Facilities throughout the term of the PPA, as amended.

        Amortization charged to operating expenses amounted to USD 9,394, USD 9,393, and USD 9,441 in 2002, 2001 and 2000, respectively.

8. RELATED PARTY TRANSACTIONS

        a.    Reimbursable costs

        Certain costs were incurred by related parties on behalf of, and charged to the Company. These costs aggregated approximately USD 3,813, USD 2,454 and USD 4,333 in 2002, 2001 and 2000, respectively.

        b.    Certain other transactions with related parties are also discussed in Note 9 and Note 14.

352



9. LONG-TERM LOANS

        Long-term loans were comprised as follows:

 
  2002
  2001
 
Senior Debt Facilities          
  USEXIM Facility   507,882   514,363  
  JEXIM Facility—tranche A   506,398   513,000  
  JEXIM Facility—tranche B   337,603   342,000  
  OPIC Facility   197,480   200,000  
   
 
 
    1,549,363   1,569,363  
   
 
 
Senior Debt Funding Loan   180,000   180,000  
   
 
 
Subordinated Loans          
  Edison Mission Energy Asia Pte., Ltd.   176,004   176,004  
  Paiton Power Financing B.V.   143,018   143,018  
  Capital Indonesia Power I C.V.   54,978   54,978  
   
 
 
    374,000   374,000  
   
 
 
Series B Subordinated Loans          
  Edison Mission Energy Asia Pte., Ltd.   137,296   135,896  
  Paiton Power Financing B.V.   92,949   91,812  
  Capital Indonesia Power I C.V.   35,731   35,294  
   
 
 
    265,976   263,002  
   
 
 
Total   2,369,339   2,386,365  
Current maturities of long-term loans   (140,851 ) (1,569,363 )
   
 
 
Non-current portion   2,228,488   817,002  
   
 
 

Senior Debt Facilities

        On 31 March 1995, the Company entered into an agreement (the "Common Agreement", as amended as of 25 March 1996) with the following lenders: The Export-Import Bank of the United States ("USEXIM"), Japan Bank for International Cooperation ("JBIC"), as successors in interest to The Export-Import Bank of Japan ("JEXIM"), and Overseas Private Investment Corporation ("OPIC"). The principal effect of the Common Agreement is to establish certain uniform terms which are applicable to the senior debt facilities provided such as funding, payments and prepayments, conditions precedent, representations and warranties, affirmative and negative covenants, and events of default. Separate financing agreements for the senior debt facilities have been entered into with each of the lenders who were to provide an aggregate of USD 1,820,000. All of the senior debt facilities are variable rate based loans except for the JEXIM tranche A loan which bears interest at 9.44%. The Company has entered into interest rate swap agreements on a portion of its debt to reduce the impact of changes in interest rates on its floating rate long-term debt. See Note 10.

353



        The obligations of the Company are collateralized by pledges of all of the Company's capital stock and liens on and security interests in substantially all of the Company's assets (including plant assets), its rights under various agreements, all of the Company's revenues and all insurance proceeds payable to the Company. The financing agreements contain restrictions, which, among other items, require the Company to comply with various administrative requirements. The agreements with lenders also require the Company to pay certain fees.

        Interest on loans is due on a quarterly basis in arrears, and coincides with the scheduled principal payments dates. Repayment of the loan principal becomes due over a period of twelve years commencing from 1999. None of the scheduled repayments of principal totaling approximately USD 453,761 as of 31 December 2002 were made during 2000 and 2001, and only USD 20,000 was repaid in 2002. See the following paragraph concerning the waivers of events of default.

        In response to PLN's failure to pay invoices submitted to it under the PPA (see Note 14a), on 15 October 1999, the Company entered into an Interim Arrangement Agreement (the "Interim Arrangement"), as amended as of 30 December 2002 with the senior lenders. Under this agreement, the parties agree to enter into certain waivers pursuant to the Financing Agreements, and amendments to the Common Agreement, in order to establish an interim arrangement under the Financing Agreements. These waivers include events of default that may exist solely as a result of the failure of the Company to repay principal amounts on the scheduled dates therefore which occur during the term of the Interim Arrangement. Interest and fees continue to be paid on a timely basis. This Interim Arrangement terminated on 13 February 2003, when the Company and all the lenders reached an agreement on restructuring the terms of the senior debt facilities. This restructuring will be accounted for as a troubled debt restructuring in 2003 with no change to the carrying value of the debt.

        At 31 December 2002, the amounts due under the senior debt facilities were classified in the balance sheet based on restructured terms for the maturity of the debt. At 31 December 2001, all amounts due under the senior debt facilities were classified as a current liability in the balance sheet as the Company was in default of the debt repayment provisions of the senior debt financing agreements.

Senior Debt Funding Loan

        On 28 March 1996, Paiton Energy Funding B.V., a Netherlands corporation (the "Issuer") issued USD 180,000 of senior secured bonds (the "Bonds") to certain institutional investors. The net proceeds from the sale of the bonds were used by the Issuer to acquire certain senior indebtedness which consisted of loans made to the Company by various commercial banks and financial institutions under the Commercial Banks Facility—tranche A in place as of 31 March 1996. Upon closing of the offering for the Bonds, such senior indebtedness was replaced by the Senior Debt Funding Loan and the payment terms and the interest rate which applied to the such indebtedness were amended to contain terms which are identical to the Bonds. The Bonds bear interest at 9.34% per annum with interest payable on a quarterly basis commencing in May 1996. The Bonds mature in 2014 and principal payments commence in 2008.

        The Company has unconditionally guaranteed the payment obligations of the Issuer in respect of the Bonds. The Senior Debt Funding Loan and the guarantee will be secured, on a pari passu basis

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with the other senior debt, by pledges of the Company's capital shares and liens on, and security interests in, substantially all of the assets of the Company. The maximum potential amount of undiscounted future payments that the Company could be required to make under the guarantee is USD 180,000, which is the current carrying amount of the Senior Debt Funding Loan reflected in these financial statements.

Subordinated Loans

        On 31 March 1995, the Company entered into a subordinated loan agreement with Edison Mission Energy Asia Pte., Ltd., Paiton Power Financing B.V., and Capital Indonesia Power I C.V. (the "Subordinated Lenders"). Each of the Subordinated Lenders is affiliated with shareholders of the Company. Under this agreement, the Subordinated Lenders or their affiliates are obligated to make subordinated loans to the Company in a maximum aggregate amount of USD 487,438. The subordinated loans bear no interest prior to the last day of the availability period (such day has been established as 15 October 1999). After the availability period, interest on the outstanding principal amount is determined at 15% per annum. The repayment of any outstanding principal will not commence until 27 years after the completion of the Project. The Subordinated Lenders cancelled the Company's interest obligation for the years 2002, 2001 and 2000 on or before the commencement of each of the respective years.

Series B Subordinated Loans

        In 2001, the Company entered into the 1999 Series B Subordinated Loan Agreement with the Subordinated Lenders. Under this agreement, the Subordinated Lenders shall make loans to the Company in a maximum aggregate amount of USD 300,000. The 1999 Series B Subordinated Loans bear no interest until such time as the Company and Subordinated Lenders agree otherwise in writing. The repayment of any outstanding principal will not commence until 27 years after the completion of the Project.

        The subordinated loans referred to in the two preceding paragraphs are subordinated to the senior debt facilities provided under the Common Agreement and the Senior Debt Funding Loan.

        The following table presents the approximate annual maturities of long-term debt for the five years after 31 December 2002:

2003   140,851
2004   140,851
2005   140,851
2006   140,851
2007   140,851
Thereafter   1,665,084
   
    2,369,339
   

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10. DERIVATIVE FINANCIAL INSTRUMENTS

        The Company has entered into interest rate swap agreements on a portion of its debt to reduce the impact of changes in interest rates on its floating rate long-term debt. Under the agreements, the Company will receive or pay interest on the differential of notional principal amounts based on the London Interbank Offering Rate ("LIBOR") and the same notional amounts based on a weighted average fixed interest rate of 7.3% from July 1995 until August 1999, and 9% from August 1999 through August 2011 including the credit spread. At 31 December 2002, LIBOR was 1.4% per annum. Payments are made at the end of calculation periods (scheduled three-month periods) which commence primarily in 1995 and 1999 and end in 1999 and 2011. The notional principal amounts vary over the calculation periods; however, they were intended to correspond with anticipated borrowing levels over the period of the long-term financing.

        In accordance with SFAS No. 133, as amended, the Company recorded a liability for the loss on these interest rate swap agreements of USD 98,296 and USD 77,707, before income taxes, as of 31 December 2002 and 2001, respectively. This amount has been reflected in other comprehensive loss as the Company has designated these agreements as cash flow hedges. The estimated unrealized losses of USD 98,296 at 31 December 2002 include approximately USD 29,452 that is expected to be reclassified into earnings in 2003.

        Under the agreements, the aggregate notional principal is at its highest level (approximately USD 1,100,000) in 1999. At 31 December 2002, notional principal subject to the swap agreements totaled approximately USD 408,333, bearing fixed interest at a weighted average rate of approximately 9%.

        By using derivative financial instruments to hedge exposures to changes in interest rates, the Company exposes itself to credit risk and market risk. Credit risk is the failure of the counterparty to perform under the terms of the derivative contract. When the fair value of a derivative contract is positive, the counterparty owes the Company, which creates credit risk for the Company. When the fair value of a derivative contract is negative, the Company owes the counterparty and, therefore, it does not possess credit risk. The Company minimizes the credit risk in derivative instruments by entering into transactions with high-quality counterparties whose credit quality is reviewed regularly.

        Market risk is the adverse effect on the value of a financial instrument that results from a change in interest rates. The market risk associated with interest-rate contracts is managed by establishing and monitoring parameters that limit the types and degree of market risk that may be undertaken.

        The following table represents the derivatives in place as of 31 December 2002:

 
  Notional
amount

  Maturity
date

  Swap
rate

  Fair market value at
31/12/2002

 
Interest rate swap   131,250   15/08/2011   8.965%   (31,428 )
Interest rate swap   131,250   15/08/2011   9.035%   (31,811 )
Interest rate swap   72,917   15/08/2011   8.980%   (17,506 )
Interest rate swap   72,916   15/08/2011   8.995%   (17,551 )
   
         
 
    408,333           (98,296 )
   
         
 

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11. FAIR VALUE OF FINANCIAL INSTRUMENTS

        The following disclosure of the estimated fair value of financial instruments is made in accordance with the requirements of SFAS No. 107, "Disclosures about Fair Value of Financial Instruments". The estimated fair value amounts have been determined by the Company, using available market information and appropriate valuation methodologies. However, considerable judgment is necessarily required in interpreting market data to develop the estimates indicative of the amounts that the Company could realize in a current market exchange. The use of different market assumptions and/or estimation methodologies may have a material effect on the estimated fair value amounts.

        The following methods and assumptions were used to estimate the fair value of each class of financial instruments:

        Cash and cash equivalents, accounts receivable, and accounts payable to related parties—the carrying amounts approximate fair value because of the short maturity of these instruments.

        Long-term receivable—the fair value of the long-term receivable is estimated based on discounting the future cash flows using the interest rate at which a similar restructuring settlement payment would be agreed with a customer with a similar credit rating and similar remaining maturity.

        Long-term loans—the fair value of long-term loans is estimated by discounting the future cash flows of each instrument at rates currently offered to the Company for similar debt instruments of comparable maturities by the Company's bankers.

        Interest rate swap contracts—the fair value of interest rate swaps (used for hedging purposes) is the estimated amount the Company would receive (or pay) to terminate the swap agreements at the reporting date, taking into account current interest rates and the current credit worthiness of the swap counterparties.

 
  2002
  2001
 
 
  Carrying
amount

  Estimated
fair value

  Carrying
amount

  Estimated
fair value

 
Financial assets:                  
  Cash and cash equivalents   233,711   233,711   108,030   108,030  
  Accounts receivable   83,204   83,204   26,731   26,731  
  Long-term receivable   453,270   453,270   455,803   455,803  

Financial liabilities:

 

 

 

 

 

 

 

 

 
  Accounts payable to related parties   (180,243 ) (180,243 ) (176,146 ) (176,146 )
  Long-term loans   (2,369,339 ) (2,238,788 ) (2,386,365 ) (2,320,905 )
  Interest rate swap contracts   (98,296 ) (98,296 ) (77,707 ) (77,707 )

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12. SHARE CAPITAL

        The composition of the Company's shareholders as of 31 December 2002 and 2001 was as follows:

 
  Issued and paid-up share capital
   
 
  Paid in advance for shares to be issued
Shareholders

  Number of
Shares

  Par value
MEC Indonesia, B.V.   10,000   100,000   22,400
Paiton Power Investment Co. Ltd.   8,125   81,250   18,200
Capital Indonesia Power I C.V.   3,125   31,250   7,000
PT Batu Hitam Perkasa   3,750   37,500   8,400
   
 
 
    25,000   250,000   56,000
   
 
 

13. INCOME TAX

        Income tax (expense) benefit attributable to income (loss) from operations consists of:

 
  2002
  2001
  2000
 
Current        
Deferred   (28,573 ) 25,849   (18,705 )
   
 
 
 
    (28,573 ) 25,849   (18,705 )
   
 
 
 

        The Company's income tax (expense) benefit differed from the amount computed by applying the Indonesian tax rate of 30% to income (loss) before tax as follows:

 
  2002
  2001
  2000
 
Indonesian income tax (expense) benefit at statutory rate   (27,847 ) 27,135   (18,404 )
Items not deductible for tax purposes   (726 ) (1,286 ) (301 )
   
 
 
 
    (28,573 ) 25,849   (18,705 )
   
 
 
 

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        The items that give rise to significant portions of the deferred tax assets and deferred tax liabilities at 31 December 2002 and 2001 are presented below:

 
  2002
  2001
 
Deferred tax assets:          
  Derivative financial instruments   29,489   23,312  
  Accrued liabilities   12,929   7,681  
  Deferred financing costs   1,667    
  Net operating loss carryforwards   18,536   43,242  
   
 
 
Net deferred tax assets   62,621   74,235  
   
 
 
Deferred tax liabilities:          
  Fixed assets and deferred charges, principally due to differences in depreciation and capitalized interest   (58,418 ) (45,544 )
  Deferred financing costs     (2,092 )
   
 
 
Net deferred tax liabilities   (58,418 ) (47,636 )
   
 
 
Deferred tax assets, net   4,203   26,599  
   
 
 

        At 31 December 2002, the Company had tax loss carryforwards totaling approximately USD 62,000 which will expire in 2006. Realization of the Company's deferred tax assets is dependent upon profitable operations. Although realization is not assured, the Company believes that it is more likely than not that these deferred tax assets will be realized through the offset of future taxable income. The amount of deferred tax assets considered realizable, however, could be reduced if actual future taxable income is lower than estimated.

        Under the Indonesian tax laws, the Company submits tax returns on the basis of self-assessment. The taxation authorities may assess or amend taxes within ten years after the date the tax became payable. The Company is, and may in the future be, under examination by the Indonesian tax authority with respect to positions taken in connection with the filing of tax returns. Matters raised upon audit may involve substantial amounts, which, if resolved unfavorably, an event not currently anticipated, could possibly be material. However, in the Company's opinion, it is unlikely that the resolution of any such matters will have a material adverse effect upon the Company's financial condition or results of operations.

14. COMMITMENTS AND CONTINGENCIES

a.    Power Purchase Agreement    

        On 12 February 1994, the Power Purchase Agreement (the "PPA", as amended as of 28 June 2002), was entered into by the Company and PLN. Under the PPA, as amended, the Company is responsible for arranging the design, engineering, supply and construction of the Project as well as the operation and maintenance of the power generating units and associated common and shared facilities.

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        The Company has constructed and owns and operates the plant facilities at a site provided by PLN which is located at Paiton, East Java. The Company is obligated to pay PLN Rp 160,000,000 (approximately USD 18 as of 31 December 2002) annually for the right to use the site.

        Upon commercial operation of the Project, the Company is obligated to make available the net electrical output of the Project's plant facilities to PLN which will be purchased by PLN at amounts determined under certain formulae set forth in the PPA, as amended. The amounts to be paid by PLN for the purchase of net dependable capacity, net electrical output, emergency output and other items provided for within the PPA, as amended, may be adjusted to ensure that the Company has the same net, after tax economic return should a triggering event occur. Triggering events include but are not limited to the adoption, enactment, or application of, or any change in the interpretation or application of any legal requirements of any governmental instrumentality of the Republic of Indonesia which has or will result in material cost or savings to the Company of producing electricity.

        The term of the PPA, as amended, commenced on 12 February 1994 and will expire on 31 December 2040, unless terminated earlier in accordance with the terms of the PPA, as amended.

        Under the PPA, as amended, the electricity unit price to be paid for net dependable capacity and net electrical output consists of two parts, the capacity payment (which includes Component A for capital cost recovery, and Component B for fixed operation and maintenance cost recovery) and the energy payment (which includes Component C for fuel and Component D for variable operation and maintenance cost recovery). In addition to the two-part electricity unit price, supplemental payments shall be payable in the case of emergency output, start-up fuel costs attributable to PLN actions and net electrical output prior to commission date.

        The electricity unit price is comprised of foreign currency and non-foreign currency portions which essentially represent U.S. Dollars and Rupiah, respectively. The majority of revenues earned based on the unit price are denominated in U.S. Dollars.

        In May 1999, the Company notified PLN that the first 615 MW unit of the Project had achieved commercial operation under terms of the PPA, as amended, and, in July 1999, that the second 615 MW unit of the Project had similarly achieved such commercial operation. Because of the economic downturn, PLN was experiencing low electricity demand and PLN had, through February 2000, been dispatching the Paiton plant to zero. Pending finalization of discussions to amend and restructure the original PPA, PLN and the Company entered into various interim agreements, underwhich dispatch level fixed and energy payments were agreed.

        On 28 June 2002, the Company and PLN entered into the Amendment to Power Purchase Agreement ("PPAA"). Under the PPAA, both parties agreed to amend certain provisions of the Original PPA and to set out certain other matters in connection with such amendments. On 23 December 2002, the Company and PLN signed the Certificate of Effectiveness of the PPAA. Previously, the Company and PLN entered into a Binding Term Sheet, dated as of 14 December 2001 and effective as of 1 January 2002, to set forth the commercial terms of agreement on the principal amendments to the original PPA, including among other things changing the term of the Original PPA, and providing for Restructuring Settlement Payments ("RSP") for the settlement of arrearages.

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        Under the PPAA, the Company is to be paid for capacity and energy charges, as well as a monthly Restructuring Settlement Payment ("RSP") covering arrears owed by PLN as well as settlement of other claims. The monthly RSP is USD 4,000 and is payable over a period of 30 years commencing on 1 January 2002. See Note 4.

b.    EPC Contract    

        The Company entered into a turnkey engineering, procurement and construction contract (the "EPC Contract") dated 10 February 1995 with a consortium of companies (the "Contractor") which include Mitsui & Co., Ltd., a company which has an affiliation with one of the Company's shareholders. Under the EPC Contract, the Contractor will provide to the Company design, engineering, procurement, construction, start-up testing and commissioning services for the Project's plant and special facilities. The total price to be paid to the Contractor is approximately USD 1,800,000. Services under the EPC contract commenced in 1995 and were substantially completed in 1999.

        The Company was in arbitration proceedings with its Contractor carrying out construction work at the Company's project site arising out of a slope failure at the site. Initial awards were rendered establishing that the Contractor was not responsible for the slope failure and are, therefore, entitled to certain costs incurred in connection with the slope failure. The Contractor applied to the Arbitral Tribunal for a Partial Final Award and on 7 December 1999, the Tribunal issued a Provisional Award totaling USD 15,000, which was paid (less 2% withholding tax) by the Company to the Contractor in December 1999. On 5 January 2001, Contractor and the Company's respective counsel jointly advised the Arbitral Tribunal of the parties' fully executed Global Settlement Agreement, and requested that the arbitration be terminated and dismissed. The Arbitral Administrator acknowledged the dismissal of the arbitration.

        On 14 March 2000, the Company and Contractor entered into a Global Settlement Agreement (the "GSA", as amended on 18 December 2000). Under the GSA, the Company committed to pay the Contractor the sum of USD 135,000 as a Final Costs Claim Payment ("FCCP").

        The Final Cost Claims Payment shall be the full and final compensation for all of the Contractor's cost claims, known and unknown, arising out of or related to its performance of work on project, including but not limited to, all extra work claims, all requests for change orders, payment of the retention, payment of all unpaid payment milestones, claims arising out of inadequate access to the PLN grid, claims arising out of the failure and subsequent remediation of the south slope, all claims arising out of the Company's alleged improper set-off of amount payable to the Contractor, and all the interest claims related thereto. Interest accrues on the unpaid portion of the FCCP until the FCCP is paid in full. The Company recognized interest expense in this connection aggregating approximately USD 25,914 through 31 December 2002. Under the GSA, the Company is obligated to repay the entire amount of the FCCP as soon as reasonably practicable and, in any event, 30 September 2003 has been set as a target date for full payment of amounts owed to the Contractor pursuant to the GSA. However, this date represents only a non-binding estimate of the date of final payment, and there are no consequences to the Company if the Company is unable to settle the final payment by this date. The Company must pay all amounts owing under the GSA prior to payments of the subordinated debt

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or dividends. The accompanying financial statements include amounts due to the Contractor aggregating USD 177,164 and USD 171,856 as of 31 December 2002 and 2001, respectively.

        The Company had initiated an arbitration claim against the insurance carriers of the Company's construction all risk policy for costs relating to the slope failure. The Company has decided not to proceed with its claims against the insurance carrier, and filed a Notice of Discontinuance dated 11 December 2002 at the High Court in London. The insurer has asserted that it is entitled to recover its costs of arbitration. The Company and legal counsel have no basis to estimate the amount of costs that may be claimed by the insurer.

c.    Operations and Maintenance Agreement    

        The Company is a party to an operations and maintenance agreement (the "O&M Agreement") with PT Edison Mission Operation and Maintenance Indonesia (the "Operator"), which is affiliated with one of the Company's shareholders. The obligations of the Company and the Operator under the O&M Agreement became effective in April 1995 and continue for a term that is coterminous with the PPA. The obligations of the Operator under the O&M Agreement are guaranteed by Edison Mission Operation and Maintenance Incorporated (also affiliated with one of the shareholders of the Company).

        Under the terms of the O&M Agreement, the Operator will provide the operation, maintenance and repair services necessary for the production and delivery of electrical energy by the plant.

        The Operator will receive an annual base fee of USD 3,250 payable in equal monthly installments. The base fee shall be subject to periodic adjustments based on the US Consumer Price Index. The Company was billed USD 3,595, USD 3,502 and USD 3,385 by the Operator in 2002, 2001 and 2000, respectively.

        Commencing from Operational Acceptance of the Plant, the Company shall pay to or receive from the Operator an incentive fee or performance shortfall amount. The Company incurred an incentive fee of USD 1,533 in 2002 which was charged to plant operations costs in the statement of income. No incentive fees were incurred nor were performance shortfall amounts received in 2001 and 2000.

d.    Fuel Supply    

        The Company entered into a fuel supply agreement (the "Fuel Supply Agreement") with PT Batu Hitam Perkasa ("BHP"), one of the shareholders of the Company. Under this agreement, BHP was obligated to deliver coal to the plant in accordance with the approved coal supply plan. The Fuel Supply Agreement was for a term which commenced in April 1995 and which was scheduled to terminate on the thirtieth anniversary of the commercial operation date of the plant. From and after the commercial operation date, the Company was obligated to purchase a minimum of 700,000 tons of coal per quarter.

        BHP made a claim of approximately Rp 48,000,000 (USD 5,400) for coal delivered to the Company. BHP claimed that it was entitled to an upward adjustment in the price of coal delivered to reflect foreign exchange rate fluctuations since January 1998. The Company disputed the entire claim,

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while having paid one half of the pending claim under protest. An arbitration proceeding initiated by the Company under the Fuel Supply Agreement was commenced in 1999.

        On 15 September 1999, a Fuel Chain Temporary Suspension Agreement (the "Agreement"), as amended on 21 December 1999, was entered by and among the Company, BHP, PT Adaro Indonesia ("Adaro"), PT Indonesia Bulk Terminal ("IBT"), Louis Dreyfus Amarteurs, S.N.C. ("LDA"), (the "Parties"). Under the Agreement, the Parties agreed to suspend their respective rights and obligations under each of the Contracts (Fuel Supply Agreement between the Company and BHP, Coal Purchase Agreement between BHP and Adaro, Coal Terminal Service Agreement between BHP and IBT, Contract of Affreightment between BHP and LDA) until March 2002. In July 2002, BHP informed the Tribunal that it wished to reactivate the arbitration and asserted additional claims against the Company totaling approximately USD 250,000. On 19 December 2002, the Company and BHP entered into a Settlement Agreement. Under the Agreement, the Company and BHP agreed to settle for an aggregate settlement of USD 16,225. The Company paid BHP USD 10,250 on 30 December 2002 and has accrued the remaining USD 5,975 in its financial statements at 31 December 2002. In December 2002, the Company and BHP jointly notified the Tribunal of the Settlement Agreement and requested that BHP's supplemental counterclaims be dismissed with prejudice.

        Subsequent to 31 December 2002, on 12 February 2003, the Company and IBT entered into the IBT Settlement Agreement. Under this Agreement, the Coal Terminal Service Agreement entered into by BHP and IBT in 1995 has been terminated. Under the IBT Settlement Agreement, the Company is obligated to make a termination payment aggregating USD 28,572 payable in three instalments, USD 15,957 payable on 31 October 2003, USD 5,472 payable on 31 December 2003 and USD 7,143 payable on 31 March 2004. The total termination payment was accrued in the 31 December 2002 financial statements.

        The Company and Louis Dreyfus Armateurs, S.N.C ("LDA") entered into the LDA Settlement Agreement (the "Agreement") dated 4 December 2001, as amended as of 31 January 2003. Under the Agreement, the Company shall pay to LDA an aggregate principal amount of USD 13,000 as the Termination Payment. The Company shall pay the full amount of the Termination Payment on the date that is 30 days after the date on which the Company shall have made the second of two consecutive, regularly scheduled principal payments under the Senior Lender Financing Agreements. The maximum delay payment is on or before 31 December 2006. Interest is payable on the aggregate unpaid principal amount of Termination Payment at LIBOR plus 1.5% per annum beginning on 31 January 2003.

        On 20 December 2002, the Company reached agreements with PT Adaro Indonesia and PT Kideco Jaya Agung ("fuel suppliers") for primary fuel supply. The fuel suppliers agree to supply coal to the Company up to a maximum specified annual quantity through 2006. The base price of coal will be equal to its fuel component. There is no commitment on the part of the Company with regard to minimum fuel take in any year.

e.    PLN Labor Union Litigation    

        PLN's Labor Union initiated a lawsuit in 2001 against the Company, PLN, the Minister of Mines & Energy and a former PLN President Director. The suit seeks the termination of the PPA,

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damages equal to USD 590,000, as well as USD 2,500,000 of immaterial damages (damages the amount of which cannot now be stated) and other relief. On 17 April 2002, the Court rendered a decision in favor of the Company and the other defendants. On 23 April 2002, the PLN Union registered its appeal against the decision of the District Court to the High Court. All the appeals are pending at the High Court.

        The Company's counsel has advised the Company that PLN's Labor Union has no standing under existing law to assert any such claim against the Company and there are numerous legal and factual defects in the plaintiff's claim for relief. The Company will vigorously defend this meritless action and will move promptly for a dismissal of this suit. Management believes that, based upon applicable law in place in Indonesia at this time, the suit is clearly without merit and, upon the proper application of applicable legal precepts by the court, this suit will be resolved in the Company's favor.

15. CONCENTRATIONS OF RISK

        The Company's operations are currently principally conducted in Indonesia and it is accordingly subject to special considerations and significant risks not typically associated with companies incorporated in the United States of America and Western European countries.

        The Company's results may be adversely affected by changes in the political and social conditions in Indonesia and by changes in governmental policies with respect to laws and regulations, anti-inflationary measures, currency conversion and remittance abroad, and rates and methods of taxation, among other things.

        Many Asia Pacific countries, including Indonesia, are experiencing severe economic difficulties including volatile currency fluctuations and interest rates, liquidity problems, volatility in prices, and significant slowdowns in business activity. The crisis has also involved declining prices in shares listed on Indonesian stock exchanges, tightening of available credit, stoppage or postponement of certain construction projects.

        The Company's operations have been affected and may continue to be affected, for the foreseeable future, by the political and economic turmoil. It is uncertain how future political and economic developments in Indonesia will affect the Company's operation and results. As a result, there are uncertainties that may affect future operations of the Company.

        The economic crisis in Indonesia during 1998 necessitated a restructuring of the PPA with PLN, the Company's sole customer. PLN's inability pay to the Company a portion of the amounts due under the PPA resulted in the Company not being able to make repayments of the senior debt in accordance with the original debt amortization schedules. As a result, the Company was in default of the senior debt agreements. This resulted in a significant uncertainty with respect to the Company's ability to continue as a going concern as at 31 December 2001 and 2000.

        In December 2002, the PPA was amended as discussed in Note 14a. PLN has paid all invoices and all Restructuring Settlement Payments for 2002, as required and in accordance with the billing procedures agreed in the Binding Term Sheet and the amended PPA.

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        As discussed in Note 9, the senior debt was restructured in February 2003. In connection with the restructuring of the senior debt, the amortization schedule for repayment of the Company's loans was extended to take into account the effect upon the Company of the lower cash flow resulting from the restructured electricity tariff set forth in the PPA as amended. The initial principal repayment under the new amortization schedule was made on 18 February 2003, totaling approximately USD 35,200. The Company believes that it will have sufficient cash flows to meet its obligations for repayment of debt, interest and other liabilities as and when they come due in 2003.

        The generation of electricity by the plant requires the use of coal for fuel that must meet certain quality standards. The Company purchases coal from a limited number of suppliers, however, the Company believes that other suppliers could provide similar quality coal on comparable terms. The time required to locate and qualify other coal suppliers, however, could cause a delay in electricity generation that may be disruptive to the Company.

16. LIQUIDITY

        The Company's management has undertaken a detailed analysis of the cash flows of the Company for the twelve months ended 31 December 2003. Based on the forecast for the next twelve months, management has determined that sufficient liquidity exists to fund the operations of the business during that period. In preparing the forecast, management has reviewed historic cash requirements of the Company as well as key factors which may impact the operations of the Company during the next twelve-month period, and are of the opinion that the assumptions and sensitivities which are included in the cash flow forecast are reasonable. However, as with all assumptions in regard to future events, these are subject to inherent limitations and uncertainties and some or all of these assumptions may not be realized.

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SIGNATURES

        Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.

    MISSION ENERGY HOLDING COMPANY
(Registrant)

 

 

By:

/s/ Kevin M. Smith

Kevin M. Smith
Senior Vice President, Chief Financial Officer

 

 

Date:

March 27, 2003

        Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the registrant and in the capacities and on the dates indicated.

Signature
  Title
  Date

 

 

 

 

 
Principal Executive Officer:        

/s/ Theodore F. Craver, Jr.

Theodore F. Craver, Jr.

 

Chief Executive Officer

 

March 27, 2003

Controller or
Principal Accounting Officer:

 

 

 

 

/s/ Mark C. Clarke

Mark C. Clarke

 

Controller

 

March 27, 2003

Majority of Board of Directors:

 

 

 

 

/s/ John E. Bryson

John E. Bryson

 

Director, Chairman of the Board

 

March 27, 2003

/s/ Bryant C. Danner

Bryant C. Danner

 

Director

 

March 27, 2003

/s/ Theodore F. Craver, Jr.

Theodore F. Craver, Jr.

 

Director

 

March 27, 2003

366



CERTIFICATIONS

I, Theodore F. Craver, certify that:

1.
I have reviewed this annual report on Form 10-K of Mission Energy Holding Company;

2.
Based on my knowledge, this annual report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this annual report;

3.
Based on my knowledge, the financial statements, and other financial information included in this annual report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this annual report;

4.
The registrant's other certifying officers and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-14 and 15d-14) for the registrant and have:

a)
designed such disclosure controls and procedures to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this annual report is being prepared;

b)
evaluated the effectiveness of the registrant's disclosure controls and procedures as of a date within 90 days prior to the filing date of this annual report (the "Evaluation Date"); and

c)
presented in this annual report our conclusions about the effectiveness of the disclosure controls and procedures based on our evaluation as of the Evaluation Date;
5.
The registrant's other certifying officers and I have disclosed, based on our most recent evaluation, to the registrant's auditors and the audit committee of registrant's board of directors (or persons performing the equivalent functions):

a)
all significant deficiencies in the design or operation of internal controls which could adversely affect the registrant's ability to record, process, summarize and report financial data and have identified for the registrant's auditors any material weaknesses in internal controls; and

b)
any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant's internal controls; and
6.
The registrant's other certifying officers and I have indicated in this annual report whether there were significant changes in internal controls or in other factors that could significantly affect internal controls subsequent to the date of our most recent evaluation, including any corrective actions with regard to significant deficiencies and material weaknesses.

Date: March 27, 2003   By:   /s/ Theodore F. Craver
Theodore F. Craver
Director, Chief Executive Officer
and President

367



CERTIFICATIONS

I, Kevin M. Smith, certify that:

1.
I have reviewed this annual report on Form 10-K of Mission Energy Holding Company;

2.
Based on my knowledge, this annual report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this annual report;

3.
Based on my knowledge, the financial statements, and other financial information included in this annual report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this annual report;

4.
The registrant's other certifying officers and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-14 and 15d-14) for the registrant and have:

a)
designed such disclosure controls and procedures to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this annual report is being prepared;

b)
evaluated the effectiveness of the registrant's disclosure controls and procedures as of a date within 90 days prior to the filing date of this annual report (the "Evaluation Date"); and

c)
presented in this annual report our conclusions about the effectiveness of the disclosure controls and procedures based on our evaluation as of the Evaluation Date;
5.
The registrant's other certifying officers and I have disclosed, based on our most recent evaluation, to the registrant's auditors and the audit committee of registrant's board of directors (or persons performing the equivalent functions):

a)
all significant deficiencies in the design or operation of internal controls which could adversely affect the registrant's ability to record, process, summarize and report financial data and have identified for the registrant's auditors any material weaknesses in internal controls; and

b)
any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant's internal controls; and
6.
The registrant's other certifying officers and I have indicated in this annual report whether there were significant changes in internal controls or in other factors that could significantly affect internal controls subsequent to the date of our most recent evaluation, including any corrective actions with regard to significant deficiencies and material weaknesses.

Date: March 27, 2003   By:   /s/ Kevin M. Smith
Kevin M. Smith
Senior Vice President and
Chief Financial Officer

368



SCHEDULE I


MISSION ENERGY HOLDING COMPANY AND SUBSIDIARIES

CONDENSED FINANCIAL INFORMATION OF PARENT(1)

Condensed Balance Sheets

(In thousands)

 
  December 31,
 
  2002
  2001
Assets            
Cash and cash equivalents   $ 87,210   $ 942
Affiliate receivables     2,027     29,315
Other current assets     50    
   
 
Total current assets     89,287     30,257
Investments in subsidiaries     1,685,776     1,441,815
Investment in discontinued operations     7,249     134,853
Other long-term assets     184,898     334,718
   
 
Total Assets   $ 1,967,210   $ 1,941,643
   
 
Liabilities and Shareholder's Equity            
Accounts payable and accrued liabilities   $ 60,463   $ 65,476
Affiliate payables     746     7
Liabilities under price risk management and energy trading     957     1,300
   
 
Total current liabilities     62,166     66,783
Long-term obligations     1,161,764     1,157,710
Long-term liabilities under price risk management and energy trading     6,735    
Deferred taxes and other     377     296
   
 
Total Liabilities     1,231,042     1,224,789
Common Shareholder's Equity     736,168     716,854
   
 
Total Liabilities and Shareholder's Equity   $ 1,967,210   $ 1,941,643
   
 

(1)
On June 8, 2001, Edison International created MEHC as a wholly owned indirect subsidiary. MEHC's principal asset is EME's common stock. 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. In July 2001, MEHC issued $800 million of 13.50% senior secured notes due 2008. Concurrently with the consummation of the offering of MEHC's senior secured notes, MEHC borrowed $385 million under a term loan. MEHC does not have any substantive operations other than through EME and its subsidiaries and other investments.

369



MISSION ENERGY HOLDING COMPANY AND SUBSIDIARIES

CONDENSED FINANCIAL INFORMATION OF PARENT(1)

Condensed Statements of Income (Loss)

(In thousands)

 
  Years Ended December 31,
 
 
  2002
  2001
 
Operating expenses   $ (465 ) $ (137 )
   
 
 
Operating income (loss)     (465 )   (137 )
Equity in income from continuing operations of subsidiaries     82,813     98,389  
Equity in loss from discontinued operations of subsidiaries     (57,329 )   (1,219,253 )
Interest expense and other     (151,830 )   (77,177 )
   
 
 
Loss before income taxes     (126,811 )   (1,198,178 )
Benefit for income taxes     (58,570 )   (28,526 )
   
 
 
Net loss   $ (68,241 ) $ (1,169,652 )
   
 
 

(1)
On June 8, 2001, Edison International created MEHC as a wholly owned indirect subsidiary. MEHC's principal asset is EME's common stock. 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. In July 2001, MEHC issued $800 million of 13.50% senior secured notes due 2008. Concurrently with the consummation of the offering of MEHC's senior secured notes, MEHC borrowed $385 million under a term loan. MEHC does not have any substantive operations other than through EME and its subsidiaries and other investments.

370



MISSION ENERGY HOLDING COMPANY AND SUBSIDIARIES

CONDENSED FINANCIAL INFORMATION OF PARENT(1)

Condensed Statements of Cash Flows

(In thousands)

 
  Years Ended December 31,
 
 
  2002
  2001
 
Net cash provided by operating activities   $ 93,012   $ 5,278  
Net cash provided by financing activities     600     299,195  
Net cash used in investing activities     (7,344 )   (303,531 )
   
 
 
Net increase in cash and cash equivalents     86,268     942  
Cash and cash equivalents at beginning of period     942      
   
 
 
Cash and cash equivalents at end of period   $ 87,210   $ 942  
   
 
 
Other Cash Flow Data:              
  Cash dividends received from subsidiaries   $   $ 32,500  
   
 
 

(1)
On June 8, 2001, Edison International created MEHC as a wholly owned indirect subsidiary. MEHC's principal asset is EME's common stock. 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. In July 2001, MEHC issued $800 million of 13.50% senior secured notes due 2008. Concurrently with the consummation of the offering of MEHC's senior secured notes, MEHC borrowed $385 million under a term loan. MEHC does not have any substantive operations other than through EME and its subsidiaries and other investments.

371



SCHEDULE II


MISSION ENERGY HOLDING COMPANY AND SUBSIDIARIES

VALUATION AND QUALIFYING ACCOUNTS

(In thousands)

 
   
  Additions
   
   
Description

  Balance at
Beginning
of Year

  Charged to
Costs and
Expenses

  Charged to
Other
Accounts

  Deductions
  Balance at
End
of Year

Year Ended December 31, 2002                              
  Allowance for doubtful accounts(1)   $ 14,603   $ 1,554   $ 338   $ 3,382   $ 13,113
Year Ended December 31, 2001                              
  Allowance for doubtful accounts(1)   $ 1,126   $ 14,603       $ 1,126   $ 14,603
Year Ended December 31, 2000                              
  Allowance for doubtful accounts   $ 1,126               $ 1,126
  Maintenance Accruals(2)   $ 31,540           $ 31,540 (3)  

(1)
Excludes allowance for doubtful accounts of discontinued operations of $2.4 million and $1.4 million at December 31, 2002 and 2001, respectively.

(2)
Excludes maintenance accruals of discontinued operations. Effective January 1, 2000, EME recorded a $4.1 million, after tax, decrease to income (loss) from discontinued operations, as the cumulative effect of change in accounting for major maintenance costs.

(3)
Through December 31, 1999, EME accrued for major maintenance costs during the period between overhauls (referred to as "accrue in advance" accounting method). In March 2000, EME voluntarily decided to change its accounting policy to record major maintenance costs as an expense as incurred. This change in accounting policy is considered preferable based on guidance provided by the Securities and Exchange Commission. In accordance with Accounting Principles Board Opinion No. 20, "Accounting Changes," EME has recorded a $21.8 million, after tax, increase to income from continuing operations, as the cumulative effect of change in the accounting for major maintenance costs during the quarter ended March 31, 2000.

372




QuickLinks

TABLE OF CONTENTS
PART I
Coal-Fired Units
Collins Station
Peaking Units
PART II
RESULTS OF OPERATIONS
LIQUIDITY AND CAPITAL RESOURCES
Into ComEd
Into Cinergy
MISSION ENERGY HOLDING COMPANY AND SUBSIDIARIES REPORT OF INDEPENDENT ACCOUNTANTS
MISSION ENERGY HOLDING COMPANY AND SUBSIDIARIES CONSOLIDATED STATEMENTS OF INCOME (LOSS) (In thousands)
MISSION ENERGY HOLDING COMPANY AND SUBSIDIARIES CONSOLIDATED BALANCE SHEETS (In thousands)
MISSION ENERGY HOLDING COMPANY AND SUBSIDIARIES CONSOLIDATED BALANCE SHEETS (In thousands)
MISSION ENERGY HOLDING COMPANY AND SUBSIDIARIES CONSOLIDATED STATEMENTS OF SHAREHOLDER'S EQUITY (In thousands)
MISSION ENERGY HOLDING COMPANY AND SUBSIDIARIES CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (LOSS) (In thousands)
MISSION ENERGY HOLDING COMPANY AND SUBSIDIARIES CONSOLIDATED STATEMENTS OF CASH FLOWS (In thousands)
MISSION ENERGY HOLDING COMPANY AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Dollars in millions)
PART III
PART IV
REPORT OF INDEPENDENT ACCOUNTANTS
CALIFORNIA POWER GROUP COMBINED BALANCE SHEETS (Amounts in thousands)
CALIFORNIA POWER GROUP COMBINED STATEMENTS OF INCOME (Amounts in thousands)
CALIFORNIA POWER GROUP COMBINED STATEMENTS OF CASH FLOWS (Amounts in thousands)
CALIFORNIA POWER GROUP COMBINED STATEMENTS OF EQUITY (Amounts in thousands)
CALIFORNIA POWER GROUP NOTES TO COMBINED FINANCIAL STATEMENTS
REPORT OF INDEPENDENT AUDITORS
WATSON COGENERATION COMPANY BALANCE SHEETS
WATSON COGENERATION COMPANY STATEMENTS OF INCOME
WATSON COGENERATION COMPANY STATEMENTS OF PARTNERS' CAPITAL
WATSON COGENERATION COMPANY STATEMENTS OF CASH FLOWS
WATSON COGENERATION COMPANY NOTES TO FINANCIAL STATEMENTS DECEMBER 31, 2002
REPORT OF INDEPENDENT AUDITORS
CPC COGENERATION LLC (A LIMITED LIABILITY COMPANY) BALANCE SHEETS
CPC COGENERATION LLC (A LIMITED LIABILITY COMPANY) STATEMENTS OF INCOME
CPC COGENERATION LLC (A LIMITED LIABILITY COMPANY) STATEMENTS OF MEMBERS' EQUITY
CPC COGENERATION LLC (A LIMITED LIABILITY COMPANY) STATEMENTS OF CASH FLOWS
CPC COGENERATION LLC (A LIMITED LIABILITY COMPANY) NOTES TO FINANCIAL STATEMENTS DECEMBER 31, 2002
REPORT OF INDEPENDENT ACCOUNTANTS
FOUR STAR OIL & GAS COMPANY CONSOLIDATED BALANCE SHEETS DECEMBER 31, 2002 AND 2001
FOUR STAR OIL & GAS COMPANY NOTES TO CONSOLIDATED FINANCIAL STATEMENTS DECEMBER 31, 2002 AND 2001
REPORT OF INDEPENDENT ACCOUNTANTS
MIDWAY-SUNSET COGENERATION COMPANY BALANCE SHEETS DECEMBER 31, 2002 AND 2001 (UNAUDITED)
MIDWAY-SUNSET COGENERATION COMPANY STATEMENTS OF INCOME FOR THE YEARS ENDED DECEMBER 31, 2002, 2001 (UNAUDITED) AND 2000 (UNAUDITED)
MIDWAY-SUNSET COGENERATION COMPANY STATEMENTS OF CHANGES IN PARTNERS' EQUITY FOR THE YEARS ENDED DECEMBER 31, 2002, 2001 (UNAUDITED) AND 2000 (UNAUDITED)
MIDWAY-SUNSET COGENERATION COMPANY STATEMENTS OF CASH FLOWS FOR THE YEARS ENDED DECEMBER 31, 2002, 2001 (UNAUDITED) AND 2000 (UNAUDITED)
MIDWAY-SUNSET COGENERATION COMPANY NOTES TO FINANCIAL STATEMENTS DECEMBER 31, 2002, 2001 (UNAUDITED) AND 2000 (UNAUDITED)
REPORT OF INDEPENDENT ACCOUNTANTS
MARCH POINT COGENERATION COMPANY BALANCE SHEETS—DECEMBER 31, 2002 AND 2001 (unaudited)
MARCH POINT COGENERATION COMPANY STATEMENTS OF INCOME AND COMPREHENSIVE INCOME FOR THE YEARS ENDED DECEMBER 31, 2002, 2001 (unaudited) AND 2000 (unaudited)
MARCH POINT COGENERATION COMPANY STATEMENTS OF PARTNERS' EQUITY FOR THE YEARS ENDED DECEMBER 31, 2002, 2001 (unaudited), AND 2000 (unaudited)
MARCH POINT COGENERATION COMPANY STATEMENTS OF CASH FLOWS FOR THE YEARS ENDED DECEMBER 31, 2002, 2001 (unaudited) AND 2000 (unaudited)
MARCH POINT COGENERATION COMPANY NOTES TO FINANCIAL STATEMENTS DECEMBER 31, 2002
REPORT OF INDEPENDENT ACCOUNTANTS
ECOELÉCTRICA HOLDINGS, LTD. AND SUBSIDIARIES CONSOLIDATED BALANCE SHEETS DECEMBER 31, 2002 AND 2001
ECOELÉCTRICA HOLDINGS, LTD. AND SUBSIDIARIES CONSOLIDATED STATEMENTS OF OPERATIONS FOR THE YEARS ENDED DECEMBER 31, 2002, 2001 AND 2000
ECOELÉCTRICA HOLDINGS, LTD. AND SUBSIDIARIES CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (LOSS) FOR THE YEARS ENDED DECEMBER 31, 2002, 2001 AND 2000
ECOELÉCTRICA HOLDINGS, LTD. AND SUBSIDIARIES CONSOLIDATED STATEMENTS OF CHANGES IN STOCKHOLDERS' EQUITY FOR THE YEARS ENDED DECEMBER 31, 2002, 2001 AND 2000
ECOELÉCTRICA HOLDINGS, LTD. AND SUBSIDIARIES CONSOLIDATED STATEMENTS OF CASH FLOWS FOR THE YEARS ENDED DECEMBER 31, 2002, 2001 AND 2000
ECOELÉCTRICA HOLDINGS, LTD. AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS DECEMBER 31, 2002, 2001 (UNAUDITED) AND 2000 (UNAUDITED)
REPORT OF INDEPENDENT ACCOUNTANTS
GORDONSVILLE ENERGY, L.P. BALANCE SHEETS DECEMBER 31, 2002 AND 2001 (UNAUDITED)
GORDONSVILLE ENERGY, L.P. STATEMENTS OF INCOME AND COMPREHENSIVE INCOME FOR THE YEARS ENDED DECEMBER 31, 2002, 2001 (UNAUDITED) AND 2000 (UNAUDITED)
GORDONSVILLE ENERGY, L.P. STATEMENTS OF CHANGES IN PARTNERS' EQUITY FOR THE YEARS ENDED DECEMBER 31, 2002, 2001 (UNAUDITED) AND 2000 (UNAUDITED)
GORDONSVILLE ENERGY, L.P. STATEMENTS OF CASH FLOWS FOR THE YEARS ENDED DECEMBER 31, 2002, 2001 (UNAUDITED) AND 2000 (UNAUDITED)
GORDONSVILLE ENERGY, L.P. NOTES TO FINANCIAL STATEMENTS DECEMBER 31, 2002, 2001 (UNAUDITED) AND 2000 (UNAUDITED)
REPORT OF INDEPENDENT ACCOUNTANTS
BROOKLYN NAVY YARD COGENERATION PARTNERS, L.P. BALANCE SHEETS DECEMBER 31, 2002 AND 2001 (UNAUDITED)
BROOKLYN NAVY YARD COGENERATION PARTNERS, L.P. STATEMENTS OF OPERATIONS FOR THE YEARS ENDED DECEMBER 31, 2002, 2001 (UNAUDITED) AND 2000 (UNAUDITED)
BROOKLYN NAVY YARD COGENERATION PARTNERS, L.P. STATEMENTS OF CHANGES IN PARTNERS' EQUITY FOR THE YEARS ENDED DECEMBER 31, 2002, 2001 (UNAUDITED) AND 2000 (UNAUDITED)
BROOKLYN NAVY YARD COGENERATION PARTNERS, L.P. STATEMENTS OF CASH FLOWS FOR THE YEARS ENDED DECEMBER 31, 2002, 2001 (UNAUDITED) AND 2000 (UNAUDITED)
BROOKLYN NAVY YARD COGENERATION PARTNERS, L.P. NOTES TO FINANCIAL STATEMENTS DECEMBER 31, 2002, 2001 (UNAUDITED) AND 2000 (UNAUDITED)
PT PAITON ENERGY BALANCE SHEETS 31 DECEMBER 2002 AND 2001 (In thousands of U.S. Dollars, except per share amounts)
PT PAITON ENERGY BALANCE SHEETS (Continued) 31 DECEMBER 2002 AND 2001 (In thousands of U.S. Dollars, except per share amounts)
PT PAITON ENERGY STATEMENTS OF INCOME YEARS ENDED 31 DECEMBER 2002, 2001 AND 2000 (In thousands of U.S. Dollars, except per share amounts)
PT PAITON ENERGY STATEMENTS OF COMPREHENSIVE INCOME YEARS ENDED 31 DECEMBER 2002, 2001 AND 2000 (In thousands of U.S. Dollars, except per share amounts)
PT PAITON ENERGY STATEMENTS OF CHANGES IN SHAREHOLDERS' EQUITY YEARS ENDED 31 DECEMBER 2002, 2001 AND 2000 (In thousands of U.S. Dollars, except per share amounts)
PT PAITON ENERGY STATEMENTS OF CASH FLOWS YEARS ENDED 31 DECEMBER 2002, 2001 AND 2000 (In thousands of U.S. Dollars, except per share amounts)
PT PAITON ENERGY NOTES TO THE FINANCIAL STATEMENTS YEARS ENDED 31 DECEMBER 2002, 2001 AND 2000 (In thousands of U.S. Dollars, except per share amounts)
SIGNATURES
CERTIFICATIONS
CERTIFICATIONS
MISSION ENERGY HOLDING COMPANY AND SUBSIDIARIES CONDENSED FINANCIAL INFORMATION OF PARENT(1) Condensed Balance Sheets (In thousands)
MISSION ENERGY HOLDING COMPANY AND SUBSIDIARIES CONDENSED FINANCIAL INFORMATION OF PARENT(1) Condensed Statements of Income (Loss) (In thousands)
MISSION ENERGY HOLDING COMPANY AND SUBSIDIARIES CONDENSED FINANCIAL INFORMATION OF PARENT(1) Condensed Statements of Cash Flows (In thousands)
MISSION ENERGY HOLDING COMPANY AND SUBSIDIARIES VALUATION AND QUALIFYING ACCOUNTS (In thousands)