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


Form 10-Q

(Mark one)  

ý

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

For the Quarterly Period Ended September 30, 2004

or

o

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

For the transition period from                             to                              

Commission file number 333-68632


MISSION ENERGY HOLDING COMPANY
(Exact name of registrant as specified in its charter)

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

2600 Michelson Drive, Suite 1700
Irvine, California
(Address of principal executive offices)

 

92612
(Zip Code)

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

        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 whether the registrant is an accelerated filer (as defined in Rule 12b-2 of the Exchange Act). Yes o    No ý

        Number of shares outstanding of the registrant's Common Stock as of November 8, 2004: 1,000 shares (all shares held by an affiliate of the registrant).





TABLE OF CONTENTS

 
   
  Page
PART I—Financial Information
Item 1.   Financial Statements   1
Item 2.   Management's Discussion and Analysis of Financial Condition and Results of Operations   23
Item 3.   Quantitative and Qualitative Disclosures about Market Risk   68
Item 4.   Controls and Procedures   68
PART II—Other Information
Item 6.   Exhibits   69
    Signatures   70


PART I—FINANCIAL INFORMATION
ITEM 1.    FINANCIAL STATEMENTS


MISSION ENERGY HOLDING COMPANY AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF OPERATIONS
(In thousands, Unaudited)

 
  Three Months Ended
September 30,

  Nine Months Ended
September 30,

 
 
  2004
  2003
  2004
  2003
 
Operating Revenues                          
  Electric revenues   $ 507,023   $ 581,446   $ 1,210,038   $ 1,264,777  
  Net gains (losses) from price risk management and energy trading     (3,723 )   12,683     (1,182 )   39,059  
  Operation and maintenance services     5,935     8,039     19,133     21,679  
   
 
 
 
 
    Total operating revenues     509,235     602,168     1,227,989     1,325,515  
   
 
 
 
 
Operating Expenses                          
  Fuel     162,525     170,786     460,444     454,967  
  Plant operations     89,560     97,790     314,153     324,136  
  Plant operating leases     43,978     51,199     141,452     154,276  
  Operation and maintenance services     4,564     5,681     16,581     15,888  
  Depreciation and amortization     38,894     35,948     108,750     113,125  
  Loss on lease termination, asset impairment and other charges     35,200         989,456     251,240  
  Administrative and general     38,981     32,910     100,303     97,671  
   
 
 
 
 
    Total operating expenses     413,702     394,314     2,131,139     1,411,303  
   
 
 
 
 
  Operating income (loss)     95,533     207,854     (903,150 )   (85,788 )
   
 
 
 
 
Other Income (Expense)                          
  Equity in income from unconsolidated affiliates     107,084     117,590     179,634     205,999  
  Interest and other income (expense)     (1,344 )   (284 )   2,120     6,798  
  Gain on sale of assets             43,489      
  Interest expense     (120,295 )   (116,804 )   (332,342 )   (334,120 )
  Dividends on preferred securities                 (7,085 )
   
 
 
 
 
    Total other income (expense)     (14,555 )   502     (107,099 )   (128,408 )
   
 
 
 
 
  Income (loss) from continuing operations before income taxes     80,978     208,356     (1,010,249 )   (214,196 )
  Provision (benefit) for income taxes     21,715     71,993     (387,200 )   (100,207 )
   
 
 
 
 
Income (Loss) From Continuing Operations     59,263     136,363     (623,049 )   (113,989 )
  Income from operations of discontinued foreign subsidiaries, net of tax (Note 2)     499,668     39,207     578,809     65,881  
   
 
 
 
 
Income (Loss) Before Accounting Change     558,931     175,570     (44,240 )   (48,108 )
  Cumulative effect of change in accounting, net of tax (Note 13)                 (8,571 )
   
 
 
 
 
Net Income (Loss)   $ 558,931   $ 175,570   $ (44,240 ) $ (56,679 )
   
 
 
 
 

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

1



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

 
  Three Months Ended
September 30,

  Nine Months Ended
September 30,

 
 
  2004
  2003
  2004
  2003
 
Net Income (Loss)   $ 558,931   $ 175,570   $ (44,240 ) $ (56,679 )

Other comprehensive income (loss), net of tax:

 

 

 

 

 

 

 

 

 

 

 

 

 
  Foreign currency translation adjustments:                          
    Foreign currency translation adjustments, net of income tax expense (benefit) of $(105) and $260 for the three months and $1,068 and $1,564 for the nine months ended September 30, 2004 and 2003, respectively     33,165     6,107     26,272     69,525  
    Reclassification adjustments for sale of investment in a foreign subsidiary     (134,014 )       (134,014 )    
  Minimum pension liability adjustment     22     (61 )   (155 )   (347 )
  Unrealized gains (losses) on derivatives qualified as cash flow hedges:                          
    Other unrealized holding gains (losses) arising during period, net of income tax expense (benefit) of $5,455 and $22,125 for the three months and $(44,237) and $24,969 for the nine months ended September 30, 2004 and 2003, respectively     (1,896 )   52,768     (50,534 )   74,436  
    Reclassification adjustments included in net income (loss), net of income tax benefit of $19,214 and $1,963 for the three months and $50,701 and $5,447 for the nine months ended September 30, 2004 and 2003, respectively     26,841     1,145     69,817     (4,799 )
   
 
 
 
 
Other comprehensive income (loss)     (75,882 )   59,959     (88,614 )   138,815  
   
 
 
 
 
Comprehensive Income (Loss)   $ 483,049   $ 235,529   $ (132,854 ) $ 82,136  
   
 
 
 
 

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

2



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

 
  September 30,
2004

  December 31,
2003

Assets            
Current Assets            
  Cash and cash equivalents   $ 1,161,029   $ 435,397
  Accounts receivable—trade     189,889     133,627
  Accounts receivable—affiliates     200,918     33,345
  Assets under price risk management and energy trading     15,089     21,624
  Inventory     112,130     120,425
  Prepaid expenses and other     86,707     90,484
   
 
    Total current assets     1,765,762     834,902
   
 
Investments in Unconsolidated Affiliates     502,685     526,832
   
 
Property, Plant and Equipment     3,474,199     3,435,489
  Less accumulated depreciation and amortization     676,029     535,609
   
 
    Net property, plant and equipment     2,798,170     2,899,880
   
 
Other Assets            
  Deferred financing costs     82,116     67,738
  Long-term assets under price risk management and energy trading     94,442     96,340
  Restricted cash     129,602     186,850
  Rent payments in excess of levelized rent expense under plant operating leases     276,924     213,686
  Other long-term assets     17,200     2,123
   
 
    Total other assets     600,284     566,737
   
 
Assets of Discontinued Operations     4,501,518     7,430,273
   
 
Total Assets   $ 10,168,419   $ 12,258,624
   
 

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

3



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

 
  September 30,
2004

  December 31,
2003

 
Liabilities and Shareholder's Equity              
Current Liabilities              
  Accounts payable—affiliates   $ 16,021   $ 3,072  
  Accounts payable and accrued liabilities     256,055     250,461  
  Liabilities under price risk management and energy trading     65,746     35,845  
  Interest payable     125,336     101,740  
  Current maturities of long-term obligations     656,500     774,120  
   
 
 
    Total current liabilities     1,119,658     1,165,238  
   
 
 
Long-Term Obligations Net of Current Maturities     4,805,751     3,857,599  
   
 
 
Long-Term Deferred Liabilities              
  Deferred taxes and tax credits     254,962     687,808  
  Junior subordinated debentures     154,639     154,639  
  Other     335,870     317,429  
   
 
 
    Total long-term deferred liabilities     745,471     1,159,876  
   
 
 
Liabilities of Discontinued Operations     2,783,197     4,711,516  
   
 
 
Total Liabilities     9,454,077     10,894,229  
   
 
 
Minority Interest of Discontinued Operations     1,033     514,978  
   
 
 
Commitments and Contingencies (Note 8)              

Shareholder's Equity

 

 

 

 

 

 

 
  Common stock, par value $0.01 per share; 1,000 shares authorized; 1,000 shares issued and outstanding          
  Additional paid-in capital     2,220,217     2,218,353  
  Retained deficit     (1,393,451 )   (1,344,093 )
  Accumulated other comprehensive loss     (113,457 )   (24,843 )
   
 
 
Total Shareholder's Equity     713,309     849,417  
   
 
 
Total Liabilities and Shareholder's Equity   $ 10,168,419   $ 12,258,624  
   
 
 

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

4



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

 
  Nine Months Ended
September 30,

 
 
  2004
  2003
 
Cash Flows From Operating Activities              
  Loss from continuing operations, after accounting change, net   $ (623,049 ) $ (122,560 )
  Adjustments to reconcile loss to net cash provided by (used in) operating activities:              
    Equity in income from unconsolidated affiliates     (179,634 )   (205,999 )
    Distributions from unconsolidated affiliates     129,129     306,286  
    Depreciation and amortization     108,750     113,125  
    Deferred taxes and tax credits     (330,242 )   (51,911 )
    Asset impairment charges     35,200     251,240  
    Gain on sale of assets     (43,489 )    
    Cumulative effect of change in accounting, net of tax         8,571  
    Amortization of discount on long-term obligations     4,480     3,209  
  Changes in operating assets and liabilities:              
    Increase in accounts receivable—trade     (56,100 )   (42,254 )
    Decrease (increase) in accounts receivable—affiliates     (175,572 )   5,509  
    Decrease in inventory     5,595     17,775  
    Decrease in prepaid expenses and other     9,106     44,283  
    Increase in rent payments in excess of levelized rent expense     (58,545 )   (96,313 )
    Increase in accounts payable and accrued liabilities     26,034     38,130  
    Increase in interest payable     23,656     107,437  
    Decrease in net assets under risk management     10,159     19,021  
  Other operating, net     27,380     (11,156 )
   
 
 
    Net cash provided by (used in) operating activities     (1,087,142 )   384,393  
   
 
 
Cash Flows From Financing Activities              
  Borrowings on long-term debt and lease swap agreements     1,795,000      
  Payments on long-term debt agreements     (946,513 )   (47,256 )
  Financing costs     (35,739 )    
   
 
 
    Net cash provided by (used in) financing activities     812,748     (47,256 )
   
 
 
Cash Flows From Investing Activities              
  Investments in and loans to energy projects         (23,758 )
  Capital expenditures     (39,032 )   (71,191 )
  Proceeds from sale of interest in projects     857,488      
  Decrease in restricted cash     56,553     49,212  
  Investments in other assets     (345 )   21,719  
   
 
 
    Net cash provided by (used in) investing activities     874,664     (24,018 )
   
 
 
Net changes in cash of discontinued operations     43,545     (92,486 )
   
 
 
Net increase in cash and cash equivalents     643,815     220,633  
Cash and cash equivalents at beginning of period     653,770     734,450  
   
 
 
Cash and cash equivalents at end of period     1,297,585     955,083  
Cash and cash equivalents classified as part of discontinued operations     (136,556 )   (131,192 )
   
 
 
Cash and cash equivalents of continuing operations   $ 1,161,029   $ 823,891  
   
 
 

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

5



MISSION ENERGY HOLDING COMPANY AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
SEPTEMBER 30, 2004
(Dollars in millions, Unaudited)

Note 1. General

        In the opinion of management, all adjustments, including recurring accruals, have been made that are necessary to present fairly the consolidated financial position and results of operations for the periods covered by this report. The results of operations for the nine months ended September 30, 2004 are not necessarily indicative of the operating results for the full year.

        Mission Energy Holding Company's (MEHC's) significant accounting policies are described in Note 2 to its Consolidated Financial Statements as of December 31, 2003 and 2002, included in MEHC's annual report on Form 10-K for the year ended December 31, 2003. MEHC follows the same accounting policies for interim reporting purposes, with the exception of the change in accounting for variable interest entities (see Note 14). This quarterly report should be read in connection with such financial statements. Terms used but not defined in this report are defined in MEHC's annual report on Form 10-K for the year ended December 31, 2003.

        MEHC's independent auditors' audit opinion for the year ended December 31, 2003 contains an explanatory paragraph that indicates the consolidated financial statements included in its 2003 annual report on Form 10-K have been prepared on the basis that MEHC will continue as a going concern and that the uncertainty about Edison Mission Midwest Holdings' ability to repay or refinance $693 million of debt that matures in December 2004 raises substantial doubt about MEHC's ability to continue as a going concern. In April 2004, all of the outstanding debt of Edison Mission Midwest Holdings was repaid in full through new financings obtained by Midwest Generation. For further discussion, see Note 7—Refinancing.

Interim Financial Presentation

        Beginning in this third quarter report on Form 10-Q, the consolidated financial statements for all periods presented reflect the reclassification of the results of EME's international power generation portfolio as discontinued operations in accordance with Statement of Financial Accounting Standards No. 144, "Accounting for the Impairment or Disposal of Long-Lived Assets" (SFAS No. 144). Refer to Note 2—Discontinued Operations, which presents detailed information regarding the discontinued international operations. Certain other reclassifications have been made to prior year amounts to conform to current year classifications.

        Furthermore, as a result of the reclassification of the results of EME's international operations as discontinued operations, certain footnotes presented in MEHC's second quarter report on Form 10-Q for the quarter ended June 30, 2004 are no longer required to be presented. Goodwill that had been presented in the second quarter report on Form 10-Q is primarily related to the acquisitions of Contact Energy Limited (Contact Energy) and First Hydro. In addition, intangible assets subject to amortization are primarily related to customer contracts at Contact Energy. Accordingly, activity relating to goodwill and intangible assets described above is now reflected as part of discontinued operations.

        EME continues to operate predominantly in one line of business, electric power generation, with all of its continuing operations located in the United States. As a result of the sale of Contact Energy and announced plans to sell the remainder of its portfolio of international assets (which made up the

6



reportable segments in Asia Pacific and Europe), EME does not meet the criteria for segment reporting and, therefore, this footnote has been removed.

        Except as indicated, amounts reflected in the notes to the consolidated financial statements relate to continuing operations of EME.

Note 2. Discontinued Operations

Contact Energy

        On September 30, 2004, EME completed the sale of its 51.2% interest in Contact Energy to Origin Energy New Zealand Limited. Consideration for the sale was NZ$1,101.4 million (approximately US$739 million) in cash and NZ$535 million (approximately US$359 million) of debt assumed by the purchaser. The after-tax gain on the sale of Contact Energy was $141 million. On October 5, 2004, EME repaid $600 million of the $800 million secured loan at Mission Energy Holdings International, Inc. with the majority of the proceeds received from the sale of Contact Energy. The remaining proceeds will be retained for general corporate purposes.

MEC International B.V.

        On July 29, 2004, EME entered into an agreement to sell its remaining international power generation portfolio, owned by a wholly owned Dutch subsidiary, MEC International B.V., to a consortium comprised of International Power plc (70%) and Mitsui & Co., Ltd. (30%) (the BV transaction). The purchase price is $2.3 billion, subject to certain purchase price adjustments prior to closing that are expected to result in a net purchase price of approximately $2.2 billion. Closing of the BV transaction is subject to approval by International Power's shareholders and to a number of regulatory approvals and project level consents. If certain project level approvals and consents are not obtained, one or more projects may be excluded from the sale transaction and the purchase price may be adjusted accordingly. The sale is expected to close in the fourth quarter of 2004. EME's estimate of the after-tax gain on the sale of its international projects is approximately $120 million. Net proceeds from the sale will be used to repay the remaining $200 million due from the $800 million secured loan at Mission Energy Holdings International, Inc., other indebtedness and for general corporate purposes. EME will retain its ownership of the subsidiaries associated with the Lakeland project and some inactive subsidiaries.

Lakeland Project

        In 2001, EME ceased consolidating the activities of Lakeland Power Ltd. when an administrative receiver was appointed following a default by Norweb Energi Ltd, the counterparty to a long-term power sales agreement. The consolidated financial statements have been restated to conform to discontinued operations treatment for all historical periods presented. In 2003, a third party completed the purchase of the Lakeland power plant from the administrative receiver for £24 million. The proceeds from the sale and existing cash were used to fund partial repayment of the outstanding debt owed to secured creditors of the project. Lakeland Power Ltd.'s administrative receiver has filed a claim against Norweb Energi Ltd. for termination of the power purchase agreement. To the extent that Lakeland Power Ltd. receives payment under its claim, such amounts will first be used to repay amounts due to creditors. In October 2004, EME purchased the secured creditors' debt from Lakeland Power Ltd. for approximately £6 million. The purchase of the outstanding bank debt was completed to enhance EME's overall position to maximize recovery from the ultimate proceeds received from the claim against Norweb Energi. EME's subsidiary that owns the outstanding shares of Lakeland

7



Power Ltd. will be entitled to receive any residual amount of the proceeds from the claim after creditors' claims are resolved.

Ferrybridge and Fiddler's Ferry Plants

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

Summarized Financial Information for Discontinued Operations

        Summarized results of discontinued operations are as follows:

 
  Three Months Ended
September 30,

  Nine Months Ended
September 30,

 
 
  2004
  2003
  2004
  2003
 
Total operating revenues   $ 354   $ 412   $ 1,132   $ 1,087  
Income before income taxes and minority interest     60     83     222     153  
Provision (benefit) for income taxes     (317 )   27     (266 )   56  
Minority interest     (18 )   (17 )   (50 )   (31 )
Income from operations of discontinued foreign subsidiaries     359     39     438     66  
Gain on sale before income taxes     312         312      
Gain on sale after income taxes     141         141      

        During the third quarter ended September 30, 2004, EME recorded a deferred income tax benefit of $327 million in accordance with Emerging Issues Task Force Issue No. 93-17, "Recognition of Deferred Tax Assets for a Parent Company's Excess Tax Basis in the Stock of a Subsidiary That Is Accounted for as a Discontinued Operation," (EITF 93-17). Under EITF 93-17, because the tax basis of the stock of EME's Dutch subsidiary, MEC International B.V., exceeds EME's book basis, an adjustment to deferred taxes was required during the third quarter of 2004. The tax basis of the stock of MEC International B.V. exceeds the book basis primarily due to taxable income recognized in the United States on several types of foreign earnings (generally referred to as Subpart F income under U.S. income tax regulations). Even though EME recorded current taxes payable in the United States on Subpart F income, no recognition of deferred taxes was recorded under Statement of Financial Accounting Standards No. 109, " Accounting for Income Taxes," until the operations of MEC International B.V. were classified as discontinued operations.

        The assets and liabilities associated with the discontinued operations and assets held for sale are segregated on the consolidated balance sheets at September 30, 2004 and December 31, 2003. The

8



carrying amount of major asset and liability classifications for EME's international operations recorded as discontinued operations and held for sale are as follows:

 
  September 30,
2004

  December 31,
2003

Cash and cash equivalents   $ 137   $ 218
Accounts receivable-trade, net of allowance of $6 million in 2003     45     220
Other current assets     85     191
   
 
  Total current assets     267     629
   
 
Investments     1,158     1,080
   
 
Net property, plant and equipment     2,579     4,522
   
 
Goodwill     308     865
Other long-term assets     190     334
   
 
  Total other assets     498     1,199
   
 
Assets of discontinued operations   $ 4,502   $ 7,430
   
 
Accounts payable and accrued liabilities   $ 61   $ 230
Interest payable     28     59
Current maturities of long-term obligations     29     82
Other current liabilities     24     185
   
 
  Total current liabilities     142     556
   
 
Long-term obligations net of current maturities     1,707     2,640
   
 
Deferred taxes and tax credits     378     606
Deferred revenue     423     570
Other long-term liabilities     133     340
   
 
  Total long-term deferred liabilities     934     1,516
   
 
Liabilities of discontinued operations   $ 2,783   $ 4,712
   
 

Note 3. Loss on Lease Termination, Asset Impairment and Other Charges

        Loss on lease termination, asset impairment and other charges was $35 million and $989 million for the third quarter and nine months ended September 30, 2004, respectively. On April 27, 2004, EME's subsidiary, Midwest Generation, LLC (Midwest Generation) terminated the Collins Station lease through a negotiated transaction with the lease equity investor. Midwest Generation made a lease termination payment of approximately $960 million. This amount represented the $774 million of lease debt outstanding, plus accrued interest, and the amount owed to the lease equity investor for early termination of the lease. Midwest Generation received title to the Collins Station as part of the transaction. EME recorded a pre-tax loss of approximately $956 million (approximately $587 million after tax) due to termination of the lease and the planned decommissioning of the asset and disposition of excess inventory.

        Following the termination of the Collins Station lease, Midwest Generation announced plans to permanently cease operations at the Collins Station by December 31, 2004 and decommission the plant. On July 30, 2004, PJM Interconnection, LLC (PJM) accepted Midwest Generation's request to cease operations at the Collins Station. PJM found that the decommissioning of the plant would not affect the operation or reliability of the PJM markets. During the third quarter of 2004, EME reached an agreement with Exelon Generation Company LLC (Exelon Generation) to terminate the power purchase agreement effective September 30, 2004 for the two units at the Collins Station that remained

9



under contract. As a result of the termination of the power purchase agreement, EME revised the estimated useful life of the remaining plant assets to end on September 30, 2004 instead of December 31, 2004. Accordingly, EME recorded a pre-tax impairment charge of $5 million during the third quarter of 2004. In October 2004, EME finalized plans to reduce the workforce in Illinois and expects to recognize a $4 million pre-tax charge for exit costs during the fourth quarter of 2004.

        In September 2004, management completed an analysis of future competitiveness in the expanded PJM marketplace of its eight small peaking units in Illinois. Based on this analysis, management decided to decommission six of the eight small peaking units, subject to regulatory review and approval. As a result of this decision, projected future cash flows associated with the Illinois peaking units were less than the book value of the units, resulting in an impairment under Statement of Financial Accounting Standards No. 144, "Accounting for the Impairment or the Disposal of Long-Lived Assets." During the third quarter of 2004, EME recorded a pre-tax impairment charge of $29 million (approximately $18 million after tax).

        EME anticipates that the termination payment and decommissioning of the Collins Station and small peaking units will result in substantial income tax deductions.

        Asset impairment charges were $251 million for the nine months ended September 30, 2003. Asset impairment charges in 2003 consisted of $245 million related to the impairment of eight small peaking units owned by Midwest Generation in Illinois and $6 million related to the write-down of EME's investment in the Gordonsville project, which was sold in the fourth quarter of 2003.

Note 4. Inventory

        Inventory is stated at the lower of weighted average cost or market. Inventory at September 30, 2004 and December 31, 2003 consisted of the following:

 
  September 30,
2004

  December 31,
2003

Coal and fuel oil   $ 71   $ 77
Spare parts, materials and supplies     41     43
   
 
Total   $ 112   $ 120
   
 

Note 5. Accumulated Other Comprehensive Income (Loss)

        Accumulated other comprehensive income (loss), including discontinued operations, consisted of the following:

 
  Currency
Translation
Adjustments

  Unrealized Gains
(Losses) on Cash
Flow Hedges

  Minimum
Pension Liability
Adjustment

  Accumulated Other
Comprehensive
Income (Loss)

 
Balance at December 31, 2003   $ 145   $ (159 ) $ (11 ) $ (25 )
Current period change     (107 )   19         (88 )
   
 
 
 
 
Balance at September 30, 2004   $ 38   $ (140 ) $ (11 ) $ (113 )
   
 
 
 
 

        The amount of commodity hedges included in unrealized gains (losses) on cash flow hedges, net of tax, at September 30, 2004, was a loss of $63 million. The amount of interest rate hedges included in

10



unrealized gains (losses) on cash flow hedges, net of tax, at September 30, 2004, was a loss of $77 million. Unrealized losses included both continuing and discontinued operations as follows:

        Under SFAS No. 133, the portion of a cash flow hedge that does not offset the change in value of the transaction being hedged, which is commonly referred to as the ineffective portion, is immediately recognized in earnings. EME recorded net gains (losses) of approximately $(13) million and $3 million during the third quarters of 2004 and 2003, respectively, and $(9) million and $3 million during the nine months ended September 30, 2004 and 2003, respectively, representing the amount of cash flow hedges' ineffectiveness for continuing operations, reflected in net gains (losses) from price risk management and energy trading in EME's consolidated income statement.

        Interest rate swaps entered into to hedge the floating interest rate risk on the $385 million term loan qualified for treatment as cash flow hedges under SFAS No. 133 with appropriate adjustments made to other comprehensive income. At December 31, 2003, MEHC recorded a decrease of approximately $3 million, after tax, to other comprehensive income resulting from unrealized holding losses on these contracts. On July 2, 2004, the interest rate swaps were terminated. During the third quarter and nine months ended September 30, 2004, MEHC recorded an increase of approximately $1 million, after tax, to other comprehensive income resulting from the gain realized upon termination of these contracts. During the nine months ended September 30, 2004, MEHC also recorded an increase of approximately $2 million, after tax, to other comprehensive income resulting from unrealized gains on these contracts through June 30, 2004. During the quarter and nine months ended September 30, 2003, MEHC recorded an increase of approximately $1 million, after tax, to other comprehensive income resulting from unrealized gains on these contracts.

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Note 6. Employee Benefit Plans

Pension Plans

        EME previously disclosed in its financial statements for the year ended December 31, 2003, that it expected to contribute $13 million to its United States pension plans in 2004. As of September 30, 2004, $9 million in contributions have been made. EME anticipates that its original expectation will be met by year-end 2004.

        Components of pension expense for United States plans are:

 
  Three Months Ended
September 30,

  Nine Months Ended
September 30,

 
 
  2004
  2003
  2004
  2003
 
Service cost   $ 4   $ 4   $ 12   $ 12  
Interest cost     2     2     6     6  
Expected return on plan assets     (1 )   (1 )   (3 )   (3 )
Net amortization and deferral                  
   
 
 
 
 
Total expense   $ 5   $ 5   $ 15   $ 15  
   
 
 
 
 

Postretirement Benefits Other Than Pensions

        EME previously disclosed in its financial statements for the year ended December 31, 2003, that it expected to contribute $1 million to its postretirement benefits other than its pension plan in 2004. EME expects to make these contributions in the fourth quarter of 2004.

        Components of postretirement benefits expense are:

 
  Three Months Ended
September 30,

  Nine Months Ended
September 30,

 
  2004
  2003
  2004
  2003
Service cost   $   $   $   $
Interest cost     1     1     3     3
Expected return on plan assets                
Net amortization and deferral                
   
 
 
 
Total expense   $ 1   $ 1   $ 3   $ 3
   
 
 
 

Note 7. Refinancing

MEHC Financing Developments

        On April 5, 2004, the lenders under MEHC's $385 million term loan due in 2006 exercised their right to require MEHC to repurchase $100 million of principal amount at par on July 2, 2004 (referred to as the "Term Loan Put-Option"). The $100 million principal, plus interest, was paid on July 2, 2004.

EME Financing Developments

        On October 5, 2004, EME repaid $600 million of the $800 million secured loan at Mission Energy Holdings International, Inc. with the majority of the proceeds received from the sale of Contact Energy.

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        On April 27, 2004, EME replaced its $145 million corporate credit facility with a new $98 million secured corporate credit facility. This credit facility matures on April 27, 2007. Loans made under this credit facility bear interest at LIBOR plus 3.50% per annum. As security for its obligations under this credit facility, EME pledged its ownership interests in the holding companies through which it owns its interests in the Illinois Plants, the Homer City facilities, the Westside projects and the Sunrise project. EME also granted a security interest in an account into which all distributions received by it from the Big 4 projects will be deposited. EME will be free to use these distributions unless and until an event of default occurs under its corporate credit facility.

        In addition, EME completed the repayment of the remaining $28 million due under the Coal and Capex facility (guaranteed by EME) in April 2004. Accordingly, this credit agreement has been terminated and EME no longer has a contingent liability related to this credit agreement.

Midwest Generation Financing Developments

        On April 27, 2004, Midwest Generation completed a private offering of $1 billion aggregate principal amount of its 8.75% second priority senior secured notes due 2034. Holders of the notes may require Midwest Generation to repurchase, or Midwest Generation may elect to repay, the notes on May 1, 2014 and on each one-year anniversary thereafter at 100% of their principal amount, plus accrued and unpaid interest. Concurrent with the issuance of the notes, Midwest Generation borrowed $700 million under a new first priority senior secured term loan facility. The term loan has a final maturity of April 27, 2011 and bears interest at LIBOR plus 3.25% per annum. Midwest Generation has agreed to repay $1,750,000 of the term loan on each quarterly payment date. Midwest Generation also entered into a new five-year $200 million working capital facility that replaced a prior facility. The new working capital facility also provides for the issuance of letters of credit. As of September 30, 2004, Midwest Generation had no borrowings outstanding under the working capital facility and had reimbursement obligations under a letter of credit for approximately $3 million that expires in 2005. Midwest Generation used the proceeds of the notes issuance and the term loan to refinance $693 million of indebtedness (plus accrued interest and fees) owed by its direct parent, Edison Mission Midwest Holdings Co., which had been guaranteed by Midwest Generation and was due in December 2004, and to make the termination payment under the Collins Station lease in the amount of approximately $960 million.

        Midwest Generation is permitted to use the new working capital facility and cash on hand to provide credit support (either through loans or letters of credit) for forward contracts with third-party counterparties entered into by Edison Mission Marketing & Trading on its behalf for capacity and energy generated from the Illinois Plants. Utilization of this credit facility in support of such forward contracts provides additional liquidity support for implementation of EME's contracting strategy for the Illinois Plants.

        The term loan and working capital facility share a first priority lien and the senior secured notes have a second priority lien in a collateral package which consists of, among other things, substantially all the coal-fired generating plants owned by Midwest Generation and the assets relating to those plants, as well as the equity interests of Midwest Generation and its parent company and the intercompany notes entered into by EME and Midwest Generation in connection with the Powerton-Joliet sale-leaseback transaction.

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Note 8. Commitments and Contingencies

Contractual Obligations

        MEHC's long-term debt maturities for the next five twelve-month periods ending September 30 are: 2005—$657 million; 2006—$335 million; 2007—$332 million; 2008—$1.2 billion; 2009—$613 million; and thereafter—$2.3 billion. These amounts have been updated primarily to reflect financing activities completed during the first nine months of 2004. See Note 7—Refinancing.

Fuel Supply Contracts

        Midwest Generation and Homer City have entered into additional fuel purchase agreements with various third-party suppliers during the first nine months of 2004. Midwest Generation and Homer City's fuel purchase commitments under these agreements are currently estimated to be $22 million for 2004, $63 million for 2005, $97 million for 2006, $101 million for 2007, and $57 million for 2008.

Capital Improvements

        At September 30, 2004, EME's subsidiaries had firm commitments to spend approximately $11 million on capital expenditures during the remainder of 2004 and 2005. These expenditures are planned to be financed by existing subsidiary credit facilities and cash generated from operations. The construction and other capital expenditures primarily relate to planned improvements at Midwest Generation. During the third quarter of 2004, Midwest Generation decided to return Will County Units 1 and 2 to service. Operations at these units were suspended in 2002, pending recovery of market prices. As part of returning these units to service, Midwest Generation expects to spend approximately $10 million installing environmental improvements by June 30, 2005.

Commercial Commitments

Introduction

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

Standby Letters of Credit

        At September 30, 2004, standby letters of credit aggregated $48 million and were scheduled to expire as follows: remainder of 2004—$35 million; and 2005—$13 million.

Guarantees and Indemnities

Tax Indemnity Agreements—

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

14



potential obligations, EME cannot determine a maximum potential liability which would be triggered by a valid claim from the lessors. EME has not recorded a liability related to these indemnities. In connection with the termination of the lease for the Collins Station (See Note 7—Refinancing), Midwest Generation will continue to have obligations under the tax indemnity agreement with the former lease equity investor.

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

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

        Midwest Generation entered into a supplemental agreement with Commonwealth Edison and Exelon Generation on February 20, 2003 to resolve a dispute regarding interpretation of its reimbursement obligation for asbestos claims under the environmental indemnities set forth in the Asset Sale Agreement. Under this supplemental agreement, Midwest Generation agreed to reimburse Commonwealth Edison and Exelon Generation for 50% of specific existing asbestos claims and expenses less recovery of insurance costs, and agreed to a sharing arrangement for liabilities and expenses 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 upon tender by Commonwealth Edison of appropriate proof of liability for an asbestos-related settlement, judgment, verdict, or expense. At September 30, 2004, Midwest Generation had $14 million recorded as a liability related to this matter and had made $3 million in payments through September 2004.

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

        In connection with the acquisition of the Homer City facilities, EME Homer City agreed to indemnify the sellers with respect to specific environmental liabilities before and after the date of sale as specified in the Asset Purchase Agreement dated August 1, 1998. EME guaranteed the obligations of EME Homer City. Due to the nature of the obligation under this indemnity provision, it is not subject to a maximum potential liability and does not have an expiration date. Payments would be triggered under this indemnity by a claim from the sellers. EME has not recorded a liability related to this indemnity.

Indemnities Provided under Asset Sale Agreements—

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

15



triggered under these indemnities by valid claims from the sellers or purchasers, as the case may be. EME has not recorded a liability related to these indemnities.

Guarantee of Brooklyn Navy Yard Contractor Settlement Payments—

        On March 31, 2004, EME completed the sale of 100% of the stock of Mission Energy New York, Inc., which holds a fifty percent partnership interest in Brooklyn Navy Yard Cogeneration Partners, L.P. (referred to as Brooklyn Navy Yard) to BNY Power Partners LLC. Brooklyn Navy Yard owns a 286 MW gas-fired cogeneration power plant in Brooklyn, New York. In February 1997, the construction contractor asserted general monetary claims under the turnkey agreement against Brooklyn Navy Yard. A settlement agreement was executed on January 17, 2003, and all litigation has been dismissed. EME agreed to indemnify Brooklyn Navy Yard and, in connection with the sale of EME's interest in Brooklyn Navy Yard, BNY Power Partners for any payments due under this settlement agreement, which are scheduled through 2006. At September 30, 2004, EME had recorded a liability of $11 million related to this indemnity.

Capacity Indemnification Agreements—

        EME has guaranteed, jointly and severally with Texaco Inc., the obligations of March Point Cogeneration Company under its project power sales agreements to repay capacity payments to the project's power purchaser in the event that the power sales agreements terminate, March Point Cogeneration Company abandons the project, or the project fails to return to normal operations within a reasonable time after a complete or partial shutdown, during the term of the power contracts. In addition, subsidiaries of EME have guaranteed the obligations of Kern River Cogeneration Company and Sycamore Cogeneration Company under their project power sales agreements to repay capacity payments to the projects' power purchaser in the event that the projects unilaterally terminate their performance or reduce their electric power producing capability during the term of the power contracts. The obligations under the indemnification agreements as of September 30, 2004, if payment were required, would be $162 million. EME has no reason to believe that any of these projects will either cease operations or reduce its electric power producing capability during the term of its power contract.

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

        EME agreed to indemnify its lenders under its credit facilities from amounts drawn on a $35 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. 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. The agreement for the sale of EME's international assets requires the buyer to replace this letter of credit prior to or concurrently with the closing.

Subsidiary Guarantee for Performance of Unconsolidated Affiliate—

        A subsidiary of EME has guaranteed the obligations of an unconsolidated affiliate to make payments to a third party for power delivered under a fixed-price power sales agreement. This agreement runs through 2007. 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

16



payments under the guarantee, EME's subsidiary and EME are indemnified by Peabody Energy Corporation pursuant to the 2000 Purchase and Sale Agreement for Citizens Power LLC. EME's subsidiary has not recorded a liability related to this indemnity.

Contingencies

Legal Developments Affecting Sunrise Power Company

        Sunrise Power Company, in which EME's wholly owned subsidiary owns a 50% interest, sells all its output to the California Department of Water Resources. On May 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. Defendants, including Sunrise Power Company, have stipulated to respond to the complaint thirty days after it is assigned to a specific court of the San Francisco Superior Court. In December 2003, Mr. Millar filed a First Amended Class Action and Representative Action Complaint which contains allegations similar to those in the earlier complaint but also alleges a class action. One of the newly added parties has again removed the lawsuit to federal court. After various procedural motions, the case has been re-assigned to Judge Whaley in San Diego, who has heard plaintiff's motion to remand and has asked for supplemental briefing. A decision on the remand is expected before the end of 2004. EME believes that the outcome of this litigation will not have a material adverse effect on its consolidated financial position or results of operations.

Regulatory Developments Affecting Doga Project

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

        The effect of the new regulation is still undetermined, as the new license provisions have not been specified. Doga complied with the new regulation's stipulation to apply for a new generation license by June 2, 2003. The license has not been issued yet. If actions or inactions undertaken pursuant to the new regulation directly or indirectly impede, hinder, prevent or delay the operation of the Doga facility or increase Doga's cost of performing its obligations under its project documents, this may constitute a "risk event" under Doga's Implementation Contract. A risk event may permit Doga to request an increase in its tariff or, under certain circumstances, request a buyout of the project by the Ministry of Energy and Natural Resources.

        On October 3, 2002, Doga (and several other power producers in Turkey acting independently) filed a lawsuit in the Danistay, Turkey's high administrative court, against the Energy Market Regulatory Authority seeking both an injunction and permanent invalidation of certain provisions of

17



the new regulation on the grounds of the illegality and unconstitutionality of any new license requirement that does not take into account the vested rights of a company operating pursuant to previously agreed terms of the Implementation Contract.

        On May 12, 2003, the Danistay rejected Doga's request for injunctive relief (as well as those of the other power companies with similar claims). On July 10, 2003, Doga appealed the Danistay's ruling. Doga's appeal was heard by the General Council of the Administrative Chambers of Danistay on October 10, 2003 and was rejected. There are no further rights of appeal against the decision regarding the injunction. The Danistay will continue to hear the merits of Doga's lawsuit. A decision is not expected to be rendered before the second quarter of 2005.

Income Taxes

        EME is, and may in the future be, under examination by tax authorities in varying tax jurisdictions with respect to positions it 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.

Litigation

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

Environmental Matters and Regulations

        EME and its subsidiaries are subject to environmental regulation by federal, state and local authorities in the United States and foreign regulatory authorities with jurisdiction over projects located outside the United States. EME believes that it is in substantial compliance with environmental regulatory requirements and that maintaining compliance with current requirements will not materially affect its financial position or results of operation. However, possible future developments, such as the promulgation of more stringent environmental laws and regulations, future proceedings that may be initiated by environmental authorities, and settlements agreed to by other companies could affect the costs and the manner in which EME conducts its business and could cause it to make substantial additional capital expenditures. There is no assurance that EME would be able to recover these increased costs from its customers or that EME's financial position and results of operations would not be materially adversely affected.

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

Note 9. Dispositions of Investments in Energy Plants

        On January 7, 2004, EME completed the sale of 100% of its stock of Edison Mission Energy Oil & Gas, which in turn held minority interests in Four Star Oil & Gas, to Medicine Bow Energy

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Corporation. Proceeds from the sale were approximately $100 million. EME recorded a pre-tax gain on the sale of approximately $47 million during the first quarter of 2004.

        On March 31, 2004, EME completed the sale of 100% of its stock of Mission Energy New York, Inc., which in turn owned a 50% partnership interest in Brooklyn Navy Yard Cogeneration Partners L.P., to a third party for a sales price of approximately $42 million. EME recorded an impairment charge of $53 million during the fourth quarter of 2003 related to the planned disposition of this investment and a pre-tax loss of approximately $4 million during the first quarter of 2004 due to changes in the terms of the sale.

Note 10. Investments in Unconsolidated Affiliates

        The following table presents summarized financial information of the significant subsidiary investments in unconsolidated affiliates accounted for by the equity method. The significant subsidiary investments include the California Power Group, Watson Cogeneration Company, Midway-Sunset Cogeneration Company and March Point Cogeneration Company. The California Power Group (not a legal entity) consists 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. For the three and nine months ended September 30, 2003, the significant subsidiary investments also included Gordonsville Energy, L.P., Four Star Oil & Gas Company and Brooklyn Navy Yard Cogeneration Partners, L.P. EME sold its interests in Gordonsville Energy and Brooklyn Navy Yard on November 21, 2003 and March 31, 2004, respectively. In addition, EME sold 100% of its stock of Edison Mission Energy Oil & Gas, which in turn held minority interests in Four Star Oil & Gas, on January 7, 2004. Therefore, Gordonsville Energy, Brooklyn Navy Yard and Four Star Oil & Gas are not included in the balances for the three and nine months ended September 30, 2004.

 
  Three Months Ended
September 30,

  Nine Months Ended
September 30,

 
  2004
  2003
  2004
  2003
Operating revenues   $ 486   $ 590   $ 1,162   $ 1,541
Operating income     228     255     382     493
Income before accounting change     224     241     369     456
Net income     224     241     369     437

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Note 11. Supplemental Statements of Cash Flows Information

 
  Nine Months Ended
September 30,

 
 
  2004
  2003
 
Components Related to Continuing Operations              
  Cash paid              
    Interest (net of amount capitalized)   $ 282   $ 328  
    Income taxes (receipts)     20     (127 )
    Cash payments under plant operating leases     213     255  

Components Related to Discontinued Operations

 

 

 

 

 

 

 
  Cash paid              
    Interest (net of amount capitalized)     225     152  
    Income taxes (receipts)     42     35  
 
Details of assets acquired

 

 

 

 

 

 

 
    Fair value of assets acquired   $   $ 333  
    Liabilities assumed         58  
   
 
 
    Net cash paid for acquisitions   $   $ 275  
   
 
 
  Non-cash activities from deconsolidation of variable interest entities              
    Assets   $ 220   $  
    Liabilities     254      

Note 12. Stock-based Compensation

        Edison International has three stock-based employee compensation plans, which are described more fully in Note 16—Stock Compensation Plans, included in MEHC's annual report on Form 10-K for the year ended December 31, 2003. EME accounts for those plans using the intrinsic value method. Upon grant, 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 if EME had used the fair value accounting method.

 
  Three Months Ended
September 30,

  Nine Months Ended
September 30,

 
 
  2004
  2003
  2004
  2003
 
Net income (loss), as reported   $ 559   $ 176   $ (44 ) $ (57 )
Add: stock-based compensation expense included in reported net income (loss), net of related tax effects     3     1     9     2  
Deduct: Total stock-based employee compensation expense determined under fair value based method for all awards, net of related tax effects     (1 )   (1 )   (2 )   (2 )
   
 
 
 
 
Pro forma net income (loss)   $ 561   $ 176   $ (37 ) $ (57 )
   
 
 
 
 

Note 13. Cumulative Effect of Change in Accounting Principle

        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

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of a liability for an asset retirement obligation in the period in which it is incurred. When the liability is initially recorded, the entity capitalizes the cost by increasing the carrying amount of the related long-lived asset. Over time, the liability is increased to its present value each period, and the capitalized cost is depreciated over the useful life of the related asset. Upon settlement of the liability, an entity either settles the obligation for its recorded amount or incurs a gain or loss upon settlement. As of January 1, 2003, EME recorded a $9 million, after tax, decrease to net income as the cumulative effect of the adoption of SFAS No. 143.

Note 14. New Accounting Pronouncements

Emerging Issues Task Force Issue No. 02-14

        In June 2004, the Emerging Issues Task Force reached a consensus on Issue No. 02-14, "Whether an Investor Should Apply the Equity Method of Accounting to Investments Other Than Common Stock." EITF 02-14 addresses whether the equity method of accounting applies when an investor does not have an investment in voting common stock of an investee but exercises significant influence through other means. EITF 02-14 states that an investor should only apply the equity method of accounting when it has investments in either common stock or in-substance common stock of an investee, provided that the investor has the ability to exercise significant influence over the operating and financial policies of the investee. The accounting provisions of EITF 02-14 are effective for reporting periods beginning after September 15, 2004. EME does not expect the adoption of EITF 02-14 to have a material impact on its consolidated financial statements.

Statement of Financial Accounting Standards Interpretation No. 46

        In December 2003, the FASB re-issued Statement of Financial Accounting Standards Interpretation No. 46, "Consolidation of Variable Interest Entities" (FIN 46R). The primary objective of the interpretation is to provide guidance on the identification of, and financial reporting for, entities over which control is achieved through means other than voting rights; such entities are known as variable interest entities. Under this interpretation, the primary beneficiary is the variable interest holder that absorbs a majority of expected losses; if no variable interest holder meets this criteria, then it is the variable interest holder that receives a majority of the expected residual returns. The primary beneficiary is required to consolidate the variable interest entity unless specific exceptions or exclusions are met. This interpretation applies to variable interest entities created after January 31, 2003, and applies to variable interest entities in which EME holds a variable interest that it acquired before February 1, 2003. This interpretation is effective for special purpose entities as of December 31, 2003 and for all other entities as of March 31, 2004.

Variable Interest Entities

        EME completed a review of the application of FIN 46R to its subsidiaries and affiliates and concluded that it has variable interests in variable interest entities as defined in this interpretation. The

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following table summarizes the variable interest entities held by continuing operations in which EME has a significant variable interest:

Variable Interest Entity

  Location

  Investment at
September 30, 2004

  EME's Ownership
Interest at
September 30, 2004

  Description

Sunrise   Fellows, CA   $ 112   50 % Gas-fired facility
Watson   Carson, CA     100   49 % Cogeneration facility
Sycamore   Bakersfield, CA     63   50 % Cogeneration facility
Midway-Sunset   Fellows, CA     54   50 % Cogeneration facility
Kern River   Bakersfield, CA     49   50 % Cogeneration facility

        EME has determined that it is not the primary beneficiary in these entities; accordingly, EME will account for its variable interests on the equity method. EME's maximum exposure to loss in these variable interest entities is generally limited to its investment in these entities.

Deconsolidation of Variable Interest Entities

        In accordance with FIN 46R, EME determined that it was not the primary beneficiary of the Doga and Kwinana projects and, accordingly, deconsolidated these projects at March 31, 2004. The Doga and Kwinana projects are part of the sale of international operations and, accordingly, are included in discontinued operations.

FASB Staff Position FAS 106-2

        In May 2004, the FASB issued FASB Staff Position FAS 106-2, "Accounting and Disclosure Requirements Related to the Medicare Prescription Drug, Improvement and Modernization Act of 2003." The primary objective of the position is to provide accounting guidance related to the Medicare Prescription Drug, Improvement and Modernization Act of 2003. EME adopted this guidance effective July 1, 2004, which had an immaterial impact on its consolidated financial statements. According to proposed federal regulations, EME's retiree health care plans provide prescription drug benefits that are deemed to be actuarially equivalent to Medicare benefits. Accordingly, EME recognized the subsidy in the measurement of its accumulated obligation and recorded an actuarial gain.

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ITEM 2.    MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS

        This Management's Discussion and Analysis of Financial Condition and Results of Operations (MD&A) contains forward-looking statements. These statements are based on Mission Energy Holding Company's (MEHC's) knowledge of present facts, current expectations about future events and assumptions about future developments. Forward-looking statements are not guarantees of performance; they are subject to risks, uncertainties and assumptions that could cause actual future activities and results of operations to be materially different from those set forth in this discussion. Important factors that could cause actual results to differ include risks set forth in "Market Risk Exposures" below, and under "Risks Related to the Business" in the MD&A included in Item 7 of MEHC's annual report on Form 10-K for the year ended December 31, 2003.

        The MD&A of this Form 10-Q discusses material changes in the results of operations, financial condition and other developments of MEHC since December 31, 2003, and as compared to the third quarter and nine months ended September 30, 2003. This discussion presumes that the reader has read or has access to the MD&A included in Item 7 of MEHC's annual report on Form 10-K for the year ended December 31, 2003.

        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 $285 million term loan due 2006, and neither EME nor any of its subsidiaries or other investments has any obligation with respect to the notes or the term loan.

        The MD&A presents a discussion of management's focus during the third quarter of 2004, including forward-looking information, and a discussion of MEHC's financial results and analysis of its financial condition. It is presented in four major sections:

 
  Page

Management's Overview; Critical Accounting Policies and Estimates

 

23

Results of Operations

 

27

Liquidity and Capital Resources

 

43

Market Risk Exposures

 

56

MANAGEMENT'S OVERVIEW; CRITICAL ACCOUNTING POLICIES AND ESTIMATES

Management's Overview

MEHC as a Holding Company

        MEHC has a 100% ownership interest in EME, which itself operates through its subsidiaries and affiliates. EME continues to operate predominantly in one line of business, electric power generation with all of its continuing operations located in the United States. MEHC has no business activities other than through its ownership interest in EME. During 2001, MEHC issued $800 million of senior secured notes and borrowed $385 million under a term loan. MEHC's ability to honor its obligations under the senior secured notes and the term loan is entirely dependent upon the receipt of dividends from EME and receipt of tax-allocation payments from MEHC's parent, Edison Mission Group Inc.,

23



and ultimately Edison International. See Liquidity and Capital Resources—Intercompany Tax-Allocation Agreement. Dividends from EME are limited based on its earnings and cash flow, business and tax considerations, and restrictions imposed by applicable law.

        On April 5, 2004, the lenders under MEHC's $385 million term loan due in 2006 exercised their right to require MEHC to repurchase $100 million of principal amount at par on July 2, 2004 (referred to as the "Term Loan Put-Option"). The $100 million principal, plus interest, was paid on July 2, 2004.

Dividends to MEHC

        In July and October 2004, EME made dividend payments of $69 million and $5 million, respectively, to MEHC. These payments were used together with cash on hand to meet the Term Loan Put-Option payment discussed above.

        EME amended its certificate of incorporation and bylaws in May 2004 to eliminate the so-called "ring-fencing" provisions that were implemented in early 2001 during the California energy crisis, which had included restrictions on dividends.

Disposition of EME's International Operations

        As indicated in MEHC's annual report on Form 10-K for the year ended December 31, 2003, EME engaged investment bankers to market for sale its international project portfolio. During the third quarter of 2004:

        Together, these two transactions represent the sale of all of EME's interests in its international projects, except that EME will retain its ownership of the Lakeland project and some inactive international subsidiaries. The estimated net gain on sale of international projects, including recognition of a deferred tax benefit of $327 million during the third quarter of 2004, is $573 million. See "Mission

24



Energy Holding Company and Subsidiaries Notes to Consolidated Financial Statements—Note 2. Discontinued Operations."

Accounting Presentation of Discontinued and Continuing Operations

        Beginning in this third quarter report on Form 10-Q, all of EME's international operations are accounted for as discontinued operations in accordance with Statement of Financial Accounting Standards No. 144, "Accounting for the Impairment or Disposal of Long-Lived Assets," and, accordingly, all prior periods have been restated to reclassify the results of operations and assets and liabilities as discontinued operations. Continuing operations include EME's Illinois Plants and Homer City facilities, and equity investments in power projects primarily located in California. EME financial statements and the discussion set forth herein have been adjusted to this format of reporting.

Overview of EME's 2004 Financial Performance from Continuing Operations

        EME's financial performance from continuing operations during the third quarter and nine months ended September 30, 2004 and 2003 included a number of important items:

        Excluding these items, EME's income (loss) from continuing operations was $107 million and $31 million during the three and nine months ended September 30, 2004, respectively, compared to $161 million and $113 million during the comparable periods of the prior year. Key items affecting EME's operating performance included:

25


Dispositions of Investments in Other Energy Plants

        On January 7, 2004, EME completed the sale of 100% of its stock of Edison Mission Energy Oil & Gas, which in turn held minority interests in Four Star Oil & Gas, to Medicine Bow Energy Corporation. Proceeds from the sale were approximately $100 million. EME recorded a pre-tax gain on the sale of approximately $47 million during the first quarter of 2004.

        On March 31, 2004, EME completed the sale of 100% of its stock of Mission Energy New York, Inc., which in turn owned a 50% partnership interest in Brooklyn Navy Yard Cogeneration Partners L.P., to a third party for a sales price of approximately $42 million. EME recorded an impairment charge of $53 million during the fourth quarter of 2003 related to the planned disposition of this investment and a pre-tax loss of approximately $4 million during the first quarter of 2004 due to changes in the terms of the sale.

Expansion of PJM in Illinois

        The Illinois Plants are located within the service territory of Exelon Generation's affiliate, Commonwealth Edison, which on April 27, 2004 was granted approval by the Federal Energy Regulatory Commission (the FERC) to join PJM effective May 1, 2004. EME had protested the integration of Commonwealth Edison into PJM before American Electric Power (AEP), because Commonwealth Edison's service territory, independent of AEP, was only partially integrated into PJM via a limited transmission pathway of 500 MW capability. This lack of interconnection capability limited Midwest Generation's access to the broader PJM market. These concerns became moot on October 1, 2004, when AEP was integrated into PJM. As of October 1, 2004, Midwest Generation had direct access to a fully interconnected market that covers twelve states and the District of Columbia, and serves a peak load of over 107,000 MW over 49,300 miles of transmission lines. For further discussion, see "Market Risk Exposures—Regulatory Matters."

Critical Accounting Policies and Estimates

        For a discussion of EME's critical accounting policies, refer to "Critical Accounting Policies and Estimates" on page 46 of MEHC's annual report on Form 10-K for the year ended December 31, 2003.

26


RESULTS OF OPERATIONS

Introduction

        This section discusses operating results for the third quarters and nine months of 2004 and 2003. Beginning in this third quarter report on Form 10-Q, all of EME's international operations are accounted for as discontinued operations. Discontinued operations are discussed separately below until completion of the sale of these operations as an aid to understanding the performance of these projects during the third quarter and nine months ended September 30, 2004. Continuing operations include EME's Illinois Plants and Homer City facilities, equity investments in power projects primarily located in California, corporate interest expense and general and administrative expenses. This section also discusses the effect of new accounting pronouncements on EME's consolidated financial statements. It is organized under the following headings:

 
  Page

Net Income (Loss) Summary

 

27

Results of Continuing Operations

 

28

Results of Discontinued Operations

 

35

New Accounting Pronouncements

 

41

Net Income (Loss) Summary

        Net income (loss) is comprised of the following components:

 
  Three Months Ended
September 30,

  Nine Months Ended
September 30,

 
 
  2004
  2003
  2004
  2003
 
 
  (in millions)

 
Mission Energy Holding Company (parent company):                          

Loss from continuing operations

 

$

(26

)

$

(24

)

$

(75

)

$

(74

)

Edison Mission Energy and its Consolidated Subsidiaries:

 

 

 

 

 

 

 

 

 

 

 

 

 

Income (loss) from continuing operations

 

 

85

 

 

161

 

 

(548

)

 

(40

)
Income from discontinued operations     500     39     579     66  
Cumulative changes in accounting                 (9 )
   
 
 
 
 
Net Income (Loss)   $ 559   $ 176   $ (44 ) $ (57 )
   
 
 
 
 

        MEHC's loss from continuing operations for the third quarter and nine months ended September 30, 2004 was $26 million and $75 million, respectively, compared to $24 million and $74 million for the third quarter and nine months of 2003. There was no significant change in loss from continuing operations in 2004 from 2003.

        EME's 2003 loss from a change in accounting principle resulted from the adoption of a new accounting standard for asset retirement obligations. See "Results of Continuing Operations—Cumulative Effect of Change in Accounting Principle" for further discussion of this change in accounting.

27



        EME's income (loss) from continuing operations for the third quarters and nine months ended September 30, 2004 and 2003 is comprised of:

 
  Three Months Ended
September 30,

  Nine Months Ended
September 30,

 
 
  2004
  2003
  2004
  2003
 
 
  (in millions)

 
Income (Loss) from Continuing Operations   $ 85   $ 161   $ (548 ) $ (40 )
Discrete Items (after tax)                          
  Loss on lease termination, asset impairment and other charges (see "—Results of Continuing Operations—Earnings from Consolidated Operations—Illinois Plants")     (22 )       (608 )   (153 )
  Gain on sale of assets (see "—Results of Continuing Operations—Earnings from Unconsolidated Affiliates—Four Star Oil & Gas")             29      
   
 
 
 
 
Income from Continuing Operations (excluding discrete items)   $ 107   $ 161   $ 31   $ 113  
   
 
 
 
 

        The decrease in the third quarter income from continuing operations, excluding discrete items, was primarily attributable to lower capacity revenues at EME's Illinois Plants and lower earnings from EME's Homer City facilities, due to lower generation and higher fuel costs related to the cost of emission allowances. In addition, the decrease in earnings was due to the absence of earnings from Four Star Oil & Gas, which was sold on January 7, 2004. The year-to-date decrease in income from continuing operations, excluding discrete items, was primarily attributable to lower earnings from EME's Homer City facilities described above and an absence of earnings from Four Star Oil & Gas.

Results of Continuing Operations

Overview

        EME operates in one line of business, electric power generation. Operating revenues are primarily related to the sale of power generated from the Illinois Plants and Homer City facilities. 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 in 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 words "earnings" or "losses" in this section to describe EME's income or loss from continuing operations before income taxes and minority interest.

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        The following section provides a summary of the operating results for the third quarter and nine months ended September 30, 2004 and 2003 together with discussions of the contributions by specific projects and of other significant factors affecting these results.

 
  Three Months Ended
September 30,

  Nine Months Ended
September 30,

 
 
  2004
  2003
  2004
  2003
 
 
  (in millions)

 
Income (Loss) before Taxes (Earnings/Losses)                          
  Consolidated operations                          
  Illinois Plants   $ 98   $ 181   $ (850 ) $ (99 )
  Homer City     26     60     61     110  
  Other     4     11     6     34  
  Unconsolidated affiliates                          
  Big 4 projects     72     65     122     115  
  Four Star Oil & Gas         13         39  
  Sunrise     28     29     29     36  
  March Point     (1 )   2     6     5  
  Other     5     4     9     (9 )
   
 
 
 
 
      232     365     (617 )   231  
  MEHC and EME corporate interest expense     (112 )   (117 )   (333 )   (335 )
  EME corporate and regional administrative and general     (39 )   (33 )   (100 )   (96 )
  Gain on sale of assets             43      
  EME corporate depreciation and other, net         (7 )   (3 )   (14 )
   
 
 
 
 
  Income (Loss) from Continuing Operations Before Income Taxes   $ 81   $ 208   $ (1,010 ) $ (214 )
   
 
 
 
 

29


Earnings from Consolidated Operations

Illinois Plants

 
  Three Months Ended
September 30,

  Nine Months Ended
September 30,

 
 
  2004
  2003
  2004
  2003
 
Operating Revenues                          
  Energy revenues   $ 201   $ 209   $ 558   $ 516  
  Capacity revenues     170     222     267     348  
  Net losses from price risk management     (3 )   (6 )       (2 )
   
 
 
 
 
  Total operating revenues     368     425     825     862  
   
 
 
 
 
Operating Expenses                          
  Fuel     102     120     302     315  
  Plant operations     75     76     244     248  
  Plant operating leases     19     26     66     79  
  Depreciation and amortization     33     27     90     89  
  Loss on lease termination, asset impairment and other charges     35         989     245  
  Administrative and general     2     1         7  
   
 
 
 
 
  Total operating expenses     266     250     1,691     983  
   
 
 
 
 
Operating Income (Loss)     102     175     (866 )   (121 )
   
 
 
 
 
Other Income (Expense)                          
  Interest income from note receivable from EME     28     28     85     85  
  Interest expense     (32 )   (22 )   (69 )   (63 )
   
 
 
 
 
  Total other income (expense)     (4 )   6     16     22  
   
 
 
 
 
Income (Loss) Before Taxes   $ 98   $ 181   $ (850 ) $ (99 )
   
 
 
 
 
Statistics—Coal-Fired Generation                          
 
Generation (in GWhr):

 

 

 

 

 

 

 

 

 

 

 

 

 
    Power purchase agreement     3,892     3,806     9,761     10,481  
    Merchant     4,408     4,195     12,417     10,073  
   
 
 
 
 
    Total coal-fired generation     8,300     8,001     22,178     20,554  
   
 
 
 
 
  Equivalent Availability(1)     91.9%     94.1%     81.8%     82.3%  
 
Forced outage rate(2)

 

 

5.0%

 

 

4.4%

 

 

6.5%

 

 

6.6%

 
 
Average realized energy price/MWhr:

 

 

 

 

 

 

 

 

 

 

 

 

 
    Power purchase agreement   $ 16.56   $ 18.06   $ 17.18   $ 18.22  
    Merchant   $ 32.96   $ 28.92   $ 30.98   $ 26.79  
   
 
 
 
 
    Total coal-fired generation   $ 25.27   $ 23.76   $ 24.90   $ 22.42  
   
 
 
 
 

(1)
The availability factor is determined by the number of megawatt-hours the coal plants are available to generate electricity divided by the product of the capacity of the coal plants (in megawatts) and the number of hours in the period. The coal plants are not available during periods of planned and unplanned maintenance.

(2)
Midwest Generation generally refers to unplanned maintenance as a forced outage.

30


        Losses from the Illinois Plants increased $751 million for the nine months ended September 30, 2004, compared to the corresponding period of 2003. Discrete items affecting the losses of the Illinois Plants include:

        Earnings from the Illinois Plants, excluding the above discrete items, were $133 million and $139 million during the three and nine months ended September 30, 2004, respectively, compared to $181 million and $146 million for the comparable periods in the prior year. The decrease in the third quarter earnings was $48 million due to the following factors:

        Partially offset by:

        The nine months earnings for 2004 from the Illinois Plants decreased $7 million, compared to the corresponding period of 2003 primarily due to a decrease in capacity revenues under the power purchase agreements. This decrease was mostly offset by higher energy revenues, lower fuel costs, and lower plant operating lease costs, described above. The higher energy revenues were a result of increased merchant generation at the coal plants released from their power purchase agreement with Exelon Generation and higher merchant energy prices.

        Losses from price risk management activities decreased $3 million and $2 million for the third quarter and nine months ended September 30, 2004, respectively, compared to the corresponding periods of 2003. The gains (losses) represent the ineffective portion of forward contracts which are derivatives that qualify as cash flow hedges under SFAS No. 133, gains (losses) related to power contracts that did not qualify for hedge accounting under SFAS No. 133, and realized gains on swaps and financial transmission rights that did not qualify for hedge accounting under SFAS No. 133. Midwest Generation recorded net losses of approximately $5 million for both the third quarters of 2004 and 2003 and $0.2 million and $1 million during the nine months ended September 30, 2004 and 2003, respectively, representing the amount of cash flow hedges ineffectiveness. The ineffective portion of the cash flow hedges was partially attributable to differences in energy prices between "Into ComEd" and delivery points outside "Into ComEd" prior to May 1, 2004 and differences in energy prices between the aggregate Midwest Generation unit price and other delivery points, effective May 1, 2004. In addition, Midwest Generation recognized ineffective gains (losses) on the ineffective portion of forward contracts that expired during the respective periods.

31



        The earnings (losses) of the Illinois Plants included interest income of $28 million for the third quarters of both 2004 and 2003 and $85 million for the nine months ended of both September 30, 2004 and 2003 related to loans to EME. In August 2000, Midwest Generation, which owns or leases the Illinois Plants, entered into a sale-leaseback transaction of the Powerton-Joliet facilities. The proceeds from the sale of these facilities were loaned to EME, which also provided a guarantee of the related lease obligations of Midwest Generation. The Powerton-Joliet sale-leaseback is recorded as an operating lease for accounting purposes.

Homer City

 
  Three Months Ended
September 30,

  Nine Months Ended
September 30,

 
 
  2004
  2003
  2004
  2003
 
Operating Revenues                          
  Energy revenues   $ 130   $ 138   $ 363   $ 379  
  Capacity revenues     6     11     22     22  
  Net gains (losses) from price risk management     (6 )   7     (13 )   4  
   
 
 
 
 
  Total operating revenues     130     156     372     405  
   
 
 
 
 
Operating Expenses                          
  Fuel     60     51     155     139  
  Plant operations     14     15     69     66  
  Plant operating leases     25     25     76     76  
  Depreciation and amortization     4     4     12     12  
  Administrative and general     1         1      
   
 
 
 
 
  Total operating expenses     104     95     313     293  
   
 
 
 
 
Operating Income     26     61     59     112  
   
 
 
 
 

Other Income (Expense)

 

 

 

 

 

 

 

 

 

 

 

 

 
  Interest expense     (1 )   (1 )   (1 )   (2 )
  Other income (expense)     1         3      
   
 
 
 
 
  Total other income (expense)         (1 )   2     (2 )
   
 
 
 
 
Income Before Taxes   $ 26   $ 60   $ 61   $ 110  
   
 
 
 
 

Statistics

 

 

 

 

 

 

 

 

 

 

 

 

 
 
Generation (in GWhr)

 

 

3,562

 

 

4,042

 

 

9,937

 

 

10,690

 
  Availability(1)     91.7%     97.6%     82.9%     87.8%  
  Forced outage rate(2)     1.4%     2.1%     5.6%     4.3%  
  Average realized energy price/MWhr   $ 35.99   $ 34.57   $ 36.36   $ 35.46  

(1)
The availability factor is determined by the number of megawatt-hours the coal plants are available to generate electricity divided by the product of the capacity of the coal plants (in megawatts) and the number of hours in the period. The coal plants are not available during periods of planned and unplanned maintenance.

(2)
Homer City generally refers to unplanned maintenance as a forced outage.

        Earnings from Homer City decreased $34 million and $49 million for the third quarter and nine months ended September 30, 2004, respectively, compared to the corresponding periods of 2003. During the third quarter of 2004, coal deliveries under contracts with four fuel suppliers to Homer City were temporarily interrupted. As a result of these interruptions, Homer City reduced generation during

32


off-peak periods when power prices were lower and purchased coal from alternative suppliers at spot prices which were substantially higher than the contract prices from these four fuel suppliers. These factors contributed to lower generation in the third quarter of 2004. Management is currently seeking to secure the delivery of the coal shortfall under existing contracts with these fuel suppliers and is reviewing these contracts to determine what further course of action, if any, should be undertaken. In addition, the increase in sulfur emission costs during the third quarter of 2004 is reflected in higher fuel costs. The 2004 nine-month decrease in earnings was due to lower generation during the third quarter of 2004 described above, from an unplanned outage at Unit 1 in February 2004, higher maintenance costs from the outage during the first quarter of 2004 and higher sulfur emission costs. Losses from price risk management activities in 2004 also contributed to the decrease in earnings for the third quarter and year-to-date period in 2004.

        Losses from price risk management activities increased $13 million and $17 million for the third quarter and nine months ended September 30, 2004, respectively, compared to the corresponding periods of 2003. The losses represent the ineffective portion of forward and futures contracts which are derivatives that qualify as cash flow hedges under SFAS No. 133 and gains (losses) related to futures contracts that did not qualify for hedge accounting under SFAS No. 133. Homer City recorded net gains (losses) of approximately $(9) million and $7 million during the third quarters of 2004 and 2003, respectively, and $(9) million and $3 million during the nine months ended September 30, 2004 and 2003, respectively, representing the amount of the ineffective portion of the cash flow hedges. The ineffective gains (losses) during the third quarter and nine months ended September 30, 2004 and 2003 from Homer City were partially attributable to changes in the difference between energy prices at PJM West Hub (the delivery point under forward contracts) and the energy prices at the delivery point where power generated by the Homer City facilities is delivered into the transmission system (referred to as the Homer City busbar). In addition, Homer City recognized ineffective gains (losses) related to forward contracts that expired during the respective periods. See "Market Risk Exposures—Commodity Price Risk—Americas" for more information regarding forward market prices.

Earnings from Unconsolidated Affiliates

Big 4 Projects

        Earnings from the Big 4 projects increased $7 million for both the third quarter and nine months ended September 30, 2004, compared to the corresponding periods of 2003. The change in earnings was largely due to higher energy prices in 2004. For the nine months ended September 30, 2004, the impact of the higher energy prices in 2004 was partially offset due to planned outages at the Sycamore Cogeneration plant and the Watson Cogeneration plant in March 2004.

        The earnings from the Big 4 projects included interest expense from Edison Mission Energy Funding of $3 million and $4 million for the third quarters of 2004 and 2003, respectively. For the nine months ended September 30, 2004 and 2003, earnings included interest expense from Edison Mission Energy Funding of $10 million and $12 million, respectively.

Four Star Oil & Gas

        EME's share of earnings from Four Star Oil & Gas Company was $13 million and $39 million for the third quarter and nine months ended September 30, 2003, respectively, with no earnings recorded in 2004 from its ownership interest due to the sale of the project. The 2004 earnings represent the gain on sale of 100% of EME's stock of Edison Mission Energy Oil & Gas, which in turn held minority interests in Four Star Oil & Gas, on January 7, 2004. Proceeds from the sale were approximately

33



$100 million. EME recorded a pre-tax gain on the sale of approximately $47 million during the first quarter of 2004.

Sunrise

        Earnings from the Sunrise project decreased $1 million and $7 million for the third quarter and nine months ended September 30, 2004, respectively, compared to the corresponding periods of 2003. The 2004 decreases primarily resulted from higher interest expense due to the completion of the Sunrise project financing in September 2003.

March Point

        Earnings from March Point decreased $3 million and increased $1 million for the third quarter and nine months ended September 30, 2004, respectively, compared to the corresponding periods of 2003. The third quarter decrease 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. The year-to-date increase was attributable to higher operating revenues in 2004 because there was no planned outage in 2004, as there was during the corresponding period in June 2003.

Other

        Gains from energy trading activities were $6 million and $12 million for the third quarters of 2004 and 2003, respectively, and $11 million and $37 million for the nine months ended September 30, 2004 and 2003, respectively. The net gains from energy trading activities were the result of proprietary trading in the power markets in which EME has power plants. Gains from proprietary energy trading activities during the first nine months of 2004 were lower than the corresponding period in 2003 due to less favorable market conditions (prices and volatility).

        The 2004 increase was also due in part to the absence of the $6 million loss related to the write-down of EME's investment in the Gordonsville project which occurred in the second quarter of 2003.

Seasonal Disclosure

        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.

34


MEHC and EME Corporate Interest Expense

 
  Three Months Ended
September 30,

  Nine Months Ended
September 30,

 
  2004
  2003
  2004
  2003
 
  (in thousands)

MEHC (excluding EME) interest expense to third parties   $ 42,102   $ 40,178   $ 122,634   $ 119,802
EME's interest expense to third parties     41,516     48,865     125,525     130,344
EME's interest expense to Midwest Generation     28,298     28,333     84,931     85,022
   
 
 
 
Total interest expense   $ 111,916   $ 117,376   $ 333,090   $ 335,168
   
 
 
 

Administrative and General Expenses

        Administrative and general expenses increased $6 million and $3 million for the third quarter and nine months ended September 30, 2004, compared to the corresponding periods of 2003. The increases were primarily due to increased use of third party consultants and higher performance-based compensation.

Income Taxes

        MEHC's effective income tax benefit rate from continuing operations during the nine months ended September 30, 2004 was 38% compared to 47% during the first nine months of 2003. The higher effective income tax benefit rate in 2003 is due to higher state tax benefits, net of federal income taxes recognized under the tax-allocation agreement with Edison International, and a lower tax rate on earnings for EME's investment in Four Star Oil & Gas during 2003 as a result of a dividends received deduction. During the first nine months of 2004 and 2003, EME recorded additional state tax benefits, net of federal income taxes, of $5 million and $15 million, respectively, as a result of participation in the tax-allocation agreement with Edison International.

Cumulative Effect of Change in Accounting Principle

Statement of Financial Accounting Standards No. 143

        Effective January 1, 2003, EME adopted Statement of Financial Accounting Standards No. 143, "Accounting for Asset Retirement Obligations." SFAS No. 143 requires entities to record the fair value of a liability for an asset retirement obligation in the period in which it is incurred. When the liability is initially recorded, the entity capitalizes the cost by increasing the carrying amount of the related long-lived asset. Over time, the liability is increased to its present value each period, and the capitalized cost is depreciated over the useful life of the related asset. Upon settlement of the liability, an entity either settles the obligation for its recorded amount or incurs a gain or loss upon settlement. As of January 1, 2003, EME recorded a $9 million, after tax, decrease to net income as the cumulative effect of the adoption of SFAS No. 143.

Results of Discontinued Operations

        As discussed under Management's Overview, EME:

35


        During the third quarter ended September 30, 2004, EME recorded a deferred income tax benefit of $327 million in accordance with Emerging Issues Task Force Issue No. 93-17, "Recognition of Deferred Tax Assets for a Parent Company's Excess Tax Basis in the Stock of a Subsidiary That Is Accounted for as a Discontinued Operation," (EITF 93-17). Under EITF 93-17, because the tax basis of the stock of EME's Dutch subsidiary, MEC International B.V., exceeds EME's book basis, an adjustment to deferred taxes was required during the third quarter of 2004. The tax basis of the stock of MEC International B.V. exceeds the book basis primarily due to taxable income recognized in the United States on several types of foreign earnings (generally referred to as Subpart F income under U.S. income tax regulations). Even though EME recorded current taxes payable in the United States on Subpart F income, no recognition of deferred taxes was recorded under Statement of Financial Accounting Standards No. 109, "Accounting for Income Taxes," until the operations of MEC International B.V. were classified as discontinued operations.

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        As the sale of the remaining international power projects is expected to be completed during the fourth quarter of 2004, the following interim information is provided as an aid in understanding the performance of the international projects consistent with prior quarterly reports.

 
  Three Months Ended September 30,
  Nine Months Ended
September 30,

 
 
  2004(1)
  2003
  2004(1)
  2003
 
 
  (in millions)

 
Operating Revenues from Consolidated Subsidiaries                          
  Contact Energy   $ 239   $ 228   $ 639   $ 566  
  First Hydro     75     87     268     247  
  Loy Yang B     51     47     156     127  
  Doga(3)         31     29     98  
  Other     11     20     56     67  
   
 
 
 
 
    $ 376   $ 413   $ 1,148   $ 1,105  
   
 
 
 
 
Income (Loss) before Taxes and Minority Interest (Earnings/Losses)                          
  Consolidated operations                          
  Contact Energy(2)   $ 34   $ 42   $ 115   $ 71  
  First Hydro     1     (8 )   10     (19 )
  Loy Yang B     16     14     46     29  
  Doga(3)         8     6     14  
  Other     4     2     22     15  
  Unconsolidated affiliates                          
  Paiton     16     18     49     42  
  ISAB     13     13     32     23  
  EcoEléctrica     6     2     18     1  
  Italian Wind         (1 )   6      
  Doga(3)     2         3      
  Other     2     2     9     3  
   
 
 
 
 
    $ 94   $ 92   $ 316   $ 179  
   
 
 
 
 

(1)
The earnings for the third quarter and nine months of 2004 are not presented in accordance with generally accepted accounting principles in the United States. Under SFAS No. 144, depreciation expense of assets held for sale is discontinued which EME has followed in preparation of its consolidated statement of income. However, in order to present the above results of operations on a comparable basis to the third quarter and nine months of 2003, depreciation expense has been included in each of the above projects. The following table reconciles the total earnings of projects classified as discontinued operations above with the income before taxes and minority interest under generally accepted accounting principles:

 
  Three Months Ended September 30,
  Nine Months Ended September 30,
 
  2004
  2003
  2004
  2003
 
  (in millions)

Income before taxes and minority interest (project basis)   $ 94   $ 92   $ 316   $ 179
Depreciation expense     20         20    
   
 
 
 
Income before taxes and minority interest under generally accepted accounting principles   $ 114   $ 92   $ 336   $ 179
   
 
 
 
(2)
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 Note 2, Discontinued Operations. 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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(3)
Income before taxes of Doga through March 31, 2004 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 Note 2, Discontinued Operations, through March 31, 2004. Effective March 31, 2004, the Doga project was deconsolidated due to the adoption of FIN 46. Beginning April 1, 2004, EME recorded its interest in the Doga project on the equity method of accounting.

Contact Energy

        Operating revenues increased $11 million and $73 million for the third quarter and nine months ended September 30, 2004, respectively, compared to the corresponding periods of 2003. The 2004 increases were primarily due to higher electricity retail and generation revenues arising from the Taranaki combined-cycle plant purchased in March 2003 and increased number of retail customers in the year 2003, as well as ongoing strength in retail volumes, tariff adjustments and management of transmission constraints. In addition, there was a 12% and 15% increase in the average exchange rate of the New Zealand dollar compared to the U.S. dollar during the third quarter and nine months ended September 30, 2004, respectively, compared to the corresponding periods of 2003.

        Earnings from Contact Energy, included in the consolidated statements of income of EME as described above, decreased $8 million and increased $44 million for the third quarter and nine months ended September 30, 2004, respectively, compared to the corresponding periods of 2003. The 2004 year-to-date increase was primarily due to increased margins due to the factors described above related to revenues. In addition, gains (losses) from price risk management activities were $(6) million and $1 million for the third quarter and nine months ended September 30, 2004, respectively, compared to $7 million and $2 million for the third quarter and nine months ended September 30, 2003, respectively. The gains (losses) from price risk management activities primarily related to a change in market value of electricity and financial contracts that were not designated as cash flow hedges for hedge accounting under SFAS No. 133. Also included in the gains (losses) from price risk management activities during the third quarter and nine months ended September 30, 2004 was approximately $(1) million and $1 million, respectively, representing the ineffective portion of cross currency interest rate swaps. These are derivatives that qualify as fair value hedges under SFAS No. 133.

First Hydro

        Operating revenues decreased $12 million and increased $21 million for the third quarter and nine months ended September 30, 2004, respectively, compared to the corresponding periods of 2003. The third quarter decrease was due to lower volumes of power sales in the third quarter of 2004. Partially offsetting this decrease was a 13% increase in the average exchange rate of the British pound compared to the U.S. dollar during the third quarter of 2004, compared to the same prior year quarter. The 2004 year-to-date increase resulted primarily from higher volumes of power sales and higher ancillary services revenues in 2004. In addition, there were higher electric revenues from the First Hydro plant due to a 13% increase in the average exchange rate of the British pound compared to the U.S. dollar during the nine months ended September 30, 2004, compared to the same prior year period. The First Hydro plant is expected to provide for higher electric revenues during its winter months.

        Earnings from First Hydro increased $9 million and $29 million for the third quarter and nine months ended September 30, 2004, respectively, compared to the corresponding periods of 2003. The 2004 increase in earnings is primarily due to an $8 million and $5 million gain from price risk management activities for the third quarter and nine months ended September 30, 2004, respectively, compared to an $8 million and $20 million loss from price risk management activities for the third quarter and nine months ended September 30, 2003, respectively. First Hydro's gains (losses) from

38



price risk management relate to the change in market value of commodity contracts that are recorded at fair value under SFAS No. 133, with changes in fair value recorded through the income statement.

Loy Yang B

        Operating revenues increased $4 million and $29 million for the third quarter and nine months ended September 30, 2004, respectively, compared to the corresponding periods of 2003. The 2004 increases in operating revenues were primarily due to higher generation in 2004 compared to 2003 as a result of a planned outage in March 2003 and an 8% and 16% increase in the average exchange rate of the Australian dollar compared to the U.S. dollar during the third quarter and nine months ended September 30, 2004, respectively, compared to the corresponding periods of 2003.

        Earnings from Loy Yang B increased $2 million and $17 million for the third quarter and nine months ended September 30, 2004, respectively, compared to the corresponding periods of 2003. The 2004 increases in earnings were due to higher electric revenues discussed above.

Paiton Energy

        Earnings from Paiton Energy decreased $2 million and increased $7 million for the third quarter and nine months ended September 30, 2004, respectively, compared to the corresponding periods of 2003. The third quarter decrease was primarily due to decreased revenues mostly due to lower availability resulting from a planned outage during the third quarter of 2004. The 2004 year-to-date increase in earnings was primarily attributable to a decrease in Indonesian income taxes resulting from interest expense from partner subordinated loans and lower costs incurred in 2004 related to debt restructuring activities, partially offset by lower revenues described above.

Doga

        Revenues from Doga were $31 million and $98 million for the third quarter and nine months ended September 30, 2003, respectively. Revenues from Doga were $29 million for the nine months ended September 30, 2004, representing revenues from the first quarter of 2004. There were no revenues recorded on a consolidated basis during the three months ended September 30, 2004 due to the deconsolidation of the Doga project on March 31, 2004. Beginning April 1, 2004, EME recorded its interest in the Doga project on the equity method of accounting.

        Earnings from Doga (consolidated) were $8 million and $14 million for the third quarter and nine months ended September 30, 2003, respectively. Earnings from Doga (consolidated) were $6 million for the nine months ended September 30, 2004, representing earnings for the first quarter of 2004. Earnings from Doga (unconsolidated) were $2 million and $3 million for the third quarter and nine months ended September 30, 2004, respectively. The earnings of Doga (unconsolidated) are reported after local country taxes and are, therefore, not comparable to the earnings of Doga (consolidated) which are before local country taxes. The net income of the Doga project before minority interest improved during the nine months ended September 30, 2004, compared to the same period of 2003 due to lower income taxes.

ISAB

        Earnings from ISAB increased $9 million for the nine months ended September 30, 2004, compared to the corresponding period of 2003. There was no change in earnings for the third quarter of 2004 compared to the third quarter of 2003. The 2004 increase was primarily attributable to higher

39



revenues, from a tariff increase resulting from higher energy prices, and higher generation in 2004 as compared to 2003, resulting from a major planned overhaul of the plant in April 2003.

EcoEléctrica

        Earnings from the EcoEléctrica project increased $4 million and $17 million for the third quarter and nine months ended September 30, 2004, respectively, compared to the corresponding periods of 2003. The 2004 increases were primarily due to higher operating revenues in 2004 over 2003 resulting from plant outages from November 2002 through February 2003.

Italian Wind

        Earnings from the Italian Wind project increased $1 million and $6 million for the third quarter and nine months ended September 30, 2004, respectively, compared to the corresponding periods of 2003. The 2004 increases were primarily due to higher revenues from a tariff increase resulting from higher energy prices and higher generation caused by more wind in the first nine months of 2004, compared to the first nine months of 2003.

Other

        Operating revenues from other consolidated subsidiaries decreased $9 million and $11 million for the third quarter and nine months ended September 30, 2004, respectively, compared to the corresponding periods of 2003. The 2004 decreases were primarily due to the deconsolidation of the Kwinana project on March 31, 2004. Beginning April 1, 2004, EME recorded its interest in the Kwinana project on the equity method of accounting.

        Earnings from other projects (consolidated subsidiaries and unconsolidated affiliates) increased $2 million and $13 million for the third quarter and nine months ended September 30, 2004, respectively, compared to the corresponding periods of 2003. The 2004 increases in earnings were primarily due to higher earnings from the CBK project in the Philippines due to the completion of Kalayaan Phase II units in early 2004 and EME's Spanish Hydro project largely due to higher generation caused by more rainfall in the first nine months of 2004, compared to the first nine months of 2003.

Previously Reported Discontinued Operations

Ferrybridge and Fiddler's Ferry Plants

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

        During the second quarter of 2003, EME recorded losses of $1 million from discontinued operations primarily related to taxes.

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Lakeland Project

        In 2001, EME ceased consolidating the activities of Lakeland Power Ltd. when an administrative receiver was appointed following a default by Norweb Energi Ltd, the counterparty to a long-term power sales agreement. The consolidated financial statements have been restated to conform to discontinued operations treatment for all historical periods presented. In 2003, a third party completed the purchase of the Lakeland power plant from the administrative receiver for £24 million. The proceeds from the sale and existing cash were used to fund partial repayment of the outstanding debt owed to secured creditors of the project. Lakeland Power Ltd.'s administrative receiver has filed a claim against Norweb Energi Ltd. for termination of the power purchase agreement. To the extent that Lakeland Power Ltd. receives payment under its claim, such amounts will first be used to repay amounts due to creditors. In October 2004, EME purchased the secured creditors' debt from Lakeland Power Ltd. for approximately £6 million. The purchase of the outstanding bank debt was completed to enhance EME's overall position to maximize recovery from the ultimate proceeds received from the claim against Norweb Energi. EME's subsidiary that owns the outstanding shares of Lakeland Power Ltd. will be entitled to receive any residual amount of the proceeds from the claim after creditors' claims are resolved.

        During the third quarter and nine months ended September 30, 2003, EME recorded losses of $423 thousand and approximately $1 million, respectively, from discontinued operations related to administrative expenses incurred as part of the close-out activities.

New Accounting Pronouncements

Emerging Issues Task Force Issue No. 02-14

        In June 2004, the Emerging Issues Task Force reached a consensus on Issue No. 02-14, "Whether an Investor Should Apply the Equity Method of Accounting to Investments Other Than Common Stock." EITF 02-14 addresses whether the equity method of accounting applies when an investor does not have an investment in voting common stock of an investee but exercises significant influence through other means. EITF 02-14 states that an investor should only apply the equity method of accounting when it has investments in either common stock or in-substance common stock of an investee, provided that the investor has the ability to exercise significant influence over the operating and financial policies of the investee. The accounting provisions of EITF 02-14 are effective for reporting periods beginning after September 15, 2004. EME does not expect the adoption of EITF 02-14 to have a material impact on its consolidated financial statements.

Statement of Financial Accounting Standards Interpretation No. 46

        In December 2003, the FASB re-issued Statement of Financial Accounting Standards Interpretation No. 46, "Consolidation of Variable Interest Entities" (FIN 46R). The primary objective of the interpretation is to provide guidance on the identification of, and financial reporting for, entities over which control is achieved through means other than voting rights; such entities are known as variable interest entities. Under this interpretation, the primary beneficiary is the variable interest holder that absorbs a majority of expected losses; if no variable interest holder meets this criteria, then it is the variable interest holder that receives a majority of the expected residual returns. The primary beneficiary is required to consolidate the variable interest entity unless specific exceptions or exclusions are met. This interpretation applies to variable interest entities created after January 31, 2003, and applies to variable interest entities in which EME holds a variable interest that it acquired before February 1, 2003. This interpretation is effective for special purpose entities as of December 31, 2003 and for all other entities as of March 31, 2004.

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Variable Interest Entities

        EME completed a review of the application of FIN 46R to its subsidiaries and affiliates and concluded that it has variable interests in variable interest entities as defined in this interpretation. The following table summarizes the variable interest entities held by continuing operations in which EME has a significant variable interest:

Variable Interest Entity

  Location

  Investment at
September 30, 2004

  EME's Ownership
Interest at
September 30, 2004

  Description

Sunrise   Fellows, CA   $ 112   50%   Gas-fired facility
Watson   Carson, CA     100   49%   Cogeneration facility
Sycamore   Bakersfield, CA     63   50%   Cogeneration facility
Midway-Sunset   Fellows, CA     54   50%   Cogeneration facility
Kern River   Bakersfield, CA     49   50%   Cogeneration facility

        EME has determined that it is not the primary beneficiary in these entities; accordingly, EME will account for its variable interests on the equity method. EME's maximum exposure to loss in these variable interest entities is generally limited to its investment in these entities.

Deconsolidation of Variable Interest Entities

        In accordance with FIN 46R, EME determined that it was not the primary beneficiary of the Doga and Kwinana projects and, accordingly, deconsolidated these projects at March 31, 2004. The Doga and Kwinana projects are part of the sale of international operations and, accordingly, are included in discontinued operations.

FASB Staff Position FAS 106-2

        In May 2004, the FASB issued FASB Staff Position FAS 106-2, "Accounting and Disclosure Requirements Related to the Medicare Prescription Drug, Improvement and Modernization Act of 2003." The primary objective of the position is to provide accounting guidance related to the Medicare Prescription Drug, Improvement and Modernization Act of 2003. EME adopted this guidance effective July 1, 2004, which had an immaterial impact on its consolidated financial statements. According to proposed federal regulations, EME's retiree health care plans provide prescription drug benefits that are deemed to be actuarially equivalent to Medicare benefits. Accordingly, EME recognized the subsidy in the measurement of its accumulated obligation and recorded an actuarial gain.

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LIQUIDITY AND CAPITAL RESOURCES

Introduction

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

 
  Page
MEHC's Liquidity   43
EME's Liquidity   44
Key Financing Developments   44
Termination of the Collins Station Lease   45
2004 Capital Expenditures   45
MEHC's Historical Consolidated Cash Flow   46
EME's Credit Ratings   47
EME's Liquidity as a Holding Company   48
Dividend Restrictions in Major Financings   50
MEHC's Interest Coverage Ratio   53
Contractual Obligations   55
Off-Balance Sheet Transactions   55
Environmental Matters and Regulations   55

        For a complete discussion of these issues, read this quarterly report in conjunction with MEHC's annual report on Form 10-K for the year ended December 31, 2003.

MEHC's Liquidity

        MEHC's ability to honor its obligations under the senior secured notes and the term loan, and to pay overhead is entirely dependent upon the receipt of dividends from EME and receipt of tax-allocation payments from MEHC's parent, Edison Mission Group, and Edison International. See "EME's Liquidity as a Holding Company—Intercompany Tax-Allocation Agreement." Dividends from EME are limited based on its earnings and cash flow, business and tax considerations and restrictions imposed by applicable law.

        At September 30, 2004, MEHC had cash and cash equivalents of $5 million (excluding amounts held by EME and its subsidiaries). On April 5, 2004, the lenders under MEHC's $385 million term loan due in 2006 exercised their right to require MEHC to repurchase $100 million of principal amount at par on July 2, 2004 (referred to as the "Term Loan Put-Option"). The $100 million principal, plus interest, was paid on July 2, 2004.

Dividends to MEHC

        In July and October 2004, EME made dividend payments of $69 million and $5 million, respectively, to MEHC. These payments were used together with cash on hand to meet the Term Loan Put-Option payment discussed above.

        EME amended its certificate of incorporation and bylaws in May 2004 to eliminate the so-called "ring-fencing" provisions that were implemented in early 2001 during the California energy crisis, which had included restrictions on dividends.

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EME's Liquidity

        At September 30, 2004, EME and its subsidiaries had cash and cash equivalents of $1.2 billion, including $739 million received from the sale of Contact Energy, and EME had available the full amount of borrowing capacity under a $98 million corporate credit facility. On October 5, 2004, EME repaid $600 million of the $800 million secured loan at Mission Energy Holdings International, Inc. with the majority of the proceeds received from the sale of Contact Energy. EME's consolidated debt at September 30, 2004 was $4.4 billion. In addition, EME's subsidiaries had $5.3 billion of long-term lease obligations that are due over periods ranging up to 31 years.

Key Financing Developments

EME Financing Developments

        On April 27, 2004, EME replaced its $145 million corporate credit facility with a new $98 million secured corporate credit facility. This credit facility matures on April 27, 2007. Loans made under this credit facility bear interest at LIBOR plus 3.50% per annum. As security for its obligations under this credit facility, EME pledged its ownership interests in the holding companies through which it owns its interests in the Illinois Plants, the Homer City facilities, the Westside projects, and the Sunrise project. EME also granted a security interest in an account into which all distributions received by it from the Big 4 projects will be deposited. EME will be free to use these distributions unless and until an event of default occurs under its corporate credit facility.

        In addition, EME completed the repayment of the remaining $28 million due under the Coal and Capex facility (guaranteed by EME) in April 2004. Accordingly, this credit agreement has been terminated and EME no longer has a contingent liability related to this credit agreement.

Midwest Generation Financing Developments

        On April 27, 2004, Midwest Generation completed a private offering of $1 billion aggregate principal amount of its 8.75% second priority senior secured notes due 2034. Holders of the notes may require Midwest Generation to repurchase, or Midwest Generation may elect to repay, the notes on May 1, 2014 and on each one-year anniversary thereafter at 100% of their principal amount, plus accrued and unpaid interest. Concurrent with the issuance of the notes, Midwest Generation borrowed $700 million under a new first priority senior secured term loan facility. The term loan has a final maturity of April 27, 2011 and bears interest at LIBOR plus 3.25% per annum. Midwest Generation has agreed to repay $1,750,000 of the term loan on each quarterly payment date. Midwest Generation also entered into a new five-year $200 million working capital facility that replaced a prior facility. The new working capital facility also provides for the issuance of letters of credit. As of September 30, 2004, Midwest Generation had no borrowings outstanding under the working capital facility and had reimbursement obligations under a letter of credit for approximately $3 million that expires in 2005. Midwest Generation used the proceeds of the notes issuance and the term loan to refinance $693 million of indebtedness (plus accrued interest and fees) owed by its direct parent, Edison Mission Midwest Holdings Co., which had been guaranteed by Midwest Generation and was due in December 2004, and to make the termination payment under the Collins Station lease in the amount of approximately $960 million.

        Midwest Generation is permitted to use the new working capital facility and cash on hand to provide credit support (either through loans or letters of credit) for forward contracts with third-party counterparties entered into by Edison Mission Marketing & Trading on its behalf for capacity and energy generated from the Illinois Plants. Utilization of this credit facility in support of such forward

44



contracts provides additional liquidity support for implementation of EME's contracting strategy for the Illinois Plants.

        The term loan and working capital facility share a first priority lien and the senior secured notes have a second priority lien in a collateral package which consists of, among other things, substantially all the coal-fired generating plants owned by Midwest Generation and the assets relating to those plants, as well as the equity interests of Midwest Generation and its parent company and the intercompany notes entered into by EME and Midwest Generation in connection with the Powerton-Joliet sale-leaseback transaction.

Termination of the Collins Station Lease

        On April 27, 2004, Midwest Generation terminated the Collins Station lease through a negotiated transaction with the lease equity investor. Midwest Generation made a lease termination payment of approximately $960 million. This amount represented the $774 million of lease debt outstanding, plus accrued interest, and the amount owed to the lease equity investor for early termination of the lease. Midwest Generation received title to the Collins Station as part of the transaction. EME recorded a pre-tax loss of approximately $956 million (approximately $587 million after tax) due to termination of the lease and the planned decommissioning of the asset and disposition of excess inventory.

        Following the termination of the Collins Station lease, Midwest Generation announced plans to permanently cease operations at the Collins Station by December 31, 2004 and decommission the plant. On July 30, 2004, PJM accepted Midwest Generation's request to cease operations at the Collins Station. PJM found that the decommissioning of the plant would not affect the operation or reliability of the PJM markets. During the third quarter of 2004, EME reached an agreement with Exelon Generation to terminate the power purchase agreement effective September 30, 2004 for the two units at the Collins Station that remained under contract. As a result of the termination of the power purchase agreement, EME revised the estimated useful life of the remaining plant assets to end on September 30, 2004 instead of December 31, 2004. Accordingly, EME recorded a pre-tax impairment charge of $5 million during the third quarter of 2004. In October 2004, EME finalized plans to reduce the workforce in Illinois and expects to recognize a $4 million pre-tax charge for exit costs during the fourth quarter of 2004.

        In September 2004, management completed an analysis of future competitiveness in the expanded PJM marketplace of its eight small peaking units in Illinois. Based on this analysis, management decided to decommission six of the eight small peaking units, subject to regulatory review and approval. As a result of this decision, projected future cash flows associated with the Illinois peaking units were less than the book value of the units resulting in an impairment under Statement of Financial Accounting Standards No. 144, "Accounting for the Impairment or the Disposal of Long-Lived Assets." During the third quarter of 2004, EME recorded a pre-tax impairment charge of $29 million (approximately $18 million after tax).

        EME anticipates that the lease termination payment and decommissioning of the Collins Station and small peaking units will result in substantial income tax deductions.

2004 Capital Expenditures

        The estimated capital and construction expenditures of EME's subsidiaries for the final quarter of 2004 are $12 million. These expenditures are planned to be financed by existing subsidiary credit agreements and cash generated from their operations. During the third quarter of 2004, Midwest Generation decided to return Will County Units 1 and 2 to service. Operations at these units were

45



suspended in 2002, pending recovery of market prices. As part of returning these units to service, Midwest Generation expects to install environmental improvements of approximately $10 million by June 30, 2005. In addition, Homer City plans to spend approximately $17 million related to environmental improvements prior to the summer of 2005.

MEHC's Historical Consolidated Cash Flow

Consolidated Cash Flows from Operating Activities

        Cash used in operating activities from continuing operations increased $1.5 billion in the first nine months of 2004, compared to the first nine months of 2003. The 2004 increase was primarily attributable to the $960 million lease termination payment in 2004 related to the Collins Station lease and tax-allocation payments of $43 million paid by EME to Edison International during the first nine months of 2004, compared to $89 million in tax-allocation payments received by EME from Edison International during the first nine months of 2003. EME made tax payments in the first three quarters of 2004 primarily attributable to taxable income resulting from the sale of the Four Star Oil & Gas and Brooklyn Navy Yard projects. In addition, MEHC received $24 million in tax-allocation payments from Edison International during the first nine months of 2004, compared to $41 million during the first nine months of 2003. For further discussion of the tax-allocation payments, see "—EME's Liquidity as a Holding Company—Intercompany Tax-Allocation Agreement." In addition, distributions from unconsolidated affiliates during the first nine months of 2004 were lower than the corresponding period of 2003, primarily because the 2003 distributions included $151 million from completion of the Sunrise project financing in September 2003.

Consolidated Cash Flows from Financing Activities

        Cash provided by financing activities from continuing operations increased $860 million in the first nine months of 2004, compared to the first nine months of 2003. The 2004 increase was due to a higher level of borrowings in 2004 compared to 2003, primarily due to the $1 billion secured notes and $700 million term loan facility received by Midwest Generation in April 2004 partially offset by the repayment of $693 million related to Edison Mission Midwest Holdings' credit facility and $28 million related to the Coal and Capex facility in April 2004 and $100 million related to the $385 million term loan in July 2004.

Consolidated Cash Flows from Investing Activities

        Cash provided by investing activities from continuing operations increased $899 million in the first nine months of 2004, compared to the first nine months of 2003. The 2004 increase was due to a combination of the following:

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EME's Credit Ratings

Overview

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

 
  Moody's Rating
  S&P Rating
EME   B1   B
Midwest Generation, LLC:        
  First priority senior secured rating   Ba3   B+
  Second priority senior secured rating   B1   B-
Edison Mission Marketing & Trading   Not Rated   B

        On August 6, 2004, Moody's raised EME's credit rating to B1 from B2. 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. EME notes that these credit ratings are not recommendations to buy, sell or hold its securities and may be revised at any time by a rating agency.

        EME does not have any "rating triggers" contained in subsidiary financings that would result in EME being required to make equity contributions or provide additional financial support to its subsidiaries.

        Edison Mission Marketing & Trading has provided credit for the benefit of counterparties in the form of cash and letters of credit ($93 million as of September 30, 2004) for EME's price risk management and domestic trading activities (including Midwest Generation and Homer City) related to accounts payable and unrealized losses. A subsidiary of EME has also supported a portion of First Hydro's United Kingdom hedging activities through a cash collateralized credit facility, under which letters of credit totaling £22 million have been issued as of September 30, 2004.

        With the remaining power purchase agreements with Exelon Generation expiring on December 31, 2004, EME expects to generate higher merchant generation in 2005 which will increase the potential for margin and collateral requirements. Changes in forward market prices and the strategies adopted for merchant generation could further increase the need for credit support for price risk management activities related to these projects. EME estimates that total margin and collateral requirements to support price risk management could increase to approximately $400 million if 50% of merchant generation from the Illinois Plants and Homer City facilities was sold forward for one year and power prices subsequently increased using common industry analytics. Midwest Generation has cash on hand and a $200 million working capital facility that can be used to provide credit support for forward contracts entered into on behalf of the Illinois Plants. In addition, EME has cash on hand and a $98 million working capital facility that can be used to provide credit support for its subsidiaries. See "EME's Liquidity" for further discussion.

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Credit Rating of Edison Mission Marketing & Trading

        Pursuant to the Homer City sale-leaseback documents, a below investment grade credit rating of Edison Mission Marketing & Trading restricts the ability of EME Homer City Generation L.P. to enter into permitted trading activities, as defined in the documents, with Edison Mission Marketing & Trading to sell forward the output of the Homer City facilities. These documents include a requirement that the counterparty to such transactions, and EME Homer City, if acting as seller to an unaffiliated third party, be investment grade. EME currently sells all of the output from the Homer City facilities through Edison Mission Marketing & Trading, which has a below investment grade credit rating, and EME Homer City is not rated. Therefore, in order for EME to continue to sell forward the output of the Homer City facilities, either: (1) EME must obtain consent from the sale-leaseback owner participant to permit EME Homer City to sell directly into the market or through Edison Mission Marketing & Trading; or (2) Edison Mission Marketing & Trading must provide assurances of performance consistent with the requirements of the sale-leaseback documents. EME has obtained a consent from the sale-leaseback owner participant that will allow EME Homer City to enter into such sales, under specified conditions, through December 31, 2004. EME Homer City continues to be in compliance with the terms of the consent; however, the consent is revocable. The owner participant has not indicated that it intends to revoke the consent; however, there can be no assurance that it will not do so in the future. Revocation of the consent would not affect trades between Edison Mission Marketing & Trading and EME Homer City that had been entered into while the consent was still in effect. EME is permitted to sell the output of the Homer City facilities into the spot market at any time. See "Market Risk Exposures—Commodity Price Risk—Americas—Homer City Facilities."

EME's Liquidity as a Holding Company

Overview

        At September 30, 2004, EME had corporate cash and cash equivalents of $84 million to meet liquidity needs. EME's corporate cash and cash equivalents increased by $139 million subsequent to September 30, 2004 from the net cash received from the sale of Contact Energy less the repayment of subsidiary indebtedness. See "—EME's Liquidity." EME had no borrowings outstanding or letters of credit outstanding on the $98 million secured line of credit at September 30, 2004. Cash distributions from EME's subsidiaries and partnership investments, tax-allocation payments from Edison International and unused capacity under its corporate credit facility represent EME's major sources of liquidity to meet its cash requirements. The timing and amount of distributions from EME's subsidiaries may be affected by many factors beyond its control. See "—Dividend Restrictions in Major Financings." 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 Agreement."

        EME's secured corporate credit facility provides credit available in the form of cash advances or letters of credit. In addition to the interest payments, EME pays a commitment fee of 0.50% on the unutilized portion of the facility. EME has agreed to maintain a minimum interest coverage ratio and a minimum recourse debt to recourse capital ratio (as such ratios are defined in the credit agreement). At September 30, 2004, EME met both these ratio tests.

        As security for its obligations under its new corporate credit facility, EME pledged its ownership interests in the holding companies through which it owns its interests in the Illinois Plants, the Homer City facilities, the Westside projects and the Sunrise project. EME also granted a security interest in an account into which all distributions received by it from the Big 4 projects will be deposited. EME will

48



be free to use these distributions unless and until an event of default occurs under its corporate credit facility.

Historical Distributions Received By EME

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

 
  Nine Months Ended
September 30,

 
  2004
  2003
 
  (in millions)

Domestic Projects            

Distributions from Consolidated Operating Projects:

 

 

 

 

 

 
  EME Homer City Generation L.P. (Homer City facilities)   $ 61   $ 102
  Holding companies of other consolidated operating projects         1

Distributions from Unconsolidated Operating Projects:

 

 

 

 

 

 
  Edison Mission Energy Funding Corp. (Big 4 Projects)     80     74
  Four Star Oil & Gas Company         15
  Sunrise Power Company     5     66
  Holding companies for Westside projects     13     20
  Holding companies of other unconsolidated operating projects     1     5
   
 
Total Distributions from Domestic Projects   $ 160   $ 283
   
 
International Projects (Mission Energy Holdings International)            

Distributions from Consolidated Operating Projects:

 

 

 

 

 

 
  First Hydro Holdings (First Hydro project)   $ 29   $ 18
  Loy Yang B     12     22
  Doga         18
  Contact Energy     50     16
  Valley Power         8
  Kwinana(1)     4     4
  Holding companies of other consolidated operating projects     10    

Distributions from Unconsolidated Operating Projects:

 

 

 

 

 

 
  ISAB Energy     24     1
  IVPC4 (Italian Wind project)     18     8
  Derwent     1     1
  Doga     15    
  EcoEléctrica     9    
  Paiton         9
  Tri Energy     2    
  Holding companies of other unconsolidated operating projects     4     2
   
 
Total Distributions from International Projects   $ 178   $ 107
   
 
Total Distributions   $ 338   $ 390
   
 

(1)
Distributions for the nine months ended September 30, 2004 reflect distributions made during the first quarter of 2004. Effective March 31, 2004, the Kwinana project was deconsolidated due to the adoption of FIN 46R.

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Intercompany Tax-Allocation Agreement

        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. MEHC became a party to the tax-allocation agreement with Edison Mission Group on July 2, 2001, when it became part of the Edison International consolidated filing group. EME and MEHC have historically received tax-allocation payments related to domestic net operating losses incurred by EME and MEHC. The right of MEHC and EME to receive and the amount and timing of tax-allocation payments is dependent on the inclusion of MEHC and EME, respectively, in the consolidated income tax returns of Edison International and its subsidiaries and other factors, including the consolidated taxable income of Edison International and its subsidiaries, the amount of net operating losses and other tax items of MEHC, EME, its subsidiaries, and other subsidiaries of Edison International and specific procedures regarding allocation of state taxes. MEHC and EME receive tax-allocation payments for tax losses when and to the extent that the consolidated Edison International group generates sufficient taxable income in order to be able to utilize MEHC's tax losses or the tax losses of EME in the consolidated income tax returns for Edison International and its subsidiaries. Based on the application of the factors cited above, MEHC and EME may be obligated during periods they generate taxable income to make payments under the tax-allocation agreements.

Dividend Restrictions in Major Financings

General

        Each of EME's direct or indirect subsidiaries is organized as a legal entity separate and apart from EME and its other subsidiaries. Assets of EME's subsidiaries are not available to satisfy EME's obligations or the obligations of any of its other subsidiaries. However, unrestricted cash or other assets that are available for distribution may, subject to applicable law and the terms of financing arrangements of the parties, be advanced, loaned, paid as dividends or otherwise distributed or contributed to EME or to its subsidiary holding companies.

50



Key Ratios of EME's Principal Subsidiaries Affecting Dividends

        Set forth below are key ratios of EME's principal subsidiaries for the twelve months ended September 30, 2004:

Subsidiary

  Financial Ratio

  Covenant

  Actual

Midwest Generation, LLC (Illinois Plants)   Interest Coverage Ratio   Greater than or equal to 1.25 to 1   2.39 to 1(1)

Midwest Generation, LLC (Illinois Plants)

 

Secured Leverage Ratio

 

Less than or equal to 8.75 to 1

 

5.94 to 1

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

 

Senior Rent Service Coverage Ratio

 

Greater than 1.7 to 1

 

2.73 to 1

Edison Mission Energy Funding Corp. (Big 4 Projects)

 

Debt Service Coverage Ratio

 

Greater than or equal to 1.25 to 1

 

2.54 to 1

Mission Energy Holdings International

 

Interest Coverage Ratio

 

Greater than or equal to 1.3 to 1

 

3.92 to 1(2)

(1)
Interest coverage ratio was computed on a pro forma basis assuming the credit facility had been in existence for a twelve-month period.

(2)
For more information about this interest coverage ratio, see "—Mission Energy Holdings International Interest Coverage Ratio" below.

        For a more detailed description of the 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, refer to "Dividend Restrictions in Major Financings" on page 82 of MEHC's annual report on Form 10-K for the year ended December 31, 2003.

Midwest Generation Financing Restrictions on Distributions

        Midwest Generation is bound by the covenants in its credit facility and indenture as well as certain covenants under the Powerton-Joliet lease documents with respect to Midwest Generation making payments under the leases. These covenants include restrictions on the ability to, among other things, incur debt, create liens on its property, merge or consolidate, sell assets, make investments, engage in transactions with affiliates, make distributions, make capital expenditures, enter into agreements restricting its ability to make distributions, engage in other lines of business or engage in transactions for any speculative purpose. In addition, the credit facility contains financial covenants binding on Midwest Generation.

Covenants in Credit Agreement

        In order for Midwest Generation to make a distribution, it must be in compliance with covenants specified under its credit agreement. Compliance with the covenants in its credit agreement includes maintaining the following two financial performance requirements:

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        In addition, Midwest Generation's distributions are limited in amount. The aggregate amount of distributions made by Midwest Generation since April 27, 2004 may not exceed the sum of (i) 75% of excess cash flow (as defined in the credit agreement) generated since that date, plus (ii) up to 100% of the amount of equity contributions or subordinated loans made by EME or a subsidiary of EME to Midwest Generation after April 27, 2004, but in this latter case only to the extent excess cash flow not used for a dividend under (i) is available for such payments. With the remaining 25% of excess cash flow, Midwest Generation must offer to prepay the term loan to the lenders. Each of the lenders may, at its option, decline such prepayment with respect to its pro rata share of the term loan. If Midwest Generation is rated investment grade, the aggregate amount of distributions made by Midwest Generation may equal but not exceed 100% of excess cash flow generated since becoming investment grade plus 75% of excess cash flow generated during the period between April 27, 2004 and the date immediately prior to becoming investment grade.

        Excess cash flow was $117 million for the period between April 27, 2004 and September 30, 2004. At September 30, 2004, Midwest Generation met both of the covenant requirements described above under the credit agreement and made a distribution of $88 million in October 2004. As required under the credit agreement, Midwest Generation made an offer to the lenders to prepay $29 million of the term loan, of which $5 million was accepted by certain lenders and repaid on October 20, 2004. The remaining $24 million of excess cash flow not repaid will be retained by Midwest Generation as working capital or used to make a voluntary prepayment at a later date, as provided under the credit agreement.

Covenants in Indenture

        Midwest Generation's indenture contains restrictions on its ability to make a distribution substantially similar to those in the credit agreement. Failure to achieve the conditions required for distributions will not result in a default under the indenture, nor does the indenture contain any other financial performance requirements.

Mission Energy Holdings International Interest Coverage Ratio

        Under the credit agreement governing its term loan, Mission Energy Holdings International has agreed to maintain a minimum interest coverage ratio of 1.30 to 1 beginning March 2004 for the trailing twelve-month period.

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        The following table sets forth the major components of the interest coverage ratio for the twelve months ended September 30, 2004 and the year ended December 31, 2003 on a pro forma basis assuming the term loan had been in existence at the beginning of 2003:

 
  September 30, 2004
  December 31, 2003
 
 
  Actual
  Pro Forma
Adjustment(1)

  Pro Forma
  Actual
  Pro Forma
Adjustment(1)

  Pro Forma
 
 
  (in millions)

 
Funds Flow from Operations                                      
  Historical distributions from international projects   $ 237   $   $ 237   $ 158   $   $ 158  
  Other fees and cash payments considered distributions under the term loan     16         16     20         20  
  Administrative and general expenses     (2 )       (2 )   (2 )       (2 )
   
 
 
 
 
 
 
Total Funds Flow from Operations   $ 251   $   $ 251   $ 176   $   $ 176  
   
 
 
 
 
 
 
Term Loan Interest Expense   $ 48   $ 16   $ 64   $ 4   $ 60   $ 64  
   
 
 
 
 
 
 
Interest Coverage Ratio                 3.92                 2.75  
               
             
 

(1)
The pro forma adjustment assumes that the $800 million loan was outstanding at the beginning of 2003. Pro forma interest expense was calculated using the interest rate floor of 7% plus amortization of deferred financing costs.

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

MEHC's Interest Coverage Ratio

        The following details with respect to MEHC's interest coverage ratio are provided as an aid to understanding the computations 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 read 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. The following table sets forth

53



MEHC's interest coverage ratio for the twelve months ended September 30, 2004 and the year ended December 31, 2003:

 
  September 30,
2004

  December 31,
2003

 
 
  (in millions)

 
Funds Flow from Operations:              
  Operating Cash Flow(1) from Consolidated Operating Projects(2):              
    Illinois Plants(3)   $ 236   $ 242  
    Homer City     104     153  
    First Hydro     55     (8 )
  Other consolidated operating projects     183     165  
  Price risk management and energy trading     (14 )   11  
  Distributions from unconsolidated Big 4 projects     104     98  
  Distributions from other unconsolidated operating projects     142     178  
  Interest income     5     4  
  Interest expense at Mission Energy Holdings International     (52 )    
  Operating expenses     (163 )   (144 )
   
 
 
  Total EME funds flow from operations   $ 600   $ 699  
 
Operating cash flow from unrestricted subsidiaries

 

 


 

 

(2

)
  Funds flow from operations of projects sold     (57 )   (1 )
  MEHC     1     1  
   
 
 
    $ 544   $ 697  
   
 
 
Interest Expense:              
  EME   $ 268   $ 286  
  EME—affiliate debt     1     1  
  MEHC interest expense     163     160  
  Interest savings on projects sold     (54 )    
   
 
 
    Total interest expense   $ 378   $ 447  
   
 
 
Interest Coverage Ratio     1.44     1.56  
   
 
 

(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. Unconsolidated operating projects are entities of which EME owns 50% or less and which EME accounts for on the equity method or EME is not the primary beneficiary under FIN 46R.

(3)
Distribution to EME of funds flow from operations of the Illinois Plants is currently restricted. See "Dividend Restrictions in Major Financings—Midwest Generation Financing Restrictions on Distributions," for a description of restrictions applicable to future periods.

        The above interest coverage ratio was determined in accordance with the definitions set forth in the bond indenture governing MEHC's senior secured notes and the credit agreement governing the term loan. The interest coverage ratio prohibits MEHC, EME and its subsidiaries from incurring additional indebtedness, except as specified in the indenture and the financing documents, unless MEHC's interest coverage ratio exceeds 2.0 to 1 for the immediately preceding four fiscal quarters.

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Contractual Obligations

Fuel Supply Contracts

        Midwest Generation and Homer City have entered into additional fuel purchase agreements with various third-party suppliers during the first nine months of 2004. Midwest Generation and Homer City's fuel purchase commitments under these agreements are currently estimated to be $22 million for 2004, $63 million for 2005, $97 million for 2006, $101 million for 2007, and $57 million for 2008.

Off-Balance Sheet Transactions

        For a discussion of EME's off-balance sheet transactions, refer to "Off-Balance Sheet Transactions" on page 96 of MEHC's annual report on Form 10-K for the year ended December 31, 2003. Except as set forth under "Liquidity and Capital Resources—Termination of the Collins Station Lease," there have been no other significant developments that affect disclosures presented in the annual report.

Environmental Matters and Regulations

        For a discussion of EME's environmental matters, refer to "Environmental Matters and Regulations" on page 99 of MEHC's annual report on Form 10-K for the year ended December 31, 2003 and the notes to the Consolidated Financial Statements set forth therein. There have been no other significant developments with respect to environmental matters specifically affecting EME since the filing of MEHC's annual report.

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MARKET RISK EXPOSURES

Introduction

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

        This section discusses these market risk exposures under the following headings:

 
  Page
Commodity Price Risk   56
Credit Risk   63
Interest Rate Risk   65
Foreign Exchange Rate Risk   65
Fair Value of Financial Instruments   66
Regulatory Matters   67

        For a complete discussion of these issues, read this quarterly report in conjunction with MEHC's annual report on Form 10-K for the year ended December 31, 2003.

Commodity Price Risk

General Overview

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

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

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Americas

Introduction

        Electric power generated at EME's domestic merchant plants is generally sold under bilateral arrangements with utilities and power marketers under short-term transactions with terms of two years or less or to the PJM and/or the New York Independent System Operator (NYISO) markets. As discussed further below, beginning in 2003, EME has been selling a significant portion of the power generated from its Illinois Plants into wholesale power markets, including PJM since May 1, 2004.

        EME's merchant operations expose it to commodity price risk, which represents the potential loss that can be caused by a change in the market value of a particular commodity. Commodity price risks are actively monitored by a risk management committee to ensure compliance with EME's risk management policies. Policies are in place which define the risk tolerance for EME's merchant activities. Procedures exist which allow for monitoring of all commitments and positions with regular reviews by the risk management committee. Despite this, there can be no assurance that all risks have been accurately identified, measured and/or mitigated.

Illinois Plants

Status of the Exelon Generation Power Purchase Agreements—

        Energy generated at the Illinois Plants has historically been sold under three power purchase agreements between EME's wholly owned subsidiary, Midwest Generation, and Exelon Generation Company, under which Exelon Generation is obligated to make capacity payments for the plants under contract and energy payments for the energy produced by these plants and taken by Exelon Generation. The power purchase agreements began on December 15, 1999. The power purchase agreement for the Collins Station was terminated effective September 30, 2004; the other two contracts (for coal-fired generation and peaking units) expire in December 2004. The capacity payments provide the units under contract with revenue for fixed charges, and the energy payments compensate those units for all, or a portion of, variable costs of production.

        Approximately 57% and 68% of the energy and capacity sales from the Illinois Plants in the first nine months of 2004 and 2003, respectively, were to Exelon Generation under the power purchase agreements. As a result of Exelon Generation's election to release units from contract for 2004, Midwest Generation's reliance on sales into the wholesale market increased in 2004 from 2003. For the nine months ended September 30, 2004, 3,859 MW of Midwest Generation's generating capacity (2,383 MW related to its coal-fired generation units, 1,084 MW related to its Collins Station, and 392 MW related to its peaking units) were subject to power purchase agreements with Exelon Generation. Following the termination of the Collins Station power purchase agreement, 2,775 MW will be subject to power purchase agreements with Exelon Generation during the fourth quarter of 2004. 2004 is the final contract year under these power purchase agreements.

Merchant Sales—

        The energy and capacity from units not subject to a power purchase agreement with Exelon Generation are sold under terms, including price and quantity, negotiated by Edison Mission Marketing & Trading with customers through a combination of bilateral agreements, forward energy sales and spot market sales. These arrangements generally have a term of two years or less. Thus, EME is subject to market risks related to the price of energy and capacity from those units. Capacity prices for merchant energy sales are, and are expected in the near term to remain, substantially less than

57



those Midwest Generation currently receives under the 1999 power purchase agreements with Exelon Generation. 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. 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.

        Prior to May 1, 2004, the primary markets available to Midwest Generation for wholesale sales of electricity from the Illinois Plants were direct "wholesale customers" and broker-arranged "over-the-counter customers." The most liquid over-the-counter markets in the Midwest region have historically been for sales into the control area of Cinergy and, to a lesser extent, for sales into the control areas of Commonwealth Edison and American Electric Power, referred to as "Into ComEd" and "Into AEP," respectively. "Into ComEd" and "Into AEP" are bilateral markets for the sale or purchase of electrical energy for future delivery. Due to geographic proximity, "Into ComEd" was the primary market for Midwest Generation.

        The following table depicts the historical average market prices for energy per megawatt-hour "Into ComEd" for the first four months of 2004.

 
  Into ComEd*
Historical Energy Prices

  On-Peak(1)
  Off-Peak(1)
  24-Hr
January   $ 43.30   $ 15.18   $ 27.88
February     43.05     18.85     29.98
March     40.38     21.15     30.66
April     39.50     16.76     27.88
   
 
 
Four-Month Average   $ 41.56   $ 17.99   $ 29.10
   
 
 

(1)
On-peak refers to the hours of the day between 6:00 a.m. and 10:00 p.m. Monday through Friday, excluding North American Electric Reliability Council (NERC) holidays. All other hours of the week are referred to as off-peak.

*
Source: Energy prices were determined by obtaining broker quotes and other public price sources, for "Into ComEd" delivery points.

        Following Commonwealth Edison's joining PJM on May 1, 2004, sales of electricity from the Illinois Plants now include bilateral and spot sales into PJM, with spot sales being based on locational marginal pricing. These sales, into the expanded PJM, the primary market currently available to Midwest Generation, replaced sales previously made as bilateral sales and spot sales "Into ComEd." See "—Regulatory Matters" for a more detailed discussion of recent developments regarding Commonwealth Edison's joining PJM and "—Homer City Facilities" below for a discussion of locational marginal pricing. Performance of transactions in these markets is subject to contracts that generally provide for liquidated damages supported by a variety of credit requirements, which may include independent credit assessment, parent company guarantees, letters of credit, and cash margining arrangements.

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        The following table depicts the historical average market prices for energy per megawatt-hour since joining PJM on May 1, 2004.

Historical Energy Prices

  Northern
Illinois Hub

May   $ 34.05
June     28.58
July     30.92
August     26.31
September     27.98
   

Five-Month Average

 

$

29.57
   

*
Energy prices calculated at the Northern Illinois Hub delivery point using hourly real-time prices as published by PJM. There is no comparison for the same months in 2003.

        Forward market prices in the Northern Illinois Hub 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, plant outages in the region, 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 set forth in the table below.

        The following table sets forth the forward market prices for energy per megawatt-hour as quoted for sales into the Northern Illinois Hub at September 30, 2004:

 
  24-Hour Northern
Illinois Hub
Forward Energy Prices*

2004      
  October   $ 25.86
  November     27.52
  December     30.49

2005 Calendar "strip"(1)

 

$

32.82

(1)
Market price for energy purchases for the entire calendar year, as quoted for sales into the Northern Illinois Hub.

*
Energy prices were determined by obtaining broker quotes and other public sources for the Northern Illinois Hub delivery point.

        Midwest Generation intends to hedge a portion of its merchant portfolio risk through Edison Mission Marketing & Trading. The following table summarizes Midwest Generation's hedge position (primarily based on prices at the Northern Illinois Hub) at September 30, 2004:

 
  2004
  2005
  2006
Megawatt hours     3,250,276     4,659,585     438,000
Average price/MWhr   $ 27.87   $ 38.14   $ 31.50

        To the extent Midwest Generation does not hedge its merchant portfolio, 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

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spot market sales. Second, Midwest Generation's ability to enter into hedging transactions will depend upon its and Edison Mission Marketing & Trading's credit capacity and upon the over-the-counter forward sales markets having sufficient liquidity to enable Midwest Generation to identify counterparties who are able and willing to enter into hedging transactions with it. Midwest Generation is permitted to use its new working capital facility and cash on hand to provide credit support for forward contracts entered into by Edison Mission Marketing & Trading for capacity and energy generation by Midwest Generation under an intercompany energy services agreement between Midwest Generation and Edison Mission Marketing & Trading. Utilization of this credit facility in support of such forward contracts is expected to provide additional liquidity support for implementation of Midwest Generation's contracting strategy for the Illinois Plants. See "—Credit Risk," below.

        In addition to the prevailing market prices, Midwest Generation's ability to derive profits from the sale of electricity from the units released from contract by Exelon Generation 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.

        Effective May 1, 2004, the transmission system of Commonwealth Edison became integrated into PJM. Over EME's and Midwest Generation's objections, such integration was allowed to occur in advance of the integration of American Electric Power into PJM, which had resulted in the creation of an islanded market within PJM limited to the service territory of Commonwealth Edison. Concerns about the islanded market of Commonwealth Edison became moot on October 1, 2004, when American Electric Power was integrated into PJM. In general, power produced by Midwest Generation not under contract with Exelon Generation has been sold in the past using transmission obtained from Commonwealth Edison under its open-access tariff filed with the FERC, and the application of the PJM tariff to Commonwealth Edison's transmission system could also affect the rates, terms and conditions of transmission service received by Midwest Generation. Given the recent integration of American Electric Power into PJM, such changes, if any, are not expected to have a material effect on Midwest Generation. See "—Regulatory Matters" for further discussion.

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

        EME is continuing to monitor the activities at the FERC related to the expansion of PJM and to advocate regulatory positions that promote efficient and fair markets in which the Illinois Plants compete.

Homer City Facilities

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

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        The following table depicts the average market prices per megawatt-hour in PJM during the first nine months of 2004 and 2003:

 
  24-Hour PJM
Historical Energy Prices*

 
  2004
  2003
January   $ 51.12   $ 36.56
February     47.19     46.13
March     39.54     46.85
April     43.01     35.35
May     44.68     32.29
June     36.72     27.26
July     40.09     36.55
August     34.76     39.27
September     40.62     28.71
   
 

Nine-Month Average

 

$

41.97

 

$

36.55
   
 

*
Energy prices were calculated at the Homer City busbar (delivery point) using historical hourly real-time 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 the first nine months of 2004 were higher than the average historical market prices during the first nine months of 2003. 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, plant outages in the region, 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 set forth in the table below.

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

        Under the PJM market design, locational marginal pricing (sometimes referred to as LMP), which establishes hourly prices at specific locations throughout PJM by considering factors including generator bids, load requirements, transmission congestion and losses, can cause the price at a specific delivery point to be raised or lowered relative to other locations depending on how the point is impacted by transmission constraints. During the past 12 months, transmission congestion in PJM has resulted in prices at the PJM West Hub (the primary trading hub in PJM) being higher than those at Homer City by an average of three percent.

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

        The following table sets forth the forward market prices for energy per megawatt-hour as quoted for sales into the PJM West Hub at September 30, 2004:

 
  24-Hour PJM West Hub
Forward Energy Prices*

2004      
  October   $ 39.23
  November     41.40
  December     45.15

2005 Calendar "strip"(1)

 

$

46.19

(1)
Market price for energy purchases for the entire calendar year, as quoted for sales into the PJM West Hub.

*
Energy prices were determined by obtaining broker quotes and other public sources for the PJM West Hub delivery point. Forward prices at PJM West Hub are generally higher than the prices at the Homer City busbar.

        The following table summarizes Homer City's hedge position at September 30, 2004:

 
  2004
  2005
Megawatt hours     2,287,200     6,336,000
Average price/MWhr   $ 36.66   $ 44.48

        The average price/MWhr for Homer City's hedge position is based on PJM West Hub. Energy prices at the PJM West Hub have averaged three percent higher than energy prices at Homer City during the past twelve months. A discussion of the basis risk between PJM West Hub and Homer City is set forth above.

        Market conditions for the sale of capacity and energy from the Homer City facilities affect the ability of EME's subsidiary, EME Homer City, to meet its obligations under the Homer City sale-leaseback documents. These market conditions are beyond EME's control.

Europe

United Kingdom

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

        The electricity trading arrangements introduced in March 2001 provide, among other things, for the establishment of a range of voluntary short-term power exchanges and brokered markets operating

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from a year or more in advance to 1 hour prior to the delivery or receipt of power. In the final hour after the notification of all contracts, the system operator can accept bids and offers in the Balancing Mechanism to balance generation and demand and resolve any transmission constraints. There is a mandatory settlement process for recovering imbalances between contracted and metered volumes with strong incentives for being in balance, and a Balancing and Settlement Code Panel to oversee governance of the Balancing Mechanism. The system operator can also purchase system reserve and response services to maintain the quality of the electrical supply directly from generators (generally referred to as "ancillary services"). Ancillary services contracts typically run for up to a year and can consist of both fixed amounts and variable amounts represented by prices for services that are only paid for when actually called upon by the grid operator. A key feature of the trading arrangements is the requirement for firm physical delivery, which means that a generator must deliver, and a consumer must take delivery of, its net contracted positions or pay for any energy imbalance at the imbalance prices calculated by the system operator based on the prices of bids and offers accepted in the Balancing Mechanism. This provides an incentive for parties to contract in advance and for the development of forwards and futures markets. Under these arrangements, there has been an increased emphasis on credit quality, including the need for parent company guarantees or letters of credit for companies below investment grade.

        The wholesale price of electricity fell significantly between 2002 and 2003. The reduction was driven principally by surplus generating capacity and increased competition. During 2003, prices were more volatile, and in the second half of 2004, prices for baseload electricity have risen in line with increases in the cost of gas for generation. The increases have been accompanied during 2004 by a considerable narrowing in the peak/off peak differentials. Compliance with First Hydro's bond financing documents is subject to market conditions for electric energy and ancillary services, which are beyond First Hydro's control.

Asia Pacific

Australia

        The Loy Yang B plant and the Valley Power Peaker project sell electrical energy through a centralized electricity pool, which provides for a system of generator bidding, central dispatch and a settlements system based on a clearing market for each half-hour of every day. The National Electricity Market Management Company, operator and administrator of the pool, determines a spot price each half-hour. To mitigate exposure to price volatility of the electricity traded into the pool, the Loy Yang B plant and the Valley Power Peaker project have entered into a number of financial hedges. The State Hedge agreement with the State Electricity Commission of Victoria is a long-term contractual arrangement based upon a fixed price commencing May 8, 1997 and terminating October 31, 2016. The State Government of Victoria, Australia guarantees the State Electricity Commission of Victoria's obligations under the State Hedge. From January 2003 to July 2014, approximately 77% of the Loy Yang B plant output sold is hedged under the State Hedge. From August 2014 to October 2016, approximately 55% 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.

Credit Risk

        In conducting EME's price risk management and trading activities, EME contracts with a number of utilities, energy companies and financial institutions, collectively referred to as counterparties. In the

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

        To manage credit risk, EME looks at the risk of a potential default by counterparties. Credit risk is measured by the loss that would be incurred if counterparties failed to perform pursuant to the terms of their contractual obligations. EME measures, monitors and mitigates, to the extent possible, credit risk. To mitigate counterparty risk, master netting agreements are used whenever possible and counterparties may be required to pledge collateral when deemed necessary. EME also takes other appropriate steps to limit or lower credit exposure. Processes have also been established to determine and monitor the creditworthiness of counterparties. EME manages the credit risk on the portfolio based on credit ratings using published ratings of counterparties and other publicly disclosed information, such as financial statements, regulatory filings, and press releases, to guide it in the process of setting credit levels, risk limits and contractual arrangements including master netting agreements. A risk management committee regularly reviews the credit quality of EME's counterparties. Despite this, there can be no assurance that these efforts will be wholly successful in mitigating credit risk or that collateral pledged will be adequate.

        EME measures credit risk exposure from counterparties of its merchant energy activities by the sum of: (i) 60 days of accounts receivable, (ii) current fair value of open positions, and (iii) a credit value at risk. EME's subsidiaries enter into master agreements and other arrangements in conducting price risk management and trading activities which typically provide for a right of setoff in the event of bankruptcy or default by the counterparty. Accordingly, EME's credit risk exposure from counterparties is based on net exposure under these agreements. At September 30, 2004, the credit ratings of EME's counterparties were as follows:

S&P Credit Rating

  September 30, 2004
 
  (in millions)

A or higher   $ 49
A-     26
BBB+     113
BBB     21
BBB-     10
Below investment grade     12
   
Total   $ 231
   

        Exelon Generation accounted for 41% and 46% of EME's consolidated operating revenues for the first nine months of 2004 and 2003, respectively. The percentage is less in 2004 because a smaller number of plants are subject to contracts with Exelon Generation. See "—Commodity Price Risk—Americas—Illinois Plants." Any failure of Exelon Generation to make payments under the power purchase agreements could adversely affect EME's results of operations and financial condition.

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

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        Approximately 15% of EME's consolidated operating revenues for the first nine months of 2004 were to BP Energy Company, a third-party customer. (An investment grade affiliate of BP Energy has guaranteed payment of amounts due under the related contracts.)

Interest Rate Risk

        MEHC mitigated the risk of interest rate fluctuations associated with the $385 million term loan ($100 million due July 2, 2004 and $285 million due 2006) by arranging for variable rate financing with interest rate swaps. MEHC entered into swaps that covered interest accrued from January 2, 2003 to July 2, 2004 and April 2, 2003 to July 2, 2004. MEHC has not entered into any new interest rate swaps associated with the $285 million portion of the term loan for periods beyond July 2, 2004.

        Interest rate changes affect the cost of capital needed to operate EME's projects. 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. 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 $6.1 billion at September 30, 2004, compared to the carrying value of $5.5 billion. The fair market value of MEHC's parent only total long-term obligations was $1.3 billion at September 30, 2004, compared to the carrying value of $1.1 billion.

Foreign Exchange Rate Risk

        Fluctuations in foreign currency exchange rates can affect, on a U.S. dollar equivalent basis, the amount of EME's equity contributions to, and distributions from, its international projects. At times, EME has hedged a portion of its current exposure to fluctuations in foreign exchange rates through financial derivatives, offsetting obligations denominated in foreign currencies, and indexing underlying project agreements to U.S. dollars or other indices reasonably expected to correlate with foreign exchange movements. In addition, EME has used statistical forecasting techniques to help assess foreign exchange risk and the probabilities of various outcomes. EME cannot provide assurances, however, that fluctuations in exchange rates will be fully offset by hedges or that currency movements and the relationship between certain macroeconomic variables will behave in a manner that is consistent with historical or forecasted relationships.

        The First Hydro plant in the U.K. and the plants in Australia have been financed in their local currencies, pounds sterling and Australian dollars, respectively, thus hedging the majority of their acquisition costs against foreign exchange fluctuations. As discussed in "Management's Overview," EME entered into sales agreements for its international operations.

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Fair Value of Financial Instruments

Non-Trading Derivative Financial Instruments

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

 
  September 30,
2004

  December 31,
2003

 
Commodity price:              
  Electricity   $ (49 ) $ (7 )
Interest rate:              
  Interest rate swaps   $   $ (5 )

        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 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 September 30, 2004 (in millions):

 
  Total Fair
Value

  Maturity
<1 year

  Maturity
1 to 3
years

  Maturity
4 to 5
years

  Maturity
>5 years

Prices actively quoted   $ (49 ) $ (58 ) $ 9   $   $
   
 
 
 
 

Energy Trading Derivative Financial Instruments

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

        The fair value of the commodity financial instruments related to energy trading activities as of September 30, 2004 and December 31, 2003, are set forth below (in millions):

 
  September 30, 2004
  December 31, 2003
 
  Assets
  Liabilities
  Assets
  Liabilities
Electricity   $ 98   $ 6   $ 104   $ 11
Other                 1
   
 
 
 
Total   $ 98   $ 6   $ 104   $ 12
   
 
 
 

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        The change in the fair value of trading contracts for the nine months ended September 30, 2004, was as follows (in millions):

Fair value of trading contracts at January 1, 2004   $ 92  
Net gains from energy trading activities     11  
Amount realized from energy trading activities     (11 )
   
 
Fair value of trading contracts at September 30, 2004   $ 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 September 30, 2004) (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     91     (2 )   7     5     81
   
 
 
 
 
Total   $ 92   $ (1 ) $ 7   $ 5   $ 81
   
 
 
 
 

Regulatory Matters

        For a discussion of EME's regulatory matters, refer to "Regulatory Matters" on page 24 of MEHC's annual report on Form 10-K for the year ended December 31, 2003. There have been no other significant developments with respect to regulatory matters specifically affecting EME since the filing of MEHC's annual report, except as follows:

        Commonwealth Edison's application to join PJM was approved by the FERC on April 27, 2004, with an effective date of May 1, 2004. EME had protested such action before the FERC because the integration of Commonwealth Edison into PJM in advance of American Electric Power (AEP) created an isolated market within PJM limited to the service territory of Commonwealth Edison. The integration of AEP into PJM had been delayed by the actions of state regulatory authorities in Virginia and Kentucky. However, the issues raised in the Kentucky proceedings were resolved in June 2004 and the Virginia case was settled in August 2004, which permitted the integration of AEP to take place without incident on October 1, 2004.

        On March 19, 2004, in a separate but related matter, the FERC issued an order having the effect of postponing to December 1, 2004 the effective date for elimination of regional through and out rates in the region encompassed by PJM (as expanded by the addition of Commonwealth Edison and AEP) and the Midwest Independent System Operator (MISO). The effect of this order was that the so-called rate pancaking was not eliminated prior to the integration of Commonwealth Edison and AEP into PJM. 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 FERC included in its order a strong statement that the existing through and out rates must be eliminated no later than December 1, 2004.

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        The transmission owners and other stakeholder interests in the region met on several occasions from June through early September 2004, attempting to reach consensus on an acceptable long-term rate structure for the combined PJM/MISO footprint. A consensus among all affected parties could not be reached; however, two competing proposals for a long-term rate structure have emerged from such discussions and both were filed with the FERC on October 1, 2004. Neither of those plans would impose transmission costs on system users other than load-serving entities. However, the FERC has also initiated an investigation under Section 206 of the Federal Power Act, which would permit the agency to adopt a structure different from those which have been proposed by the parties. In its order initiating the investigation, the FERC reiterated its previous statement that it would act on such a structure by December 1, 2004. Until through and out rates are eliminated, EME will continue to have to pay transmission charges for power sold for delivery to customers within the MISO. In addition, sales to customers outside of the MISO and PJM will continue to be subject to the through and out rates applicable to such transactions.

        On July 27, 2004, AEP reached a settlement with staff of the Virginia State Corporation Commission that allowed AEP to transfer control of its transmission lines in the state to PJM. The settlement eliminated the need for the FERC to act to ensure that AEP was able to enter PJM on October 1, 2004, the target date set by both AEP and PJM. Such integration took place on October 1, 2004, as previously noted.

        Given the removal of the uncertainties regarding the market structure issues discussed previously, the direct impact on Midwest Generation of the above-described matters will be limited to the delay in the elimination of regional through and out rates. This is not expected to have a material effect on Midwest Generation's financial results prior to the anticipated elimination of such rates between PJM and the MISO on December 1, 2004.


ITEM 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

        For a discussion of market risk sensitive instruments, refer to "Market Risk Exposures" on page 106 of MEHC's annual report on Form 10-K for the year ended December 31, 2003. Refer to "Market Risk Exposures" in Item 2 for an update to that disclosure.


ITEM 4. CONTROLS AND PROCEDURES

Disclosure Controls and Procedures

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

Internal Control Over Financial Reporting

        There were no changes in MEHC's internal control over financial reporting (as such term is defined in Rules 13a-15(f) or 15d-15(f) under the Exchange Act) during the fiscal quarter to which this report relates that have materially affected, or are reasonably likely to materially affect, MEHC's internal control over financial reporting.

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PART II—OTHER INFORMATION

ITEM 6. EXHIBITS

Exhibit No.

  Description

2.1   Purchase Agreement, dated July 29, 2004, by and among Edison Mission Energy, IPM Eagle LLP, International Power plc, Mitsui & Co., Ltd. and the other sellers on the signature page hereto, incorporated by reference to Exhibit 2.1 to Edison Mission Energy's Form 10-Q for the quarter ended September 30, 2004.

31.1

 

Certification of the Chief Executive Officer pursuant to Section 302 of the Sarbanes-Oxley Act.

31.2

 

Certification of the Chief Financial Officer pursuant to Section 302 of the Sarbanes-Oxley Act.

32

 

Statement Pursuant to 18 U.S.C. Section 1350.

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SIGNATURES

        Pursuant to the requirements 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 and
Chief Financial Officer

 

 

Date:

November 8, 2004

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QuickLinks

TABLE OF CONTENTS
MISSION ENERGY HOLDING COMPANY AND SUBSIDIARIES CONSOLIDATED STATEMENTS OF OPERATIONS (In thousands, Unaudited)
MISSION ENERGY HOLDING COMPANY AND SUBSIDIARIES CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (LOSS) (In thousands, Unaudited)
MISSION ENERGY HOLDING COMPANY AND SUBSIDIARIES CONSOLIDATED BALANCE SHEETS (In thousands, Unaudited)
MISSION ENERGY HOLDING COMPANY AND SUBSIDIARIES CONSOLIDATED BALANCE SHEETS (In thousands, Unaudited)
MISSION ENERGY HOLDING COMPANY AND SUBSIDIARIES CONSOLIDATED STATEMENTS OF CASH FLOWS (In thousands, Unaudited)
MISSION ENERGY HOLDING COMPANY AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS SEPTEMBER 30, 2004 (Dollars in millions, Unaudited)
PART II—OTHER INFORMATION
SIGNATURES