MISSION ENERGY HOLDING CO - 10-Q Quarterly Report

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

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 August 13, 2003: 1,000 shares (all shares held by an affiliate of the registrant).

		Page
PART I—Financial Information
Item 1.	Financial Statements	1
Item 2.	Management's Discussion and Analysis of Financial Condition and Results of Operations	22
Item 3.	Quantitative and Qualitative Disclosures about Market Risk	72
Item 4.	Controls and Procedures	72
PART II—Other Information
Item 1.	Legal Proceedings	73
Item 6.	Exhibits and Reports on Form 8-K	73
	Signatures	74

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

MISSION ENERGY HOLDING COMPANY AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

JUNE 30, 2003

(Dollars in millions, Unaudited)

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 six months ended June 30, 2003 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, 2002 and 2001, included in MEHC's annual report on Form 10-K for the year ended December 31, 2002. MEHC follows the same accounting policies for interim reporting purposes. 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, 2002. Certain prior period amounts have been reclassified to conform to the current period financial statement presentation. These reclassifications had no effect on net income or shareholder's equity.

A number of significant developments during late 2001 and 2002 adversely affected independent power producers and subsidiaries of major integrated energy companies that sell a sizable portion of their generation into the wholesale energy market (sometimes referred to as merchant generators), including several of EME's subsidiaries. These developments included lower prices and greater volatility in wholesale energy markets both in the United States and United Kingdom, significant declines in the credit ratings of most major market participants, decreased availability of debt financing or refinancing, and a resulting decline of liquidity in the energy markets due to growing concern about the ability of counterparties to perform their obligations. Since the beginning of 2003, several merchant generators reached agreements to extend existing bank credit facilities and at least three merchant generators have filed for Chapter 11 protection under the Bankruptcy Code.

EME's largest subsidiary, Edison Mission Midwest Holdings, has $911 million of debt maturing on December 11, 2003 which will need to be repaid, extended or refinanced. Edison Mission Midwest Holdings is not expected to have sufficient cash to repay the $911 million debt due on December 11, 2003. EME has $275 million of debt maturing on September 16, 2003, which will also need to be repaid, extended or refinanced. During the second quarter, EME and Edison Mission Midwest Holdings commenced discussions with their lenders regarding restructuring their respective indebtedness. There is no assurance that either EME or Edison Mission Midwest Holdings will be able to extend or refinance their respective debt obligations on similar terms and rates as the existing debt, on commercially reasonable terms, on the terms permitted under the financing documents entered into in July 2001 by EME's parent company, MEHC, or at all. A failure to repay, extend, or refinance the Edison Mission Midwest Holdings or EME obligations is likely to result in, or in the case of EME would result in, a default under the MEHC senior secured notes and term loan. These events could make it necessary for MEHC or EME, or both, to file a petition for reorganization under Chapter 11 of the United States Bankruptcy Code. MEHC's independent accountants' audit opinion for the year ended December 31, 2002 contains an explanatory paragraph that indicates the consolidated financial statements have been prepared on the basis that MEHC will continue as a going concern and that the

uncertainty about Edison Mission Midwest Holdings' ability to repay, extend or refinance this obligation raises substantial doubt about MEHC's ability to continue as a going concern. Accordingly, the consolidated financial statements do not include any adjustments that might result from the resolution of this uncertainty.

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

In July 2003, EME agreed to sell its 50% interest in the Gordonsville project to a third party. Completion of the sale, currently expected during the fourth quarter of 2003, is subject to closing conditions, including obtaining regulatory approval. Net proceeds from the sale, including distribution of a debt service reserve fund, are expected to be approximately $32 million. EME recorded an impairment charge of $6 million during the second quarter of 2003 related to the planned disposition of this investment.

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

During the second quarter of 2003, EME recorded an asset impairment charge of $245 million ($150 million after tax) related to eight small peaking plants owned by its indirect subsidiary, Midwest Generation, LLC (Midwest Generation), in Illinois. The impairment charge resulted from a revised long-term outlook for capacity revenues from the peaking plants. The lower capacity revenue outlook is the result of a number of factors, including higher long-term natural gas prices and the current generation overcapacity in the MAIN region market. The book value of these assets was written down from $286 million to an estimated fair market value of $41 million. The estimated fair market value was determined based on discounting estimated future cash flows using a 17.5% discount rate.

Effective January 1, 2002, EME adopted Statement of Financial Accounting Standards No. 142, "Goodwill and Other Intangible Assets." SFAS No. 142 establishes accounting and reporting standards requiring goodwill not to be amortized but rather tested for impairment at least annually at the reporting unit level. EME will perform its annual evaluation of goodwill on October 1, 2003, or sooner if indicators of impairment exist. During the third quarter of 2002, EME concluded that fair value of the goodwill related to the Citizens Power LLC acquisition was impaired by $14 million, net of $9 million of income tax benefit and, accordingly, reported this amount as a cumulative change in accounting. In accordance with SFAS No. 3, "Reporting Accounting Changes in Interim Financial Statements," EME's financial statements for the first quarter of 2002 were restated to reflect the accounting change as of January 1, 2002.

Included in "Restricted cash and other assets" on EME's consolidated balance sheet are customer contracts with a gross carrying amount of $92 million and accumulated amortization of $8 million at June 30, 2003. The contracts have a weighted average amortization period of 20 years. For the three and six months ended June 30, 2003, the amortization expense was $1 million and $2 million, respectively. Based on the current amount of intangible assets subject to amortization, the estimated amortization expense for fiscal years 2004 through 2008 is approximately $5 million each year. Intangible assets classified in "Restricted cash and other assets" of $1 million at June 30, 2003 consists of an additional minimum pension liability at EME's subsidiary, Midwest Generation.

Changes in the carrying amount of goodwill, by geographical segment, for the six months ended June 30, 2003 are as follows:

Inventory is stated at the lower of weighted average cost or market. Inventory at June 30, 2003 and December 31, 2002 consisted of the following:

The amount of commodity hedges included in unrealized gains (losses) on cash flow hedges, net of tax, at June 30, 2003, was a loss of $42 million. The amount of interest rate hedges included in unrealized gains (losses) on cash flow hedges, net of tax, at June 30, 2003, was a loss of $150 million. The amount of foreign currency hedges included in unrealized gains (losses) on cash flow hedges, net of tax, at June 30, 2003, was a gain of $10 million.

Unrealized losses on commodity hedges included those related to the hedge agreement with the State Electricity Commission of Victoria for electricity prices from the Loy Yang B project in Australia. This contract does not qualify under the normal sales and purchases exception because financial

settlement of the contract occurs without physical delivery. These losses arise because current forecasts of future electricity prices in these markets are greater than contract prices. Unrealized losses on interest rate hedges included those related to EME's share of interest rate swaps of its unconsolidated affiliates, Contact Energy and the Loy Yang B project. Unrealized gains on foreign currency hedges included those related to Contact Energy's cross currency interest rate swaps.

As EME's hedged positions are realized, approximately $40 million, after tax, of the net unrealized gains on cash flow hedges at June 30, 2003 are expected to be reclassified into earnings during the next 12 months. Management expects that when the hedged items are recognized in earnings, the net unrealized gains associated with them will be offset. The maximum period over which EME has designated a cash flow hedge, excluding those forecasted transactions related to the payment of variable interest on existing financial instruments, is 13 years. Actual amounts ultimately reclassified into earnings over the next 12 months could vary materially from this estimated amount as a result of changes in market conditions.

Interest rate swaps entered into to hedge the floating interest rate risk on the $385 million term loan due 2006 qualify for treatment under SFAS No. 133 as cash flow hedges with appropriate adjustments made to other comprehensive income. At June 30, 2003 and December 31, 2002, MEHC recorded unrealized holding losses on these contracts totaling approximately $5 million, after tax. During the quarter and six months ended June 30, 2003, MEHC recorded a $181 thousand, after tax, increase and a $143 thousand, after tax, decrease, respectively, to other comprehensive income resulting from unrealized gains (losses) on these contracts. During the quarter and six months ended June 30, 2002, MEHC recorded an $890 thousand, after tax, and a $579 thousand, after tax, decrease, respectively, to other comprehensive income resulting from unrealized losses on these contracts.

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

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

On May 14, 2003, a third party completed the purchase of the Lakeland power plant from the administrative receiver for £24 million. The proceeds from the sale and existing cash were used to fund partial repayment of the outstanding debt owed to secured creditors of the project.

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. The consolidated financial statements have been restated to conform to discontinued operations treatment for all historical periods presented.

	Three Months Ended June 30,					Six Months Ended June 30,
	2003			2002		2003			2002
Total operating revenues	$	—		$	17	$	—		$	38
Income (loss) before income taxes		(1	)		9		(1	)		14
Income (loss) from operations of discontinued foreign subsidiaries	$	(2	)	$	9	$	(2	)	$	15

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

		June 30, 2003		December 31, 2002
Accounts receivable—trade, net of allowance of $2 million in 2003 and 2002		$	2	$	1
Other current assets			2		3

	Total current assets		4		4

Other long-term assets			1		6

Assets of discontinued operations		$	5	$	10

Accounts payable and accrued liabilities		$	4	$	3

	Total current liabilities		4		3

Liabilities of discontinued operations		$	4	$	3

The following table summarizes EME's consolidated commercial commitments as of June 30, 2003. Details regarding these commercial commitments are discussed in the sections following the table.

Projects		U.S. Currency
CBK(i)		$	19
Sunrise (ii)		$	4

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

Midwest Generation has entered into additional fuel purchase agreements with several third-party suppliers during the first six months of 2003. Midwest Generation's aggregate fuel purchase commitments under these agreements are currently estimated to be $39 million for 2003, $105 million for 2004 and $107 million for 2005.

term of 15 years, is currently estimated to be $4 million for the second half of 2003; $8 million for 2004; $8 million for 2005; $8 million for 2006; and $8 million for 2007.

Sunrise Power Company, in which EME's wholly owned subsidiary owns a 50% interest, sells all its output to the California Department of Water Resources under an eleven-year power purchase agreement entered into on June 25, 2001 and restructured on December 31, 2002. In January 2003, the California Public Utilities Commission and the California Electricity Oversight Board dismissed the complaints they had filed with the Federal Energy Regulatory Commission, or the FERC, against Sunrise Power Company, alleging that the contract was "unjust and unreasonable."

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

On May 15, 2002, Sunrise Power Company was served with a complaint filed in the Superior Court of the State of California, City and County of San Francisco, by James M. Millar, "individually, and on behalf of the general public and as a representative taxpayer suit" against sellers of long-term power to the California Department of Water Resources, including Sunrise Power Company. The lawsuit alleges that the defendants, including Sunrise Power Company, engaged in unfair and fraudulent business practices by knowingly taking advantage of a manipulated power market to obtain unfair contract terms. The lawsuit seeks to enjoin enforcement of the "unfair and oppressive terms and conditions" in the contracts, as well as restitution by the defendants of excessive monies obtained by the defendants. Plaintiffs in several other class action lawsuits pending in Northern California have filed petitions seeking to have the Millar lawsuit consolidated with those lawsuits. The defendants in the Millar lawsuit and other class action suits removed all the lawsuits to the U.S. District Court, Northern District of California, and filed a motion to stay all proceedings pending final resolution of the jurisdictional issue. Various plaintiffs filed pleadings opposing the removal and requesting that the matters be remanded to state court. On July 7, 2003, the lawsuit was remanded to state court. EME believes that the outcome of this litigation will not have a material adverse effect on its consolidated financial position or results of operations.

On August 4, 2002, a new Electricity Market License Regulation was implemented in Turkey. The new regulation contains, among other things, a requirement for each generator to obtain a generation license. Historically, Doga's Implementation Contract has been its sole license. The new regulation contemplates an initial fixed license fee and a yearly license fee based on the amount of energy generated, which will increase the project's costs of operation by an undetermined amount. In addition, the 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. If actions or inactions undertaken pursuant to the new regulation directly or indirectly impede, hinder, prevent or delay the operation of the Doga facility or increase Doga's cost of

performing its obligations under its project documents, this may constitute a "risk event" under Doga's Implementation Contract. A risk event may permit Doga to request an increase in its tariff or, under certain circumstances, request a buyout of the project by the Ministry of Energy and Natural Resources.

On October 3, 2002, Doga (and several other power producers in Turkey acting independently) filed a lawsuit in the Danistay, Turkey's high administrative court, against the Energy Market Regulatory Authority seeking both an injunction and permanent invalidation of certain provisions of the new regulation on the grounds of the illegality and unconstitutionality of any new license requirement that does not take into account the vested rights of a company operating pursuant to previously agreed terms of the Implementation Contract.

On May 12, 2003, the Danistay rejected Doga's request for injunctive relief (as well as those of the other power companies with similar claims). On July 10, 2003, Doga appealed the Danistay's ruling. Doga anticipates the appeal will be heard by the General Council of the Administrative Chambers of Danistay during the fourth quarter of 2003.

If the Council grants Doga's request for an injunction, the Energy Market Regulatory Authority will have to suspend the implementation of the new Electricity Market License Regulation process until a final decision is rendered by the Court. If the Council rejects Doga's request for an injunction, there will be no further rights of appeal against the decision regarding the injunction, and the licensing process (and Doga's lawsuit) will continue.

A subsidiary of EME, Edison Mission Marketing and Trading (referred to as EMMT) and NRG Power Marketing, Inc. (referred to as NRG Power Marketing) are parties to a contract pursuant to which NRG Power Marketing sells 217,000 MWhr annually of electricity to EMMT. EMMT then resells this electricity to an unconsolidated 25%-owned affiliate, CL Power Sales Eight, L.L.C. (referred to as CL Eight). On May 14, 2003, NRG Power Marketing filed for protection under Chapter 11 of the Bankruptcy Code. On August 7, 2003, NRG Power Marketing was successful in having the contract with EMMT rejected by the Bankruptcy Court in the Southern District of New York. EMMT had sought an order lifting from the automatic stay so that EMMT could bring a proceeding at the FERC to seek an order directing NRG Power Marketing to continue performing under the contract with EMMT; the Bankruptcy Court denied this motion. As a result, EMMT is still obligated to provide electricity to CL Eight, but without the supply from NRG Power Marketing. EMMT has entered into purchase agreements for a portion of the volumes due under the supply contract. Current market prices exceed the price which CL Eight is required to pay to EMMT for the electricity delivered. To the extent EMMT suffers losses as a result of being required to resell such electricity for less than it paid to purchase it, EMMT and EME are indemnified by Peabody Energy Corporation pursuant to the 2000 Purchase and Sale Agreement for the acquisition of Citizens Power LLC.

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.

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

In connection with the sale-leaseback transactions that EME has entered into related to the Collins Station, Powerton and Joliet plants in Illinois and the Homer City facilities in Pennsylvania, EME or one of its subsidiaries has entered into tax indemnity agreements. Under these tax indemnity agreements, EME agreed to indemnify the lessors in the sale-leaseback transactions for specified adverse tax consequences that could result in certain situations set forth in each tax indemnity agreement, including specified defaults under the respective leases. The potential indemnity obligations under these tax indemnity agreements could be significant. Due to the nature of these obligations under these tax indemnity agreements, EME cannot determine a maximum potential liability. The indemnities would be triggered by a valid claim from the lessors. EME has not recorded a liability related to these indemnities.

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

Midwest Generation entered into a supplemental agreement with Commonwealth Edison on February 20, 2003 to resolve a dispute regarding interpretation of its reimbursement obligation for asbestos claims under the environmental indemnities set forth in the Asset Sale Agreement. Under this supplemental agreement, Midwest Generation agreed to reimburse Commonwealth Edison 50% of specific existing asbestos claims less recovery of insurance costs, and agreed to a sharing arrangement for liabilities associated with future asbestos related claims as specified in the agreement. The obligations under this agreement are not subject to a maximum liability. The supplemental agreement has a five-year term with an automatic renewal provision (subject to the right to terminate). Payments are made under this indemnity by a valid claim provided from Commonwealth Edison. At June 30, 2003, Midwest Generation had $5 million recorded as a liability related to known claims provided by Commonwealth Edison.

In connection with the acquisition of the Homer City facilities, EME Homer City Generation L.P. (EME Homer City) agreed to indemnify the sellers against damages, claims and losses arising from environmental liabilities before and after the date of sale as specified in the Asset Purchase Agreement dated August 1, 1998. EME guaranteed the obligations of EME Homer City. Due to the nature of the obligation under this indemnity provision, it is not subject to a maximum potential liability 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.

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

Brooklyn Navy Yard is a 286 MW gas-fired cogeneration power plant in Brooklyn, New York. EME's wholly owned subsidiary owns 50% of the project. In February 1997, the construction contractor asserted general monetary claims under the turnkey agreement against Brooklyn Navy Yard Cogeneration Partners, L.P. A settlement agreement was executed on January 17, 2003, and all litigation has been dismissed. EME agreed to indemnify Brooklyn Navy Yard Cogeneration Partners, L.P. for any payments due under this settlement agreement, which are scheduled through 2006. At June 30, 2003, EME recorded a liability of $13 million related to this indemnity.

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

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 June 30, 2003, if payment were required, would be $196 million. EME has no reason to believe that any of these projects will either cease operations or reduce its electric power producing capability during the term of its power contract.

EME agreed to indemnify its lenders under its credit facilities from amounts drawn on a $42 million letter of credit issued for the benefit of the lenders to ISAB Energy, a 49% unconsolidated affiliate, in lieu of ISAB Energy funding a debt service reserve account using additional equity contributions. Accordingly, a default under ISAB Energy's project debt could result in a draw under the letter of credit which, in turn, would result in a borrowing under EME's credit facilities. The letter of credit is renewed each six-month period or until ISAB Energy funds the debt service account. The indemnification is subject to the maximum amount drawn under the letter of credit. EME has not recorded a liability related to this indemnity.

A subsidiary of EME agreed to indemnify Central Maine Power Company against decreases in the value of power deliveries by CL Power Sales Eight, L.L.C., an unconsolidated affiliate, to Central Maine Power as a result of the implementation of a location-based pricing system in the New England Power Pool. The indemnity has the same term as a power supply agreement between Central Maine Power and CL Eight, which runs through December 2016. It is not possible to determine potential differences in values between the various points of delivery in New England Power Pool at this time. Due to the nature of this indemnity, a maximum potential liability cannot be determined. To the extent EME's subsidiary would be required to make a payment under this indemnity, it and EME are indemnified by Peabody Energy Corporation pursuant to the 2000 Purchase and Sale Agreement for the acquisition of Citizens Power LLC. EME's subsidiary has not recorded a liability related to this indemnity.

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

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

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

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

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, CPC Cogeneration LLC, Four Star Oil & Gas Company, Midway-Sunset Cogeneration Company, March Point Cogeneration Company, EcoEléctrica Holdings, Ltd. and Subsidiaries, Gordonsville Energy, L.P., Brooklyn Navy Yard Cogeneration Partners, L.P., PT Paiton Energy, ISAB Energy S.r.l. and CBK Power Co. Ltd. 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.

		Six Months Ended June 30,
		2003			2002
Cash paid
	Interest (net of amount capitalized)	$	292		$	284
	Income taxes (receipts)	$	(85	)	$	(226	)
	Cash payments under plant operating leases	$	197		$	191
Details of assets acquired
	Fair value of assets acquired	$	333		$	—
	Liabilities assumed		58			—

	Net cash paid for acquisitions	$	275		$	—

Edison International has three stock-based employee compensation plans, which are described more fully in Note 15—Stock Compensation Plans included in MEHC's annual report on Form 10-K for the year ended December 31, 2002. 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 (loss) if EME had used the fair value accounting method.

	Three Months Ended June 30,		Six Months Ended June 30,
	2003		2002		2003		2002
Net loss, as reported	$	(191	)	$	(21	)	$	(232	)	$	(93	)
Add: stock-based compensation expense included in reported net loss, net of related tax effects		—			2			1			2
Deduct: Total stock-based employee compensation expense determined under fair value based method for all awards, net of related tax effects		—			(1	)		(1	)		(1	)

Pro forma net loss	$	(191	)	$	(20	)	$	(232	)	$	(92	)

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 adoption of SFAS No. 143.

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

Initial asset retirement obligation as of January 1, 2003	$	17
Accretion expense		1
Translation adjustments		1

Balance of asset retirement obligation as of June 30, 2003	$	19

Had SFAS No. 143 been applied retroactively in the six months ended June 30, 2002, it would not have had a material effect upon EME's results of operations. The pro forma liability for asset retirement obligation is not shown due to the immaterial impact on EME's consolidated balance sheet.

Statement of Financial Accounting Standards Interpretation No. 45. In November 2002, the Financial Accounting Standards Board issued Statement of Financial Accounting Standards Interpretation No. 45, "Guarantor's Accounting and Disclosure Requirements for Guarantees, Including Indirect Guarantees of Indebtedness of Others." This interpretation establishes reporting requirements to be made by a guarantor about its obligations under certain guarantees that it has issued. It also clarifies that a guarantor is required to recognize, at the inception of a guarantee, a liability for the fair value of the obligation undertaken in issuing the guarantee. The initial recognition and initial measurement provisions of this interpretation are applicable on a prospective basis to guarantees issued or modified after December 31, 2002. The adoption of this standard had no impact on EME's financial statements. See disclosure regarding guarantees and indemnities in Note 8—Commitments and Contingencies.

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

Under FIN 46, an enterprise that will (1) absorb a majority of a variable interest entity's expected losses (if they occur), (2) receive a majority of a variable interest entity's expected residual returns (if they occur), or (3) both of the above, must consolidate the variable interest entity. The enterprise that consolidates the variable interest entity is called the primary beneficiary. EME believes it is reasonably possible that one or more of its investments in unconsolidated affiliates will be a variable interest entity. Accordingly, EME is in the process of making this determination, and for investments in unconsolidated affiliates which are variable interest entities, a further determination will be made if EME is the primary beneficiary.

EME has concluded that it is the primary beneficiary of Brooklyn Navy Yard Cogeneration Partners L.P. since it is at risk with respect to a majority of its losses and is entitled to receive a majority of its residual returns. Accordingly, EME will consolidate Brooklyn Navy Yard Cogeneration Partners L.P. effective July 1, 2003. In accordance with the transition provisions of FIN 46, the consolidation of Brooklyn Navy Yard Cogeneration Partners L.P. will be based on the historical cost of the assets, liabilities and non-controlling interest which would have been carried by EME effective when EME became the primary beneficiary. This means that EME will consolidate the assets and liabilities of Brooklyn Navy Yard Cogeneration Partners L.P. using the June 30, 2003 balance sheet and eliminate intercompany balances. EME expects the consolidation of this entity to increase total assets by approximately $362 million and total liabilities by approximately $434 million. Furthermore, EME expects to record a loss of approximately $72 million in the third quarter of 2003 as a cumulative change of accounting as a result of consolidating this variable interest entity. This loss is primarily due to cumulative losses allocated to the other 50% partner in excess of equity contributions recorded.

Statement of Financial Accounting Standards No. 149. In April 2003, the Financial Accounting Standards Board issued Statement of Financial Accounting Standards No. 149, "Amendment of Statement 133 on Derivative Instruments and Hedging Activities." This statement amends and clarifies financial accounting and reporting for derivative instruments and for hedging activities under SFAS No. 133. The amendment reflects decisions made by the FASB and the Derivatives Implementation Group (DIG) process in connection with issues raised about the application of SFAS No. 133. Generally, the provisions of SFAS No. 149 will be applied prospectively for contracts entered into or modified after June 30, 2003 and for hedging relationships designated after June 30, 2003. SFAS No. 149 provisions that resulted from the DIG process that became effective in fiscal quarters beginning before June 15, 2003 will continue to be applied based upon their original effective dates. EME does not expect that this standard will have a material impact on its consolidated financial statements.

Other Statement of Financial Accounting Standards No. 133 Guidance. In June 2003, the Derivative Implementation Group of the Financial Accounting Standards Board under Statement No. 133 Implementation Issue Number C20 issued clarifying guidance related to permitted pricing adjustments in a contract qualifying under the normal purchases and normal sales exception under SFAS No. 133. This implementation guidance becomes effective on October 1, 2003. EME is currently re-evaluating

which contracts, if any, that have previously been designated as normal purchases or normal sales would now not qualify for this exception.

Statement of Financial Accounting Standards No. 150. In May 2003, the Financial Accounting Standards Board issued Statement of Financial Accounting Standards No. 150, "Accounting for Certain Financial Instruments with Characteristics of both Liabilities and Equity." This statement establishes standards for how to classify and measure certain financial instruments with characteristics of both liabilities and equity. It requires that an issuer classify a financial instrument that is within its scope as a liability or asset, as appropriate. SFAS No. 150 is effective for all freestanding financial instruments entered into or modified after May 31, 2003; otherwise, it will become effective at the beginning of the first interim period beginning after June 15, 2003. Effective July 1, 2003, EME's company-obligated mandatorily redeemable securities and redeemable preferred stock will be presented separately as long-term liabilities on its consolidated balance sheets. These items are currently classified between equity and liabilities. In addition, dividend payments on these instruments will be recorded as interest expense on EME's consolidated statements of income. EME does not expect that this standard will have a material impact on its consolidated financial statements.

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

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

The following discussion contains forward-looking statements. These statements are based on Mission Energy Holding Company's (MEHC's) knowledge of present facts, current expectations about future events and assumptions about future developments. Forward-looking statements are not guarantees of performance; they are subject to risks, uncertainties and assumptions that could cause actual future activities and results of operations to be materially different from those set forth in this discussion. Important factors that could cause differences in MEHC's results of operations are set forth under "—Market Risk Exposures" below, and under "—Risk Factors" in the Management's Discussion and Analysis of Results of Operations and Financial Condition included in Item 7 of MEHC's annual report on Form 10-K for the year ended December 31, 2002.

The Management's Discussion and Analysis of Financial Condition and Results of Operations of this Form 10-Q discusses material changes in the results of operations, financial condition and other developments of MEHC since December 31, 2002, and as compared to the second quarter and six months ended June 30, 2002. This discussion presumes that the reader has read or has access to Management's Discussion and Analysis of Results of Operations and Financial Condition included in Item 7 of MEHC's annual report on Form 10-K for the year ended December 31, 2002.

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

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

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

EME is an independent power producer engaged in the business of owning or leasing and operating electric power generation facilities worldwide. EME also conducts price risk management and energy trading activities in power markets open to competition. Edison International, EME's ultimate

parent company, also owns Southern California Edison Company, one of the largest electric utilities in the United States.

As of June 30, 2003, EME owned or leased interests in 27 domestic and 55 international operating power plants with an aggregate generating capacity of 24,079 megawatts (MW), of which EME's share was 18,928 MW. At that date, one international power plant, totaling 355 MW of generating capacity, of which EME's anticipated share will be approximately 178 MW, was under construction.

MEHC's (parent company's) loss from continuing operations for the second quarter and six months ended June 30, 2003 was $24 million and $48 million, respectively, compared to $23 million and $46 million for the second quarter and six months ended June 30, 2002, respectively. The 2003 increases in loss from continuing operations were primarily due to lower interest income and higher consulting fees in 2003.

EME's loss from continuing operations for the second quarter and six months ended June 30, 2003 was $165 million and $173 million, respectively, compared to $6 million and $47 million for the second quarter and six months ended June 30, 2002, respectively. The second quarter increase in loss from continuing operations was primarily due to an asset impairment charge of $150 million, lower generation from the coal plants in Illinois, lower earnings from EME's First Hydro plant and higher interest and rent expense at the Collins Station. The increase in loss was partially offset by higher U.S. energy prices and higher earnings from EME's oil and gas activities.

The $150 million after-tax impairment charge resulted from a revised long-term outlook for capacity revenues from eight small peaking plants in Illinois. The lower capacity revenue outlook is the result of a number of factors, including higher long-term natural gas prices and the current generation overcapacity in the MAIN region market. Since capacity value represents a key revenue component for these small peaking plants, the revised outlook resulted in a write-down of the book value of these assets to their estimated fair market value. See "Liquidity and Capital Resources—Discussion of Recourse Debt to Recourse Capital Ratio."

The 2003 year-to-date increase in loss from continuing operations was primarily due to the asset impairment charge of $150 million described above, reduction in revenue from EME's Illinois Plants, lower earnings from EME's First Hydro plant and higher interest and rent expense at the Collins Station. Partially offsetting these items were higher PJM power prices and higher generation by EME's Homer City facilities, higher west coast energy prices and higher earnings from oil and gas activities.

Operating revenues increased 6% and 16% for the second quarter and six months ended June 30, 2003, respectively, compared to the corresponding periods of 2002. The 2003 increases were primarily due to increased electric revenues from the Homer City facilities due to increased generation and

higher energy prices and increased electric revenues from Contact Energy primarily due to higher wholesale electricity prices, higher generation and an increase in the value of the New Zealand dollar compared to the U.S. dollar. Partially offsetting the 2003 increases was lower capacity revenue from the Illinois Plants.

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

Net gains and (losses) from price risk management activities result from recording derivatives at fair value under Statement of Financial Accounting Standards No. 133, "Accounting for Derivative Instruments and Hedging Activities" (SFAS No. 133). Included in net gains (losses) from price risk management were:

Under SFAS No. 133, the portion of a cash flow hedge that does not offset the change in value of the transaction being hedged, which is commonly referred to as the ineffective portion, is immediately recognized in earnings. EME recorded a net gain of approximately $10 million and $1 million during the second quarters of 2003 and 2002, respectively, and approximately $2 million and $(189) thousand during the six months ended June 30, 2003 and 2002, respectively, representing the amount of cash flow hedges' ineffectiveness. The net gain during the second quarter of 2003 from Homer City primarily resulted from forward contracts that expired during the quarter. The net loss during the six months ended June 30, 2003 from Homer City was attributable to increases in the difference between energy prices at PJM West Hub (where EME's subsidiary enters into forward contracts) and the energy prices at the delivery point where power generated by the Homer City facilities is delivered into the transmission system (referred to as the Homer City busbar). The net gain related to the Illinois Plants resulted from similar differences in energy prices between "Into ComEd" and delivery points outside "Into ComEd." These prices are used to fair value forward contracts that qualify as cash flow hedges.

EME records the ineffective portion of the change in the fair value of these contracts through the income statement. See "—Market Risk Exposures—Americas" for more information regarding forward market prices.

The 2003 net gains from energy trading activities were primarily the result of net gains from transmission congestion contracts and other power contracts in markets where EME has power plants. The 2002 net gains from energy trading activities primarily represent the completion of the restructuring of a power sales agreement with an unaffiliated electric utility. As part of the transaction, an EME subsidiary purchased the power sales agreement held by a third party, modified its terms and conditions, and entered into a long-term power supply agreement with another party. Although the sale and purchase of power arising from these contracts will occur over their term, net gains of $2 million and $19 million were recorded during the second quarter and six months ended June 30, 2002, respectively, attributable to the fair value of the contracts (generally referred to as mark-to-market accounting).

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

Fuel costs increased 6% and 20% for the second quarter and six months ended June 30, 2003, respectively, compared to the corresponding periods of 2002. The second quarter increase was primarily due to increased generation from the Homer City facilities partially offset by lower generation from the coal plants in Illinois. The 2003 year-to-date increase was primarily due to increased generation from the Homer City facilities. The 2003 increases in Homer City generation were primarily the result of outages experienced during the first two quarters of 2002.

Plant operations and transmission costs increased $39 million and $58 million for the second quarter and six months ended June 30, 2003, respectively, compared to the corresponding periods of 2002. Transmission costs were $63 million and $43 million for the second quarters of 2003 and 2002, respectively, and $118 million and $79 million for the six months ended June 30, 2003 and 2002, respectively. The 2003 increases in transmission costs were primarily due to higher retail sales generated by Contact Energy.

Depreciation and amortization expense increased $11 million and $26 million for the second quarter and six months ended June 30, 2003, respectively, compared to the corresponding periods of 2002. The 2003 increases were primarily due to higher amortization expense of customer contracts resulting from the adoption of SFAS No. 142 at Contact Energy. In addition, depreciation expense increased in the first six months of 2003 from the first six months of 2002, resulting from the termination of the Midwest Generation equipment lease in August 2002.

Asset impairment charges were $251 million for the second quarter and six months ended June 30, 2003. Asset impairment charges in 2003 consisted of $245 million related to the impairment of eight small peaking plants owned by EME's wholly owned subsidiary, Midwest Generation, in Illinois and $6 million related to the write-down of EME's investment in the Gordonsville project due to its planned disposition (refer to "—Dispositions" for further discussion). The impairment charge relating to the peaking plants resulted from a revised long-term outlook for capacity revenues from the peaking plants. The lower capacity revenue outlook is the result of a number of factors, including higher long-term natural gas prices and the current generation overcapacity in the MAIN region market. See "—Market Risk Exposures—Illinois Plants." The book value of these assets was written down from $286 million to an estimated fair market value of $41 million. The estimated fair market value was

determined based on discounting estimated future cash flows using a 17.5% discount rate. No comparable amount was recorded for the first six months of 2002.

Administrative and general expenses decreased $1 million and $7 million for the second quarter and six months ended June 30, 2003, respectively, compared to the corresponding periods of 2002. The 2003 decreases were primarily due to cost reductions implemented in 2002, partially offset by higher consulting fees in 2003 related to debt restructuring activities. During the second quarter and six months ended June 30, 2002, EME severance and other related costs were approximately $279 thousand and $5 million, respectively.

Equity in income from unconsolidated affiliates increased 20% and 21% for the second quarter and six months ended June 30, 2003, respectively, compared to the corresponding periods of 2002. The 2003 increases were primarily due to an increase in EME's share of income from the Big 4 projects, Four Star Oil & Gas and the Sunrise project. EME's third quarter equity in income from its domestic energy projects is materially higher than equity in income related to other quarters of the year due to warmer weather during the summer months and because a number of EME's domestic energy projects, located on the west coast, have power sales contracts that provide for higher payments during the summer months.

Interest and other income decreased $2 million and $7 million for the second quarter and six months ended June 30, 2003, respectively, compared to the corresponding periods of 2002. The 2003 decreases were primarily due to higher foreign exchange losses from EME's intercompany loans and lower interest income.

Interest expense increased $5 million and $9 million for the second quarter and six months ended June 30, 2003, respectively, compared to the corresponding periods of 2002. The 2003 increases were due to higher interest costs at the Illinois Plants due to a downgrade of the credit rating of Edison Mission Midwest Holdings and higher levels of borrowings at Contact Energy. See "—Liquidity and Capital Resources—Credit Ratings."

MEHC's annual effective tax rate (excluding EME's state tax reallocation benefits, the impact of a change in statutory tax rates in Turkey and income tax benefit related to EME's impairment charges) was 41% during the six months ended June 30, 2003, compared to 42% during the first six months of 2002. During the six months ended June 30, 2003, EME recorded approximately $10 million of additional state tax benefits net of federal income taxes, as a result of participation in a tax-allocation agreement with Edison International. The Turkish corporate tax rate decreased from 33% to 30%, retroactive to January 1, 2003, as a result of legislation passed in April 2003. In accordance with SFAS No. 109, "Accounting for Income Taxes," the reductions in the Turkish income tax rates resulted in an increase in income tax expense of approximately $4 million during the second quarter of 2003 due to a reduction in deferred tax assets. During the second quarter of 2003, EME recorded a tax benefit of $98 million relating to the impairment of the small peaking plants in Illinois and its Gordonsville project.

Minority interest expense decreased $1 million and $2 million for the second quarter and six months ended June 30, 2003, respectively, compared to the corresponding periods of 2002. Minority interest primarily relates to 49% ownership of Contact Energy by the public in New Zealand.

During the second quarter and six months ended June 30, 2003, EME recorded $1 million from discontinued operations related to administrative expenses incurred as part of the close-out activities. During the second quarter of 2002 and the six-month period ended June 30, 2002, EME recorded income of $6 million and $12 million, respectively, from discontinued operations primarily related to operating income from the Lakeland power plant.

During the second quarter and six months ended June 30, 2003, EME recorded losses of $1 million from discontinued operations primarily related to taxes. During the second quarter of 2002, EME recorded income of $3 million from discontinued operations primarily related to an insurance recovery from claims filed prior to the sale of the power plants.

reporting unit level. EME will perform its annual evaluation of goodwill on October 1, 2003 or sooner if indicators of impairment exist. During the third quarter of 2002, EME concluded that fair value of the goodwill related to the Citizens Power LLC acquisition was impaired by $14 million, net of $9 million of income tax benefit and, accordingly, reported this amount as a cumulative change in accounting. In accordance with SFAS No. 3, "Reporting Accounting Changes in Interim Financial Statements," EME's financial statements for the first quarter of 2002 were restated to reflect the accounting change as of January 1, 2002.

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

EME operates predominantly in one line of business, electric power generation, organized by three geographic regions: Americas, Asia Pacific, and Europe. Operating revenues are derived from EME's majority-owned domestic and international entities. Intercompany interest expense and income between EME and its consolidated subsidiaries have been eliminated in the following project results, except as described below with respect to loans provided to EME from a wholly owned subsidiary, Midwest Generation. Equity in income from unconsolidated affiliates relates to energy projects where EME's ownership interest is 50% or less in the projects. The equity method of accounting is generally used to account for the operating results of entities over which EME has a significant influence but in which it does not have a controlling interest. With respect to entities accounted for under the equity method, EME recognizes its proportional share of the income or loss of such entities.

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

Operating revenues from the Illinois Plants decreased $57 million and $11 million for the second quarter and six months ended June 30, 2003, respectively, compared to the corresponding periods of 2002. The second quarter decline was primarily due to lower capacity revenue from the reduction in megawatts contracted under the power purchase agreements as described below. Energy revenues for the second quarters of 2003 and 2002 remained relatively flat as an overall decrease in generation was offset by an increase in average realized energy prices primarily due to the shift to merchant generation. The shift to merchant generation has resulted in minimal capacity revenues but higher energy revenues due to higher average realized energy prices as compared to the power purchase agreements. The year-to-date decrease was also due to lower capacity revenue from the reduction in megawatts contracted under the power purchase agreements, offset by an increase in energy revenue due to the shift to merchant generation.

In accordance with the power purchase agreements, Exelon Generation released 4,548 MW of generating capacity during 2002 from the power purchase agreements at the Illinois Plants. Of the generating capacity released by Exelon Generation, EME's subsidiary suspended operations for 1,370 MW and decommissioned 45 MW. As a result, beginning in 2003, the Illinois Plants have had 3,133 MW available for sale as merchant generation.

Exelon Generation is obligated under the power purchase agreements to make capacity payments for the plants under contract (4,739 MW during 2003) and energy payments for electricity produced by these plants. As a result of the decline in contracted generating capacity under the power purchase agreements, revenues from Exelon Generation as a percentage of EME's consolidated operating revenues decreased from 41% for the second quarter of 2002 to 23% for the second quarter of 2003 and from 36% for the first six months of 2002 to 21% for the first six months of 2003. Revenues from Exelon Generation were $162 million and $274 million for the second quarters of 2003 and 2002, respectively. Revenues from Exelon Generation were $293 million and $436 million for the six-month periods ended June 30, 2003 and 2002, respectively. For more information on the power purchase agreements, see "—Market Risk Exposures—Illinois Plants."

Earnings from the Illinois Plants decreased $287 million and $285 million for the second quarter of 2003 and the six-month period ended June 30, 2003, respectively, compared to the corresponding periods of 2002. Included in the 2003 results was an asset impairment charge of $245 million related to small peaking plants in Illinois. See "—Consolidated Operating Results—Operating Expenses" and "—Market Risk Exposures—Illinois Plants."

In addition to the asset impairment charge related to the small peaking plants, EME's indirect subsidiary, Midwest Generation, also reported an impairment charge of $475 million, after tax, related to the 2,698 MW gas-fired Collins Station in its second quarter report on Form 10-Q. The impairment charge resulted from a write-down of the book value of the Collins Station capitalized assets from $858 million to an estimated fair market value of $78 million. The impairment charge by Midwest Generation is not reflected in the operating results of EME or MEHC because the lease related to the Collins Station is treated in the respective financial statements as an operating lease and not as an asset and, therefore, is not subject to impairment for accounting purposes. See "—Liquidity and Capital Resources—Discussion of Recourse Debt to Recourse Capital Ratio."

Earnings from the Illinois Plants decreased $42 million, excluding the impairment charge described above, for the second quarter of 2003, compared to the corresponding period of 2002, due to lower revenues as described above, partially offset by lower fuel costs related to lower generation at the Collins Station and the coal-fired units. Earnings from the Illinois Plants decreased $40 million,

excluding the impairment charge described above, for the six months ended June 30, 2003, compared to the corresponding period of 2002, due to the following factors:

The earnings of the Illinois Plants included interest income related to loans to EME of $28 million and $30 million for the second quarters of 2003 and 2002, respectively, and $56 million and $61 million for the six months ended June 30, 2003 and 2002, respectively. 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.

Gain (losses) from price risk management activities were $6 million and none for the second quarter and $4 million and $(2) million for the six months ended June 30, 2003 and 2002, respectively. The 2003 gains primarily reflect the ineffective portion of forward contracts which are derivatives that qualify as cash flow hedges under SFAS No. 133. See "—Consolidated Operating Results—Operating Revenues" for further discussion. The 2002 losses represent the change in market value of futures contracts with respect to a portion of anticipated fuel purchases that did not qualify as cash flow hedges under SFAS No. 133.

Operating revenues from Homer City increased $22 million and $85 million for the second quarter and six months ended June 30, 2003, respectively, compared to the corresponding periods of 2002. The 2003 increases are primarily due to increased generation, resulting from an unplanned outage on Unit 3 and extended outages on Units 1 and 2 during the first half of 2002, and higher energy prices. On February 10, 2002, Homer City experienced a major unplanned outage due to a collapse of the SCR ductwork of one of the units, known as Unit 3. The unit was restored to operation on April 4, 2002 and operated with the SCR bypassed until June 19, 2003, when it was returned to service. As a result of the Unit 3 ductwork collapse, EME reviewed the similar structures on Units 1 and 2 and determined

that as a precaution it would be appropriate to install additional reinforcement in these structures. The additional reinforcement extended the duration of planned outages for these units, which had been scheduled to end on June 2, 2002. Unit 1 returned to service on June 28, 2002 and Unit 2 returned to service on June 26, 2002.

Earnings from Homer City increased $15 million and $59 million for the second quarter and six months ended June 30, 2003, respectively, compared to the corresponding periods of 2002. The 2003 increase in earnings is due to increased generation and higher energy prices. See "—Market Risk Exposures—Homer City Facilities."

Gains (losses) from price risk management activities were $5 million and $(1) million for the second quarter and $(3) million and $(1) million for the six months ended June 30, 2003 and 2002, respectively. The gains (losses) primarily represent the ineffective portion of forward contracts which are derivatives that qualify as cash flow hedges under SFAS No. 133. See "—Consolidated Operating Results—Operating Revenues" for further discussion.

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

Earnings from the Big 4 projects increased $10 million and $26 million for the second quarter and six months ended June 30, 2003, respectively, compared to the corresponding periods of 2002. The change in earnings was largely due to higher energy prices in 2003. The earnings from the Big 4 projects included interest expense from Edison Mission Energy Funding of $4 million and $5 million for the second quarters of 2003 and 2002, respectively. For the six month periods ended June 30, 2003 and 2002, earnings included interest expense from Edison Mission Energy Funding of $8 million and $10 million, respectively.

EME owns a 37.2% direct and indirect interest, with 36.05% voting stock, in Four Star Oil & Gas Company, with majority control held by affiliates of ChevronTexaco Corporation. Four Star Oil & Gas owns oil and gas reserves in the San Juan Basin, the Hugoton Basin, the Permian Basin and offshore Gulf Coast and Alabama. EME's share of earnings from Four Star Oil & Gas Company increased $4 million and $12 million for the second quarter and six months ended June 30, 2003, respectively, compared to the corresponding periods of 2002. The 2003 increases in earnings were primarily due to higher natural gas prices.

Earnings from the Sunrise project increased $5 million for the second quarter and six months ended June 30, 2003, compared to the corresponding periods of 2002. The 2003 increases in earnings primarily resulted from additional earnings from the completion of Phase 2 of the Sunrise project in June 2003.

Earnings from March Point decreased $3 million for the second quarter and six months ended June 30, 2003, compared to the corresponding periods of 2002. The 2003 decreases in earnings were primarily due to a planned outage in June 2003.

Net losses from other projects in the Americas region (consolidated subsidiaries and unconsolidated affiliates) increased $3 million and net earnings decreased $22 million for the second quarter and six months ended June 30, 2003, respectively, compared to the same prior year periods. The 2003 year-to-date decrease was partially due to lower earnings from the EcoEléctrica project, primarily because of lower operating revenues resulting from plant outages, and losses from the TM Star project due to a change in market value of natural gas contracts that did not qualify for hedge accounting under SFAS No. 133. In addition, other projects included a $6 million loss for the second quarter and six months ended June 30, 2003 related to asset impairment charges. See "—Consolidated Operating Results—Operating Expenses" for further discussion of these items.

Operating revenues increased $54 million and $102 million for the second quarter and six months ended June 30, 2003, respectively, compared to the same prior year periods. The 2003 increases were partially due to higher wholesale electricity prices and higher generation which primarily resulted from the Taranaki Station acquisition in March 2003. In addition, there was a 23% increase in the average exchange rate of the New Zealand dollar compared to the U.S. dollar during the second quarter and six months ended June 30, 2003, compared to the corresponding periods of 2002.

Earnings from Contact Energy, included in the consolidated statements of income of EME as described above, decreased $3 million and $5 million for the second quarter and six months ended June 30, 2003, respectively, compared to the corresponding periods of 2002. In 2003, the higher revenues discussed above were offset by increased operating and interest costs associated with the Taranaki Station acquisition. Also included in the 2003 year-to-date decrease is a $5 million loss from price risk management activities related to a change in market value of electricity and financial contracts that were not designated as cash flow hedges for hedge accounting under SFAS No. 133. No comparable amount was recorded for the first six months of 2002.

Operating revenues increased $4 million and $3 million for the second quarter and six months ended June 30, 2003, respectively, compared to the corresponding periods of 2002. The 2003 increases were primarily due to a 16% and 14% increase in the average exchange rate of the Australian dollar compared to the U.S. dollar during the second quarter and six months ended June 30, 2003, respectively, compared to the corresponding periods of 2002. The 2003 increases were partially offset by lower generation resulting from a planned outage in March 2003 and lower pool prices for the power sold into the wholesale energy market.

Earnings from Loy Yang B decreased $1 million and $7 million for the second quarter and six months ended June 30, 2003, respectively, compared to the same prior year periods. The 2003 decrease in earnings is due to lower electric revenues discussed above and higher plant maintenance costs related to the planned outage in March 2003.

Earnings from Paiton Energy increased $8 million and $5 million for the second quarter and six months ended June 30, 2003, respectively, compared to the corresponding periods of 2002. The 2003 increases in earnings were primarily due to lower project interest expense, lower depreciation (due to a change from 30 to 40 years in the useful life of the power plant resulting from an extension of the power sales agreement) and a decrease in Indonesia income taxes resulting from interest expense from partner subordinated loans.

Operating revenues from other consolidated subsidiaries increased $1 million and $6 million for the second quarter and six months ended June 30, 2003, respectively, compared to the same prior year periods. The 2003 increase in operating revenues is primarily due to higher electric revenues from the Valley Power Peaker project in Australia. Commercial operation of the Valley Power Peaker project commenced during the second quarter of 2002.

Operating revenues decreased $7 million and increased $5 million for the second quarter and six months ended June 30, 2003, respectively, compared to the corresponding periods of 2002. The second quarter decrease was primarily due to lower ancillary services revenues and decreased volume of power sales, partially offset by an 11% increase in the average exchange rate of the British pound compared to the U.S. dollar during the second quarter of 2003, compared to the same prior year quarter. The 2003 year-to-date increase resulted primarily from higher electric revenues from the First Hydro plant due to an 11% increase in the average exchange rate of the British pound compared to the U.S. dollar during the six months ended June 30, 2003, compared to the same prior year period. This increase was partially offset by lower ancillary services revenues during the six months ended June 30, 2003, from the corresponding period of 2002. The First Hydro plant is expected to provide for higher electric revenues during its winter months.

Earnings from First Hydro decreased $21 million and $28 million for the second quarter and six months ended June 30, 2003, respectively, compared to the same prior year periods. The 2003 decrease in earnings is partially due to a $6 million and $11 million loss from price risk management activities for the second quarter and six months ended June 30, 2003, respectively, compared to a $1 million loss

and $3 million gain from price risk management activities for the second quarter and six months ended June 30, 2002, respectively. First Hydro's gains (losses) from price risk management relate to realized losses and 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. The earnings decline in the second quarter of 2003 is also attributable to lower revenues described above.

Revenues from Doga increased $6 million and $9 million for the second quarter and six months ended June 30, 2003, respectively, compared to the corresponding periods of 2002. The 2003 increases were primarily due to an increase in steam sales and higher natural gas prices. Earnings from Doga decreased $3 million and $5 million for the second quarter and six months ended June 30, 2003, respectively, compared to the same prior year periods. The 2003 decreases in earnings were primarily due to foreign exchange losses on local currency denominated net assets and taxes.

Earnings from ISAB decreased $7 million and $5 million for the second quarter and six months ended June 30, 2003, respectively, compared to the corresponding periods of 2002. The 2003 decreases were primarily due to lower generation resulting from a major planned overhaul of the plant in April 2003.

Earnings from other projects in the Europe region (consolidated subsidiaries and unconsolidated affiliates) increased $5 million and $9 million for the second quarter and six months ended June 30, 2003, respectively, compared to the corresponding periods of 2002. The 2003 increase in earnings is primarily due to increased operating revenues from EME's Spanish Hydro project largely due to higher generation caused by more rainfall in the first six months of 2003, compared to the first six months of 2002.

Europe's Regional G&A decreased $1 million and $3 million for the second quarter and six months ended June 30, 2003, respectively, compared to the same prior year periods. The 2003 decrease in Regional G&A is primarily due to lower development costs.

At June 30, 2003, MEHC and its subsidiaries had cash and cash equivalents of $910 million and EME had available a total of $71 million of borrowing capacity under its $487 million corporate credit facility. MEHC's consolidated debt at June 30, 2003 was $7.9 billion, including $275 million of EME debt maturing on September 16, 2003 and $911 million of debt maturing on December 11, 2003 which is owed by EME's largest subsidiary, Edison Mission Midwest Holdings. In addition, EME's subsidiaries have $7 billion of long-term lease obligations that are due over periods ranging up to 32 years.

The $275 million of debt at EME maturing on September 16, 2003 will need to be repaid, extended or refinanced. In addition, the $911 million of debt of Edison Mission Midwest Holdings maturing on December 11, 2003 will need to be repaid, extended or refinanced. Edison Mission Midwest Holdings is not expected to have sufficient cash to repay the $911 million debt due on December 11, 2003. During the second quarter, EME and Edison Mission Midwest Holdings commenced discussions with their lenders regarding restructuring their respective indebtedness. There is no assurance that either EME or Edison Mission Midwest Holdings will be able to extend or refinance their respective debt obligations on similar terms and rates as the existing debt, on commercially reasonable terms, on the terms permitted under the financing documents entered into by MEHC in July 2001, or at all. A failure to repay, extend, or refinance the Edison Mission Midwest Holdings or EME obligations is likely to result in, or in the case of EME would result in, a default under the MEHC senior secured notes and term loan. These events could make it necessary for MEHC or EME, or both, to file a petition for reorganization under Chapter 11 of the United States Bankruptcy Code. MEHC's independent accountants' audit opinion for the year ended December 31, 2002 contains an explanatory paragraph that indicates the consolidated financial statements have been prepared on the basis that MEHC will continue as a going concern and that the uncertainty about Edison Mission Midwest Holdings' ability to repay, extend or refinance this obligation raises substantial doubt about MEHC's ability to continue as a going concern. Accordingly, the consolidated financial statements do not include any adjustments that might result from the resolution of this uncertainty.

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

At June 30, 2003, MEHC had cash and cash equivalents of $109 million and restricted cash of $80 million (excluding amounts held by EME and its subsidiaries). Restricted cash represented monies deposited into the interest escrow accounts described above. The funds collected in the accounts were used to make the interest payments due under the senior secured notes and the term loan through July 15, 2003. The lenders under MEHC's $385 million term loan due in 2006 have the right to require MEHC to repurchase up to $100 million of principal amount at par on July 2, 2004 (referred to as the "Term Loan Put-Option"). In order for MEHC to have sufficient cash in the event of an exercise of a

significant portion, or all, of the Term Loan Put-Option, MEHC would require additional cash from dividends from EME, or would need to either extend the effective date of the Term Loan Put-Option or extend or refinance the term loan. The timing and amount of dividends from EME and its subsidiaries may be affected by many factors beyond MEHC's control. Dividends from EME are currently limited as described in "Ability of Edison Mission Energy to Pay Dividends."

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

	Moody's Rating	S&P Rating
Edison Mission Energy (senior unsecured)	B2	BB-
Edison Mission Midwest Holdings (bank facility)	Ba3	BB-
Edison Mission Marketing & Trading (senior unsecured)	Not Rated	BB-

Moody's Investors Service and Standard & Poor's Rating Service have assigned a negative rating outlook for each of these entities.

The credit ratings of EME are below investment grade and, accordingly, EME has agreed to provide collateral in the form of cash and letters of credit for the benefit of counterparties for its price risk management and domestic trading activities related to accounts payable and unrealized losses ($56 million as of August 8, 2003). EME has also provided collateral for a portion of its United Kingdom trading activities. To this end, EME's subsidiary, Edison Mission Operation and Maintenance Limited, has obtained a cash collateralized credit facility, under which letters of credit totaling £19 million have been issued as of July 31, 2003.

EME anticipates that sales of power from its Illinois Plants, Homer City facilities and First Hydro plants in the United Kingdom may require additional credit support, depending upon market conditions and the strategies adopted for the sale of this power. Changes in forward market prices and margining requirements could further increase the need for credit support for the price risk management and trading activities related to these projects. EME currently projects the potential working capital required to support its price risk management and trading activity to be between $100 million and $200 million from time to time during 2003.

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

As a result of the downgrade of Edison Mission Midwest Holdings below investment grade in October 2002, provisions in the agreements binding on Edison Mission Midwest Holdings and Midwest Generation restrict the ability of Edison Mission Midwest Holdings to make distributions to its parent company, thereby eliminating distributions to EME.

The following table summarizes the provisions restricting cash distributions (sometimes referred to as cash traps) and the related changes in the cost of borrowing by Edison Mission Midwest Holdings

under the applicable financing agreements. The currently applicable provisions are those set forth in the same row as the Standard & Poor's rating "BB-."

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

Based on its current credit ratings, provisions in the agreements binding on Edison Mission Midwest Holdings require it to deposit, on a quarterly basis, 100% of its excess cash flow as defined in the agreements into a cash flow recapture account held and maintained by the collateral agent. In accordance with these provisions, Edison Mission Midwest Holdings deposited $50 million into the cash flow recapture account on October 31, 2002, and another $28 million on January 27, 2003. The funds in the cash flow recapture account may be used only to meet debt service obligations of Edison Mission Midwest Holdings if funds are not otherwise available from working capital. There is no assurance that Edison Mission Midwest Holdings' current credit rating will not be lowered again, in which case Edison Mission Midwest Holdings would be required to use the funds from time to time on deposit in the cash flow recapture account to repay indebtedness.

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

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. (EME Homer City) 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 is permitted to sell the output of the Homer City facilities into the PJM market at any time on a spot-market basis. See "—Market Risk Exposures—Homer City Facilities."

EME has a $487 million corporate credit facility which includes a $275 million component, Tranche A, that expires on September 16, 2003 and a $212 million component, Tranche B, that expires on September 17, 2004. As of June 30, 2003, EME had borrowed $275 million under Tranche A in order to improve its short-term liquidity. At June 30, 2003, EME had borrowing capacity under Tranche B of $71 million and corporate cash and cash equivalents of $302 million.

Cash distributions from EME's subsidiaries and partnership investments, tax-allocation payments from Edison International and unused capacity under its corporate credit facilities represent EME's major sources of liquidity to meet its cash requirements. In addition, EME is engaged in the Sunrise project financing which it plans to complete during the next three months, which, if completed, will result in the receipt by EME of approximately $150 million of capital previously invested in this project. See "Edison Mission Energy's Subsidiary Financing Plans." EME expects its 2003 cash requirements to be primarily comprised of:

The timing and amount of distributions from EME's subsidiaries may be affected by many factors beyond its control. See "—Historical Distributions Received by Edison Mission Energy—Restricted Assets of EME's Subsidiaries." Also see "—Risk Factors" in the Management's Discussion and Analysis of Results of Operations and Financial Condition included in Item 7 of EME's annual report on Form 10-K for the year ended December 31, 2002. In addition, the right of EME to receive tax-allocation payments, and the timing and amount of tax-allocation payments received by EME are subject to factors beyond EME's control. See "—Intercompany Tax-Allocation Payments." If Tranche A of the corporate facility is not extended and the Sunrise project financing is not completed as scheduled, EME's ability to provide credit support for bilateral contracts for power and fuel related to its merchant energy operations will be severely limited. If EME is unable to provide such credit support, this will reduce the number of counterparties willing to enter into bilateral contracts with EME's subsidiaries, thus requiring EME's subsidiaries to rely on short-term markets instead of bilateral contracts. Furthermore, if this situation occurs, EME may not be able to meet margining requirements if forward prices for power increase significantly. Failure to meet a margining requirement would permit the counterparty to terminate the related bilateral contract early and demand immediate payment of damages incurred by reason of such termination.

EME's corporate credit facility provides credit available in the form of cash advances or letters of credit. At June 30, 2003, Tranche A consisted of borrowings of $275 million, and $141 million of letters of credit were outstanding under Tranche B. In addition to the interest payments, EME pays a facility fee determined by its long-term credit ratings (0.875% and 1.00% at June 30, 2003 for Tranche A and Tranche B, respectively) on the entire credit facility independent of the level of borrowings.

Under the credit agreement governing its credit facility, EME has agreed to maintain an interest coverage ratio that is based on cash received by EME, including tax-allocation payments, cash disbursements and interest paid. At June 30, 2003, EME met this interest coverage ratio. The interest coverage ratio in the ring-fencing provisions of EME's certificate of incorporation and bylaws remains relevant for determining EME's ability to make distributions. See "—Edison Mission Energy's Interest Coverage Ratio."

The lower operating cash flow from continuing operations in the first half of 2003, compared to the first half of 2002, reflects lower distributions from unconsolidated affiliates. Distributions from unconsolidated affiliates during the first six months of 2002 were higher than the first six months of 2003 primarily due to the collection of past due accounts receivable from California utilities, arising from the California energy crisis, by EME's investments in California qualifying facilities which amounts were then distributed to their partners. EME received $89 million and $211 million in tax-allocation payments from Edison International during the first six months of 2003 and 2002, respectively, offsetting the cash used in operating activities. In addition, MEHC received $25 million and $30 million in tax-allocation payments from Edison International during the first six months of 2003 and 2002, respectively. For further discussion on the tax-allocation payments, see "—Intercompany Tax-Allocation Payments." The change in operating cash flow from continuing operations in the first half of 2003 was also due to the timing of cash receipts and disbursements related to working capital items.

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

	Six Months Ended June 30,
	2003		2002
	(in millions)
Continuing operations	$	487	$	(146	)
Discontinued operations		—		(9	)

	$	487	$	(155	)

Cash provided by financing activities from continuing operations during the first half of 2003 consisted of net borrowings of $275 million on EME's $487 million corporate credit facility and

$275 million in borrowings used to finance the acquisition of the Taranaki power station by Contact Energy, EME's 51% owned subsidiary. A debt service payment of $23 million related to one of EME's subsidiaries was made in March 2003.

Cash used in financing activities from continuing operations during the first half of 2002 consisted of payment at maturity of $100 million of senior notes, net payments of $80 million on EME's corporate credit facility, $22 million related to debt service payments of one of EME's subsidiaries, and payments of $86 million from its Coal and Capex facility. In addition, a wholly owned subsidiary borrowed $84 million under a note purchase agreement in January 2002. EME also received $54 million from a swap agreement with a bank related to lease payments for its Homer City facilities.

	Six Months Ended June 30,
	2003			2002
	(in millions)
Continuing operations	$	(371	)	$	(42	)
Discontinued operations		5			1

	$	(366	)	$	(41	)

Cash used in investing activities from continuing operations during the first half of 2003 included $275 million paid by Contact Energy for the acquisition of the Taranaki power station during the first quarter of 2003 and $39 million in equity contributions to the Sunrise and CBK projects. EME invested $79 million in the first half of 2003 in new plant and equipment principally related to the Illinois Plants, the Homer City facilities and Contact Energy.

Cash used in investing activities from continuing operations during the first half of 2002 included $80 million paid for the purchase of a power sales agreement held by a third party. EME invested $115 million in the first half of 2002 in new plant and equipment principally related to the Valley Power Peaker project in Australia, the Illinois Plants and the Homer City facilities. Also, included in capital expenditures during the first half of 2002 were payments for three turbines purchased under EME's Master Turbine Lease with funds from restricted cash of $61 million. Included in the first half of 2002 investing activities was $86 million of restricted cash used to purchase the three turbines and satisfy EME's obligation related to the termination of EME's Master Turbine Lease, thereby reducing EME's restricted cash account. EME received proceeds of $44 million from the sales of its 50% interests in the Commonwealth Atlantic and James River projects and its 30% interest in the Harbor project during the first quarter of 2002. In addition, EME received $78 million as a return of capital from the Kern River and Sycamore projects subsequent to their receipt of payments of past due accounts receivable from Southern California Edison during the first quarter of 2002. Restricted cash totaling $53 million was used to meet EME's lease payment obligations.

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 interest costs of recourse debt. Distributions for the first six

months of each year are not necessarily indicative of annual distributions due to the seasonal fluctuations in EME's business.

		Six Months Ended June 30,
		2003		2002
		(in millions)
Distributions from Consolidated Operating Projects:
	EME Homer City Generation L.P. (Homer City facilities)	$	127	$	—
	Holding companies of other consolidated operating projects		53		4
Distributions from Unconsolidated Operating Projects:
	Edison Mission Energy Funding Corp. (Big 4 Projects)(1)		20		82
	Four Star Oil & Gas Company		—		21
	Holding companies of other unconsolidated operating projects		31		30

Total Distributions		$	231	$	137

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

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

Edison Mission Midwest Holdings must also maintain a debt service coverage ratio for the prior twelve-month period of at least 1.50 to 1 as long as the power purchase agreements with Exelon Generation represent 50% or more of Edison Mission Midwest Holdings' and its subsidiaries' revenues. If the power purchase agreements with Exelon Generation represent less than 50% of Edison Mission Midwest Holdings' and its subsidiaries' revenues, it must maintain a debt service coverage ratio of at least 1.75 to 1. EME expects that revenues for 2003 from Exelon Generation will represent 50% or more of Edison Mission Midwest Holdings' and its subsidiaries' revenues. In addition, Edison Mission Midwest Holdings must maintain a debt-to-capital ratio no greater than 0.60 to 1. Failure to meet the historical debt service coverage ratio and the debt-to-capital ratio are events of default under the credit agreement and Collins lease agreements, which, upon a vote by a majority of the lenders, could cause an acceleration of the due date of the obligations of Edison Mission Midwest Holdings and those associated with the Collins lease. Such an acceleration would result in an event of default under the Powerton and Joliet leases. During the 12 months ended June 30, 2003, the historical debt service coverage ratio was 3.46 to 1 and the debt-to-capital ratio was 0.53 to 1.

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

EME Homer City Generation L.P. completed a sale-leaseback of the Homer City facilities in December 2001. In order to make a distribution, EME Homer City must be in compliance with the covenants specified in the lease agreements, including the following financial performance requirement measured on the date of distribution:

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

During the 12 months ended June 30, 2003, the senior rent service coverage ratio was 4.32 to 1.

A subsidiary of First Hydro Holdings, First Hydro Finance plc, has issued £400 million of Guaranteed Secured Bonds due in 2021. In order to make a distribution, First Hydro Finance must be in compliance with the covenants specified in its bond indenture, including an interest coverage ratio. When measured for the twelve-month period ended December 31, 2002, First Hydro Holdings met the interest coverage ratio and made a distribution of $18 million on May 7, 2003. When measured for the twelve-month period ended June 30, 2003, First Hydro Holdings' interest coverage ratio was approximately 1.49 to 1.

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

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

EME's subsidiaries, which EME refers to in this context as the guarantors, that hold EME's interests in the Big 4 projects completed a $450 million secured financing in December 1996. Edison Mission Energy Funding Corp., a special purpose Delaware corporation, issued notes ($260 million) and bonds ($190 million), the net proceeds of which were lent to the guarantors in exchange for a note. The guarantors have pledged their cash proceeds from the Big 4 projects to Edison Mission Energy Funding as collateral for the note. All distributions receivable by the guarantors from the Big 4 projects are deposited into trust accounts from which debt service payments are made on the obligations of

Edison Mission Energy Funding and from which distributions may be made to EME if the guarantors and Edison Mission Energy Funding are in compliance with the terms of the covenants in their financing documents, including the following requirements measured on the date of distribution:

The debt service coverage ratio is determined primarily based upon the amount of distributions received by the guarantors from the Big 4 projects during the relevant quarter divided by the debt service (principal and interest) on Edison Mission Energy Funding's notes and bonds paid or due in the relevant quarter. During the 12 months ended June 30, 2003, the debt service coverage ratio was 2.37 to 1. Although the credit ratings of Edison Mission Energy Funding's notes and bonds are below investment grade, this has no effect on the ability of the guarantors to make distributions to EME.

EME holds a 50% interest in CBK Power Co Ltd. CBK Power operates under a 25-year build-rehabilitate-operate-transfer agreement with National Power Corporation for the 756 MW Caliraya-Botocan-Kalayaan hydro electric complex, located in the Republic of the Philippines, which EME refers to as the CBK project. On April 23, 2003, the President of the Republic of the Philippines signed into law the 2003 General Appropriations Act, which includes a provision that prohibits payments by agencies of the Philippine government to CBK Power with respect to two of its units until National Power Corporation submits a report based upon a review of "overpayments" to the CBK project, if any, and until the project documentation has been amended to provide for recovery by National Power Corporation of any "overpayments." The assertion regarding "overpayment" stems from a supplemental agreement entered into during 1999 which modified the original build-rehabilitate- operate-transfer agreement by adjusting the schedule for completion of two units of the CBK complex.

Under the supplemental agreement, the schedule for the rehabilitation of existing Kalayaan Units 1 and 2 was brought forward because of National Power Corporation's concern about the possibility of transformer failure and other risks affecting the reliability of these units. Under the original schedule, Kalayaan Units 1 and 2 were to be operated by CBK Power for operation and maintenance fees only during the lengthy construction of new Kalayaan Units 3 and 4, and upon completion of these units, Kalayaan Units 1 and 2 were to be taken out of service for rehabilitation. Under the build-rehabilitate-operate-transfer agreement, National Power Corporation is obligated to pay capital recovery fees to CBK Power upon completion of the construction or rehabilitation of each unit, as the case may be. EME understands the term, "overpayment" as used in the Special Provision of the General Appropriations Act, refers to the payments of capital recovery fees for Kalayaan Units 1 and 2 arising from the earlier than initially scheduled rehabilitation of these units. At the time EME made its investment in CBK Power, the decision to accelerate the work on Kalayaan Units 1 and 2 had been made and incorporated in the supplemental agreement, and all appropriate Philippine government approvals of the supplemental and other project agreements with National Power Corporation had been obtained. Subsequently, some parties in the Philippines have contended that payments made to CBK Power as a result of the earlier than initially scheduled rehabilitation of Kalayaan Units 1 and 2 were unreasonable in comparison to the amount of additional work required to rehabilitate the units.

On May 22, 2003, CBK Power and National Power Corporation, with the concurrence of Power Sector Assets and Liabilities Management Corporation (PSALM), entered into a settlement agreement. PSALM is a Philippine government-owned entity with responsibility for the electric power sector. The settlement agreement provides for certain concessions to National Power Corporation which have been deemed by the parties to satisfy the requirements of the Special Provision. In addition, on May 23, 2003, National Power Corporation submitted a report to the Congress of the Philippines as required by

the provisions of the 2003 General Appropriations Act. Subsequently, the Secretary of Management and Budget confirmed to National Power Corporation that payments could be made to CBK using funds provided by the 2003 General Appropriations Act based on National Power Corporation's determination that the requirements of those provisions have been met. National Power Corporation has cleared all arrears owing to CBK Power and has made all payments since the signing of the settlement agreement in a timely manner.

The effectiveness of the settlement agreement is subject to certain conditions precedent. For CBK Power, the primary requirement is approval by its lenders. That approval is currently pending. National Power Corporation was required to obtain, and has obtained, approval from the National Economic Development Authority—Investment Coordinating Committee. The outstanding items required of Philippine Government parties include opinions of counsel from National Power Corporation and PSALM and a confirmation from the Department of Finance that the Government Undertaking remains in full force and effect. The parties originally set a deadline of June 22, 2003 to complete all conditions precedent. That deadline has, by mutual agreement, been extended to August 20, 2003. Given the complexities of the outstanding conditions, it may be necessary to extend the deadline for an additional 30 days. EME believes that the parties will agree to an extension.

As of June 30, 2003, EME has invested $59 million in the CBK project and as of such date is committed to invest up to an additional $19 million. EME believes that it will recover its entire investment. The indebtedness incurred by CBK Power is non-recourse to EME and, except for EME's commitment to contribute up to an additional $19 million as equity, EME has no obligation with respect to CBK Power's indebtedness. Further, these events do not constitute a default under any indebtedness incurred by EME or to which EME or any of its affiliates is subject.

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

MEHC's interest coverage ratio is comprised of interest income and expense related to its holding company activities and the consolidated financial information of EME. For a complete discussion of EME's interest coverage ratio and the components included therein, see "Edison Mission Energy's Interest Coverage Ratio" below. The following table sets forth MEHC's interest coverage ratio for the twelve months ended June 30, 2003 and the year ended December 31, 2002:

			June 30, 2003			December 31, 2002
			(in millions)
Funds Flow from Operations:
	Edison Mission Energy		$	597		$	692
	Operating cash flow from unrestricted subsidiaries			(1	)		(17	)
	Outflows of funds from operations of projects sold			(17	)		2
	Mission Energy Holding Company			3			7

			$	582		$	684

Interest Expense:
	Edison Mission Energy		$	280		$	293
	Edison Mission Energy—affiliate debt			1			2
	Mission Energy Holding Company interest expense			160			159

		Total interest expense	$	441		$	454

Interest Coverage Ratio				1.32			1.51

The above interest coverage ratio was determined in accordance with the definitions set forth in the bond indenture governing MEHC's senior secured notes and the credit agreement governing the term loan. The interest coverage ratio prohibits MEHC, EME and its subsidiaries from incurring additional indebtedness, except as specified in the indenture and the financing documents, unless MEHC's interest coverage ratio exceeds 1.75 to 1 for the immediately preceding four fiscal quarters prior to June 30, 2003 and 2.0 to 1 for periods thereafter.

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

EME's interest coverage ratio for the twelve months ended June 30, 2003 was 2.13 to 1. See further details of EME's interest coverage ratio below. Accordingly, EME is not permitted to pay dividends in the next quarter under the "ring-fencing" provisions of EME's certificate of incorporation and bylaws. EME did not pay or declare any dividends to MEHC during the first six months of 2003.

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

The following table sets forth the major components of the interest coverage ratio for the twelve months ended June 30, 2003 and the year ended December 31, 2002:

			June 30, 2003			December 31, 2002
			(in millions)
Funds Flow from Operations:
	Operating Cash Flow(1) from Consolidated Operating Projects(2):
		Illinois Plants(3)	$	263		$	294
		Homer City		111			51
		First Hydro		2			47
	Other consolidated operating projects			153			158
	Price risk management and energy trading			15			16
	Distributions from unconsolidated Big 4 projects			75			137
	Distributions from other unconsolidated operating projects			104			120
	Interest income			6			8
	Operating expenses			(132	)		(139	)

		Total funds flow from operations	$	597		$	692

Interest Expense:
	From obligations to unrelated third parties		$	166		$	178
	From notes payable to Midwest Generation			114			115

		Total interest expense	$	280		$	293

Interest Coverage Ratio				2.13			2.36

The major factors affecting funds flow from operations during the twelve months ended June 30, 2003, compared to the year ended December 31, 2002, were:

Interest expense decreased by $13 million for the twelve months ended June 30, 2003, compared to the year ended December 31, 2002 due to a lower average debt balance.

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

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

Financial Ratio		Covenant		Actual at June 30, 2003		Description
Recourse Debt to Recourse Capital Ratio		Less than or equal to 67.5	%	66.3	%	Ratio of (a) senior recourse debt to (b) sum of (i) shareholder's equity per EME's balance sheet adjusted by comprehensive income after December 31, 1999, plus (ii) senior recourse debt

The recourse debt to recourse capital ratio of EME at June 30, 2003 and December 31, 2002 was calculated as follows:

		June 30, 2003			December 31, 2002
		(in millions)
Recourse Debt(1)
	Corporate Credit Facilities	$	424		$	140
	Senior Notes		1,600			1,600
	Guarantee of termination value of Powerton/Joliet operating leases		1,461			1,452
	Coal and Capex Facility		186			182
	Other		33			30

	Total Recourse Debt to EME	$	3,704		$	3,404

Adjusted Shareholder's Equity(2)		$	1,884		$	2,066

Recourse Capital(3)		$	5,588		$	5,470

Recourse Debt to Recourse Capital Ratio			66.3	%		62.2	%

During the six months ended June 30, 2003, the recourse debt to recourse capital ratio was increased due to:

EME's indirect subsidiary, Midwest Generation, reported an asset impairment charge of $475 million, after tax, related to the 2,698 MW gas-fired Collins Station in its second quarter report on Form 10-Q. The impairment charge resulted from a write-down of the book value of capitalized assets related to the Collins Station from $858 million to an estimated fair market value of $78 million. The impairment charge by Midwest Generation is not reflected in the operating results of EME because the lease related to the Collins Station is treated in EME's financial statements as an operating lease and not as an asset and, therefore, is not subject to impairment for accounting purposes. EME is evaluating a number of debt restructuring alternatives, some of which could result in the consolidation of the Collins Station and recognition of a loss in the consolidated accounts of EME. A restructuring alternative that resulted in the consolidation of the Collins Station would require EME to obtain modifications to net worth covenants contained in its credit facilities and the guarantee it provides to the owner participants in the Powerton and Joliet sale-leaseback.

The estimated capital and construction expenditures of EME's subsidiaries for the remaining two quarters of 2003 total $41 million. These expenditures are planned to be financed by existing subsidiary

credit agreements and cash generated from their operations, except with respect to the Homer City project. Under the Homer City sale-leaseback agreements, EME has committed to provide funds for capital expenditures needed to complete the Homer City environmental improvement project. EME expects to contribute $24 million in 2003 to fund the completion of this project, of which $14 million was contributed during the first half of 2003.

EME's wholly owned subsidiary, Edison Mission Midwest Holdings, had debt with the following maturities at June 30, 2003:

In addition, Edison Mission Midwest Holdings has a $150 million working capital facility (unused at June 30, 2003) which is scheduled to expire on December 15, 2004. At June 30, 2003, Edison Mission Midwest Holdings had cash and cash equivalents of $201 million, as well as $78 million deposited into a restricted cash account. Edison Mission Midwest Holdings is not expected to have sufficient cash to repay the $911 million debt due on December 11, 2003. Edison Mission Midwest Holdings plans to extend or refinance the $911 million debt obligation prior to its expiration in December 2003. During the second quarter, Edison Mission Midwest Holdings commenced discussions with its lenders regarding restructuring its indebtedness. Completion of an extension or refinancing is subject to a number of uncertainties, including the ability of the Illinois Plants to generate funds during the remainder of 2003 and the availability of new credit from financial institutions on acceptable terms in light of industry conditions. Accordingly, there is no assurance that Edison Mission Midwest Holdings will be able to extend or refinance this debt when it becomes due or that the terms will not be substantially different from those under the current credit facility.

EME owns a 50% interest in Sunrise Power Company, which owns a natural gas-fired facility in Kern County, California, which EME refers to as the Sunrise project. The Sunrise project consists of two phases. Phase 1, a simple-cycle gas-fired facility (320 MW), was completed on June 27, 2001. Phase 2, conversion to a combined-cycle gas-fired facility (bringing the capacity to a total of 572 MW), was completed on June 1, 2003. Sunrise Power Company entered into a long-term power purchase agreement with the California Department of Water Resources on June 25, 2001. The agreement was amended on December 31, 2002 as part of the settlement of several matters between Sunrise Power Company and the State of California. The construction of the Sunrise project was funded with equity contributions by its partners, including EME. Sunrise Power Company has engaged a financial advisor to assist with obtaining project financing. Completion of project financing is subject to a number of uncertainties, including market uncertainties. EME believes that project financing will be completed during the next three months, although no assurance can be provided in this regard. If project financing is completed as planned, EME estimates a distribution of approximately $150 million from the proceeds of such financing.

MEHC and EME are included in the consolidated federal and combined state income tax returns of Edison International and are eligible to participate in tax-allocation payments with other subsidiaries

of Edison International. These arrangements depend on Edison International continuing to own, directly or indirectly, at least 80% of the voting power of the stock of MEHC and EME and at least 80% of the value of such stock. The arrangements are subject to the terms of tax allocation and payment agreements among Edison International, MEHC, EME and other Edison International subsidiaries. The agreements to which MEHC and EME are parties may be terminated by the immediate parent company of MEHC at any time, by notice given before the first day of the first tax year with respect to which the termination is to be effective. However, termination does not relieve any party of any obligations with respect to any tax year beginning prior to the notice. MEHC became a party to the tax-allocation agreement with Edison Mission Group on July 2, 2001, when it became part of the Edison International consolidated filing group. EME and MEHC have historically received tax-allocation payments related to domestic net operating losses incurred by EME and MEHC. The right of MEHC and EME to receive and the amount and timing of tax-allocation payments are dependent on the inclusion of MEHC and EME, respectively, in the consolidated income tax returns of Edison International and its subsidiaries, the amount of net operating losses and other tax items of MEHC, EME and its subsidiaries and other subsidiaries of Edison International and specific procedures regarding allocation of state taxes. MEHC and EME receive tax-allocation payments for tax losses when and to the extent that the consolidated Edison International group generates sufficient taxable income in order to be able to utilize MEHC's tax losses or the tax losses of EME in the consolidated income tax returns for Edison International and its subsidiaries. During the six-month period ended June 30, 2003, MEHC and EME received $25 million and $89 million, respectively, in tax-allocation payments from Edison International. In the future, based on the application of the factors cited above, MEHC or EME may be obligated during periods they generate taxable income to make payments under the tax-allocation agreements.

In April 2003, Midwest Generation and Commonwealth Edison amended their February 2003 settlement agreement which terminated Midwest Generation's obligation to build additional gas-fired generation in the Chicago area. In accordance with the amendment, Midwest Generation paid Commonwealth Edison $9.8 million in exchange for the termination of nine annual installment payments of $1.5 million beginning in 2004 and for the termination of the security interest of Commonwealth Edison in 125,000 barrels of oil at the Collins Station.

In April 2003, the Sunrise project assumed EME's obligations under a gas transportation agreement, thereby reducing EME's contractual commitments to transport natural gas. EME's share of the commitment to pay minimum fees under its remaining gas transportation agreement, which has a term of 15 years, is currently estimated to be $4 million for the second half of 2003; $8 million for 2004; $8 million for 2005; $8 million for 2006; and $8 million for 2007.

EME's primary market risk exposures are associated with the sale of electricity from and the procurement of fuel for its uncontracted generating plants. These risks arise from fluctuations in electricity and fuel prices, emission 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 "—General—Current Developments" and "—Liquidity and Capital Resources—Edison Mission Energy's Credit Ratings" for a discussion of market developments and their impact on EME's credit and the credit of its counterparties.

EME's merchant power plants and energy trading activities expose EME to commodity price risks. Commodity price risks are actively monitored to ensure compliance with EME's risk management policies. Policies are in place which define risk tolerances for each EME regional business unit. Procedures exist which allow for monitoring of all commitments and positions with regular reviews by a risk management committee. In order to provide more predictable earnings and cash flow, EME may hedge a portion of the electric output of its merchant plants, the output of which is not committed to be sold under long-term contracts. When appropriate, EME manages the spread between electric prices and fuel prices, and uses forward contracts, swaps, futures, or options contracts to achieve those objectives. There is no assurance that contracts to hedge changes in market prices will be effective.

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

EME performs a "value at risk" analysis in its daily business to measure, monitor and control its overall market risk exposure in respect of its Illinois Plants, its Homer City facilities, its Four Star investment and its proprietary positions. The use of value at risk allows management to aggregate overall commodity risk, compare risk on a consistent basis and identify the risk factors. Value at risk measures the possible loss over a given time interval, under normal market conditions, at a given confidence level. Given the inherent limitations of value at risk and relying on a single risk

measurement tool, EME supplements this approach with the use of stress testing and worst-case scenario analysis for key risk factors, as well as stop loss limits and counterparty credit exposure limits. Despite this, there can be no assurance that all risks have been accurately identified, measured and/or mitigated.

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

Electric power 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 purchases capacity and has the right to purchase energy generated by the Illinois Plants. The agreements, which began on December 15, 1999 and expire in December 2004, provide for capacity and energy payments. Exelon Generation is obligated to make a capacity payment for the plants under contract and an energy payment for the electricity produced by these plants and taken by Exelon Generation. The capacity payments provide the revenue for fixed charges, and the energy payments compensate the Illinois Plants for all, or a portion of, variable costs of production.

Under each of the power purchase agreements, Exelon Generation, upon notice by given dates, has the option to terminate each agreement with respect to all or a portion of the units subject to it. As a result of notices given in 2002, effective January 1, 2003, Exelon Generation released 4,548 MW of Midwest Generation's generating capacity from the power purchase agreements, thus increasing Midwest Generation's reliance on sales into the wholesale markets. As a result, 4,739 MW of capacity remain subject to power purchase agreements with Exelon Generation in 2003.

Exelon Generation notified Midwest Generation on June 25, 2003 of its exercise of its option to purchase 687 MW of capacity and energy (out of a possible total of 1,265 MW subject to the option) during 2004 from Midwest Generation's coal-fired units in accordance with the terms of the existing power purchase agreement related to Midwest Generation's coal-fired generation units. As a result, 578 MW of the capacity of these units will no longer be subject to the power purchase agreement beginning January 1, 2004. The notification received from Exelon Generation has no effect on its commitments to purchase capacity from these generating units for the balance of 2003. For 2004, Exelon Generation will have 2,383 MW of capacity related to its coal-fired generation units under contract with Midwest Generation.

Under the power purchase agreements related to Midwest Generation's Collins Station and peaking units, Exelon Generation continues to have a similar option to terminate, exercisable not later than 90 days prior to January 1, 2004, the power purchase agreements for 2004 with respect to all or a portion of the 1,084 MW of capacity from the Collins Station, and 694 MW of capacity from the peaking units, that were retained for 2003.

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

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

The following table depicts the historical average market prices for energy per megawatt-hour "Into ComEd" and "Into Cinergy" for the first six months of 2003:

The following table sets forth forward market prices for energy per megawatt-hour as quoted for sales "Into ComEd" and "Into Cinergy" at June 30, 2003. These forward prices will continue to fluctuate as a result of a number of factors, including gas prices, electricity demand, which is also affected by economic growth, and the amount of existing and planned power plant capacity. The actual

spot prices for electricity delivered into these markets may vary materially from the forward market prices.

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

In addition to the prevailing market prices, Midwest Generation's ability to derive profits from the sale of electricity from the released units will be affected by the cost of production, including costs incurred to comply with environmental regulations. The costs of production of the released units vary and, accordingly, depending on market conditions, the amount of generation that will be sold from the released units is expected to vary from unit to unit. In this regard, Midwest Generation suspended operations of Will County Units 1 and 2 and Collins Station Units 4 and 5 at the end of 2002 pending improvement in market conditions. If market conditions were to be depressed for an extended period of time, Midwest Generation would need to consider decommissioning Will County Units 1 and 2, which would result in a charge against income. Collins Station Units 4 and 5 are subject to a long-term lease which requires that for the term of the lease, these units be maintained in condition for return to service, should market conditions improve. Thus, in the absence of an agreement with the lessor under the lease, Midwest Generation cannot decommission these units.

In addition to the price risks described previously, Midwest Generation's ability to transmit energy to counterparty delivery points to consummate spot sales and hedging transactions may also be affected by transmission service limitations and constraints and new standard market design proposals proposed

by and currently pending before the Federal Energy Regulatory Commission, or the FERC. Although the FERC and the relevant industry participants are working to minimize such issues, Midwest Generation cannot determine how quickly or how effectively such issues will be resolved. Currently, transmission must be obtained from Commonwealth Edison under its open-access tariff filed with the FERC. Commonwealth Edison and PJM are attempting to integrate Commonwealth Edison into PJM by November 2003. EME and a number of other affected parties have filed with the FERC contesting the integration of Commonwealth Edison into PJM on a so-called "islanded" basis. See "—Regulatory Matters." EME is unable to predict the outcome of these efforts or the effect of any final integration configuration on the markets into which Midwest Generation sells its power.

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

The following table depicts the average market prices per megawatt-hour in PJM during the first six months of 2003 and 2002:

	24-Hour PJM Historical Energy Prices*
	2003		2002
January	$	36.56	$	20.52
February		46.13		20.62
March		46.85		24.27
April		35.35		25.68
May		32.29		21.98
June		27.26		24.98

Six-Month Average	$	37.41	$	23.01

As shown on the above table, the average historical market prices at the Homer City busbar (delivery point) during the first six months of 2003 were significantly higher than the average historical market prices during the first six months of 2002. Forward market prices in PJM fluctuate as a result of a number of factors, including natural gas prices, transmission congestion, changes in market rules, electricity demand which is affected by weather and economic growth, and the amount of existing and planned power plant capacity. The actual spot prices for electricity delivered into these markets may vary materially from the forward market prices.

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

price risk management activities use to enter into forward contracts. EME's revenues with respect to such forward contracts include:

Under the PJM market design, locational marginal pricing (sometimes referred to as LMP) has the effect of raising prices at those delivery points affected by transmission congestion. During the past 12 months, an increase in transmission congestion at delivery points east of the Homer City facilities has resulted in prices at the PJM West Hub (which includes delivery points east of the Homer City facilities) being higher than those at the Homer City busbar. Thus, while forward prices at PJM West Hub have historically been higher than the prices at the Homer City busbar by less than 5%, increased congestion during the last 12 months at delivery points east of the Homer City facilities has resulted in prices at PJM West Hub being on average 10% higher than those at the Homer City busbar.

By entering into forward contracts using the PJM West Hub as the delivery point, EME is exposed to "basis risk," which occurs when forward contracts are executed on a different basis (in this case PJM West Hub) than the actual point of delivery (Homer City busbar). In order to mitigate basis risk resulting from forward contracts using PJM West Hub as the delivery point, EME has participated in purchasing firm transmission rights in PJM, and may continue to do so in the future. A firm transmission right provides the holder with a financial instrument to receive actual spot prices at one point of delivery and pay spot prices at another point of delivery. Accordingly, EME's price risk management activities include using firm 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 June 30, 2003:

		24-Hour PJM West Forward Energy Prices*
2003
	July	$	44.17
	August		45.90
	September		36.18
	October		34.17
	November		33.12
	December		34.57
2004 Calendar "strip"(1)			34.34

The ability of EME's subsidiary, EME Homer City, to make payments under the long-term lease entered into as part of the sale-leaseback transaction discussed under "—Off-Balance Sheet Transactions—Sale-Leaseback Transactions," included in Item 7 of MEHC's annual report on Form 10-K for the year ended December 31, 2002, depends on revenues generated by the Homer City

facilities, which depend in part on the market conditions for the sale of capacity and energy. These market conditions are beyond EME's control.

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

The electricity trading arrangements introduced in March 2001 provide, among other things, for the establishment of a range of voluntary short-term power exchanges and brokered markets operating from a year or more in advance to 1 hour prior to the delivery or receipt of power. In the final hour after the notification of all contracts, the system operator can accept bids and offers in the Balancing Mechanism to balance generation and demand and resolve any transmission constraints. There is a mandatory settlement process for recovering imbalances between contracted and metered volumes with strong incentives for being in balance, and a Balancing and Settlement Code Panel to oversee governance of the Balancing Mechanism. The system operator can also purchase system reserve and response services to maintain the quality of the electrical supply directly from generators (generally referred to as "ancillary services"). Ancillary services contracts typically run for up to a year and can consist of both fixed amounts and variable amounts represented by prices for services that are only paid for when actually called upon by the grid operator. A key feature of the trading arrangements is the requirement for firm physical delivery, which means that a generator must deliver, and a consumer must take delivery of, its net contracted positions or pay for any energy imbalance at the imbalance prices calculated by the system operator based on the prices of bids and offers accepted in the Balancing Mechanism. This provides an incentive for parties to contract in advance and for the development of forwards and futures markets. Under these arrangements, there has been an increased emphasis on credit quality, including the need for parent company guarantees or letters of credit for companies below investment grade.

The wholesale price of electricity has decreased significantly in recent years. The reduction has been driven principally by surplus generating capacity and increased competition. During 2002 and the first quarter of 2003, there was further downward pressure on wholesale prices but some recovery in the peak/off peak differentials for the upcoming winter period. This gradual recovery in the forwards market has continued through the second quarter, reflecting an expected reduction in the excess of available physical generating capacity over expected electrical demand for the upcoming winter period.

Despite the difficult market conditions, First Hydro has continued to meet the interest coverage ratios specified in its bond financing documents, and to meet its half yearly interest payments without recourse to the project's debt service reserve. EME believes that if market and trading conditions experienced thus far in 2003 are sustained, First Hydro will continue to be compliant with the requirements of its bond financing documents. This compliance is, however, subject to market conditions for electric energy and ancillary services, which are beyond EME's control.

The Loy Yang B plant and the Valley Power Peaker project sell electrical energy through a centralized electricity pool, which provides for a system of generator bidding, central dispatch and a settlements system based on a clearing market for each half-hour of every day. The National Electricity Market Management Company, operator and administrator of the pool, determines a system marginal price each half-hour. To mitigate exposure to price volatility of the electricity traded into the pool, the Loy Yang B plant and the Valley Power Peaker project have entered into a number of financial hedges. The State Hedge agreement with the State Electricity Commission of Victoria is a long-term contractual arrangement based upon a fixed price commencing May 8, 1997 and terminating October 31, 2016. The State Government of Victoria, Australia guarantees the State Electricity Commission of Victoria's obligations under the State Hedge. From January 2003 to July 2014, approximately 77% of the Loy Yang B plant output sold is hedged under the State Hedge. From August 2014 to October 2016, approximately 56% of the Loy Yang B plant output sold is hedged under the State Hedge. Additionally, the Loy Yang B plant and the Valley Power Peaker project have entered into a number of derivative contracts to mitigate further against price volatility inherent in the electricity pool. These contracts consist of fixed forward electricity contracts and/or cap contracts that expire on various dates through December 31, 2006.

Contact Energy generates about 30% of New Zealand's electricity and is the largest retailer of natural gas and electricity in New Zealand. A substantial portion of Contact Energy's generation output is matched with the demand of its retail electricity customers or sold through forward contracts with other wholesale electricity counterparties. The forward contracts and/or option contracts have varying terms that expire on various dates through June 30, 2010, although the majority of the forward contracts are short term (less than two years).

The New Zealand government released a government policy statement in December 2001, which called for the industry to rationalize the three existing industry codes, form a single governance structure and address transmission investment and pricing issues. An amendment to New Zealand's Electricity Act of 1992 was passed that laid out the form that regulation would take if the industry did not heed the government's call.

Throughout 2002, the industry developed a proposed rulebook with the aim of meeting the New Zealand government's call for rationalization. The adoption of the rulebook required a two-thirds majority vote from each industry sector (i.e., wholesale, networks, and end users). The vote was held in April/May of 2003 and failed to meet the prescribed majorities for introduction. Subsequently, the New Zealand government has stepped in and is proceeding to establish a new governance body to be known as the Electricity Commission along with a set of rules to govern the market. The rules are expected to be largely based on the rulebook developed by the industry.

While the industry governance arrangements were developing, several events in the months preceding the winter of 2003 in New Zealand led to concerns about the security of supply in the country. Wholesale electricity prices increased significantly in response to lower hydro inflows, higher demand, and anticipated restrictions on the availability of thermal fuel. The New Zealand government responded by calling for nationwide energy savings in the order of 10%. Heavy rains in June and July have lessened the short-term concerns about supply security, and the savings program has now ended.

However, there are ongoing concerns that new investment in generation has not been forthcoming and that there is a significant risk that similar events may arise in subsequent years. In March 2003, the

New Zealand government's initial response to the concerns was to notify the industry that significant changes may be required to the electricity market to avoid the risk of insufficient supply in the future.

Furthermore, on May 20, 2003, the New Zealand government announced a policy statement confirming that substantial changes would be made to the electricity market. The main elements were:

Submissions have been made in respect of the policy, which are currently being considered by the New Zealand government. Final details of the policy are currently expected to be developed over the next six months, and it is expected that legislation will be passed by early next year.

In conducting EME's price risk management and trading activities, EME contracts with a number of utilities, energy companies and financial institutions. Due to factors beyond EME's control, market liquidity has decreased significantly since the beginning of 2002, and a number of formerly significant trading parties have completely withdrawn from the market or substantially reduced their trading activities. The reduction in the credit quality of traditional trading parties increases EME's credit risk. In addition, the decrease in market liquidity may require EME to rely more heavily on wholesale electricity sales to wholesale customer markets, which may also increase EME's credit risk. While various industry groups and regulatory agencies have taken steps to address market liquidity, transparency and credit issues, there is no assurance as to when, or how effectively, such efforts will restore market confidence. In the event a counterparty were to default on its trade obligation, EME would be exposed to the risk of possible loss associated with reselling the contracted product at a lower price if the non-performing counterparty were unable to pay the resulting liquidated damages owed to EME. Further, EME would be exposed to the risk of non-payment of accounts receivable accrued for products delivered prior to the time such counterparty defaulted.

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

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

counterparties is based on net exposure under these agreements. The credit ratings supporting the credit risk exposure from counterparties of merchant energy activities at June 30, 2003 were as follows:

Exelon Generation accounted for 21% and 36% of EME's consolidated operating revenues for the first half of 2003 and 2002, respectively. The percentage is less in 2003 because a smaller number of plants are subject to contracts with Exelon Generation. See "Market Risk Exposures—Americas—Illinois Plants." Any failure of Exelon Generation to make payments to Midwest Generation under the power purchase agreements could result in a shortfall of cash available for Midwest Generation to meet its obligations. A default by Midwest Generation in meeting its obligations could in turn have a material adverse effect on EME.

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

MEHC has mitigated the risk of interest rate fluctuations associated with the $385 million term loan due 2006 by arranging for variable rate financing with interest rate swaps. Swaps covering interest accrued from January 2, 2002 to January 2, 2003 expired on January 2, 2003. Subsequently, MEHC entered into swaps that cover interest accrued from January 2, 2003 to July 2, 2004 and April 2, 2003 to July 2, 2004.

Interest rate changes affect the cost of capital needed to operate EME's projects and the lease costs under the Collins Station lease. EME has mitigated the risk of interest rate fluctuations by arranging for fixed rate financing or variable rate financing with interest rate swaps, interest rate options or other hedging mechanisms for a number of its project financings. Interest expense included $23 million and $20 million of additional interest expense for the six months ended June 30, 2003 and 2002, respectively, as a result of interest rate hedging mechanisms. EME has entered into several interest rate swap agreements under which the maturity date of the swaps occurs prior to the final maturity of the underlying debt.

EME had short-term obligations of $298 million at June 30, 2003, consisting of borrowings under EME's corporate credit facility and promissory notes related to Contact Energy. The fair values of these obligations approximated their carrying values at June 30, 2003, and would not have been materially affected by changes in market interest rates. The fair market values of long-term fixed interest rate obligations are subject to interest rate risk. The fair market value of MEHC's total long-term obligations (including current portion) was $7.2 billion at June 30, 2003, compared to the carrying value of $7.6 billion. The fair market value of MEHC's parent only total long-term obligations was $1 billion at June 30, 2003, compared to the carrying value of $1.2 billion.

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

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

During the first six months of 2003, foreign currencies in Australia, New Zealand and the U.K. increased in value compared to the U.S. dollar by 19%, 12% and 3%, respectively (determined by the change in the exchange rates from December 31, 2002 to June 30, 2003). The increase in value of these currencies was the primary reason for the foreign currency translation gain of $63 million during the first six months of 2003.

Contact Energy enters into foreign currency forward exchange contracts to hedge identifiable foreign currency commitments associated with transactions in the ordinary course of business. The contracts are primarily in Australian and U.S. dollars with varying maturities through February 2006. At June 30, 2003, the outstanding notional amount of the contracts totaled $17 million and the fair value of the contracts totaled $(272) thousand.

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

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

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

			June 30, 2003			December 31, 2002
Derivatives:
	Interest rate:
		Interest rate swap/cap agreements	$	(58	)	$	(56	)
		Interest rate options		—			(2	)
	Commodity price:
		Electricity		(90	)		(100	)
	Cross currency interest rate swaps			—			(2	)

In assessing the fair value of EME's non-trading derivative financial instruments, EME uses a variety of methods and assumptions based on the market conditions and associated risks existing at each balance sheet date. The fair value of commodity price contracts takes into account quoted market prices, time value of money, volatility of the underlying commodities and other factors. The 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 June 30, 2003) (in millions):

	Total Fair Value			Maturity <1 year			Maturity 1 to 3 years		Maturity 4 to 5 years			Maturity >5 years
Prices actively quoted	$	(4	)	$	(15	)	$	11	$	—		$	—
Prices based on models and other valuation methods		(86	)		16			8		(12	)		(98	)

Total	$	(90	)	$	1		$	19	$	(12	)	$	(98	)

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

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 activities and its trading activities with third parties 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 June 30, 2003 and December 31, 2002, are set forth below (in millions):

The change in the fair value of trading contracts for the quarter ended June 30, 2003, was as follows (in millions):

Fair value of trading contracts at December 31, 2002	$	92
Net gains from energy trading activities		25
Amount realized from energy trading activities		(19	)

Fair value of trading contracts at June 30, 2003	$	98

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 June 30, 2003) (in millions):

	Total Fair Value		Maturity <1 year			Maturity 1 to 3 years		Maturity 4 to 5 years		Maturity >5 years
Prices actively quoted	$	5	$	5		$	—	$	—	$	—
Prices based on models and other valuation methods		93		(3	)		4		8		84

Total	$	98	$	2		$	4	$	8	$	84

For a discussion of EME's regulatory matters, refer to "Regulatory Matters" on page 22 of MEHC's annual report on Form 10-K for the year ended December 31, 2002 and the notes to the Consolidated Financial Statements set forth therein. There have been no significant developments with regard to regulatory matters that affect disclosures presented in the annual report, except as follows:

Currently, power produced by the Illinois Plants not under contract with Exelon Generation is sold using transmission which must be obtained from Commonwealth Edison under its open-access tariff filed with the FERC. In 2002, Commonwealth Edison applied to the FERC for approval to join PJM in conjunction with American Electric Power, thereby creating an enlarged, contiguous regional transmission organization encompassing a broad regional market. Approval of this application was granted by the FERC on April 1, 2003. Concurrently, the ability of American Electric Power to join PJM has been brought into question by the enactment of legislation in Virginia requiring the approval of Virginia state authorities for any transfer of control from American Electric Power to PJM of American Electric Power transmission assets located in Virginia. On April 16, 2003, Commonwealth Edison and PJM issued a joint press release stating that the integration of Commonwealth Edison into PJM would proceed separately from that of American Electric Power, notwithstanding the absence of a direct transmission link owned by Commonwealth Edison between its service territory and the existing PJM. In response to this announcement, EME and other affected parties filed with the FERC for clarification or rehearing of its April 1, 2003 order, and essentially contested the appropriateness of Commonwealth Edison joining PJM on an "islanded" basis. Commonwealth Edison and PJM had stated their intentions to proceed with integration beginning June 1, 2003, and EME requested expedited treatment of its request for clarification or rehearing. The FERC indicated in subsequent orders that it would act on the request by July 14, 2003, but has not done so. In the meantime, it clarified that a series of pre-conditions imposed by an order issued on July 31, 2002, tentatively approving the stated decisions of Commonwealth Edison and American Electric Power to join PJM together, continue to be applicable to the separate application of Commonwealth Edison to join PJM standing alone. Those conditions include (a) the elimination of multiple transmission rates between PJM and the Midwest Independent System Operator (Midwest ISO), which controls the transmission markets surrounding the service territory of Commonwealth Edison, and (b) an agreement between PJM and the Midwest ISO regarding the management of operations across their "seams," which are required to be done in such a manner as to hold harmless utility customers of the Midwest ISO in Wisconsin and Michigan from the adverse effects of congestion and loop flows caused by the membership of Commonwealth Edison in PJM. On July 23, 2002, the FERC issued an order rejecting

the regional wheeling rates proposed by the Midwest ISO and PJM for "through" and "out" transactions (also known as "RTORs") for power delivered into the areas served by the Midwest ISO and PJM (the Midwest ISO/PJM footprint) and directed them to make a compliance filing eliminating the charges in question. The FERC also set for hearing the question of whether similar RTOR wheeling rates established by the former Alliance companies for power deliveries into the Midwest ISO/PJM footprint should be modified. On August 1, 2003, Commonwealth Edison filed a notice of appeal of the July 31, 2002 order and the June 4, 2003 order on rehearing with the U.S. Court of Appeals for the D.C. Circuit. See also "Market Risk Exposures—Commodity Price Risk—Americas—Illinois Plants."

For a discussion of EME's off-balance sheet transactions, refer to "Off-Balance Sheet Transactions" on page 84 of MEHC's annual report on Form 10-K for the year ended December 31, 2002.

For a discussion of EME's environmental matters, refer to "Environmental Matters and Regulations" on page 104 of MEHC's annual report on Form 10-K for the year ended December 31, 2002 and the notes to the Consolidated Financial Statements set forth therein. There have been no other significant developments with regard to environmental matters that affect disclosures presented in the annual report, except as follows.

On July 25, 2003, the Environmental Protection Agency announced that it will reopen certain aspects of its December 31, 2002 "new source review" regulation in response to petitions from environmental groups and state and local governments challenging aspects of the rule. The Environmental Protection Agency denied a request to stay implementation of the rule pending reconsideration.

Prior to EME's purchase of the Homer City facilities, the Environmental Protection Agency requested information from the prior owners of the plant concerning physical changes at the plant. On February 21, 2003, Midwest Generation received a request for information regarding past operations, maintenance and physical changes at the Illinois coal plants from the Environmental Protection Agency. On July 28, 2003, Commonwealth Edison received a substantially similar request for information from the Environmental Protection Agency related to these same plants. Other than these requests for information, no proceedings have been initiated with respect to any of EME's United States facilities.

A federal court ruled on August 7, 2003 that Ohio Edison Company violated provisions of the federal Clean Air Act by upgrading seven aging coal-fired power plants located at one site without obtaining the necessary preconstruction permits under the new source review program. This decision is currently being reviewed by EME to assess what implications, if any, the decision would have on EME, its assets or operations.

For a discussion of EME's critical accounting policies and estimates, refer to "Critical Accounting Policies and Estimates" on page 52 of MEHC's annual report on Form 10-K for the year ended December 31, 2002.

by approximately $362 million and total liabilities by approximately $434 million. Furthermore, EME expects to record a loss of approximately $72 million in the third quarter of 2003 as a cumulative change of accounting as a result of consolidating this variable interest entity. This loss is primarily due to cumulative losses allocated to the other 50% partner in excess of equity contributions recorded.

For a discussion of market risk sensitive instruments, refer to "Market Risk Exposures" on page 87 of MEHC's annual report on Form 10-K for the year ended December 31, 2002. Refer to "Market Risk Exposures" in Item 2 for an update to that disclosure.

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

There have not been any changes in MEHC's internal control over financial reporting (as such term is defined in Rules 13a-15(f) and 15d-15(f) under the Exchange Act) during the 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.

Exhibit No.		Description
31.1		Certification of the Chief Executive Officer pursuant to Section 302 of the Sarbanes-Oxley Act.
31.2		Certification of the Chief Financial Officer pursuant to Section 302 of the Sarbanes-Oxley Act.
32		Statement Pursuant to 18 U.S.C. Section 1350.
99.1		Homer City Facilities Funds Flow From Operations for the twelve months ended June 30, 2003, incorporated by reference to Exhibit 99.1 to Edison Mission Energy's Form 10-Q for the quarter ended June 30, 2003.
99.2		Illinois Plants Funds Flow From Operations for the twelve months ended June 30, 2003, incorporated by reference to Exhibit 99.2 to Edison Mission Energy's Form 10-Q for the quarter ended June 30, 2003.

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.

(Mark one)
ý	QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
For the Quarterly Period Ended June 30, 2003
or
o	TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
For the transition period from to

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

			Three Months Ended June 30,						Six Months Ended June 30,
			2003			2002			2003			2002
Operating Revenues
	Electric revenues		$	685,924		$	661,160		$	1,366,857		$	1,166,977
	Net gains from price risk management and energy trading			17,792			3,241			10,962			24,607
	Operation and maintenance services			11,597			8,247			20,954			17,781

		Total operating revenues		715,313			672,648			1,398,773			1,209,365

Operating Expenses
	Fuel			243,128			229,551			520,015			434,123
	Plant operations and transmission costs			247,458			208,793			450,284			391,945
	Plant operating leases			51,609			51,266			103,077			103,295
	Operation and maintenance services			7,370			5,913			13,749			13,015
	Depreciation and amortization			72,024			60,706			143,855			118,145
	Asset impairment charges			251,240			—			251,240			—
	Administrative and general			42,774			43,486			81,688			88,649

		Total operating expenses		915,603			599,715			1,563,908			1,149,172

	Operating income (loss)			(200,290	)		72,933			(165,135	)		60,193

Other Income (Expense)
	Equity in income from unconsolidated affiliates			67,640			56,246			131,477			108,820
	Interest and other income			496			2,328			8,243			15,270
	Interest expense			(158,795	)		(154,007	)		(315,263	)		(306,243	)
	Dividends on preferred securities			(5,724	)		(5,302	)		(11,318	)		(10,438	)

		Total other income (expense)		(96,383	)		(100,735	)		(186,861	)		(192,591	)

	Loss from continuing operations before income taxes and minority interest			(296,673	)		(27,802	)		(351,996	)		(132,398	)
	Benefit for income taxes			(117,853	)		(8,726	)		(144,462	)		(55,044	)
	Minority interest			(9,841	)		(10,739	)		(13,902	)		(16,105	)

Loss From Continuing Operations				(188,661	)		(29,815	)		(221,436	)		(93,459	)
	Income (loss) from operations of discontinued foreign subsidiary, net of tax (Note 7)			(2,470	)		9,378			(2,242	)		14,707

Loss Before Accounting Change				(191,131	)		(20,437	)		(223,678	)		(78,752	)
	Cumulative effect of change in accounting, net of tax (Notes 4 and 13)			—			—			(8,571	)		(13,986	)

Net Loss			$	(191,131	)	$	(20,437	)	$	(232,249	)	$	(92,738	)

			Three Months Ended June 30,						Six Months Ended June 30,
			2003			2002			2003			2002

Net Loss			$	(191,131	)	$	(20,437	)	$	(232,249	)	$	(92,738	)
Other comprehensive income (expense), net of tax:
	Foreign currency translation adjustments:
		Foreign currency translation adjustments, net of income tax expense of $2,269 and $2,978 for the three months and $1,304 and $2,111 for the six months ended June 30, 2003 and 2002, respectively		42,130			63,396			63,418			79,255
	Minimum pension liability adjustment			(487	)		—			(286	)		—
	Unrealized gains (losses) on derivatives qualified as cash flow hedges:
		Cumulative effect of change in accounting for derivatives, net of income tax expense of $5,562 for the three and six months ended June 30, 2002		—			6,357			—			6,357
		Other unrealized holding gains (losses) arising during period, net of income tax expense of $20,641 and $2,916 for the three months and $2,844 and $14,556 for the six months ended June 30, 2003 and 2002, respectively		25,140			(23,894	)		21,668			14,502
		Reclassification adjustments included in net loss, net of income tax expense (benefit) of $447 and $(1,389) for the three months and $(3,484) and $(961) for the six months ended June 30, 2003 and 2002, respectively		(4,675	)		2,588			(5,944	)		3,294

Other comprehensive income				62,108			48,447			78,856			103,408

Comprehensive Income (Loss)			$	(129,023	)	$	28,010		$	(153,393	)	$	10,670

			June 30, 2003		December 31, 2002
Assets
Current Assets
	Cash and cash equivalents		$	910,177	$	734,374
	Accounts receivable—trade, net of allowance of $14,134 and $13,113 in 2003 and 2002, respectively			390,574		296,193
	Accounts receivable—affiliates			27,049		41,478
	Assets under price risk management and energy trading			62,537		33,742
	Inventory			165,348		176,437
	Prepaid expenses and other			94,576		169,312

		Total current assets		1,650,261		1,451,536

Investments in Unconsolidated Affiliates				1,749,605		1,645,253

Property, Plant and Equipment				8,125,234		7,649,791
	Less accumulated depreciation and amortization			1,083,670		888,060

		Net property, plant and equipment		7,041,564		6,761,731

Other Assets
	Goodwill			774,941		659,837
	Deferred financing costs			79,984		90,187
	Long-term assets under price risk management and energy trading			118,504		112,571
	Restricted cash and other			719,221		635,113

		Total other assets		1,692,650		1,497,708

Assets of Discontinued Operations				4,826		10,273

Total Assets			$	12,138,906	$	11,366,501

			June 30, 2003			December 31, 2002
Liabilities and Shareholder's Equity
Current Liabilities
	Accounts payable—affiliates		$	78,666		$	12,985
	Accounts payable and accrued liabilities			451,710			456,540
	Liabilities under price risk management and energy trading			146,661			45,494
	Interest payable			158,271			152,231
	Short-term obligations			298,148			77,551
	Current maturities of long-term obligations			1,221,374			1,089,918

		Total current liabilities		2,354,830			1,834,719

Long-Term Obligations Net of Current Maturities				6,404,062			6,033,775

Long-Term Deferred Liabilities
	Deferred taxes and tax credits			1,148,845			1,180,900
	Deferred revenue			536,441			454,438
	Long-term incentive compensation			28,811			29,486
	Long-term liabilities under price risk management and energy trading			126,650			169,219
	Other			196,291			219,703

		Total long-term deferred liabilities		2,037,038			2,053,746

Liabilities of Discontinued Operations				4,210			3,024

Total Liabilities				10,800,140			9,925,264

Minority Interest				457,239			423,844

Preferred Securities of Subsidiaries
	Company-obligated mandatorily redeemable security of partnership holding solely parent debentures			150,000			150,000
	Subject to mandatory redemption			146,475			131,225

		Total preferred securities of subsidiaries		296,475			281,225

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			2,220,669			2,218,285
	Retained deficit			(1,497,527	)		(1,265,171	)
	Accumulated other comprehensive loss			(138,090	)		(216,946	)

Total Shareholder's Equity				585,052			736,168

Total Liabilities and Shareholder's Equity			$	12,138,906		$	11,366,501

			Six Months Ended June 30,
			2003			2002
Cash Flows From Operating Activities
	Loss from continuing operations, after accounting change, net		$	(230,007	)	$	(107,445	)
	Adjustments to reconcile income to net cash provided by operating activities:
		Equity in income from unconsolidated affiliates		(131,477	)		(108,820	)
		Distributions from unconsolidated affiliates		65,127			176,890
		Depreciation and amortization		143,855			118,145
		Deferred taxes and tax credits		(140,003	)		(49,423	)
		Asset impairment charges		251,240			—
		Cumulative effect of change in accounting, net of tax		8,571			13,986
		Amortization of discount on long-term obligations		2,122			1,997
	Changes in operating assets and liabilities:
		Decrease (increase) in accounts receivable		(44,923	)		144,218
		Decrease (increase) in inventory		12,976			(19,905	)
		Decrease (increase) in prepaid expenses and other		94,278			(15,438	)
		Increase (decrease) in accounts payable and accrued liabilities		31,360			(70,986	)
		Increase in interest payable		74,074			75,199
		Increase in long-term incentive compensation		2,951			2,204
		Decrease (increase) in net assets under risk management		9,571			(27,755	)
	Other operating, net			(110,563	)		(70,942	)

				39,152			61,925
	Operating cash flows from discontinued operations			104			50,934

		Net cash provided by operating activities		39,256			112,859

Cash Flows From Financing Activities
	Borrowings on long-term debt and lease swap agreements			226,797			197,048
	Payments on long-term debt agreements			(40,461	)		(314,248	)
	Short-term financing and lease swap agreements, net			303,100			(29,661	)
	Contributions from parent			—			600
	Financing costs			(2,531	)		—

				486,905			(146,261	)
	Financing cash flows from discontinued operations			—			(8,693	)

		Net cash provided by (used in) financing activities		486,905			(154,954	)

Cash Flows From Investing Activities
	Investments in and loans to energy projects			(42,167	)		(5,358	)
	Purchase of common stock of acquired companies			(274,813	)		—
	Purchase of power sales agreement			—			(80,084	)
	Capital expenditures			(79,104	)		(175,661	)
	Proceeds from return of capital and loan repayments			11,903			83,754
	Proceeds from sale of assets			—			43,986
	Decrease in restricted cash			3,727			103,716
	Investments in other assets			9,119			2,164
	Other, net			—			(14,304	)

				(371,335	)		(41,787	)
	Investing cash flows from discontinued operations			4,908			978

		Net cash used in investing activities		(366,427	)		(40,809	)

Effect of exchange rate changes on cash				16,124			27,308

Net increase (decrease) in cash and cash equivalents				175,858			(55,596	)
Cash and cash equivalents at beginning of period				734,450			435,191

Cash and cash equivalents at end of period				910,308			379,595
Cash and cash equivalents classified as part of discontinued operations				(131	)		(32,812	)

Cash and cash equivalents of continuing operations			$	910,177		$	346,783

	Americas		Asia Pacific		Europe		Total
Carrying amount at December 31, 2002	$	2	$	384	$	274	$	660
Goodwill resulting from an acquisition(1)		—		43		—		43
Translation adjustments and other		—		65		7		72

Carrying amount at June 30, 2003	$	2	$	492	$	281	$	775

	June 30, 2003		December 31, 2002
Coal and fuel oil	$	96	$	111
Spare parts, materials and supplies		69		65

Total	$	165	$	176

	Currency Translation Adjustments			Unrealized Gains (Losses) on Cash Flow Hedges			Minimum Pension Liability Adjustment			Accumulated Other Comprehensive Income (Loss)
Balance at December 31, 2002	$	(8	)	$	(198	)	$	(11	)	$	(217	)
Current period change		63			16			—			79

Balance at June 30, 2003	$	55		$	(182	)	$	(11	)	$	(138	)

	Amount of Commitments Per Period in U.S.$
Commercial Commitments	Amount of Commitments Per Period in U.S.$												Total Amounts Committed
Commercial Commitments	2003		2004		2005		2006		2007		Thereafter		Total Amounts Committed
Standby letters of credit	$	125	$	57	$	—	$	—	$	—	$	1	$	183
Firm commitments to contribute project equity		23		—		—		—		—		—		23
Capital improvements at EME's project subsidiaries		18		3		4		4		—		—		29

Total Commercial Commitments	$	166	$	60	$	4	$	4	$	—	$	1	$	235

Three Months Ended		Americas			Asia Pacific		Europe			Corporate/ Other			Total
June 30, 2003
Operating revenues from consolidated subsidiaries		$	330		$	257	$	110		$	—		$	697
Net gains (losses) from price risk management and energy trading			23			1		(6	)		—			18

	Total operating revenues	$	353		$	258	$	104		$	—		$	715

Income (loss) from continuing operations before income taxes and minority interest		$	(195	)	$	53	$	(19	)	$	(136	)	$	(297	)

June 30, 2002
Operating revenues from consolidated subsidiaries		$	364		$	198	$	111		$	(3	)	$	670
Net gains (losses) from price risk management and energy trading			5			1		(1	)		(2	)		3

Total operating revenues		$	369		$	199	$	110		$	(5	)	$	673

Income (loss) from continuing operations before income taxes and minority interest		$	63		$	48	$	6		$	(145	)	$	(28	)

Six Months Ended		Americas			Asia Pacific			Europe			Corporate/ Other			Total
June 30, 2003
Operating revenues from consolidated subsidiaries		$	698		$	450		$	242		$	(2	)	$	1,388
Net gains (losses) from price risk management and energy trading			27			(5	)		(11	)		—			11

	Total operating revenues	$	725		$	445		$	231		$	(2	)	$	1,399

Income (loss) from continuing operations before income taxes and minority interest		$	(156	)	$	69		$	5		$	(270	)	$	(352	)

June 30, 2002
Operating revenues from consolidated subsidiaries		$	623		$	339		$	226		$	(4	)	$	1,184
Net gains (losses) from price risk management and energy trading			23			—			3			(1	)		25

Total operating revenues		$	646		$	339		$	229		$	(5	)	$	1,209

Income (loss) from continuing operations before income taxes and minority interest		$	50		$	75		$	31		$	(288	)	$	(132	)

Amount		Due Date
(in millions)
$	911	December 11, 2003
	808	December 15, 2004

$	1,719

	Into ComEd*						Into Cinergy*
Historical Energy Prices	Into ComEd*						Into Cinergy*
Historical Energy Prices	On-Peak(1)		Off-Peak(1)		24-Hr		On-Peak(1)		Off-Peak(1)		24-Hr
January	$	42.62	$	20.77	$	30.81	$	44.38	$	21.46	$	32.00
February		54.43		23.13		37.81		58.09		24.00		39.99
March		47.96		22.35		33.92		51.68		24.34		36.69
April		39.12		15.05		26.67		41.12		15.96		28.11
May		29.59		10.80		19.57		28.89		10.68		19.18
June		30.27		8.17		19.22		28.41		8.31		18.36

Six-Month Average	$	40.67	$	16.71	$	28.00	$	42.10	$	17.46	$	29.06

			Three Months Ended June 30,						Six Months Ended June 30,
			2003			2002			2003			2002
Statistics—Coal-Fired Generation
	Generation (in GWhr):
		Power purchase agreement		3,075			6,049			6,675			12,047
		Merchant		2,674			120			5,878			356

		Total coal-fired generation		5,749			6,169			12,553			12,403

	Availability(1)			80.9	%		77.9	%		77.9	%		79.5	%
	Forced outage rate(2)			7.9	%		8.8	%		7.9	%		6.4	%
	Average realized energy price/MWh:
		Power purchase agreement	$	18.66		$	20.34		$	18.31		$	18.53
		Merchant	$	25.01		$	21.79		$	25.27		$	20.26

		Total coal-fired generation	$	21.61		$	20.36		$	21.57		$	18.57

	Capacity revenues (in millions)		$	94		$	149		$	126		$	201

		Three Months Ended June 30,						Six Months Ended June 30,
		2003			2002			2003			2002
Statistics
	Generation (in GWhr)		3,018			2,239			6,648			4,934
	Availability(1)		76.7	%		56.5	%		82.8	%		61.8	%
	Forced outage rate(2)		4.1	%		23.0	%		5.5	%		26.2	%
	Average realized energy price/MWh	$	31.52		$	30.68		$	35.99		$	28.45
	Capacity revenues (in millions)	$	7		$	13		$	10		$	26

		Into ComEd*						Into Cinergy*
Forward Energy Prices		Into ComEd*						Into Cinergy*
Forward Energy Prices		On-Peak(1)		Off-Peak(1)		24-Hr		On-Peak(1)		Off-Peak(1)		24-Hr
2003
	July	$	47.75	$	19.50	$	32.87	$	44.25	$	19.50	$	31.21
	August		48.00		21.00		33.19		46.00		21.00		32.29
	September		33.38		18.50		25.44		34.00		18.50		25.73
	October		32.75		17.25		24.92		33.50		18.00		25.67
	November		33.25		18.25		24.58		34.00		19.00		25.33
	December		34.25		19.25		26.35		35.00		20.00		27.10
2004 Calendar "strip"(2)			36.59		19.42		27.46		37.25		20.42		28.30

S&P Credit Rating	June 30, 2003
	(in millions)
A or higher	$	61
A-		14
BBB+		64
BBB		51
BBB-		6
Below investment grade		6

Total	$	202

	June 30, 2003				December 31, 2002
	Assets		Liabilities		Assets		Liabilities
Electricity	$	140	$	42	$	109	$	15
Other		—		—		—		2

Total	$	140	$	42	$	109	$	17

Date of Report	Date Filed	Item(s) Reported
May 7, 2003	May 7, 2003	7, 9
May 14, 2003	May 15, 2003	5
June 25, 2003	June 27, 2003	5

		MISSION ENERGY HOLDING COMPANY (REGISTRANT)
		By:	/s/ Kevin M. Smith Kevin M. Smith Senior Vice President and Chief Financial Officer
		Date:	August 13, 2003