Edgar Filing: EDISON MISSION ENERGY

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As filed with the Securities and Exchange Commission on October 12, 2006

Registration No. 333-137579

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

AMENDMENT NO. 1
TO
FORM S-4
REGISTRATION STATEMENT
UNDER
THE SECURITIES ACT OF 1933

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

Delaware
(State or other jurisdiction of
incorporation or organization)

4911
(Primary Standard Industrial
Classification Code Number)

95-4031807
(I.R.S. Employer
Identification No.)

18101 Von Karman Avenue, Suite 1700
Irvine, California 92612
(949) 752-5588
(Address, including zip code, and telephone number, including area code, of registrant's principal executive offices)

Steven D. Eisenberg, Esq.
Edison Mission Energy
18101 Von Karman Avenue, Suite 1700
Irvine, California 92612
(949) 752-5588
(Name, address, including zip code, and telephone number, including area code, of agent for service)

With copies to:
Robert M. Chilstrom, Esq.
Harold F. Moore, Esq.
Skadden, Arps, Slate, Meagher & Flom LLP
Four Times Square
New York, New York 10036-6522
(212) 735-3000

Approximate date of commencement of proposed sale to the public: As soon as practicable after this registration statement becomes effective.

If the securities being registered on this Form are being offered in connection with the formation of a holding company and there is compliance with General Instruction G, check the following box. o

If this Form is filed to register additional securities for an offering pursuant to Rule 462(b) under the Securities Act, check the following box and list the Securities Act registration statement number of the earlier effective registration statement for the same offering. o

If this Form is a post-effective amendment filed pursuant to Rule 462(d) under the Securities Act, check the following box and list the Securities Act registration statement number of the earlier effective registration statement for the same offering. o

The Registrant hereby amends this registration statement on such date or dates as may be necessary to delay its effective date until the Registrant shall file a further amendment which specifically states that this Registration Statement shall thereafter become effective in accordance with Section 8(a) of the Securities Act of 1933, or until the Registration Statement shall become effective on such date as the Securities and Exchange Commission, acting pursuant to the said Section 8(a), may determine.

The information in this prospectus is not complete and may be changed. These securities may not be sold until the registration statement filed with the Securities and Exchange Commission is effective. This prospectus is not an offer to sell these securities, and it is not soliciting an offer to buy, these securities in any state where the offer or sale is not permitted.

Subject to completion, dated October 12, 2006.

PROSPECTUS

Edison Mission Energy

Offer to exchange $500,000,000 aggregate principal amount of 7.50% Senior Notes due
2013 (CUSIPs 281023 AL 5, U27811 AC 9 and 281023 AM 3) for $500,000,000
7.50% Senior Notes due 2013 which have been registered under the Securities
Act of 1933, as amended, and $500,000,000 aggregate principal amount of
7.75% Senior Notes due 2016 (CUSIPs 281023 AP 6, U27811 AD 7
and 281023 AQ 4) for $500,000,000 7.75% Senior Notes due 2016
which have been registered under the Securities Act

The exchange offer will expire at 5:00 p.m., New York City time,
on November 9, 2006, unless extended.

Terms of the exchange offer:

•: The new notes are being registered with the Securities and Exchange Commission and are being offered in exchange for the old notes that previously were issued in an offering exempt from the Securities and Exchange Commission's registration requirements.
•: The terms of the exchange offer are summarized below and more fully described in this prospectus.
•: We will exchange the new notes to be issued for all outstanding old notes that are validly tendered and not withdrawn pursuant to the exchange offer.
•: You may withdraw tenders of old notes at any time prior to the expiration of the exchange offer.
•: The terms of the new notes are substantially identical to those of the old notes, except that the transfer restrictions and registration rights relating to the old notes will not apply to the new notes.
•: The exchange of old notes for new notes will not be a taxable transaction for United States federal income tax purposes, but you should see the discussion under the heading "Material United States Federal Tax Consequences."
•: We will not receive any cash proceeds from the exchange offer.
•: We issued the old notes in a transaction not requiring registration under the Securities Act, and as a result, their transfer is restricted. We are making the exchange offer to satisfy your registration rights, as a holder of the old notes.

See "Risk Factors" beginning on page 11 for a discussion of certain risks that you should consider prior to tendering your outstanding old notes for exchange.

Neither the Securities and Exchange Commission nor any state securities commission has approved or disapproved of these securities or passed upon the adequacy or accuracy of this prospectus. Any representation to the contrary is a criminal offense.

Prospectus dated October 12, 2006

TABLE OF CONTENTS

		Page
ABOUT THIS PROSPECTUS		i
WHERE YOU CAN FIND MORE INFORMATION		i
FORWARD-LOOKING STATEMENTS		ii
INDUSTRY AND MARKET DATA		iii
NOTICE TO NEW HAMPSHIRE RESIDENTS		iii
SUMMARY		1
RISK FACTORS		11
THE EXCHANGE OFFER		20
USE OF PROCEEDS		27
CAPITALIZATION		28
SELECTED CONSOLIDATED FINANCIAL DATA		29
MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS		32
QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK		97
BUSINESS		97
MANAGEMENT		117
EXECUTIVE COMPENSATION		119
CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS		128
DESCRIPTION OF THE NOTES		129
MATERIAL U.S. FEDERAL INCOME TAX CONSEQUENCES		140
PLAN OF DISTRIBUTION		143
CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE		144
LEGAL MATTERS		144
EXPERTS		144
INDEX TO CONSOLIDATED FINANCIAL STATEMENTS		F-1

ABOUT THIS PROSPECTUS

This prospectus is part of a registration statement on Form S-4 under the Securities Act of 1933 (as amended, the "Securities Act") that we filed with the Securities and Exchange Commission (the "SEC"). You should rely only on the information contained in this prospectus or to which we have referred you. We have not authorized anyone to provide you with information that is different. We are not making an offer of these securities in any state where the offer is not permitted. The information in this prospectus may only be accurate on the date of this prospectus.

This prospectus contains summaries, believed to be accurate, of some of the terms of specific documents, but reference is made to the actual documents, copies of which will be made available upon request, for the complete information contained in those documents. All summaries are qualified in their entirety by this reference.

WHERE YOU CAN FIND MORE INFORMATION

We file annual, quarterly and current reports and other information with the SEC. You may read and copy any document that we file at the public reference rooms of the SEC at 100 F Street, N.E., Washington, D.C. 20549. You may obtain information on the operation of the public reference rooms by calling the SEC at 1-800-SEC-0330. The SEC also maintains an internet site at http://www.sec.gov,

from which you can access our filings. Any statement made in this prospectus concerning any document filed with the SEC is not necessarily complete, and reference is made to the copy of the document filed.

This prospectus incorporates important business and financial information about us from documents that we have filed with the SEC but have not included in or delivered with this prospectus. We will provide you with copies of this information, without charge, upon written or oral request to:

Edison Mission Energy
18101 Von Karman Avenue, Suite 1700
Irvine, California 92612
(949) 752-5588
Attention: General Counsel

To obtain timely delivery of requested documents before the expiration of the exchange offer, you must request them no later than November 2, 2006, which is five business days before the exchange offer expires.

FORWARD-LOOKING STATEMENTS

This prospectus and the documents incorporated herein by reference contain "Forward-Looking Statements" within the meaning of the Private Securities Litigation Reform Act of 1995. These forward-looking statements reflect our current expectations and projections about future events based on our knowledge of present facts and circumstances as of the date of this prospectus and assumptions about future events and include any statement that does not directly relate to a historical or current fact. Other information distributed by us that is incorporated by reference in this prospectus, or that refers to this prospectus, may also contain forward-looking statements. In this prospectus and elsewhere, the words "expects," "believes," "anticipates," "estimates," "projects," "intends," "plans," "probable," "may," "will," "could," "would," "should," and variations of such words and similar expressions, or discussions of strategy or plans, are intended to identify forward-looking statements. Such forward-looking statements necessarily involve risks and uncertainties that could cause actual results to differ materially from those anticipated. Some of the risks, uncertainties and other important factors that could cause results to differ, or that otherwise could impact us or our subsidiaries, include but are not limited to:

•: supply and demand for electric capacity and energy, and the resulting prices and dispatch volumes, in the wholesale markets to which our generating units have access;
•: the cost and availability of coal, natural gas and fuel oil, and associated transportation;
•: market volatility and other market conditions that could increase our obligations to post collateral beyond the amounts currently expected, and the potential effect of such conditions on our ability and the ability of our subsidiaries to provide sufficient collateral in support of their hedging activities and purchases of fuel;
•: the cost and availability of emission credits or allowances;
•: transmission congestion in and to each market area and the resulting differences in prices between delivery points;
•: governmental, statutory, regulatory or administrative changes or initiatives affecting us or the electricity industry generally, including the market structure rules applicable to each market and environmental regulations that could require additional expenditures or otherwise affect our cost and manner of doing business;

•: the extent of additional supplies of capacity, energy and ancillary services from current competitors or new market entrants, including the development of new generation facilities and technologies that may be able to produce electricity at a lower cost than our generating facilities and/or increased access by competitors to our markets as a result of transmission upgrades;
•: the difficulty of predicting wholesale prices, transmission congestion, energy demand, and other activities in the complex and volatile markets in which we and our subsidiaries participate;
•: operating risks, including equipment failure, availability, heat rate and output;
•: effects of legal proceedings, changes in or interpretations of tax laws, rates or policies, and changes in accounting standards;
•: general political, economic and business conditions;
•: weather conditions, natural disasters and other unforeseen events; and
•: our continued participation and the continued participation by our subsidiaries in tax-allocation and payment agreements with our respective affiliates.

Readers are urged to read this entire prospectus and carefully consider the risks, uncertainties and other factors that affect our business. There may be other factors that may cause our actual results to differ materially from the results referred to in the forward-looking statements. All forward-looking statements attributable to us or persons acting on our behalf apply only as of the date of this prospectus and are expressly qualified in their entirety by the cautionary statements included and incorporated by reference in this prospectus. We undertake no obligation to publicly update or revise any forward-looking statement whether as a result of new information, future events or otherwise. Readers should review future reports filed by us with the SEC.

INDUSTRY AND MARKET DATA

Industry and market data used throughout this prospectus, including the SEC filings incorporated by reference, were obtained through internal company research, surveys and studies conducted by third parties and industry and general publications. Neither we nor the initial purchasers have independently verified, or make any representations about the accuracy of, market and industry data from third-party sources. While we believe internal company estimates are reliable and market definitions are appropriate, they have not been verified by any independent sources, and neither we nor the initial purchasers make any representations about the accuracy of such estimates.

NOTICE TO NEW HAMPSHIRE RESIDENTS

NEITHER THE FACT THAT A REGISTRATION STATEMENT OR AN APPLICATION FOR A LICENSE HAS BEEN FILED UNDER CHAPTER 421 B OF THE NEW HAMPSHIRE UNIFORM SECURITIES ACT ("RSA 421-B"), WITH THE STATE OF NEW HAMPSHIRE NOR THE FACT THAT A SECURITY IS EFFECTIVELY REGISTERED OR A PERSON IS LICENSED IN THE STATE OF NEW HAMPSHIRE CONSTITUTES A FINDING BY THE SECRETARY OF STATE THAT ANY DOCUMENT FILED UNDER RSA 421 B IS TRUE, COMPLETE AND NOT MISLEADING. NEITHER ANY SUCH FACT NOR THE FACT THAT AN EXEMPTION OR EXCEPTION IS AVAILABLE FOR A SECURITY OR A TRANSACTION MEANS THAT THE SECRETARY OF STATE HAS PASSED IN ANY WAY UPON THE MERITS OR QUALIFICATIONS OF, OR RECOMMENDED OR GIVEN APPROVAL TO, ANY PERSON, SECURITY, OR TRANSACTION. IT IS UNLAWFUL TO MAKE, OR CAUSE TO BE MADE, TO ANY PROSPECTIVE PURCHASER, CUSTOMER OR CLIENT ANY REPRESENTATION INCONSISTENT WITH THE PROVISIONS OF THIS PARAGRAPH.

iii

SUMMARY

This summary highlights information about us and the exchange offer. This summary may not contain all the information that is important to you. Therefore, you should read this summary and the more detailed information appearing elsewhere in this prospectus. We encourage you to read this prospectus in its entirety. In this prospectus, the terms "the Company," "we," "our," "ours" and "us" refer to Edison Mission Energy and its direct and indirect subsidiaries unless otherwise stated or the context otherwise requires. You should consider the issues discussed in the "Risk Factors" section beginning on page 11 in evaluating your investment in the Notes.

Edison Mission Energy

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

EME was formed in 1986 with two domestic operating power plants. As of June 30, 2006, EME's continuing operations consisted of owned or leased interests in 29 operating power plants with an aggregate net physical capacity of 10,473 megawatts, or MW, of which EME's capacity pro rata share was 9,295 MW.

EME operates in one line of business, independent power production, with all of its continuing operations located in the United States, except the Doga project in Turkey. Operating revenues are primarily related to the sale of power Generated from our fossil fuel plants located in Illinois, and the Homer City electric generating station located in Pennsylvania. EME is headquartered in Irvine, California with additional offices located in Chicago, Illinois and Boston, Massachusetts.

EME is a Delaware corporation. Our principal executive offices are located at 18101 Von Karman Avenue, Suite 1700, Irvine, California 92612 and its telephone number at that address is (949) 752-5588. You can find more information about us posted on the Internet website maintained by our ultimate parent, Edison International, at www.edison.com. The information on Edison International's website is not part of this prospectus.

Overview of Facilities

As of June 30, 2006, our operations consisted of ownership or leasehold interests in the following operating power plants:

Power Plants				Location	Fuel Type	Ownership Interest		Net Physical Capacity (in MW)	EME's capacity pro rata share (in MW)
Merchant Power Plants
	Illinois Plants (6 plants)(1)			Illinois	Coal/Oil/Gas	100	%	5,918	5,918
	Homer City(1)			Pennsylvania	Coal	100	%	1,884	1,884
Contracted Power Plants
Domestic
	Big 4 Projects
		Kern River(1)		California	Natural Gas	50	%	300	150
		Midway-Sunset(1)		California	Natural Gas	50	%	225	113
		Sycamore(1)		California	Natural Gas	50	%	300	150
		Watson		California	Natural Gas	49	%	385	189
	Westside Projects
		Coalinga(1)		California	Natural Gas	50	%	38	19
		Mid-Set(1)		California	Natural Gas	50	%	38	19
		Salinas River(1)		California	Natural Gas	50	%	38	19
		Sargent Canyon(1)		California	Natural Gas	50	%	38	19
	American Bituminous(1)			West Virginia	Waste Coal	50	%	80	40
	March Point			Washington	Natural Gas	50	%	140	70
	Sunrise(1)			California	Natural Gas	50	%	572	286
	Huntington			New York	Biomass	38	%	25	9
	Wind Projects
		San Juan Mesa(1)		New Mexico	Wind	75	%	120	90
		Minnesota Wind Projects (7 plants)		Minnesota	Wind	50-99	%	83	67
		Storm Lake		Iowa	Wind	100	%	109	109
International
	Doga(1)			Turkey	Natural Gas	80	%	180	144

			Total					10,473	9,295

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

In January 2006, we acquired a 99.9% interest in the Wildorado wind project, which owns a 161 MW wind farm located in northern Texas. During the first quarter of 2006, construction started on the Wildorado project, and commercial operation is expected to begin in April 2007. In April 2006, we received, as a capital contribution from our parent, ownership interests in a 192 MW portfolio of wind projects located in Iowa and Minnesota and a small biomass project. These projects were previously owned by our affiliate, Edison Capital.

Refinancing Plans

Tender offer and consent solicitation. On May 5, 2006, we launched a tender offer for any and all of our outstanding 10% Senior Notes due 2008 (the "2008 Senior Notes") and 9.875% Senior Notes due 2011 (the "2011 Senior Notes"), combined with a solicitation of consents from registered holders

of these senior notes to amendments to the indentures pursuant to which these notes were issued, in each case, to eliminate substantially all the restrictive covenants, eliminate or modify certain events of default and eliminate or modify related provisions contained in each indenture. We refer to this transaction as the Tender Offer and Consent Solicitation in this prospectus. These proposed amendments included amendments necessary to permit us to increase the size of our secured corporate credit facility.

On June 6, 2006, we completed our Tender Offer and Consent Solicitation. The amendments to the indentures pursuant to which the 2008 Senior Notes and 2011 Senior Notes were issued, which were proposed in connection with the Tender Offer and Consent Solicitation, became operative. The amendments to the indentures eliminated substantially all the restrictive covenants, eliminated or modified certain events of default and eliminated or modified related provisions contained in each indenture.

Notes offering. On June 6, 2006, we completed our private offering of $500 million aggregate principal amount of our 7.50% Senior Notes due 2013 (the "Old 2013 Notes") and $500 million aggregate principal amount of our 7.75% Senior Notes due 2016 (the "Old 2016 Notes" and, together with the Old 2013 Notes, the "Old Notes").

We used the net proceeds of the offering of the Old Notes, together with cash on hand, to purchase $368.9 million in aggregate principal amount of the 2008 Senior Notes (representing approximately 92.2% of the previously outstanding 2008 Senior Notes) and $595.6 million in aggregate principal amount of the 2011 Senior Notes (representing 99.3% of the previously outstanding 2011 Senior Notes) that were validly tendered pursuant to the Tender Offer and Consent Solicitation. The net proceeds of the offering of the Old Notes, together with cash on hand, were also used to pay related tender premiums. The total tender premiums paid on all 2008 Senior Notes and 2011 Senior Notes validly tendered were $106.8 million, and the total consent fees paid on all 2008 Senior Notes and 2011 Senior Notes validly tendered were $28.8 million. The total accrued and unpaid interest paid on validly tendered 2008 Senior Notes and 2011 Senior Notes was $19.7 million.

Replacement of secured credit facility. On June 15, 2006, we replaced our existing $98 million secured credit facility with a new $500 million secured revolving credit facility.

The refinancing plan improved our liquidity, extended the maturity dates of our indebtedness, reduced annual interest costs, and improved the operating flexibility of the covenants associated with our outstanding debt. Completion of the refinancing plan pursuant to the Tender Offer and Consent Solicitation resulted in a significant charge against income due to the early retirement of the outstanding senior notes.

The Exchange Offer

As part of our Old Notes offering, which was completed on June 6, 2006, we entered into a registration rights agreement in respect of the Old Notes in which we agreed, among other things, to deliver this prospectus to you and to complete an exchange offer for the Old Notes. Below is a summary of the terms of the exchange offer.

Securities Offered	$1,000,000,000 principal amount of New Notes, consisting of:
	$500,000,000 principal amount of 7.50% Senior Notes due 2013 (the "New 2013 Notes"); and
	$500,000,000 principal amount of 7.75% Senior Notes due 2016 (the "New 2016 Notes" and, together with the New 2013 Notes, the "New Notes"). The form and terms of these New Notes are identical in all material respects to those of the corresponding tranche of Old Notes. The New Notes, however, will not contain transfer restrictions and registration rights applicable to the Old Notes.
The Exchange Offer	We are offering to issue up to $1,000,000,000 aggregate principal amount of the New Notes in exchange for a like principal amount of the Old Notes in order to satisfy our obligations under the registration rights agreement that we entered into when the Old Notes were issued.
Expiration Date; Tenders	The exchange offer will expire at 5:00 p.m., New York City time, on November 9, 2006, unless extended in our sole and absolute discretion. By tendering your Old Notes, you represent that:
	•	you are not our "affiliate," as defined in Rule 405 under the Securities Act;
	•	any New Notes you receive in the exchange offer are being acquired by you in the ordinary course of your business;
	•	at the time of commencement of the exchange offer, neither you nor, to your knowledge, anyone receiving New Notes from you, has any arrangement or understanding with any person to participate in the distribution, as defined in the Securities Act, of the Old Notes or the New Notes in violation of the Securities Act;
	•	if you are not a participating broker-dealer, you are not engaged in, and do not intend to engage in, the distribution, as defined in the Securities Act, of the Old Notes or the New Notes; and

	•	if you are a broker-dealer, you will receive the New Notes for your own account in exchange for Old Notes that were acquired by you as a result of your market-making or other trading activities and that, you will deliver a prospectus in connection with any resale of the New Notes you receive. For further information regarding resales of the New Notes by participating broker-dealers, see "Plan of Distribution."
	We will extend the duration of the exchange offer as required by applicable law, and may choose to extend if we decide to give holders of Old Notes more time to tender their Old Notes.
Withdrawal; Non-Acceptance	You may withdraw any Old Notes tendered in the exchange offer at any time prior to 5:00 p.m., New York City time, on November 9, 2006. If for any reason the tender of any Old Notes is not accepted for exchange, such withdrawn or unaccepted Old Notes will be credited to the tendering holder's account at The Depository Trust Company, or DTC. For further information regarding the withdrawal of tendered Old Notes, see "The Exchange Offer—Terms of the Exchange Offer" and "The Exchange Offer—Withdrawal Rights."
Conditions to the Exchange Offer	The exchange offer is subject to certain conditions, which we may waive. See "The Exchange Offer—Conditions to the Exchange Offer" for more information regarding the conditions to the exchange offer.
Procedures for Tendering Old Notes	To participate in the exchange offer, you must tender your Old Notes by using the book-entry transfer procedures described below and transmitting an agent's message to the exchange agent on or prior to the expiration or termination of the exchange offer. In order for a book-entry transfer to constitute a valid tender of your Old Notes in the exchange offer, Wells Fargo Bank, National Association, as exchange agent, must receive a confirmation of book-entry transfer of your Old Notes into the exchange agent's account at DTC prior to the expiration or termination of the exchange offer. For more information regarding the use of book-entry transfer procedures, including a description of the required agent's message, see "The Exchange Offer—Book-Entry Transfer."
Special Procedures for Beneficial Owners	If you are a beneficial owner whose Old Notes are registered in the name of the broker, dealer, commercial bank, trust company or other nominee and you wish to tender your Old Notes in the exchange offer, you should promptly contact the person in whose name the Old Notes are registered, and instruct that person to tender on your behalf.

Certain United States Federal Income Tax Consequences	The exchange of Old Notes for New Notes pursuant to the exchange offer will not be a taxable transaction for U.S. federal income tax purposes. See "Material U.S. Federal Income Tax Consequences" for more information regarding the tax consequences of the exchange offer to you.
Use of Proceeds	We will not receive any cash proceeds from the exchange offer.
Exchange Agent	Wells Fargo Bank, National Association is the exchange agent for the exchange offer. You can find the address and telephone number of the exchange agent below in "The Exchange Offer—Exchange Agent."
Resales	Based on interpretations by the staff of the SEC, as set forth in no-action letters issued to third parties, we believe that the New Notes issued in the exchange offer may be offered for resale, resold or otherwise transferred by you without compliance with the registration and prospectus delivery requirements of the Securities Act as long as:
	•	you are not an affiliate of ours or a broker-dealer that acquired the Old Notes directly from us;
	•	you are acquiring the New Notes in the ordinary course of your business; and
	•	you are not participating, do not intend to participate and have no arrangement or understanding with any person to participate, in a distribution of the Old Notes or the New Notes.
	If you are an affiliate of ours or are engaged in or intend to engage in or have any arrangement or understanding with any person to participate in the distribution of the Old Notes or the New Notes:
	•	you cannot rely on the applicable interpretations of the staff of the SEC; and
	•	you must comply with the registration requirements of the Securities Act in connection with any resale transaction.
	Each broker or dealer that receives New Notes for its own account in exchange for Old Notes that were acquired as a result of market-making or other trading activities may be deemed an underwriter and thus must acknowledge that it will comply with the registration and prospectus delivery requirements of the Securities Act in connection with any offer, resale, or other transfer of the New Notes issued in the exchange offer, including the delivery of a prospectus that contains information with respect to any selling holder required by the Securities Act in connection with any resale of the New Notes.

	Furthermore, any broker-dealer that acquired any of its Old Notes directly from us may not rely on the applicable interpretation of the SEC staff contained in no-action letters for Exxon Capital Holdings Corp. (available May 13, 1988), Morgan Stanley & Co. Incorporated (available June 5, 1991) and Shearman & Sterling (available July 2, 1993).
	As a condition to participation in the exchange offer, each holder will be required to represent that it is not our affiliate or a broker-dealer that acquired the Old Notes directly from us.
Broker-Dealers	Each broker-dealer that receives New Notes for its own account in exchange for Old Notes, where such Old Notes were acquired by such broker-dealer as a result of market-making activities or other trading activities, must acknowledge that it will deliver a prospectus in connection with any resale of such New Notes. See "Plan of Distribution."
Consequences of Not Exchanging Old Notes	If you do not exchange your Old Notes in the exchange offer, you will continue to be subject to the restrictions on transfer described in the legend on your Old Notes. In general, you may offer or sell your Old Notes only:
	•	if they are registered under the Securities Act and applicable state securities laws;
	•	if they are offered or sold under an exemption from registration under the Securities Act and applicable state securities laws; or
	•	if they are offered or sold in a transaction not subject to the Securities Act and applicable state securities laws.
	We do not currently intend to register the Old Notes under the Securities Act. Under some circumstances, however, holders of the Old Notes, including holders who are not permitted to participate in the exchange offer or who may not freely sell New Notes received in the exchange offer, may require us to file, and to cause to become effective, a shelf registration statement covering resales of the Old Notes by these holders. For more information regarding the consequences of not tendering your Old Notes and our obligations to file a shelf registration statement, see "The Exchange Offer—Consequences of Exchanging or Failing to Exchange Old Notes."
No Prior Market	The New Notes will be a new issue of securities for which there is no existing market. Accordingly, we cannot assure you that a liquid market for the New Notes will develop or be maintained.

Summary of the Terms of the Notes

The form and the terms of the New Notes and the Old Notes are identical in all material respects, except that the transfer restrictions and registration rights applicable to the Old Notes do not apply to the New Notes. The New Notes will evidence the same debt as the Old Notes and will be governed by the same indenture dated June 6, 2006, first supplemental indenture dated June 6, 2006 and second supplemental indenture dated June 6, 2006 (collectively, the "Indenture").

Issuer	Edison Mission Energy
New Notes Offered	$1,000,000,000 principal amount of New Notes, consisting of:
	$500,000,000 principal amount of New 2013 Notes; and
	$500,000,000 principal amount of New 2016 Notes.
Maturity Dates	New 2013 Notes—June 15, 2013
	New 2016 Notes—June 15, 2016
Interest Payment Dates	Interest on the New Notes will be paid semi-annually in arrears on June 15 and December 15 of each year, commencing on December 15, 2006.
Ranking of the Notes	The New Notes will be senior unsecured obligations of EME, will rank pari passu with all of EME's senior unsecured indebtedness and will rank senior to EME's subordinated indebtedness, if any. All existing and future liabilities of EME's subsidiaries will be effectively senior to the New Notes.
Certain Covenants	The Indenture governing the New Notes contains covenants limiting or prohibiting EME's ability to, among other things:
	•	create liens,
	•	incur secured indebtedness, and
	•	merge or consolidate with other entities.
	These covenants are subject to important qualifications and exceptions. See "Description of the Notes—Certain Covenants."
Optional Redemption	We may redeem some or all of the New Notes at any time at a price equal to 100% of the principal amount of, plus accrued and unpaid interest on, the New Notes plus a "make-whole" premium. See "Description of the Notes—Redemption."
Risk Factors	See "Risk Factors" for a discussion of certain factors that should be considered in evaluating an investment in the New Notes.

Summary Consolidated Financial Data

The following table sets forth a summary of our consolidated financial data for the periods indicated. In April 2006, EME received, as a capital contribution, ownership interests in a portfolio of wind projects located in Iowa and Minnesota and a small biomass project. These projects were previously owned by EME's affiliate, Edison Capital. EME accounted for this acquisition at Edison Capital's historical cost as a transaction between entities under common control for a net book value of approximately $76 million. The historical consolidated financial and operating results data reflects the acquisition as though EME had always owned the projects for all periods presented. The historical consolidated operating data for each of the three years ended December 31, 2005 and the financial position data as of December 31, 2005 and 2004 were derived from the audited historical consolidated financial statements included elsewhere in this prospectus. The following selected historical consolidated financial data as of June 30, 2006 and for the six months ended June 30, 2006 and 2005 has been derived from our unaudited consolidated financial statements included elsewhere in this prospectus. Our unaudited consolidated financial statements were prepared on a basis consistent with that used in preparing our audited consolidated financial statements and include all material adjustments, all of which are of a normal recurring nature, that, in the opinion of management, are necessary for a fair statement of our financial position and results of operations for the unaudited periods.

You should read the following information in conjunction with the section entitled "Management's Discussion and Analysis of Financial Condition and Results of Operations" and the historical consolidated financial statements and the related notes included elsewhere in this prospectus. Historical results are not necessarily indicative of results that may be expected for any future period.

		Years Ended December 31,									Six Months Ended June 30,
		2003			2004			2005			2005			2006
		(in millions)									(in millions) (unaudited)
Income Statement Data
Operating revenues		$	1,779		$	1,653		$	2,265		$	939		$	977
Operating expenses
	Fuel, plant operations and plant operating lease		1,334			1,300			1,287			653			658
	Loss on lease termination, asset impairment and other charges		304			989			7			7			—
	Depreciation and amortization		156			152			134			66			71
	Administrative and general		138			149			154			70			64

	Total Operating Expenses		1,932			2,590			1,582			796			793

Operating income (loss)			(153	)		(937	)		683			143			184
Equity in income from unconsolidated affiliates			239			218			229			83			71
Impairment on equity method investment			—			—			(55	)		—			—
Interest and other income			2			52			69			24			66
Loss on early extinguishment of debt			—			—			(4	)		(4	)		(143	)
Interest expense			(303	)		(298	)		(300	)		(151	)		(145	)

Income (loss) from continuing operations before income taxes and minority interest			(215	)		(965	)		622			95			33
Provision (benefit) for income taxes			(121	)		(406	)		208			19			1
Minority interest			(2	)		(1	)		—			—			—

Income (loss) from continuing operations			(96	)		(560	)		414			76			32
Income (loss) from operations of discontinued subsidiaries (including gain on disposal of $533 million in 2004), net of tax			124			690			29			28			77

Income (loss) before accounting change			28			130			443			104			109
Cumulative effect of change in accounting, net of tax(1)			(9	)		—			(1	)		—			—

Net income (loss)		$	19		$	130		$	442		$	104		$	109

(1): Our 2005 loss from a change in accounting principle resulted from the adoption of a new accounting standard for conditional asset retirements. Our 2003 loss from a change in accounting principle resulted from adoption of a new accounting standard for asset retirement obligations.

	As of December 31,
	As of December 31,						As of June 30, 2006
	2003(2)		2004(3)		2005		As of June 30, 2006
	(in millions)						(in millions) (unaudited)
Balance Sheet Data
Assets	$	12,299	$	7,087	$	7,023	$	7,021
Current liabilities		1,203		994		846		523
Long-term obligations		2,919		3,530		3,330		3,294
Preferred securities		—		—		—		—
Shareholder's equity		1,954		1,745		1,910		2,242

(2): In the fourth quarter of 2003, we adopted FIN No. 46, "Consolidation of Variable Interest Entities, an Interpretation of ARB No. 51," which required us to reflect the junior subordinated deferrable debentures as a liability, which under the prior accounting treatment would have been eliminated in consolidation, instead of the Monthly Income Preferred Securities.
(3): Assets decreased in 2004 compared to 2003 due to completion of the sale of substantially all of our international assets.

	Years Ended December 31,			Six Months Ended June 30,
	2003	2004	2005	2005	2006
	(in millions)			(in millions)
Other Data
Ratio of earnings to fixed charges(4)(5)	—	—	2.23	1.40	1.20

(4): For purposes of computing the ratio of earnings to fixed charges, earnings are divided by fixed charges. "Earnings" represent the aggregate of income (loss) for continuing operations before income taxes and minority interest. "Fixed charges" represent interest (whether expensed or capitalized), dividends on preferred securities for continuing operations, amortization of debt discount and the interest component of rental expense.
(5): For the years ended December 31, 2004 and 2003, there was a fixed charge deficiency of $953 million and $85 million, respectively.

RISK FACTORS

Your investment in the New Notes involves a high degree of risk. You should carefully consider the risks described below as well as other information and data included in this prospectus before making an investment decision. Additional risks and uncertainties not presently known to us or that we currently believe are immaterial may also adversely impact our business operations. If any of the events described in the risk factors below occur, our business, financial condition, operating results and prospects could be materially adversely affected, which in turn could adversely affect our ability to pay interest and/or principal on the New Notes.

Risks Relating to Exchange Offer

You may have difficulty selling the Old Notes which you do not exchange, since Old Notes will continue to have restrictions on transfer and cannot be sold without registration under securities laws or exemptions from registration.

If a large number of Old Notes are exchanged for New Notes issued in the exchange offer, it may be difficult for holders of Old Notes that are not exchanged in the exchange offer to sell the Old Notes, since those Old Notes may not be offered or sold unless they are registered or there are exemptions from registration requirements under the Securities Act or state laws that apply to them. In addition, if there are only a small number of Old Notes outstanding, there may not be a very liquid market in those Old Notes. There may be few investors that will purchase unregistered securities in which there is not a liquid market. See "The Exchange Offer—Consequences of Exchanging or Failing to Exchange Old Notes."

In addition, if you do not tender your Old Notes or if we do not accept some Old Notes, those notes will continue to be subject to the transfer and exchange provisions of the Indenture and the existing transfer restrictions of the Old Notes that are described in the legend on such notes and in the offering memorandum relating to the Old Notes.

Late deliveries of Old Notes or any other failure to comply with the exchange offer procedures could prevent a holder from exchanging its Old Notes.

Noteholders are responsible for complying with all exchange offer procedures. The issuance of New Notes in exchange for Old Notes will only occur upon completion of the procedures described in this prospectus under "The Exchange Offer." Therefore, holders of Old Notes who wish to exchange them for New Notes should allow sufficient time for timely completion of the exchange procedure. Neither we nor the exchange agent are obligated to extend the offer or notify you of any failure to follow the proper procedure.

If you do not exchange your Old Notes in the exchange offer, you will no longer be entitled to an increase in interest payments on Old Notes that the Indenture provides for if we fail to complete the exchange offer.

Once the exchange offer has been completed, holders of outstanding Old Notes will not be entitled to any increase in the interest rate on their notes, which the Indenture provides for if we fail to complete the exchange offer. Holders of Old Notes will not have any further rights to have their Old Notes registered, except in limited circumstances, once the exchange offer is completed.

If you exchange your Old Notes, you may not be able to resell the New Notes you receive in the exchange offer without registering them and delivering a prospectus.

If you exchange your Old Notes in the exchange offer for the purpose of participating in a distribution of the New Notes, you may be deemed to have received restricted securities and, if so, you will be required to comply with the registration and prospectus delivery requirements of the Securities Act in connection with any resale transaction.

Based on interpretations by the SEC in no-action letters, we believe, with respect to New Notes issued in the exchange offer, that:

•: holders who are not "affiliates" of ours within the meaning of Rule 405 of the Securities Act,
•: holders who acquire their notes in the ordinary course of business and
•: holders who do not engage in, intend to engage in, or have arrangements to participate in a distribution (within the meaning of the Securities Act) of the notes do not have to comply with the registration and prospectus delivery requirements of the Securities Act.

Holders described in the preceding sentence must tell us in writing at our request that they meet these criteria. Holders that do not meet these criteria could not rely on interpretations of the SEC in no-action letters, and would have to register the New Notes they receive in the exchange offer and deliver a prospectus for them. In addition, holders that are broker-dealers may be deemed "underwriters" within the meaning of the Securities Act in connection with any resale of New Notes acquired in the exchange offer. Holders that are broker-dealers must acknowledge that they acquired their Old Notes in market-making activities or other trading activities and must deliver a prospectus when they resell the New Notes they acquire in the exchange offer in order not to be deemed an underwriter. Our obligation to make this prospectus available to broker-dealers is limited. We cannot guarantee that a proper prospectus will be available to broker-dealers wishing to resell their New Notes.

You should review the more detailed discussion in "The Exchange Offer—Procedures for Tendering Old Notes" and "The Exchange Offer—Consequences of Exchanging or Failing to Exchange Old Notes."

Risks Relating to Our Business

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

Our merchant energy power plants do not have long-term power purchase agreements. Because the output of these power plants is not committed to be sold under long-term contracts, these projects are subject to market forces which determine the amount and price of energy, capacity and ancillary services sold from the power plants. The factors that influence the market price for energy, capacity and ancillary services include:

•: prevailing market prices for coal, natural gas and fuel oil, and associated transportation;
•: the extent of additional supplies of capacity, energy and ancillary services from current competitors or new market entrants, including the development of new generation facilities or technologies that may be able to produce electricity at a lower cost than our generating facilities and/or increased access by competitors to our markets as a result of transmission upgrades;

•: transmission congestion in and to each market area and the resulting differences in prices between delivery points;
•: the market structure rules established for each market area and regulatory developments affecting the market areas, including any price limitations and other mechanisms adopted to address volatility or illiquidity in these markets or the physical stability of the system;
•: the cost and availability of emission credits or allowances;
•: the availability, reliability and operation of competing power generation facilities, including nuclear generating plants where applicable, and the extended operation of such facilities beyond their presently expected dates of decommissioning;
•: weather conditions prevailing in surrounding areas from time to time; and
•: changes in the demand for electricity or in patterns of electricity usage as a result of factors such as regional economic conditions and the implementation of conservation programs.

In addition, unlike most other commodities, electric power can only be stored on a very limited basis and generally must be produced concurrently with its use. As a result, the wholesale power markets are subject to significant and unpredictable price fluctuations over relatively short periods of time.

There is no assurance that our merchant energy power plants will be successful in selling power into their markets or that the prices received for their power will generate positive cash flows. If our merchant energy power plants do not meet these objectives, they may not be able to generate enough cash to service their own debt and lease obligations, which could have a material adverse effect on us.

Our financial results can be affected by changes in fuel prices, fuel transportation cost increases, and interruptions in fuel supply.

Our business is subject to changes in fuel costs, which may negatively affect our financial results and financial position by increasing the cost of producing power. The fuel markets can be volatile, and actual fuel prices can differ from our expectations.

Although we attempt to purchase fuel based on our known fuel requirements, we are still subject to the risks of supply interruptions, transportation cost increases, and fuel price volatility. In addition, fuel deliveries may not exactly match energy sales, due in part to the need to purchase fuel inventories in advance for reliability and dispatch requirements. The price at which we can sell our energy may not rise or fall at the same rate as a corresponding rise or fall in fuel costs.

We may not be able to hedge market risks effectively.

We are exposed to market risks through our ownership and operation of merchant energy power plants and through our power marketing business. These market risks include, among others, volatility arising from the timing differences associated with buying fuel, converting fuel into energy and delivering energy to a buyer. We use forward contracts and derivative financial instruments, such as futures contracts and options, to manage market risks and exposure to fluctuating electricity and fuel prices. These activities, although intended to mitigate our exposure, expose us to other risks.

The effectiveness of our hedging activities may depend on the amount of working capital available to post as collateral in support of these transactions, either in support of performance guarantees or as a cash margin. The amount of credit support that must be provided typically is based on the difference

between the price of the commodity in a given contract and the market price of the commodity. Significant movements in market prices can result in a requirement to provide cash collateral and letters of credit in very large amounts. Without adequate liquidity to meet margin and collateral requirements, we could be exposed to the following:

•: a reduction in the number of counterparties willing to enter into bilateral contracts, which would result in increased reliance on short-term and spot markets instead of bilateral contracts, increasing our exposure to market volatility; and
•: a failure to meet a margining requirement, which could permit the counterparty to terminate the related bilateral contract early and demand immediate payment for the replacement value of the contract.

As a result of these and other factors, we cannot predict with precision the effect that risk management decisions may have on our businesses, operating results or financial position.

We are exposed to credit and performance risk from third parties under supply and transportation contracts.

We rely on contracts for the supply and transportation of fuel and other services required for the operation of our generation facilities. Our operations are exposed to the risk that counterparties will not perform their obligations. If a counterparty failed to perform under a contract, we would need to obtain alternate suppliers or alternate means of transportation for our requirements of fuel or other services, which could result in higher costs or disruptions in our operations. Furthermore, we are exposed to credit risk because damages related to a breach of contract may not be recoverable. Accordingly, the failure of a supplier to fulfill our contractual obligations could have a material adverse effect on our financial results.

We are subject to extensive energy industry regulation.

Our operations are subject to extensive regulation by governmental agencies. Our projects are subject to federal laws and regulations that govern, among other things, transactions by and with purchasers of power, including utility companies, the development and construction of generation facilities, the ownership and operations of generation facilities, and access to transmission. Under limited circumstances where exclusive federal jurisdiction is not applicable or specific exemptions or waivers from state or federal laws or regulations are otherwise unavailable, federal and/or state utility regulatory commissions may have broad jurisdiction over non-utility owned electric power plants. Generation facilities are also subject to federal, state and local laws and regulations that govern, among other things, the geographical location, zoning, land use and operation of a project.

There is no assurance that the introduction of new laws or other future regulatory developments will not have a material adverse effect on our business, results of operations or financial condition, nor is there any assurance that we will be able to obtain and comply with all necessary licenses, permits and approvals for our projects. If projects cannot comply with all applicable regulations, our business, results of operations and financial condition could be adversely affected.

We are subject to extensive environmental regulation and permitting requirements that may involve significant and increasing costs.

Our operations are subject to extensive environmental regulation. We are required to obtain and comply with conditions established by licenses, permits and other approvals in order to construct, operate or modify our facilities. Failure to comply with these requirements could subject us to civil or criminal liability, the imposition of liens or fines, or actions by regulatory agencies seeking to curtail

our operations. We may also be exposed to risks arising from past, current or future contamination at our former or existing facilities or with respect to off-site waste disposal sites that have been used in our operations.

We devote significant resources to environmental monitoring, pollution control equipment and emission allowances to comply with environmental regulatory requirements. We believe that we are in substantial compliance with environmental regulatory requirements and that maintaining compliance with current requirements will not materially affect our financial position or results of operations. However, the current trend is toward more stringent standards, stricter regulation, and more expansive application of environmental regulations. Future environmental laws and regulations, and future enforcement proceedings that may be taken by environmental authorities, could affect the costs and the manner in which we conduct our business and could cause us to make substantial additional capital expenditures. There is no assurance that we would be able to recover these increased costs from our customers or that our business, financial position and results of operations would not be materially adversely affected.

Environmental advocacy groups and regulatory agencies in the United States have been focusing considerable attention on carbon dioxide emissions from coal-fired power plants and their potential role in climate change. The adoption of laws and regulations to implement carbon dioxide controls could adversely affect our coal-fired plants. Also, coal plant emissions of nitrogen oxides and sulfur oxides, mercury and particulates are subject to increased controls and mitigation expenses. Additionally, certain of the states in which we operate are contemplating air pollution control regulations that are more stringent than existing and proposed federal regulations. Changing environmental regulations could require us to purchase additional emission allowances or install additional pollution control technology, and could make some units uneconomical to maintain or operate. If we cannot comply with all applicable regulations, we could be required to retire or suspend operations at our facilities, or restrict or modify the operations of our facilities, and our business, results of operations and financial condition could be adversely affected.

Typically, environmental laws require a lengthy and complex process for obtaining licenses, permits and approvals prior to construction, operation or modification of a project or generating facility. Meeting all the necessary requirements can delay or sometimes prevent the completion of a proposed project as well as require extensive modifications to existing projects, which may involve significant capital expenditures. We cannot provide assurance that we will be able to obtain and comply with all necessary licenses, permits and approvals for our plants.

The ability of our largest subsidiary, Midwest Generation, LLC, to make distributions is restricted.

Midwest Generation, LLC, which owns or leases our fossil fuel plants located in Illinois, has entered into financing documents that contain restrictions on its ability to pay dividends.

We are the guarantor of the Powerton and Joliet (Units 7 and 8) leases and are obligated under intercompany notes to make debt service payments to Midwest Generation. Each intercompany note is a general corporate obligation of ours, which ranks pari passu with the New Notes, and payments on it are made from distributions from subsidiaries and other sources of cash received by us. Accordingly, we must continue to make payments under the intercompany notes regardless of whether or not Midwest Generation makes distributions to us. If we were not able to satisfy our obligations under the intercompany notes, it would result in a default under the financing documents of EME and Midwest Generation. This could have a material adverse effect on our results of operations and cash flow and our ability to make payment on the New Notes.

Competition could adversely affect our business.

The independent power industry is characterized by numerous capable competitors, some of whom may have more extensive operating experience in the acquisition and development of power projects, larger staffs, and greater financial resources than we do. Further, in recent years some power markets have been characterized by strong and increasing competition as a result of regulatory changes and other factors which can contribute to a reduction in market prices for power from time to time. These regulatory and other changes may increase competitive pressures in the markets in which we operate.

Newer plants owned by our competitors are often more efficient than our facilities. This may put some of our facilities at a competitive disadvantage to the extent that our competitors are able to produce more power from each increment of fuel than our facilities are capable of producing.

Several participants in the wholesale markets, including many regulated utilities, have a lower cost of capital than most merchant generators and often are able to recover fixed costs through rate base mechanisms, allowing them to build, buy and upgrade generation assets without relying exclusively on market clearing prices to recover their investments. This could affect our ability to compete effectively in the markets in which those entities operate.

Our parent, Mission Energy Holding Company, depends upon cash flows from us to service its debt.

The principal asset of MEHC is the common stock of EME. In July 2001, MEHC issued $800 million of 13.50% senior secured notes due 2008. These senior secured notes are secured by a first priority security interest in our common stock. Any foreclosure on the pledge of our common stock by the holders of the senior secured notes would result in a change in control of EME which could have a material adverse effect on MEHC and us. Dividends from us are limited based on our earnings and cash flow, the terms of restrictions contained in our corporate credit facility, business and tax considerations and restrictions imposed by applicable law.

Restrictions in our certificate of incorporation, our credit facilities and the MEHC financing documents limit our ability to enter into specified transactions that we otherwise may enter into and may significantly impede our ability to refinance our debt.

The financing documents entered into by MEHC contain financial and investment covenants restricting us. Our certificate of incorporation binds us to the provisions in MEHC's financing documents by restricting our ability to enter into specified transactions and engage in specified business activities without shareholder approval. The instruments governing our indebtedness also contain financial and investment covenants. Restrictions contained in these documents could affect, and in some cases significantly limit or prohibit, our ability to, among other things, incur, refinance, and prepay debt, make capital expenditures, pay dividends and make other distributions, make investments, create liens, sell assets, enter into sale and leaseback transactions, issue equity interests, enter into transactions with affiliates, create restrictions on the ability to pay dividends or make other distributions and engage in mergers and consolidations. These restrictions may significantly impede our ability to take advantage of business opportunities as they arise, to grow our business and compete effectively, or to develop and implement any refinancing plans in respect of our indebtedness.

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

Our projects may be affected by general operating risks and hazards customary in the power generation industry. We may not have adequate insurance to cover all these hazards.

The operation of power generation facilities involves many operating risks, including:

•: performance below expected levels of output or efficiency;
•: interruptions in fuel supply;
•: disruptions in the transmission of electricity;
•: curtailment of operations due to transmission constraints;
•: breakdown or failure of equipment or processes;
•: imposition of new regulatory, permitting, or environmental requirements, or violations of existing requirements;
•: employee work force factors, including strikes, work stoppages or labor disputes;
•: operator error; and
•: catastrophic events such as terrorist activities, fires, tornadoes, earthquakes, explosions, floods or other similar occurrences affecting power generation facilities or the transmission and distribution infrastructure over which power is transported.

These and other hazards can cause significant personal injury or loss of life, severe damage to and destruction of property, plant and equipment, contamination of or damage to the environment, and suspension of operations. The occurrence of one or more of the events listed above could decrease or eliminate revenues generated by our projects or significantly increase the costs of operating them, and could also result in our being named as a defendant in lawsuits asserting claims for substantial damages, potentially including environmental cleanup costs, personal injury, property damage, fines and penalties. Equipment and plant warranties and insurance may not be sufficient or effective under all circumstances to cover lost revenues or increased expenses. A decrease or elimination in revenues generated by the facilities or an increase in the costs of operating them could decrease or eliminate funds available to meet our obligations as they become due and could have a material adverse effect on us. A default under a financing obligation of a project entity could result in a loss of our interest in the project.

Our future acquisitions and development projects may not be successful.

Our long-term strategy includes the development and acquisition of electric power generation facilities. The development of a power project may require us to expend significant amounts for preliminary engineering, permitting, legal and other expenses before we can determine whether we will win a competitive bid, or whether a project is feasible, economically attractive or financeable. We may not be successful in obtaining financing for our projects and may not be able to obtain sufficient equity capital, project cash flow, or additional borrowings to enable us to fund equity commitments for future projects.

In addition to the competition already existing in the markets in which we presently operate or may consider operating in the future, we are likely to encounter significant competition for acquisition opportunities that may become available as a result of the consolidation of the power industry, in general, as well as the passage of the Energy Policy Act of 2005. We may be unable to identify attractive acquisition or development opportunities and/or to complete and integrate them on a successful and timely basis.

Risks Relating to the New Notes

We are primarily a holding company. Our only material source of cash is and will be distributions from our subsidiaries, and the New Notes are effectively subordinated to the claims of the creditors of our direct and indirect subsidiaries.

We are primarily a holding company with no material business operations of our own. Our most significant assets are the capital stock of our subsidiaries. We conduct virtually all of our business operations through those subsidiaries. Accordingly, our only material source of cash, including cash to make payments on or redeem the New Notes or our other indebtedness, is and will be dividends and distributions with respect to our ownership interests in our subsidiaries that are derived from the earnings and cash flow generated by our subsidiaries. We cannot assure you that our subsidiaries will generate sufficient earnings and cash flow to pay dividends or distributions to us or that applicable state law and contractual restrictions will permit dividends or distributions in the future. In addition, our direct and indirect subsidiaries will not guarantee the New Notes and will have no legal obligation to make payments on the New Notes or make funds available for those payments, whether by dividends, loans or other payments. Accordingly, we may not be able to pay interest on the New Notes or principal when due at maturity or otherwise.

In the event of a bankruptcy, liquidation, dissolution, reorganization or similar proceeding involving EME, the New Notes will be effectively subordinated to the claims of the creditors of all of EME's direct and indirect subsidiaries, including trade creditors and holders of indebtedness of those subsidiaries. Accordingly, there might only be a limited amount of assets available to satisfy your claims as a holder of the New Notes upon an acceleration of the maturity of the New Notes.

We have a substantial amount of indebtedness, including long-term lease obligations.

As of June 30, 2006, our consolidated debt was $3.4 billion. In addition, our subsidiaries have $4.4 billion of long-term power plant lease obligations that are due over a period ranging up to 29 years. Subject to certain exceptions, the Indenture governing the New Notes will limit our ability to incur secured debt to 10% of our consolidated net tangible assets, but will not impose limitations on our ability to incur additional unsecured indebtedness. See "Description of the Notes—Certain Covenants; Restrictions on Liens." All existing and future liabilities of our subsidiaries will be effectively senior to the New Notes. We have entered into a new secured corporate credit facility consisting of $500 million in revolving loan and letter of credit capacity. The New Notes will be effectively subordinated to borrowings under this facility to the extent of the collateral securing such indebtedness.

The substantial amount of consolidated debt and financial obligations presents the risk that we might not have sufficient cash to service our indebtedness, including the New Notes, or long-term lease obligations and that the existing corporate debt, project debt and lease obligations could limit our ability to grow our business, to compete effectively or operate successfully under adverse economic conditions. If our cash flows and capital resources were insufficient to allow us to make scheduled payments on our debt, we might have to reduce or delay capital expenditures, sell assets, seek additional capital, or restructure or refinance the debt. The terms of our debt may not allow these alternative measures, the debt or equity may not be available on acceptable terms, and these alternative measures may not satisfy all scheduled debt service obligations.

You may find it difficult to sell your notes because there is no existing trading market for the New Notes.

You may find it difficult to sell your notes because an active trading market for the notes may not develop. The New Notes are being offered to the holders of the Old Notes. The Old Notes were issued on June 6, 2006, primarily to a small number of institutional investors. After the exchange offer, the trading market for the remaining untendered Old Notes could be adversely affected. There is no existing trading market for the New Notes. Future trading prices of the New Notes will depend on many factors, including prevailing interest rates, our operating results, and the market for similar securities. We do not intend to apply for listing or quotation of the New Notes on any exchange, and so we do not know the extent to which investor interest will lead to the development of a trading market or how liquid that market might be. Although the initial purchasers in the private offering of the Old Notes have informed us that they intend to make a market in the New Notes, they are not obligated to do so. The initial purchasers may cease their market-making at any time. As a result, the market price of the New Notes could be adversely affected.

Historically, the market for non-investment grade debt has been subject to disruptions that have caused substantial volatility in the prices of securities similar to the New Notes offered by this prospectus. The market for the New Notes, if any, may be subject to similar disruptions. These disruptions may adversely affect the value of the New Notes.

THE EXCHANGE OFFER

Purpose of the Exchange Offer

When we sold the Old Notes on June 6, 2006, or the "closing date," we entered into a registration rights agreement with the initial purchasers of the Old Notes. Under the registration rights agreement, we agreed to file a registration statement regarding the exchange of the Old Notes for New Notes which are registered under the Securities Act. We also agreed to use our reasonable best efforts to cause the registration statement to become effective with the SEC and to conduct this exchange offer after the registration statement is declared effective. The registration rights agreement provides that we will be required to pay additional interest to the holders of the Old Notes if:

•: we do not file the exchange offer registration statement with the SEC on or prior to the 180th calendar day following the closing date;
•: the exchange offer registration statement has not been declared effective on or prior to the 240th calendar day following the closing date; or
•: the exchange offer is not consummated on or prior to 30 business days after the 240th calendar day following the closing date.

The exchange offer is not being made to holders of Old Notes in any jurisdiction where the exchange would not comply with the securities or blue sky laws of such jurisdiction. A copy of the registration rights agreement is filed as an exhibit to the registration statement of which this prospectus forms a part.

Terms of the Exchange Offer

Upon the terms and conditions described in this prospectus, we will accept for exchange Old Notes that are properly tendered on or before the expiration date and not withdrawn as permitted below. As used in this prospectus, the term "expiration date" means 5:00 p.m., New York City time, on November 9, 2006. However, if we, in our sole discretion, have extended the period of time for which the exchange offer is open, the term "expiration date" means the latest time and date to which we extend the exchange offer.

As of the date of this prospectus, $1,000,000,000 aggregate principal amount at maturity of the Old Notes is outstanding. The Old Notes were offered under the Indenture. This prospectus is first being sent on or about October 12, 2006 to all holders of Old Notes known to us. Our obligation to accept Old Notes for exchange in the exchange offer is subject to the conditions described below under "Conditions to the Exchange Offer." We reserve the right to extend the period of time during which the exchange offer is open. We would then delay acceptance for exchange of any Old Notes by giving oral or written notice of an extension to the holders of Old Notes as described below. During any extension period, all Old Notes previously tendered will remain subject to the exchange offer and may be accepted for exchange by us. Any Old Notes not accepted for exchange will be returned to the tendering holder after the expiration or termination of the exchange offer. Holders of Old Notes do not have dissenters' rights of appraisal in connection with the exchange offer.

Old Notes tendered in the exchange offer must be in denominations of principal amount of $2,000 and any integral multiple of $1,000.

We reserve the right to amend or terminate the exchange offer, and not to accept for exchange any Old Notes not previously accepted for exchange, upon the occurrence of any of the conditions of

the exchange offer specified below under "—Conditions to the Exchange Offer." We will give oral or written notice of any extension, amendment, non-acceptance or termination to the holders of the Old Notes as promptly as practicable. We will notify you of any extension by means of a press release or other public announcement no later than 9:00 a.m., New York City time on that date.

Our acceptance of the tender of Old Notes by a tendering holder will form a binding agreement upon the terms and subject to the conditions provided in this prospectus.

Procedures for Tendering

A tendering holder must, on or prior to the expiration date, transmit an agent's message to the exchange agent at the address listed below under the heading "—Exchange Agent."

In addition, the exchange agent must receive, on or before the expiration date, a timely confirmation of book-entry transfer of the Old Notes into the exchange agent's account at the Depository Trust Company, the book-entry transfer facility, along with an agent's message.

The Depository Trust Company will be referred to as DTC in this prospectus.

The term "agent's message" means a message, transmitted to DTC and received by the exchange agent and forming a part of a book-entry transfer, that states that DTC has received an express acknowledgment that the tendering holder agrees to appoint the exchange agent as the tendering holder's true and lawful agent and attorney-in-fact with respect to such tendered Old Notes, with full power of substitution, among other things, to cause the Old Notes to be assigned, transferred and exchanged.

If you are a beneficial owner whose Old Notes are registered in the name of a broker, dealer, commercial bank, trust company or other nominee, and wish to tender, you should promptly instruct the registered holder to tender on your behalf.

We will determine in our sole discretion all questions as to the validity, form and eligibility of Old Notes tendered for exchange. This discretion extends to the determination of all questions concerning the timing of receipts and acceptance of tenders. These determinations will be final and binding.

We reserve the right to reject any amount of Old Notes not properly tendered, or any acceptance that might, in our judgment or our counsel's judgment, be unlawful. We also reserve the right to waive any conditions of the exchange offer as applicable to all Old Notes prior to the expiration date. We also reserve the right to waive any defects or irregularities or conditions of the exchange offer as to any amount of Old Notes prior to the expiration date. Our interpretation of the terms and conditions of the exchange offer as to any amount of Old Notes either before or after the expiration date shall be final and binding on all parties. Unless waived, any defects or irregularities in connection with tenders of Old Notes must be cured within a reasonable period of time. None of we, the exchange agent or any other person will be under any duty to give notification of any defect or irregularity in any tender of Old Notes. Nor will we, the exchange agent or any other person incur any liability for failing to give notification of any defect or irregularity.

By tendering, each holder will represent to us that, among other things:

•: the holder is not an affiliate of ours (as defined in Rule 405 under the Securities Act) or a broker-dealer tendering notes acquired directly from us for its own account;

•: the New Notes are being acquired in the ordinary course of business of the person receiving the New Notes, whether or not that person is the holder;
•: neither the holder nor the other person has any arrangement or understanding with any person to participate in the distribution (within the meaning of the Securities Act) of the New Notes; and
•: the holder is not engaged in, and does not intend to engage in, a distribution of the New Notes.

However, any purchaser of Old Notes who is our "affiliate" (within the meaning of the Securities Act) who intends to participate in the exchange offer for the purpose of distributing the New Notes or a broker-dealer (within the meaning of the Securities Act) that acquired Old Notes in a transaction other than as part of its trading or market-making activities and who has arranged or has an understanding with any person to participate in the distribution of the New Notes:

•: will not be able to rely on the applicable interpretation by the staff of the SEC set forth in the applicable no-action letters;
•: will not be able to tender its Old Notes in the exchange offer; and
•: must comply with the registration and prospectus delivery requirements of the Securities Act in connection with any sale or transfer of the notes unless such sale or transfer is made pursuant to an exemption from such requirements.

By tendering, each broker-dealer that receives New Notes for its own account in exchange for Old Notes, where the Old Notes were acquired by it for its own account as a result of market-making activities or other trading activities, will acknowledge that it will deliver a prospectus that meets the requirements of the Securities Act in connection with any resale of the New Notes. By so acknowledging and by delivering a prospectus, a broker-dealer will not be deemed to admit that it is an "underwriter" within the meaning of the Securities Act. However, a broker-dealer may be a statutory underwriter. See "Plan of Distribution."

Furthermore, any broker-dealer that acquired any of its Old Notes directly from us:

•: may not rely on the applicable interpretation of the staff of the SEC's position contained in Exxon Capital Holdings Corp., SEC no-action letter (April 13, 1988), Morgan, Stanley & Co. Inc., SEC no-action letter (June 5, 1991), and Shearman & Sterling, SEC no-action letter (July 2, 1993); and
•: must also be named as a selling holder in connection with the registration and prospectus delivery requirements of the Securities Act relating to any resale transaction.

Acceptance of Old Notes for Exchange; Delivery of New Notes

Upon satisfaction or waiver of all of the conditions to the exchange offer, we will accept, promptly after the expiration date, all Old Notes properly tendered, unless we terminate the exchange offer because of the non-satisfaction of conditions. We will issue the New Notes as soon as practicable after acceptance of the Old Notes. See "—Conditions to the Exchange Offer" below. For purposes of the exchange offer, we will be deemed to have accepted properly tendered Old Notes for exchange when, as and if we have given oral or written notice to the exchange agent, with prompt written confirmation of any oral notice.

For each Old Note accepted for exchange, the holder of the Old Note will receive a New Note having a principal amount equal to that of the surrendered Old Note. The New Notes will bear interest

from the most recent date to which interest has been paid on the Old Notes. Accordingly, registered holders of New Notes on the relevant record date for the first interest payment date following the completion of the exchange offer will receive interest accruing from the most recent date to which interest has been paid. The accreted value of the New Notes will be the same as the accreted value of the Old Notes. Old Notes accepted for exchange will cease to accrue interest from and after the date of completion of the exchange offer. Holders of Old Notes whose Old Notes are accepted for exchange will not receive any payment for accrued interest on the Old Notes otherwise payable on any interest payment date, the record date for which occurs on or after completion of the exchange offer and will be deemed to have waived their rights to receive the accrued interest on the Old Notes.

In all cases, issuance of New Notes for Old Notes will be made only after timely receipt by the exchange agent of a timely book-entry confirmation of the Old Notes into the exchange agent's account at the book-entry transfer facility.

Unaccepted or non-exchanged Old Notes will be returned without expense to the tendering holder of the Old Notes. In the case of Old Notes tendered by book-entry transfer in accordance with the book-entry procedures described below, the non-exchanged Old Notes will be returned or recredited promptly.

Book-Entry Transfer

The exchange agent will make a request to establish an account for the Old Notes at DTC for purposes of the exchange offer within two business days after the date of this prospectus. A holder of the Old Notes must make book-entry delivery of Old Notes by causing DTC to transfer those Old Notes into the exchange agent's account at DTC in accordance with DTC's procedure for transfer. This holder should transmit its acceptance to DTC on or prior to the expiration date. DTC will verify this acceptance, execute a book-entry transfer of the tendered Old Notes into the exchange agent's account at DTC and then send to the exchange agent confirmation of this book-entry transfer. The confirmation of this book-entry transfer will include an agent's message confirming that DTC has received an express acknowledgment from this holder that this holder agrees to be bound by the assignment, transfer and exchange of the Old Notes. Delivery of New Notes issued in the exchange offer may be effected through book-entry transfer at DTC. However, an agent's message must be transmitted to and received by the exchange agent at the address listed below under "—Exchange Agent" on or prior to the expiration date.

Exchanging Book-Entry Notes

The exchange agent and DTC have confirmed that any financial institution that is a participant in DTC may utilize DTC Automated Tender Offer Program, or ATOP, procedures to tender Old Notes. Any participant in the DTC may make book-entry delivery of Old Notes by causing the DTC to transfer such Old Notes into the exchange agent's account in accordance with the DTC's ATOP procedures for transfer. However, the exchange for the Old Notes so tendered will only be made after a book-entry confirmation of the book-entry transfer of Old Notes into the exchange agent's account, and timely receipt by the exchange agent of an agent's message.

Withdrawal Rights

Tenders of Old Notes may be withdrawn at any time before 5:00 p.m., New York City time, on the expiration date.

For a withdrawal to be effective, the exchange agent must receive a written notice of withdrawal at the address or at the facsimile number, indicated below under "—Exchange Agent" before 5:00 p.m., New York City time, on the expiration date. Any notice of withdrawal must specify the number of the account at the DTC from which the Old Notes were tendered and specify the name and number of the account at the DTC to be credited with the withdrawn Old Notes and otherwise comply with the procedures of DTC.

We will determine all questions as to the validity, form and eligibility, including time of receipt, or notices of withdrawal. Any Old Notes so withdrawn will be deemed not to have been validly tendered for exchange. No New Notes will be issued unless the Old Notes so withdrawn are validly re-tendered. Any Old Notes that have been tendered for exchange, but which are not exchanged for any reason, will be credited to an account maintained with the DTC. Properly withdrawn Old Notes may be re-tendered by following the procedures described under "—Procedures for Tendering" above at any time on or before 5:00 p.m., New York City time, on the expiration date.

Conditions to the Exchange Offer

Notwithstanding any other provision of the exchange offer, we shall not be required to accept for exchange, or to issue New Notes in exchange for, any Old Notes, and may terminate or amend the exchange offer, if at any time prior to the expiration date any of the following events occurs:

•: there is threatened, instituted or pending any action or proceeding before, or any injunction, order or decree issued by, any court or governmental agency or other governmental regulatory or administrative agency or commission;
•: a change in applicable law prohibits the consummation of such exchange offer; or
•: any change, or any development involving a prospective change, has occurred or been threatened in our business, financial condition, operations or prospects and those of our subsidiaries taken as a whole that is or may be adverse to us, or we have become aware of facts that have or may have an adverse impact on the value of the Old Notes or the New Notes, which in our reasonable judgment in any case makes it inadvisable to proceed with the exchange offer and about which change or development we make a public announcement.

All conditions will be deemed satisfied or waived prior to the expiration date, unless we assert them prior to the expiration date. The foregoing conditions to the exchange offer are for our sole benefit and we may prior to the expiration date assert them regardless of the circumstances giving rise to any of these conditions, or we may prior to the expiration date waive them in whole or in part in our reasonable discretion. Our failure at any time to exercise any of the foregoing rights will not be deemed a waiver of any right.

In addition, we will not accept for exchange any Old Notes tendered, and no New Notes will be issued in exchange for any Old Notes, if at this time any stop order is threatened or in effect relating to the registration statement of which this prospectus constitutes a part. We are required to make every reasonable effort to obtain the withdrawal of any order suspending the effectiveness of a Registration Statement at the earliest possible moment.

Exchange Agent

We have appointed The Wells Fargo Bank, National Association as the exchange agent for the exchange offer. You should direct all executed letters, questions and requests for assistance, or requests for additional copies of this prospectus to the exchange agent addressed as follows:

Delivery To:

The Wells Fargo Bank, National Association

By Hand, Registered or Certified Mail, or Overnight Courier:
Wells Fargo Bank, National Association
707 Wilshire Boulevard, 17^th Floor
Los Angeles, California 90017
Attn: Maddy Hall

For Information Call: (213) 614-2588
By Facsimile: (213) 614-3355
Confirm By Telephone: (213) 614-2588

All other questions should be addressed to Edison Mission Energy, 18101 Von Karman Avenue, Suite 1700, Irvine, California 92612, Attention: Steven D. Eisenberg. If you deliver the transmit instructions via facsimile other than to any facsimile number indicated above, then your delivery or transmission will not constitute a valid delivery or transmission.

Fees and Expenses

We will not make any payment to brokers, dealers or others soliciting acceptances of the exchange offer. We have agreed to pay all expenses incidental to the exchange offer other than commissions and concessions of any broker or dealer and certain transfer taxes and will indemnify holders of the notes, including any broker-dealers, against certain liabilities, including liabilities under the Securities Act. The estimated cash expenses to be incurred in connection with the exchange offer will be paid by us and will include fees and expenses of the exchange agent, accounting, legal, printing and related fees and expenses.

Accounting Treatment

We will not recognize any gain or loss for accounting purposes upon the consummation of the exchange offer. We will amortize the expense of the exchange offer over the term of the New Notes in accordance with accounting principles generally accepted in the United States of America.

Transfer Taxes

We will pay any transfer taxes in connection with the exchange of Old Notes for New Notes in the exchange offer unless you instruct us to register New Notes in the name of, or request any Old Notes not tendered or not accepted in the exchange offer be returned to, a person other than the registered tendering holder. In those cases, you will be responsible for the payment of any applicable transfer tax.

Consequences of Exchanging or Failing to Exchange the Old Notes

Holders of Old Notes who do not exchange their Old Notes for New Notes in the exchange offer will continue to be subject to the provisions in the Indenture regarding transfer and exchange of the Old Notes and the restrictions on transfer of the Old Notes as described in the legend on the Old Notes as a consequence of the issuance of the Old Notes under exemptions from, or in transactions not subject to, the registration requirements of the Securities Act and applicable state securities laws. In general, the Old Notes may not be offered or sold, unless registered under the Securities Act, except under an exemption from, or in a transaction not subject to, the Securities Act and applicable state securities laws. Old Notes holders that do not exchange Old Notes for New Notes in the exchange offer will no longer have any registration rights with respect to such notes.

Based on existing interpretations of the Securities Act by the SEC's staff contained in several no-action letters to third parties, and subject to the immediately following sentence, we believe that the New Notes would generally be freely transferable by holders after the exchange offer without further registration under the Securities Act, subject to certain representations required to be made by each holder of New Notes, as set forth below. However, any purchaser of New Notes who is one of our "affiliates" (as defined in Rule 405 under the Securities Act) or who intends to participate in the exchange offer for the purpose of distributing the New Notes:

•: will not be able to rely on the applicable interpretation of the staff of the SEC;
•: will not be able to tender its Old Notes in the exchange offer; and
•: must comply with the registration and prospectus delivery requirements of the Securities Act in connection with any sale or transfer of the notes unless such sale or transfer is made pursuant to an exemption from such requirements. See "Plan of Distribution."

We do not intend to seek our own interpretation regarding the exchange offer and there can be no assurance that the SEC's staff would make a similar determination with respect to the New Notes as it has in other interpretations to other parties, although we have no reason to believe otherwise.

USE OF PROCEEDS

We will not receive any proceeds from the exchange offer. In consideration for issuing the New Notes, we will receive in exchange the Old Notes of like principal amount, the terms of which are identical in all material respects to the New Notes. The Old Notes surrendered in exchange for New Notes will be retired and canceled and cannot be reissued. Accordingly, issuance of the New Notes will not result in any increase in our indebtedness. We have agreed to bear the expenses of the exchange offer. No underwriter is being used in connection with the exchange offer.

CAPITALIZATION

The following table sets forth our cash and cash equivalents and consolidated capitalization as of June 30, 2006. This table should be read in conjunction with "Use of Proceeds," "Management's Discussion and Analysis of Financial Condition and Results of Operations" and our financial statements and the related notes in this prospectus.

		As of June 30, 2006
Cash and cash equivalents		$	1,328
Short-term investments			260
Short- and long-term obligations(1)(2):
	Old Notes		1,000
	10% Senior Notes due 2008		31
	9.875% Senior Notes due 2011		4
	7.73% Senior Notes due 2009		599
	Long-term obligations to affiliates		78

EME recourse debt			1,712
Subsidiary debt obligations			1,712

Total consolidated debt			3,424
Shareholder's equity(3)			2,242

Total capitalization		$	5,666

(1): Although not included in the table above, we are obligated under an intercompany loan with Midwest Generation to repay $1.4 billion of intercompany loans resulting from the Powerton and Joliet sale-leaseback transaction.
(2): As of June 30, 2006, we had the full amount of borrowing capacity under our $500 million revolving credit facility.
(3): In connection with the repayment of the 2008 Senior Notes and the 2011 Senior Notes, tender premiums of $136 million, together with remaining deferred financing costs related to these Senior Notes, were expensed. The after-tax impact was approximately $88 million.

MEHC depends on dividends from us to make interest payments on its 13.5% senior secured notes due 2008 and to repay such indebtedness when it becomes due. MEHC has pledged our stock to secure its obligations under its senior secured notes. We intend to retain sufficient cash on hand to make dividends to MEHC to satisfy its payment obligations with respect to its senior secured notes. See "Risk Factors—Our parent, Mission Energy Holding Company, depends upon cash flows from us to service its debt."

SELECTED CONSOLIDATED FINANCIAL DATA

The following table sets forth a summary of our consolidated financial data for the periods indicated. In April 2006, EME received, as a capital contribution, ownership interests in a portfolio of wind projects located in Iowa and Minnesota and a small biomass project. These projects were previously owned by EME's affiliate, Edison Capital. EME accounted for this acquisition at Edison Capital's historical cost as a transaction between entities under common control for a net book value of approximately $76 million. The historical consolidated financial and operating results data reflects the acquisition as though EME had always owned the projects for all periods presented. The historical consolidated operating data for each of the three years ended December 31, 2005 and the financial position data as of December 31, 2005 and 2004 were derived from the audited historical consolidated financial statements included elsewhere in this prospectus. We derived the historical consolidated operating results data for each of the two years ended December 31, 2002 and the financial position data as of December 31, 2003, 2002 and 2001 from our accounting records. The following selected historical consolidated financial data as of June 30, 2006 and for the six months ended June 30, 2006 and 2005 has been derived from our unaudited consolidated financial statements included elsewhere in this prospectus. Our unaudited consolidated financial statements were prepared on a basis consistent with that used in preparing our audited consolidated financial statements and include all material adjustments, all of which are of a normal recurring nature, that, in the opinion of management, are necessary for a fair statement of our financial position and results of operations for the unaudited periods.

		Years Ended December 31,															Six Months Ended June 30,
		2001(1)			2002			2003			2004			2005			2005			2006
		(in millions)															(in millions) (unaudited)
Income Statement Data
Operating revenues		$	1,771		$	1,713		$	1,779		$	1,653		$	2,265		$	939		$	977
Operating expenses
	Fuel, plant operations and plant operating lease		1,256			1,292			1,334			1,300			1,287			653			658
	Loss on lease termination, asset impairment and other charges and credits		59			60			304			989			7			7			—
	Depreciation and amortization		175			147			156			152			134			66			71
	Administrative and general		133			118			138			149			154			70			64

	Total Operating Expenses		1,623			1,617			1,932			2,590			1,582			796			793

Operating income (loss)			148			96			(153	)		(937	)		683			143			184
Equity in income from unconsolidated affiliates			333			196			239			218			229			83			71
Impairment on equity method investment			—			—			—			—			(55	)		—			—
Interest and other income			83			15			2			52			69			24			66
Loss on early extinguishment of debt			—			—			—			—			(4	)		(4	)		(143	)
Interest expense			(428	)		(313	)		(303	)		(298	)		(300	)		(151	)		(145	)

Income (loss) from continuing operations before income taxes and minority interest			136			(6	)		(215	)		(965	)		622			95			33
Provision (benefit) for income taxes			67			(28	)		(121	)		(406	)		208			19			1
Minority interest			(2	)		(2	)		(2	)		(1	)		—			—			—

Income (loss) from continuing operations			67			20			(96	)		(560	)		414			76			32
Income (loss) from operations of discontinued subsidiaries (including gain on disposal of $533 million in 2004 and loss on disposal of $1.1 billion in 2001), net of tax			(1,198	)		22			124			690			29			28			77

Income (loss) before accounting change			(1,131	)		42			28			130			443			104			109
Cumulative effect of change in accounting, net of tax(2)			15			(14	)		(9	)		—			(1	)		—			—

Net income (loss)		$	(1,116	)	$	28		$	19		$	130		$	442		$	104		$	109

(1): In the fourth quarter of 2002, EME adopted SFAS No. 145, "Rescission of FASB Statements No. 4, 44 and 64, Amendment of FASB Statement No. 13, and Technical Corrections," which required EME to reclassify as part of income from continuing operations an extraordinary gain of $6 million, net of tax, recorded in December 2001. The extraordinary gain was attributable to the extinguishment of debt that was assumed by the third-party lessors in the December 2001 Homer City sale-leaseback transaction.
(2): Our 2005 loss from a change in accounting principle resulted from the adoption of a new accounting standard for conditional asset retirements. Our 2003 loss from a change in accounting principle resulted from adoption of a new accounting standard for asset retirement obligations. Our 2002 loss from a change in accounting principle resulted from

adoption of a new accounting standard for goodwill and other intangible assets. Our 2001 gain from a change in accounting principle resulted from adoption of a new accounting standard for derivative instruments and hedging activities.

	As of December 31,
	As of December 31,										As of June 30, 2006
	2001		2002		2003(3)		2004(4)		2005		As of June 30, 2006
	(in millions)										(in millions) (unaudited)
Balance Sheet Data
Assets	$	10,898	$	11,220	$	12,299	$	7,087	$	7,023	$	7,021
Current liabilities		656		1,356		1,203		994		846		523
Long-term obligations		3,978		3,022		2,919		3,530		3,330		3,294
Preferred securities		254		281		—		—		—		—
Shareholder's equity		1,664		1,751		1,954		1,745		1,910		2,242

(3): In the fourth quarter of 2003, we adopted FIN No. 46, "Consolidation of Variable Interest Entities, an Interpretation of ARB No. 51," which required us to reflect the junior subordinated deferrable debentures as a liability, which under the prior accounting treatment would have been eliminated in consolidation, instead of the Monthly Income Preferred Securities.
(4): Assets decreased in 2004 compared to 2003 due to completion of the sale of substantially all of our international assets.

	Years Ended December 31,					Six Months Ended June 30,
	2001(1)	2002	2003	2004	2005	2005	2006
	(in millions)					(in millions)
Other Data
Ratio of earnings to fixed charges(5)(6)	1.03	1.18	—	—	2.23	1.40	1.20

(5): For purposes of computing the ratio of earnings to fixed charges, earnings are divided by fixed charges. "Earnings" represent the aggregate of income (loss) for continuing operations before income taxes and minority interest. "Fixed charges" represent interest (whether expensed or capitalized), dividends on preferred securities for continuing operations, amortization of debt discount and the interest component of rental expense.
(6): For the years ended December 31, 2004 and 2003, there was a fixed charge deficiency of $953 million and $85 million, respectively.

MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION
AND RESULTS OF OPERATIONS

This Management's Discussion and Analysis of Financial Condition and Results of Operations is presented in four sections:

		Page
Management's Overview; Critical Accounting Estimates		32
Results of Operations		37
Liquidity and Capital Resources		58
Market Risk Exposures		85

MANAGEMENT'S OVERVIEW; CRITICAL ACCOUNTING ESTIMATES

Management's Overview

Introduction

EME is a holding company which operates primarily through its subsidiaries and affiliates which are engaged in the business of developing, acquiring, owning or leasing, operating and selling energy and capacity from independent power production facilities. EME's subsidiaries or affiliates have typically been formed to own all or an interest in one or more power plants and ancillary facilities, with each plant or group of related plants being individually referred to by EME as a project. As of June 30, 2006, EME's subsidiaries and affiliates owned or leased interests in 29 operating power plants.

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

Merchant Operations

The majority of EME's power plant operations are located in the PJM control area and sell power under short-term contracts. These power plants are known as merchant power plants since the generation is not sold under long-term contracts. EME's revenues and the results of operations of its merchant power plants depend upon prevailing market prices for capacity, energy, ancillary services, emission allowances or credits, fuel oil, coal, natural gas and associated transportation costs in the market areas where EME's merchant plants are located. EME's income from continuing operations increased substantially from its merchant operations since 2004 due to higher wholesale energy prices driven largely by increases in the market price of natural gas and oil. The average market price during

2005 at the Northern Illinois Hub (related to the Illinois Plants) increased to $46.39 per megawatt hour (MWh), compared to the average market prices at "Into ComEd" and at the Northern Illinois Hub of $29.52 per MWh during 2004.

Energy Trading Activities

EME seeks to generate profit by utilizing the commercial platform of its subsidiary, EMMT, to engage in trading activities in those markets where merchant power plants are located. EMMT trades power, fuel and transmission primarily in the eastern power grid using financial products available over the counter, through exchanges and from independent system operators. EME's earnings from energy trading activities were $55 million during the first six months of 2006 and $195 million during 2005. Volatile market conditions during the first half of 2006 and in 2005, driven by changes in prices for natural gas and oil and warmer summer temperatures during 2005, have created favorable conditions for EMMT's trading strategies during these periods compared to 2004. Because EMMT is below investment grade, it must post margin and collateral in order to participate in its marketing and trading activities. As of June 30, 2006, margin and collateral posted to support trading activities of EMMT was approximately $61 million. This amount includes collateral posted independent system operators as well as initial and mark-to-market margin posted for outstanding volumes of futures and over-the-counter contracts. Income from trading activities will vary substantially from period to period depending on market conditions.

Business Development

Wind Projects

EME has an active development group seeking opportunities for growth in its electricity generating business. Beginning in 2005, EME has undertaken a number of activities with respect to new wind projects, including:

•: Completion in January 2006 of the purchase of development rights for the Wildorado wind project. This project started construction on April 24, 2006 and is scheduled for completion during April 2007, with total construction costs estimated to be $270 million. Upon completion, power from the project will be sold under a twenty-year power purchase agreement to Southwestern Public Service.
•: Securing during 2005 and 2006 a supply of 285 turbines for 538 MW of new wind projects which are expected to be developed and constructed by the end of 2007.
•: Completion in December 2005 of the acquisition of the San Juan Mesa wind project and subsequent sale of 25% of its ownership interest in the San Juan Mesa wind project to a third party.
•: Advancing during 2006 the development of a number of wind projects, including four projects totaling 181 MW that have been approved for investment, subject to completion of specific contractual or permitting arrangements.

In addition, in April 2006 EME received, as a capital contribution, ownership interests in a 192 MW portfolio of wind projects (EME's share is 176 MW) located in Iowa and Minnesota. These projects were previously owned by EME's affiliate, Edison Capital. EME accounted for this acquisition at Edison Capital's historical cost as a transaction between entities under common control for a net book value of approximately $76 million.

Thermal Projects

EME expects to make investments in thermal projects during the next several years. As part of its development efforts, EME is in the process of obtaining permits for two sites in Southern California for peaker plants. Generally, it is expected that thermal projects in which EME invests will sell electricity under long-term power purchase contracts. EME has responded to several requests for proposals to build or acquire generation and recently submitted two indicative bids in response to the request for offers for electricity supply from new generation resources announced by Southern California Edison Company in July 2006. In connection with these thermal development activities, in September 2006, EME entered into an agreement for the purchase of five gas turbines and related equipment for an aggregate purchase price of approximately $140 million. In addition, under the terms of this agreement, EME obtained an option, exercisable through January 26, 2007, to purchase five additional gas turbines and related equipment.

In June 2006, subsidiaries of EME and BP America Inc. formed Carson Hydrogen Power LLC for the development of a power project to be located in Carson, California. Carson Hydrogen is intended as an industrial gasification project that will integrate proven gasification, power generation and enhanced oil recovery technologies. In June 2006, the project submitted an application to the United States Department of Energy (DOE) to qualify for gasification tax credits under the Energy Policy Act of 2005. Funding of tax credits is limited and, accordingly, there is no assurance that the project will be allocated tax credits. A decision from DOE is not expected until the end of 2006. In the meantime, Carson Hydrogen is conducting engineering studies required for project implementation.

Financing Activities

On June 6, 2006, EME completed a private offering of $500 million of its 7.50% senior notes due 2013 and $500 million of its 7.75% senior notes due 2016. The proceeds of the offering were used, together with cash on hand, to purchase substantially all of EME's outstanding 10% senior notes due 2008 and 9.875% senior notes due 2011. In connection with the purchase of these notes, EME recorded a $143 million loss on early extinguishment of debt in the second quarter of 2006.

On June 15, 2006, EME entered into a new credit agreement providing for $500 million in revolving loan and letter of credit capacity to be used for general corporate purposes including credit support for the hedging and trading activities of EME and its subsidiaries. The new credit agreement replaces EME's $98 million credit agreement.

ERP Initiative

EME has commenced a new initiative as part of an Edison International enterprise-wide project to implement an integrated enterprise resource planning (ERP) application from SAP during the next two years. The implementation of this application will replace EME's existing financial, human resources, materials management, and fuel management information systems with SAP's integrated ERP application. The objective of this initiative is to improve the efficiency and effectiveness of EME's operational systems and enhance the transparency of information throughout the company.

Critical Accounting Estimates

Introduction

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

Derivative Financial Instruments and Hedging Activities

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

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

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

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

EME enters into master agreements and other arrangements in conducting price risk management and trading activities with a right of setoff in the event of bankruptcy or default by the counterparty.

These types of transactions are reported net in the balance sheet in accordance with Financial Accounting Standards Board Interpretation No. 39, "Offsetting Amounts Related to Certain Contracts."

Impairment of Long-Lived Assets

EME follows Statement of Financial Accounting Standards No. 144, "Accounting for the Impairment or Disposal of Long-Lived Assets," or SFAS No. 144. EME evaluates long-lived assets whenever indicators of impairment exist. This accounting standard requires that if the undiscounted expected future cash flow from a company's assets or group of assets (without interest charges) is less than its carrying value, asset impairment must be recognized in the financial statements. The amount of impairment is determined by the difference between the carrying amount and fair value of the asset.

The assessment of impairment is a critical accounting estimate because significant management judgment is required to determine: (1) if an indicator of impairment has occurred, (2) how assets should be grouped, (3) the forecast of undiscounted expected future cash flow over the asset's estimated useful life to determine if an impairment exists, and (4) if an impairment exists, the fair value of the asset or asset group. Factors that EME considers important, which could trigger an impairment, include operating losses from a project, projected future operating losses, the financial condition of counterparties, or significant negative industry or economic trends. During 2005, 2004 and 2003, EME recorded impairment charges of $55 million, $35 million and $304 million, respectively, related to specific assets included in continuing operations. See "Results of Continuing Operations—Earnings from Consolidated Operations—Illinois Plants" and "Results of Continuing Operations—Earnings from Unconsolidated Affiliates—Impairment Loss on Equity Method Investment" and "—Asset Impairment Charges."

Off-Balance Sheet Financing

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

Based on existing accounting guidance, EME does not record these lease obligations in its consolidated balance sheet. If these transactions were required to be consolidated as a result of future changes in accounting guidance, it would: (1) increase property, plant and equipment and long-term obligations in the consolidated financial position, and (2) impact the pattern of expense recognition related to these obligations because EME would likely change from its current straight-line recognition of rental expense to an annual recognition of the straight-line depreciation on the leased assets as well as the interest component of the financings which is weighted more heavily toward the early years of the obligations. The difference in expense recognition would not affect EME's cash flows under these

transactions. See "Liquidity and Capital Resources—Off-Balance Sheet Transactions—Sale-Leaseback Transactions."

Contract Indemnities

During 2004, EME sold a majority of its international operations. The asset sale agreements contain indemnities from EME to the purchasers, including indemnification for pre-closing environmental liabilities and for pre-closing foreign taxes imposed with respect to operations of the assets prior to the sale. At June 30, 2006, EME had recorded an estimated liability of $94 million related to these matters.

In addition, Midwest Generation has agreed to reimburse Commonwealth Edison and Exelon Generation for 50% of specific existing asbestos claims and expenses less recovery of insurance costs, and agreed to a sharing arrangement for liabilities and expenses associated with future asbestos-related claims as specified in a supplemental agreement. See "Liquidity and Capital Resources—Contractual Obligations, Commitments and Contingencies—Commercial Commitments." Midwest Generation engaged an independent actuary during 2004 with extensive experience in performing asbestos studies to estimate future losses based on its claims experience and other available information. In calculating future losses, the actuary made various assumptions, including, but not limited to, the settlement of future claims under the supplemental agreement with Commonwealth Edison as described above, the distribution of exposure sites, and that the filing date of asbestos claims will not be after 2045. At June 30, 2006, Midwest Generation had recorded a liability of $66 million related to this contract indemnity.

Income Taxes

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

As part of the process of preparing its consolidated financial statements, EME is required to estimate its income taxes in each jurisdiction in which it operates. This process involves estimating actual current tax expense together with assessing temporary differences resulting from differing treatment of items, such as depreciation, for tax and accounting purposes. These differences result in deferred tax assets and liabilities, which are included within EME's consolidated balance sheet. In addition, estimated taxes for uncertain tax positions are accrued and included in other long-term liabilities in the consolidated balance sheet.

For additional information regarding EME's accounting policies, see "Audited Consolidated Financial Statements of Edison Mission Energy—Notes to Consolidated Financial Statements—Note 2. Summary of Significant Accounting Policies."

RESULTS OF OPERATIONS

EME operates in one line of business, independent power production. Operating revenues are primarily derived from the sale of power generated from the Illinois Plants and the Homer City facilities. Intercompany interest expense and income between EME and its consolidated subsidiaries have been eliminated in the following project results, except as described below with respect to loans

provided to EME from a wholly owned subsidiary, Midwest Generation. Equity in income from unconsolidated affiliates relates to energy projects accounted for under the equity method. EME recognizes its proportional share of the income or loss of such entities.

On April 1, 2006, EME received, as a capital contribution, ownership interests in a portfolio of wind projects located in Iowa and Minnesota and a small biomass project. These projects were previously owned by EME's affiliate, Edison Capital. Edison Mission Group is a subsidiary of Edison International and is the holding company for its wholly owned subsidiaries, Mission Energy Holding Company (MEHC) and Edison Capital. MEHC is the holding company of its wholly owned subsidiary EME. EME accounted for this acquisition at Edison Capital's historical cost as a transaction between entities under common control. Therefore, these consolidated financial statements include the results of operations, financial position and cash flows of the acquired projects as though EME had such ownership throughout the periods presented.

EME uses the words "earnings" or "losses" in this section to describe income or loss from continuing operations before income taxes.

Interim Results of Continuing Operations

The following section provides a summary of the operating results for the second quarters of 2006 and 2005 and six months ended June 30, 2006 and 2005 together with discussions of the contributions by specific projects and of other significant factors affecting these results.

		Three Months Ended June 30,						Six Months Ended June 30,
		2006			2005			2006			2005
		(in millions)
Project Earnings (Losses)(1)
	*Consolidated operations*
	Illinois Plants	$	25		$	18		$	152		$	110
	Homer City		35			8			33			50
	Energy Trading(2)		26			19			55			41
	San Juan Mesa		1			—			5			—
	Storm Lake		3			2			3			2
	Other		(1	)		—			—			—
	*Unconsolidated affiliates*
	Big 4 projects		32			40			55			61
	Sunrise		5			5			3			2
	March Point		—			(4	)		—			4
	Doga		5			1			4			5
	Other		2			1			3			5

			133			90			313			280
	Corporate interest income		20			13			37			24
	Corporate interest expense		(64	)		(68	)		(130	)		(136	)
	Corporate administrative and general		(25	)		(26	)		(49	)		(59	)
	Gain on sale of assets		—			—			4			—
	Loss on early extinguishment of debt		(143	)		—			(143	)		(4	)
	Other income (expense), net		—			—			10			(6	)

		$	(79	)	$	9		$	42		$	99

(1): Project earnings are equal to income from continuing operations before income taxes, except for production tax credits. Accordingly, project earnings for the wind projects include $4 million and $3 million of production tax credits for the second quarters of 2006 and 2005, respectively, and $9 million and $4 million for the six months ended June 30, 2006 and 2005,

respectively. Production tax credits are recognized as wind energy is generated based upon a per kilowatt-hour rate prescribed in applicable federal and state statutes. Under generally accepted accounting principles (GAAP), production tax credits generated by the wind projects are recorded as a reduction in income taxes. Accordingly, project earnings (losses) represent a non-GAAP performance measure which may not be comparable to those of other companies. Management believes that inclusion of production tax credits in project earnings for wind projects is more meaningful for investors as federal and state subsidies are an integral part of the economics of these projects. The following table reconciles the total project earnings as shown above with income from continuing operations before income taxes under GAAP:

	Three Months Ended June 30,						Six Months Ended June 30,
	2006			2005			2006			2005
	(in millions)
Project earnings (losses)	$	(79	)	$	9		$	42		$	99
Less: Production tax credits		(4	)		(3	)		(9	)		(4	)

Income (loss) from continuing operations before income taxes	$	(83	)	$	6		$	33		$	95

(2): Income from energy trading represents the gains recognized from price volatility associated with the purchase and sale of contracts for electricity, fuels and transmission. The indirect cost of energy trading is included in administrative and general expenses.

Earnings from Consolidated Operations

Illinois Plants

			Three Months Ended June 30,						Six Months Ended June 30,
			2006			2005			2006			2005
			(in millions)
Operating Revenues
	Energy revenues		$	261		$	244		$	599		$	571
	Capacity revenues			7			8			13			14
	Other revenues			2			2			4			4
	Net losses from price risk management			(4	)		(1	)		(4	)		(11	)

	Total operating revenues			266			253			612			578

Operating Expenses
	Fuel			72			72			166			171
	Gain on sale of emission allowances(1)			—			—			(6	)		—
	Plant operations			115			107			196			191
	Plant operating leases			18			19			37			37
	Depreciation and amortization			25			25			50			50
	Asset impairment charges			—			7			—			7
	Administrative and general			7			5			12			10

	Total operating expenses			237			235			455			466

Operating Income				29			18			157			112

Other Income (Expense)
	Interest income on note receivable from EME			28			29			56			57
	Interest expense and other			(32	)		(29	)		(61	)		(59	)

	Total other income (expense)			(4	)		—			(5	)		(2	)

Income Before Taxes			$	25		$	18		$	152		$	110

Statistics
	Coal-Fired Generation(2)
		Generation (in GWh)		5,493			5,834			12,738			14,229
		Equivalent availability(3)		66.0	%		62.1	%		76.4	%		71.1	%
		Capacity factor(4)		44.8	%		47.6	%		52.3	%		58.4	%
		Load factor(5)		67.9	%		76.7	%		68.4	%		82.1	%
		Forced outage rate(6)		7.7	%		9.6	%		5.0	%		8.7	%
	Average energy price/MWh		$	47.63		$	41.83		$	47.09		$	40.12
	Average fuel costs/MWh		$	13.42		$	12.51		$	13.14		$	12.12

(1): EME recorded $6 million of intercompany profit during the first quarter of 2006 on emission allowances sold by the Illinois Plants to the Homer City facilities in the fourth quarter of 2005 but not used by the Homer City facilities until the first quarter of 2006.
(2): This table summarizes key performance measures related to coal-fired generation, which represents the majority of the operations of the Illinois Plants.
(3): The equivalent availability factor is defined as the number of megawatt-hours the coal plants are available to generate electricity divided by the product of the capacity of the coal plants (in megawatts) and the number of hours in the period. Equivalent availability reflects the impact of the unit's inability to achieve full load, referred to as derating, as well as outages which result in a complete unit shutdown. The coal plants are not available during periods of planned and unplanned maintenance.

(4): Capacity factor is defined as the actual number of megawatt-hours generated by the coal plants divided by the product of the capacity of the coal plants (in megawatts) and the number of hours in the period.
(5): The load factor is determined by dividing capacity factor by the equivalent availability factor.
(6): Midwest Generation refers to unplanned maintenance as a forced outage.

Earnings from the Illinois Plants were $25 million and $152 million during the second quarter of 2006 and six months ended June 30, 2006, respectively, compared to $18 million and $110 million for the comparable periods in the prior year. The increase in the second quarter earnings of $7 million was primarily due to higher energy margin (energy revenues less fuel expenses) and an asset impairment charge recorded during the second quarter of 2005 primarily associated with a redefined capital program related to coal dust mitigation partially offset by higher planned maintenance costs. Although generation in the second quarter of 2006 was lower than the second quarter of 2005, energy margin increased primarily due to a 14% increase in average energy prices.

Earnings for the six months ended June 30, 2006 increased $42 million primarily due to higher energy margin driven by higher average energy prices, recognition of income in 2006 from the sale of emission allowances to the Homer City facilities, and the 2005 asset impairment charge described above.

Losses from price risk management activities are due to price changes on power contracts that did not qualify for hedge accounting under SFAS No. 133. At June 30, 2006, cumulative unrealized losses of $12 million (pre-tax) have been recognized on hedge contracts that pertain to the remainder of 2006, 2007 and 2008. See "Market Risk Exposures—Commodity Price Risk" for more information regarding forward market prices.

The earnings of the Illinois Plants included interest income of $28 million and $29 million for the second quarters of 2006 and 2005, respectively, and $56 million and $57 million for the six months ended June 30, 2006 and 2005, respectively, related to loans to EME. In August 2000, Midwest Generation, which owns or leases the Illinois Plants, entered into a sale-leaseback transaction of the Powerton-Joliet facilities. The proceeds from the sale of these facilities were loaned to EME, which also provided a guarantee of the related lease obligations of Midwest Generation. The Powerton-Joliet sale-leaseback is recorded as an operating lease for accounting purposes.

Homer City

		Three Months Ended June 30,						Six Months Ended June 30,
		2006			2005			2006			2005
		(in millions)
Operating Revenues
	Energy revenues	$	143		$	133		$	277		$	288
	Capacity revenues		4			5			6			9
	Other revenues		3			—			4			—
	Net gains (losses) from price risk management		1			(2	)		(13	)		(4	)

	Total operating revenues		151			136			274			293

Operating Expenses
	Fuel(1)		68			60			129			124
	Gain on sale of emission allowances(2)		—			—			—			—
	Plant operations		28			37			63			59
	Plant operating leases		26			26			51			51
	Depreciation and amortization		4			4			8			8
	Administrative and general		1			2			2			4

	Total operating expenses		127			129			253			246

Operating Income			24			7			21			47

Other Income (Expense)
	Interest and other income		12			2			13			4
	Interest expense		(1	)		(1	)		(1	)		(1	)

	Total other income (expense)		11			1			12			3

Income Before Taxes		$	35		$	8		$	33		$	50

Statistics
	Generation (in GWh)		2,866			3,102			5,387			6,636
	Equivalent availability(3)		74.3	%		77.1	%		73.1	%		82.6	%
	Capacity factor(4)		69.5	%		75.2	%		65.7	%		80.8	%
	Load factor(5)		93.6	%		97.6	%		89.9	%		97.9	%
	Forced outage rate(6)		19.9	%		3.6	%		22.8	%		5.6	%
	Average energy price/MWh	$	50.02		$	42.93		$	51.43		$	43.38
	Average fuel costs/MWh	$	24.13		$	19.36		$	24.03		$	18.65

(1): Included in fuel costs were $9 million and $14 million during the second quarters of 2006 and 2005, respectively, and $21 million and $29 million during the six months ended June 30, 2006 and 2005, respectively, related to the net cost of SO2 emission allowances. See "Market Risk Exposures—Commodity Price Risk—Emission Allowances Price Risk" for more information regarding the price of SO2 allowances.
(2): The Homer City facilities sold excess NOx emission allowances to the Illinois Plants at fair market value. Sales to the Illinois Plants were $6 million in the first quarter of 2006. EME eliminated the intercompany transaction for emission allowances sold but not yet used by the Illinois Plants at June 30, 2006.
(3): The equivalent availability factor is defined as the number of megawatt-hours the coal plants are available to generate electricity divided by the product of the capacity of the coal plants (in megawatts) and the number of hours in the period. Equivalent availability reflects the impact of the unit's inability to achieve full load, referred to as derating, as well as outages which result in a complete unit shutdown. The coal plants are not available during periods of planned and unplanned maintenance.
(4): The capacity factor is defined as the actual number of megawatt-hours generated by the coal plants divided by the product of the capacity of the coal plants (in megawatts) and the number of hours in the period.

(5): The load factor is determined by dividing capacity factor by the equivalent availability factor.
(6): Homer City refers to unplanned maintenance as a forced outage.

Earnings from Homer City increased $27 million and decreased $17 million for the second quarter of 2006 and six months ended June 30, 2006, respectively, compared to the corresponding periods of 2005. The second quarter increase is primarily attributable to higher energy margin, lower planned maintenance costs and estimated insurance recovery related to the Unit 3 outage described below. Although generation in the second quarter of 2006 was lower than the second quarter of 2005, due to the unplanned outage at Unit 3, there was a 17% increase in average energy prices. The 2006 year-to-date decrease is primarily attributable to lower energy margin and higher plant operating costs in 2006 due to the unplanned outage at Unit 3, partially offset by estimated insurance recovery. Homer City is generally classified as a baseload plant, which means the amount of generation is largely based on the availability of the plant. Accordingly, the Unit 3 outage reduced the amount of generation during the first six months of 2006.

Homer City Unit 3 Outage—

On January 29, 2006, the main power transformer on Unit 3 of the Homer City facilities failed resulting in a suspension of operations at this unit. Homer City secured a replacement transformer and Unit 3 returned to service on May 5, 2006. Homer City has adjusted its previously planned outage schedules for Unit 3 and the other Homer City units in order to minimize to the extent practicable overall outage activities for all units through the first half of 2007. Taking into consideration the impact of the outage, generation for the year is currently expected to be approximately 13 terawatt hours (TWh). The actual financial impact and generation levels in 2006 will depend on the effect of market conditions upon the dispatch of the plant and on prevailing power prices during the balance of the year.

The main transformer failure will result in claims under Homer City's property and business interruption insurance policies. At June 30, 2006, Homer City recorded a $17 million receivable related to these claims. Resolution of the claims is subject to a number of uncertainties, including computations of the lost profit during the outage period.

Price Risk Management—

Homer City recorded gains (losses) of approximately $(5) million and $1 million during the second quarters of 2006 and 2005, respectively, and $(16) million and $(3) million during the six months ended June 30, 2006 and 2005, respectively, representing the amount of cash flow hedges' ineffectiveness. Losses related to the ineffective portion of hedge contracts were primarily due to changes in the difference between energy prices at PJM West Hub (the settlement point under forward contracts) and the energy prices at the Homer City busbar (the delivery point where power generated by the Homer City facilities is delivered into the transmission system). Also included in net gains (losses) from price risk management activities are economic hedges that did not qualify for hedge accounting under SFAS No. 133 of $6 million and $(3) million in the second quarters of 2006 and 2005, respectively, and $3 million and $(1) million during the six months ended June 30, 2006 and 2005, respectively. At June 30, 2006, cumulative unrealized losses of $42 million (pre-tax) have been recognized on hedge contracts that pertain to the remainder of 2006, 2007 and 2008. See "Market Risk Exposures—Commodity Price Risk" for more information regarding forward market prices.

Energy Trading

EME seeks to generate profit by utilizing the commercial platform of its subsidiary, EMMT, to engage in trading activities in those markets in which it is active as a result of its management of the merchant power plants of Midwest Generation and Homer City. EMMT trades power, fuel and transmission primarily in the eastern power grid using products available over the counter, through exchanges and from independent system operators. Earnings from energy trading activities increased $7 million and $14 million for the second quarter of 2006 and six months ended June 30, 2006, respectively, compared to the corresponding periods of 2005. The increase in earnings from energy trading activities was primarily due to increased congestion at specific delivery points in the eastern power grid in which EMMT purchased financial transmission rights. See "Business—Regulatory Matters—MISO Revenue Sufficiency Guarantee Charges" for information regarding potential refund exposure related to virtual supply offers made by EMMT in MISO after April 1, 2005.

San Juan Mesa

EME's earnings from the San Juan Mesa wind project were $1 million and $5 million for the second quarter of 2006 and six months ended June 30, 2006, with no earnings recorded in 2005 due to the acquisition of the San Juan Mesa wind project on December 27, 2005.

During the first quarter of 2006, EME completed the sale of 25% of its ownership interest in the San Juan Mesa wind project to Citi Renewable Investments I LLC, a wholly owned subsidiary of Citicorp North America, Inc. Proceeds from the sale were $43 million. EME recorded a pre-tax gain on the sale of approximately $4 million during the first quarter of 2006.

Earnings from Unconsolidated Affiliates

Big 4 Projects

Earnings from the Big 4 projects decreased $8 million and $6 million for the second quarter of 2006 and six months ended June 30, 2006, respectively, compared to the corresponding periods of 2005. The decreases in earnings were primarily due to lower earnings from the Kern River project during the first six months of 2006, compared to the first six months of 2005, resulting from the expiration of the project's long-term power purchase and steam supply agreements in August 2005. Effective June 1, 2006, the project commenced selling electricity under a five-year bilateral agreement with Southern California Edison Company. The decrease in year-to-date earnings was partially offset by generally higher steam and energy prices in 2006 over 2005.

The earnings from the Big 4 projects included interest expense from Edison Mission Energy Funding of $1 million and $2 million for the second quarters of 2006 and 2005, respectively, and $3 million and $5 million for the six months ended June 30, 2006 and 2005, respectively.

March Point

EME's share of earnings from its ownership interest in March Point was $(4) million for the second quarter of 2005 and $4 million for the six months ended June 30, 2005, respectively, resulting, in part, from mark-to-market gains (losses) related to gas purchase contracts. During the third quarter of 2005, EME recorded an impairment charge related to its March Point investment which resulted in suspension of equity accounting. Accordingly, no earnings were recorded during the first six months of 2006.

Doga

Earnings from the Doga project increased $4 million in the second quarter of 2006 compared to the second quarter of 2005 and were about the same for the respective six-month periods. The second quarter increase in earnings was primarily due to higher energy margin, lower maintenance expenses and lower taxes.

In June 2006, the corporate tax rate in Turkey was reduced from 30% to 20%. Although this will reduce future income tax payments, Doga will report a loss from a reduction in deferred tax assets (related to levelization of income under the power purchase agreement for financial reporting purposes). EME records its share of earnings from Doga on a lag, which means that the impact of the reduction in deferred tax assets will be recorded in the third quarter of 2006. EME's share of the loss related to reduction in deferred tax assets is estimated to be approximately $11 million.

Corporate Interest Income

EME corporate interest income increased $7 million and $13 million for the second quarter of 2006 and six months ended June 30, 2006, respectively, compared to the corresponding periods of 2005. The increase was primarily attributable to higher interest rates in 2006 compared to 2005.

Corporate Interest Expense

	Three Months Ended June 30,				Six Months Ended June 30,
	2006		2005		2006		2005
	(in millions)
Interest expense to third parties	$	36	$	39	$	74	$	79
Interest expense to Midwest Generation		28		29		56		57

Total corporate interest expense	$	64	$	68	$	130	$	136

Corporate Administrative and General Expenses

Administrative and general expenses decreased $10 million for the six months ended June 30, 2006, compared to the corresponding period of 2005. The decrease was primarily due to $10 million of costs incurred during the six months ended June 30, 2005 for severance and related costs in connection with EME restructuring activities.

Loss on Early Extinguishment of Debt

Loss on early extinguishment of debt was $143 million for the second quarter of 2006 and six months ended June 30, 2006 related to the early repayment of EME's 10% senior notes due August 15, 2008 and 9.875% senior notes due April 15, 2011.

Loss on early extinguishment of debt was $4 million in the first six months of 2005 consisting of a $4 million loss related to the early repayment of junior subordinated debentures recorded during the first quarter of 2005.

Other Income (Expense), Net

Other income (expense), net increased $16 million for the six months ended June 30, 2006, compared to the corresponding period of 2005. The 2006 increase was partially attributable to an $8 million gain related to receipt of shares from Mirant Corporation from settlement of a claim recorded during the first quarter of 2006.

Income Taxes

EME's income tax provision from continuing operations was $1 million and $19 million for the six months ended June 30, 2006 and 2005, respectively. Income tax benefits are recognized pursuant to a tax-allocation agreement with Edison International. See "Liquidity and Capital Resources—EME's Liquidity as a Holding Company—Intercompany Tax-Allocation Agreement." During the six months ended June 30, 2006 and 2005, EME recognized $9 million and $4 million, respectively, of production tax credits related to wind projects and $3 million and $5 million, respectively, related to estimated state income tax benefits allocated from EIX. During the second quarter of 2005, EME resolved a dispute regarding additional taxes asserted by the Internal Revenue Service during the audit of the 1994-1996 tax returns. As a result of the resolution of this item, EME reversed $11.5 million of accrued taxes, recording this amount instead as a reduction of income taxes during the second quarter of 2005.

Interim Results of Discontinued Operations

Income from discontinued operations, net of tax, was $4 million and $21 million for the second quarters of 2006 and 2005, respectively, and $77 million and $28 million during the first six months of 2006 and 2005, respectively. The 2006 increase is largely attributable to distributions received from the Lakeland project, discussed below. During the first six months of 2005, EME completed the following sales:

On January 10, 2005, EME sold its 50% equity interest in the CBK hydroelectric power project to CBK Projects B.V. Proceeds from the sale were approximately $104 million.

On February 3, 2005, EME sold its 25% equity interest in the Tri Energy project to a consortium comprised of International Power plc 70% and Mitsui & Co., Ltd. (30%), referred to as IPM. Proceeds from the sale were approximately $20 million.

The aggregate after-tax gain on the sale of the aforementioned projects was $5 million.

Lakeland Project

EME previously owned a 220 MW power plant located in the United Kingdom, referred to as the Lakeland project. An administrative receiver was appointed in 2002 as a result of default by the project's counterparty, a subsidiary of TXU Europe Group plc and the project company was subsequently placed in liquidation. In response to its claim against the TXU subsidiary for damages resulting from the termination of the power sales agreement, the Lakeland project received a settlement of £116 million (approximately $217 million). EME is entitled to receive the amount of the settlement remaining after payment of creditor claims. As creditor claims have been settled, EME has received to date payments of £13 million (approximately $24 million) in April 2005, £61 million (approximately $106 million) in the first quarter of 2006, and £9 million (approximately $16 million) in April 2006. The after-tax income attributable to the Lakeland project was $10 million and $24 million for the second quarters of 2006 and 2005, respectively, and $83 million and $24 million for the six months ended June 30, 2006 and 2005, respectively. Beginning in 2002, EME reported the Lakeland project among discontinued operations and accounts for its ownership of Lakeland Power on the cost method, with earnings being recognized as cash is distributed from the project.

Annual Results of Continuing Operations for 2005, 2004 and 2003

The following section provides a summary of the operating results for the three years ended December 31, 2005 together with discussions of the contributions by specific projects and of other significant factors affecting these results.

		Years Ended December 31,
		2005			2004			2003
		(in millions)
Project Earnings (Losses)(1)
	*Consolidated operations*
	Illinois Plants	$	547		$	(881	)	$	(112	)
	Homer City		74			77			137
	Energy Trading(2)		195			23			34
	Doga(3)		—			6			13
	Storm Lake		2			8			(4	)
	Other		(1	)		4			5
	*Unconsolidated affiliates*
	Big 4 projects		158			142			135
	Four Star Oil & Gas		—			—			43
	Sunrise		29			28			35
	March Point		9			17			10
	Impairment loss on equity method investment		(55	)		—			—
	Doga		7			1			—
	Asset impairment charges		—			—			(59	)
	Other		13			12			1

			978			(563	)		238
	Corporate interest income		55			6			2
	Corporate interest expense		(270	)		(283	)		(292	)
	Corporate administrative and general		(126	)		(150	)		(138	)
	Gain on sale of assets		—			43			—
	Loss on early extinguishment of debt		(4	)		—			—
	Other income (expense), net		(3	)		(11	)		(18	)

		$	630		$	(958	)	$	(208	)

(1): Project earnings are equal to income from continuing operations before income taxes, except for production tax credits. Accordingly, project earnings for the wind projects include $8 million, $7 million and $7 million of production tax credits for the years ended December 31, 2005, 2004 and 2003, respectively. Production tax credits are recognized as wind energy is generated based upon a per kilowatt-hour rate prescribed in applicable federal and state statutes. Under GAAP, production tax credits generated by the wind projects are recorded as a reduction in income taxes. Accordingly, project earnings (losses) represent a non-GAAP performance measure which may not be comparable to those of other companies. Management believes that inclusion of production tax credits in project earnings for wind projects is more meaningful for investors as federal and state subsidies are an integral part of the economics of these projects. The following table reconciles the total project earnings as shown above with income from continuing operations before income taxes under GAAP:

	Years Ended December 31,
	2005			2004			2003
	(in millions)
Project earnings (losses)	$	630		$	(958	)	$	(208	)
Less: Production tax credits		(8	)		(7	)		(7	)

Income (loss) from continuing operations before income taxes	$	622		$	(965	)	$	(215	)

(2): Income from energy trading represents the gains recognized from price volatility associated with the purchase and sale of contracts for electricity, fuels and transmission. The indirect cost of energy trading is included in administrative and general expenses.
(3): Income before taxes of Doga represents both EME's 80% ownership interest and the ownership interests of minority interest holders on a calendar year basis. The interests of minority shareholders in the after-tax earnings of Doga are reflected in a separate line item in the consolidated statements of income.

Earnings from Consolidated Operations

Illinois Plants

			Years Ended December 31,
			2005			2004			2003
			(in millions)
Operating Revenues
	Energy revenues		$	1,445		$	758		$	667
	Capacity revenues			27			289			380
	Other revenues			10			15			8
	Net losses from price risk management			(53	)		(4	)		(3	)

	Total operating revenues			1,429			1,058			1,052

Operating Expenses
	Fuel(1)			383			408			401
	Gain on sale of emission allowances(2)			(56	)		(26	)		(10	)
	Plant operations			351			379			333
	Plant operating leases			75			84			104
	Depreciation and amortization			99			116			116
	Loss on lease termination, asset impairment and other charges			7			989			245
	Administrative and general			19			1			7

	Total operating expenses			878			1,951			1,196

Operating Income (Loss)				551			(893	)		(144	)

Other Income (Expense)
	Interest income from note receivable from EME			113			113			113
	Interest expense and other			(117	)		(101	)		(81	)

	Total other income (expense)			(4	)		12			32

Income (Loss) Before Taxes			$	547		$	(881	)	$	(112	)

Statistics—Coal-Fired Generation(3)
	Generation (in GWh):
		Merchant		30,953			17,133			13,561
		Power purchase agreement		—			13,435			13,949

		Total coal-fired generation		30,953			30,568			27,510

	Equivalent availability(4)			79.6	%		84.4	%		82.7	%
	Forced outage rate(5)			7.8	%		5.4	%		7.7	%
	Average energy price/MWh:
		Merchant	$	46.68		$	31.11		$	26.57
		Power purchase agreement	$	—		$	17.46		$	18.08
		Total coal-fired generation(6)	$	46.68		$	24.84		$	22.27
	Average fuel costs/MWh		$	12.40		$	11.60		$	11.28

(1): The Illinois Plants purchased NOx emission allowances from the Homer City facilities at fair market value. Purchases were $5 million in 2005 and none in 2004 and 2003. These purchases are included in fuel costs.

(2): The Illinois Plants sold excess SO2 emission allowances to the Homer City facilities at fair market value. Sales to the Homer City facilities were $61 million in 2005, $26 million in 2004 and $10 million in 2003. These sales reduced operating expenses. In addition, EME eliminated $6 million of intercompany profit in 2005 on emission allowances sold but not yet used by the Homer City facilities at December 31, 2005.
(3): This table summarizes key performance measures related to coal-fired generation, which represents the majority of the operations of the Illinois Plants.
(4): The availability factor is determined by the number of megawatt-hours the coal plants are available to generate electricity divided by the product of the capacity of the coal plants (in megawatts) and the number of hours in the period. Equivalent availability reflects the impact of the unit's inability to achieve full load, referred to as derating, as well as outages which result in a complete unit shutdown. The coal plants are not available during periods of planned and unplanned maintenance.
(5): Midwest Generation refers to unplanned maintenance as a forced outage.
(6): The average energy price in prior year periods represents an average, weighted by generation, of energy prices earned by the merchant coal plants and energy prices earned under the power purchase agreements with Exelon Generation. Due to the structure of the power purchase agreements with Exelon Generation (with higher capacity prices and lower energy prices), the composite data in 2004 and 2003 is not directly comparable to 2005 merchant energy prices.

Earnings from the Illinois Plants increased $1.4 billion in 2005 compared to 2004, and losses increased $769 million in 2004 compared to 2003. Discrete items affecting the income (loss) of the Illinois Plants include:

•: $961 million loss in 2004 related to the termination of the Collins Station lease and the return of ownership of the Collins Station to EME, and the impairment of plant assets and related inventory reserves. Management concluded that the Collins Station was not economically competitive in the marketplace given generation overcapacity and ceased operations effective September 30, 2004; and
•: $29 million loss recorded in 2004 and $245 million loss in 2003 related to the impairment of small peaking units in Illinois.

Earnings from the Illinois Plants, excluding the above discrete items, increased $438 million in 2005 compared to 2004, and decreased $24 million in 2004 compared to 2003. The 2005 increase in earnings is due to the following factors:

•: substantially higher energy revenues resulting from increased average energy prices;
•: higher fuel costs in 2004 during the period the Collins Station operated (operations ceased effective September 30, 2004);
•: an increase in sales of excess SO2 emission allowances in 2005, as compared to 2004, primarily due to higher market prices;
•: the absence in 2005 as compared to 2004 of a $56 million charge recorded during the fourth quarter of 2004 related to an estimate of possible future payments under a contract indemnity agreement related to asbestos claims with respect to activities at the Illinois Plants prior to their acquisition in 1999. See "Liquidity and Capital Resources—Contractual Obligations, Commitments and Contingencies—Indemnities Provided as Part of the Acquisition of the Illinois Plants"; and
•: lower plant operating lease costs due to the termination of the Collins Station lease in April 2004.

Partially offset by:

•: lower capacity revenues resulting from the expiration of the power purchase agreements with Exelon Generation;

•: higher plant operation costs due to higher planned maintenance;
•: higher coal costs attributable to higher coal prices primarily due to price escalation under coal and transportation agreements; and
•: higher interest expense primarily attributable to a full year of interest expense in 2005 versus approximately eight months of interest expense in 2004 related to debt issued in April 2004 by Midwest Generation, which owns or leases the Illinois Plants.

The 2004 decrease in earnings is due to the following factors:

•: a $56 million charge related to an estimate of possible future payments under a contract indemnity agreement related to asbestos claims with respect to activities at the Illinois Plants prior to their acquisition in 1999; and
•: higher interest expense from new indebtedness incurred in 2004 compared to 2003.

Partially offset by:

•: lower plant operating lease costs due to the termination of the Collins Station lease in April 2004;
•: higher sales of excess SO2 emission allowances due to higher market prices; and
•: higher energy revenues in 2004 from increased merchant generation at higher prices which offset the lower capacity payments received under the power purchase agreements with Exelon Generation. Accordingly, energy revenues increased $90 million and capacity revenues decreased $91 million during 2004 compared to 2003.

During 2003 and 2004, one unit at the Collins Station was available for sale into the wholesale power market. Due to the substantial increase in natural gas prices in 2003 and 2004, the marginal cost of generation generally exceeded the spot price for energy. As a result, merchant sales from the Collins Station were minimal during 2003 and 2004. The Illinois Plants permanently ceased operations at all Collins Station units on September 30, 2004 after termination of the Collins Station lease.

Losses from price risk management were $53 million, $4 million and $3 million in 2005, 2004 and 2003, respectively. The 2005 increase was primarily due to significant price increases in 2005 on power contracts that did not qualify for hedge accounting under SFAS No. 133 resulting in losses. These energy contracts were entered into to hedge the price risk related to projected sales of power through 2007 (sometimes referred to as economic hedges). The 2005 losses included $30 million related to the 2005 hedge contracts which related to activities reported as energy revenues and $23 million unrealized losses related to 2006 and 2007 hedge contracts. See "Market Risk Exposures—Commodity Price Risk" for more information regarding forward market prices.

The earnings (losses) of the Illinois Plants included interest income of $113 million for each of the three years ended December 31, 2005, 2004 and 2003 related to loans to EME. In August 2000, Midwest Generation entered into a sale-leaseback transaction of the Powerton-Joliet facilities. The proceeds from the sale of these facilities were loaned to EME, which also provided a guarantee of the related lease obligations of Midwest Generation. The Powerton-Joliet sale-leaseback is recorded as an operating lease for accounting purposes. See "Management's Overview; Critical Accounting Estimates—Critical Accounting Estimates—Off-Balance Sheet Financing" for further discussion of these leases.

Homer City

		Years Ended December 31,
		2005			2004			2003
		(in millions)
Operating Revenues
	Energy revenues	$	632		$	486		$	491
	Capacity revenues		18			28			30
	Net gains (losses) from price risk management		(58	)		(17	)		10

	Total operating revenues		592			497			531

Operating Expenses
	Fuel(1)		288			215			199
	Gain on sale of emission allowances(2)		(4	)		—			(6	)
	Plant operations		112			88			82
	Plant operating leases		102			102			102
	Depreciation and amortization		16			15			15
	Administrative and general		6			3			1

	Total operating expenses		520			423			393

Operating Income			72			74			138

Other Income (Expense)
	Interest expense		(1	)		(1	)		(2	)
	Interest and other income (expense)		3			4			1

	Total other income (expense)		2			3			(1	)

Income Before Taxes		$	74		$	77		$	137

Statistics
	Generation (in GWh)		13,637			13,292			14,403
	Equivalent availability(3)		85.2	%		85.1	%		88.7	%
	Forced outage rate(4)		4.8	%		5.3	%		5.1	%
	Average energy price/MWh	$	46.29		$	36.20		$	34.02
	Average fuel costs/MWh	$	21.08		$	16.15		$	13.79

(1): The Homer City facilities purchased SO2 emission allowances from the Illinois Plants at fair market value. Purchases were $61 million in 2005, $26 million in 2004 and $10 million in 2003. These purchases are included in fuel costs.
(2): The Homer City facilities sold excess NOx emission allowances to the Illinois Plants at fair market value. Sales to the Illinois Plants were $5 million in 2005 and none in 2004 and 2003. These sales reduced operating expenses. In addition, EME eliminated $1 million of intercompany profit in 2005 on emission allowances sold but not yet used by the Illinois Plants at December 31, 2005.
(3): The availability factor is determined by the number of megawatt-hours the coal plants are available to generate electricity, divided by the product of the capacity of the coal plants (in megawatts) and the number of hours in the period. Equivalent availability reflects the impact of the unit's inability to achieve full load, referred to as derating, as well as outages which result in a complete unit shutdown. The coal plants are not available during periods of planned and unplanned maintenance.
(4): Homer City refers to unplanned maintenance as a forced outage.

Earnings from Homer City decreased $3 million in 2005 compared to 2004 and $60 million in 2004 compared to 2003. The 2005 decrease was primarily attributable to increased losses related to price risk management activities (explained below), mostly offset by higher energy margin including the effect of higher wholesale energy prices, higher coal prices, higher priced SO2 emission allowances and higher plant operations costs. Homer City had higher planned equipment maintenance costs in 2005 compared

to 2004 and incurred costs in 2005 related to the replacement of the catalyst for the pollution control equipment. Included in fuel costs were $81 million, $42 million and $18 million in 2005, 2004 and 2003, respectively, related to the net cost of SO2 emission allowances. See "Market Risk Exposures—Commodity Price Risk—Emission Allowances Price Risk" for more information regarding the price of SO2 allowances.

The 2004 decrease in earnings is primarily due to increased losses related to price risk management activities and an increase in fuel costs from higher priced SO2 emission allowances. Homer City also had lower energy revenues in 2004 due to lower generation and availability, which was mostly offset by increased average energy prices. Lower generation in 2004 was caused by a temporary interruption of coal deliveries under contracts with four fuel suppliers to the Homer City facilities. As a result of these interruptions, Homer City reduced generation during off-peak periods when power prices were lower and purchased coal from alternative suppliers at spot prices which were substantially higher than the contract prices from these four fuel suppliers. In addition, the Homer City facilities had an unplanned outage at Unit 1 in February 2004.

The average energy price earned by Homer City in 2005 and 2004 was $46.29/MWh and $36.20/MWh, respectively, compared to the average real-time market price at the Homer City busbar (the delivery point where power generated by the Homer City facilities is delivered into the transmission system) for the same periods of $54.80/MWh and $40.79/MWh, respectively. Homer City's average energy price was lower than the average real-time market price due to: (1) hedge contracts having been entered into in prior periods when market prices were lower, and (2) an increase in the differential in market prices at the PJM West Hub (the settlement point under forward contracts) versus the Homer City busbar. The increase in the differential is referred to as a widening of the basis between these PJM locations. Homer City hedges its energy price risk at PJM West Hub and retains the risk that the basis between PJM West Hub and Homer City widens. See "Market Risk Exposures—Commodity Price Risk—Basis Risk."

Losses from price risk management activities increased $41 million in 2005 compared to 2004 and $27 million in 2004 compared to 2003. The 2005 and 2004 increases were primarily attributable to the ineffective portion of forward and futures contracts which are derivatives that qualify as cash flow hedges under SFAS No. 133. Homer City recorded net gains (losses) of approximately $(63) million, $(14) million and $11 million in 2005, 2004 and 2003, respectively, representing the amount of cash flow hedges' ineffectiveness. The ineffective losses from Homer City were primarily attributable to an increase in the difference between energy prices at PJM West Hub and the energy prices at the Homer City busbar. Included in the 2005 ineffective losses was $44 million related to the 2006 and 2007 hedge contracts. Partially offsetting the ineffective losses were gains in 2005 primarily related to futures contracts that did not qualify for hedge accounting under SFAS No. 133. See "Market Risk Exposures—Commodity Price Risk" for more information regarding forward market prices.

Seasonal Disclosure

Due to higher electric demand resulting from warmer weather during the summer months, electric revenues generated from the Illinois Plants and the Homer City facilities are generally higher during the third quarter of each year. However, as a result of recent increases in market prices for power, driven in part by higher natural gas and oil prices, this historical trend may not be applicable to quarterly revenue in the future.

Energy Trading

EME seeks to generate profit by utilizing the commercial platform of its subsidiary, EMMT, to engage in trading activities in those markets in which it is active as a result of its management of the merchant power plants of Midwest Generation and Homer City. EMMT trades power, fuel and transmission primarily in the eastern power grid using products available over-the-counter, through exchanges and from independent system operators. Earnings from energy trading activities were $195 million, $23 million and $34 million in 2005, 2004 and 2003, respectively. Volatile market conditions in 2005, driven by increased prices for natural gas and oil and warmer summer temperatures, have created favorable conditions for EMMT's trading strategies in 2005 compared to 2004 and 2003.

Earnings from Unconsolidated Affiliates

Big 4 Projects

EME owns partnership investments (50% ownership or less) in Kern River Cogeneration Company, Midway-Sunset Cogeneration Company, Sycamore Cogeneration Company and Watson Cogeneration Company. These projects have similar economic characteristics and have been used, collectively, to secure bond financing by Edison Mission Energy Funding Corp., a special purpose entity. 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 $16 million in 2005 compared to 2004, and $7 million in 2004 compared to 2003. The 2005 and 2004 changes in earnings were largely due to higher energy prices in 2005 and 2004. The impact of the higher energy prices in 2005 was partially offset by lower earnings from the Kern River project during 2005, compared to 2004, resulting from the expiration of the project's long-term power purchase and steam supply agreements in August 2005 and an unplanned outage in December 2005. The impact of the higher energy prices in 2004 was partially offset by planned outages at the Sycamore Cogeneration plant and the Watson Cogeneration plant in March 2004.

Earnings from the Big 4 projects are net of interest expense of $9 million, $12 million and $16 million in 2005, 2004 and 2003, respectively, with respect to Edison Mission Energy Funding.

Four Star Oil & Gas

EME's share of earnings from its ownership interest in Four Star Oil & Gas Company was $43 million in 2003, with no earnings from its ownership interest recorded in 2004 and 2005 due to the sale of its interest in the company. The 2004 earnings include the gain on sale of 100% of EME's stock of Edison Mission Energy Oil & Gas, which in turn held minority interests in Four Star Oil & Gas, on January 7, 2004. Proceeds from the sale were approximately $100 million. EME recorded a pre-tax gain on the sale of approximately $47 million during the first quarter of 2004.

Sunrise

Earnings from the Sunrise project increased $1 million in 2005 from 2004 and decreased $7 million in 2004 from 2003. The 2005 increase was primarily the result of higher energy revenues attributable to increased dispatch. The 2004 decrease primarily resulted from higher interest expense due to the completion of the Sunrise project financing in September 2003.

March Point

Earnings from March Point decreased $8 million in 2005 from 2004 and increased $7 million in 2004 from 2003. The 2005 decrease is primarily attributable to earnings recorded for a full year in 2004, compared to nine months in 2005 due to the impairment charge recorded during the third quarter of 2005 discussed below. The increase in 2004 was attributable to higher operating revenues in 2004 because there was no planned outage in 2004, as there was in 2003.

Impairment Loss on Equity Method Investment

During the third quarter of 2005, EME fully impaired its equity investment in the March Point project following an updated forecast of future project cash flows. The March Point project is a 140 MW natural gas-fired cogeneration facility located in Anacortes, Washington, in which a subsidiary of EME owns a 50% partnership interest. The March Point project sells electricity to Puget Sound Energy, Inc. under two power purchase agreements that expire in 2011 and sells steam to Equilon Enterprises, LLC (a subsidiary of Shell Oil) under a steam supply agreement that also expires in 2011. March Point purchases a portion of its fuel requirements under long-term contracts with the remaining requirements purchased at current market prices. March Point's power sales agreements do not provide for a price adjustment related to the project's fuel costs. During the first nine months of 2005, long-term natural gas prices increased substantially, thereby adversely affecting the future cash flows of the March Point project. As a result, management concluded that its investment was impaired and recorded a $55 million charge during the third quarter of 2005.

Doga

In accordance with Statement of Financial Accounting Standards Interpretation No. 46(R), "Consolidation of Variable Interest Entities," EME determined that it was not the primary beneficiary of the Doga project and, accordingly, deconsolidated this project at March 31, 2004. Beginning April 1, 2004, EME recorded its interest in the Doga project on the equity method basis of accounting. Earnings from the Doga project were $7 million in 2005 and $1 million in 2004, representing earnings from the final three quarters of 2004. Revenues included in EME's consolidated statements of income from the Doga project were $29 million in 2004, representing revenues from the first quarter of 2004, and $124 million in 2003. Earnings from the Doga project were $6 million in 2004, representing earnings from the first quarter of 2004, and $13 million in 2003. Earnings decreased in 2004 from 2003 primarily due to lower generation and higher major maintenance costs due also to plant outages and the write-off of uncollectible receivables.

Asset Impairment Charges

Asset impairment charges were none in 2005 and 2004 and $59 million in 2003. In 2003, EME recorded a $59 million loss related to the write-down of EME's investments in the Brooklyn Navy Yard and Gordonsville projects due to their planned dispositions. These projects have since been sold.

Other

Earnings from other projects (unconsolidated affiliates) increased $11 million in 2004 from 2003. The 2004 increase was primarily due to higher earnings from the TM Star project due to mark-to-market losses recorded in 2003.

Seasonal Disclosure

EME's third quarter equity in income from its 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 energy projects located on the West Coast have power sales contracts that provide for higher payments during the summer months.

Corporate Interest Income

EME corporate interest income increased $49 million in 2005 from 2004 and $4 million in 2004 from 2003. The 2005 increase was primarily attributable to higher average cash balances in 2005 compared to 2004 due largely to cash proceeds received from the sale of international operations.

Corporate Interest Expense

	Years Ended December 31,
	2005		2004		2003
	(in millions)
Interest expense to third parties	$	157	$	170	$	179
Interest expense to Midwest Generation		113		113		113

Total corporate interest expense	$	270	$	283	$	292

Corporate Administrative and General Expenses

Administrative and general expenses decreased $24 million in 2005 from 2004, and increased $12 million in 2004 from 2003. The 2005 decrease was primarily due to decreased use of third-party consultants, partially offset by charges for severance and related costs of $13 million recorded in 2005. The 2004 increase was primarily due to increased use of third-party consultants and higher performance-based compensation, partially offset by lower debt restructuring costs.

Loss on Early Extinguishment of Debt

Loss on early extinguishment of debt was $4 million in 2005. Extinguishment of debt consisted of a $4 million loss related to the early repayment of EME's junior subordinated debentures recorded during the first quarter of 2005.

Income Taxes

EME's income tax provision (benefit) from continuing operations was $208 million in 2005, $(406) million in 2004 and $(121) million in 2003. Income tax benefits are recognized pursuant to a tax-allocation agreement with Edison International. See "Liquidity and Capital Resources—EME's Liquidity as a Holding Company—Intercompany Tax-Allocation Agreement." During the second quarter of 2005, EME resolved a dispute regarding additional taxes asserted by the Internal Revenue Service during the audit of the 1994-1996 tax returns. As a result of the resolution of this item, EME reversed $11.5 million of accrued taxes which was recorded as a reduction of income taxes during the second quarter of 2005. During the second quarter of 2004, EME recorded a tax benefit of $368 million primarily relating to the loss on the termination of the Collins Station lease, and during the first quarter of 2004, EME recorded a tax provision of $18 million relating to the sale of 100% of its stock in Edison Mission Energy Oil & Gas, which in turn held interests in Four Star Oil & Gas.

Cumulative Effect of Change in Accounting Principle for 2005, 2004 and 2003

Statement of Financial Accounting Standard Interpretation No. 47

Effective December 31, 2005, EME adopted Financial Accounting Standard Interpretation No. 47, "Accounting for Conditional Asset Retirement Obligations" (FIN 47). For further discussion of FIN 47 refer to "New Accounting Pronouncements." EME recorded a $1 million, after tax, decrease to net income as the cumulative effect of the adoption of FIN 47.

Statement of Financial Accounting Standards No. 143

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

Annual Results of Discontinued Operations for 2005, 2004, and 2003

Income from discontinued operations, net of tax, was $29 million in 2005, $690 million in 2004 and $124 million in 2003. During 2005, EME completed the following sales:

•: On January 10, 2005, EME sold its 50% equity interest in the CBK hydroelectric power project to CBK Projects B.V. Proceeds from the sale were approximately $104 million.
•: On February 3, 2005, EME sold its 25% equity interest in the Tri Energy project to IPM. Proceeds from the sale were approximately $20 million.

The aggregate after-tax gain on sale of the projects mentioned above was $5 million. During the third quarter of 2005, EME recorded tax benefit adjustments of $28 million, which resulted from completion of the 2004 federal and California income tax returns and quarterly review of tax accruals. The majority of the tax adjustments are related to the sale of the international projects in December 2004. During the fourth quarter of 2005, EME recorded an after-tax charge of $25 million related to a tax indemnity for a project sold to IPM in December 2004. This charge related to an adverse tax court ruling in Spain, which the local company plans to appeal.

During 2004, EME completed the following sales:

•: On September 30, 2004, EME sold its 51.2% interest in Contact Energy to Origin Energy New Zealand Limited. Consideration for the sale was NZ$1,101.4 million (approximately US$739 million) in cash and NZ$535 million (approximately US$359 million) of debt assumed by the purchaser.
•: On December 16, 2004, EME sold the stock and related assets of MEC International B.V. (MECIBV) to IPM. The sale of MECIBV included the sale of EME's interests in ten electric power generating projects or companies located in Europe, Asia, Australia, and Puerto Rico. Consideration from the sale of MECIBV was $2.0 billion in cash. EME retained its ownership of the subsidiaries associated with the Lakeland project and some inactive subsidiaries.

The aggregate after-tax gain on the sale of the above-referenced international projects was $533 million.

Lakeland Project

EME previously owned a 220-MW power plant located in the United Kingdom, referred to as the Lakeland project. An administrative receiver was appointed in 2002 as a result of a default by the project's counterparty, a subsidiary of TXU Europe Group plc. Following a claim for termination of the power sales agreement, the Lakeland project received a settlement of £116 million (approximately $217 million). EME is entitled to receive the remaining amount of the settlement after payment of creditor claims. The after-tax income attributable to the Lakeland project was $24 million for 2005 and none in 2004 and 2003. Beginning in 2002, EME reported the Lakeland project as discontinued operations and accounts for its ownership of Lakeland Power on the cost method (earnings are recognized as cash is distributed from the project).

Related Party Transactions

Specified EME subsidiaries have ownership in partnerships that sell electricity generated by their project facilities to Southern California Edison Company and others under the terms of long-term power purchase agreements. Sales by these partnerships to Southern California Edison Company under these agreements amounted to $932 million, $824 million and $754 million in 2005, 2004 and 2003, respectively.

New Accounting Pronouncements

Statement of Financial Accounting Standards No. 151

In November 2004, the FASB issued SFAS No. 151, "Inventory Costs." SFAS No. 151 requires that abnormal amounts of idle facility expense, freight, handling costs and spoilage be recognized as current-period charges. Further, SFAS No. 151 requires the allocation of fixed production overheads to inventory based on the normal capacity of the production facilities. Unallocated overheads must be recognized as an expense in the period in which they are incurred. SFAS No. 151 is effective for inventory costs incurred beginning in the first quarter of 2006. The adoption of this standard had no impact on EME's consolidated financial statements.

Statement of Financial Accounting Standards Interpretation No. 47

In March 2005, the FASB issued FIN 47, Accounting for Conditional Asset Retirement Obligations (AROs), an interpretation of SFAS 143. This interpretation clarifies that an entity is required to recognize a liability for the fair value of a conditional ARO if the fair value can be reasonably estimated, even though uncertainty exists about the timing and/or method of settlement. This interpretation became effective as of December 31, 2005 for EME. EME identified conditional AROs related to asbestos removal and disposal costs at its owned Illinois Plants (buildings and power plant facilities) and retired structures leased at the Powerton Station. EME recorded a $1 million, after tax, charge as a cumulative effect adjustment for asbestos removal and disposal activities associated with retired Powerton structures that are currently scheduled for demolition in 2007. EME has not recorded a liability related to the owned structures because it cannot reasonably estimate fair value of the obligation at this time. The range of time over which EME may settle this obligation in the future (demolition or other method) is sufficiently large to not allow for the use of expected present value techniques.

Statement of Financial Accounting Standards No. 123(R)

A new accounting standard requires companies to use the fair value accounting method for stock-based compensation. EME implemented the new standard in the first quarter of 2006 and applied the modified prospective transition method. Under the modified prospective method, the new accounting standard was applied effective January 1, 2006 to the unvested portion of awards previously granted and will be applied to all prospective awards. Prior financial statements were not restated under this method. The new accounting standard resulted in the recognition of expense for all stock-based compensation awards. Prior to January 1, 2006, EME used the intrinsic value method of accounting, which resulted in no recognition of expense for Edison International stock options.

Prior to adoption of the new accounting standard, EME presented all tax benefits of deductions resulting from the exercise of stock options as a component of operating cash flows under the caption "Other operating—liabilities" in the consolidated statements of cash flows. The new accounting standard requires the cash flows resulting from the tax benefits that occur from estimated tax deductions in excess of the compensation cost recognized for those options (excess tax benefits) to be classified as financing cash flows. The $4 million excess tax benefit is classified as a financing cash inflow in 2006.

Due to the adoption of this new accounting standard, EME recorded a cumulative effect adjustment that increased net income by approximately $0.4 million, net of tax, in the first quarter of 2006, mainly to reflect the change in the valuation method for performance shares classified as liability awards and the use of forfeiture estimates.

FASB Staff Position FIN 46(R)-6

In April 2006, the FASB issued Staff Position FIN 46(R)-6, "Determining Variability to be Considered in Applying FIN 46(R)." FIN 46(R)-6 states that the variability to be considered in applying FIN 46(R) shall be based on an analysis of the design of the entity following a two-step process. The first step is to analyze the nature of the risks in the entity. The second step would be to determine the purpose(s) for which the entity was created and determine the variability (created by the risks identified in Step 1) the entity is designed to create and pass along to its interest holders. The guidance in this FASB Staff Position is effective prospectively beginning July 1, 2006, although companies have until December 31, 2006 to elect retrospective applications. EME has not yet selected a transition method.

Statement of Financial Accounting Standards Interpretation No. 48

In July 2006, the FASB issued Statement of Financial Accounting Standards Interpretation No. 48, "Accounting for Uncertainty in Income Taxes," that clarifies the accounting for uncertain tax positions. An enterprise would be required to recognize, in its financial statements, the best estimate of the impact of a tax position by determining if the weight of the available evidence indicates it is more likely than not, based solely on the technical merits, that the position will be sustained on audit. The effective date applicable to EME is January 1, 2007. EME is currently assessing the potential impact of the interpretation on its financial condition.

LIQUIDITY AND CAPITAL RESOURCES

At June 30, 2006, EME and its subsidiaries had cash and cash equivalents and short-term investments of $1.6 billion and EME had available the full amount of borrowing capacity under its new $500 million corporate credit facility. EME's consolidated debt at June 30, 2006 was $3.4 billion. In addition, EME's subsidiaries had $4.4 billion of long-term lease obligations related to the sale-leaseback transactions that are due over periods ranging up to 29 years.

EME Financing Developments

During June 2006, EME replaced its $98 million credit agreement with a new credit agreement that provides for a $500 million senior secured revolving loan and letter of credit facility and matures on June 15, 2012. As security for its obligations under this credit facility, EME pledged its ownership interests in the holding companies through which it owns its interests in the Illinois Plants, the Homer City facilities, the Westside projects and the Sunrise project. EME also granted a security interest in an account into which all distributions received by it from the Big 4 projects will be deposited. EME will be free to use these proceeds unless an event of default occurs under the credit facility.

Also in June 2006, EME completed a private offering of $500 million aggregate principal amount of its 7.50% senior notes due June 15, 2013 and $500 million aggregate principal amount of its 7.75% senior notes due June 15, 2016. EME will pay interest on the senior notes on June 15 and December 15 of each year, beginning on December 15, 2006. The senior notes are redeemable by EME at any time at a price equal to 100% of the principal amount of, plus accrued and unpaid interest and liquidated damages, if any, on, the senior notes plus a "make-whole" premium.

EME used the net proceeds of the offering of the senior notes, together with cash on hand, to purchase $369 million in aggregate principal amount of its 10% senior notes due August 15, 2008 and $596 million in aggregate principal amount of its 9.875% senior notes due April 15, 2011, that were validly tendered pursuant to EME's previously announced cash tender offer and consent solicitation. The net proceeds of the offering of the senior notes, together with cash on hand, were also used to pay related tender premiums, consent fees and accrued interest. EME recorded a $143 million loss on early extinguishment of debt during the second quarter of 2006.

Midwest Generation Financing

On December 15, 2005, Midwest Generation completed a refinancing of indebtedness. The refinancing was effected through the amendment and restatement of Midwest Generation's existing credit facility, previously amended and restated on April 18, 2005. The credit facility, as previously amended and restated, provided for approximately $343 million of first priority secured institutional term loans due in 2011 and $500 million of first priority secured revolving credit, working capital facilities, $200 million due in 2009 and $300 million due in 2011, with a lender option to require prepayment in 2010.

The refinancing consisted of, among other things, a reduction in the interest rate applicable to the term loan and the working capital facilities, and a modification of financial covenants. After giving effect to the refinancing, all the facilities carry a lower interest rate of LIBOR + 1.75%. The maturity date of the repriced term loan remains 2011. The previously existing working capital facilities were combined into one $500 million facility, maturing in 2011, with a lender option to require prepayment in 2010. Also, as part of the refinancing, Midwest Generation's financial covenants were modified, with its consolidated interest coverage ratio for the immediately preceding four consecutive fiscal quarters required to be at least 1.40 to 1 (increased from 1.25 to 1), and its secured leverage ratio for the 12-month period ended on the last day of the immediately preceding fiscal quarter required to be no greater than 7.25 to 1 (reduced from 8.75 to 1).

Capital Expenditures

The estimated capital and construction expenditures of EME's subsidiaries are $280 million in the remaining two quarters of 2006 and $493 million, $28 million and $25 million for 2007, 2008 and 2009, respectively. The non-environmental portion of these expenditures relates to the construction of the

Wildorado wind project, purchases of turbines, upgrades to dust collection/mitigation systems and the coal handling system, ash removal improvements and various other projects. EME plans to finance these expenditures with existing subsidiary credit agreements, cash on hand or cash generated from operations. Included in the estimated expenditures are environmental expenditures of $4 million for the remaining two quarters of 2006, $12 million for 2007, $6 million for 2008, and $25 million for 2009. The environmental expenditures relate to environmental projects such as selective catalytic reduction system improvements at the Homer City facilities and projects at the Illinois Plants.

EME's Historical Consolidated Cash Flow

Consolidated Cash Flows from Operating Activities

Interim Results

Cash provided by operating activities from continuing operations increased $465 million in the first six months of 2006, compared to the first six months of 2005. The 2006 increase was primarily attributable to a decrease of $363 million in required margin and collateral deposits in 2006 for EME's price risk management and trading activities, compared to an increase of $33 million in 2005. This change resulted from a decrease in forward market prices at June 30, 2006 as compared to December 31, 2005.

Cash provided by operating activities from discontinued operations increased $64 million in the first six months of 2006, compared to the first six months of 2005. The 2006 increase reflects higher distributions received in 2006 compared to 2005 from the Lakeland power project. See "Results of Operations—Results of Discontinued Operations—Lakeland Project" for more information regarding these distributions.

Annual Results

Net cash provided by (used in) operating activities:

	Years Ended December 31,
	2005			2004			2003
	(in millions)
Continuing operations	$	(239	)	$	(353	)	$	409
Discontinued operations		20			(434	)		243

	$	(219	)	$	(787	)	$	652

Cash used in operating activities from continuing operations decreased $114 million in 2005 from 2004, and increased $762 million in 2004 from 2003. The 2005 decrease was primarily attributable to the $960 million lease termination payment in 2004 related to the Collins Station lease and improved operating income in 2005. Partially offsetting these decreases was $656 million in required margin and collateral deposits in 2005 for EME's price risk management and trading activities, compared to $30 million in 2004. This increase in margin and collateral deposits resulted from an increase in forward market prices.

The 2004 increase was primarily attributable to the $960 million lease termination payment in 2004 related to the Collins Station lease and tax-allocation payments of $7 million paid to Edison International during 2004, compared to $112 million in tax-allocation payments received by EME from Edison International during 2003. EME made tax payments in 2004 primarily attributable to taxable

income resulting from the sale of the Four Star Oil & Gas and Brooklyn Navy Yard projects. In addition, distributions from unconsolidated affiliates were lower during 2004 compared to 2003, primarily because the 2003 distributions included $151 million from completion of the Sunrise project financing in September 2003.

Cash used in operating activities from discontinued operations in 2004 primarily reflects settlement of working capital items from the sale of EME's international operations. Cash provided by operating activities from discontinued operations in 2003 primarily reflects operating income and distributions from international projects.

Consolidated Cash Flows from Financing Activities

Interim Results

Cash used in financing activities from continuing operations decreased $737 million in the first six months of 2006, compared to the first six months of 2005. The 2006 decrease was primarily attributable to net proceeds of $1 billion received from EME's issuance of senior notes in June 2006, which were mostly used to repay $965 million of EME's outstanding senior notes and $136 million paid for tender premiums and related fees.

In addition, Midwest Generation also had borrowings of $315 million under its credit facility, mostly offset by repayments of $285 million in 2006. In addition, dividend payments were made to MEHC of $360 million in 2005 compared to a $12 million dividend payment to MEHC in 2006. In 2005, EME repaid its junior subordinated debentures for $150 million and Midwest Generation repaid $302 million related to its existing term loan.

Annual Results

Net cash used in financing activities:

	Years Ended December 31,
	2005			2004			2003
	(in millions)
Continuing operations	$	(773	)	$	(21	)	$	(464	)
Discontinued operations		—			(144	)		153

	$	(773	)	$	(165	)	$	(311	)

Cash used in financing activities from continuing operations increased $752 million in 2005 from 2004, and decreased $443 million in 2004 from 2003. The 2005 increase was primarily attributable to dividend payments made to MEHC of $360 million during 2005, compared to $74 million during 2004. The increase was also due to the repayment of EME's junior subordinated debentures of $150 million in January 2005 and a $302 million repayment in April 2005 related to Midwest Generation's existing term loan.

The 2004 decrease was due to a higher level of borrowings in 2004 compared to 2003, primarily due to the $1 billion secured notes and $700 million term loan facility received by Midwest Generation in April 2004 partially offset by the repayment of the $800 million secured loan at EME's subsidiary, Mission Energy Holdings International, Inc., $693 million related to Edison Mission Midwest Holdings' credit facility and $28 million related to the Coal and Capex facility in April 2004.

Cash used in financing activities from discontinued operations in 2004 primarily reflects repayment of debt and dividends to minority shareholders. Cash provided by financing activities from discontinued operations in 2003 primarily reflects borrowings by Contact Energy to finance the acquisition of a power station, partially offset by repayment of debt.

Consolidated Cash Flows from Investing Activities

Interim Results

Cash used in investing activities from continuing operations increased $403 million in the first six months of 2006, compared to the first six months of 2005. The 2006 increase was primarily due to net purchases of marketable securities of $76 million in the first six months of 2006, compared to net sales of marketable securities of $140 million in the first six months of 2005. In addition, EME paid $18 million towards the purchase price of the Wildorado wind project during the first quarter of 2006, incurred higher capital expenditures in 2006 and received lower proceeds from sales of projects. In 2005, EME received proceeds of $124 million from the sale of its 25% investment in the Tri Energy project and its 50% investment in the CBK project compared to proceeds of $43 million in 2006 from the sale of 25% of its ownership interest in the San Juan Mesa wind project.

Annual Results

Net cash provided by (used in) investing activities:

	Years Ended December 31,
	2005			2004		2003
	(in millions)
Continuing operations	$	(134	)	$	2,707	$	(96	)
Discontinued operations		5			18		(413	)

	$	(129	)	$	2,725	$	(509	)

Cash used in investing activities from continuing operations increased $2.8 billion in 2005 from 2004, and decreased $2.8 billion in 2004 from 2003. The 2005 increase was primarily attributable to proceeds of $2.7 billion received in 2004 from the sale of most of EME's international operations and $154 million paid towards the purchase price for the San Juan Mesa project in December 2005. Proceeds of $124 million received in 2005 from the sale of EME's 25% investment in the Tri Energy project and EME's 50% investment in the CBK project were comparable to proceeds of $118 million received in 2004, described below. Partially offsetting the 2005 increase were net purchases of marketable securities of $43 million in 2005, compared to $120 million in 2004.

The 2004 decrease was due to a combination of the following:

•: $2.7 billion in proceeds received in 2004 from the sale of most of EME's international operations.
•: $118 million in proceeds received in 2004 from the sale of EME's stock in Edison Mission Energy Oil & Gas and the sale of EME's 50% partnership interest in the Brooklyn Navy Yard project.
•: a reduction in investment in new plant and equipment. EME invested $55 million and $81 million in property and equipment during 2004 and 2003, respectively.
•: $23 million in equity contributions to the Sunrise project in 2003.

Cash used in investing activities from discontinued operations in 2003 primarily reflects $275 million paid in 2003 by Contact Energy for an acquisition of a power station and investments in new plant and equipment.

Credit Ratings

Overview

Credit ratings for EME and its subsidiaries, Midwest Generation and EMMT, are as follows:

		Moody's Rating	S&P Rating
EME		B1	BB-
Midwest Generation:
	First priority senior secured rating	Baa3	BB
	Second priority senior secured rating	Ba2	B+
EMMT		Not Rated	BB-

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

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

Credit Rating of EMMT

The Homer City sale-leaseback documents restrict EME Homer City's ability to enter into trading activities, as defined in the documents, with EMMT to sell forward the output of the Homer City facilities if EMMT does not have an investment grade credit rating from Standard & Poor's or Moody's or, in the absence of those ratings, if it is not rated as investment grade pursuant to EME's internal credit scoring procedures. 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 the output from the Homer City facilities through EMMT, 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 EMMT; or (2) EMMT 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, 2006. EME Homer City continues to be in compliance with the terms of the consent; however, the consent is revocable by the sale-leaseback owner participant at any time. The sale-leaseback owner participant has not indicated that it intends to revoke the consent; however, there can be no assurance that it will not do so in the future. Revocation of the consent would not affect trades between EMMT and EME Homer City that had been entered into while the consent was still in effect. EME is permitted to sell the output of the Homer City facilities into the spot market at any time. See "Market Risk Exposures—Commodity Price Risk—Energy Price Risk Affecting Sales from the Homer City Facilities."

Margin, Collateral Deposits and Other Credit Support for Energy Contracts

In connection with entering into contracts in support of EME's price risk management and energy trading activities (including forward contracts, transmission contracts and futures contracts), EME's subsidiary, EMMT, has entered into agreements to mitigate the risk of nonperformance. Because the credit ratings of EMMT and EME are below investment grade, EME has historically provided collateral in the form of cash and letters of credit for the benefit of counterparties related to accounts payable and unrealized losses in connection with these price risk management and trading activities. At June 30, 2006, EMMT had deposited $289 million in cash with brokers in margin accounts in support of futures contracts and had deposited $46 million with counterparties in support of forward energy and transmission contracts. In addition, EME had issued letters of credit of $7 million in support of commodity contracts at June 30, 2006.

Future cash collateral requirements may be higher than the margin and collateral requirements at June 30, 2006, if wholesale energy prices increase further or the amount hedged increases. EME estimates that margin and collateral requirements for energy contracts outstanding as of June 30, 2006 could increase by no more than approximately $310 million over the remaining life of the contracts using a 95% confidence level.

Midwest Generation has cash on hand and a $500 million working capital facility to support margin requirements specifically related to contracts entered into by EMMT related to the Illinois Plants. At June 30, 2006, Midwest Generation had borrowed $200 million under this credit facility which was partially used to finance margin advances to EMMT of $142 million. In addition, EME has cash on hand and a $500 million working capital facility to provide credit support to subsidiaries. See "—EME Financing Developments" and "—EME's Liquidity as a Holding Company" for further discussion.

EME's Liquidity as a Holding Company

Overview

At June 30, 2006, EME had corporate cash and cash equivalents and short-term investments of $1.3 billion to meet liquidity needs. Cash distributions from EME's subsidiaries and partnership investments and unused capacity under its corporate credit facility represent EME's major sources of liquidity to meet its cash requirements. The timing and amount of distributions from EME's subsidiaries may be affected by many factors beyond its control. See "—Dividend Restrictions in Major Financings."

EME Homer City Interim Funding Arrangements

During March 2006, EME, through its subsidiary, Edison Mission Finance, advanced funds in the amount of $9 million to EME Homer City under the subordinated revolving loan agreement in place between Edison Mission Finance and EME Homer City. The funds were used to assist EME Homer City with a cash shortfall resulting from reduced revenues and higher maintenance expenses caused by the Unit 3 outage. For similar reasons, at the end of March 2006 and April 2006, EMMT made advance payments to EME Homer City in the amounts of $43.5 million and $20 million, respectively, against future deliveries of power to it under its trading arrangements with EME Homer City. The proceeds of the subordinated loans were deposited in EME Homer City's operating account and the prepayment by EMMT was deposited in EME Homer City's revenue account. It is currently anticipated that a substantial portion of the advance payments will be applied against amounts invoiced to EMMT within the next 12 months.

Intercompany Tax-Allocation Agreement

EME is included in the consolidated federal and combined state income tax returns of Edison International and is eligible to participate in tax-allocation payments with other subsidiaries of Edison International in circumstances where domestic tax losses are incurred. The right of EME to receive and the amount of and timing of tax-allocation payments are dependent on the inclusion of EME in the consolidated income tax returns of Edison International and its subsidiaries and other factors, including the consolidated taxable income of Edison International and its subsidiaries, the amount of net operating losses and other tax items of EME, its subsidiaries, and other subsidiaries of Edison International and specific procedures regarding allocation of state taxes. EME receives 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 EME's consolidated tax losses in the consolidated income tax returns for Edison International and its subsidiaries. Based on the application of the factors cited above, EME is obligated during periods it generates taxable income to make payments under the tax-allocation agreements. EME made tax-allocation payments to Edison International of $162 million during the first six months of 2006. EME received tax-allocation payments from Edison International of $3 million during the first six months of 2005. EME paid tax-allocation payments to Edison International of $129 million and $7 million during 2005 and 2004, respectively.

Dividend Restrictions in Major Financings

General

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

Key Ratios of EME's Principal Subsidiaries Affecting Dividends

Set forth below are key ratios of EME's principal subsidiaries required by financing arrangements for the twelve months ended June 30, 2006:

Subsidiary	Financial Ratio	Covenant	Actual
Midwest Generation, LLC (Illinois Plants)	Interest Coverage Ratio	Greater than or equal to 1.40 to 1	6.45 to 1
Midwest Generation, LLC (Illinois Plants)	Secured Leverage Ratio	Less than or equal to 7.25 to 1	2.00 to 1
EME Homer City Generation L.P. (Homer City facilities)	Senior Rent Service Coverage Ratio	Greater than 1.7 to 1	2.26 to 1(1)

(1): The senior rent service coverage ratio is determined by dividing net operating cash flow by senior rent. Net operating cash flow represents revenues less operating expenses as defined in the sale-leaseback documents. Revenue during the twelve months ended June 30, 2006 includes $43.5 million and $20 million from an advance payment from EMMT on March 31, 2006 and April 30, 2006, respectively, against future deliveries of power to it under its trading arrangements with EME Homer City.

Midwest Generation Financing Restrictions on Distributions

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

Covenants in Credit Agreement

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

•: At the end of each fiscal quarter, Midwest Generation's consolidated interest coverage ratio for the immediately preceding four consecutive fiscal quarters must be at least 1.40 to 1. The consolidated interest coverage ratio is defined as the ratio of consolidated net income (plus or minus specified amounts as set forth in the credit agreement), to consolidated interest expense (as more specifically defined in the credit agreement).
•: Midwest Generation's secured leverage ratio for the 12-month period ended on the last day of the immediately preceding fiscal quarter may be no greater than 7.25 to 1. The secured leverage ratio is defined as the ratio of the aggregate principal amount of Midwest Generation secured debt plus all indebtedness of a subsidiary of Midwest Generation, to the aggregate amount of consolidated net income (plus or minus specified amounts as set forth in the credit agreement).

In addition, Midwest Generation's distributions are limited in amount. Under the terms of Midwest Generation's credit agreement, Midwest Generation is permitted to distribute 75% of its excess cash flow (as defined in the credit agreement). In addition, if equity is contributed to Midwest Generation, Midwest Generation is permitted to distribute 100% of excess cash flow until the aggregate portion of distributions that Midwest Generation attributed to the equity contribution equals the amount of the equity contribution. Because EME made a $300 million equity contribution to Midwest Generation on April 19, 2005, Midwest Generation is permitted to distribute 100% of excess cash flow until the aggregate portion of such distributions attributed to that equity contribution equals $300 million. After taking into account Midwest Generation's most recent distribution in July 2006, $128 million of the equity contribution is still available for this purpose. To the extent Midwest Generation makes a distribution which is not fully attributed to an equity contribution, Midwest Generation is required to make concurrently with such distribution an offer to repay debt in an amount equal to the excess, if any, of one-third of such distribution over the amount attributed to the equity contribution.

Covenants in Indenture

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

EME Homer City (Homer City facilities)

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

•: At the end of each quarter, the senior rent service coverage ratio for the prior twelve-month period (taken as a whole) must be greater than 1.7 to 1. The senior rent service coverage ratio is defined as all income and receipts of EME Homer City less amounts paid for operating expenses, required capital expenditures, taxes and financing fees divided by the aggregate amount of the debt portion of the rent, plus fees, expenses and indemnities due and payable with respect to the lessor's debt service reserve letter of credit.

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 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.

EME Corporate Credit Facility Restrictions on Distributions from Subsidiaries

EME's corporate credit facility contains covenants that restrict its ability, and the ability of several of its subsidiaries, to make distributions. This restriction binds the subsidiaries through which EME owns the Westside projects, the Sunrise project, the Illinois Plants, the Homer City facilities and the Big 4 projects. These subsidiaries would not be able to make a distribution to EME if an event of default were to occur and be continuing under EME's corporate credit facility after giving effect to the distribution.

In addition, EME granted a security interest in an account into which all distributions received by it from the Big 4 projects are deposited. EME is free to use these distributions unless and until an event of default occurs under its corporate credit facility.

As of June 30, 2006, EME had no borrowings outstanding under this credit facility.

Contractual Obligations, Commitments and Contingencies

Contractual Obligations

Interim Update at June 30, 2006

At June 30, 2006, EME's subsidiaries had firm commitments to spend approximately $157 million during the remainder of 2006 and $33 million in 2007 on capital and construction expenditures. The majority of these expenditures relate to the construction of the Wildorado wind project. Also included are expenditures for boiler header replacement, dust collection and mitigation system and various other projects. These expenditures are planned to be financed by existing subsidiary credit agreements, cash on hand or cash generated from operations.

At June 30, 2006, in connection with wind projects in development, EME had entered into agreements with turbine vendors securing 235 turbines with remaining commitments of $110 million in 2006 and $244 million in 2007. In addition, EME had options to acquire an additional 50 turbines for delivery in 2007 that were exercised on July 31, 2006. In July 2006, EME entered into an agreement to purchase 20 turbines from another supplier with options to purchase another 32 turbines for delivery in 2007 subject to certain conditions.

Contractual Obligation at December 31, 2005

The following table summarizes EME's significant consolidated contractual obligations as of December 31, 2005.

				Payments Due by Period (in millions)
Contractual Obligations		Total		Less than 1 year		1 to 3 years		3 to 5 years		More than 5 years
Long-term debt(1)		$	4,983	$	353	$	1,100	$	1,016	$	2,514
Operating lease obligations			4,766		363		718		694		2,991
Purchase obligations:
	Capital improvements		8		8		—		—		—
	Turbine commitments(2)		192		114		78		—		—
	Fuel supply contracts		1,031		367		487		158		19
	Gas transportation agreements		100		8		16		16		60
	Coal transportation		680		226		301		153		—
Other contractual obligations			55		12		22		21		—
Employee benefit plan contribution(3)			15		15		—		—		—

Total Contractual Obligations		$	11,830	$	1,466	$	2,722	$	2,058	$	5,584

(1): See "Audited Consolidated Financial Statements of Edison Mission Energy—Notes to Consolidated Financial Statements—Note 11. Financial Instruments." Table assumes long-term debt is held to maturity, except the Midwest Generation senior secured notes which are assumed to be held until 2014. Amount also includes interest payments over applicable period of the debt.
(2): See "Management's Overview—Business Development—Wind Projects" and "Interim Update at June 30, 2006," for additional details.
(3): Amount includes estimated contribution for pension plans and postretirement benefits other than pensions. The estimated contributions beyond 2006 are not available. For more information, see "Audited Consolidated Financial Statements of Edison Mission Energy—Notes to Consolidated Financial Statements—Note 14. Employee Benefit Plans."

Operating Lease Obligations—

At December 31, 2005, minimum operating lease payments were primarily related to long-term leases for the Powerton and Joliet Stations and the Homer City facilities. During 2000, EME entered into sale-leaseback transactions for two power facilities, the Powerton and Joliet coal-fired stations located in Illinois, with third-party lessors. During the fourth quarter of 2001, EME entered into a sale-leaseback transaction for the Homer City coal-fired facilities located in Pennsylvania, with third-party lessors. Total minimum lease payments during the next five years are $337 million in 2006, $336 million in 2007, $337 million in 2008, $336 million in 2009, $325 million in 2010, and the minimum lease payments due after 2010 are $2.9 billion. For further discussion, see "—Off-Balance Sheet Transactions—Sale-Leaseback Transactions."

Fuel Supply Contracts—

At December 31, 2005, EME's subsidiaries had contractual commitments to purchase coal. The remaining contracts' lengths range from one year to seven years. The minimum commitments are based on the contract provisions, which consist of fixed prices, subject to adjustment clauses.

Gas Transportation Agreements—

At December 31, 2005, EME had a contractual commitment to transport natural gas. EME is committed to pay its share of fixed monthly capacity charges under its gas transportation agreement, which has a remaining contract length of 12 years.

Coal Transportation Agreements—

At December 31, 2005, EME's subsidiaries had contractual commitments for the transport of coal to their respective facilities, with remaining contract lengths that range from one year to six years. Midwest Generation's primary contract is with Union Pacific Railroad (and various delivering carriers) which extends through 2011. Midwest Generation commitments under this agreement are based on actual coal purchases from the Powder River Basin. Accordingly, Midwest Generation's contractual obligations for transportation are based on coal volumes set forth in their fuel supply contracts. EME Homer City commitments under its agreements are based on the contract provisions, which consist of fixed prices, subject to adjustment clauses. Only a portion of total coal shipments to the Homer City facilities are shipped by rail. Trucking remains the predominant mode of transportation for coal shipments to the Homer City facilities.

Commercial Commitments

Introduction

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

Standby Letters of Credit

As of December 31, 2005, standby letters of credit aggregated to $33 million and were scheduled to expire as follows: 2006—$28 million and 2007—$5 million.

Guarantees and Indemnities

Tax Indemnity Agreements—

In connection with the sale-leaseback transactions that EME has entered into related to the Powerton and Joliet Stations in Illinois, the Collins Station in Illinois, and the Homer City facilities in Pennsylvania, EME and several of its subsidiaries entered into tax indemnity agreements. Under these tax indemnity agreements, these entities agreed to indemnify the lessors in the sale-leaseback transactions for specified adverse tax consequences that could result in certain situations set forth in each tax indemnity agreement, including specified defaults under the respective leases. The potential indemnity obligations under these tax indemnity agreements could be significant. Due to the nature of these potential obligations, EME cannot determine a maximum potential liability which would be triggered by a valid claim from the lessors. EME has not recorded a liability related to these indemnities. In connection with the termination of the Collins Station lease in April 2004, Midwest Generation will continue to have obligations under the tax indemnity agreement with the former lease equity investor.

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

In connection with the acquisition of the Illinois Plants, EME agreed to indemnify Commonwealth Edison with respect to specified environmental liabilities before and after December 15, 1999, the date of sale. The indemnification claims are reduced by any insurance proceeds and tax benefits related to such claims and are subject to a requirement that Commonwealth Edison 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. This indemnification for environmental liabilities is not limited in term and would be triggered by a valid claim from Commonwealth Edison. Except as discussed below, EME has not recorded a liability related to this indemnity.

Midwest Generation entered into a supplemental agreement with Commonwealth Edison and Exelon Generation Company on February 20, 2003 to resolve a dispute regarding interpretation of its reimbursement obligation for asbestos claims under the environmental indemnities set forth in the Asset Sale Agreement. Under this supplemental agreement, Midwest Generation agreed to reimburse Commonwealth Edison and Exelon Generation for 50% of specific existing asbestos claims and expenses less recovery of insurance costs, and agreed to a sharing arrangement for liabilities and expenses associated with future asbestos-related claims as specified in the agreement. As a general matter, Commonwealth Edison and Midwest Generation apportion responsibility for future asbestos-related claims based upon the number of exposure sites that are Commonwealth Edison locations or Midwest Generation locations. 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 of either party to terminate). Payments are made under this indemnity upon tender by Commonwealth Edison of appropriate proof of liability for an asbestos-related settlement, judgment, verdict, or expense. There were approximately 175 cases for which Midwest Generation was potentially liable and that had not been settled and dismissed at June 30, 2006. Midwest Generation had recorded a $66 million liability at June 30, 2006 related to this matter.

The amounts recorded by Midwest Generation for the asbestos-related liability are based upon a number of assumptions. Future events, such as the number of new claims to be filed each year, the average cost of disposing of claims, as well as the numerous uncertainties surrounding asbestos litigation in the United States, could cause the actual costs to be higher or lower than projected.

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

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

Indemnities Provided under Asset Sale Agreements—

valid claims from the sellers or purchasers, as the case may be. At June 30, 2006, EME had recorded a liability of $94 million related to these matters.

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

Guarantee of Brooklyn Navy Yard Contractor Settlement Payments—

On March 31, 2004, EME completed the sale of 100% of the stock of Mission Energy New York, Inc., which held a 50% partnership interest in Brooklyn Navy Yard Cogeneration Partners, L.P. (referred to as Brooklyn Navy Yard), to BNY Power Partners LLC. Brooklyn Navy Yard owns a 286 MW gas-fired cogeneration power plant in Brooklyn, New York. In February 1997, the construction contractor asserted general monetary claims under the turnkey agreement against Brooklyn Navy Yard. A settlement agreement was executed on January 17, 2003, and all litigation has been dismissed. EME agreed to indemnify Brooklyn Navy Yard and, in connection with the sale of EME's interest in Brooklyn Navy Yard, BNY Power Partners for any payments due under this settlement agreement, which are scheduled through January 2007. At June 30, 2006, EME had recorded a liability of $4 million related to this indemnity.

Capacity Indemnification Agreements—

EME has guaranteed, jointly and severally with Texaco Inc., the obligations of March Point Cogeneration Company under its project power sales agreements to repay capacity payments to the project's power purchaser in the event that the power sales agreements terminate, March Point Cogeneration Company abandons the project, or the project fails to return to normal operations within a reasonable time after a complete or partial shutdown, during the term of the power sales agreements. In addition, a subsidiary of EME has guaranteed the obligations of Sycamore Cogeneration Company under its project power sales agreement to repay capacity payments to the project's power purchaser in the event that the project unilaterally terminates its performance or reduces its electric power producing capability during the term of the power sales agreement. The obligations under the indemnification agreements as of June 30, 2006, if payment were required, would be $114 million. EME has not recorded a liability related to these indemnities.

Subsidiary Guarantee for Performance of Unconsolidated Affiliate—

A subsidiary of EME has guaranteed the obligations of an unconsolidated affiliate to make payments to a third party for power delivered under a fixed-price power sales agreement. This agreement runs through 2007. EME believes there is sufficient cash flow to pay the power suppliers, assuming timely payment by the power purchasers. Due to the nature of this indemnity, a maximum potential liability cannot be determined. To the extent EME's subsidiary would be required to make payments under the guarantee, EME's subsidiary and EME are indemnified by Peabody Energy Corporation pursuant to the 2000 Purchase and Sale Agreement for Citizens Power LLC. EME's subsidiary has not recorded a liability related to this indemnity.

Contingencies

MISO Revenue Sufficiency Guarantee Charges

On April 25, 2006, the FERC issued an order regarding the MISO's "Revenue Sufficiency Guarantee" charges, or RSG charges. The MISO's business practice manuals and other instructions to market participants have stated, since the implementation of market operations on April 1, 2005, that RSG charges will not be imposed on offers to supply power not supported by actual generation (also known as virtual supply offers). However, some market participants raised questions about the language of the MISO's tariff concerning that issue and, in October 2005, the MISO submitted to the FERC proposed tariff revisions clarifying its tariff to reflect its business practices with respect to RSG charges and filed corrected tariff sheets exempting virtual supply from RSG charges. In its April 25 decision, the FERC interpreted the MISO's tariff to require that virtual supply offers must be included in the calculation of the RSG charges and that, to the extent that the MISO did not charge virtual supply offers for RSG charges, it violated the terms of its tariff. The FERC order then proceeded to require the MISO to recalculate the RSG charges back to April 1, 2005, and to make refunds to customers, with interest, reflecting the recalculated charges. In order to make such refunds, it is likely that the MISO will attempt to impose retroactively RSG charges on those who submitted virtual supply offers during the recalculation period. Edison Mission Marketing & Trading, or EMMT, made virtual supply offers in the MISO during this period on which no RSG charges were imposed, and thus may be subject to a claim for refunds from the MISO (which claim will be contested by EMMT). Because calculation of any claimed liability for refunds depends on information not currently available to it, EMMT cannot reasonably estimate a range of loss related to this matter. In addition, the FERC's April 25 order has been challenged by the MISO and other parties, including EMMT, and as the FERC has issued an extension of time to comply with the requirements of the order until after the date of issuance of an order on rehearing, the eventual outcome of these proceedings is unclear.

Midway-Sunset Cogeneration Company

San Joaquin Energy Company, a wholly owned subsidiary of EME, owns a 50% general partnership interest in Midway-Sunset Cogeneration Company, which owns a 225 MW cogeneration facility near Fellows, California. Midway-Sunset is a party to several proceedings pending at the FERC involving claims for refunds from entities that sold power and related services into the California markets operated by the California Power Exchange (PX) and the California Independent System Operator (ISO) (collectively the California Markets) at prices that were allegedly not just and reasonable, as required by the Federal Power Act.

Midway-Sunset is a party to these proceedings because Midway-Sunset was a seller in the California Markets during 2000 and 2001, both for its own account and on behalf of Southern California Edison Company (SCE) and Pacific Gas and Electric Company (PG&E), the utilities to which the majority of Midway-Sunset's power was contracted for sale. As a seller into the California Markets, Midway-Sunset is potentially liable for refunds to purchasers in these markets.

The claims asserted against Midway-Sunset for refunds related to power sold into the California Markets, including power sold on behalf of SCE and PG&E, are estimated to be less than $70 million for all periods under consideration. Midway-Sunset has calculated its potential liability for refunds related to power sold into the California Markets on its own behalf (excluding power sold on behalf of SCE and PG&E) to be approximately $0.5 million for the period October 2, 2000 through June 20, 2001. Midway Sunset's potential liability for sales on its own behalf during the period May 1, 2000 through October 1, 2000 has not yet been calculated but is not expected to be material. These

calculations were made in accordance with the methodology approved by the FERC, but it is possible that this methodology will be challenged.

Because Midway-Sunset did not retain any proceeds from power sold into the California Markets on behalf of SCE and PG&E in excess of the amounts to which it was entitled under the pre-existing power sales contracts, but instead passed those proceeds on to the utilities, EME believes that PG&E and SCE are obligated to reimburse Midway-Sunset for any refund liability that it incurs as a result of sales made into the California Markets on their behalf. Midway-Sunset intends vigorously to assert these positions. However, at this time EME cannot predict the outcome of this matter.

Tax Matters

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

Litigation

EME 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.

Insurance

On January 29, 2006, the main power transformer on Unit 3 of the Homer City facilities failed, resulting in a suspension of operations at this unit. EME Homer City secured a replacement transformer and Unit 3 returned to service on May 5, 2006. The main transformer failure will result in claims under EME Homer City's property and business interruption insurance policies. At June 30, 2006, EME Homer City recorded a $17 million receivable, of which $11 million relates to business interruption insurance coverage and has been reflected in other income (expense), net in EME's consolidated income statements.

Off-Balance Sheet Transactions

Introduction

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

Investments Accounted for under the Equity Method

EME has a number of investments in power projects that are accounted for under the equity method. Under the equity method, the project assets and related liabilities are not consolidated in EME's consolidated balance sheet. Rather, EME's financial statements reflect its investment in each entity and it records only its proportionate ownership share of net income or loss. These investments are of three principal categories.

Historically, EME has invested in qualifying facilities, those which produce electrical energy and steam, or other forms of energy, and which meet the requirements set forth in the Public Utility Regulatory Policies Act. See "Business—Regulatory Matters—U.S. Federal Energy Regulation." Prior to the passage of the Energy Policy Act of 2005, these regulations limited EME's ownership interest in qualifying facilities to no more than 50% due to EME's affiliation with Southern California Edison Company, a public utility. For this reason, EME owns a number of domestic energy projects through partnerships in which it has a 50% or less ownership interest.

Entities formed to own these projects are generally structured with a management committee or board of directors in which EME exercises significant influence but cannot exercise unilateral control over the operating, funding or construction activities of the project entity. EME's energy projects have generally secured long-term debt to finance the assets constructed and/or acquired by them. These financings generally are secured by a pledge of the assets of the project entity, but do not provide for any recourse to EME. Accordingly, a default on a long-term financing of a project could result in foreclosure on the assets of the project entity resulting in a loss of some or all of EME's project investment, but would generally not require EME to contribute additional capital. At December 31, 2005, entities which EME has accounted for under the equity method had indebtedness of $601 million, of which $287 million is proportionate to EME's ownership interest in these projects.

Sale-Leaseback Transactions

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

EME's subsidiaries account for these leases as financings in their separate financial statements due to specific guarantees provided by EME or another one of its subsidiaries as part of the sale-leaseback transactions. These guarantees do not preclude EME from recording these transactions as operating leases in its consolidated financial statements, but constitute continuing involvement under SFAS No. 98 that precludes EME's subsidiaries from utilizing this accounting treatment in their separate subsidiary financial statements. Instead, each subsidiary continues to record the power plants as assets in a similar manner to a capital lease and records the obligations under the leases as lease financings. EME's subsidiaries, therefore, record depreciation expense from the power plants and interest expense from the lease financing in lieu of an operating lease expense which EME uses in preparing its consolidated financial statements. The treatment of these leases as an operating lease in its consolidated financial statements in lieu of a lease financing, which is recorded by EME's subsidiaries, resulted in an increase in consolidated net income by $72 million, $73 million and $81 million in 2005, 2004 and 2003, respectively.

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

Power Station(s)	Acquisition Price		Equity Investor	Original Equity Investment in Owner/Lessor		Amount of Lessor Debt at December 31, 2005		Maturity Date of Lessor Debt
	(in millions)
Powerton/Joliet	$	1,367	PSEG/ Citigroup, Inc.	$	238	$	333.5 Series A 769.7 Series B	2009 2016
Homer City		1,591	GECC/ Metropolitan Life Insurance Company(1)		798	$	282.0 Series A 524.3 Series B	2019 2026

PSEG—PSEG Resources, Inc.

GECC—General Electric Capital Corporation

(1): On September 29, 2005, GECC sold 10% of its investment to Metropolitan Life Insurance Company.

The operating lease payments to be made by each of EME's subsidiary lessees are structured to service the lessor debt and provide a return to the owner/lessor's equity investors. Neither the value of the leased assets nor the lessor debt is reflected in EME's consolidated balance sheet. In accordance with generally accepted accounting principles, EME records rent expense on a levelized basis over the terms of the respective leases. To the extent that EME's cash rent payments exceed the amount levelized over the term of each lease, EME records prepaid rent. At June 30, 2006, December 31, 2005 and 2004, prepaid rent on these leases was $506 million, $395 million and $277 million, respectively. To the extent that EME's cash rent payments are less than the amount levelized, EME reduces the amount of prepaid rent.

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

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

EME's Obligations to Midwest Generation

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

included by them in assessing EME's credit ratings. The following table summarizes principal payments due under this intercompany loan:

Years Ending December 31,	Principal Amount		Interest Amount		Total
	(in millions)
2006	$	3	$	113	$	116
2007		3		113		116
2008		4		112		116
2009		4		112		116
2010		5		112		117
Thereafter		1,343		512		1,855

Total	$	1,362	$	1,074	$	2,436

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

Environmental Matters and Regulations

Introduction

EME and its subsidiaries are subject to environmental regulation by federal, state and local authorities. EME believes that it is in substantial compliance with environmental regulatory requirements and that maintaining compliance with current requirements will not materially affect its financial position or results of operations. However, possible future developments, such as the promulgation of more stringent environmental laws and regulations, future proceedings that may be initiated by environmental authorities, and settlements agreed to by other companies could affect the costs and the manner in which EME conducts its business, and may also 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 as a result.

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

Federal—United States of America

Clean Air Act

Clean Air Interstate Rule—

On May 12, 2005, the Clean Air Interstate Rule, or CAIR, was published in the Federal Register. The CAIR requires 28 eastern states and the District of Columbia to address ozone attainment issues

by reducing regional nitrogen oxide (NOx) and/or sulfur dioxide (SO2) emissions. The CAIR reduces the current Clean Air Act Title IV Phase II SO2 emissions allowance cap for 2010 and 2015 by 50% and 65%, respectively. The CAIR also reduces regional NOx emissions in 2009 and 2015 by 53% and 61%, respectively, from 2003 levels. The emissions reductions required by the CAIR are based on controls that the EPA has determined are highly cost effective for electric generating units. The EPA anticipates that states will achieve their reductions primarily by reducing emissions from the power generation sector by requiring power plants to participate in an emissions cap and trade system, although states can achieve required reductions by regulating other emissions sources. On April 28, 2006, the EPA published in the Federal Register a final rule promulgating Federal implementation plans requiring that electric generating units in all jurisdictions covered by the CAIR participate in the cap and trade program to achieve the required emissions reductions until states have approved implementation plans. The CAIR has been challenged in court by state, environmental and industry groups, which may result in changes to the substance of the rule.

EME expects that compliance with the CAIR and the regulations and revised state implementation plans, or SIPs, developed as a consequence of the CAIR will result in increased capital expenditures and operating expenses. Given the uncertainty of the requirements that will need to be implemented and the options available to meet the NOx and SO2 reductions fleetwide, EME at this time cannot accurately estimate the cost to meet these obligations. EME's approach to meeting these obligations will consist of a blending of capital expenditure and emission allowance purchases, to the extent permitted by SIPs, based on an ongoing assessment of the dynamics of its market conditions.

Mercury Regulation—

The Clean Air Mercury Rule, or CAMR, published in the Federal Register on May 18, 2005, creates a market-based cap-and-trade program to reduce nationwide utility emissions of mercury in two distinct phases. In the first phase of the program, which will come into effect in 2010, the annual nationwide cap will be 38 tons. Emissions of mercury are to be reduced primarily by taking advantage of mercury reductions achieved by reducing SO2 and NOx emissions under the CAIR. In the second phase, which is to take effect in 2018, coal-fired power plants will be subject to a lower annual cap, which will reduce emissions nationwide to 15 tons. States may join the trading program by adopting the CAMR model trading rule in state regulations, or they may adopt regulations that mirror the necessary components of the model trading rule. States are not required to adopt a cap-and-trade program and may promulgate alternative regulations, such as command and control regulations, that are equivalent to or more stringent than the CAMR's suggested cap-and-trade program. Any program adopted by a state must be approved by the United States Environmental Protection Agency, or US EPA.

Contemporaneously with the adoption of the CAMR, the US EPA rescinded its previous finding that mercury emissions from coal-fired power plants had to be regulated pursuant to Section 112 of the federal Clean Air Act, which would have imposed technology-based standards. Litigation has been filed challenging the US EPA's rescission action and claiming that the agency should have imposed technology-based limitations on mercury emissions instead of adopting a market-based program. Litigation was also filed to challenge the CAMR. As a result of these challenges, the CAMR rules and timetables may change.

As discussed below, both Illinois and Pennsylvania have issued proposed rules that would opt out of the CAMR and instead impose command-and-control mercury regulations. If Illinois and Pennsylvania were to implement the CAMR by adopting a cap-and-trade program for achieving reductions in mercury emissions, EME may have the option to purchase mercury emission allowances, to install pollution control equipment, to otherwise alter its operations to reduce mercury emissions, or to implement some combination thereof. Implementation of environmental control technology at its

Illinois Plants and Homer City facilities, to comply with the CAMR and other Clean Air Act developments described herein, either alone or in conjunction with purchasing allowances, will require higher capital expenditures over a number of years.

Because the mercury SIPs may not adopt the CAMR's cap-and-trade program, and because EME cannot predict the outcome of the legal challenge to the CAMR and the US EPA's decision not to regulate mercury emissions pursuant to Section 112 of the federal Clean Air Act, the full impact of this regulation currently cannot be assessed. Additional capital costs related to these regulations could be required in the future and they could be material. EME's approach to meeting these obligations will continue to be based upon an ongoing assessment of applicable legal requirements and market conditions.

As part of its evaluation of environmental control technologies for the Homer City facilities, EME has considered installing flue gas desulfurization systems for Units 1 and 2 (similar to Unit 3 which has this technology) to reduce emissions, including mercury. However, in light of higher estimated capital costs, the impact of the recent decline in emissions costs and the continued uncertainty over the final provisions of relevant environmental regulations, EME has deferred making commitments for the installation of further environmental controls at the Homer City facilities at this time. EME is studying alternative environmental technologies while continuing to review and refine the scope of the project, estimated costs for control equipment and to monitor developments related to mercury and other environmental regulations.

National Ambient Air Quality Standards—

Ambient air quality standards for ozone and fine particulate matter were adopted by the US EPA in July 1997. These standards were challenged in the courts, and on March 26, 2002, the United States Court of Appeals for the District of Columbia Circuit upheld the US EPA's revised ozone and fine particulate matter ambient air quality standards.

The US EPA designated non-attainment areas for the 8-hour ozone standard on April 30, 2004, and for the fine particulate standard on January 5, 2005. Almost all of EME's facilities are located in counties that have been identified as being in non-attainment with both standards. States are required to revise their implementation plans for the ozone and particulate matter standards within three years of the effective date of the respective non-attainment designations. The revised SIPs are likely to require additional emission reductions from facilities that are significant emitters of ozone precursors and particulates. Any additional obligations on EME's facilities to further reduce their emissions of SO2, NOx and fine particulates to address local non-attainment with the 8-hour ozone and fine particulate matter standards will not be known until the states revise their implementation plans. Depending upon the final standards that are adopted, EME may incur substantial costs or experience other financial impacts resulting from required capital improvements or operational changes.

On September 22, 2006 the US EPA signed a final rule that implements the revisions to its fine particulate standard originally proposed on January 17, 2006. Under the new rule, the annual standard remains the same but the 24-hour fine particulate standard is significantly more stringent. The rule may require states to impose further emission reductions beyond those necessary to meet the existing standards. Although EME may incur substantial costs or experience financial impacts as a result of any new standards, the uncertainties associated with this ongoing rulemaking at this time render EME unable to accurately estimate the costs to meet any such obligation. EME anticipates, however, that any such further emission reduction obligations would not be imposed until 2010 at the earliest.

Regional Haze—

The goal of the 1999 regional haze regulations is to restore visibility in mandatory federal Class I areas, such as national parks and wilderness areas, to natural background conditions in 60 years. Sources such as power plants that are reasonably anticipated to contribute to visibility impairment in Class I areas may be required to install Best Available Retrofit Technology, or BART, or implement other control strategies to meet regional haze control requirements. States are required to revise their SIPs to demonstrate reasonable further progress towards meeting regional haze goals. Emission reductions that are achieved through other ongoing control programs may be sufficient to demonstrate reasonable progress toward the long-term goal, particularly for the first 10 to 15 year phase of the program. States must develop implementation plans by December 2007. On June 15, 2005, the EPA issued final rules that provided, among other things, that states implementing CAIR would be deemed to satisfy their obligations under the regional haze regulations, such that sources subject to CAIR in those states would not be required to install BART. That regulation has been challenged in court, and litigation is ongoing. Until the litigation is complete and the SIPs are revised, EME cannot predict whether it will be required to install BART or implement other control strategies, and cannot identify the financial impacts of any additional control requirements.

New Source Review Requirements—

Since 1999, the US EPA has pursued a coordinated compliance and enforcement strategy to address Clean Air Act New Source Review, or NSR, compliance issues at the nation's coal-fired power plants. The NSR regulations impose certain requirements on facilities, such as electric generating stations, in the event that modifications are made to air emissions sources at a facility. The US EPA's strategy included both the filing of a number of suits against power plant owners, and the issuance of a number of administrative notices of violation to power plant owners alleging NSR violations. Neither EME nor any of its subsidiaries has been named as a defendant in these lawsuits and have not received any administrative Notices of Violation alleging NSR violations at any of their facilities.

At the current time, the NSR program is in a considerable state of flux. In response to conflicting court decisions concerning the applicable emissions test used to determine whether an operational or physical change at an electric generating station would require the plant to install additional pollution controls, the Supreme Court agreed to hear Environmental Defense v. Duke Energy Corp. A decision is expected in that case by early 2007. In addition, however, on October 13, 2005, the US EPA proposed a change to the NSR program. The proposal put forth several options for a new emissions test based on the impact of a facility modification on a facility's maximum hourly emissions or its emissions per unit of energy produced. The NSR emissions test advanced by the US EPA in its NSR lawsuits against power plant owners is based on the impact of a modification on a generating station's net annual emissions.

Also in October 2005, the US EPA announced a revised NSR strategy to take account of recent US EPA rulemakings, such as the CAIR and regional haze rules, affecting coal-fired power plants. Under the revised strategy, while the US EPA will continue to pursue filed cases and cases in active negotiation, it intends to shift its future enforcement focus from coal-fired power plants to other sectors where compliance assurance activities have the potential to produce significant environmental benefits. In addition, in March 2006, the U.S. Court of Appeals for the D.C. Circuit invalidated a final rule issued by the US EPA in October 2003 that clarified, among other things, the routine maintenance, repair and replacement exemption from NSR requirements. The rule sought to impose a "bright line" test so that companies would have more clarity about when the NSR applies, providing that replacement of functionally equivalent components that does not exceed 20% of the replacement value

of the process unit would fall within the exemption. The US EPA has asked for reconsideration of the Court of Appeals' decision and may appeal it to the Supreme Court.

Prior to EME's purchase of the Homer City facilities, the US EPA requested information under Section 114 of the Clean Air Act from the prior owners of the plant concerning physical changes at the plant. This request was part of the US EPA's industry-wide investigation of compliance by coal-fired plants with the Clean Air Act NSR requirements. On February 21, 2003, Midwest Generation received a request for information under Section 114 regarding past operations, maintenance and physical changes at the Illinois coal plants from the US EPA. On July 28, 2003, Commonwealth Edison received a substantially similar request for information from the US EPA related to these same plants. Under date of February 1, 2005, the US EPA submitted a request for additional information to Midwest Generation. Midwest Generation has provided responses to these requests. Other than these requests for information, no NSR enforcement-related proceedings have been initiated by the US EPA with respect to any of EME's facilities. See also "State—Illinois—Air Quality."

Developments with respect to changes to the NSR program and NSR enforcement will continue to be monitored by EME to assess what implications, if any, they will have on the operation of power plants owned or operated by EME or its subsidiaries, or on EME's results of operations or financial position.

Clean Water Act—Cooling Water Intake Structures

On July 9, 2004, the US EPA published the final Phase II rule implementing Section 316(b) of the Clean Water Act establishing standards for cooling water intake structures at existing electrical generating stations that withdraw more than 50 million gallons of water per day and use more than 25% of that water for cooling purposes. The purpose of the regulation is to reduce substantially the number of aquatic organisms that are pinned against cooling water intake structures or drawn into cooling water systems. Pursuant to the regulation, a demonstration study must be conducted when applying for a new or renewed National Pollutant Discharge Elimination System, or NPDES, wastewater discharge permit. If one can demonstrate that the costs of meeting the presumptive standards set forth in the regulation are significantly greater than the costs that the US EPA assumed in its rule making or are significantly disproportionate to the expected environmental benefits, a site-specific analysis may be performed to establish alternative standards. Depending on the findings of the demonstration studies, cooling towers and/or other mechanical means of reducing impingement/ entrainment may be required. EME has begun to collect impingement and entrainment data at its potentially affected Midwest Generation facilities in Illinois to begin the process of determining what corrective actions may need to be taken.

After the final promulgation of the Phase II cooling water intake structure regulation, legal challenges were filed by environmental groups, the attorneys general for six states, a utility trade association and several individual electric power generating companies. These cases were consolidated and transferred to the United States Court of Appeals for the Second Circuit, briefs were filed, and oral argument occurred in June 2006. A decision is expected imminently. The final requirements of the Phase II rule will not be fully known until these appeals are resolved and, if necessary, the regulation is revised by the US EPA. Although the Phase II rule could have a material impact on EME's operations, EME cannot reasonably determine the financial impact on it at this time because it is in the beginning stages of collecting the data required by the regulation and due to the legal challenges mentioned above which may affect the obligations imposed by the rule.

Federal Legislative Initiatives

There have been a number of bills introduced in Congress that would amend the Clean Air Act to specifically target emissions of specific pollutants from electric utility generating stations. These bills would mandate reductions in emissions of NOx, SO2 and mercury. Some bills would also impose limitations on carbon dioxide emissions. The various proposals differ in many details, including the timing of any required reductions; the extent of required reductions; and the relationship of any new obligations that would be imposed by these bills with existing legal requirements. There is significant uncertainty as to whether any of the proposed legislative initiatives will pass in its current form or whether any compromise can be reached that would facilitate passage of legislation. Accordingly, EME is not able to evaluate the potential impact of these proposals at this time.

Environmental Remediation

Under various federal, state and local environmental laws and regulations, a current or previous owner or operator of any facility, including an electric generating facility, may be required to investigate and remediate releases or threatened releases of hazardous or toxic substances or petroleum products located at that facility, and may be held liable to a governmental entity or to third parties for property damage, personal injury, natural resource damages, and investigation and remediation costs incurred by these parties in connection with these releases or threatened releases. In addition, persons who arrange for the disposal or treatment of hazardous or toxic substances at a disposal or treatment facility may be liable for the costs to remediate releases of hazardous substances from such facilities even where the disposal of such wastes was undertaken in compliance with applicable laws. Many of these laws, including the Comprehensive Environmental Response, Compensation and Liability Act of 1980, commonly referred to as CERCLA, as amended by the Superfund Amendments and Reauthorization Act of 1986, impose liability without regard to whether the owner knew of or caused the presence of the hazardous substances, and courts have interpreted liability under these laws to be strict and joint and several.

With respect to potential liabilities arising under CERCLA or similar laws for the investigation and remediation of contaminated property, EME accrues a liability to the extent the costs are probable and can be reasonably estimated. Midwest Generation had accrued approximately $4 million as of June 30, 2006 for estimated environmental investigation and remediation costs for the Illinois Plants. This estimate is based upon the number of sites, the scope of work and the estimated costs for environmental activity where such expenditures could be reasonably estimated. Future estimated costs may vary based on changes in regulations or requirements of federal, state, or local governmental agencies, changes in technology, and actual costs of disposal. In addition, future remediation costs will be affected by the nature and extent of contamination discovered at the sites that requires remediation. Given the prior history of the operations at its facilities, EME cannot be certain that the existence or extent of all contamination at its sites has been fully identified. However, based on available information, management believes that future costs in excess of the amounts disclosed on all known and quantifiable environmental contingencies will not be material to EME's financial position.

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

Obligations, Commitments and Contingencies—Commercial Commitments—Guarantees and Indemnities" for a discussion of these indemnities.

State—Illinois

Air Quality

Beginning with the 2003 ozone season (May 1 through September 30), EME has been required to comply with an average NOx emission rate of 0.25 lb NOx/MMBtu of heat input. This limitation is commonly referred to as the East St. Louis State Implementation Plan. This regulation is a State of Illinois requirement. Each of the Illinois Plants has complied with this standard in 2003. Beginning with the 2004 ozone season, the Illinois Plants became subject to the federally mandated "NOx SIP Call" regulation that provided ozone-season NOx emission allowances to a 19-state region east of the Mississippi. This program provides for NOx allowance trading similar to the SO2 (acid rain) trading program already in effect. EME qualified for early reduction allowances by reducing NOx emissions at various plants ahead of the imposed deadline. During 2004, the Illinois Plants stayed within their NOx allocations by augmenting their allocation with early reduction credits generated within the fleet. In 2005, the Illinois Plants used banked allowances, along with some purchased allowances, to stay within their NOx allocations. In 2006, EME has continued to continue to purchase allowances while evaluating the costs and benefits of various technologies to determine whether any additional pollution controls should be installed at the Illinois facilities.

On March 14, 2006, the Illinois Environmental Protection Agency submitted a proposed rule to the Illinois Pollution Control Board, or PCB, for adoption. The proposed rule requires a 90% reduction of mercury emissions from coal-fired power plants averaged across company-owned Illinois stations and a minimum reduction of 75% for individual generating units by July 1, 2009. A 90% reduction at each station would be required by 2013. Buying or selling of emission allowances under the CAMR federal cap and trade program would be prohibited. The Pollution Control Board must act on proposed rules submitted by the Illinois EPA after evidentiary hearings, including the presentation and cross-examination of expert testimony. The first hearing on the rule was held in June 2006 and a second hearing was held in August 2006. The PCB is expected to issue an order on the proposed rule after final comments which were filed on September 20, 2006. After the Pollution Control Board adopts rules, they must be submitted to the General Assembly's Joint Committee on Administrative Rules for notice, hearing, and adoption, rejection or modification. Rules adopted through such state proceedings are also subject to court appeal. EME is not able at this time to predict the final form of these rules or provide an estimate of their financial impact.

On May 30, 2006, the Illinois EPA submitted a proposed regulation to the Illinois Pollution Control Board to implement the federal CAIR which requires reductions in NOx and SO2. Although this SIP was to be submitted to the US EPA by September 11, 2006, the US EPA Federal implementation plan which was promulgated on March 15, 2006 allows the Illinois EPA to submit an abbreviated SIP by April 30, 2007. The Illinois Pollution Control Board has scheduled hearings on this CAIR proposal which are to begin on October 10, 2006 and November 28, 2006. The Illinois EPA has also begun to develop SIPs to meet National Ambient Air Quality Standards for 8-hour ozone and fine particulates. These SIPs will be developed with the intent of bringing non-attainment areas, such as Chicago, into attainment. They are expected to deal with all emission sources, not just power generators, and to address emissions of NOx, SO2, and Volatile Organic Carbon. These SIPs are to be submitted to the US EPA by June 15, 2007 for 8-hour ozone, and by April 5, 2008 for fine particulates. EME is not able at this time to predict the final form of the SIPs or to estimate their financial impact.

Water Quality

The Illinois EPA is reviewing the water quality standards for the Des Plaines River adjacent to the Joliet Station and immediately downstream of the Will County Station to determine if the use classification should be upgraded. An upgraded use classification could result in more stringent limits being applied to wastewater discharges to the river from these plants. If the existing use classification is changed, the limits on the temperature of the discharges from the Joliet and Will County plants may be made more stringent. The Illinois EPA has also begun a review of the water quality standards for the Chicago River and Chicago Sanitary and Ship Canal which are adjacent to the Fisk and Crawford Stations. Proposed changes to the existing standards are still being developed. Accordingly, EME is not able to estimate financial impact of potential changes to the water quality standards. However, the cost of additional cooling water treatment, if required, could be substantial.

State—Pennsylvania

Air Quality

During 2006, the Pennsylvania Department of Environmental Protection, or PADEP, is expected to begin the process of developing a SIP to implement the federal CAIR which requires reductions in NOx and SO2. While this SIP is to be submitted to the US EPA by September 11, 2006, no proposal has been made by the US EPA at this time. Consequently, EME believes it is probable that the PADEP will follow the same abbreviated SIP path as the State of Illinois and submit its SIP by April 30, 2007. The Ozone Transport Commission, of which Pennsylvania is a member, is developing a model rule that would continue to allow SO2 and NOx emissions trading, but would impose more stringent limits on SO2 and NOx emissions and would phase in these reductions more quickly than is required by CAIR. EME does not know whether the northeast states will ultimately agree to this model rule or whether Pennsylvania will implement such a rule. Pennsylvania is also required to develop a SIP to implement the federal CAMR, which SIP is to be submitted to the US EPA by November 17, 2006. With respect to mercury, on May 17, 2006, the PADEP submitted a proposed rule to the State's Environmental Quality Board, which is still pending before the Environmental Quality Board, that would require coal-fired power plants to reduce mercury emissions by 80% by 2010 and 90% by 2015. The proposed rule would not allow the use of emissions trading to achieve compliance. Public hearings on the proposal were conducted in July 2006, and the PADEP, as well as an Independent Regulatory Review Commission and two committees of the General Assembly, may suggest changes to its rule before final adoption by the Environmental Quality Board. After the Environmental Quality Board adoption of a final rule, the rule remains subject to another round of review before the Independent Regulatory Review Commission. The General Assembly also is considering adoption of mercury regulations that could pre-empt the Environmental Quality Board rulemaking. In May 2006, the State Senate passed a bill that would implement the federal CAMR as the state rule. The House has held several committee hearings on the Senate bill for potential alternatives. EME is not able at this time to predict the final form of the SIPs or to estimate their financial impact.

Water Quality

performance of the treatment system, the discharge still was not able to consistently meet the selenium effluent limits. EME identified additional options for achieving the selenium limits, and, with PADEP's approval, has undertaken a pilot program utilizing biological treatment. EME prepared a draft of a consent order and agreement addressing the selenium issue and presented it to PADEP for consideration in connection with the renewal of the station's NPDES permit. PADEP has included civil penalties in consent agreements related to other facilities with selenium treatment issues, but the amount of civil penalties that may be assessed against EME cannot be estimated at this time.

Climate Change

The Kyoto Protocol on climate change officially came into effect on February 16, 2005. Under the Kyoto Protocol, the United States would have been required, by 2008-2012, to reduce its greenhouse gas emissions, such as carbon dioxide, by 7% from 1990 levels. Under the Bush administration, however, the United States has chosen not to pursue ratification of the Kyoto Protocol. Instead, the Bush administration has proposed several alternatives to mandatory reductions of greenhouse gases.

There have been petitions from states and other parties to compel the US EPA to regulate greenhouse gases under the Clean Air Act. Also, in 2004, several states and environmental organizations brought a complaint in federal court in New York, alleging that several electric utility corporations are jointly and severally liable under a theory of public nuisance for damages caused by the alleged contribution to global warming resulting from carbon dioxide emissions from coal-fired power plants owned and operated by these companies or their subsidiaries. Neither EME nor its subsidiaries were named as defendants in the complaint. The case was dismissed and is currently on appeal with the United States Court of Appeals for the Second Circuit.

On December 20, 2005, seven northeastern states entered into a Memorandum of Understanding to create a regional initiative to establish a cap and trade greenhouse gas program for electric generators, referred to as the Regional Greenhouse Gas Initiative, or RGGI. The model RGGI rule for implementation of the Memorandum of Understanding was announced in August 2006. The current proposal is to commence the program in 2009 by setting a cap (for the 2009 to 2015 period) on allowances based on carbon dioxide emissions from 2000 to 2004 and reducing emissions by 10% between 2015 and 2020. The Memorandum of Understanding provides that at least 25% of the state allowance allocations be set aside for public purposes, suggesting that from the commencement of the program, generators subject to the RGGI may receive allowances that are materially less than their carbon dioxide emissions. Illinois and Pennsylvania are not signatories to the RGGI, although Pennsylvania has participated as an observer of the process. If Pennsylvania were to join the RGGI, this could have a material impact on EME's Homer City facility.

In California, Governor Schwarzenegger issued an executive order on June 1, 2005, setting forth targets for greenhouse gas reductions. The targets called for a reduction of greenhouse gas emissions to 2000 levels by 2010; a reduction of greenhouse gas emissions to 1990 levels by 2020; and a reduction of greenhouse gas emissions to 80% below 1990 levels by 2050. Two bills have passed both houses of the California legislature and are awaiting the Governor's signature: SB 1368, which establishes a greenhouse gas emissions standard for base load generation equal to that of a combined-cycle gas turbine generator, and AB 32, which requires reduction of greenhouse gas emissions to 1990 levels by 2020. In addition, the California Public Utilities Commission is addressing climate change related issues in various regulatory proceedings.

the future viability of fossil fuels, particularly coal, as an energy source for new and existing electric generating facilities.

MARKET RISK EXPOSURES

Introduction

EME's primary market risk exposures are associated with the sale of electricity and capacity from and the procurement of fuel for its merchant power plants. These market risks arise from fluctuations in electricity, capacity and fuel prices, emission allowances, and transmission rights. Additionally, EME's financial results can be affected by fluctuations in interest rates. EME manages these risks in part by using derivative financial instruments in accordance with established policies and procedures.

Commodity Price Risk

General Overview

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

•: prevailing market prices for coal, natural gas and fuel oil, and associated transportation;
•: the extent of additional supplies of capacity, energy and ancillary services from current competitors or new market entrants, including the development of new generation facilities and/or technologies that may be able to produce electricity at a lower cost than EME's generating facilities and/or increased access by competitors to EME's markets as a result of transmission upgrades;
•: transmission congestion in and to each market area and the resulting differences in prices between delivery points;
•: the market structure rules established for each market area and regulatory developments affecting the market areas, including any price limitations and other mechanisms adopted to address volatility or illiquidity in these markets or the physical stability of the system;
•: the cost and availability of emission credits or allowances;
•: the availability, reliability and operation of competing power generation facilities, including nuclear generating plants, where applicable, and the extended operation of such facilities beyond their presently expected dates of decommissioning;
•: weather conditions prevailing in surrounding areas from time to time; and
•: changes in the demand for electricity or in patterns of electricity usage as a result of factors such as regional economic conditions and the implementation of conservation programs.

A discussion of commodity price risk for the Illinois Plants and the Homer City facilities is set forth below.

Introduction

In addition to prevailing market prices, EME's ability to derive profits from the sale of electricity will be affected by the cost of production, including costs incurred to comply with environmental regulations. The costs of production of the units vary and, accordingly, depending on market conditions, the amount of generation that will be sold from the units is expected to vary from unit to unit.

EME uses "value at risk" to identify, measure, monitor and control its overall market risk exposure in respect of its Illinois Plants, its Homer City facilities, and its trading 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.

Hedging Strategy

To reduce its exposure to market risk, EME hedges a portion of its merchant portfolio risk through EMMT, an EME subsidiary engaged in the power marketing and trading business. To the extent that EME does not hedge its merchant portfolio, the unhedged portion will be subject to the risks and benefits of spot market price movements. Hedge transactions are primarily implemented through the use of contracts cleared on the Intercontinental Trading Exchange and the New York Mercantile Exchange. Hedge transactions are also entered into as forward sales to utilities and power marketing companies.

The extent to which EME hedges its market price risk depends on several factors. First, EME evaluates over-the-counter market prices to determine whether sales at forward market prices are sufficiently attractive compared to assuming the risk associated with fluctuating spot market sales. Second, EME's ability to enter into hedging transactions depends upon its and Midwest Generation's credit capacity and upon the forward sales markets having sufficient liquidity to enable EME to identify appropriate counterparties for hedging transactions.

In the case of hedging transactions related to the generation and capacity of the Illinois Plants, Midwest Generation is permitted to use its working capital facility and cash on hand to provide credit support for these hedging transactions entered into by EMMT under an energy services agreement between Midwest Generation and EMMT. Utilization of this credit facility in support of hedging transactions provides additional liquidity support for implementation of EME's contracting strategy for the Illinois Plants. In the case of hedging transactions related to the generation and capacity of the Homer City facilities, credit support is provided by EME pursuant to intercompany arrangements between it and EMMT. See "—Credit Risk," below.

Energy Price Risk Affecting Sales from the Illinois Plants

All the energy and capacity from the Illinois Plants is sold under terms, including price and quantity, negotiated by EMMT with customers through a combination of bilateral agreements, forward energy sales and spot market sales. As discussed further below, power generated at the Illinois Plants is generally sold into the PJM market.

Midwest Generation sells its power into PJM at spot prices based upon locational marginal pricing. Hedging transactions related to the generation of the Illinois Plants are generally entered into at the Northern Illinois Hub in PJM, and may also be entered into at other trading hubs, including the AEP/Dayton Hub in PJM and the Cinergy Hub in the MISO. These trading hubs have been the most liquid locations for hedging purposes. However, hedging transactions which settle at points other than the Northern Illinois Hub are subject to the possibility of basis risk. See "—Basis Risk" below for further discussion.

PJM has a short-term market, which establishes an hourly clearing price. The Illinois Plants are situated in the PJM control area and are physically connected to high-voltage transmission lines serving this market.

The following table depicts the average historical market prices for energy per megawatt-hour during 2005 and 2004 and during the first six months of 2006.

	2006(1)		2005(1)		2004
January	$	42.27	$	38.36	$	27.88	(2)
February		42.66		34.92		29.98	(2)
March		42.50		45.75		30.66	(2)
April		43.16		38.98		27.88	(2)
May		39.96		33.60		34.05	(1)
June		34.80		42.45		28.58	(1)

2006 and 2005 Six-Month Average	$	40.89	$	39.01

July				50.87		30.92	(1)
August				60.09		26.31	(1)
September				53.30		27.98	(1)
October				49.39		30.93	(1)
November				44.03		29.15	(1)
December				64.99		29.90	(1)

Yearly Average			$	46.39	$	29.52

(1): Represents average historical market prices for energy as quoted for sales into the Northern Illinois Hub. Energy prices were calculated at the Northern Illinois Hub delivery point using hourly real-time prices as published by PJM.
(2): Represents average historical market prices for energy "Into ComEd." Energy prices were determined by obtaining broker quotes and other public price sources for "Into ComEd" delivery points.

Forward market prices at the Northern Illinois Hub fluctuate as a result of a number of factors, including natural gas prices, transmission congestion, changes in market rules, electricity demand (which in turn is affected by weather, economic growth, and other factors), plant outages in the region, and the amount of existing and planned power plant capacity. The actual spot prices for electricity delivered by the Illinois Plants into these markets may vary materially from the forward market prices set forth in the table below.

The following table sets forth the forward market prices for energy per megawatt-hour as quoted for sales into the Northern Illinois Hub at June 30, 2006:

		24-Hour Northern Illinois Hub Forward Energy Prices(1)
2006
	July	$	43.77
	August		47.64
	September		36.86
	October		33.17
	November		38.21
	December		50.37
2007 Calendar "strip"(2)		$	45.49
2008 Calendar "strip"(2)		$	45.10

(1): Energy prices were determined by obtaining broker quotes and information from other public sources relating to the Northern Illinois Hub delivery point.
(2): Market price for energy purchases for the entire calendar year, as quoted for sales into the Northern Illinois Hub.

The following table summarizes Midwest Generation's hedge position (primarily based on prices at the Northern Illinois Hub) at June 30, 2006:

		2006			2007			2008
Megawatt hours			10,039,760			16,237,200			3,072,000
Average price/MWh(1)		$	47.61		$	48.25		$	66.13

(1): The above hedge positions include forward contracts for the sale of power during different periods of the year and the day. Market prices tend to be higher during on-peak periods during the day and during summer months, although there is significant variability of power prices during different periods of time. Accordingly, the above hedge position at June 30, 2006 is not directly comparable to the 24-hour Northern Illinois Hub prices set forth above.

Subsequent to June 30, 2006, EMMT entered into an agreement with a third party to hedge the price risk for 500 MW of on-peak power from the Illinois Plants for 2007, 2008 and 2009 (using the Northern Illinois Hub as a reference point). Under the terms of the agreement, EME has guaranteed the obligation of EMMT, but neither EME nor EMMT is required to post margin, provide liens on property or provide other collateral to support the obligations under the agreement. In addition, EMMT participated successfully in the Illinois auction, and on September 19, 2006, executed contracts for the supply of electricity.

Energy Price Risk Affecting Sales from the Homer City Facilities

Electric power generated at the Homer City facilities is generally sold into the PJM market. PJM has a short-term market, which establishes 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 historical market prices for energy per megawatt-hour at the Homer City busbar and in PJM West Hub during 2005, 2004, 2003 and during the first six months of 2006:

	Historical Energy Prices(1) 24-Hour PJM
	Homer City								West Hub
	2006		2005		2004		2003		2006		2005		2004		2003
January	$	48.67	$	45.82	$	51.12	$	36.56	$	54.57	$	49.53	$	55.01	$	43.62
February		49.54		39.40		47.19		46.13		56.39		42.05		44.22		48.31
March		53.26		47.42		39.54		46.85		58.30		49.97		39.21		54.85
April		48.50		44.27		43.01		35.35		49.92		44.55		42.82		35.93
May		44.71		43.67		44.68		32.29		48.55		43.64		48.04		32.10
June		38.78		46.63		36.72		27.26		45.78		53.72		38.05		29.10

2006 Six-Month Average	$	47.24	$	44.54					$	52.25	$	47.24

July				54.63		40.09		36.55				66.34		43.64		40.88
August				66.39		34.76		39.27				82.83		38.59		39.74
September				66.67		40.62		28.71				76.82		41.96		29.51
October				67.93		37.37		26.96				77.56		37.78		27.47
November				59.78		35.79		29.17				62.01		36.91		29.30
December				75.03		38.59		35.89				81.97		41.83		35.92

Yearly Average			$	54.80	$	40.79	$	35.08			$	60.92	$	42.34	$	37.23

(1): Energy prices were calculated at the Homer City busbar (delivery point) and PJM West Hub using historical hourly real-time prices provided on the PJM web-site.

Forward market prices at the PJM West Hub fluctuate as a result of a number of factors, including natural gas prices, transmission congestion, changes in market rules, electricity demand (which in turn is affected by weather, economic growth and other factors), plant outages in the region, and the amount of existing and planned power plant capacity. The actual spot prices for electricity delivered by the Homer City facilities into these markets may vary materially from the forward market prices set forth in the table below.

The following table sets forth the forward market prices for energy per megawatt-hour as quoted for sales into the PJM West Hub at June 30, 2006:

		24-Hour PJM West Hub Forward Energy Prices(1)
2006
	July	$	59.69
	August		63.18
	September		49.56
	October		48.23
	November		53.15
	December		65.25
2007 Calendar "strip"(2)		$	63.80
2008 Calendar "strip"(2)		$	62.58

(1): Energy prices were determined by obtaining broker quotes and information from other public sources relating to the PJM West Hub delivery point. Forward prices at PJM West Hub are generally higher than the prices at the Homer City busbar.
(2): Market price for energy purchases for the entire calendar year, as quoted for sales into the PJM West Hub.

The following table summarizes Homer City's hedge position at June 30, 2006:

		2006			2007			2008
Megawatt hours			4,415,900			7,590,000			2,371,200
Average price/MWh(1)		$	54.07		$	64.35		$	66.01

(1): The above hedge positions include forward contracts for the sale of power during different periods of the year and the day. Market prices tend to be higher during on-peak periods during the day and during summer months, although there is significant variability of power prices during different periods of time. Accordingly, the above hedge position at June 30, 2006 is not directly comparable to the 24-hour PJM West Hub prices set forth above.

The average price/MWh for Homer City's hedge position is based on PJM West Hub. Energy prices at the Homer City busbar have been lower than energy prices at the PJM West Hub. See "—Basis Risk" below for a discussion of the difference.

Basis Risk

Sales made from the Illinois Plants and the Homer City facilities in the real-time or day-ahead market receive the actual spot prices at the busbars (delivery points) of the individual plants. In order to mitigate price risk from changes in spot prices at the individual plant busbars, EME may enter into cash settled futures contracts as well as forward contracts with counterparties for energy to be delivered in future periods. Currently, a liquid market for entering into these contracts at the individual plant busbars does not exist. A liquid market does exist for a settlement point at the PJM West Hub in the case of the Homer City facilities and for a settlement point at the Northern Illinois Hub in the case of the Illinois Plants. EME's price risk management activities use these settlement points (and, to a lesser extent, other similar trading hubs) to enter into hedging contracts. EME's revenues with respect to such forward contracts include:

•: sales of actual generation in the amounts covered by the forward contracts with reference to PJM spot prices at the busbar of the plant involved, plus,

•: sales to third parties at the price under such hedging contracts at designated settlement points (generally the PJM West Hub for the Homer City facilities and the Northern Illinois Hub for the Illinois Plants) less the cost of power at spot prices at the same designated settlement points.

Under PJM's market design, locational marginal pricing, which establishes market prices at specific locations throughout PJM by considering factors including generator bids, load requirements, transmission congestion and losses, can cause the price of a specific delivery point to be higher or lower relative to other locations depending on how the point is affected by transmission constraints. To the extent that, on the settlement date of a hedge contract, spot prices at the relevant busbar are lower than spot prices at the settlement point, the proceeds actually realized from the related hedge contract are effectively reduced by the difference. This is referred to as "basis risk." During both the six months ended June 30, 2006 and during 2005, transmission congestion in PJM has resulted in prices at the Homer City busbar being lower than those at the PJM West Hub (EME Homer City's primary trading hub) by an average of 10%, compared to 6% during the six months ended June 30, 2005 and 4% during 2004. The monthly average difference during the twelve months ended June 30, 2006 ranged from 3% to 20%, which occurred in August 2005. In contrast to the Homer City facilities, during the past 12 months, the prices at the Northern Illinois Hub were substantially the same as those at the individual busbars of the Illinois Plants.

By entering into cash settled futures contracts and forward contracts using the PJM West Hub and the Northern Illinois Hub (or other similar trading hubs) as settlement points, EME is exposed to basis risk as described above. In order to mitigate basis risk, EME has purchased 7.8 TWh of financial transmission rights and basis swaps in PJM for Homer City during the period July 1, 2006 through May 31, 2007, and may continue to purchase financial transmission rights and basis swaps in the future. A financial transmission right is a financial instrument that entitles the holder to receive the difference of actual spot prices for two delivery points in exchange for a fixed amount. Accordingly, EME's price risk management activities include using financial transmission rights alone or in combination with forward contracts and basis swap contracts to manage basis risk.

Coal Price and Transportation Risk

The Illinois Plants use approximately 18 million to 20 million tons of coal annually, primarily obtained from the Southern Powder River Basin of Wyoming. In addition, the Homer City facilities use approximately 5 million to 6 million tons of coal annually, obtained primarily from mines located near the facilities in Pennsylvania. Coal purchases are made under a variety of supply agreements with terms ranging from one year to eight years. The following table summarizes the percent of expected coal requirements for the next five years that were under contract at June 30, 2006.

	Percent of Coal Requirements Under Contract
	2006(1)	2007	2008	2009	2010
Illinois Plants	108%	95%	33%	33%	33%
Homer City facilities	99%	97%	39%	15%	0%

(1): The percentage in 2006 is calculated based on coal supply and expected generation requirements for a full year.

EME is subject to price risk for purchases of coal that are not under contract. Prices of Northern Appalachian, or NAPP, coal, which is related to the price of coal purchased for the Homer City facilities, increased considerably during 2005 and 2004. In January 2004, prices of NAPP coal (with 13,000 British Thermal units (Btu) per pound heat content and <3.0 pounds of SO2 per MMBtu sulfur content) were below $40 per ton and increased to more than $60 per ton during 2004. The price of

NAPP coal fluctuated between $44 per ton and $57 per ton during 2005, with a price of $45 per ton at December 30, 2005, as reported by the Energy Information Administration. The overall increase in the NAPP coal price was largely attributed to greater demand from domestic power producers and increased international shipments of coal to Asia. During the first six months of 2006, the price of NAPP coal decreased to $37.50 per ton at June 23, 2006, as reported by the Energy Information Administration, due to the combined effects of a mild winter, easing natural gas prices and improving eastern stockpiles. Prices of Powder River Basin, or PRB, coal (with 8,800 Btu per pound heat content and 0.8 pounds of SO2 per MMBtu sulfur content), which is purchased for the Illinois Plants, significantly increased in 2005 due to the curtailment of coal shipments during 2005 due to increased PRB coal demand from other regions (east), rail constraints (discussed below), higher oil and natural gas prices and higher prices for SO2 allowances. On June 23, 2006, the Energy Information Administration reported the price of PRB coal to be $12.25 per ton, which compares to 2005 prices that ranged from $6.20 per ton to $18.48 per ton and 2004 prices of generally below $7.00 per ton. The price of PRB coal decreased during the first six months of 2006 from 2005 year-end prices due to easing natural gas prices, lower prices for SO2 allowances and mild weather during the first six months of 2006.

After two derailments in May 2005, the railroads that bring coal from the PRB mines to the Illinois Plants discovered significant problems with the joint-rail line that serves the PRB mines. Repairs to the joint-rail line are expected to continue through most of 2006. Even though some restrictions in coal shipments have occurred while repairs are being completed, EME expects to continue receiving a sufficient amount of coal to generate power based on communications with the railroad companies.

Emission Allowances Price Risk

The federal Acid Rain Program requires electric generating stations to hold SO2 allowances, and Illinois and Pennsylvania regulations implemented the federal NOx SIP Call requirement. Under these programs, EME purchases (or sells) emission allowances based on the amounts required for actual generation in excess of (or less than) the amounts allocated under these programs. As part of the acquisition of the Illinois Plants and the Homer City facilities, EME obtained the rights to the emission allowances that have been or are allocated to these plants.

The price of emission allowances, particularly SO2 allowances issued through the federal Acid Rain Program, increased substantially during 2005 and 2004 and decreased during the first half of 2006 from 2005 year-end prices. The average price of purchased SO2 allowances increased from $204 per ton during 2003 to $435 per ton during 2004 to $1,219 per ton during 2005 and decreased to $899 per ton during the six months ended June 30, 2006. The increase in the price of SO2 allowances has been attributed to reduced numbers of both allowance sellers and prior year allowances. The decrease in the price of SO2 allowances during the six months ended June 30, 2006 from 2005 year-end prices has been attributed to lower loads in January 2006 and a decline in natural gas prices. The price of SO2 allowances, determined by obtaining broker quotes and information from other public sources, was $750 per ton as of July 31, 2006.

Based on EME's anticipated SO2 emission allowances requirements in 2006, EME expects that a 10% change in the price of SO2 emission allowances at December 31, 2005 would increase or decrease pre-tax income in 2006 by approximately $7 million. See "Liquidity and Capital Resources—Environmental Matters and Regulations" for a discussion of environmental regulations related to emissions.

Credit Risk

In conducting EME's price risk management and trading activities, EME contracts with a number of utilities, energy companies, financial institutions, and other companies, collectively referred to as counterparties. In the event a counterparty were to default on its trade obligation, EME would be exposed to the risk of possible loss associated with re-contracting the product at a price different from the original contracted 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 a counterparty defaulted.

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

EME measures credit risk exposure from counterparties of its merchant energy activities as either: (i) the sum of 60 days of accounts receivable, current fair value of open positions, and a credit value at risk, or (ii) the sum of delivered and unpaid accounts receivable and the current fair value of open positions. EME's subsidiaries enter into master agreements and other arrangements in conducting price risk management and trading activities which typically provide for a right of setoff in the event of bankruptcy or default by the counterparty. Accordingly, EME's credit risk exposure from counterparties is based on net exposure under these agreements. At June 30, 2006, the amount of exposure, broken down by the credit ratings of EME's counterparties, was as follows:

S&P Credit Rating	June 30, 2006
	(in millions)
A or higher	$	88
A-		18
BBB+		52
BBB		65
BBB-		—
Below investment grade		2

Total	$	225

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

In addition, coal for the Illinois Plants and the Homer City facilities is purchased from suppliers under contracts which may be for multiple years. A number of the coal suppliers to the Illinois Plants

and the Homer City facilities do not currently have an investment grade credit rating and, accordingly, EME may have limited recourse to collect damages in the event of default by a supplier. EME seeks to mitigate this risk through diversification of its coal suppliers and through guarantees and other collateral arrangements when available. Despite this, there can be no assurance that these efforts will be successful in mitigating credit risk from coal suppliers.

EME's merchant plants sell electric power generally into the PJM market by participating in PJM's capacity and energy markets or transact capacity and energy on a bilateral basis. Sales into PJM accounted for approximately 69% and 70% of EME's consolidated operating revenues for the six months ended June 30, 2006 and the year ended December 31, 2005, respectively. Moody's Investors Service rates PJM's senior unsecured debt Aa3. PJM, an independent system operator with over 300 member companies, maintains its own credit risk policies and does not extend unsecured credit to non-investment grade companies. Any losses due to a PJM member default are shared by all other members based upon a predetermined formula. At June 30, 2006, EME's account receivable due from PJM was $70 million.

Interest Rate Risk

Interest rate changes can affect earnings and the cost of capital for capital improvements or new investments in power projects. EME mitigates 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. Based on the amount of variable rate long-term debt for which EME has not entered into interest rate hedge agreements at December 31, 2005, a 100-basis-point change in interest rates at December 31, 2005 would increase or decrease annual income before taxes by approximately $5 million. The fair market values of long-term fixed interest rate obligations are subject to interest rate risk. The fair market value of EME's total long-term obligations (including current portion) was $3.7 billion at December 31, 2005, compared to the carrying value of $3.4 billion. A 10% increase in market interest rates at December 31, 2005 would result in a decrease in the fair value of total long-term obligations by approximately $125 million. A 10% decrease in market interest rates at December 31, 2005 would result in an increase in the fair value of total long-term obligations by approximately $141 million.

The fair market value of EME's consolidated long-term obligations (including current portion) was $3.5 billion at June 30, 2006, compared to the carrying value of $3.4 billion.

Fair Value of Financial Instruments

Non-Trading Derivative Financial Instruments

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

			June 30, 2006			December 31, 2005			December 31, 2004
Commodity price:
	Electricity		$	(3	)	$	(434	)	$	10

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. A 10% change

in the market price at December 31, 2005 would increase or decrease the fair value of outstanding derivative commodity price contracts by approximately $250 million. The following table summarizes the maturities and the related fair value, based on actively traded prices, of EME's commodity price risk management assets and liabilities (in millions):

Prices Actively Quoted	Total Fair Value			Maturity <1 year			Maturity 1 to 3 years			Maturity 4 to 5 years		Maturity >5 years
As of December 31, 2005	$	(434	)	$	(354	)	$	(80	)	$	—	$	—

As of June 30, 2006	$	(3	)	$	5		$	(8	)	$	—	$	—

Energy Trading Derivative Financial Instruments

The fair value of the commodity financial instruments related to energy trading activities as of June 30, 2006 and December 31, 2005 and 2004, are set forth below (in millions):

	June 30, 2006				December 31, 2005				December 31, 2004
	Assets		Liabilities		Assets		Liabilities		Assets		Liabilities
Electricity	$	120	$	4	$	127	$	27	$	125	$	36
Other		1		2		1		—		—		—

Total	$	121	$	6	$	128	$	27	$	125	$	36

The change in the fair value of trading contracts was as follows (in millions):

For the year ended December 31, 2005
Fair value of trading contracts at January 1, 2005	$	89
Net gains from energy trading activities		202
Amount realized from energy trading activities		(203	)
Other changes in fair value		13

Fair value of trading contracts at December 31, 2005	$	101
For the six months ended June 30, 2006
Net gains from energy trading activities		59
Amount realized from energy trading activities		(52	)
Other changes in fair value		7

Fair value of trading contracts at June 30, 2006	$	115

A 10% change in the market price at December 31, 2005 would increase or decrease the fair value of trading contracts by approximately $6 million.

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 (in millions):

	Total Fair Value		Maturity <1 year		Maturity 1 to 3 years		Maturity 4 to 5 years		Maturity >5 years
As of December 31, 2005
Prices actively quoted	$	12	$	12	$	—	$	—	$	—
Prices based on models and other valuation methods		89		2		9		15		63

Total	$	101	$	14	$	9	$	15	$	63

As of June 30, 2006
Prices actively quoted	$	29	$	26	$	3	$	—	$	—
Prices based on models and other valuation methods		86		1		11		17		57

Total	$	115	$	27	$	14	$	17	$	57

QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

Information responding to quantitative and qualitative disclosures about market risk is filed with this prospectus under "Management's Discussion and Analysis of Financial Condition and Results of Operations."

BUSINESS

The Company

EME is an independent power producer engaged in the business of owning or leasing, operating and selling energy and capacity from electric power generation facilities. EME also conducts price risk management and energy trading activities in power markets open to competition. EME is a wholly owned subsidiary of Mission Energy Holding Company, which is referred to as MEHC in this prospectus. Edison International is EME's ultimate parent company. Edison International also owns Southern California Edison Company, one of the largest electric utilities in the United States.

EME was formed in 1986 with two domestic operating power plants. As of June 30, 2006, EME's continuing operations consisted of owned or leased interests in 29 operating power plants with an aggregate net physical capacity of 10,473 MW of which EME's capacity pro rata share was 9,295 MW.

EME Restructuring Activities

During 2004 and early 2005, EME sold assets totaling 6,452 MW, which constituted most of its international assets. These international assets, except for the Doga project, which has not been sold, are accounted for as discontinued operations in accordance with Statement of Financial Accounting Standards No. 144, "Accounting for the Impairment or Disposal of Long-Lived Assets," and, accordingly, all prior periods have been restated to reclassify the results of operations and assets and liabilities as discontinued operations. The sale of the international operations included:

•: On September 30, 2004, EME sold its 51.2% interest in Contact Energy Limited to Origin Energy New Zealand Limited.
•: On December 16, 2004, EME sold the stock and related assets of MEC International B.V. to a consortium comprised of International Power plc (70%) and Mitsui & Co., Ltd. (30%), which is referred to as IPM in this prospectus. The sale of MEC International included the sale of EME's ownership interests in ten electric power generating projects or companies located in Europe, Asia, Australia, and Puerto Rico.
•: On January 10, 2005, EME sold its 50% equity interest in the Caliraya-Botocan-Kalayaan, or CBK, hydroelectric power project located in the Philippines to CBK Projects B.V.
•: On February 3, 2005, EME sold its 25% equity interest in the Tri Energy project to IPM.

See "Management's Discussion and Analysis of Financial Condition and Results of Operations—Results of Operations—Results of Discontinued Operations" for further details on EME's asset sales.

EME implemented management and organizational changes in 2005 to streamline its reporting relationships and eliminate its regional management structure. In addition, EME and its affiliate, Edison Capital, combined their management teams located in Irvine, California and combined their wind development efforts. In this regard, EME and Edison Capital entered into a services agreement effective December 26, 2005. Under this services agreement, all existing employees of Edison Capital on the effective date of the agreement were transferred to EME, and thereafter EME provides

accounting, legal, tax, management and administrative services to Edison Capital and its subsidiaries of the type previously provided by the transferred employees. Edison Capital and its subsidiaries continue to operate as independent legal entities separate and apart from EME, and EME has not assumed any obligation for the performance of any of Edison Capital's obligations to any party, whether with respect to its investment portfolio or with respect to any of the creditors of Edison Capital or its subsidiaries.

Description of the Industry

Electric Power Industry

The United States electric industry, including companies engaged in providing generation, transmission, distribution and ancillary services, has undergone significant deregulation, which has led to increased competition. Until the enactment of the Public Utility Regulatory Policies Act of 1978, referred to as PURPA in this prospectus, utilities and government-owned power agencies were the only producers of bulk electric power intended for sale to third parties in the United States. PURPA encouraged the development of independent power by removing regulatory constraints relating to the production and sale of electric energy by certain non-utilities and requiring electric utilities to buy electricity from specified types of non-utility power producers, known as qualifying facilities, under specified conditions. The passage of the Energy Policy Act of 1992 further encouraged the development of independent power by significantly expanding the options available to independent power producers with respect to their regulatory status and by liberalizing transmission access. In addition, in the Energy Policy Act of 2005, referred to as EPAct 2005 in this prospectus, Congress made several changes to PURPA and other statutory provisions recognizing that a significant market for electric power produced by independent power producers, such as EME, has developed in the United States and indicating that competitive wholesale electricity markets have become accepted as a fundamental aspect of the electricity industry.

As part of the regulatory developments discussed above, the Federal Energy Regulatory Commission, referred to as the FERC in this prospectus, encouraged the formation of independent system operators, or ISOs, and regional transmission organizations, or RTOs. In those areas where ISOs and RTOs have been formed, market participants have expanded access to transmission service. ISOs and RTOs may also operate real-time and day ahead energy and ancillary service markets, which are governed by FERC-approved tariffs and market rules. The development of such organized markets into which independent power producers are able to sell has reduced their dependence on bilateral contracts with electric utilities. See further discussion of regulations under "Regulatory Matters—U.S. Federal Energy Regulation."

Electric Power Markets

EME's largest power plants are its fossil fuel power plants located in Illinois, which are collectively referred to as the Illinois Plants in this prospectus, and the Homer City electric generating station located in Pennsylvania, which is referred to as the Homer City facilities in this prospectus. The Illinois Plants and the Homer City facilities sell power into PJM Interconnection, LLC, commonly referred to as PJM. PJM operates a wholesale spot energy market and determines the market-clearing price for each hour based on bids submitted by participating generators which indicate the minimum prices a bidder is willing to accept to be dispatched at various incremental generation levels. PJM conducts both day-ahead and real-time energy markets. PJM's energy markets are based on locational marginal pricing, which establishes hourly prices at specific locations throughout PJM. Locational marginal pricing is determined by considering a number of factors, including generator bids, load requirements, transmission congestion and transmission losses. PJM requires all load serving entities to maintain prescribed levels of capacity, including a reserve margin, to ensure system reliability. PJM also

determines the amount of capacity available from each specific generator and operates capacity markets. PJM's capacity markets have a single market-clearing price. Load serving entities and generators, such as EME's subsidiaries Midwest Generation, LLC, or Midwest Generation, with respect to the Illinois Plants, and EME Homer City Generation L.P., or EME Homer City, with respect to the Homer City facilities, may participate in PJM's capacity markets or transact capacity sales on a bilateral basis.

The Homer City facilities have direct, high voltage interconnections to both PJM and the New York Independent System Operator, which controls the transmission grid and energy and capacity markets for New York State and is commonly referred to as the NYISO. As in PJM, the market-clearing price for NYISO's day-ahead and real-time energy markets is set by supplier generation bids and customer demand bids.

The Illinois Plants also sell power into PJM. On April 1, 2005, the Midwest Independent Transmission System Operator, or MISO, commenced operation, linking portions of Illinois, Wisconsin, Indiana, Michigan, and Ohio, as well as other states in the region, in the MISO, where there is a bilateral market and day-ahead and real-time markets based on locational marginal pricing similar to that of PJM. While EME does not own generating facilities within MISO, its opening has further facilitated transparency of prices and provided additional market liquidity to support risk management and trading strategies.

For a discussion of the risks related to the sale of electricity from these generating facilities, see "Management's Discussion and Analysis of Financial Condition and Results of Operations—Market Risk Exposures."

Competition

EME is subject to intense competition from energy marketers, utilities, energy marketers, industrial companies and other independent power producers. For a number of years until the recent upturn in its price, natural gas has been the fuel of choice for new power generation facilities for economic, operational and environmental reasons. While natural gas-fired facilities will continue to be an important part of the nation's generation portfolio, some regulated utilities are now constructing clean coal units and units powered by renewable resources, often with subsidies or under legislative mandate. These utilities generally have a lower cost of capital than most independent power producers and often are able to recover fixed costs through rate base mechanisms, allowing them to build, buy and upgrade generation without relying exclusively on market clearing prices to recover their investments.

Where EME sells power from plants from which the output is not committed to be sold under long-term contracts, commonly referred to as merchant plants, EME is subject to market fluctuations in prices based on a number of factors, including the amount of capacity available to meet demand, the price and availability of fuel and the presence of transmission constraints. Some of EME's competitors, such as electric utilities and distribution companies have their own generation capacity, including nuclear generation. These companies, generally larger than EME, have a lower cost of capital and may have competitive advantages as a result of their scale and location of their generation facilities.

Operating Segments

EME is headquartered in Irvine, California with additional offices located in Chicago, Illinois and Boston, Massachusetts.

Overview of Facilities

As of June 30, 2006, EME's operations consisted of ownership or leasehold interests in the following operating power plants:

Power Plants			Location	Fuel Type	Ownership Interest	Net Physical Capacity (in MW)	EME's capacity pro rata share (in MW)
Merchant Power Plants
	Illinois Plants (6 plants)(1)		Illinois	Coal/Oil/Gas	100%	5,918	5,918
	Homer City(1)		Pennsylvania	Coal	100%	1,884	1,884
Contracted Power Plants
Domestic
	Big 4 Projects
		Kern River(1)	California	Natural Gas	50%	300	150
		Midway-Sunset(1)	California	Natural Gas	50%	225	113
		Sycamore(1)	California	Natural Gas	50%	300	150
		Watson	California	Natural Gas	49%	385	189
	Westside Projects
		Coalinga(1)	California	Natural Gas	50%	38	19
		Mid-Set(1)	California	Natural Gas	50%	38	19
		Salinas River(1)	California	Natural Gas	50%	38	19
		Sargent Canyon(1)	California	Natural Gas	50%	38	19
	American Bituminous(1)		West Virginia	Waste Coal	50%	80	40
	March Point		Washington	Natural Gas	50%	140	70
	Sunrise(1)		California	Natural Gas	50%	572	286
	Huntington		New York	Biomass	38%	25	9
	Wind Projects
		San Juan Mesa(1)	New Mexico	Wind	75%	120	90
		Minnesota Wind Projects (7 plants)	Minnesota	Wind	50-99%	83	67
		Storm Lake	Iowa	Wind	100%	109	109
International
	Doga(1)		Turkey	Natural Gas	80%	180	144

		Total				10,473	9,295

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

A description of EME's larger power plants and major investments in energy projects is set forth below. In addition to the facilities and power plants that EME owns, EME uses the term "its" in regard to facilities and power plants that EME or an EME subsidiary operates under sale-leaseback arrangements.

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Illinois Plants

On December 15, 1999, Midwest Generation completed a transaction with Commonwealth Edison Company, or Commonwealth Edison, now a subsidiary of Exelon Corporation, to acquire the Illinois Plants. The Illinois Plants are located in the Mid-America Interconnected Network, which has transmission connections to the East Central Area Reliability Council and other regional markets.

The Illinois Plants include the following:

Operating Plant or Site		Location	Leased/ Owned	Fuel	Megawatts
Electric Generating Facilities
	Crawford Station	Chicago, Illinois	owned	coal	542
	Fisk Station	Chicago, Illinois	owned	coal	326
	Joliet Unit 6	Joliet, Illinois	owned	coal	290
	Joliet Units 7 and 8	Joliet, Illinois	leased	coal	1,044
	Powerton Station	Pekin, Illinois	leased	coal	1,538
	Waukegan Station	Waukegan, Illinois	owned	coal	781
	Will County Station	Romeoville, Illinois	owned	coal	1,092	(1)
Peaking Units
	Fisk	Chicago, Illinois	owned	oil/gas	197
	Waukegan	Waukegan, Illinois	owned	oil/gas	108

	Total				5,918

Other Plant or Site
	Collins Station(2)	Grundy County, Illinois
	Crawford peaker(3)	Chicago, Illinois
	Joliet peaker(4)	Joliet, Illinois
	Calumet peaker(4)	Chicago, Illinois
	Electric Junction peaker(4)	Aurora, Illinois
	Lombard peaker(4)	Lombard, Illinois
	Sabrooke peaker(4)	Rockford, Illinois

(1): Operations at Will County Station Units 1 and 2 (310 MW) were returned to service in late 2004 after being suspended since January 2003.
(2): All Collins Station units ceased operations and were decommissioned by December 31, 2004.
(3): Peaking units ceased operations as of April 21, 2005.
(4): Peaking units ceased operations as of December 31, 2004.

As part of the purchase of the Illinois Plants, EME assigned its right to purchase the Collins Station to third-party entities and Midwest Generation simultaneously entered into a long-term lease arrangement of the Collins Station with these third-party entities. In April 2004, Midwest Generation terminated the Collins Station lease through a negotiated transaction with the lease equity investor and received title to the Collins Station as part of the transaction. Following the lease termination, Midwest Generation permanently ceased operations at the Collins Station, effective September 30, 2004, and decommissioned the plant by December 31, 2004, and all units were permanently retired from service, disconnected from the grid, and rendered inoperable, with all operating permits surrendered.

In August 2000, EME completed sale-leaseback transactions involving its Powerton and Units 7 and 8 of its Joliet power facilities. EME sold these assets to third parties to obtain capital to repay corporate debt and entered into long-term leases of the facilities from these third parties to maintain

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control of the use of the power plants during the terms of the leases. See "Off-Balance Sheet Transactions" section in "Management's Discussion and Analysis of Financial Condition and Results of Operations—Liquidity and Capital Resources."

Illinois Power Sales

Energy generated at the Illinois Plants was historically sold under three power purchase agreements between Midwest Generation and Exelon Generation Company LLC, or Exelon Generation, under which Exelon Generation was obligated to make capacity payments for the plants under contract and energy payments for the energy produced by the Illinois Plants and taken by Exelon Generation. The power purchase agreements began on December 15, 1999, and all were terminated by December 31, 2004.

All the energy and capacity from the Illinois Plants is now sold under terms, including price and quantity, negotiated by Edison Mission Marketing & Trading, Inc., or EMMT, an EME subsidiary engaged in the power marketing and trading business, with customers through a combination of bilateral agreements, forward energy sales and spot market sales. Thus, EME is subject to market risks related to the price of energy and capacity from the Illinois Plants. Power generated at the Illinois Plants is generally sold into the PJM market. Capacity prices for merchant energy sales within PJM are, and are expected in the near term to remain at a level unlikely to generate significant revenue for Midwest Generation.

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

Transmission

Prior to May 1, 2004, sales of power produced by Midwest Generation required using transmission that had to be obtained from Commonwealth Edison. As discussed previously, the Illinois Plants are now dispatched into the broader PJM market. In addition, a number of other utilities in the region participate in the MISO, where there is a single rate for transmission within the MISO.

On November 18, 2004, the FERC issued an order eliminating regional through and out transmission rates in the region encompassed by PJM and the MISO. The effect of this order was to eliminate so-called rate pancaking between PJM and the MISO on a prospective basis. Rate pancaking occurs when energy must move through multiple, separately priced transmission systems to travel from its point of production to its point of delivery, and each transmission owner along the line charges separately for the use of its system. At the same time, the FERC also imposed a transitional revenue recovery mechanism which has created controversy and some continuing uncertainty as to its impact on transactions in the region. The mechanism required the filing of tariffs by PJM and the MISO imposing a "Seams Elimination Cost Adjustment," or SECA, to be in effect until May 1, 2006, to compensate the "new PJM companies"—AEP, Commonwealth Edison and Dayton Power & Light, among others—for lost revenues attributable to the elimination. On November 30, 2004, the FERC clarified that SECAs can be recovered for lost revenues associated with elimination of intra-RTO pancaked rates.

The response to the November 18 and November 30 orders from the parties potentially liable for the SECAs was strongly negative. Rehearings were sought by a broad range of interests that are opposed to the imposition of SECAs. Although both PJM and the MISO have made tariff filings with the FERC that purport to comply with the orders and eliminate through and out transmission rates as of December 1, 2004, numerous protests to such filings have been made, challenging SECAs on legal and equitable grounds and evidentiary hearings have been held by the FERC. Pending further orders of

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the FERC and/or the outcome of future hearings, under the provisions of the PJM tariff as filed, Midwest Generation is currently not subject to SECAs with respect to its sales of power within PJM. It is not possible, however, to predict the outcome of the hearings or to rule out the possibility that Midwest Generation could be ordered in the future to pay SECAs with respect to sales within PJM after December 1, 2004.

For further discussion of the market risks related to Midwest Generation's transmission service, see "Management's Discussion and Analysis of Financial Condition and Results of Operations—Market Risk Exposures."

Fuel Supply

Coal is used to fuel 5,613 MW of Midwest Generation's generating capacity. The coal is purchased from several suppliers that operate mines in the Southern Powder River Basin of Wyoming. The total volume of coal consumed annually is largely dependent on the amount of generation and ranges between 16 million to 20 million tons.

All coal is transported under long-term transportation agreements with the Union Pacific Railroad and various delivering carriers. As of December 31, 2005, Midwest Generation leased approximately 4,400 railcars to transport the coal from the mines to the generating stations and the leases have remaining terms that range from as short as 2 months up to 15 years, with options to extend the leases or purchase some railcars at the end of the lease terms. The coal is transported nearly 1,200 miles from the mines to the Illinois Plants.

Coal for the Fisk and Crawford Stations is first shipped by rail to the Will County Station where it is transferred from the railcars, blended as necessary to meet station specifications, and loaded into river barges. These barges are towed to the stations by an independent contractor under a transportation agreement with Midwest Generation.

Midwest Generation has approximately 305 MW of peaking capacity in the form of simple cycle combustion turbines at the Fisk and Waukegan Stations. These units are fueled with distillate fuel oils.

See "Management's Discussion and Analysis of Financial Condition and Results of Operations—Liquidity and Capital Resources—Contractual Obligations, Commitments and Contingencies," for additional discussion of contractual commitments related to Midwest Generation's fuel supply and coal transportation contracts.

Homer City Facilities

On March 18, 1999, EME completed a transaction with GPU, Inc., New York State Electric & Gas Corporation and their respective affiliates to acquire the Homer City facilities. These facilities consist of three coal-fired boilers and steam turbine-generator units (referred to as Units 1, 2 and 3 in this prospectus), one coal cleaning facility, water supply provided by a reservoir known as Two Lick Dam and associated support facilities in the mid-Atlantic region of the United States.

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

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Fuel Supply

Units 1 and 2 typically consume approximately 3.3 million to 3.5 million tons of mid-range sulfur coal per year. Approximately 90% or more of this coal is obtained under contracts with the remainder purchased in the spot market as needed. Two types of coal are purchased, ready to burn coal and raw coal. Ready to burn coal is of a quality that can be burned directly in Units 1 and 2, whereas the raw coal purchased for consumption by Units 1 and 2 must be cleaned in the Homer City coal cleaning facility, which has the capacity to clean up to 5 million tons of coal per year.

Unit 3 consumes approximately 2 million tons of coal per year. EME Homer City purchases the majority of its Unit 3 coal under contracts with the balance purchased in the spot market. A wet scrubber flue gas desulfurization system for Unit 3 enables this unit to burn less expensive, higher sulfur coal, while still meeting environmental standards for emission control.

In general, the coal purchased for all three units originates from mines that are within approximately 100 miles of the Homer City facilities. It is delivered to the station by truck and by rail.

See "Management's Discussion and Analysis of Financial Condition and Results of Operations—Liquidity and Capital Resources—Contractual Obligations, Commitments and Contingencies," for additional discussion of contractual commitments related to EME Homer City's fuel supply and coal transportation contracts.

Emission Allowances for the Homer City Facilities and Illinois Plants

Certain state and federal environmental laws require power plant operators to hold or obtain emission allowances equal, on an annual basis, to their plants' emissions of nitrogen oxide or sulfur dioxide. Emission allowances were acquired as part of the acquisition of the Homer City facilities and the Illinois Plants. Additional allowances are purchased by EME Homer City and Midwest Generation when operations make this necessary and are sold when they have more than needed for planned levels of operation.

See "Management's Discussion and Analysis of Financial Condition and Results of Operations—Liquidity and Capital Resources—Environmental Matters and Regulations" for a discussion of environmental regulations related to emissions. See "Management's Discussion and Analysis of Financial Condition and Results of Operations—Market Risk Exposures—Commodity Price Risk—Emission Allowances Price Risk" for a discussion of price risks related to the purchase or sale of emission allowances.

Big 4 Projects

EME owns partnership investments in Kern River Cogeneration Company, Midway-Sunset Cogeneration Company, Sycamore Cogeneration Company and Watson Cogeneration Company, as described below. These projects sell power to Southern California Edison Company, an affiliate of EME. Because these projects have similar economic characteristics and have been used, collectively, to obtain bond financing by Edison Mission Energy Funding Corp., a special purpose entity, EME views these projects collectively and refers to them as the Big 4 projects. See "Audited Consolidated Financial Statements of Edison Mission Energy—Notes to Consolidated Financial Statements—Note 2. Summary of Significant Accounting Policies," for discussion of EME's accounting for this entity.

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Kern River Cogeneration Plant

EME owns a 50% partnership interest in Kern River Cogeneration Company, which owns a 300 MW natural gas-fired cogeneration facility located near Bakersfield, California, which EME refers to as the Kern River project. Kern River Cogeneration's prior long-term power purchase agreement with Southern California Edison Company and its steam supply agreement with Texaco Exploration and Production Inc., or TEPI, a wholly owned subsidiary of Chevron Corporation, both expired on August 9, 2005. On August 10, 2005, Kern River Cogeneration entered into a Reformed Standard Offer No. 1 As-Available Energy and Capacity Power Purchase Agreement, or RSO#1, with Southern California Edison, which will remain in effect until August 10, 2010, unless terminated earlier by Kern River Cogeneration. On August 10, 2005, Kern River Cogeneration also entered into a new five-year Steam Purchase and Sale Agreement with Chevron North America Exploration and Production Company, a division of Chevron U.S.A., Inc. In addition, as of December 31, 2005, Kern River Cogeneration entered into a five-year bilateral agreement with Southern California Edison. This contract, which replaces the RSO#1 with Southern California Edison, became effective on June 1, 2006.

Midway-Sunset Cogeneration Plant

EME owns a 50% partnership interest in Midway-Sunset Cogeneration Company, which owns a 225 MW natural gas-fired cogeneration facility located near Taft, California, which EME refers to as the Midway-Sunset project. Midway-Sunset Cogeneration sells electricity to Southern California Edison, Aera Energy LLC, or Aera, and Pacific Gas & Electric Company under power purchase agreements that expire in 2009 and steam to Aera under a steam supply agreement that also expires in 2009.

Sycamore Cogeneration Plant

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

Watson Cogeneration Plant

EME owns a 49% partnership interest in Watson Cogeneration Company, which owns a 385 MW natural gas-fired cogeneration facility located in Carson, California, which EME refers to as the Watson project. Watson Cogeneration sells electricity to Southern California Edison and to BP West Coast Products LLC under power purchase agreements that expire in 2008 and steam to BP West Coast Products LLC under a steam supply agreement that also expires in 2008.

Other Power Plants

Sunrise Power Plant

EME owns a 50% interest in Sunrise Power Company, LLC, which owns a 572 MW natural gas-fired facility in Kern County, California, which EME refers to as the Sunrise project. Sunrise Power entered into a long-term power purchase agreement with the California Department of Water Resources in June 2001, which expires in 2012.

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March Point Cogeneration Plant

EME owns a 50% partnership interest in March Point Cogeneration Company, which owns a 140 MW natural gas-fired cogeneration facility located in Anacortes, Washington, which EME refers to as the March Point project. The March Point project consists of two phases. Phase 1 is an 80 MW gas turbine cogeneration facility and Phase 2 is a 60 MW gas turbine combined cycle facility. March Point Cogeneration sells electricity to Puget Sound Energy, Inc. under a power purchase agreement that expires in 2011 and steam to Equilon Enterprises, LLC under a steam supply agreement that also expires in 2011. During the third quarter of 2005, EME recorded a $55 million charge to impair fully its equity investment in the March Point project due to the adverse impact on cash flows from increases in long-term natural gas prices. For further discussion, see "Management's Discussion and Analysis of Financial Condition and Results of Operations—Results of Operations—Results of Continuing Operations—Earnings from Unconsolidated Affiliates."

Westside Power Plants

EME owns partnership investments in Coalinga Cogeneration Company, Mid-Set Cogeneration Company, Salinas River Cogeneration Company, and Sargent Canyon Cogeneration Company. Due to similar economic characteristics, EME views these projects collectively and refers to them as the Westside projects. EME owns a 50% partnership interest in each of the companies listed above and each company owns a 38 MW natural gas-fired cogeneration facility located in California. Three of these projects sell electricity to Pacific Gas & Electric Company under 15-year power purchase agreements which expire in 2007. Mid-Set Cogeneration's original power purchase agreement with Pacific Gas & Electric expired in May 2004. Mid-Set Cogeneration continues to sell electricity to Pacific Gas & Electric at "as available" rates under an agreement that expires on December 31, 2009.

American Bituminous Power Plant

EME owns a 50% interest in American Bituminous Power Partners, L.P., which owns an 80 MW waste coal facility located in Grant Town, West Virginia, which EME refers to as the Ambit project. Ambit sells electricity to Monongahela Power Company under a power purchase agreement that expires in 2035.

Huntington Biomass Project

EME owns a 38% limited partnership interest in Covanta Huntington LP, which owns a 25 MW waste-to-energy facility located near the Town of Huntington, New York, which EME refers to as the Huntington project. The project processes waste materials under a solid waste disposal services agreement with the Town of Huntington, which is set to expire in 2012 with an option to renew. The project also sells electricity to Long Island Power Authority under a 23-year power purchase agreement.

San Juan Mesa Wind Power Plant

EME owns a 75% interest in San Juan Mesa Wind Project LLC, which owns a 120 MW wind ranch located near Elida, New Mexico, which EME refers to as the San Juan Mesa wind project. The project uses wind to generate electricity from turbines, which is sold to Southwestern Public Service, a subsidiary of Xcel Energy, under a 20-year power purchase agreement. The San Juan Mesa wind project achieved commercial operation in December 2005.

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Minnesota Wind Projects

EME owns percentage interests of between 49.5% and 99% in 38 separate Minnesota limited liability companies, each of which owns a small wind-powered electric generation facility in Murray, Cottonwood, Lincoln and Pipestone counties in Minnesota, which EME refers to collectively as the Minnesota wind projects. The Minnesota wind projects collectively total approximately 83 MW. Each of the Minnesota wind projects sells electricity to either (i) Northern States Power Company under a 20-year or 30-year power purchase agreement or (ii) Interstate Power and Light Company under a 15-year power purchase agreement.

Storm Lake Wind Power Plant

EME owns a 100% interest in Storm Lake Power Partners I LLC, which owns a 109 MW wind ranch located near Alta, Iowa, which EME refers to as the Storm Lake wind project. The project sells electricity to Mid-American Energy Company under a 20-year power purchase agreement.

Doga Cogeneration Plant

EME owns an 80% interest in Doga Enerji, which owns a 180 MW natural gas-fired cogeneration plant near Istanbul, Turkey, which EME refers to as the Doga project. Doga Enerji sells electricity to Türkiye Elektrik Dagitim Anonim Sirketi, commonly known as TEDAS, under a power purchase agreement that expires in 2019.

Business Development

Wind Business Development

EME expects to make significant investments in wind projects during the next several years. Historically, wind projects have received federal subsidies in the form of production tax credits. In August 2005, production tax credits were made available for new wind projects placed in service by December 31, 2007 under EPAct 2005. EME has undertaken a number of key activities with respect to wind projects, including the following:

•: Completion in January 2006 of the purchase of development rights for the Wildorado wind project. This project started construction on April 24, 2006 and is scheduled for completion during April 2007, with total construction costs estimated to be $270 million. Upon completion, power from the project will be sold under a twenty-year power purchase agreement to Southwestern Public Service.
•: Securing during 2005 and 2006 a supply of 285 turbines for 538 MW of new wind projects which are expected to be developed and constructed by the end of 2007.
•: Completion in December 2005 of the acquisition of the San Juan Mesa wind project and subsequent sale of 25% of its ownership interest in the San Juan Mesa wind project to a third party.
•: Advancing during 2006 the development of a number of wind projects, including four projects totaling 181 MW that have been approved for investment, subject to completion of specific contractual or permitting arrangements.

In addition, in April 2006 EME received, as a capital contribution ownership interests in a 192 MW portfolio of wind projects (EME's share is 176 MW) located in Iowa and Minnesota. These projects were previously owned by EME's affiliate, Edison Capital. EME accounted for this acquisition

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at Edison Capital's historical cost as a transaction between entities under common control for a net book value of approximately $76 million.

Thermal Business Development

In June 2006, subsidiaries of EME and BP America Inc. formed Carson Hydrogen Power LLC for the development of a power project to be located in Carson, California. Carson Hydrogen is intended as an industrial gasification project that will integrate proven gasification, power generation and enhanced oil recovery technologies. In June 2006, the project submitted an application to the United States Department of Energy, or DOE, to qualify for gasification tax credits under EPAct 2005. Funding of tax credits is limited and, accordingly, there is no assurance that the project will be allocated tax credits. A decision from DOE is not expected until the end of 2006. In the meantime, Carson Hydrogen is conducting engineering studies required for project implementation.

Discontinued Operations

For a description of discontinued operations, see "Audited Consolidated Financial Statements of Edison Mission Energy—Notes to Consolidated Financial Statements—Note 8. Divestitures."

Price Risk Management and Trading Activities

EME's power marketing and trading subsidiary, EMMT, markets the energy and capacity of EME's merchant generating fleet and, in addition, trades electric power and energy and related commodity and financial products, including forwards, futures, options and swaps. EMMT segregates its marketing and trading activities into two categories:

•: Marketing and Fuel Management—EMMT engages in the sale of electricity and purchase of fuels (other than coal) through intercompany contracts with EME's subsidiaries that own or lease the Illinois Plants and the Homer City facilities. The objective of these activities is to sell the output of the power plants on a forward basis, thereby increasing the predictability of earnings and cash flows. EMMT also conducts risk management activities to manage the price risk associated with the purchase of fuels, including natural gas and fuel oil. Transactions entered into related to marketing and fuel management activities are designated separately from EMMT's trading activities and are recorded in what EMMT calls its hedge book.
•: Trading—As part of its trading activities, EMMT seeks to generate profit from the volatility of the price of electricity, fuels and transmission by buying and selling contracts for their sale or provision, as the case may be, in wholesale markets under limitations approved by EME's risk management committee. EMMT records these transactions in what it calls its proprietary book.

In conducting EME's price risk management and trading activities, EMMT contracts with a number of utilities, energy companies and financial institutions. 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 to another buyer at a lower price or having to purchase the contracted product from another supplier at a higher price if the non-performing counterparty were unable to pay the resulting liquidated damages owed to EME. Further, EME would be exposed to the risk of non-payment of accounts receivable accrued for products delivered prior to the time such counterparty defaulted.

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

EME's merchant power plants and energy trading activities expose EME to commodity price risks. Commodity price risks are actively monitored by EME's risk management committee to ensure compliance with EME's risk management policies. Policies are in place which define risk tolerances, and procedures exist which allow for monitoring of all commitments and positions with regular reviews by the risk management committee. EME uses "value at risk" to identify, measure, monitor and control its overall market risk exposure in respect of its Illinois Plants, its Homer City facilities and its proprietary positions. The use of value at risk allows management to aggregate overall commodity risk, compare risk on a consistent basis and identify 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 reliance on a single risk measurement tool, EME supplements this approach with the use of stress testing and worst-case scenario analysis for key risk factors, as well as stop loss limits and counterparty credit exposure limits. Despite this, there can be no assurance that all risks have been accurately identified, measured and/or mitigated.

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

Significant Customer

EME derived a significant source of its operating revenues from electric power sold into the PJM market from the Homer City facilities in the past three fiscal years and from the Illinois Plants in 2005 and 2004. Sales into the PJM pool accounted for approximately 69%, 23% and 18% of EME's consolidated operating revenues for the years ended December 31, 2005, 2004 and 2003, respectively. In 2004 and 2003, EME also derived a significant source of its revenues from the sale of energy and capacity generated at the Illinois Plants to Exelon Generation primarily under three power purchase agreements. These power purchase agreements had all expired by the end of 2004. Exelon Generation accounted for approximately 35% and 40% of EME's consolidated operating revenues for the years ended December 31, 2004 and 2003, respectively.

For the year ended December 31, 2004, approximately 15% of EME's consolidated operating revenues generated at the Homer City facilities and Illinois Plants was from sales to BP Energy Company, a third-party customer.

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Insurance

EME maintains insurance policies consistent with those normally carried by companies engaged in similar business and owning similar properties. EME's insurance program includes all-risk property insurance, including business interruption, covering real and personal property, including losses from boilers, machinery breakdowns, and the perils of earthquake and flood, subject to specific sublimits. EME also carries general liability insurance covering liabilities to third parties for bodily injury or property damage resulting from operations, automobile liability insurance and excess liability insurance. Limits and deductibles in respect of these insurance policies are comparable to those carried by other electric generating facilities of similar size. However, no assurance can be given that EME's insurance will be adequate to cover all losses.

The Homer City property insurance program currently covers losses up to $1 billion. Under the terms of the participation agreements entered into on December 7, 2001 as part of the sale-leaseback transaction of the Homer City facilities, EME Homer City is required to maintain specified minimum insurance coverages if and to the extent that such insurance is available on a commercially reasonable basis. Although the insurance covering the Homer City facilities is comparable to insurance coverages normally carried by companies engaged in similar businesses, and owning similar properties, the insurance coverages that are in place do not meet the minimum insurance coverages required under the participation agreements. Due to the current market environment, the minimum insurance coverage is not commercially available at reasonable prices. EME Homer City has obtained a waiver under the participation agreements which permits it to maintain its current insurance coverage through June 1, 2007.

Seasonality

Regulatory Matters

General

EME's operations are subject to extensive regulation by governmental agencies. EME's operating projects are subject to energy, environmental and other governmental laws and regulations at the federal, state and local levels in connection with the ownership and operation of its projects, and the use of electric energy, capacity and related products, including ancillary services from its projects. Federal laws and regulations govern, among other things, transactions by and with purchasers of power, including utility companies, the operation of a power plant and the ownership of a power plant. Under limited circumstances where exclusive federal jurisdiction is not applicable or specific exemptions or waivers from state or federal laws or regulations are otherwise unavailable, federal and/or state utility regulatory commissions may have broad jurisdiction over non-utility owned electric power plants. Energy-producing projects are also subject to federal, state and local laws and regulations that govern

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the geographical location, zoning, land use and operation of a project. Federal, state and local environmental requirements generally require that a wide variety of permits and other approvals be obtained before the commencement of construction or operation of an energy-producing facility and that the facility then operate in compliance with these permits and approvals.

EME is subject to a varied and complex body of laws and regulations that are in a state of flux. Intricate and changing environmental and other regulatory requirements could necessitate substantial expenditures and could create a significant risk of expensive delays or significant loss of value in a project if it were to become unable to function as planned due to changing requirements or local opposition.

PJM Reliability Pricing Model

On August 31, 2005, PJM filed under sections 205 and 206 of the Federal Power Act a proposal for a reliability pricing model, or RPM, to replace its existing capacity construct. The proposal offers RPM as a new capacity construct to address the deficiencies in PJM's current structure in a comprehensive and integrated manner. On April 20, 2006, the FERC issued an Initial Order on RPM, finding that as a result of a combination of factors, PJM's existing capacity construct is unjust and unreasonable as a long-term capacity solution, because it fails to set prices adequate to ensure energy resources to meet its reliability responsibilities. Although the FERC did not find that the RPM proposal, as filed by PJM, is the just and reasonable replacement for the current capacity construct because some elements of the proposal need further development and elaboration, it did find that certain elements of the RPM proposal, with some adjustment and clarification, may form the basis for a just and reasonable capacity market. Accordingly, in the order the FERC provided guidance on PJM's RPM proposal, as well as other features that need to be included in a just and reasonable capacity market, and established further proceedings to resolve these issues. At this time, it is not possible to predict the outcome of those proceedings or their prospective effect on the nature and operation of the PJM markets.

MISO Revenue Sufficiency Guarantee Charges

On April 25, 2006, the FERC issued an order regarding the MISO's "Revenue Sufficiency Guarantee" charges, or RSG charges. The MISO's business practice manuals and other instructions to market participants have stated, since the implementation of market operations in April 1, 2005, that RSG charges will not be imposed on offers to supply power not supported by actual generation (also known as virtual supply offers). However, some market participants raised questions about the language of the MISO's tariff concerning that issue and in October 2005, the MISO submitted to the FERC proposed tariff revisions clarifying its tariff to reflect its business practices with respect to RSG charges, and filed corrected tariff sheets exempting virtual supply from RSG charges. In its April 25 decision, the FERC interpreted the MISO's tariff to require that virtual supply offers must be included in the calculation of the RSG charges and that to the extent that the MISO did not charge virtual supply offers for RSG charges, it violated the terms of its tariff. The FERC order then proceeded to require the MISO to recalculate the RSG charges back to April 1, 2005, and to make refunds to customers, with interest, reflecting the recalculated charges. In order to make such refunds, it is likely that the MISO will attempt to impose retroactively RSG charges on those who submitted virtual supply offers during the recalculation period. EMMT made virtual supply offers in the MISO during this period on which no RSG charges were imposed, and thus may be subject to a claim for refunds from the MISO (which claim will be contested by EMMT). Because calculation of any claimed liability for refunds depends on information not currently available to it, EMMT cannot reasonably estimate a range of loss related to this matter. In addition, the FERC's April 25 order has been challenged by the MISO and other parties, including EMMT, and as the FERC has issued an extension of time to comply with the

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requirements of the order until after the date of issuance of an order on rehearing, the eventual outcome of these proceedings is unclear. The FERC order also requires the MISO to modify its tariff on a prospective basis to impose RSG charges on virtual supply offers. At this time, it is not possible to predict how the prospective effect of the order will affect the nature and operation of the MISO markets.

FERC Order Regarding PJM Marginal Losses

On May 1, 2006, the FERC issued an order in response to a complaint filed by Pepco Holdings, Inc. against PJM regarding marginal losses for transmission. The FERC concluded that PJM has violated its tariff by not implementing marginal losses and further directed PJM to implement marginal losses by October 2, 2006. Implementation of marginal losses will adjust the algorithm that calculates locational marginal prices to include a marginal loss component in addition to the already included congestion component. This may have an adverse impact on sellers in the Western PJM and Northern Illinois regions. On June 19, 2006, the FERC issued an order delaying implementation of marginal losses in PJM until June 1, 2007, and at this time, it is not possible to predict how the prospective effect of the order will affect the prices at which EME Homer City and Midwest Generation will be able to sell their power.

U.S. Federal Energy Regulation

The FERC has ratemaking jurisdiction and other authority with respect to interstate wholesale sales and transmission of electric energy (other than transmission that is "bundled" with retail sales) under the Federal Power Act and with respect to certain interstate sales, transportation and storage of natural gas under the Natural Gas Act of 1938. Prior to February 8, 2006, the Securities and Exchange Commission had regulatory powers with respect to upstream owners of electric and natural gas utilities under the Public Utility Holding Company Act of 1935, or PUHCA 1935, which was repealed as of that date by EPAct 2005. The enactment of PURPA and the adoption of regulations under PURPA by the FERC provided incentives for the development of cogeneration facilities and small power production facilities using alternative or renewable fuels by establishing certain exemptions from the Federal Power Act and PUHCA 1935 for the owners of qualifying facilities. The passage of the Energy Policy Act in 1992 further encouraged independent power production by providing additional exemptions from PUHCA 1935 for exempt wholesale generators and foreign utility companies.

The Energy Policy Act of 2005

A comprehensive energy bill was passed by the U.S. House and Senate in July 2005 and was signed by President Bush on August 8, 2005. Known as "EPAct 2005," this comprehensive legislation includes provisions for the repeal of PUHCA 1935 and amendments to PURPA, for merger review reform, for the introduction of new regulations regarding "Transmission Operation Improvements," for transmission rate reform, for incentives for various generation technologies and for the extension through December 31, 2007 of production tax credits for wind and other specified types of generation.

The FERC has finalized rules to implement the congressionally mandated repeal of PUHCA 1935, effective February 8, 2006, and enactment of the Public Utility Holding Company Act of 2005, or PUHCA 2005. The repeal of PUHCA 1935 and its replacement by PUHCA 2005 effectively eliminates many of the restrictions on outside investment in the electricity industry, investment by and transactions between utilities, and geographic constraints on utility systems. PUHCA 1935 repeal is expected to enable investment in utility systems by private equity funds, financial institutions, foreign utility companies, and other non-utility companies without the burden of registration as a "public utility holding company." It also eliminates limits on investment in non-utility operations companies that were

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registered holding companies under PUHCA 1935, subject to other applicable regulatory limitations, as well as geographic limits on potential utility combinations. PUHCA 2005 is primarily a "books and records access" statute and does not give the FERC any new substantive authority under the Federal Power Act or Natural Gas Act. The FERC has also issued final rules to implement the electric company merger and acquisition provisions of EPAct 2005.

Federal Power Act

The Federal Power Act grants the FERC exclusive jurisdiction over the rates, terms and conditions of wholesale sales of electricity and transmission services in interstate commerce (other than transmission that is "bundled" with retail sales), including ongoing, as well as initial, rate jurisdiction. This jurisdiction allows the FERC to revoke or modify previously approved rates after notice and opportunity for hearing. These rates may be based on a cost-of-service approach or, in geographic and product markets determined by the FERC to be workably competitive, may be market based. Most qualifying facilities, as that term is defined in PURPA, are exempt from the ratemaking and several other provisions of the Federal Power Act. Exempt wholesale generators certified in accordance with the FERC's rules under PUHCA 2005 and other non-qualifying facility independent power projects are subject to the Federal Power Act and to the FERC's ratemaking jurisdiction thereunder, but the FERC typically grants exempt wholesale generators the authority to charge market-based rates to purchasers which are not affiliated electric utility companies as long as the absence of market power is shown. In addition, the Federal Power Act grants the FERC jurisdiction over the sale or transfer of jurisdictional facilities, including wholesale power sales contracts and, after EPAct 2005, generation facilities, and in some cases, jurisdiction over the issuance of securities or the assumption of specified liabilities and some interlocking directorates. In granting authority to make sales at market-based rates, the FERC typically also grants blanket approval for the issuance of securities and partial waiver of the restrictions on interlocking directorates.

As of December 31, 2005, a number of EME's operating projects, including the Homer City facilities and the Illinois Plants, were subject to the FERC ratemaking regulation under the Federal Power Act. EME's future domestic non-qualifying facility independent power projects will also be subject to the FERC jurisdiction on rates.

Public Utility Regulatory Policies Act of 1978

PURPA provides two primary benefits to qualifying facilities. First, all cogeneration facilities that are qualifying facilities are exempt from certain provisions of the Federal Power Act and regulations of the FERC thereunder. Second, the FERC regulations promulgated under PURPA require that electric utilities purchase electricity generated by qualifying facilities at a price based on the purchasing utility's avoided cost (unless, pursuant to EPAct 2005, the FERC determines that the relevant market meets certain conditions for competitive, nondiscriminatory access), and that the utilities sell back up power to the qualifying facility on a nondiscriminatory basis. The FERC's regulations also permit qualifying facilities and utilities to negotiate agreements for utility purchases of power at prices different from the utility's avoided costs. While it had been common for utilities to enter into long-term contracts with qualifying facilities in order, among other things, to facilitate project financing of independent power facilities and to reflect the deferral by the utility of capital costs for new plant additions, increasing competition and the development of new power markets have resulted in a trend toward shorter term power contracts that would place greater risk on the project owner.

If one of the projects in which EME has an interest were to lose its status as a qualifying cogeneration facility, the project would no longer be entitled to the qualifying facility-related exemptions from regulation. As a result, the project could become subject to rate regulation by the

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FERC under the Federal Power Act and additional state regulation. Loss of qualifying facility status could also trigger defaults under covenants to maintain qualifying facility status in the project's power sales agreements, steam sales agreements and financing agreements and result in termination, penalties or acceleration of indebtedness under such agreements. If a power purchaser were to cease taking and paying for electricity or were to seek to obtain refunds of past amounts paid because of the loss of qualifying facility status, EME cannot provide assurance that the costs incurred in connection with the project could be recovered through sales to other purchasers. Moreover, EME's business and financial condition could be adversely affected if regulations or legislation were modified or enacted that changed the standards applicable to EME's facilities for maintaining qualifying facility status or that eliminated or reduced the benefits and exemptions currently enjoyed by EME's qualifying facilities. Loss of qualifying facility status on a retroactive basis could lead to, among other things, fines and penalties, or claims by a utility customer for the refund of payments previously made.

EPAct 2005 made several important amendments to PURPA, including the elimination of qualifying facility ownership restrictions, elimination of the requirement that electric utilities enter into new contracts to purchase electricity from qualifying facilities that have access to wholesale power markets that meet specified criteria or sell energy to existing qualifying facilities in states where there is retail electricity competition and no obligation under state law to make power sales, the granting of new authority to the FERC to ensure recovery by electric utilities of all prudently incurred costs associated with purchases of energy and capacity from qualifying facilities, and certain obligations upon electric utilities for interconnection and metering for qualifying facilities. The FERC has initiated several proceedings to promulgate rules and regulations to implement the mandates of EPAct 2005 with respect to PURPA, and EME is continuing to evaluate the effect of the legislation and proposed regulations on its business activities.

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

Natural Gas Act

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

Transmission of Wholesale Power

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

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The Energy Policy Act of 1992 laid the groundwork for a competitive wholesale market for electricity by, among other things, expanding the FERC's authority to order electric utilities to transmit third-party electricity over their transmission lines, thus allowing qualifying facilities under PURPA, power marketers and those qualifying as exempt wholesale generators under PUHCA 1935 to more effectively compete in the wholesale market.

In 1996, the FERC issued Order No. 888, also known as the Open Access Rules, which require utilities to offer eligible wholesale transmission customers open access on utility transmission lines on a comparable basis to the utilities' own use of the lines and directed jurisdictional public utilities that control a substantial portion of the nation's electric transmission networks to file uniform, non-discriminatory open access tariffs containing the terms and conditions under which they would provide such open access transmission service. The FERC subsequently issued Order Nos. 888-A, 888-B and 888-C to clarify the terms that jurisdictional transmitting utilities are required to include in their open access transmission tariffs and Order No. 889, which required those transmitting utilities to abide by specified standards of conduct when using their own transmission systems to make wholesale sales of power, and to post specified transmission information, including information about transmission requests and availability, on a publicly available computer bulletin board.

On September 16, 2005, the FERC issued a Notice of Inquiry, inviting comments on (1) whether reforms are needed to the Order No. 888 pro forma open access transmission tariff and the open access transmission tariffs of public utilities to ensure that services thereunder are just, reasonable and not unduly discriminatory or preferential; (2) the implementation of the newly established section 211A of the Federal Power Act concerning the provision of open access transmission service by unregulated transmitting utilities; and (3) section 1233 of EPAct 2005, which defines the native load service obligation.

On May 19, 2006, the FERC issued a Notice of Proposed Rulemaking, in which it proposed amendments to its regulations adopted in Order No. 888, and to the pro forma open access transmission tariff, to ensure that transmission services are provided on a basis that is just, reasonable, and not unduly discriminatory or preferential. While the FERC reaffirmed many of the core elements of Order No. 888 and does not attempt to create new market structures through this rulemaking, it proposes to increase the clarity and transparency of the rules applicable to the planning and use of the transmission system and address ambiguities and the lack of sufficient detail in several important areas of the pro forma open access transmission tariff. Numerous parties filed comments in response to the Notice, and as the matter is currently pending before the FERC, the final outcome remains unclear.

See "Overview of Facilities—Transmission" for further discussion of developments and other transmission issues affecting the Illinois Plants.

Environmental Matters and Regulations

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

Employees

At December 31, 2005, EME and its subsidiaries employed 1,745 people, including:

•: approximately 752 employees at the Illinois Plants covered by a collective bargaining agreement governing wages, certain benefits and working conditions. This collective bargaining agreement

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expired on December 31, 2005. A new agreement was reached with the union representing the Illinois employees, with an expiration date of December 31, 2009. Midwest Generation also has a separate collective bargaining agreement governing retirement, health care, disability and insurance benefits that expires on June 15, 2006; and

•: approximately 190 employees at the Homer City facilities covered by a collective bargaining agreement governing wages, benefits and working conditions. This collective bargaining agreement expires on December 31, 2006.

EME's Relationship with Certain Affiliated Companies

EME is an indirect subsidiary of Edison International. Edison International is a holding company. Edison International is also the corporate parent of Southern California Edison Company, an electric utility that serves customers in California.

MEHC

On June 8, 2001, Edison International created MEHC as a wholly owned indirect subsidiary. MEHC's principal asset is EME's common stock. During 2001, MEHC issued $800 million of 13.50% senior secured notes due 2008. The senior secured notes are secured by a first priority security interest in EME's common stock. Any foreclosure on the pledge of EME's common stock by the holders of the senior secured notes could result in a change in control of EME. A change in control of EME could trigger an obligation of Midwest Generation to repurchase its outstanding senior secured notes at 101% of the aggregate principal amount of notes repurchased, plus accrued and unpaid interest and liquidated damages, if any, and could result in an event of default under Midwest Generation's secured term loan facility. This relationship is discussed further in "Audited Consolidated Financial Statements of Edison Mission Energy—Notes to Consolidated Financial Statements—Note 1. General—Organization."

Properties

EME leases its principal office in Irvine, California. The office lease is for approximately 60,000 square feet and expires on December 31, 2010. EME also leases office space in Chicago, Illinois; Chantilly, Virginia; Boston, Massachusetts; and Washington D.C. The Chicago lease is for approximately 41,000 square feet and expires on December 31, 2014. The Chantilly lease is for approximately 30,000 square feet and expires on March 31, 2010 and has been subleased since May 2001. The Boston lease is for approximately 37,000 square feet and expires on July 31, 2007. The Washington D.C. lease is immaterial.

The following table shows, as of December 31, 2005, the material properties owned or leased by EME's subsidiaries and affiliates. Each property represents at least five percent of EME's income before tax or is one in which EME has an investment balance greater than $50 million. Most of these properties are subject to mortgages or other liens or encumbrances granted to the lenders providing financing for the plant or project.

Plant	Location	Interest In Land	Plant Description
Homer City	Pittsburgh, Pennsylvania	Owned	Coal-fired generation facility
Illinois Plants	Northeast Illinois	Owned	Coal, oil/gas-fired generation facilities
Kern River	Oildale, California	Leased	Natural gas-turbine cogeneration facility
Midway-Sunset	Fellows, California	Leased	Natural gas-turbine cogeneration facility
Sunrise	Fellows, California	Leased	Combined cycle generation facility
Sycamore	Oildale, California	Leased	Natural gas-turbine cogeneration facility
Watson	Carson, California	Leased	Natural gas-turbine cogeneration facility

Legal Proceedings

No material legal proceedings are presently pending against EME.

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MANAGEMENT

Directors and Executive Officers

Our directors are elected by, and serve until their successors are elected by, our sole stockholder. Our officers are elected from time to time by the board of directors and hold office at the discretion of the board of directors. Set forth below are our current directors and executive officers and their ages and positions with us as of September 25, 2006.

Name	Age	Position
Theodore F. Craver, Jr.	55	Director, President and Chief Executive Officer
Thomas R. McDaniel	57	Director
Jacob A. Bouknight, Jr.	62	Director
W. James Scilacci	51	Senior Vice President and Chief Financial Officer
Raymond W. Vickers	63	Senior Vice President and General Counsel
Guy F. Gorney	51	Senior Vice President
Paul Jacob	45	Senior Vice President
John P. Finneran, Jr.	47	Vice President
Gerald P. Loughman	50	Vice President
Jenene J. Wilson	63	Vice President

Business Experience

Described below are the principal occupations and business activities of our directors and executive officers for the past five years, in addition to their positions indicated above.

Mr. Craver has been a director of Edison Mission Energy since January 2001 and chairman of the board, president and chief executive officer since January 2005. Mr. Craver has been chief executive officer of Edison Capital since January 2005. From January 2002 until January 2005, Mr. Craver was executive vice president of Edison International. Mr. Craver was senior vice president from January 2000 to December 2001, and was chief financial officer and treasurer of Edison International from January 2000 until January 2005. Mr. Craver also serves as a director of Health Net and a Trustee of the Autry National Center.

Mr. McDaniel has been director of Edison Mission Energy since August 2002. Mr. McDaniel has been executive vice president, chief financial officer and treasurer of Edison International since January 2005. Mr. McDaniel has served as director of Edison Capital since September 1987. From August 2002 until January 2005, Mr. McDaniel was president and chief executive officer of Edison Mission Energy, and from January 2003 until January 2005, served as chairman of the board. From September 1987 until January 2005, Mr. McDaniel served as chief executive officer and director of Edison Capital, in addition to serving as president of Edison Capital from September 1987 to July 2002.

Mr. Bouknight has been director of Edison Mission Energy since July 2005. Mr. Bouknight has been executive vice president and general counsel of Edison International since July 2005. Prior to joining Edison International, Mr. Bouknight was a partner at the law firm of Steptoe & Johnson LLP from December 1994 to July 2005.

Mr. Scilacci has been senior vice president and chief financial officer of Mission Energy Holding Company and Edison Mission Energy since March 2005. Mr. Scilacci was senior vice president and chief financial officer of Southern California Edison Company from January 2003 to March 2005 and

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vice president and chief financial officer of Southern California Edison Company from January 2000 to December 2002.

Mr. Vickers has been senior vice president and general counsel of Edison Mission Energy since March 1999.

Mr. Gorney has been senior vice president of Coal Generation for Edison Mission Energy since March 2006, president of Midwest Generation, LLC since May 2005, and president of Midwest Generation EME, LLC since June 2005. Mr. Gorney was vice president of Operations Planning & Fuels for Edison Mission Energy from August 2000 to February 2006, vice president of Operations, Maintenance & Fuels for the Americas Region from January 2002 to January 2005, and vice president of Operations Planning from August 2000 to January 2002.

Mr. Jacob has been senior vice president of Marketing and Trading for Edison Mission Energy since March 2006 and president of Edison Mission Marketing & Trading since February 2001. Mr. Jacob was vice president of Edison Mission Energy from September 2000 to February 2006.

Mr. Finneran has been vice president of Business Management for Edison Mission Energy since April 2005. Mr. Finneran was vice president of Edison Mission Energy and vice president Finance, Americas from July 2002 to April 2005. Mr. Finneran was vice president of Edison Mission Energy and regional vice president of Finance, Americas Region from September 1999 to July 2002.

Mr. Loughman has been vice president of Development for Edison Mission Energy since March 2005. Mr. Loughman was director of Business Planning & Development for Southern California Edison Company from January 2003 to March 2005, and was vice president for Business Development, Americas Region for Edison Mission Energy from July 2000 to January 2003.

Ms. Wilson has been vice president of Human Resources for Edison Mission Energy since December 2001. Prior to joining Edison Mission Energy, Ms. Wilson served as vice president of Human Resources at MySmart Solutions since October 2000.

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EXECUTIVE COMPENSATION

SUMMARY COMPENSATION TABLE

Except as set forth below, the following table presents information regarding compensation paid by EME to each of the named executive officers during the years 2005, 2004 and 2003 for services rendered by such persons in all capacities to EME and its subsidiaries.

					Long-Term Compensation
		Annual Compensation			Awards	Payouts
(a)	(b)	(c)	(d)	(e)	(f)	(g)	(h)
Name and Principal Position(1)	Year	Salary ($)	Bonus ($)	Other Annual Compensation(5) ($)	Securities Underlying Options(6) #	LTIP Payouts(7) ($)	All Other Compensation(8) ($)
Theodore F. Craver, Jr.(2) Chairman of the Board, President and Chief Executive Officer	2005	570,000	798,000	20,108	172,644	—	175,605
Raymond W. Vickers Senior Vice President and General Counsel	2005 2004 2003	445,000 431,000 415,000	417,000 475,000 408,000	10,729 6,122 5,468	35,772 49,127 42,813	1,373,339 574,568 478,538	94,399 82,458 57,564
Paul Jacob(3) Vice President	2005 2004 2003	324,900 310,650 298,700	325,000 272,000 267,000	3,822 13,975 1,594	21,547 29,212 23,112	422,636 163,540 34,819	32,639 31,602 12,500
W. James Scilacci(4) Senior Vice President and Chief Financial Officer	2005	245,454	243,623	12,116	24,783	—	34,823
John P. Finneran, Jr. Vice President	2005 2004 2003	279,000 270,000 260,000	259,000 249,000 233,000	200 12,675 1,172	18,503 25,390 22,129	609,467 247,754 172,874	49,897 37,005 27,213

(1): The principal positions shown are at December 31, 2005.
(2): Effective January 1, 2005, Mr. Craver was elected chairman of the board, president and chief executive officer of EME. Compensation shown for Mr. Craver is that attributable to his EME employment.
(3): Effective March 1, 2006, Mr. Jacob was elected senior vice president.
(4): Effective March 17, 2005, Mr. Scilacci was elected senior vice president and chief financial officer of EME. Compensation shown for Mr. Scilacci is that attributable to his EME employment.
(5): The amounts shown in column (e) represent the amount of reimbursed taxes. Other perquisites provided to each of the named executive officers do not exceed the lesser of $50,000 or 10% of the named executive officer's annual salary plus bonus for the applicable year.
(6): No stock appreciation rights have been awarded.
(7): The amounts shown in column (g) for 2005 include (i) payment of the 2002 Edison International performance shares, and (ii) the value of the shares of Edison International Common Stock issued in payment of 25% of the deferred stock units awarded in 2001 pursuant to the Edison International Stock Option Retention Exchange Offer.
(8): The amounts shown in column (h) for 2005 include plan contributions (contributions to the Edison 401(k) Savings Plan and a supplemental plan for eligible participants who are affected by 401(k) Plan participation limits imposed on higher paid individuals by federal tax law), preferential interest (that portion of interest that is considered under the Securities and

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Exchange Commission rules to be at above-market rates) accrued on deferred compensation and survivor benefits in the following amounts:

Name	Plan Contributions ($)	Preferential Interest ($)	Survivor Benefits* ($)
Theodore F. Craver, Jr.	29,700	119,292	26,613
Raymond W. Vickers	53,012	15,397	25,990
Paul Jacob	32,286	343	10
W. James Scilacci	17,595	14,494	2,734
John P. Finneran, Jr.	30,568	18,356	973

*: Includes the 2005 cost of survivor benefits under the Survivor Benefit Plan, Executive Deferred Compensation Plan, 1985 Deferred Compensation Plan, Survivor Income Continuation Plan, and Supplemental Survivor Income/Retirement Income Plan.

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OPTION GRANTS IN 2005

The following table presents information regarding Edison International nonqualified stock options granted during 2005 to the named executive officers listed in the Summary Compensation Table above, pursuant to the Edison International Equity Compensation Plan or Edison International 2000 Equity Plan. No stock appreciation rights were granted to any participant during 2005.

Individual Grants					Grant Date Value
(a)	(b)	(c)	(d)	(e)	(f)
Name	Number of Securities Underlying Options Granted(1)(2) (#)	Percent of Total Options Granted to Employees in Fiscal Year (%)	Exercise or Base Price ($ /Sh)	Expiration Date	Grant Date Present Value(3) ($)
Theodore F. Craver, Jr.	100,644 72,000	14 10	31.935 32.710	01/02/2015 01/02/2015	939,009 688,320
Raymond W. Vickers	35,772	5	31.935	01/02/2015	333,753
Paul Jacob	21,547	3	31.935	01/02/2015	201,034
W. James Scilacci	24,783	3	31.935	01/02/2015	231,225
John P. Finneran, Jr.	18,503	3	31.935	01/02/2015	172,633

(1)

Seventy-five percent of each named executive officer's annual long-term incentive compensation for 2005 was awarded in the form of Edison International nonqualified stock options and dividend equivalents. The remaining portion of the named executive officer's long-term incentive compensation for 2005 was awarded in the form of Edison International performance shares as set forth below in the table entitled "Long-Term Incentive Plan Awards in Last Fiscal Year." Each Edison International stock option granted in 2005 may be exercised to purchase one share of Edison International Common Stock at an exercise price equal to the fair market value of the underlying common stock on the date the Edison International stock option was granted. Edison International will substitute cash awards to the extent necessary to pay required tax withholding or any governmental levies.

(2)

The Edison International stock options and dividend equivalents are subject to a four-year vesting period with one-fourth of the total award vesting and becoming exercisable on January 2, 2006, January 2, 2007, January 2, 2008 and January 2, 2009. The awards of Mr. Craver are transferable to a spouse, child or grandchild. If an award holder terminates employment after attaining age 65, after attaining age 55 with five years of service during the vesting period, or after such earlier date that qualifies the holder for retirement under any company retirement plan, the Edison International stock options will continue to vest as scheduled and be exercisable for the full original term, subject to pro rated adjustment for such separations from service occurring within the first year following the grant date. If an award holder terminates employment because of death or permanent and total disability during the vesting period, all unvested Edison International stock options and dividend equivalents will immediately vest and the Edison International stock options may be exercised pursuant to their original terms by the award holder or beneficiary. If an award holder is terminated involuntarily not for cause, one additional year of vesting credit will be applied and the Edison International stock options and dividend equivalents will vest on a pro rata basis. If the award holder is not retirement-eligible, he or she will then have one year to exercise the vested Edison International stock options before they are forfeited, or until the end of the original term if earlier. If employment is terminated other than as described above, unvested Edison International stock options and dividend equivalents are forfeited. Edison International stock options which had vested as of the prior anniversary date of the grant are also forfeited unless exercised within 180 days of the date of termination.

Dividend equivalents in the amount of dividends that would have been paid on the number of shares of common stock covered by the corresponding Edison International stock option will be credited to an account established on behalf of the holder to the extent dividends are declared on Edison International Common Stock during the first five years of the Edison International stock option term. Dividend equivalents accumulate without interest. Dividend equivalents are paid in cash as soon as administratively practical after the vesting dates or, if later, in January after the dividend equivalents are credited, although Edison International has discretion to pay dividend equivalents in shares of Edison International Common Stock. No further dividend equivalents will accrue as to any Edison International stock option once that Edison International stock option is exercised, expires, or otherwise terminates.

Appropriate and proportionate adjustments may be made by the Edison International Compensation and Executive Personnel Committee to outstanding Edison International stock options and dividend equivalents to reflect any impact resulting from various corporate events such as reorganizations, mergers and stock splits. If Edison International is not the

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surviving corporation after such a transaction, all Edison International stock options and dividend equivalents then outstanding will vest and be exercisable for a period of two years if Edison International Common Stock remains outstanding, or until the end of their respective terms if earlier. If Edison International Common Stock does not remain outstanding following such a transaction, and the Edison International stock options and dividend equivalents are not assumed by a successor entity, unexercised Edison International stock options and dividend equivalents will be settled in cash.

The Edison International Compensation and Executive Personnel Committee administers the Equity Compensation Plan as to the named executive officers and has sole discretion to determine all terms and conditions of any award, subject to plan limits. It may substitute cash that is equivalent in value to the Edison International stock options and dividend equivalents and, with the consent of the executive, may amend the terms of any award agreement, including the post-termination term, and the vesting schedule.

(3): The grant date value of each Edison International stock option awarded in January 2005 to the named executive officers was calculated to be $9.33 per option share using the Black-Scholes stock option pricing model. In making this calculation, it was assumed that the exercise period was ten years, the volatility rate was 19.61%, the risk-free rate of return was 4.21%, the average dividend yield was 3.13% and the stock price and exercise price were $31.935. The grant date value of each Edison International stock option awarded in February 2005 to the named executive officers was calculated to be $9.56 per option share using the Black-Scholes stock option pricing model. In making this calculation, it was assumed that the exercise period was ten years, the volatility rate was 19.64%, the risk-free rate of return was 4.22%, the average dividend yield was 3.06% and the stock price and exercise price were $32.71.

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AGGREGATED OPTION EXERCISES IN 2005
AND FISCAL YEAR-END OPTION VALUES

The following table presents information regarding the exercise of Edison International stock options during 2005 by the named executive officers listed in the Summary Compensation Table above and unexercised stock options held as of December 31, 2005 by the named executive officers. No stock appreciation rights were exercised during 2005 or held at year-end 2005 by any of the named executive officers.

(a)	(b)	(c)	(d)	(e)
			Number of Securities Underlying Unexercised Options at Fiscal Year-End(1) (#)	Value of Unexercised in the-Money Options at Fiscal Year-End(1)(2) ($)
Name	Shares Acquired on Exercise (#)	Value Realized ($)	Exercisable/ Unexercisable	Exercisable/ Unexercisable
Theodore F. Craver, Jr.	22,300	561,186	235,444 / 329,983	5,364,693 / 5,929,739
Raymond W. Vickers	65,456	1,448,146	17,782 / 105,372	333,211 / 2,171,320
Paul Jacob	32,124	778,269	— / 60,154	— / 1,217,646
W. James Scilacci	29,400	646,653	72,945 / 74,399	1,624,617 / 1,534,238
John P. Finneran, Jr.	—	—	50,487 / 53,633	1,195,189 / 1,101,447

(1): Each Edison International stock option may be exercised for one share of Edison International Common Stock at an exercise price equal to the fair market value of the underlying common stock on the date the option was granted. Dividend equivalents on outstanding Edison International stock options issued prior to 2000 and after 2002 accrue to the extent dividends are declared on Edison International Common Stock. The option terms for current year awards are discussed in footnote (2) in the table above entitled "Option Grants in 2005."
(2): Edison International stock options are treated as in-the-money if the fair market value of the underlying stock at December 31, 2005 exceeded the exercise price of the Edison International stock options. The dollar amounts shown for the Edison International stock options are the differences between (i) the fair market value of the Edison International Common Stock underlying all unexercised in-the-money options at year-end 2005 and (ii) the exercise prices of those Edison International stock options.

The aggregate value at year-end 2005 of all accrued dividend equivalents for the named executive officers was:

		Vested/Unvested $ / $
Theodore F. Craver, Jr.		495,311 / 462,266
Raymond W. Vickers		24,430 / 157,067
Paul Jacob		— / 91,250
W. James Scilacci		124,324 / 114,094
John P. Finneran, Jr.		55,831 / 81,192

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LONG-TERM INCENTIVE PLAN
AWARDS IN LAST FISCAL YEAR

The following table presents information regarding Edison International performance shares granted during 2005 to the named executive officers listed in the Summary Compensation Table above.

			Estimated Future Payouts Under Non-Stock Price-Based Plans(2)
(a)	(b)	(c)	(d)	(e)	(f)
Name	Number of Shares, Units or Other Rights(1) (#)	Performance or Other Period Until Maturation or Payout	Threshold (#)	Target (#)	Maximum (#)
Theodore F. Craver, Jr.	16,802	3 years	4,201	16,802	50,406
Raymond W. Vickers	3,484	3 years	871	3,484	10,452
Paul Jacob	2,099	3 years	525	2,099	6,297
W. James Scilacci	2,414	3 years	604	2,414	7,242
John P. Finneran, Jr.	1,802	3 years	451	1,802	5,406

(1)

Twenty-five percent of each named executive officer's annual long-term incentive compensation for 2005 was awarded in the form of Edison International performance shares (Performance Shares). The remaining portion of the named executive officer's long-term incentive compensation for 2005 was awarded in the form of Edison International stock options and dividend equivalents as set forth above in the table entitled "Option Grants in 2005."

Performance Shares are stock-based units with each unit worth one share of Edison International Common Stock, payment of which is subject to a three-year performance measure based on the percentile ranking of Edison International total shareholder return compared to the total shareholder return for each stock comprising the Philadelphia Utility Index, adjusted to delete AES Corporation and to add Sempra Energy. A target number of contingent Performance Shares was awarded. Dividend equivalents included with these grants are described below. The Performance Shares cannot be voted or sold. One-half of any earned Performance Shares will be paid in Edison International Common Stock under the Equity Compensation Plan, and one-half will be paid in cash equal to the value of such stock outside of the plan, although Edison International has discretion to pay all Performance Shares in stock. The payment will be based on the average of the New York Stock Exchange high and low prices of Edison International Common Stock on December 31, 2007, subject to the named executive officer continued employment by EME through that date. If an award holder terminates employment after attaining age 65, after attaining age 55 with five years of service during the performance period, or after such earlier date that qualifies the holder for retirement under any company retirement plan, the Performance Shares will continue to vest as scheduled, subject to prorated adjustment for such separations from service occurring within the first year following the grant date. If an award holder terminates employment because of death or permanent and total disability during the performance period, the Performance Shares will remain eligible to vest on a pro rata basis. If an award holder is terminated involuntarily not for cause, the Performance Shares will remain eligible to vest on a pro rata basis, and one additional year of vesting credit will be applied. If employment is terminated during the performance period other than as described above, unvested Performance Shares are forfeited. The Performance Shares are not transferable, but a beneficiary may be designated in the event of death. Edison International will substitute cash awards to the extent necessary to pay required tax withholding or any government levies, and has reserved the right to substitute cash awards substantially equivalent in value to the Performance Shares.

Dividend equivalents in the amount of dividends that would have been paid on the number of shares of common stock covered by the corresponding target number of Performance Shares will be credited to an account established on behalf of the holder to the extent dividends are declared on Edison International Common Stock. The dividend equivalents accumulate without interest and will be paid in cash following the end of the performance period when the Performance Shares are paid although Edison International has discretion to pay dividend equivalents in shares of Edison International Common Stock. The dividend equivalents paid will be adjusted upward or downward at the time of payment to correlate with the actual number of Performance Shares paid based on the Edison International total shareholder return percentile ranking. In the event of a termination of the award holder's employment during the performance period, the dividend equivalents will be subject to the rules applicable to Performance Shares described above.
Appropriate and proportionate adjustments may be made by the Edison International Compensation and Executive Personnel Committee to outstanding Performance Shares to reflect any impact resulting from various corporate events such as reorganizations and stock splits. If Edison International is not the surviving corporation in such a reorganization, Performance Shares then outstanding will vest and be paid in cash at the greater of the value of the target number of

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Performance Shares or the value of shares that would have been paid if the performance period ended on that date based on actual performance.

(2): The amounts shown in columns (d), (e), and (f) represent the number of shares of Edison International Common Stock payable half in stock and half in cash for the specified levels of Edison International total shareholder return performance. The Edison International total shareholder return ranking must be at the 40th percentile to achieve the threshold payment indicated in column (d), which is 25 percent of the target number of shares. The target number shown in column (e) will be paid if the Edison International total shareholder return rank is at the 50th percentile. If the Edison International total shareholder return percentile ranking is at the 90th percentile or higher, the maximum payment will be earned, which is three times the target amount. Amounts in between these total shareholder return performance percentiles are interpolated on a straight-line basis. The amounts shown do not include dividend equivalents.

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PENSION PLAN TABLE(1)

The following table presents estimated gross annual benefits(2) payable upon retirement at age 65 to the named executive officers listed in the Summary Compensation Table above in the remuneration and years of service classifications indicated.

		Years of Service
Annual Remuneration		Years of Service
Annual Remuneration		10		15		20		25		30		35		40
$	200,000	$	50,000	$	67,500	$	85,000	$	102,500	$	120,000	$	130,000	$	140,000
	250,000		62,500		84,375		106,250		128,125		150,000		162,500		175,000
	300,000		75,000		101,250		127,500		153,750		180,000		195,000		210,000
	350,000		87,500		118,125		148,750		179,375		210,000		227,500		245,000
	400,000		100,000		135,000		170,000		205,000		240,000		260,000		280,000
	450,000		112,500		151,875		191,250		230,625		270,000		292,500		315,000
	500,000		125,000		168,750		212,500		256,250		300,000		325,000		350,000
	550,000		137,500		185,625		233,750		281,875		330,000		357,500		385,000
	600,000		150,000		202,500		255,000		307,500		360,000		390,000		420,000
	650,000		162,500		219,375		276,250		333,125		390,000		422,500		455,000
	700,000		175,000		236,250		297,500		358,750		420,000		455,000		490,000
	750,000		187,500		253,125		318,750		384,375		450,000		487,500		525,000
	800,000		200,000		270,000		340,000		410,000		480,000		520,000		560,000
	850,000		212,500		286,875		361,250		435,625		510,000		552,500		595,000
	900,000		225,000		303,750		382,500		461,250		540,000		585,000		630,000
	950,000		237,500		320,625		403,750		486,875		570,000		617,500		665,000

(1)

The annual pension benefit estimates are based on the terms of the retirement plan, a qualified defined benefit employee retirement plan, and the executive retirement plan, a non qualified supplemental executive retirement plan, currently covering EME's executive officers with the following assumptions: (i) the qualified retirement plan will be maintained, (ii) optional forms of payment which reduce benefit amounts have not been selected, and (iii) any benefits in excess of limits contained in the Internal Revenue Code of 1986 and any incremental benefits not included in the qualified retirement plan will be paid out of the executive retirement plan or an excess benefit plan as unsecured obligations of EME. For purposes of the executive retirement plan, as of December 31, 2005, the years of service completed were: Mr. Craver, 9; Mr. Vickers, 6; Mr. Jacob, 13; Mr. Scilacci, 21; and Mr. Finneran, 6.

(2)

The retirement benefit of the named executive officers at age 65 is determined by a percentage of the executive's highest 36 months of salary and annual incentive prior to attaining age 65. Compensation used to calculate combined benefits under the plans is based on salary and bonus (excluding special recognition awards) as reported in the table above entitled "Summary Compensation Table."

The service percentage is based on 1³/4% per year for the first 30 years of service (52¹/2% upon completion of 30 years of service) and 1% for each year in excess of 30. The named executive officers receive an additional service percentage of ³/4% per year for the first ten years of service (7¹/2% upon completion of ten years of service). The actual benefit is offset by up to 40% of the executive's primary Social Security benefits and by profit sharing contributions, if any, made by EME to the officers' 401(k) accounts.

The normal form of benefit is a life annuity with a 50% survivor benefit following the death of the participant. Retirement benefits are reduced for retirement prior to age 61. The amounts shown in the Pension Plan Table above do not reflect reductions in retirement benefits due to the Social Security offset or early retirement.

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Compensation of Directors

EME's directors do not receive any compensation for serving on its board of directors or attending meetings.

Termination of Employment Arrangements

Severance and Change in Control Arrangements

Edison International provides severance benefits and change in control benefits to certain key employees, including all of the named executive officers, under the Edison International Executive Severance Plan (the "Severance Plan").

Under the Severance Plan, an eligible executive is generally entitled to severance benefits if his or her employment is terminated by his or her employer without cause and other than due to the executive's disability.

Severance benefits generally include: (1) cash severance benefits consisting of an amount equal to a year's base salary, an amount equal to a year's target bonus, and an amount equal to a pro rata portion of the executive's target bonus for the portion of the calendar year employed prior to severance, (2) an additional year of service credit and an additional year of age credit for the purposes of calculating the executive's pension benefit under the Executive Retirement Plan, and (3) an additional year of vesting of stock options and dividend equivalents, performance shares and deferred stock units, and certain additional benefits.

Alternatively, a participating executive is generally entitled to enhanced severance benefits if, within a period that starts six months before and ends two years after an event that is deemed a "Change in Control" of Edison International, the executive's employment is terminated by the employer for any reason other than cause or disability or by the executive for good reason, Edison International or any successor breaches any provision of the Severance Plan, or a successor fails or refuses to assume Edison International's obligations under the Severance Plan. These enhanced severance benefits generally consist of full vesting of stock options and dividend equivalents, performance shares and deferred stock units in addition to the severance benefits described above. If the executive is the Chief Executive Officer of Edison International, Southern California Edison Company, EME or Edison Capital or the General Counsel or Chief Financial Officer of Edison International within the twelve months preceding his or her termination date, then the severance benefits are subject to further enhancement, and generally consist of a cash severance benefit amounting to three years' worth of base salary and target bonus, the prorated target bonus for the year in which termination occurs, three years of service and age credit under the Executive Retirement Plan, and enhancements to certain additional benefits. If the executive is a senior vice president or higher-ranking officer of Edison International, Southern California Edison Company, EME or Edison Capital (but not one of the officers listed above) within the twelve months preceding his termination date, the enhancement to the severance benefits generally includes a cash severance benefit amounting to two years' worth of base salary and target bonus, the prorated target bonus for the year in which termination occurs, two years of service and age credit under the Executive Retirement Plan, and enhancements to certain additional benefits.

The Severance Plan also provides that if, following a Change in Control, excise taxes under Section 4999 of the Internal Revenue Code of 1986, as amended, apply to payments made under the Severance Plan or other plans or agreements, the executive will be entitled to receive an additional payment (net of income, employment and excise taxes) to compensate the executive for any excise tax imposed.

Compensation Committee Interlocks and Insider Participation

The Board of Directors of EME determines the executive compensation arrangements for EME's executive officers. Mr. Craver is an officer and employee of EME, and also is an EME director.

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CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS

For information concerning transactions between EME and specified security holders, see "Management's Discussion and Analysis of Financial Condition and Results of Operations—Liquidity and Capital Resources—EME's Liquidity as a Holding Company—Intercompany Tax-Allocation Agreement" and paragraphs one and three related to administrative services and tax-allocation agreement, under "Audited Consolidated Financial Statements of Edison Mission Energy—Notes to Consolidated Financial Statements—Note 18. Related Party Transactions."

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DESCRIPTION OF THE NOTES

In this "Description of the Notes," references to "EME," "we," "our," "ours" and "us" refer only to Edison Mission Energy, and not to any of our direct or indirect subsidiaries or affiliates. The following description is a summary of certain provisions of the Indenture and the New Notes. It does not restate the Indenture and the New Notes in their entirety. We urge you to read the Indenture and the New Notes because they, and not this description, define your rights as a holder of these New Notes. You may obtain a copy of the Indenture and the New Notes from us by writing to us at 18101 Von Karman Avenue, Suite 1700, Irvine, California 92612.

General

We issued the Old Notes and will issue the New Notes under an Indenture, dated as of June 6, 2006, between EME and Wells Fargo Bank, National Association, as Trustee. Reference to the Notes includes the New Notes unless the context otherwise requires. The Notes are unsecured senior obligations of EME and rank equal in right of payment with all other unsubordinated indebtedness of EME. Because we conduct substantially all our business through numerous subsidiaries, all existing and future liabilities of our direct and indirect subsidiaries are and will be effectively senior to the Notes. The Notes are not guaranteed by, or otherwise be obligations of, our project subsidiaries and project affiliates, or our other direct and indirect subsidiaries and affiliates.

We issued the Old Notes in an offering exempt from registration. In this exchange offer, we will issue $500,000,000 in aggregate principal amount of New 2013 Notes in exchange for the same amount of Old 2013 Notes and $500,000,000 in aggregate principal amount of New 2016 Notes in exchange for the same amount of Old 2016 Notes. The New 2013 Notes and the Old 2013 Notes (collectively, the "2013 Notes") will bear interest at the rate of 7.50% per annum, and the New 2016 Notes and the Old 2016 Notes (collectively, the "2016 Notes") will bear interest at the rate of 7.75% per annum. We will pay interest on the Notes on each June 15 and December 15, beginning on December 15, 2006, to the holders of record on the immediately preceding June 1 and December 1. Interest on the Notes will accrue from the most recent date to which interest has been paid or, if no interest has been paid, from June 6, 2006. Interest will be computed on the basis of a 360-day year consisting of twelve 30-day months.

The Notes will be in denominations of $2,000 and any integral multiple of $1,000 in excess thereof.

We may issue additional series of notes under the Indenture from time to time in accordance with the conditions described therein.

Redemption

We may redeem all or a part of the Notes at any time upon not less than 30 nor more than 60 days' prior notice mailed by first-class mail to each holder's registered address, at a redemption price equal to 100% of the principal amount of the applicable series of Notes redeemed plus the Applicable Premium (as defined below) as of, and accrued and unpaid interest and Liquidated Damages (as defined below), if any, to the redemption date, subject to the rights of holders of the applicable series of Notes on the relevant record date to receive interest due on the relevant interest payment date.

Any notes issued under an additional series of notes will be subject to the redemption provisions in the supplemental indenture issued with respect to such series. Any additional 2013 Notes or

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2016 Notes issued after the date of the Indenture will be subject to the applicable redemption provisions and will be treated as a single class with the "Initial Notes" under the Indenture.

"Applicable Premium" means:

(1) with respect to any 2013 Notes on any redemption date, the greater of:

(a) 1.0% of the principal amount of the 2013 Note; or

(b) the excess of:

(i) the present value at such redemption date of (A) 100% of the principal amount of the 2013 Note at June 15, 2013, plus (B) all required interest payments due on the 2013 Note through June 15, 2013 (excluding accrued but unpaid interest to the redemption date), computed using a discount rate equal to the Treasury Rate as of such redemption date plus 50 basis points; over

(ii) the principal amount of the 2013 Note, if greater; and

(2) with respect to any 2016 Notes on any redemption date, the greater of:

(a) 1.0% of the principal amount of the 2016 Note; or

(b) the excess of:

(i) the present value at such redemption date of (A) 100% of the principal amount of the 2016 Note at June 15, 2016 plus (B) all required interest payments due on the 2016 Note through June 15, 2016 (excluding accrued but unpaid interest to the redemption date), computed using a discount rate equal to the Treasury Rate as of such redemption date plus 50 basis points; over

(ii) the principal amount of the 2016 Note, if greater.

"Treasury Rate" means, as of any redemption date, the yield to maturity as of such redemption date of United States Treasury securities with a constant maturity (as compiled and published in the most recent Federal Reserve Statistical Release H.15 (519) that has become publicly available at least two business days prior to the redemption date (or, if such Statistical Release is no longer published, any publicly available source of similar market data)) most nearly equal to the period from the redemption date to (i) June 15, 2013 with respect to the 2013 Notes; and (ii) June 15, 2016 with respect to the 2016 Notes; provided, however, that if the period from the redemption date to (i) June 15, 2013 with respect to the 2013 Notes, and (ii) June 15, 2016 with respect to the 2016 Notes, is less than one year, the weekly average yield on actually traded United States Treasury securities adjusted to a constant maturity of one year will be used.

Certain Covenants

Restrictions on Liens

We will agree not to pledge, mortgage, hypothecate or permit to exist any mortgage, pledge or other lien upon any property at any time directly owned by us to secure any indebtedness for money borrowed which is incurred, issued, assumed or guaranteed by us ("Indebtedness"), without providing for the Notes to be equally and ratably secured with any and all such Indebtedness and with any other Indebtedness similarly entitled to be equally and ratably secured; provided, however, that this restriction will not apply to, or prevent the creation or existence of:

(1) liens existing at the original date of issuance of the Notes;

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(2) purchase money liens which do not exceed the cost or value of the purchased property;

(3) other liens not to exceed 10% of our Consolidated Net Tangible Assets (as defined below); and

(4) liens granted in connection with extending, renewing, replacing or refinancing in whole or in part the Indebtedness (including, without limitation, increasing the principal amount of such Indebtedness) secured by liens described in clauses (1) through (3) above.

"Consolidated Net Tangible Assets" means, as of any date of determination, the total amount of all of our assets, determined on a consolidated basis in accordance with generally accepted accounting principles as of such date, less the sum of:

(a) our consolidated current liabilities, determined in accordance with generally accepted accounting principles; and

(b) our assets that are properly classified as intangible assets in accordance with generally accepted accounting principles, except for any intangible assets which are distribution or related contracts with an assignable value.

If we propose to pledge, mortgage or hypothecate any property at any time directly owned by us to secure any Indebtedness, other than as permitted by clauses (1) through (4) of the second previous paragraph, we will agree to give prior written notice thereof to the Trustee, who will give notice to the holders of Notes, and we will further agree, prior to or simultaneously with such pledge, mortgage or hypothecation, effectively to secure all the Notes equally and ratably with such Indebtedness.

This covenant will not restrict the ability of our subsidiaries and affiliates to pledge, mortgage, hypothecate or permit to exist any mortgage, pledge or lien upon their assets, in connection with project financings or otherwise.

Merger, Consolidation, Sale, Lease or Conveyance

We will agree not to merge or consolidate with or into any other person and we will agree not to sell, lease or convey all or substantially all of our assets to any person, unless (1) we are the continuing corporation, or the successor corporation or the person that acquires all or substantially all of our assets is a corporation organized and existing under the laws of the United States or a State thereof or the District of Columbia and expressly assumes all our obligations under the Notes and the Indenture, (2) immediately after such merger, consolidation, sale, lease or conveyance, there is no default or Event of Default (as defined below) under the Indenture, (3) if, as a result of the merger, consolidation, sale, lease or conveyance, any or all of our property would become the subject of a lien that would not be permitted by the Indenture, we secure the Notes equally and ratably with the obligations secured by that lien and (4) we deliver or cause to be delivered to the Trustee an officers' certificate and opinion of counsel each stating that the merger, consolidation, sale, lease or conveyance comply with the Indenture.

The meaning of the term "all or substantially all of the assets" has not been definitely established and is likely to be interpreted by reference to applicable state law if and at the time the issue arises and will be dependent on the facts and circumstances existing at the time.

Except for a sale of our assets substantially as an entirety as provided above, and other than assets we are required to sell to conform with governmental regulations, we may not sell or otherwise dispose of any assets (other than short-term, readily marketable investments purchased for cash management purposes with funds not representing the proceeds of other asset sales) if, on a pro forma basis, the

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aggregate net book value of all such sales during the most recent 12-month period would exceed 10% of our Consolidated Net Tangible Assets computed as of the end of the most recent quarter preceding such sale; provided, however, that any such sales shall be disregarded for purposes of this 10% limitation if the proceeds are invested in assets in similar or related lines of our business; and, provided further, that we may sell or otherwise dispose of assets in excess of this 10% limitation if we retain the proceeds from such sales or dispositions, which are not reinvested as provided above, as cash or cash equivalents or if we use the proceeds from such sales to purchase and retire Notes or Indebtedness ranking equal in right of payment to the Notes or indebtedness of our subsidiaries.

Reporting Obligations

We will agree to furnish or cause to be furnished to holders of Notes copies of our annual reports and of the information, documents and other reports that we are required to file with the SEC pursuant to Section 13 or 15(d) of the Exchange Act within 15 days after we file them with the SEC.

In addition, we will agree that, for so long as any of the respective Notes remain outstanding, if at any time we are not required to file with the SEC the reports required by the preceding paragraph, we will furnish to the holders of such Notes and to securities analysts and prospective investors, upon their request, the information required to be delivered pursuant to Rule 144A(d)(4) under the Securities Act.

Additional Covenants

Subject to certain exceptions and qualifications, we will agree in the Indenture to do, among other things, the following:

(1) deliver to the Trustee copies of all reports that we file with the SEC;

(2) deliver to the Trustee annual officers' certificates with respect to our compliance with our obligations under the Indenture;

(3) maintain our corporate existence, subject to the provisions described above relating to mergers and consolidations; and

(4) pay our taxes when due, except when we are contesting such taxes in good faith.

Modification of the Indenture

The Indenture will contain provisions permitting us and the Trustee, with the consent of the holders of at least a majority in aggregate principal amount of Notes then outstanding, to modify or amend the Indenture or the rights of the holders of Notes. However, no such modification or amendment may, without the consent of the holder of each outstanding Note affected thereby:

(a) change the stated maturity of the principal of, or extend the time of payment of interest on, any Note;

(b) reduce the principal amount of, or interest on, any Note;

(d) reduce any amount payable upon the redemption of any Note; or

(e) impair the right to institute suit for the enforcement of any payment on or with respect to any Note.

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In addition, without the consent of the holders of all Notes then outstanding, no such modification or amendment may:

(x) reduce the percentage in principal amount of outstanding Notes the consent of whose holders is required for modification or amendment of the Indenture;

(y) reduce the percentage in principal amount of outstanding Notes necessary for waiver of compliance with certain provisions of the Indenture or for waiver of certain defaults; or

(z) modify such provisions with respect to modification and waiver.

The holders of at least a majority in principal amount of the outstanding Notes may waive compliance by EME with certain restrictive provisions of the Indenture. The holders of a majority in principal amount of the outstanding Notes may waive any past default under the Indenture, except a default in the payment of principal or interest and certain covenants and provisions of the Indenture which cannot be amended without the consent of the holder of each outstanding Note affected.

We and the Trustee may, without the consent of any holder of Notes, amend the Indenture and the Notes for the purpose of curing any ambiguity, or of curing, correcting or supplementing any defective provision thereof, or in any manner that we and the Trustee may determine is not inconsistent with the Indenture and the Notes and will not adversely affect the interest of any holder of Notes.

Events of Default

Each of the following will be an "Event of Default" under the Indenture:

(a) our failure to pay any interest on any Note when due, which failure continues for 30 days; or

(b) our failure to pay principal or premium when due; or

(c) our failure to perform any other covenant in the Notes or the Indenture for a period of 90 days after the Trustee or the holders of at least 25% in aggregate principal amount of the Notes gives us written notice of our failure to perform; or

(d) an event of default occurring under any of our instruments under which there may be issued, or by which there may be secured or evidenced, any Indebtedness for money borrowed that has resulted in the acceleration of such Indebtedness, or any default occurring in payment of any such Indebtedness at final maturity (and after the expiration of any applicable grace periods), other than

(i) Indebtedness which is payable solely out of the property or assets of a partnership, joint venture or similar entity of which we or any of our subsidiaries or affiliates is a participant, or which is secured by a lien on the property or assets owned or held by such entity, without further recourse to or liability of us; or

(ii) Indebtedness not exceeding $20,000,000; or

(e) one or more nonappealable final judgments, decrees or orders of any court, tribunal, arbitrator, administrative or other governmental body or similar entity for the payment of money aggregating more than $20,000,000 shall be rendered against us (excluding the amount thereof covered by insurance) and shall remain undischarged, unvacated and unstayed for more than 90 days, except while being contested in good faith by appropriate proceedings; or

(f) certain events of bankruptcy, insolvency or reorganization in respect of us.

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If any Event of Default (other than an Event of Default due to certain events of bankruptcy, insolvency or reorganization) has occurred and is continuing, either the Trustee or the holders of not less than 25% in principal amount of the Notes outstanding under the Indenture may declare the principal of all Notes under the Indenture and interest accrued thereon to be due and payable immediately.

The Trustee will be entitled, subject to the duty of the Trustee during a default to act with the required standard of care, to be indemnified by the holders of Notes before proceeding to exercise any right or power under the Indenture at the request of such holders. Subject to such provisions in the Indenture for the indemnification of the Trustee and certain other limitations, the holders of a majority in principal amount of the Notes then outstanding may direct the time, method and place of conducting any proceeding for any remedy available to the Trustee or exercising any trust or power conferred on the Trustee.

No holder of Notes may institute any action against us under the Indenture (except actions for payment of overdue principal or interest) unless:

(1) such holder previously has given the Trustee written notice of the default and continuance thereof;

(2) the holders of not less than 25% in principal amount of the Notes then outstanding have requested the Trustee to institute such action and offered the Trustee reasonable indemnity;

(3) the Trustee has not instituted such action within 60 days of the request; and

(4) the Trustee has not received direction inconsistent with such written request from the holders of a majority in principal amount of the Notes then outstanding.

Defeasance and Covenant Defeasance

Defeasance

We will be deemed to have paid and will be discharged from any and all obligations in respect of the Notes on the 123rd day after we have made the deposit referred to below, and the provisions of the Indenture will cease to be applicable with respect to the Notes (except for, among other matters, certain obligations to register the transfer of or exchange of the Notes, to replace stolen, lost or mutilated Notes, to maintain paying agencies and to hold funds for payment in trust) if:

(A) we have deposited with the Trustee, in trust, money and/or certain U.S. government obligations that, through the payment of interest and principal in respect thereof in accordance with their terms, will provide money in an amount sufficient to pay the principal of, premium, if any, and accrued interest on the Notes at the time such payments are due in accordance with the terms of the Indenture;

(B) we have delivered to the Trustee:

(i) an opinion of counsel to the effect that Note holders will not recognize income, gain or loss for federal income tax purposes as a result of the defeasance and will be subject to federal income tax on the same amount and in the same manner and at the same times as would have been the case if such deposit, defeasance and discharge had not occurred, which opinion of counsel must be based upon a ruling of the Internal Revenue Service to the same effect or a change in applicable federal income tax law or related treasury regulations after the date of the Indenture; and

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(ii) an opinion of counsel reasonably acceptable to the Trustee to the effect that the defeasance trust does not constitute an "investment company" within the meaning of the Investment Company Act of 1940 and after the passage of 123 days following the deposit, the trust fund will not be subject to the effect of Section 547 of the U.S. Bankruptcy Code or Section 15 of the New York Debtor and Creditor Law;

(C) immediately after giving effect to such deposit, no Event of Default, or event that after the giving of notice or lapse of time or both would become an Event of Default, will have occurred and be continuing on the date of such deposit or during the period ending on the 123rd day after the date of such deposit, and such deposit shall not result in a breach or violation of, or constitute a default under, any other agreement or instrument to which we are a party or by which we are bound and

(D) if at such time the Notes are listed on a national securities exchange, we have delivered to the Trustee an opinion of counsel to the effect that the Notes will not be delisted as a result of such deposit and discharge.

Defeasance of Certain Covenants and Certain Events of Default

The provisions of the Indenture will cease to be applicable with respect to:

(x) the covenants described in "—Certain Covenants" (other than those with respect to the maintenance of our existence and those described under the first paragraph of the caption "—Certain Covenants—Merger, Consolidation, Sale, Lease or Conveyance");

(y) clause (c) in "—Events of Default" with respect to such covenants; and

(z) clauses (d) and (e) in "—Events of Default" upon:

(1) the deposit with the Trustee, in trust, of money and/or certain U.S. government obligations that through the payment of interest and principal in respect thereof in accordance with their terms will provide money in an amount sufficient to pay the principal of, premium, if any, and accrued interest on the Notes;

(2) the satisfaction of the conditions described in clauses (B)(ii), (C) and (D) of the preceding paragraph; and

(3) our delivery to the Trustee of an opinion of counsel reasonably acceptable to the Trustee to the effect that, among other things, the holders of the Notes will not recognize income, gain or loss for federal income tax purposes as a result of such deposit and defeasance and will be subject to federal income tax on the same amount and in the same manner and at the same times as would have been the case if such deposit and defeasance had not occurred.

Defeasance and Certain Other Events of Default

If we exercise our option to omit compliance with certain covenants and provisions of the Indenture as described in the immediately preceding paragraph and the Notes are declared due and payable because of the occurrence of an Event of Default that remains applicable, the amount of money and/or U.S. government obligations on deposit with the Trustee may not be sufficient to pay amounts due on the Notes at the time of acceleration resulting from such Event of Default. In such event, we will remain liable for such payments.

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Book-Entry; Delivery and Form

Except as set forth below, the New Notes will be issued in registered, global form in minimum denominations of $2,000 stated principal amount at maturity and integral multiples of $1,000 in excess of $2,000. New Notes will be issued at the closing of the exchange offer only against surrender of Old Notes.

The New Notes initially will be represented by one or more notes in registered, global form without interest coupons (collectively, the "Global Notes"). The Global Notes will be deposited upon issuance with the Trustee as custodian for DTC, in New York, New York, and registered in the name of DTC or its nominee, in each case for credit to an account of a direct or indirect participant in DTC as described below. Except as set forth below, the Global Notes may be transferred, in whole and not in part, only to another nominee of DTC or to a successor of DTC as its nominee. Beneficial interest in the Global Notes may not be exchanged for notes in certificated form except in the limited circumstances described below. See "—Exchange of Global Notes for Certificated Notes." Except in the limited circumstances described below, owners of beneficial interests in the Global Notes will not be entitled to receive physical delivery of the New Notes in certificated form.

Transfers of beneficial interests in the Global Notes will be subject to the applicable rules and procedures of DTC and its direct or indirect participants (including, if applicable, those of Euroclear System ("Euroclear") and Clearstream Banking, S.A. ("Clearstream") (as indirect participants in DTC)), which may change from time to time.

Depository Procedures

The following description of the operations and procedures of DTC, Euroclear and Clearstream are provided solely as a matter of convenience. These operations and procedures are solely within the control of the respective settlement systems and are subject to changes by them. EME takes no responsibility for these operations and procedures and urges investors to contact the system or their participants directly to discuss these matters.

DTC has advised us that DTC is a limited-purpose trust company created to hold securities for its participating organizations (collectively, the "Participants") and to facilitate the clearance and settlement of transactions in those securities between the Participants through electronic book-entry changes in accounts of its Participants. The Participants include securities brokers and dealers (including the initial purchasers), banks, trust companies, clearing corporations and certain other organizations. Access to DTC's system is also available to other entities such as banks, brokers, dealers and trust companies that clear through or maintain a custodial relationship with a Participant, either directly or indirectly (collectively, the "Indirect Participants"). Persons who are not Participants may beneficially own securities held by or on behalf of DTC only through the Participants or the Indirect Participants. The ownership interests in, and transfers of ownership interests in, each security held by or on behalf of DTC are recorded on the records of the Participants and Indirect Participants.

DTC has also advised us that, pursuant to procedures established by it:

(1) upon deposit of the Global Notes, DTC will credit the accounts of the Participants designated by the initial purchasers with portions of the principal amounts of the Global Notes; and

(2) ownership of these interests in the Global Notes will be shown on, and the transfer of ownership of these interests will be effected only through, records maintained by DTC (with

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respect to the Participants) or by the Participants and the Indirect Participants (with respect to other owners of beneficial interest in the Global Notes).

Investors in the Global Notes who are Participants may hold their interests therein directly through DTC. Investors in the Global Notes who are not Participants may hold their interests therein indirectly through organizations (including Euroclear and Clearstream) which are Participants. All interests in a Global Note, including those held through Euroclear or Clearstream, may be subject to the procedures and requirements of DTC. Those interests held through Euroclear or Clearstream may also be subject to the procedures and requirements of such systems. The laws of some states require that certain persons take physical delivery in definitive form of securities that they own. Consequently, the ability to transfer beneficial interests in a Global Note to such persons will be limited to that extent. Because DTC can act only on behalf of the Participants, which in turn act on behalf of the Indirect Participants, the ability of a person having beneficial interests in a Global Note to pledge such interests to persons that do not participate in the DTC system, or otherwise take actions in respect of such interests, may be affected by the lack of a physical certificate evidencing such interests.

Except as described below, owners of interests in the Global Notes will not have Notes registered in their names, will not receive physical delivery of Notes in certificated form and will not be considered the registered owners or "holders" thereof under the Indenture for any purpose.

Payments in respect of the principal of, and interest and premium, if any, and Liquidated Damages, if any, on, a Global Note registered in the name of DTC or its nominee will be payable to DTC in its capacity as the registered holder under the Indenture. Under the terms of the Indenture, we and the Trustee will treat the persons in whose names the Notes, including the Global Notes, are registered as the owners of the Notes for the purpose of receiving payments and for all other purposes. Consequently, neither we, the Trustee nor any agent of ours or the Trustee has or will have any responsibility or liability for:

(1) any aspect of DTC's records or any Participant's or Indirect Participant's records relating to or payments made on account of beneficial ownership interest in the Global Notes or for maintaining, supervising or reviewing any of DTC's records or any Participant's or Indirect Participant's records relating to the beneficial ownership interests in the Global Notes; or

(2) any other matter relating to the actions and practices of DTC or any of its Participants or Indirect Participants.

DTC has advised us that its current practice, upon receipt of any payment in respect of securities such as the Notes (including principal and interest), is to credit the accounts of the relevant Participants with the payment on the payment date unless DTC has reason to believe that it will not receive payment on such payment date. Each relevant Participant is credited with an amount proportionate to its beneficial ownership of an interest in the principal amount of the relevant security as shown on the records of DTC. Payments by the Participants and the Indirect Participants to the beneficial owners of Notes will be governed by standing instructions and customary practices and will be the responsibility of the Participants or the Indirect Participants and will not be the responsibility of DTC, the Trustee or us. Neither we nor the Trustee will be liable for any delay by DTC or any of the Participants or the Indirect Participants in identifying the beneficial owners of the Notes, and we and the Trustee may conclusively rely on and will be protected in relying on instructions from DTC or its nominee for all purposes.

Subject to compliance with the transfer restrictions applicable to the Notes described herein, cross-market transfers between the Participants, on the one hand, and Euroclear or Clearstream participants, on the other hand, will be effected through DTC in accordance with DTC's rules on behalf of

137

Euroclear or Clearstream, as the case may be, by their respective depositaries; however, such cross-market transactions will require delivery of instructions to Euroclear or Clearstream, as the case may be, by the counterparty in such system in accordance with the rules and procedures and within the established deadlines (Brussels time) of such system. Euroclear or Clearstream, as the case may be, will, if the transaction meets its settlement requirements, deliver instructions to its respective depositary to take action to effect final settlement on its behalf by delivering or receiving interests in the relevant Global Note in DTC, and making or receiving payment in accordance with normal procedures for same-day funds settlement applicable to DTC. Euroclear participants and Clearstream participants may not deliver instructions directly to the depositories for Euroclear or Clearstream.

DTC has advised us that it will take any action permitted to be taken by a holder of Notes only at the direction of one or more Participants to whose account DTC has credited the interests in the Global Notes and only in respect of such portion of the aggregate principal amount of the Notes as to which such Participant or Participants has or have given such direction. However, if there is an Event of Default under the Notes, DTC reserves the right to exchange the Global Notes for legended Notes in certificated form, and to distribute such Notes to its Participants.

Although DTC, Euroclear and Clearstream have agreed to the foregoing procedures to facilitate transfers of interests in the Global Notes among participants in DTC, Euroclear and Clearstream, they are under no obligation to perform or to continue to perform such procedures, and may discontinue such procedures at any time. None of EME, the Trustee and any of their respective agents will have any responsibility for the performance by DTC, Euroclear or Clearstream or their respective participants or indirect participants of their respective obligations under the rules and procedures governing their operations.

Exchange of Global Notes for Certificated Notes

A Global Note is exchangeable for Certificated Notes if:

(1) DTC (a) notifies us that it is unwilling or unable to continue as depositary for the Global Notes or (b) has ceased to be a clearing agency registered under the Exchange Act and, in either case, EME fails to appoint a successor depositary;

(2) we, at our option, notify the Trustee in writing that we elect to cause the issuance of the Certificated Notes; or

(3) there has occurred and is continuing a default or Event of Default with respect to the New Notes.

In addition, beneficial interests in a Global Note may be exchanged for Certificated Notes upon prior written notice given to the Trustee by or on behalf of DTC in accordance with the Indenture. In all cases, Certificated Notes delivered in exchange for any Global Note or beneficial interests in Global Notes will be registered in the names, and issued in any approved denominations, requested by or on behalf of the depositary (in accordance with its customary procedures).

Exchange of Certificated Notes for Global Notes

Certificated Notes may not be exchanged for beneficial interests in any Global Note unless the transferor first delivers to the Trustee a written certificate (in the form provided in the Indenture) to the effect that such transfer will comply with the appropriate transfer restrictions applicable to such New Notes.

138

Same Day Settlement and Payment

We will make payments in respect of the New Notes represented by the Global Notes (including principal, premium, if any, interest and Liquidated Damages, if any) by wire transfer of immediately available funds to the accounts specified by DTC or its nominee. We will make all payments of principal, interest and premium, if any, and Liquidated Damages, if any, with respect to Certificated Notes by wire transfer of immediately available funds to the accounts specified by the holders of the Certificated Notes or, if no such account is specified, by mailing a check to each such holder's registered address. The New Notes represented by the Global Notes are expected to be eligible to trade in The PORTAL^SM Market and to trade in DTC's Same-Day Funds Settlement System, and any permitted secondary market trading activity in such New Notes will, therefore, be required by DTC to be settled in immediately available funds. We expect that secondary trading in any Certificated Notes will also be settled in immediately available funds.

Because of time zone differences, the securities account of a Euroclear or Clearstream participant purchasing an interest in a Global Note from a Participant will be credited, and any such crediting will be reported to the relevant Euroclear or Clearstream participant, during the securities settlement processing day (which must be a business day for Euroclear and Clearstream) immediately following the settlement date of DTC. DTC has advised EME that cash received in Euroclear or Clearstream as a result of sales of interests in a Global Note by or through a Euroclear or Clearstream participant to a Participant will be received with value on the settlement date of DTC but will be available in the relevant Euroclear or Clearstream cash account only as of the business day for Euroclear or Clearstream following DTC's settlement date.

139

MATERIAL U.S. FEDERAL INCOME TAX CONSEQUENCES

The following summary describes certain material United States federal income and estate tax considerations for Non-U.S. Holders (as defined below) of exchanging the Old Notes for the New Notes and of the ownership and disposition of the New Notes. The summary is based on the Internal Revenue Code of 1986, as amended (the "Code"), and Treasury regulations, rulings and judicial decisions as of the date hereof, all of which may be repealed, revoked or modified with possible retroactive effect. This discussion does not deal with Non-U.S. Holders that may be subject to special tax rules (including, but not limited to, insurance companies, tax-exempt organizations, financial institutions, dealers in securities or currencies, Non-U.S. Holders who hold the Old Notes or will hold the New Notes as a hedge against currency risks or as part of a straddle, synthetic security, conversion transaction or other integrated investment comprised of the Old Notes or New Notes and one or more other investments, U.S. expatriates or partnerships or other pass-through entities). The summary is applicable only to Non-U.S. Holders that acquired the Old Notes pursuant to the offering at the initial offering price and are exchanging such Old Notes for New Notes pursuant to the exchange offer, and who hold the Old Notes, and will hold the New Notes, as capital assets within the meaning of Section 1221 of the Code. This summary is for general information only and does not address all aspects of U.S. federal income taxation that may be relevant to Non-U.S. Holders in light of their particular circumstances, and it does not address any U.S. federal tax consequences other than income and estate tax, and it does not address any tax consequences arising under the laws of any state, local or foreign taxing jurisdiction. Non-U.S. Holders who consider exchanging their Old Notes for New Notes should consult their own tax advisors as to the particular tax consequences to them of exchanging the Old Notes for New Notes or holding or disposing of the New Notes.

As used herein, the term "Non-U.S. Holder" means a beneficial owner of a note (other than a partnership) that is not a "U.S. Holder." A "U.S. Holder" is a beneficial owner of notes that for U.S. federal income tax purposes is: (i) a citizen or resident of the United States, (ii) a corporation (including any entity treated as a corporation) created or organized in or under the laws of the United States, any state or political subdivision thereof or therein, (iii) an estate the income of which is subject to U.S. federal income tax without regard to its source or (iv) a trust if (x) a court within the United States is able to exercise primary supervision over the administration of the trust and one or more U.S. persons have the authority to control all substantial decisions of the trust or (y) the trust has a valid election in effect under applicable Treasury regulations to be treated as a U.S. person.

Exchange Offer

The exchange of Old Notes for New Notes pursuant to the exchange offer will not constitute a taxable exchange for U.S. federal income tax purposes because there is not a significant modification of the terms of the Old Notes. Rather, the New Notes received will be treated as a continuation of the Old Notes in the hands of the exchanging holder. As a result, there will be no U.S. federal income tax consequences to holders exchanging the Old Notes for New Notes pursuant to the exchange offer and any exchanging holder of Old Notes will have the same tax basis and holding period in respect of the New Notes as it would have had in respect of the Old Notes surrendered in the exchange.

Payment of Interest

Under present U.S. federal income tax law, subject to the discussion of backup withholding and information reporting below, payments of principal and interest on the New Notes to any Non-U.S. Holder will not be subject to U.S. federal income, branch profits or withholding tax provided that (i) the Non-U.S. Holder does not actually or constructively own 10% or more of the total combined voting power of all classes of stock of EME entitled to vote, (ii) the Non-U.S. Holder is not a bank

140

receiving interest pursuant to a loan agreement entered into in the ordinary course of its trade or business, (iii) the Non-U.S. Holder is not a controlled foreign corporation (as defined for U.S. federal income tax purposes) that is related to EME (directly or indirectly) through stock ownership, (iv) such interest payments are not effectively connected with a U.S. trade or business (or, if certain tax treaties apply, the Non-U.S. Holder does not maintain a U.S. permanent establishment to which the payment is attributable) and (v) certain certification requirements are met. Such certification will be satisfied if the beneficial owner of the New Note certifies on Internal Revenue Service ("IRS") Form W-8BEN or a substantially similar substitute form, under penalties of perjury, that it is not a U.S. person and provides its name and address, and (x) such beneficial owner files such form with the withholding agent or (y) in the case of a New Note held by a securities clearing organization, bank or other financial institution that holds customers' securities in the ordinary course of its trade or business (a "financial institution") and holds the New Note, such financial institution certifies to EME or its agent under penalties of perjury that such statement has been received from the beneficial owner by it or by a financial institution between it and the beneficial owner and furnishes the withholding agent with a copy thereof.

If the above conditions are not met a Non-U.S. Holder may be entitled to a reduction in or an exemption from withholding tax on interest under a tax treaty between the United States and the Non-U.S. Holder's country of residence. To claim such a reduction or exemption, a Non-U.S. Holder must generally complete IRS Form W-8BEN and claim this reduction or exemption on the form. In some cases, a Non-U.S. Holder may instead be permitted to provide documentary evidence of its claim to the intermediary, or a qualified intermediary may already have some or all of the necessary evidence in its files.

A Non-U.S. Holder generally will also be exempt from withholding tax on interest if such interest is effectively connected with such Non-U.S. Holder's conduct of a U.S. trade or business (or, if certain tax treaties apply, the Non-U.S. Holder maintains a U.S. permanent establishment to which the interest is attributable) and the Non-U.S. Holder provides EME with an IRS Form W-8ECI. In such case, the Non-U.S. Holder will generally be subject to U.S. federal income tax on the interest on a net basis in the same manner as if such Non-U.S. Holder were a U.S. Holder. In addition, if the Non-U.S. Holder is a foreign corporation, the interest may be subject to a branch profits tax at a rate of 30% (or lower applicable treaty rate).

Disposition of the New Notes

Under present U.S. federal income tax law, subject to the discussion of backup withholding and information reporting below, a Non-U.S. Holder will not be subject to U.S. federal income or branch profits tax on gain realized on the sale, exchange, redemption, retirement or other disposition of a New Note (except to the extent the proceeds from the disposition are attributable to accrued interest, which will be taxable to the extent not previously includible in income as described above), unless (i) the gain is effectively connected with a trade or business carried on by such holder within the United States (or, if certain tax treaties apply, the Non-U.S. Holder maintains a U.S. permanent establishment to which the gain is attributable), or (ii) the holder is an individual who is present in the United States for 183 days or more in the taxable year of disposition and certain other requirements are met.

A Non-U.S. Holder described in (i) above will be required to pay U.S. federal income tax on the net gain derived from the disposition in the same manner as if such Non-U.S. Holder were a U.S. Holder, and if such Non-U.S. Holder is a foreign corporation, it may also be required to pay an additional branch profits tax at a 30% rate (or a lower rate if so specified by an applicable income tax treaty). A Non-U.S. Holder described in (ii) above will be subject to a 30% U.S. federal income tax (or, if applicable, a lower treaty rate) on the gain derived from the disposition, which may be offset by

141

U.S. source capital losses, even though the Non-U.S. Holder is not considered a resident of the United States.

Federal Estate Tax

An individual Non-U.S. Holder who at the time of death is not a citizen or resident of the United States (for U.S. federal estate tax purposes), will not be subject to U.S. federal estate tax at the time of his or her death with respect to the New Note held by such Non-U.S. Holder, provided that:

•: such Non-U.S. Holder does not does not actually or constructively own 10% or more of the total combined voting power of all classes of EME stock that are entitled to vote; and
•: the interest accrued on the New Note was not effectively connected with such Non-U.S. Holder's conduct of a trade or business in the United States (and, if certain tax treaties apply, such Non-U.S. Holder did not maintain a U.S. permanent establishment to which the accrued interest was attributable).

Backup Withholding and Information Reporting

In general, payments of interest and the proceeds of the sale, exchange, redemption, retirement or other disposition of the New Notes payable by a U.S. paying agent or other U.S. intermediary will be subject to information reporting. In addition, backup withholding at a rate of 28% will apply to these payments if the Non-U.S. Holder fails to provide the certification on IRS Form W-8 described above or otherwise does not provide evidence of exempt status. Non-U.S. Holders that comply with certain certification requirements are not subject to backup withholding. Any amount paid as backup withholding will be creditable against the Non-U.S. Holder's U.S. federal income tax liability provided that the required information is timely furnished to the IRS. Non-U.S. Holders of New Notes should consult their tax advisors as to their qualification for exemption from backup withholding and the procedure for obtaining such an exemption.

142

PLAN OF DISTRIBUTION

Each broker-dealer that receives New Notes for its own account under the exchange offer must acknowledge that it will deliver a prospectus in connection with any resale of those notes. This prospectus, as it may be amended or supplemented from time to time, may be used by a broker-dealer for resales of New Notes received in exchange for Old Notes that had been acquired as a result of market-making or other trading activities. We have agreed that, for a period of 180 days after the expiration date of the exchange offer, we will make this prospectus, as it may be amended or supplemented, available to any broker-dealer for use in connection with any such resale. In addition, until November 20, 2006, all dealers effecting transactions in the New Notes may be required to deliver a prospectus.

We will not receive any proceeds from any sale of New Notes by broker-dealers. New Notes received by broker-dealers for their own account under the exchange offer may be sold from time to time in one or more transactions in the over-the-counter market, in negotiated transactions, through the writing of options on those notes or a combination of those methods, at market prices prevailing at the time of resale, at prices related to prevailing market prices or at negotiated prices. Any resales may be made directly to purchasers or to or through brokers or dealers who may receive compensation in the form of commissions or concessions from the selling broker-dealer or the purchasers of the New Notes. Any broker-dealer that resells New Notes received by it for its own account under the exchange offer and any broker or dealer that participates in a distribution of the New Notes may be deemed to be an "underwriter" within the meaning of the Securities Act and any profit on any resale of New Notes and any commissions or concessions received by these persons may be deemed to be underwriting compensation under the Securities Act. By acknowledging that it will deliver and by delivering a prospectus, a broker-dealer will not be deemed to admit that it is an "underwriter" within the meaning of the Securities Act.

For a period of 180 days after the expiration date of this exchange offer, we will promptly send additional copies of this prospectus and any amendment or supplement to this prospectus to any broker-dealer that requests such documents. We have agreed to pay all expenses incident to this exchange offer (including the expense of one counsel for the holders of the securities) other than commissions or concessions of any brokers or dealers and will indemnify the holders of the securities (including any broker-dealers) against certain liabilities, including liabilities under the Securities Act.

Under existing interpretations of the Securities Act by the SEC's staff contained in several no-action letters to third parties, and subject to the immediately following sentence, we believe that the New Notes would generally be freely transferable by holders after the exchange offer without further registration under the Securities Act, subject to certain representations required to be made by each holder of New Notes, as set forth below. However, any purchaser of New Notes who is one of our "affiliates" (as defined in Rule 405 under the Securities Act) or who intends to participate in the exchange offer for the purpose of distributing the New Notes:

•: will not be able to rely on the applicable interpretation of the staff of the SEC;
•: will not be able to tender its old notes in the exchange offer; and
•: must comply with the registration and prospectus delivery requirements of the Securities Act in connection with any sale or transfer of the notes unless such sale or transfer is made pursuant to an exemption from such requirements.

143

CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS
ON ACCOUNTING AND FINANCIAL DISCLOSURE

None

LEGAL MATTERS

Certain legal matters with respect to the Notes will be passed upon for EME by Skadden, Arps, Slate, Meagher & Flom LLP, New York, New York. Skadden, Arps, Slate, Meagher & Flom LLP also represents the initial purchasers from time to time.

EXPERTS

The financial statements as of December 31, 2005 and December 31, 2004 and for each of the three years in the period ended December 31, 2005 included in this prospectus and financial statement schedules included in the registration statement, have been so included in reliance on the report of PricewaterhouseCoopers LLP, an independent registered public accounting firm, given on the authority of said firm as experts in auditing and accounting.

144

TABLE OF CONTENTS

		Page
Unaudited Consolidated Financial Statements of Edison Mission Energy
	Consolidated Statements of Income (Loss) for the three and six months ended June 30, 2006 and 2005	F-2
	Consolidated Statements of Comprehensive Income for the three and six months ended June 30, 2006 and 2005	F-3
	Consolidated Balance Sheets at June 30, 2006 and December 31, 2005	F-4
	Consolidated Statements of Cash Flows for the six months ended June 30, 2006 and 2005	F-6
	Notes to Consolidated Financial Statements	F-7
Audited Consolidated Financial Statements of Edison Mission Energy
	Report of Independent Registered Public Accounting Firm	F-25
	Consolidated Statements of Income for the years ended December 31, 2005, 2004 and 2003	F-26
	Consolidated Balance Sheets at December 31, 2005 and 2004	F-27
	Consolidated Statements of Shareholder's Equity for the years ended December 31, 2005, 2004 and 2003	F-29
	Consolidated Statements of Comprehensive Income for the years ended December 31, 2005, 2004 and 2003	F-30
	Consolidated Statements of Cash Flows for the years ended December 31, 2005, 2004 and 2003	F-31
	Notes to Consolidated Financial Statements	F-32
Financial Statement Schedules of Edison Mission Energy
	Schedule I—Condensed Financial Information of Parent	F-79
	Schedule II—Valuation and Qualifying Accounts	F-82

F-1

EDISON MISSION ENERGY AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF INCOME (LOSS)
(In millions, Unaudited)

			Three Months Ended June 30,						Six Months Ended June 30,
			2006			2005			2006			2005
Operating Revenues
	Electric revenues		$	427		$	398		$	914		$	898
	Net gains from price risk management and energy trading			24			17			41			29
	Operation and maintenance services			8			7			13			12
	Other revenues			4			—			9			—

		Total operating revenues		463			422			977			939

Operating Expenses
	Fuel			142			134			291			299
	Plant operations			147			146			266			254
	Plant operating leases			44			44			88			88
	Operation and maintenance services			8			7			13			12
	Depreciation and amortization			36			32			71			66
	Asset impairment charges			—			7			—			7
	Administrative and general			33			34			64			70

		Total operating expenses		410			404			793			796

	Operating income			53			18			184			143

Other Income (Expense)
	Equity in income from unconsolidated affiliates			46			47			71			83
	Interest income			23			15			43			27
	Other income (expense), net			11			—			19			(3	)
	Gain on sale of assets			—			—			4			—
	Loss on early extinguishment of debt			(143	)		—			(143	)		(4	)
	Interest expense			(73	)		(74	)		(145	)		(151	)

		Total other income (expense)		(136	)		(12	)		(151	)		(48	)

	Income (loss) from continuing operations before income taxes			(83	)		6			33			95
	Provision (benefit) for income taxes			(40	)		(13	)		1			19

Income (Loss) From Continuing Operations				(43	)		19			32			76
	Income from operations of discontinued subsidiaries, net of tax (Note 7)			4			21			77			28

Net Income (Loss)			$	(39	)	$	40		$	109		$	104

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

F-2

EDISON MISSION ENERGY AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME
(In millions, Unaudited)

			Three Months Ended June 30,						Six Months Ended June 30,
			2006			2005			2006			2005
Net Income (Loss)			$	(39	)	$	40		$	109		$	104
Other comprehensive income (loss), net of tax:
		Minimum pension liability adjustment, net of income tax effect		(2	)		—			(2	)		—
	Unrealized gains (losses) on derivatives qualified as cash flow hedges:
		Other unrealized holding gains (losses) arising during period, net of income tax expense (benefit) of $45 and $12 for the three months and $172 and $(43) for the six months ended June 30, 2006 and 2005, respectively		67			16			253			(54	)
		Reclassification adjustments included in net income (loss), net of income tax expense (benefit) of $(12) and $2 for the three months and $8 and $5 for the six months ended June 30, 2006 and 2005, respectively		17			(3	)		(12	)		(8	)

Other comprehensive income (loss)				82			13			239			(62	)

Comprehensive Income			$	43		$	53		$	348		$	42

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

F-3

EDISON MISSION ENERGY AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
(In millions, Unaudited)

			June 30, 2006		December 31, 2005
Assets
Current Assets
	Cash and cash equivalents		$	1,328	$	1,155
	Short-term investments			260		183
	Accounts receivable—trade			191		337
	Accounts receivable—affiliates			161		18
	Inventory			183		120
	Assets under price risk management and energy trading			152		78
	Margin and collateral deposits			240		561
	Deferred taxes			16		155
	Prepaid expenses and other			64		68

		Total current assets		2,595		2,675

Investments in Unconsolidated Affiliates				373		405

Property, Plant and Equipment				3,997		3,856
	Less accumulated depreciation and amortization			913		844

		Net property, plant and equipment		3,084		3,012

Other Assets
	Deferred financing costs			48		43
	Long-term assets under price risk management and energy trading			105		90
	Restricted cash			121		105
	Rent payments in excess of levelized rent expense under plant operating leases			506		395
	Long-term margin and collateral deposits			96		137
	Other long-term assets			93		161

		Total other assets		969		931

Total Assets			$	7,021	$	7,023

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

F-4

EDISON MISSION ENERGY AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
(In millions, Unaudited)

			June 30, 2006			December 31, 2005
Liabilities and Shareholder's Equity
Current Liabilities
	Accounts payable—affiliates		$	17		$	32
	Accounts payable			56			64
	Accrued liabilities			171			207
	Liabilities under price risk management and energy trading			119			418
	Interest payable			30			51
	Current maturities of long-term obligations			130			74

		Total current liabilities		523			846

Long-term obligations net of current maturities				3,294			3,330
Deferred taxes and tax credits				304			227
Long-term liabilities under price risk management and energy trading				26			83
Other long-term liabilities				588			598

Total Liabilities				4,735			5,084

Minority Interest				44			29

Commitments and Contingencies (Note 11)
Shareholder's Equity
	Common stock, par value $0.01 per share; 10,000 shares authorized; 100 shares issued and outstanding as of June 30, 2006 and December 31, 2005			64			64
	Additional paid-in capital			2,212			2,228
	Accumulated deficit			(62	)		(171	)
	Accumulated other comprehensive income (loss)			28			(211	)

Total Shareholder's Equity				2,242			1,910

Total Liabilities and Shareholder's Equity			$	7,021		$	7,023

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

F-5

EDISON MISSION ENERGY AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CASH FLOWS
(In millions, Unaudited)

			Six Months Ended June 30,
			2006			2005 Revised(1)
Cash Flows From Operating Activities
	Net income		$	109		$	104
	Less: Income from discontinued operations			(77	)		(28	)

	Income from continuing operations, net		$	32		$	76
	Adjustments to reconcile income to net cash provided by (used in) operating activities:
		Equity in income from unconsolidated affiliates		(71	)		(83	)
		Distributions from unconsolidated affiliates		88			89
		Depreciation and amortization		76			66
		Deferred taxes and tax credits		42			16
		Gain on sale of assets		(4	)		—
		Loss on early extinguishment of debt		143			4
		Asset impairment charges		—			7
	Changes in operating assets and liabilities:
		Decrease (increase) in margin and collateral deposits		363			(142	)
		Decrease (increase) in accounts receivable		3			(17	)
		Increase in inventory		(63	)		(22	)
		Decrease in prepaid expenses and other		10			56
		Increase in rent payments in excess of levelized rent expense		(112	)		(67	)
		Decrease in accounts payable		(4	)		(7	)
		Decrease in accrued liabilities		(32	)		(68	)
		Decrease in interest payable		(21	)		(4	)
		(Increase) decrease in net assets under risk management		(26	)		3
		Other operating—assets		(1	)		4
		Other operating—liabilities		(26	)		21

				397			(68	)
	Operating cash flow from discontinued operations			82			18

		Net cash provided by (used in) operating activities		479			(50	)

Cash Flows From Financing Activities
	Borrowings on long-term debt			1,315			3
	Payments on long-term debt agreements			(1,293	)		(511	)
	Repayment of loan by parent			—			(5	)
	Cash dividends to parent			(12	)		(360	)
	Payments for price appreciation on stock options exercised			(9	)		(7	)
	Excess tax benefits related to stock option exercises			4			—
	Premium paid on extinguishment of debt and financing costs			(153	)		(5	)

		Net cash used in financing activities		(148	)		(885	)

Cash Flows From Investing Activities
	Capital expenditures			(118	)		(35	)
	Proceeds from return of capital and loan repayments			—			5
	Purchase of interest of acquired companies			(18	)		—
	Proceeds from sale of interest in projects			43			—
	Proceeds from sale of discontinued operations			—			124
	Purchase of short-term investments			(173	)		—
	Maturities and sales of short-term investments			97			140
	Decrease (increase) in restricted cash			(12	)		21
	Turbine deposits			(17	)		(9	)
	Proceeds from (investments in) other assets			40			(1	)

				(158	)		245
	Investing cash flow from discontinued operations			—			5

		Net cash provided by (used in) investing activities		(158	)		250

Effect of consolidation of variable interest entities on cash				—			3

Net increase (decrease) in cash and cash equivalents				173			(682	)
Cash and cash equivalents at beginning of period				1,155			2,280

Cash and cash equivalents at end of period				1,328			1,598
Cash and cash equivalents classified as part of discontinued operations				—			(1	)

Cash and cash equivalents of continuing operations			$	1,328		$	1,597

(1): See Note 1—Revisions for further explanation.
The accompanying notes are an integral part of these consolidated financial statements.

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EDISON MISSION ENERGY AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
JUNE 30, 2006
(Unaudited)

Note 1. General

In the opinion of management, all adjustments, including recurring accruals, have been made that are necessary to fairly state the consolidated financial position, results of operations and cash flows for the periods covered by this quarterly report on Form 10-Q. The results of operations for the six months ended June 30, 2006 are not necessarily indicative of the operating results for the full year.

Edison Mission Energy's (EME's) significant accounting policies are described in Note 2 to its Consolidated Financial Statements as of December 31, 2005 and 2004, included in EME's annual report on Form 10-K for the year ended December 31, 2005. EME follows the same accounting policies for interim reporting purposes, with the exception of the change in accounting for stock-based compensation (explained below). This quarterly report should be read in connection with such financial statements. Terms used but not defined in this report are defined in EME's annual report on Form 10-K for the year ended December 31, 2005.

On April 1, 2006, EME received, as a capital contribution, ownership interests in a portfolio of wind projects located in Iowa and Minnesota and a small biomass project. See Note 6—Acquisitions and Consolidations—Acquisitions, for further discussion. These projects were previously owned by EME's affiliate, Edison Capital. Edison Mission Group is a subsidiary of Edison International and is the holding company for its wholly owned subsidiaries, Mission Energy Holding Company (MEHC) and Edison Capital. MEHC is the holding company of its wholly owned subsidiary EME. EME accounted for this acquisition at Edison Capital's historical cost as a transaction between entities under common control. Therefore, these consolidated financial statements include the results of operations, financial position and cash flows of the acquired projects as though EME had such ownership throughout the periods presented.

Stock-Based Compensation

EME's stock-based compensation plans primarily include the issuance of Edison International stock options and performance shares. Edison International usually does not issue new common stock for equity awards earned. Rather, a third party is used to facilitate the exercise of stock options and the purchase and delivery of outstanding common stock for settlement of performance shares earned. The amount of cash used to settle stock options exercised was $6 million and $13 million for the second quarters of 2006 and 2005, respectively, and $19 million for both the six months ended June 30, 2006 and 2005. No cash was used to settle performance shares classified as equity awards in the second quarters of 2006 and 2005, and $10 million and $4 million was used for the six months ended June 30, 2006 and 2005, respectively. Edison International has approximately 13.7 million shares remaining for future issuance under its stock-based compensation plans, which are described more fully in Note 13—Stock Compensation Plans.

Prior to January 1, 2006, EME accounted for these plans using the intrinsic value method. Upon grant, no stock-based compensation cost for stock options was reflected in net income, as the grant date was the measurement date, and all options granted under these plans had an exercise price equal to the market value of the underlying common stock on the date of grant. Previously, stock-based compensation cost for performance shares was remeasured at each reporting period and related compensation expense was adjusted. As discussed in Note 14—New Accounting Pronouncements,

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effective January 1, 2006, EME implemented a new accounting standard that requires companies to use the fair value accounting method for stock-based compensation resulting in the recognition of expense for all stock-based compensation awards. EME recognizes stock-based compensation expense on a straight-line basis over the vesting period. EME recognizes stock-based compensation expense for awards granted to retirement-eligible participants as follows: for stock-based awards granted prior to January 1, 2006, EME recognized stock-based compensation expense over the explicit vesting period and accelerated any remaining unrecognized compensation expense when a participant actually retired; for awards granted or modified after January 1, 2006 to participants who are retirement-eligible or will become retirement-eligible prior to the end of the normal vesting period for the award, stock-based compensation is recognized on a prorated basis over the initial year or over the period between the date of grant and the date the participant first becomes eligible for retirement. If EME recognized stock-based compensation expense for awards granted prior to January 1, 2006, over a period to the date the participant first became eligible for retirement, there would be no significant changes to stock-based compensation expense for the second quarters of 2006 and 2005 and for the six months ended June 30, 2006 and 2005.

Total stock-based compensation expense (reflected in the caption "Administrative and general" on the consolidated statements of income) was $2 million and $7 million for the second quarters of 2006 and 2005, respectively, and $4 million and $12 million for the six months ended June 30, 2006 and 2005, respectively. The income tax benefit recognized in the income statement was $1 million and $3 million for the second quarters of 2006 and 2005, respectively, and $2 million and $5 million for the six months ended June 30, 2006 and 2005, respectively.

The following table illustrates the effect on net income if EME had used the fair value accounting method for the second quarter of 2005 and six months ended June 30, 2005.

	Three Months Ended June 30, 2005			Six Months Ended June 30, 2005
	(in millions)
Net income, as reported	$	40		$	104
Add: stock-based compensation expense using the intrinsic value accounting method—net of tax		4			7
Less: stock-based compensation expense using the fair value accounting method—net of tax		(3	)		(6	)

Pro forma net income	$	41		$	105

Reclassifications

Certain prior year reclassifications have been made to conform to the current year financial statement presentation. Except as indicated, amounts reflected in the notes to the consolidated financial statements relate to continuing operations of EME.

Revisions

EME revised its Consolidated Statements of Cash Flows for the six months ended June 30, 2005 to separately disclose the operating and investing portion of the cash flows attributable to its discontinued operations consistent with its Consolidated Statements of Cash Flow for the year ended December 31, 2005 included in EME's annual report on Form 10-K for the year ended December 31, 2005. EME had previously reported these amounts on a combined basis in its quarterly report on Form 10-Q for the six months ended June 30, 2005.

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Note 2. Inventory

Inventory is stated at the lower of weighted average cost or market. Inventory at June 30, 2006 and December 31, 2005 consisted of the following:

	June 30, 2006		December 31, 2005
	(in millions)
Coal and fuel oil	$	139	$	77
Spare parts, materials and supplies		44		43

Total	$	183	$	120

Note 3. Short-term Investments

Held-to-Maturity Securities

At June 30, 2006 and December 31, 2005, EME had marketable debt securities that were classified as held-to-maturity and carried at amortized cost plus accrued interest which approximated their fair value.

Held-to-maturity securities, which all mature within one year, consisted of the following:

	June 30, 2006		December 31, 2005
	(in millions)
Commercial paper	$	197	$	99
Certificates of deposit		59		34
Time deposits		—		50
Corporate bonds		4		—

Total	$	260	$	183

Note 4. Refinancing

Credit Agreement

On June 15, 2006, EME replaced its $98 million credit agreement with a new credit agreement that provides for a $500 million senior secured revolving loan and letter of credit facility and matures on June 15, 2012. Loans made under this credit facility bear interest, at EME's election, at either LIBOR (which is based on the interbank Eurodollar market) or the base rate (which is calculated as the higher of Citibank, N.A.'s publicly announced base rate and the federal funds rate in effect from time to time plus 0.50%) plus, in both cases, an applicable margin. The applicable margin depends on EME's debt ratings. As of June 30, 2006, EME had available the full amount of borrowing capacity under this credit facility. The credit facility contains financial covenants which require EME to maintain a minimum interest coverage ratio and a maximum corporate debt to corporate capital ratio. A failure to meet a ratio threshold could trigger other provisions, such as mandatory prepayment provisions or restrictions on dividends.

As security for its obligations under this credit facility, EME pledged its ownership interests in the holding companies through which it owns its interests in the Illinois Plants, the Homer City facilities, the Westside projects and the Sunrise project. EME also granted a security interest in an account into

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which all distributions received by it from the Big 4 projects will be deposited. EME will be free to use these proceeds unless an event of default occurs under the credit facility.

Senior Notes Offering

On June 6, 2006, EME completed a private offering of $500 million aggregate principal amount of its 7.50% senior notes due June 15, 2013 and $500 million aggregate principal amount of its 7.75% senior notes due June 15, 2016. EME will pay interest on the senior notes on June 15 and December 15 of each year, beginning on December 15, 2006. The senior notes are redeemable by EME at any time at a price equal to 100% of the principal amount of, plus accrued and unpaid interest and liquidated damages, if any, on, the senior notes plus a "make-whole" premium.

The senior notes are EME's senior unsecured obligations, ranking equal in right of payment to all of EME's existing and future senior unsecured indebtedness, and will be senior to all of EME's future subordinated indebtedness. EME's secured debt and its other secured obligations are effectively senior to the senior notes to the extent of the value of the assets securing such debt or other obligations. None of EME's subsidiaries have guaranteed the senior notes and, as a result, all the existing and future liabilities of EME's subsidiaries are effectively senior to the senior notes.

EME used the net proceeds of the offering of the senior notes, together with cash on hand, to purchase $369 million in aggregate principal amount of its 10% senior notes due August 15, 2008 and $596 million in aggregate principal amount of its 9.875% senior notes due April 15, 2011. The net proceeds of the offering of the senior notes, together with cash on hand, were also used to pay related tender premiums, consent fees and accrued interest. EME recorded a $143 million loss on early extinguishment of debt during the second quarter of 2006.

Note 5. Accumulated Other Comprehensive Income (Loss)

Accumulated other comprehensive income (loss) consisted of the following:

	Unrealized Gains (Losses) on Cash Flow Hedges			Minimum Pension Liability Adjustment			Accumulated Other Comprehensive Income (Loss)
	(in millions)
Balance at December 31, 2005	$	(210	)	$	(1	)	$	(211	)
Current period change		241			(2	)		239

Balance at June 30, 2006	$	31		$	(3	)	$	28

Unrealized gains on cash flow hedges, net of tax, at June 30, 2006, include unrealized gains on commodity hedges primarily related to Midwest Generation, LLC (Midwest Generation) and EME Homer City Generation L.P. (EME Homer City) futures and forward electricity contracts that qualify for hedge accounting. These gains arise because current forecasts of future electricity prices in the relevant markets are lower than the contract prices. The decrease in the unrealized losses during the six months ended June 30, 2006 resulted from a decrease in market prices for power.

As EME's hedged positions for continuing operations are realized, approximately $26 million, after tax, of the net unrealized gains on cash flow hedges at June 30, 2006 are expected to be reclassified into earnings during the next 12 months. Management expects that reclassification of net unrealized gains will offset energy revenue recognized at market prices. Actual amounts ultimately reclassified into earnings over the next 12 months could vary materially from this estimated amount as a result of

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changes in market conditions. The maximum period over which a cash flow hedge is designated is through December 31, 2008.

Under SFAS No. 133, the portion of a cash flow hedge that does not offset the change in value of the transaction being hedged, which is commonly referred to as the ineffective portion, is immediately recognized in earnings. EME recorded net gains (losses) of approximately $(6) million and $1 million during the second quarters of 2006 and 2005, respectively, and $(17) million and $(3) million during the six months ended June 30, 2006 and 2005, respectively, representing the amount of cash flow hedges' ineffectiveness for continuing operations, reflected in net gains from price risk management and energy trading in EME's consolidated income statements.

Note 6. Acquisitions and Consolidations

Acquisitions

Transfer of Wind Projects from an Affiliate

On April 1, 2006, EME received, as a capital contribution, ownership interests in a portfolio of wind projects located in Iowa and Minnesota and a small biomass project. The acquisition was accounted for as a transaction between entities under common control. As such, the assets and liabilities of the projects acquired were recorded at historical cost on the acquisition date for a net book value of approximately $76 million. EME's historical financial statements have been adjusted for all periods presented to reflect the acquisition as though EME had always owned the projects. Summarized results of the projects acquired for periods presented prior to the acquisition date of April 1, 2006 are as follows:

	Three Months Ended March 31, 2006			Three Months Ended June 30, 2005			Six Months Ended June 30, 2005
	(in millions)
Total operating revenues	$	4		$	5		$	11
Loss before income taxes		(1	)		—			—
Benefit for income taxes		(3	)		(2	)		(4	)
Income from continuing operations		2			2			4

The principal components of the net book value of assets and liabilities at March 31, 2006 are current assets ($8 million), property, plant and equipment, net ($156 million), other non-current assets ($42 million), deferred income ($56 million) and deferred income taxes ($59 million).

Wildorado Wind Project

On January 5, 2006, EME completed a transaction with Cielo Wildorado, G.P., LLC and Cielo Capital, L.P. to acquire a 99.9% interest in the Wildorado Wind Project, which owns a 161 MW wind farm located in the panhandle of northern Texas, referred to as the Wildorado wind project. The acquisition included all development rights, title and interest held by Cielo in the Wildorado wind project, except for a small minority stake in the project retained by Cielo. The total purchase price was $29 million. As of June 30, 2006, a cash payment of $18 million had been made towards the purchase price. Total project costs of the Wildorado wind project, excluding capitalized interest, are estimated to be approximately $270 million with commercial operations expected to begin in April 2007. The acquisition was accounted for utilizing the purchase method. The fair value of the Wildorado wind project was equal to the purchase price and as a result, the total purchase price was allocated to property, plant and equipment in EME's consolidated balance sheet.

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Consolidations

Variable Interest Entities

In December 2003, the FASB re-issued Statement of Financial Accounting Standards Interpretation No. 46, "Consolidation of Variable Interest Entities" (FIN 46R). FIN 46R defines a variable interest entity as a legal entity whose equity owners do not have sufficient equity at risk or a controlling financial interest in the entity. Under FIN 46R, the primary beneficiary is the variable interest holder that absorbs a majority of expected losses; if no variable interest holder meets this criteria, then it is the variable interest holder that receives a majority of the expected residual returns. The primary beneficiary is required to consolidate the variable interest entity unless specific exceptions or exclusions are met.

EME completed a review of the application of FIN 46R to its subsidiaries and affiliates and concluded that it had significant variable interests in variable interest entities as defined in this Interpretation. As of June 30, 2006, these entities consisted of five equity investments (the Big 4 projects and the Sunrise project) that had interests in natural gas-fired facilities with a total generating capacity of 1,782 MW. An operations and maintenance subsidiary of EME operates the Big 4 projects, but EME does not supply the fuel consumed or purchase the power generated by these facilities. EME determined that it is not the primary beneficiary in these entities; accordingly, EME continues to account for its variable interests on the equity method. EME's maximum exposure to loss in these variable interest entities is generally limited to its investment in these entities, which totaled $324 million as of June 30, 2006.

Note 7. Divestitures

Dispositions

On March 7, 2006, EME completed the sale of a 25% ownership interest in the San Juan Mesa wind project to Citi Renewable Investments I LLC, a wholly owned subsidiary of Citicorp North America, Inc. Proceeds from the sale were $43 million. EME recorded a pre-tax gain on the sale of approximately $4 million during the first quarter of 2006.

Discontinued Operations

Tri Energy Project

On February 3, 2005, EME sold its 25% equity interest in the Tri Energy project pursuant to a Purchase Agreement, dated December 15, 2004, by and between EME and a consortium comprised of International Power plc (70%) and Mitsui & Co., Ltd. (30%), referred to as IPM, for approximately $20 million. EME recorded an impairment charge of approximately $5 million during the fourth quarter of 2004 related to the planned disposition of this investment. The sale of this investment had no significant effect on net income in the first quarter of 2005.

CBK Project

On January 10, 2005, EME sold its 50% equity interest in the CBK project pursuant to a Purchase Agreement, dated November 5, 2004, by and between EME and Corporacion IMPSA S.A. Proceeds from the sale were approximately $104 million. EME recorded a pre-tax gain on the sale of approximately $9 million during the first quarter of 2005.

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Lakeland Project

EME previously owned a 220 MW power plant located in the United Kingdom, referred to as the Lakeland project. An administrative receiver was appointed in 2002 as a result of a default by its counterparty, a subsidiary of TXU Europe Group plc and the project company was subsequently placed in liquidation. In response to its claim against the TXU subsidiary for damages from the termination of the power sales agreement, the Lakeland project received a settlement of £116 million (approximately $217 million). EME is entitled to receive the amount of the settlement remaining after payment of creditor claims. As creditor claims have been settled, EME has received to date payments of £13 million (approximately $24 million) in April 2005, £61 million (approximately $106 million) in the first quarter of 2006, and £9 million (approximately $16 million) in April 2006. The after-tax income attributable to the Lakeland project was $10 million and $24 million for the second quarters of 2006 and 2005, respectively, and $83 million and $24 million for the six months ended June 30, 2006 and 2005, respectively. Beginning in 2002, EME reported the Lakeland project among discontinued operations and accounts for its ownership of Lakeland Power on the cost method, with earnings being recognized as cash is distributed from the project.

Summarized Financial Information for Discontinued Operations

In accordance with SFAS No. 144, all the projects discussed above are classified as discontinued operations in the accompanying consolidated statements of income. Summarized results of discontinued operations are as follows:

	Three Months Ended June 30,				Six Months Ended June 30,
	2006		2005		2006		2005
	(in millions)
Total operating revenues	$	—	$	—	$	—	$	—
Income before income taxes and minority interest		7		22		119		22
Provision (benefit) for income taxes		3		1		42		(1	)
Minority interest		—		—		—		—
Income from operations of discontinued foreign subsidiaries		4		21		77		23
Gain on sale before income taxes		—		—		—		9
Gain on sale after income taxes		—		—		—		5

Assets of $1 million and liabilities of $4 million associated with the discontinued operations are included on the consolidated balance sheet at December 31, 2005 in other long-term assets and other long-term liabilities, respectively.

Note 8. Investments in Unconsolidated Affiliates

The following table presents summarized financial information of the significant subsidiary investments in unconsolidated affiliates accounted for by the equity method. The significant subsidiary investments include the Big 4 projects. The Big 4 projects consist of Kern River Cogeneration

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Company, Midway-Sunset Cogeneration Company, Sycamore Cogeneration Company and Watson Cogeneration Company.

	Three Months Ended June 30,				Six Months Ended June 30,
	2006		2005		2006		2005
	(in millions)
Operating revenues	$	263	$	323	$	572	$	597
Operating income		70		87		123		137
Net income		67		85		117		132

Note 9. Employee Benefit Plans

Pension Plans

EME previously disclosed in its financial statements for the year ended December 31, 2005 that it expected to contribute $14 million to its pension plans in 2006. As of June 30, 2006, $4 million in contributions have been made. EME continues to expect to contribute $14 million to its pension plans in 2006.

Components of pension expense are:

	Three Months Ended June 30,						Six Months Ended June 30,
	2006			2005			2006			2005
	(in millions)
Service cost	$	4		$	4		$	9		$	9
Interest cost		2			2			4			4
Expected return on plan assets		(1	)		(2	)		(3	)		(3	)
Net amortization and deferral		—			1			—			1

Total expense	$	5		$	5		$	10		$	11

Postretirement Benefits Other Than Pensions

EME previously disclosed in its financial statements for the year ended December 31, 2005 that it expected to contribute $1 million to its postretirement benefits other than pensions in 2006. As of June 30, 2006, $0.6 million in contributions have been made. EME continues to expect to contribute $1 million to its postretirement benefits other than pensions in 2006.

Components of postretirement benefits expense are:

	Three Months Ended June 30,					Six Months Ended June 30,
	2006			2005		2006			2005
	(in millions)
Service cost	$	—		$	—	$	1		$	1
Interest cost		1			1		2			2
Amortization of unrecognized prior service costs		(1	)		—		(1	)		(1	)
Amortization of unrecognized loss		1			—		1			—

Total expense	$	1		$	1	$	3		$	2

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Note 10. Income Taxes

EME's income tax provision from continuing operations was $1 million and $19 million for the six months ended June 30, 2006 and 2005, respectively. Income tax benefits are recognized pursuant to a tax-allocation agreement with Edison International. During the six months ended June 30, 2006 and 2005, EME recognized $9 million and $4 million, respectively, of production tax credits related to wind projects and $3 million and $5 million, respectively, related to estimated state income tax benefits allocated from EIX. During the second quarter of 2005, EME resolved a dispute regarding additional taxes asserted by the Internal Revenue Service during the audit of the 1994-1996 tax returns. As a result of the resolution of this item, EME reversed $11.5 million of accrued taxes, recording this amount instead as a reduction of income taxes during the second quarter of 2005.

Note 11. Commitments and Contingencies

Contractual Obligations

Long-term Debt

EME's long-term debt maturities as of June 30, 2006 are (in millions):

July through December 2006	$	25
2007		133
2008		51
2009		613
2010		15

These amounts have been updated primarily to reflect EME's financing activities completed during the second quarter of 2006. See Note 4—Refinancing.

Capital Improvements

Commercial Commitments

Introduction

Turbine Commitments

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delivery in 2007 that were exercised on July 31, 2006. In July 2006, EME entered into an agreement to purchase 20 turbines from another supplier with options to purchase another 32 turbines for delivery in 2007 subject to certain conditions.

Standby Letters of Credit

At June 30, 2006, standby letters of credit aggregated $25 million and were scheduled to expire as follows: $18 million in 2006 and $7 million in 2007.

Guarantees and Indemnities

Tax Indemnity Agreements—

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

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liable and that had not been settled and dismissed at June 30, 2006. Midwest Generation had recorded a $66 million liability at June 30, 2006 related to this matter.

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

Indemnities Provided under Asset Sale Agreements—

The asset sale agreements for the sale of EME's international assets contain indemnities from EME to the purchasers, including indemnification for taxes imposed with respect to operations of the assets prior to the sale and for pre-closing environmental liabilities. During the second quarter of 2006, EME paid $34 million related to an indemnity to IPM for matters arising out of the exercise by one of its project partners of a purported right of first refusal. 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. At June 30, 2006, EME had recorded a liability of $94 million related to these matters.

Guarantee of Brooklyn Navy Yard Contractor Settlement Payments—

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Capacity Indemnification Agreements—

Subsidiary Guarantee for Performance of Unconsolidated Affiliate—

Contingencies

MISO Revenue Sufficiency Guarantee Charges

On April 25, 2006, the FERC issued an order regarding the MISO's "Revenue Sufficiency Guarantee" charges (RSG charges). The MISO's business practice manuals and other instructions to market participants have stated, since the implementation of market operations on April 1, 2005, that RSG charges will not be imposed on offers to supply power not supported by actual generation (also known as virtual supply offers). However, some market participants raised questions about the language of the MISO's tariff concerning that issue and, in October 2005, the MISO submitted to the FERC proposed tariff revisions clarifying its tariff to reflect its business practices with respect to RSG charges and filed corrected tariff sheets exempting virtual supply from RSG charges. In its April 25 decision, the FERC interpreted the MISO's tariff to require that virtual supply offers must be included in the calculation of the RSG charges and that, to the extent that the MISO did not charge virtual supply offers for RSG charges, it violated the terms of its tariff. The FERC order then proceeded to require the MISO to recalculate the RSG charges back to April 1, 2005, and to make refunds to customers, with interest, reflecting the recalculated charges. In order to make such refunds, it is likely that the MISO will attempt to impose retroactively RSG charges on those who submitted virtual supply offers during the recalculation period. Edison Mission Marketing & Trading (EMMT) made virtual supply offers in the MISO during this period on which no RSG charges were imposed, and thus may be subject to a claim for refunds from the MISO (which claim will be contested by EMMT). Because calculation of any claimed liability for refunds depends on information not currently available to it, EMMT cannot reasonably estimate a range of loss related to this matter. In addition, the FERC's April 25 order has been challenged by the MISO and other parties, including EMMT, and as the FERC has issued an extension of time to comply with the requirements of the order until after the date of issuance of an order on rehearing, the eventual outcome of these proceedings is unclear.

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Tax Matters

Litigation

Insurance

Environmental Matters and Regulations

The construction and operation of power plants are subject to environmental regulation by federal, state and local authorities. EME believes that it is in substantial compliance with environmental regulatory requirements and that maintaining compliance with current requirements will not materially affect its financial position or results of operation. However, possible future developments, such as the promulgation of more stringent environmental laws and regulations, future proceedings that may be initiated by environmental authorities, and settlements agreed to by other companies could affect the costs and the manner in which EME conducts its business, and may also 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 as a result.

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

With respect to potential liabilities arising under the Comprehensive Environmental Response, Compensation and Liability Act of 1980, commonly referred to as CERCLA, or similar laws for the investigation and remediation of contaminated property, EME accrues a liability to the extent that the costs are probable and can be reasonably estimated. Midwest Generation has accrued approximately $4 million at June 30, 2006 for estimated environmental investigation and remediation costs for the

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Illinois Plants. This estimate is based upon the number of sites, the scope of work and the estimated costs for environmental activity where such expenditures could be reasonably estimated. Future estimated costs may vary based on changes in regulations or requirements of federal, state or local governmental agencies, changes in technology, and actual costs of disposal. In addition, future remediation costs will be affected by the nature and extent of contamination discovered at the sites that requires remediation. Given the prior history of the operations at its facilities, EME cannot be certain that the existence or extent of all contamination at its sites has been fully identified. However, based on available information, management believes that future costs in excess of the amounts disclosed on all known and quantifiable environmental contingencies will not be material to EME's financial position. See "Note 16. Commitments and Contingencies—Environmental Matters and Regulations" in EME's financial statements included in its annual report on Form 10-K for the year ended December 31, 2005 for a more complete discussion of EME's environmental contingencies.

Note 12. Supplemental Statements of Cash Flows Information

		Six Months Ended June 30,
		2006		2005
		(in millions)
Cash paid (received)
	Interest (net of amount capitalized)	$	163	$	149
	Income taxes		168		2
	Cash payments under plant operating leases		199		154
Details of assets acquired
	Fair value of assets acquired	$	29	$	—
	Liabilities assumed		—		—

During the first six months of 2006, EME accrued $11 million in connection with the purchase price of the Wildorado wind project due upon completion of construction. In addition, EME received a capital contribution of $76 million in the form of ownership interests in a portfolio of wind projects and a small biomass project.

Note 13. Stock Compensation Plans

Stock Options

Under various plans, EME may grant stock options at exercise prices equal to the average of high and low price at the grant date and other awards related to or with a value derived from Edison International common stock to directors and certain employees. Options generally expire 10 years after the grant date and vest over a period of four years of continuous service, with expense recognized evenly over the vesting period, except for awards granted to retirement-eligible participants, as discussed in Note 1—General—Stock-Based Compensation. Stock-based compensation expense associated with stock options was $2 million and $4 million for the second quarter of 2006 and six months ended June 30, 2006, respectively. Under prior accounting rules, there was no comparable expense recognized for the same periods in 2005. See Note 1—General—Stock-Based Compensation, for further discussion.

Beginning with awards made in 2003, stock options accrue dividend equivalents for the first five years of the option term. Unless transferred to non-qualified deferral plan accounts, dividend equivalents accumulate without interest. Dividend equivalents are paid only on options that vest, including options that are unexercised. Dividend equivalents are paid in cash after the vesting date.

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Edison International has discretion to pay certain dividend equivalents in shares of Edison International common stock. Additionally, Edison International will substitute cash awards to the extent necessary to pay tax withholding or any government levies.

The fair value for each option granted was determined as of the grant date using the Black-Scholes option-pricing model. The Black-Scholes option-pricing model requires various assumptions noted in the following table.

	Three Months Ended June 30,		Six Months Ended June 30,
	2006	2005	2006	2005
Expected terms (in years)	9 to 10	9 to 10	9 to 10	9 to 10
Risk-free interest rate	4.3%-4.5%	4.2%-4.3%	4.3%-4.5%	4.2%-4.3%
Expected dividend yield	2.6%-2.8%	2.5%-2.8%	2.4%-2.8%	2.5%-3.1%
Weighted-average expected dividend yield	2.7%	2.7%	2.4%	3.1%
Expected volatility	16.8%-17.5%	18.7%-19.2%	16.2%-17.5%	18.7%-19.6%
Weighted-average volatility	17.2%	18.9%	16.3%	19.6%

The expected term of options granted is based on the actual remaining contractual term of the options. The risk-free interest rate for periods within the contractual life of the option is based on a 52-week historical average of the 10-year semi-annual coupon U.S. Treasury note. In 2006, expected volatility is based on the historical volatility of Edison International's common stock for the recent 36 months. Prior to January 1, 2006, expected volatility was based on the median of the most recent 36 months historical volatility of peer companies because Edison International's historical volatility was impacted by the California energy crisis.

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

			Weighted Average
	Stock Options		Exercise Price		Remaining Contractual Term (Years)	Aggregate Intrinsic Value
Outstanding at December 31, 2005	3,626,365		$	22.06
Granted	407,848			44.11
Transferred to affiliates	(298,647	)		21.83
Forfeited	(27,949	)		28.35
Exercised	(379,482	)		18.73

Outstanding at June 30, 2006	3,328,135		$	25.10

Vested and expected to vest at June 30, 2006	3,195,872		$	24.86	7.00	$	48,249,676

Exercisable at June 30, 2006	1,690,208		$	20.30	5.89	$	33,225,264

The weighted-average fair value of options granted during the quarters ended June 30, 2006 and 2005 was $13.47 and $13.31, respectively. The weighted-average fair value of options granted for the six months ended June 30, 2006 and 2005 was $14.42 and $11.72, respectively. The total intrinsic value of options exercised during the quarters ended June 30, 2006 and 2005 was $3 million and $7 million, respectively. The total intrinsic value of options exercised for the six months ended June 30, 2006 and 2005 was $11 million and $10 million, respectively. At June 30, 2006, there was $12 million of total unrecognized compensation cost related to stock options net of expected forfeitures. That cost is expected to be recognized over a weighted-average period of approximately 2 years. The fair value of

F-21

options vested during the quarters and six-month periods ended June 30, 2006 and 2005, was $1 million and $2 million, respectively.

Cash received from options exercised for the quarters ended June 30, 2006 and 2005 was $3 million and $6 million, respectively, and for the six months ended June 30, 2006 and 2005 was $8 million and $9 million, respectively. The estimated tax benefit from options exercised was $4 million for both the six months ended June 30, 2006 and 2005.

Performance Shares

A target number of contingent performance shares were awarded to executives in January 2004, January 2005 and March 2006, and vest at the end of December 2006, 2007 and 2008, respectively. Dividend equivalents associated with these performance shares accumulate without interest and will be payable in cash following the end of the performance period when the performance shares are paid, although Edison International has discretion to pay certain dividend equivalents in Edison International common stock. The vesting of Edison International's performance shares is dependent upon a market condition and three years of continuous service subject to a prorated adjustment for employees who are terminated under certain circumstances or retire, but payment cannot be accelerated. The market condition is based on Edison International's common stock performance relative to the performance of a specified group of companies at the end of a three-calendar-year period. The number of performance shares earned is determined based on Edison International's ranking among these companies. Dividend equivalents will be adjusted to correlate to the actual number of performance shares paid. Performance shares earned are settled half in cash and half in common stock; however, Edison International has discretion under certain of the awards to pay the half subject to cash settlement in common stock. Additionally, cash awards are substituted to the extent necessary to pay tax withholding or any government levies. The portion of performance shares settled in cash is classified as a share-based liability award. The fair value of these shares is remeasured at each reporting period and the related compensation expense is adjusted. The portion of performance shares payable in common stock is classified as a share-based equity award. Compensation expense related to these shares is based on the grant-date fair value. Performance shares expense is recognized ratably over the vesting period based on the fair values determined, except for awards granted to retirement-eligible participants, as discussed in "Stock-Based Compensation" in Note 1—General—Stock-Based Compensation. Stock-based compensation expense associated with performance shares was $0.1 million and $5.0 million for the quarters ended June 30, 2006 and 2005, respectively, and $0.5 million and $9.0 million for the six months ended June 30, 2006 and 2005, respectively.

The performance shares' fair value is determined using a Monte Carlo simulation valuation model. The Monte Carlo simulation valuation model requires a risk-free interest rate and an expected volatility rate assumption. The risk-free interest rate is based on a 52-week historical average of the three-year U.S. Treasury note and is used as proxy for the expected return for the specified group of companies. Volatility is based on the historical volatility of Edison International's common stock for the recent 36 months. Historical volatility for each company in the specified group is obtained from a financial data services provider.

Edison International's risk-free interest rate and expected volatility used to determine the grant date fair values for the 2006 and 2005 performance shares classified as share-based equity awards was 4.1% and 16.2%, respectively, and 2.7% and 27.7%, respectively. The portion of performance shares classified as share-based liability awards are revalued at each reporting period. The risk-free interest rate and expected volatility rate used to determine the fair value as of June 30, 2006 was 4.5% and 17.2%, respectively.

F-22

The total intrinsic value of performance shares settled during each of the quarters ended June 30, 2006 and 2005 was zero. The total intrinsic value of performance shares settled during the six months ended June 30, 2006 and 2005 was $19 million and $8 million, respectively, which included cash paid to settle the performance shares classified as liability awards of $8 million and $4 million for the six months ended June 30, 2006 and 2005, respectively. At June 30, 2006, there was $2 million (based on the June 30, 2006 fair value of performance shares classified as liability awards) of total unrecognized compensation cost related to performance shares. That cost is expected to be recognized over a weighted-average period of less than two years. The fair values of performance shares vested during the quarters and six-month periods ended June 30, 2006 and 2005, was zero.

A summary of the status of Edison International nonvested performance shares granted to EME employees and classified as equity awards is as follows:

	Performance Shares		Weighted-Average Grant-Date Fair Value
Nonvested at December 31, 2005	67,530		$	38.63
Granted	16,377			52.55
Forfeited	(1,266	)		39.36

Nonvested at June 30, 2006	82,641		$	41.38

The weighted-average grant-date fair value of performance shares classified as equity awards granted during the quarter ended June 30, 2005 was $46.09.

A summary of the status of Edison International nonvested performance shares granted to EME employees and classified as liability awards (the current portion is reflected in the caption "Accrued liabilities" and the long-term portion is reflected in "Other long-term liabilities" on the consolidated balance sheets) is as follows:

	Performance Shares		Weighted-Average Fair Value
Nonvested at December 31, 2005	67,547
Granted	16,396
Forfeited	(1,267	)

Nonvested at June 30, 2006	82,676		$	80.84

Note 14. New Accounting Pronouncements

Statement of Financial Accounting Standards No. 151

F-23

Statement of Financial Accounting Standards No. 123(R)

FASB Staff Position FIN 46(R)-6

Statement of Financial Accounting Standards Interpretation No. 48

F-24

EDISON MISSION ENERGY AND SUBSIDIARIES
REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To the Board of Directors and Shareholder of Edison Mission Energy:

In our opinion, the accompanying consolidated balance sheets and the related consolidated statements of income, comprehensive income, shareholder's equity and cash flows present fairly, in all material respects, the financial position of Edison Mission Energy and its subsidiaries at December 31, 2005 and 2004, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2005 in conformity with accounting principles generally accepted in the United States of America. In addition, in our opinion, the financial statement schedules "Condensed Financial Information of Parent" and "Valuation and Qualifying Accounts" present fairly, in all material respects, the information set forth therein when read in conjunction with the related consolidated financial statements. These financial statements and financial statement schedules are the responsibility of the Company's management. Our responsibility is to express an opinion on these financial statements and financial statement schedules based on our audits. We conducted our audits of these statements in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, and evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.

As discussed in Note 3 to the consolidated financial statements, the Company changed the manner in which it accounts for asset retirement costs as of January 1, 2003 and December 31, 2005. As discussed in Note 7 to the consolidated financial statements, the Company changed the manner in which it accounts for variable interest entities as of March 31, 2004.

/s/ PricewaterhouseCoopers LLP
Los Angeles, California
March 6, 2006 except for Note 21, as to which the date is September 25, 2006

F-25

EDISON MISSION ENERGY AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF INCOME
(In millions)

			Years Ended December 31,
			2005			2004			2003
Operating Revenues
	Electric revenues		$	2,151		$	1,619		$	1,702
	Net gains from price risk management and energy trading			90			9			48
	Operation and maintenance services			24			25			29

		Total operating revenues		2,265			1,653			1,779

Operating Expenses
	Fuel			617			619			669
	Plant operations			470			472			438
	Plant operating leases			177			186			206
	Operation and maintenance services			23			23			21
	Depreciation and amortization			134			152			156
	Loss on lease termination, asset impairment and other charges			7			989			304
	Administrative and general			154			149			138

		Total operating expenses		1,582			2,590			1,932

	Operating income (loss)			683			(937	)		(153	)

Other Income (Expense)
	Equity in income from unconsolidated affiliates			229			218			239
	Impairment loss on equity method investment			(55	)		—			—
	Interest income			62			10			7
	Other income (expense), net			7			(1	)		(5	)
	Gain on sale of assets			—			43			—
	Loss on early extinguishment of debt			(4	)		—			—
	Interest expense			(300	)		(298	)		(296	)
	Dividends on preferred securities			—			—			(7	)

		Total other income (expense)		(61	)		(28	)		(62	)

	Income (loss) from continuing operations before income taxes and minority interest			622			(965	)		(215	)
	Provision (benefit) for income taxes			208			(406	)		(121	)
	Minority interest			—			(1	)		(2	)

Income (Loss) From Continuing Operations				414			(560	)		(96	)

Income from operations of discontinued subsidiaries (including gain on disposal of $533 million in 2004), net of tax (Note 8)				29			690			124

Income Before Accounting Change				443			130			28
Cumulative effect of change in accounting, net of tax (Note 3)				(1	)		—			(9	)

Net Income			$	442		$	130		$	19

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

F-26

EDISON MISSION ENERGY AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
(In millions)

			December 31,
			2005		2004
Assets
Current Assets
	Cash and cash equivalents		$	1,155	$	2,272
	Short-term investments			183		140
	Accounts receivable—trade			337		211
	Accounts receivable—affiliates			18		65
	Inventory			120		107
	Assets under price risk management and energy trading			78		41
	Margin and collateral deposits			561		42
	Deferred taxes			155		—
	Prepaid expenses and other			68		96

		Total current assets		2,675		2,974

Investments in Unconsolidated Affiliates				405		474

Property, Plant and Equipment				3,856		3,683
	Less accumulated depreciation and amortization			844		747

		Net property, plant and equipment		3,012		2,936

Other Assets
	Deferred financing costs			43		49
	Long-term assets under price risk management and energy trading			90		90
	Restricted cash			105		155
	Rent payments in excess of levelized rent expense under plant operating leases			395		277
	Long-term margin and collateral deposits			137		—
	Other long-term assets			160		21

		Total other assets		930		592

Assets of Discontinued Operations				1		111

Total Assets			$	7,023	$	7,087

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

F-27

EDISON MISSION ENERGY AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
(In millions)

			December 31,
			2005			2004
Liabilities and Shareholder's Equity
Current Liabilities
	Accounts payable—affiliates		$	32		$	30
	Accounts payable			64			52
	Accrued liabilities			207			268
	Dividends payable			—			305
	Liabilities under price risk management and energy trading			418			31
	Interest payable			51			56
	Current maturities of long-term obligations			74			252

		Total current liabilities		846			994

Long-term obligations net of current maturities				3,330			3,530
Deferred taxes and tax credits				227			270
Long-term liabilities under price risk management and energy trading				83			—
Other long-term liabilities				594			538
Liabilities of discontinued operations				4			5

Total Liabilities				5,084			5,337

Minority Interest				29			5

Commitments and Contingencies (Notes 11, 12, 16 and 17)
Shareholder's Equity
	Common stock, par value $0.01 per share; 10,000 shares authorized; 100 shares issued and outstanding as of December 31, 2005 and 2004			64			64
	Additional paid-in capital			2,228			2,277
	Retained deficit			(171	)		(613	)
	Accumulated other comprehensive income (loss)			(211	)		17

Total Shareholder's Equity				1,910			1,745

Total Liabilities and Shareholder's Equity			$	7,023		$	7,087

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

F-28

EDISON MISSION ENERGY AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF SHAREHOLDER'S EQUITY
(In millions)

		Common Stock		Additional Paid-in Capital			Retained Deficit			Accumulated Other Comprehensive Income (Loss)			Total Shareholder's Equity
Balance at December 31, 2002		$	64	$	2,660		$	(762	)	$	(212	)	$	1,750
	Net income							19						19
	Other comprehensive income										190			190
	Cash distribution to parent				(5	)								(5	)

Balance at December 31, 2003			64		2,655			(743	)		(22	)		1,954
	Net income							130						130
	Other comprehensive income										39			39
	Cash contribution from parent				4									4
	Dividend payable to parent				(305	)								(305	)
	Cash dividends to parent				(74	)								(74	)
	Payments to Edison International for stock option price appreciation on options exercised				(8	)								(8	)
	Other stock transactions, net				5									5

Balance at December 31, 2004			64		2,277			(613	)		17			1,745
	Net income							442						442
	Other comprehensive loss										(228	)		(228	)
	Non-cash equity contribution				20									20
	Cash dividends to parent				(62	)								(62	)
	Payments to Edison International for stock option price appreciation on options exercised				(4	)								(4	)
	Other stock transactions, net				(3	)								(3	)

Balance at December 31, 2005		$	64	$	2,228		$	(171	)	$	(211	)	$	1,910

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

F-29

EDISON MISSION ENERGY AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME
(In millions)

			Years Ended December 31,
			2005			2004			2003
Net Income			$	442		$	130		$	19
Other comprehensive income, net of tax:
	Foreign currency translation adjustments:
		Foreign currency translation adjustments, net of income tax expense of $4 and $5 for 2004 and 2003, respectively		—			(18	)		154
		Reclassification adjustments for sale of investment in a foreign subsidiary		—			(127	)		—
	Minimum pension liability adjustment, net of income tax effect			—			10			(1	)
	Unrealized gains (losses) on derivatives qualified as cash flow hedges:
		Other unrealized holding gains (losses) arising during period, net of income tax expense (benefit) of $(54), $(6) and $2 for 2005, 2004 and 2003, respectively		(69	)		86			47
		Reclassification adjustments included in net income (loss), net of income tax expense (benefit) of $107, $(64) and $(1) for 2005, 2004 and 2003, respectively		(159	)		88			(10	)

Other comprehensive income				(228	)		39			190

Comprehensive Income			$	214		$	169		$	209

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

F-30

EDISON MISSION ENERGY AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CASH FLOWS
(In millions)

			Years Ended December 31,
			2005			2004 Revised(1)			2003 Revised(1)
Cash Flows From Operating Activities
	Net income		$	442		$	130		$	19
	Less: Income from discontinued operations			(29	)		(690	)		(124	)

	Income (loss) from continuing operations, net			413			(560	)		(105	)
	Adjustments to reconcile income to net cash provided by (used in) operating activities:
		Equity in income from unconsolidated affiliates		(227	)		(215	)		(255	)
		Distributions from unconsolidated affiliates		222			228			375
		Depreciation and amortization		142			152			156
		Minority interest		—			1			2
		Deferred taxes and tax credits		(76	)		(21	)		(19	)
		Gain on sale of assets		—			(43	)		—
		Loss on early extinguishment of debt		4			—			—
		Impairment charges		62			35			304
		Cumulative effect of change in accounting, net of tax		1			—			9
	Changes in operating assets and liabilities:
		Increase in margin and collateral deposits		(656	)		(30	)		—
		Increase in accounts receivable		(118	)		(52	)		(2	)
		Decrease (increase) in inventory		(13	)		11			28
		Decrease in prepaid expenses and other		13			15			32
		Increase in rent payments in excess of levelized rent expense		(117	)		(59	)		(96	)
		Increase (decrease) in accounts payable and accrued liabilities		9			85			(34	)
		Increase (decrease) in interest payable		(4	)		12			(9	)
		Decrease in net assets under risk management		41			13			1
		Other operating-assets		4			13			(6	)
		Other operating-liabilities		61			62			28

				(239	)		(353	)		409
	Operating cash flow from discontinued operations			20			(434	)		243

		Net cash provided by (used in) operating activities		(219	)		(787	)		652

Cash Flows From Financing Activities
	Borrowing on long-term debt and lease swap agreements			330			1,795			796
	Payments on long-term debt agreements			(712	)		(1,706	)		(1,252	)
	Cash contribution from parent			—			3			11
	Cash distribution to parent			(7	)		—			—
	Cash dividends to parent			(360	)		(74	)		—
	Payments for price appreciation on stock options exercised			(18	)		(5	)		—
	Financing costs			(6	)		(34	)		(19	)

				(773	)		(21	)		(464	)
	Financing cash flow from discontinued operations			—			(144	)		153

		Net cash used in financing activities		(773	)		(165	)		(311	)

Cash Flows From Investing Activities
	Investments in and loans to energy projects			—			—			(22	)
	Purchase of common stock of acquired companies			(154	)		—			(3	)
	Capital expenditures			(61	)		(55	)		(81	)
	Proceeds from sale of interest in projects			—			118			36
	Proceeds from sales of discontinued operations			124			2,740			—
	Purchases of short-term investments			(183	)		(301	)		(318	)
	Sales of short-term investments			140			181			298
	Decrease (increase) in restricted cash			41			30			(12	)
	Turbine deposits			(57	)		—			—
	Proceeds from (investments in) other assets			16			(6	)		6

				(134	)		2,707			(96	)
	Investing cash flow from discontinued operations			5			18			(413	)

		Net cash provided by (used in) investing activities		(129	)		2,725			(509	)

Effect of exchange rate changes on cash				—			50			5
Effect of consolidation of variable interest entities on cash				3			1			—
Effect on cash from deconsolidation of subsidiary				—			(34	)		—

Net increase (decrease) in cash and cash equivalents				(1,118	)		1,790			(163	)
Cash and cash equivalents at beginning of period				2,274			484			647

Cash and cash equivalents at end of period				1,156			2,274			484
Cash and cash equivalents classified as part of discontinued operations				(1	)		(2	)		(191	)

Cash and cash equivalents of continuing operations			$	1,155		$	2,272		$	293

(1): See Note 2—Revisions for further explanation.
The accompanying notes are an integral part of these consolidated financial statements.

F-31

EDISON MISSION ENERGY AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Note 1. General

Organization

Edison Mission Energy (EME) is a wholly owned subsidiary of Mission Energy Holding Company (MEHC), which is a wholly owned subsidiary of Edison Mission Group Inc., which is a wholly owned, non-utility subsidiary of Edison International, which is also the parent holding company of Southern California Edison Company and Edison Capital. Through its subsidiaries, EME is engaged in the business of developing, acquiring, owning or leasing, operating and selling energy and capacity from independent power production facilities. EME also conducts price risk management and energy trading activities in power markets open to competition.

On April 1, 2006, EME received, as a capital contribution, ownership interests in a portfolio of wind projects located in Iowa and Minnesota and a small biomass project. See Note 21—Subsequent Events, for further discussion. These projects were previously owned by EME's affiliate, Edison Capital. EME accounted for this acquisition at Edison Capital's historical cost as a transaction between entities under common control. Therefore, these consolidated financial statements include the results of operations, financial position and cash flows of the acquired projects as though EME had such ownership throughout the periods presented.

Note 2. Summary of Significant Accounting Policies

Basis of Consolidation

The consolidated financial statements include the accounts of EME and all subsidiaries and partnerships in which EME has a controlling interest and variable interest entities in which EME is deemed the primary beneficiary. EME's investments in unconsolidated affiliates in which a significant, but less than controlling, interest is held and variable interest entities, in which EME is not deemed to be the primary beneficiary, are accounted for by the equity method. Refer to Note 7—Acquisitions and Consolidations—Consolidations, for a discussion of EME's adoption of an accounting standard on variable interest entities. All significant intercompany transactions and balances have been eliminated in the consolidated financial statements.

Reclassifications

Revisions

EME revised its Consolidated Statements of Cash Flows for the years ended December 31, 2004 and 2003 to separately disclose the operating, financing and investing portions of the cash flows attributable to its discontinued operations. EME had previously reported these amounts on a combined basis.

F-32

Management's Use of Estimates

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

Cash Equivalents

Cash equivalents include time deposits and other investments totaling $1.1 billion and $2.2 billion at December 31, 2005 and 2004, respectively, with original maturities of three months or less. Time deposits and certificates of deposit totaled $411 million and $200 million at December 31, 2005 and 2004, respectively.

Short-term Investments

At December 31, 2005, EME had classified all marketable securities as held-to-maturity under Statement of Financial Accounting Standards No. 115, "Accounting for Certain Investments in Debt and Equity Securities" (SFAS No. 115). The securities were carried at amortized cost plus accrued interest which approximated their fair value. At December 31, 2005, all held-to-maturity securities mature within one year and consisted of $99 million of commercial paper, $50 million in time deposits and $34 million in certificates of deposit.

At December 31, 2004, EME had classified all marketable securities as available-for-sale under SFAS No. 115. The fair market value of the securities was $140 million and consisted of auction rate securities rated AAA or Aaa by S&P or Moody's, respectively, with interest rate reset dates of less than thirty days. Sales of auction rate securities were $140 million in 2005. Purchases and sales of auction rate securities were $301 million and $181 million in 2004, respectively. Unrealized gains and losses from investments in theses securities were not material.

Margin and Collateral Deposits

Margin and collateral deposits include cash deposited with counterparties and brokers as credit support under energy contracts. The amount of margin and collateral deposits generally varies based on changes in fair value of the related positions.

Property, Plant and Equipment

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

As part of the acquisition of the Illinois Plants and the Homer City facilities, EME acquired emission allowances under the United States Environmental Protection Agency's Acid Rain Program. Although the emission allowances granted under this program are freely transferable, EME intends to use substantially all the emission allowances in the normal course of its business to generate electricity. Accordingly, EME has classified emission allowances expected to be used by EME to generate power

F-33

as part of property, plant and equipment. Acquired emission allowances will be amortized over the estimated lives of the plants on a straight-line basis.

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

Power plant facilities		3-34.5 years
Leasehold improvements		Life of lease
Emission allowances		25-34.5 years
Equipment, furniture and fixtures		3-7 years
Capitalized leased equipment		5 years

Rent Expense

Rent expense under all operating leases is levelized over the terms of the leases. Operating leases primarily consist of long-term leases for the Powerton, Joliet and Homer City power plants. See Note 17—Lease Commitments for additional information on these sale-leaseback transactions.

Impairment of Investments and Long-Lived Assets

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

Capitalized Interest

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

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

	Years Ended December 31,
	2005		2004		2003
	(in millions)
Interest incurred	$	300	$	298	$	303
Interest capitalized		—		—		(7	)

	$	300	$	298	$	296

Income Taxes

EME is included in the consolidated federal and state income tax returns of Edison International and participates in tax-allocation and payment agreements with other subsidiaries of Edison International. EME calculates its tax provision in accordance with these tax agreements. EME's current

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tax liability or benefit is determined on a "with and without" basis. This means Edison International computes its combined federal and state tax liabilities including and excluding EME's taxable income or loss and state apportionment factors. This method is similar to a separate company return, except that EME recognizes, without regard to separate company limitations, additional tax liabilities or benefits based on the impact to the combined group of including EME's taxable income or losses and state apportionment factors.

EME accounts for deferred income taxes using the asset-and-liability method, wherein deferred tax assets and liabilities are recognized for future tax consequences of temporary differences between the carrying amounts and the tax bases of assets and liabilities using enacted income tax rates. Investment and energy tax credits are deferred and amortized over the term of the power purchase agreement of the respective project. Income tax accounting policies are discussed further in Note 13—Income Taxes.

EME's investments in wind-powered electric generation projects qualify for federal production tax credits under Section 45 of the Internal Revenue Code. Such credits are allowable for production during the 10-year period after a qualifying wind energy facility is placed into service. Production tax credits are recognized by EME when the corresponding electricity is produced.

Maintenance Accruals

Certain of EME's plant facilities' major pieces of equipment require major maintenance on a periodic basis. These costs are expensed as incurred.

Project Development Costs

EME capitalizes direct costs incurred in developing new projects upon attainment of principal activities needed to commence procurement and construction. These costs consist of professional fees, salaries, permits, and other directly related development costs incurred by EME. The capitalized costs are amortized over the life of operational projects or charged to expense if management determines the costs to be unrecoverable.

Deferred Financing Costs

Bank, legal and other direct costs incurred in connection with obtaining financing are deferred and amortized as interest expense on a basis which approximates the effective interest rate method over the term of the related debt. Accumulated amortization of these costs amounted to $25 million in 2005 and $19 million in 2004.

Revenue Recognition

EME is primarily an independent power producer, operating a portfolio of owned and leased plants and plants which are accounted for under the equity method. EME's subsidiaries enter into power and fuel hedging, optimization transactions and energy trading contracts, all subject to market conditions. One of EME's subsidiaries executes these transactions primarily through the use of physical forward commodity purchases and sales and financial commodity swaps and options. With respect to its physical forward contracts, EME's subsidiaries generally act as the principal, take title to the commodities, and assume the risks and rewards of ownership. Therefore, EME's subsidiaries record settlement of non-trading physical forward contracts on a gross basis. Consistent with Emerging Issues Task Force No. 03-11, "Reporting Realized Gains and Losses on Derivative Instruments that are Subject to FASB Statement No. 133, Accounting for Derivative Instruments and Hedging Activities, and Not Held for Trading Purposes," EME nets the cost of purchased power against related third party

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sales in markets that use locational marginal pricing, currently PJM. Financial swap and option transactions are settled net and, accordingly, EME's subsidiaries do not take title to the underlying commodity. Therefore, gains and losses from settlement of financial swaps and options are recorded net. Managed risks typically include commodity price risk associated with fuel purchases and power sales.

EME records revenue and related costs as electricity is generated or services are provided unless EME is subject to Statement of Financial Accounting Standards No. 133, "Accounting for Derivative Instruments and Hedging Activities" and does not qualify for the normal sales and purchases exception.

Derivative Instruments

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

SFAS No. 133 sets forth the accounting requirements for cash flow hedges. SFAS No. 133 provides that the effective portion of the gain or loss on a derivative instrument designated and qualifying as a cash flow hedging instrument be reported as a component of other comprehensive income and be reclassified into earnings in the same period during which the hedged forecasted transaction affects earnings. The remaining gain or loss on the derivative instrument, if any, must be recognized currently in earnings.

Financial instruments that are utilized for trading purposes are measured at fair value and included in the balance sheet as assets or liabilities from energy trading activities. In the absence of quoted market prices, financial instruments are valued at fair value, considering time value, volatility of the underlying commodity, and other factors as determined by EME. Resulting gains and losses are recognized in net gains from price risk management and energy trading in the accompanying Consolidated Income Statements in the period of change. Assets from price risk management and energy trading activities include the fair value of open financial positions related to trading activities and the present value of net amounts receivable from structured transactions. Liabilities from price risk management and energy trading activities include the fair value of open financial positions related to trading activities and the present value of net amounts payable from structured transactions.

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

Stock-Based Compensation

At December 31, 2005, Edison International has stock-based compensation plans, which are described more fully in Note 15—Stock Compensation Plans. EME has accounted 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

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underlying common stock on the date of grant. The following table illustrates the effect on net income if EME had used the fair value accounting method.

	Years Ended December 31,
	2005			2004			2003
	(in millions)
Net income, as reported	$	442		$	130		$	19
Add: Stock-based compensation expense included in reported net income, net of related tax effects		13			14			6
Deduct: Total stock-based employee compensation expense determined under fair value based method, net of related tax effects		(10	)		(12	)		(6	)

Pro forma net income	$	445		$	132		$	19

As noted in "—New Accounting Pronouncements—Statement of Financial Accounting Standards No. 123(R)" below, EME is required to use the fair value accounting method for stock-based employee compensation beginning in the first quarter of 2006.

New Accounting Pronouncements

Statement of Financial Accounting Standards No. 151

In November 2004, the FASB issued SFAS No. 151, "Inventory Costs." SFAS No. 151 requires that abnormal amounts of idle facility expense, freight, handling costs and spoilage be recognized as current-period charges. Further, SFAS No. 151 requires the allocation of fixed production overheads to inventory based on the normal capacity of the production facilities. Unallocated overheads must be recognized as an expense in the period in which they are incurred. SFAS No. 151 is effective for inventory costs incurred beginning in the first quarter of 2006. EME does not expect the adoption of this standard to have a material impact on EME's consolidated financial statements.

Statement of Financial Accounting Standards No. 123(R)

A new accounting standard requires companies to use the fair value accounting method for stock-based compensation. EME is required to implement the new standard in the first quarter of 2006, and will apply the modified prospective transition method. Under the modified prospective method, the new accounting standard will be applied; effective January 1, 2006, to the unvested portion of awards previously granted and will be applied to all prospective awards. Prior financial statements will not be restated under this method. The new accounting standard will result in the recognition of expense for all stock-based compensation awards where EME previously used the intrinsic value method of accounting, at times resulting in no recognition of expense for stock-based compensation.

Note 3. Asset Retirement Obligations

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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.

In March 2005, the FASB issued FIN 47, Accounting for Conditional Asset Retirement Obligations (AROs), an interpretation of SFAS 143. This interpretation clarifies that an entity is required to recognize a liability for the fair value of a conditional ARO if the fair value can be reasonably estimated even though uncertainty exists about the timing and/or method of settlement. This interpretation became effective as of December 31, 2005 for EME. EME identified conditional AROs related to asbestos removal and disposal costs at its owned Illinois Plants (buildings and power plant facilities) and retired structures leased at the Powerton Station. EME recorded a $1 million, after tax, charge as a cumulative effect adjustment for asbestos removal and disposal activities associated with retired Powerton structures that are currently scheduled for demolition in 2007. EME has not recorded a liability related to the owned structures because it cannot reasonably estimate fair value of the obligation at this time. The range of time over which EME may settle this obligation in the future (demolition or other method) is sufficiently large to not allow for the use of expected present value techniques.

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

	2005		2004		2003
	(in millions)
Beginning balance	$	5	$	5	$	4
Cumulative effect of accounting change		2		—		—
Accretion expense		—		—		1

Ending balance	$	7	$	5	$	5

The pro forma net income effect of adopting FIN 47 is not shown due to its immaterial impact on EME's results of operations. The pro forma liability for conditional AROs is not shown due to the immaterial impact on EME's consolidated balance sheet.

Note 4. Inventory

Inventory is stated at the lower of weighted average cost or market. Inventory at December 31, 2005 and December 31, 2004 consisted of the following:

	2005		2004
	(in millions)
Coal and fuel oil	$	77	$	65
Spare parts, materials and supplies		43		42

Total	$	120	$	107

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Note 5. Restructuring, Loss on Lease Termination, Asset Impairment and Other Charges

Restructuring Costs

During the first quarter of 2005, EME initiated a review of its domestic organization to better align its resources with its domestic business requirements. Management and organizational changes have been implemented to streamline EME's reporting relationships and eliminate its regional management structure. As a result of these changes, EME recorded charges of approximately $13 million (pre-tax) in 2005 for severance and related costs. These charges were included in administrative and general expense on EME's consolidated statement of income.

Loss on Lease Termination, Asset Impairment and Other Charges

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

Following the termination of the Collins Station lease, Midwest Generation announced plans on May 28, 2004 to permanently cease operations at the Collins Station by December 31, 2004 and decommission the plant. By the fourth quarter of 2004, the Collins Station was decommissioned and all units were permanently retired from service, disconnected from the grid, and rendered inoperable, with all operating permits surrendered. In September 2004, EME recorded a pre-tax impairment charge of $5 million resulting from the termination of the power purchase agreement effective September 30, 2004 for the two units at the Collins Station that remained under contract. In addition, EME recognized a $4 million pre-tax charge for exit costs recorded as part of plant operations on EME's consolidated income statement related to reducing the workforce in Illinois during the fourth quarter of 2004.

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

During 2003, EME recorded asset impairment charges of $304 million, consisting of $245 million related to eight small peaking plants owned by Midwest Generation in Illinois and $53 million and $6 million to write down the estimated net proceeds from the planned sale of the Brooklyn Navy Yard and Gordonsville projects, respectively. The impairment charge related to the peaking plants in Illinois resulted from a revised long-term outlook for capacity revenues from the peaking plants. The lower capacity revenue outlook is the result of a number of factors, including higher long-term natural gas prices and current generation overcapacity. The book value of these assets was written down from

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$286 million to an estimated fair market value of $41 million. The estimated fair market value was determined based on discounting estimated future pretax cash flows using a 17.5% discount rate.

Note 6. Accumulated Other Comprehensive Income (Loss)

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

		Currency Translation Adjustments			Unrealized Gains (Losses) on Cash Flow Hedges			Minimum Pension Liability Adjustment			Accumulated Other Comprehensive Income (Loss)
		(in millions)
Balance at December 31, 2003		$	145		$	(156	)	$	(11	)	$	(22	)
	Change for 2004		(145	)		174			10			39

Balance at December 31, 2004			—			18			(1	)		17
	Change for 2005		—			(228	)		—			(228	)

Balance at December 31, 2005		$	—		$	(210	)	$	(1	)	$	(211	)

Unrealized losses on cash flow hedges, net of tax, at December 31, 2005, include unrealized losses on commodity hedges primarily related to Midwest Generation and EME Homer City Generation L.P. (EME Homer City) futures and forward electricity contracts that qualify for hedge accounting. These losses arise because current forecasts of future electricity prices in these markets are greater than the contract prices. The increase in the unrealized losses during 2005 resulted from a combination of new hedges for 2006 and 2007 and an increase in market prices for power driven largely from higher natural gas and oil prices. In addition, EME reclassified a $9 million, after tax, unrealized gain from other comprehensive loss to earnings due to the impairment of its equity investment in the March Point project in 2005.

As EME's hedged positions for continuing operations are realized, approximately $178 million, after tax, of the net unrealized losses on cash flow hedges at December 31, 2005 are expected to be reclassified into earnings during the next 12 months. Management expects that reclassification of net unrealized losses will offset energy revenue recognized at market prices. 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. The maximum period over which a cash flow hedge is designated is through December 31, 2007.

Under SFAS No. 133, the portion of a cash flow hedge that does not offset the change in value of the transaction being hedged, which is commonly referred to as the ineffective portion, is immediately recognized in earnings. EME recorded net gains (losses) of approximately $(65) million, $(13) million and $11 million in 2005, 2004 and 2003, respectively, representing the amount of cash flow hedges' ineffectiveness for continuing operations, reflected in net gains from price risk management and energy trading in EME's consolidated income statements.

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Note 7. Acquisitions and Consolidations

Acquisitions

San Juan Mesa Project

On December 27, 2005, EME completed a transaction with Padoma Project Holdings, LLC to acquire a 100% interest in the San Juan Mesa Wind Project, which owns a 120 MW wind power generation facility located in New Mexico, referred to as the San Juan Mesa wind project. The total purchase price was $156.5 million. The acquisition was funded with cash. The acquisition was accounted for utilizing the purchase method. The fair value of the San Juan Mesa wind project was equal to the purchase price and as a result, the entire purchase price was allocated to property, plant and equipment in EME's consolidated balance sheet. EME's consolidated statement of income will reflect the operations of the San Juan Mesa project beginning January 1, 2006. The pro forma effects of the San Juan Mesa wind project acquisition on EME's consolidated financial statements were not material.

Consolidations

Variable Interest Entities

In December 2003, the FASB re-issued Statement of Financial Accounting Standards Interpretation No. 46, "Consolidation of Variable Interest Entities" (FIN 46R). This Interpretation defines a variable interest entity as a legal entity whose equity owners do not have sufficient equity at risk or a controlling financial interest in the entity. Under this Interpretation, the primary beneficiary is the variable interest holder that absorbs a majority of expected losses; if no variable interest holder meets this criteria, then it is the variable interest holder that receives a majority of the expected residual returns. The primary beneficiary is required to consolidate the variable interest entity unless specific exceptions or exclusions are met.

Consolidation of Special Purpose Entity—

Wildorado Wind, L.P. is a special purpose entity formed to develop the Wildorado project, a planned 161 MW wind power generating facility to be located in Texas. A subsidiary of EME entered into a loan agreement with Wildorado Wind to fund turbine payments for the Wildorado project. In accordance with FIN 46R, EME is the primary beneficiary and accordingly, consolidated Wildorado Wind at December 31, 2005.

Consolidation of Wind Projects—

Effective March 31, 2004, three wind projects were consolidated and at December 31, 2005, two additional wind projects were consolidated in accordance with FIN 46R. These projects were funded with nonrecourse debt totaling $29 million at December 31, 2005. Properties serving as collateral for these loans had a carrying value of $62 million and are classified as property, plant and equipment on EME's consolidated balance sheet at December 31, 2005. The creditors to these projects did not have recourse to the general credit of Edison Capital, the previous owner of these projects. See Note 21—Subsequent Events, for further discussion.

Deconsolidation of Variable Interest Entities—

In accordance with FIN 46R, EME determined that it was not the primary beneficiary of the Doga project and, accordingly, deconsolidated the project at March 31, 2004.

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Variable Interest Entities—

EME completed a review of the application of FIN 46R to its subsidiaries and affiliates and concluded that it had significant variable interests in variable interest entities as defined in this Interpretation. As of December 31, 2005, these entities consisted of five equity investments (the Big 4 projects and the Sunrise project) that had interests in natural gas-fired facilities with a total generating capacity of 1,782 MW. An operations and maintenance subsidiary of EME operates the Big 4 projects, but EME does not supply the fuel consumed or purchase the power generated by these facilities. EME determined that it is not the primary beneficiary in these entities; accordingly, EME continues to account for its variable interests on the equity method. EME's maximum exposure to loss in these variable interest entities is generally limited to its investment in these entities, which totaled $332 million as of December 31, 2005.

Note 8. Divestitures

Dispositions of Domestic Investments in Energy Plants

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

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

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

Discontinued Operations

Tri Energy Project

CBK Project

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MEC International B.V.

On December 16, 2004, EME sold the stock and related assets of MEC International B.V. (MECIBV) pursuant to a Purchase Agreement, dated July 29, 2004, by and between EME and IPM. The purchase agreement was entered into following a competitive bidding process. The sale of MECIBV included the sale of EME's interests in ten electric power generating projects or companies located in Europe, Asia, Australia, and Puerto Rico. Consideration from the sale of MECIBV and related assets was $2.0 billion.

Contact Energy

On September 30, 2004, EME sold its 51.2% interest in Contact Energy to Origin Energy New Zealand Limited pursuant to a Purchase Agreement, dated July 20, 2004. The purchase agreement was entered into following a competitive bidding process. Consideration for the sale was NZ$1,101 million (approximately US$739 million) in cash and NZ$535 million (approximately US$359 million) of debt assumed by the purchaser.

Lakeland Project

EME previously owned a 220-MW power plant located in the United Kingdom, referred to as the Lakeland project. An administrative receiver was appointed in 2002 as a result of a default by its counterparty, a subsidiary of TXU Europe Group plc. Following a claim for termination of the power sales agreement, the Lakeland project received a settlement of £116 million (approximately $217 million). EME is entitled to receive the remaining amount of the settlement after payment of creditor claims. Payments received to date include £13 million (approximately $24 million) in March 2005 and £18 million (approximately $31 million) in February 2006. Beginning in 2002, EME reported the Lakeland project as discontinued operations and accounts for its ownership of Lakeland Power on the cost method (earnings are recognized as cash is distributed from the project).

Summarized Financial Information for Discontinued Operations

In accordance with SFAS No. 144, all of the projects discussed above are classified as discontinued operations in the accompanying consolidated statements of income. Previously issued statements of operations have been restated to reflect discontinued operations reported subsequent to the original issuance date. Summarized results of discontinued operations are as follows:

	Years Ended December 31,
	2005			2004		2003
	(in millions)
Total operating revenues	$	—		$	1,281	$	1,403
Income (loss) before income taxes and minority interest		(20	)		256		252
Provision (benefit) for income taxes		(44	)		48		90
Minority interest		—			51		38
Income from operations of discontinued foreign subsidiaries		24			157		124
Gain on sale before income taxes		9			532		—
Gain on sale after income taxes		5			533		—

During the third quarter of 2005, EME recorded tax benefit adjustments of $28 million, which resulted from completion of the 2004 federal and California income tax returns and quarterly review of tax accruals. The majority of the tax adjustments are related to the sale of the international projects in December 2004 and are included in "Provision (benefit) for income taxes" in the above table. During

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the fourth quarter of 2005, EME recorded an after-tax charge of $25 million related to a tax indemnity for a project sold to IPM in December 2004. This charge related to an adverse tax court ruling in Spain, which the local company plans to appeal.

The assets and liabilities associated with the discontinued operations are segregated on the consolidated balance sheets at December 31, 2005 and 2004. The balance sheet at December 31, 2005 and 2004 was comprised of current assets of $1 million and $4 million, respectively, and investments in unconsolidated affiliates of $107 million at December 31, 2004, which was principally related to EME's investment in the Tri Energy and CBK projects. In addition, there were current liabilities of $1 million at December 31, 2004 and deferred revenue of $4 million at the end of each period.

EME has operated as one segment since the third quarter of 2004 due to the sale of most of its international assets. Prior periods' segment information have not been presented due to lack of continuing significance.

Note 9. Investments in Unconsolidated Affiliates

Investments in unconsolidated affiliates, generally 50% or less owned partnerships and corporations, are accounted for by the equity method. These investments are primarily in energy projects. For 2003, the summarized financial information included Four Star Oil & Gas Company. EME sold 100% of its stock of Edison Mission Energy Oil & Gas, which in turn held minority interests in Four Star Oil & Gas, on January 7, 2004. For 2003, the summarized financial information also included Gordonsville Energy and Brooklyn Navy Yard. EME sold its interests in Gordonsville Energy and Brooklyn Navy Yard on November 21, 2003 and March 31, 2004, respectively. Therefore, Gordonsville Energy, Brooklyn Navy Yard and Four Star Oil & Gas are not included in the balances for 2004 and 2005. The difference between the carrying value of these equity investments and the underlying equity in the net assets amounted to $2 million at December 31, 2005. The differences are being amortized over the life of the energy projects. The following table presents summarized financial information of the investments in unconsolidated affiliates:

			2005		2004
			(in millions)
Investments in Unconsolidated Affiliates
	Equity investment		$	365	$	428
	Cost investment			14		20
	Loan receivable			26		26

		Total	$	405	$	474

EME's subsidiaries have provided loans or advances related to certain projects. The loan receivable at December 31, 2005 and 2004 consists of a $26 million, 5% interest promissory note, interest payable semiannually, due April 2008. The undistributed earnings of equity method investments were $117 million in 2005 and $160 million in 2004.

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

		Years Ended December 31,
		2005		2004		2003
		(in millions)
Revenues		$	1,830	$	1,617	$	1,998
Expenses			1,452		1,192		1,546

Income before accounting change			378		425		452
Cumulative effect of change in accounting, net of tax			—		—		(8	)

	Net income	$	378	$	425	$	444

		December 31,
		2005		2004
		(in millions)
Current assets		$	665	$	624
Noncurrent assets			1,145		1,224

	Total assets	$	1,810	$	1,848

Current liabilities		$	439	$	347
Noncurrent liabilities			644		674
Equity			727		827

	Total liabilities and equity	$	1,810	$	1,848

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

The following table presents, as of December 31, 2005, the investments in unconsolidated affiliates accounted for by the equity method that represent at least five percent (5%) of EME's income before tax or in which EME has an investment balance greater than $50 million.

Unconsolidated Affiliates	Location	Investment at December 31, 2005		Ownership Interest at December 31, 2005		Operating Status
		(in millions)
Sunrise	Fellows, CA	$	107	50	%	Operating gas-fired facility
Watson	Carson, CA		85	49	%	Operating cogeneration facility
Midway-Sunset	Fellows, CA		53	50	%	Operating cogeneration facility
Sycamore	Bakersfield, CA		50	50	%	Operating cogeneration facility
Kern River	Bakersfield, CA		37	50	%	Operating cogeneration facility

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Impairment Loss on Equity Method Investment

Note 10. Property, Plant and Equipment

Property, plant and equipment consist of the following:

		December 31,
		2005		2004
		(in millions)
Power plant facilities		$	2,334	$	2,156
Leasehold improvements			90		80
Emission allowances			1,305		1,305
Construction in progress			34		33
Equipment, furniture and fixtures			92		108
Capitalized leased equipment			1		1

			3,856		3,683
Less accumulated depreciation and amortization			844		747

	Net property, plant and equipment	$	3,012	$	2,936

In connection with Midwest Generation's financing activities, EME has given first and second priority security interests in substantially all the coal-fired generating plants owned by Midwest Generation and the assets relating to those plants and receivables of EMMT directly related to Midwest Generation's hedging activities. The amount of assets pledged or mortgaged totaled approximately $2.9 billion at December 31, 2005. In addition to these assets, Midwest Generation's membership interests and the capital stock of Edison Mission Midwest Holdings were pledged. Emission allowances have not been pledged.

Note 11. Financial Instruments

Long-Term Obligations

Long-term obligations include both corporate debt and non-recourse project debt, whereby lenders rely on specific project assets to repay such obligations. At December 31, 2005, recourse debt totaled $1.7 billion and non-recourse project debt totaled $1.7 billion. At December 31, 2005, EME had no

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borrowings outstanding on the $98 million secured line of credit that matures on April 27, 2007. Long-term obligations consist of the following:

			December 31,
			2005		2004
			(in millions)
Recourse
EME (parent only)
	Senior Notes, net
		due 2008 (10.0%)	$	400	$	400
		due 2009 (7.73%)		598		598
		due 2011 (9.875%)		600		600
Long-Term Obligations—Affiliate				78		78
Junior Subordinated Debentures				—		155
Non-recourse
Due to EME Funding Corp.—Long-Term Obligation due 2005-2008 (7.33%)				92		139
EME CP Holdings Co.
	Note Purchase Agreement due 2015 (7.31%)			79		81
Midwest Generation, LLC
	Second Priority Senior Secured Notes due 2034 (8.75%)			1,000		1,000
	Credit Agreement due 2011 (LIBOR+1.75%) (5.91% at 12/31/05)			333		667
		$500 million Credit Revolver due 2011 (LIBOR+1.75%) (6.12% at 12/31/05)		170		—
Other				54		64

Subtotal			$	3,404	$	3,782
Less current maturities of long-term obligations				74		252

Total			$	3,330	$	3,530

Midwest Generation, LLC Financing

On December 15, 2005, Midwest Generation, LLC completed a refinancing of indebtedness. The refinancing was effected through the amendment and restatement of Midwest Generation's existing credit facility, previously amended and restated on April 18, 2005. The credit facility, as previously amended and restated, provided for approximately $343 million of first priority secured institutional term loans due in 2011 and $500 million of first priority secured revolving credit, working capital facilities, $200 million due in 2009 and $300 million due in 2011, with a lender option to require prepayment in 2010.

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12-month period ended on the last day of the immediately preceding fiscal quarter required to be no greater than 7.25 to 1 (reduced from 8.75 to 1).

Under the terms of Midwest Generation's credit agreement, Midwest Generation is permitted to distribute 75% of its excess cash flow (as defined in the credit agreement). In addition, if equity is contributed to Midwest Generation, Midwest Generation is permitted to distribute 100% of excess cash flow until the aggregate portion of distributions that Midwest Generation attributed to the equity contribution equals the amount of the equity contribution. Because EME made a $300 million equity contribution to Midwest Generation on April 19, 2005, Midwest Generation is permitted to distribute 100% of excess cash flow until the aggregate portion of such distributions attributed to the equity contribution equals $300 million. After taking into account Midwest Generation's most recent distribution in January 2006, $177 million of the equity contribution is still available for this purpose. To the extent Midwest Generation makes a distribution which is not fully attributed to an equity contribution, Midwest Generation is required to make concurrently with such distribution an offer to repay debt in an amount equal to the excess, if any, of one-third of such distribution over the amount attributed to the equity contribution.

Long-term Obligations—Affiliates

During 1997, EME declared a dividend of $78 million to The Mission Group (now known as Edison Mission Group Inc.) which was recorded as a note payable due in June 2007 with interest at LIBOR plus 0.275% (4.36% at December 31, 2005). The note was subsequently exchanged for two notes with the same terms and conditions and assigned to other subsidiaries of Edison International.

Junior Subordinated Debentures

In November 1994, Mission Capital, L.P., a limited partnership of which EME is the sole general partner, issued 3.5 million 9.875% Cumulative Monthly Income Preferred Securities, Series A at a price of $25 per security and invested the proceeds in 9.875% junior subordinated deferrable interest debentures due 2024 which were issued by EME in November 1994. On January 25, 2005, all of these securities were redeemed for a purchase price of 100% of the principal amount, plus accrued interest through January 25, 2005 for a total of $88 million. During August 1995, Mission Capital issued 2.5 million 8.5% Cumulative Monthly Income Preferred Securities, Series B at a price of $25 per security and invested the proceeds in 8.5% junior subordinated deferrable interest debentures due 2025 which were issued by EME in August 1995. On January 25, 2005 all of these securities were redeemed for a purchase price of 100% of the principal amount, plus accrued interest through January 25, 2005 for a total of $63 million. On January 25, 2005, EME repaid the junior subordinated debentures and consequently repaid the cumulative monthly income preferred securities (MIPS) of $150 million. In connection with the repayment of the junior subordinated debentures, EME recorded a $4 million loss on early extinguishment of debt during the first quarter of 2005.

Annual Maturities on Long-Term Obligations

Annual maturities on long-term debt at December 31, 2005, for the next five years are summarized as follows: 2006—$74 million; 2007—$133 million; 2008—$420 million; 2009—$613 million; and 2010—$15 million.

Standby Letters of Credit

As of December 31, 2005, standby letters of credit aggregated to $33 million and were scheduled to expire as follows: $28 million in 2006 and $5 million in 2007.

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Restricted Cash

Several cash balances are restricted primarily to pay amounts required for debt payments and letter of credit expenses. The total restricted cash included in EME's consolidated balance sheet was $105 million at December 31, 2005 and $155 million at December 31, 2004. Included in restricted cash were debt service reserves of $40 million and $76 million at December 31, 2005 and 2004, respectively, and collateral reserves of $65 million and $79 million at December 31, 2005 and 2004, respectively.

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

Fair Values of Non-Derivative Financial Instruments

The carrying amount of cash and cash equivalents, trade accounts receivables and payables contained in EME's consolidated balance sheet approximates fair value. The following table summarizes the carrying amounts and fair values for outstanding non-derivative financial instruments (in millions):

		December 31, 2005				December 31, 2004
		Carrying Amount		Fair Value		Carrying Amount		Fair Value
Instruments
Non-derivatives:
	Long-term obligations	$	3,404	$	3,744	$	3,782	$	4,215

In assessing the fair value of EME's financial instruments, EME uses a variety of methods and assumptions that are based on market conditions and risks existing at each balance sheet date. Quoted market prices for the same or similar instruments are used for long-term obligations.

Note 12. Risk Management and Derivative Financial Instruments

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

Commodity Price Risk Management

EME's merchant operations expose it to commodity price risk, which represents the potential loss that can be caused by a change in the market value of a particular commodity. Commodity price risks are actively monitored by a risk management committee to ensure compliance with EME's risk management policies. Policies are in place which define risk management processes, and procedures exist which allow for monitoring of all commitments and positions with regular reviews by EME's risk management committee. Despite this, there can be no assurance that all risks have been accurately identified, measured and/or mitigated. EME uses "value at risk" to identify, measure, monitor and control its overall market risk exposure in respect of its Illinois Plants, its Homer City facilities, and its trading positions. The use of value at risk allows management to aggregate overall commodity risk,

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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.

In order to provide more predictable earnings and cash flow, EME may hedge a portion of the electric output of its merchant plants. When appropriate, EME manages the spread between the electric prices and fuel prices, and uses forward contracts, swaps, futures, or options contracts to achieve those objectives. There is no assurance that contracts to hedge changes in market prices will be effective.

Interest Rate Risk Management

Interest rate changes affect the cost of capital needed to operate EME's projects. EME mitigates the risk of interest rate fluctuations by arranging for fixed rate financing or variable rate financing with interest rate swaps, interest rate options or other hedging mechanisms for a number of EME's project financings.

Credit Risk

EME's 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 effect on the operations of such power plant.

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EME derived a significant source of its operating revenues from electric power sold into the PJM market from the Homer City facilities in the past three fiscal years and from the Illinois Plants in 2005 and 2004. Sales into the PJM pool accounted for approximately 69%, 23% and 18% of EME's consolidated operating revenues for the years ended December 31, 2005, 2004 and 2003, respectively. Moody's Investor Service rates PJM's senior unsecured debt Aa3. PJM, an independent system operator with over 300 member companies, maintains its own credit risk policies and does not extend unsecured credit to non-investment grade companies. Any losses due to a PJM member default is shared by all members based upon a predetermined formula. At December 31, 2005, EME's account receivable due from PJM was $223 million.

In 2004 and 2003, EME also derived a significant source of its revenues from the sale of energy and capacity generated at the Illinois Plants to Exelon Generation primarily under three power purchase agreements. These power purchase agreements had all expired by the end of 2004. Exelon Generation accounted for 35% in 2004 and 40% in 2003 of EME's consolidated operating revenues.

Non-Trading Derivative Financial Instruments

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

		December 31, 2005						December 31, 2004
		Carrying Amount			Fair Value			Carrying Amount		Fair Value
Commodity price:
	Electricity	$	(434	)	$	(434	)	$	10	$	10

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 the commodity price contracts takes into account quoted market prices, time value of money, volatility of the underlying commodities and other factors.

Energy Trading

EME engages in energy trading activities in markets where its merchant power plants are located. EME trades power, fuel and transmission using products available over the counter, through exchanges and from independent system operators. Energy trading activity is limited by EME's risk management policies, including a limit on value at risk.

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The carrying amounts and fair values of the commodity financial instruments related to energy trading activities as of December 31, 2005 and December 31, 2004, are set forth below (in millions):

	December 31, 2005				December 31, 2004
	Assets		Liabilities		Assets		Liabilities
Electricity	$	127	$	27	$	125	$	36
Other		1		—		—		—

Total	$	128	$	27	$	125	$	36

EME recorded net gains of approximately $202 million, $29 million and $40 million in 2005, 2004 and 2003, respectively, arising from energy trading activities reflected in net gains from price risk management and energy trading in EME's consolidated income statement. In accordance with Emerging Issues Task Force No. 02-03, "Issues Involved in Accounting for Derivative Contracts Held for Trading Purposes and Contracts Involved in Energy Trading and Risk Management Activities," EME netted 3.9 million MWh and 2.9 million MWh of sales and purchases of physically settled, gross purchases and sales during 2005 and 2004, respectively.

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Note 13. Income Taxes

Current and Deferred Taxes

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

		Years Ended December 31,
		2005			2004			2003
		(in millions)
Continuing Operations:
Current
	Federal	$	231		$	(314	)	$	(70	)
	State		39			(68	)		(39	)
	Foreign		(1	)		(1	)		6

	Total current		269			(383	)		(103	)

Deferred
	Federal	$	(50	)	$	(14	)	$	(22	)
	State		(11	)		(9	)		2
	Foreign		—			—			2

	Total deferred		(61	)		(23	)		(18	)

Provision (benefit) for income taxes from continuing operations			208			(406	)		(121	)

Discontinued operations			(40	)		47			91
Change in accounting			(1	)		—			(4	)

	Total	$	167		$	(359	)	$	(34	)

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

		Years Ended December 31,
		2005			2004			2003
		(in millions)
Continuing Operations
	U.S.	$	614		$	(971	)	$	(227	)
	Foreign		8			6			12

	Total continuing operations		622			(965	)		(215	)
Discontinued operations			(11	)		788			252
Change in accounting			(2	)		—			(13	)

	Total	$	609		$	(177	)	$	24

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

		Years Ended December 31,
		2005			2004			2003
		(in millions)
Expected provision for federal income taxes		$	218		$	(338	)	$	(75	)
Increase (decrease) in the provision for taxes resulting from:
	State tax—net of federal deduction		20			(50	)		(25	)
	Dividends received deduction		—			—			(12	)
	Taxes on foreign operations at different rates		(4	)		(3	)		4
	Resolution of IRS audit issue		(11	)		—			—
	Production tax credits		(8	)		(7	)		(7	)
	Other		(7	)		(8	)		(6	)

	Provision (benefit) for income taxes	$	208		$	(406	)	$	(121	)

	Effective tax rate		33	%		42	%		56	%

The components of the net accumulated deferred income tax liability are:

			December 31,
			2005		2004
			(in millions)
Deferred tax assets
	Accrued charges		$	126	$	68
	Price risk management			162		(12	)
	Deferred income			5		3
	Other			—		1

		Total		293		60

Deferred tax liabilities
	Basis differences		$	353	$	318
	Tax credits, net			11		12
	Other			1		—

		Total		365		330

Deferred taxes and tax credits, net			$	72	$	270

Classification of accumulated deferred income taxes:
	Included in current assets		$	155	$	—
	Included in non-current liabilities		$	227	$	270

State loss carryforwards for various states totaled $6 million and $13 million at December 31, 2005 and 2004, respectively, with expiration dates beginning in 2022.

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Note 14. Employee Benefit Plans

Pension Plans

Defined benefit pension plans (the non-executive plan has a cash balance feature) cover employees who fulfill minimum service and other requirements.

At December 31, 2005 and 2004, the accumulated benefit obligations of the executive pension plans exceeded the related plan assets at the measurement dates. In accordance with accounting standards, EME's consolidated balance sheets include an additional minimum liability, with corresponding charges to intangible assets and shareholders' equity (through a charge to accumulated other comprehensive income).

The expected contributions (all by the employer) are approximately $14 million for the year ended December 31, 2006. This amount is subject to change based on, among other things, the limits established for federal tax deductibility.

EME uses a December 31 measurement date for all of its plans. The fair value of plan assets is determined by market value.

Information on plan assets and benefit obligations is shown below:

			Years Ended December 31,
			2005			2004
			(in millions)
Change in projected benefit obligation
	Projected benefit obligation at beginning of year		$	153		$	119
	Service cost			16			16
	Interest cost			8			7
	Actuarial (gains) loss			(10	)		11
	Benefits paid			(8	)		—

		Projected benefit obligation at end of year	$	159		$	153

Accumulated benefit obligation at end of year			$	137		$	123

Change in plan assets
	Fair value of plan assets at beginning of year		$	77		$	53
	Actual return on plan assets			9			7
	Employer contributions			13			17
	Benefits paid			(8	)		—

		Fair value of plan assets at end of year	$	91		$	77

Funded status			$	(68	)	$	(76	)
Unrecognized net loss				14			29
Unrecognized prior service cost				1			2

Recorded liability			$	(53	)	$	(45	)

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Additional detail of amounts recognized in balance sheets:
Intangible asset	$	1		$	1
Accumulated other comprehensive income		(5	)		(2	)
Pension plans with an accumulated benefit obligation in excess of plan assets:
Projected benefit obligation	$	159		$	99
Accumulated benefit obligation		137			72
Fair value of plan assets		91			45
Weighted-average assumptions at end of year:
Discount rate		5.50	%		5.50	%
Rate of compensation increase		5.00	%		5.00	%

Components of pension expense are:

	Years Ended December 31,
	2005			2004			2003
	(in millions)
Service cost	$	16		$	16		$	14
Interest cost		8			7			6
Expected return on plan assets		(6	)		(4	)		(4	)
Net amortization and deferral		1			1			2

Total expense recognized	$	19		$	20		$	18

Change in accumulated other comprehensive income		(3	)		(2	)		—
Weighted-average assumptions:
Discount rate		5.50	%		6.00	%		6.50	%
Rate of compensation increase		5.00	%		5.00	%		5.00	%
Expected return on plan assets		7.50	%		7.50	%		8.50	%

Asset allocations for plans are:

			December 31,
	Target for 2006		December 31,
	Target for 2006		2005		2004
United States equity	45	%	47	%	47	%
Non-United States equity	25	%	26	%	25	%
Private equity	4	%	2	%	2	%
Fixed income	26	%	25	%	26	%

Postretirement Benefits Other Than Pensions

Most non-union employees retiring at or after age 55 with at least 10 years of service are eligible for postretirement health and dental care, life insurance and other benefits. Eligibility depends on a number of factors, including the employee's hire date.

On December 8, 2003, President Bush signed the Medicare Prescription Drug, Improvement and Modernization Act of 2003. The Act authorized a federal subsidy to be provided to plan sponsors for

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certain prescription drug benefits under Medicare. EME adopted FASB Staff Position FAS 106-2, "Accounting and Disclosure Requirements Related to the Medicare Prescription Drug, Improvement and Modernization Act of 2003," for the effects of the Act, effective July 1, 2004, which reduced EME's accumulated benefits obligation by $3 million upon adoption.

The expected contributions (all by the employer) for the postretirement benefits other than pensions are $1 million for the year ended December 31, 2006. This amount is subject to change based on, among other things, the limits established for federal tax deductibility.

EME uses a December 31 measurement date.

Information on plan assets and benefit obligations is shown below:

			Years Ended December 31,
			2005			2004
			(in millions)
Change in benefit obligation
	Benefit obligation at beginning of year		$	58		$	54
	Service cost			2			2
	Interest cost			4			3
	Amendments			—			1
	Actuarial loss (gain)			9			(1	)
	Benefits paid			(1	)		(1	)

	Benefit obligation at end of year		$	72		$	58

Change in plan assets
	Fair value of plan assets at beginning of year		$	—		$	—
	Employer contributions			1			1
	Benefits paid			(1	)		(1	)

		Fair value of plan assets at end of year	$	—		$	—

Funded status			$	(72	)	$	(58	)
Unrecognized net loss				22			14
Unrecognized prior service cost				(10	)		(12	)

Recorded liability			$	(60	)	$	(56	)

Assumed health care cost trend rates:
Rate assumed for following year				10.25	%		10.00	%
Ultimate rate				5.00	%		5.00	%
Year ultimate rate reached				2011			2010
Weighted-average assumptions at end of year:
Discount rate				5.50	%		5.75	%

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Expense components of postretirement benefits are:

	Years Ended December 31,
	2005			2004			2003
	(in millions)
Service cost	$	2		$	2		$	2
Interest cost		4			3			3
Net amortization and deferral		—			(1	)		(1	)

Total expense	$	6		$	4		$	4

Assumed health care cost trend rates:
Current year		10.00	%		12.00	%		9.75	%
Ultimate rate		5.00	%		5.00	%		5.00	%
Year ultimate rate reached		2010			2010			2008
Weighted-average assumptions:
Discount rate		5.75	%		6.25	%		6.40	%

Increasing the health care cost trend rate by one percentage point would increase the accumulated obligation as of December 31, 2005, by $13 million and annual aggregate service and interest costs by $1 million. Decreasing the health care cost trend rate by one percentage point would decrease the accumulated obligation as of December 31, 2005, by $11 million and annual aggregate service and interest costs by $1 million.

Discount Rate

The discount rate enables EME to state expected future cash flows at a present value on the measurement date. EME selects its discount rate by performing a yield curve analysis. This analysis determines the equivalent discount rate on projected cash flows, matching the timing and amount of expected benefit payments. Three yield curves were considered: two corporate yield curves (Citigroup and AON) and a curve based on treasury rates (plus 90 basis points). EME also compared the yield curve analysis against the Moody's AA Corporate bond rate. At the December 31, 2005 measurement date, EME used a discount rate of 5.5% for both pensions and postretirement benefits other than pensions.

Description of Investment Strategies

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

Allowable investment types include:

•: United States Equity: Common and preferred stocks of large, medium, and small companies which are predominantly United States-based.

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•: Non-United States Equity: Equity securities issued by companies domiciled outside the United States and in depository receipts which represent ownership of securities of non-United States companies.
•: Private Equity: Limited partnerships that invest in non-publicly traded entities.
•: Fixed Income: Fixed income securities issued or guaranteed by the United States government, non-United States governments, government agencies and instrumentalities, mortgage backed securities and corporate debt obligations. A small portion of the fixed income position may be held in debt securities that are below investment grade.

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

Determination of the Expected Long-Term Rate of Return on Assets

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

Capital Markets Return Forecasts

The estimated total return for fixed income is based on an equilibrium yield for intermediate United States government bonds plus a premium for exposure to non-government bonds in the broad fixed income market. The equilibrium yield is based on analysis of historic data and is consistent with experience over various economic environments. The premium of the broad market over United States government bonds is a historic average premium. The estimated rate of return for equity is estimated to be a 3% premium over the estimated total return of intermediate United States government bonds. This value is determined by combining estimates of real earnings growth, dividend yields and inflation, each of which was determined using historical analysis. The rate of return for private equity is estimated to be a 5% premium over public equity, reflecting a premium for higher volatility and illiquidity.

Active Management Excess Return Expectations

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

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Estimated Future Benefits Payable

Estimated future benefits payable under the pension and other postretirement benefits as of December 31, 2005 are as follows:

Years Ended December 31,	Pension Plans		Other Postretirement Benefits
	(in millions)
2006	$	5	$	1
2007		6		1
2008		7		2
2009		8		2
2010		9		2
2011-2015		70		16

(1): The impact of the medicare subsidy does not change the amounts reported in the table.

Employee Stock Plans

A 401(k) plan is maintained to supplement eligible United States employees' retirement income. The plan received contributions from EME of $6 million in 2005, $5 million in 2004 and $6 million in 2003.

Note 15. Stock Compensation Plans

Stock-Based Compensation

Under various plans, EME may grant stock options at exercise prices equal to the market price at the grant date and other awards based on Edison International common stock to directors and certain employees. Options generally expire 10 years after the grant date and vest over a period of up to five years, with expense accruing evenly over the vesting period. Edison International has approximately 12.5 million shares remaining for future issuance under equity compensation plans.

Most Edison International stock options issued prior to 2000 accrue dividend equivalents, subject to certain performance criteria. The 2003 to 2005 options accrue dividend equivalents for the first five years of the option term. Unless deferred, dividend equivalents accumulate without interest. The liability and associated expense is accrued each quarter for the dividend equivalents for each option year. At the end of the performance measurement period, the expense and related liability is adjusted accordingly. Upon exercise, the dividends are paid out and the associated liability is reduced on EME's consolidated balance sheet.

The fair value for each option granted, reflecting the basis for the pro forma disclosures in Note 2, was determined as of the date of grant using the Black-Scholes option-pricing model. The following assumptions were used in determining fair value through the model:

	2005	2004	2003
Expected years until exercise	9-10	9-10	10
Risk-free interest rate	4.1% to 4.3%	4.0% to 4.3%	3.8% to 4.5%
Expected dividend yield	2.1% to 3.1%	2.7% to 3.7%	1.8%
Expected volatility	15% to 20%	19% to 22%	44% to 53%

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The weighted-average fair value of options granted during 2005, 2004 and 2003 was $9.38 per share option, $6.60 per share option and $7.31 per share option, respectively.

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

	Share Options		Exercise Price		Weighted Exercise Price
Outstanding, December 31, 2002	2,181,812		$	9.10-$28.94	$	18.60
Granted	1,020,910		$	11.88-$18.87	$	12.37
Transferred from (to) affiliates	(32,351	)	$	9.57-$28.94	$	17.70
Forfeited	(315,788	)	$	9.57-$28.94	$	23.09
Exercised	(69,769	)	$	9.10-$20.19	$	14.12

Outstanding, December 31, 2003	2,784,814		$	9.10-$28.94	$	15.95
Granted	1,212,026		$	21.88-$29.09	$	22.02
Transferred from (to) affiliates	(69,924	)	$	12.29-$28.13	$	15.85
Forfeited	(104,975	)	$	9.57-$23.14	$	18.16
Exercised	(691,988	)	$	9.10-$28.13	$	14.52

Outstanding, December 31, 2004	3,129,953		$	9.15-$29.09	$	18.44
Granted	693,578		$	31.94-$40.52	$	31.99
Transferred from (to) affiliates	790,394		$	12.29-$46.47	$	21.56
Forfeited	(172,595	)	$	12.29-$31.94	$	19.58
Exercised	(814,965	)	$	9.15-$31.94	$	16.81

Outstanding, December 31, 2005	3,626,365		$	9.57-$46.47	$	22.06

A summary of stock options outstanding at December 31, 2005 is as follows:

		Outstanding				Exercisable
Range of Exercise Prices		Number of Options	Weighed Average Remaining Years of Contractual Life	Weighted Average Exercise Price		Number of Options	Weighted Average Exercise Price
	$9.57-$13.99	751,790	6.85	$	12.09	521,318	$	12.01
	$14.00-$20.99	626,597	5.75		18.65	536,879		18.69
	$21.00-$31.49	1,451,454	6.88		23.14	644,356		24.56
	$31.50-$46.47	796,524	9.03		32.16	15,337		31.58

Total		3,626,365	7.15	$	22.06	1,717,890	$	18.98

The number of options exercisable and their weighted-average exercise prices at December 31, 2004 and 2003 were 1,051,147 at $18.30 and 863,116 at $19.26, respectively.

Other Equity-Based Awards

Performance shares were awarded in January 2003, January 2004 and January 2005 and vest at the end of December 2005, 2006 and 2007, respectively. The number of common shares paid out from the performance share awards depends on the performance of Edison International common stock relative to the stock performance of a specified group of companies. Performance share values are accrued ratably over the vesting period based on the value of the underlying Edison International common

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stock. The number of performance shares granted and their weighted-average grant-date value for 2005, 2004 and 2003 were 51,843 at $32.04, 89,911 at $21.94 and 147,367 at $12.29, respectively. In the pro forma disclosure reflected in Note 2, the portions of these performance shares settled in stock, which were half of the total shares outstanding, were treated as equity awards. The weighted-average grant-date fair values of these performance shares were $46.09, $33.62, and $21.42, for 2005, 2004, and 2003, respectively.

EME measures compensation expense related to stock-based compensation by the intrinsic value method. Compensation expense recorded under the stock compensation program was approximately $20 million, $24 million and $11 million for the years ended December 31, 2005, 2004 and 2003, respectively.

Note 16. Commitments and Contingencies

Capital Improvements

At December 31, 2005, EME's subsidiaries had firm commitments to spend approximately $8 million on capital expenditures in 2006 primarily for component replacement projects. These expenditures are planned to be financed by existing subsidiary credit facilities and cash generated from these operations.

Fuel Supply Contracts

At December 31, 2005, Midwest Generation and EME Homer City had fuel purchase commitments with various third-party suppliers. The remaining contracts' lengths range from one year to seven years. Based on the contract provisions, which consist of fixed prices, subject to adjustment clauses, these minimum commitments are currently estimated to aggregate $1.0 billion in the next five years summarized as follows: 2006—$367 million; 2007—$340 million; 2008—$147 million; 2009—$94 million; and 2010—$64 million.

Gas Transportation Agreements

At December 31, 2005, EME had a contractual commitment to transport natural gas. EME's share of the commitment to pay minimum fees under its gas transportation agreement, which has a remaining contract length of 12 years, is currently estimated to aggregate $40 million in the next five years, $8 million each year, 2006 through 2010.

Coal Transportation Agreements

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$680 million in the next five years, summarized as follows: 2006—$226 million; 2007—$216 million; 2008—$85 million; 2009—$76 million; and 2010—$77 million.

Other Contractual Obligations

At December 31, 2005, Midwest Generation was party to a long-term power purchase contract with Calumet Energy Team LLC entered into as part of the settlement agreement with Commonwealth Edison, which terminated Midwest Generation's obligation to build additional gas-fired generation in the Chicago area. The contract requires Midwest Generation to pay a monthly capacity payment and gives Midwest Generation an option to purchase energy from Calumet Energy Team at prices based primarily on operations and maintenance and fuel costs. These minimum commitments are currently estimated to aggregate $20.1 million in the next five years, summarized as follows: 2006—$3.8 million; 2007—$3.9 million; 2008—$4.0 million; and 2010—$4.3 million.

Commercial Commitments

Introduction

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

Turbine Commitments

At December 31, 2005, in connection with wind projects in development, EME had entered into agreements with two turbine vendors securing 105 turbines for $114 million in 2006 and $78 million in 2007. In addition, EME has options to acquire an additional 100 turbines for deliveries in 2007.

Guarantees and Indemnities

Tax Indemnity Agreements—

In connection with the sale-leaseback transactions that EME has entered into related to the Powerton and Joliet Stations in Illinois, the Collins Station in Illinois, and the Homer City facilities in Pennsylvania, EME and several of its subsidiaries entered into tax indemnity agreements. Under these tax indemnity agreements, these entities agreed to indemnify the lessors in the sale-leaseback transactions for specified adverse tax consequences that could result in certain situations set forth in each tax indemnity agreement, including specified defaults under the respective leases. The potential indemnity obligations under these tax indemnity agreements could be significant. Due to the nature of these potential obligations, EME cannot determine a maximum potential liability which would be triggered by a valid claim from the lessors. EME has not recorded a liability related to these indemnities. In connection with the termination of the Collins Station lease in April 2004 (See Note 5—Restructuring, Loss on Lease Termination, Asset Impairment and Other Charges), Midwest Generation will continue to have obligations under the tax indemnity agreement with the former lease equity investor.

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

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such claims and are subject to a requirement that Commonwealth Edison 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. This indemnification for environmental liabilities is not limited in term and would be triggered by a valid claim from Commonwealth Edison. Except as discussed below, EME has not recorded a liability related to this indemnity.

Midwest Generation entered into a supplemental agreement with Commonwealth Edison and Exelon Generation Company on February 20, 2003 to resolve a dispute regarding interpretation of its reimbursement obligation for asbestos claims under the environmental indemnities set forth in the Asset Sale Agreement. Under this supplemental agreement, Midwest Generation agreed to reimburse Commonwealth Edison and Exelon Generation for 50% of specific existing asbestos claims and expenses less recovery of insurance costs, and agreed to a sharing arrangement for liabilities and expenses associated with future asbestos-related claims as specified in the agreement. As a general matter, Commonwealth Edison and Midwest Generation apportion responsibility for future asbestos-related claims based upon the number of exposure sites that are Commonwealth Edison locations or Midwest Generation locations. 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 of either party to terminate). Payments are made under this indemnity upon tender by Commonwealth Edison of appropriate proof of liability for an asbestos-related settlement, judgment, verdict, or expense. There were between 185 and 195 cases for which Midwest Generation was potentially liable and that had not been settled and dismissed at December 31, 2005. Midwest Generation had recorded a $67 million and $69 million liability at December 31, 2005 and 2004, respectively, related to this matter.

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

Indemnities Provided under Asset Sale Agreements—

The asset sale agreements for the sale of EME's international assets contain indemnities from EME to the purchasers, including indemnification for taxes imposed with respect to operations of the assets prior to the sale and for pre-closing environmental liabilities. EME also provided an indemnity to IPM for matters arising out of the exercise by one of its project partners of a purported right of first refusal. The right of first refusal matter has been submitted to arbitration, with hearings having been conducted during February 2006. It is expected that a decision of the arbitration panel will be rendered in the coming months. 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. At December 31, 2005 and 2004, EME had recorded a liability of $122 million and $87 million, respectively, related to these matters.

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Guarantee of Brooklyn Navy Yard Contractor Settlement Payments—

On March 31, 2004, EME completed the sale of 100% of the stock of Mission Energy New York, Inc., which held a 50% partnership interest in Brooklyn Navy Yard Cogeneration Partners, L.P. (referred to as Brooklyn Navy Yard), to BNY Power Partners LLC. Brooklyn Navy Yard owns a 286 MW gas-fired cogeneration power plant in Brooklyn, New York. In February 1997, the construction contractor asserted general monetary claims under the turnkey agreement against Brooklyn Navy Yard. A settlement agreement was executed on January 17, 2003, and all litigation has been dismissed. EME agreed to indemnify Brooklyn Navy Yard and, in connection with the sale of EME's interest in Brooklyn Navy Yard, BNY Power Partners for any payments due under this settlement agreement, which are scheduled through January 2007. At December 31, 2005 and 2004, EME had recorded a liability of $8 million and $11 million, respectively, related to this indemnity.

Capacity Indemnification Agreements—

EME has guaranteed, jointly and severally with Texaco Inc., the obligations of March Point Cogeneration Company under its project power sales agreements to repay capacity payments to the project's power purchaser in the event that the power sales agreements terminate, March Point Cogeneration Company abandons the project, or the project fails to return to normal operations within a reasonable time after a complete or partial shutdown, during the term of the power sales agreements. In addition, a subsidiary of EME has guaranteed the obligations of Sycamore Cogeneration Company under its project power sales agreement to repay capacity payments to the project's power purchaser in the event that the project unilaterally terminates its performance or reduces its electric power producing capability during the term of the power sales agreement. The obligations under the indemnification agreements as of December 31, 2005, if payment were required, would be $124 million. EME has not recorded a liability related to these indemnities.

Subsidiary Guarantee for Performance of Unconsolidated Affiliate—

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Contingencies

Litigation

EME experiences routine litigation in the normal course of its business. Pending routine litigation is not expected to have a material adverse effect on EME's consolidated financial position or results of operations.

Environmental Matters and Regulations

Introduction

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

Federal—United States of America

Clean Air Act

Clean Air Interstate Rule—

On May 12, 2005, the Clean Air Interstate Rule (CAIR) was published in the Federal Register. The CAIR requires 28 eastern states and the District of Columbia to address ozone attainment issues by reducing regional nitrogen oxide (NOx) and sulfur dioxide (SO2) emissions. The CAIR reduces the current Clean Air Act Title IV Phase II SO2 emissions allowance cap for 2010 and 2015 by 50% and 65%, respectively. The CAIR also reduces regional NOx emissions in 2009 and 2015 by 53% and 61%, respectively, from 2003 levels. The CAIR has been challenged in court by state, environmental and industry groups, which may result in changes to the substance of the rule and to the timetables for implementation.

EME expects that compliance with the CAIR and the regulations and revised state implementation plans developed as a consequence of the CAIR will result in increased capital expenditures and operating expenses. Given the uncertainty of the requirements that will need to be implemented and the options available to meet the NOx and SO2 reductions fleetwide, EME at this time cannot accurately estimate the cost to meet these obligations. EME's approach to meeting these obligations

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will consist of a blending of capital expenditure and emission allowance purchases that will be based on an ongoing assessment of the dynamics of its market conditions.

Mercury Regulation—

The Clean Air Mercury Rule (CAMR), published in the Federal Register on May 18, 2005, creates a market-based cap-and-trade program to reduce nationwide utility emissions of mercury in two distinct phases. In the first phase of the program, which will come into effect in 2010, the annual nationwide cap will be 38 tons. Emissions of mercury are to be reduced primarily by taking advantage of mercury reductions achieved by reducing SO2 and NOx emissions under the CAIR. In the second phase, which is to take effect in 2018, coal-fired power plants will be subject to a lower annual cap, which will reduce emissions nationwide to 15 tons. States may join the trading program by adopting the CAMR model trading rule in state regulations, or they may adopt regulations that mirror the necessary components of the model trading rule. States are not required to adopt a cap-and-trade program and may promulgate alternative regulations, such as command and control regulations, that are equivalent to or more stringent than the CAMR's suggested cap-and-trade program. Any program adopted by a state must be approved by the United States Environmental Protection Agency (US EPA).

Contemporaneous with the adoption of the CAMR, the US EPA rescinded its previous finding that mercury emissions from coal-fired power plants had to be regulated as a hazardous air pollutant pursuant to Section 112 of the federal Clean Air Act, which would have imposed technology-based standards. Litigation has been filed challenging the US EPA's rescission action and claiming that the agency should have imposed technology-based limitations on mercury emissions instead of adopting a market-based program. Litigation was also filed to challenge the CAMR. As a result of these challenges, the CAMR rules and timetables may change.

If Illinois and Pennsylvania implement the CAMR by adopting a cap-and-trade program for achieving reductions in mercury emissions, EME may have the option to purchase mercury emission allowances, to install pollution control equipment, to otherwise alter its operations to reduce mercury emissions, or to implement some combination thereof. If EME were to implement environmental control technology at its Homer City facilities instead of purchasing allowances to comply with the CAMR and other Clean Air Act developments described herein, it currently estimates capital expenditures for such improvements to be approximately $350 million to $400 million in the 2006-2010 timeframe. However, because the mercury state implementation plans are not due until the fourth quarter of 2006 and such plans may not adopt the CAMR's cap-and-trade program, and because EME cannot predict the outcome of the legal challenge to the CAMR and the US EPA's decision not to regulate mercury emissions pursuant to Section 112 of the federal Clean Air Act, the full impact of this regulation currently cannot be assessed. Additional capital costs, particularly for the Illinois coal units, related to these regulations could be required in the future and they could be material. EME's approach to meeting these obligations will continue to be based upon an ongoing assessment of applicable legal requirements and market conditions.

National Ambient Air Quality Standards—

The US EPA designated non-attainment areas for the 8-hour ozone standard on April 30, 2004, and for the fine particulate standard on January 5, 2005. Almost all of EME's facilities are located in

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counties that have been identified as being in non-attainment with both standards. States are required to revise their implementation plans for the ozone and particulate matter standards within three years of the effective date of the respective non-attainment designations. The revised state implementation plans are likely to require additional emission reductions from facilities that are significant emitters of ozone precursors and particulates. Any additional obligations on EME's facilities to further reduce their emissions of SO2, NOx and fine particulates to address local non-attainment with the 8-hour ozone and fine particulate matter standards will not be known until the states revise their implementation plans. Depending upon the final standards that are adopted, EME may incur substantial costs or experience other financial impacts resulting from required capital improvements or operational changes.

On January 17, 2006, the US EPA proposed revisions to its fine particulate standard. Under the proposal, the annual standard would remain the same but the 24-hour fine particulate standard would be significantly lowered. The US EPA is under court order to issue a final rule in December 2006. If the US EPA retains its proposed new 24-hour standard or lowers the annual standard, states may be required to impose further emission reductions beyond what would be necessary to meet the existing standards. Although EME may incur substantial costs or experience financial impacts as a result of any new standards, the uncertainties associated with this ongoing rulemaking at this time render EME unable to accurately estimate the costs to meet any such obligation. EME anticipates, however, that any such further emission reduction obligations would not be imposed until 2010 at the earliest.

Regional Haze—

The goal of the 1999 regional haze regulations is to restore visibility in mandatory federal Class I areas, such as national parks and wilderness areas, to natural background conditions in 60 years. Sources such as power plants that are reasonably anticipated to contribute to visibility impairment in Class I areas may be required to install Best Available Retrofit Technology (BART) or implement other control strategies to meet regional haze control requirements. States are required to revise their state implementation plans to demonstrate reasonable further progress towards meeting regional haze goals. Emission reductions that are achieved through other ongoing control programs may be sufficient to demonstrate reasonable progress toward the long-term goal, particularly for the first 10 to 15 year phase of the program. States must develop implementation plans by December 2007. It is possible that sources that are subject to the CAIR will be able to satisfy their obligations under the regional haze regulations through compliance with the more stringent CAIR. However, until the state implementation plans are revised, EME cannot predict whether it will be required to install BART or implement other control strategies, and cannot identify the financial impacts of any additional control requirements.

New Source Review Requirements—

Since 1999, the US EPA has pursued a coordinated compliance and enforcement strategy to address Clean Air Act New Source Review (NSR) compliance issues at the nation's coal-fired power plants. The NSR regulations impose certain requirements on facilities, such as electric generating stations, in the event that modifications are made to air emissions sources at a facility. The US EPA's strategy included both the filing of a number of suits against power plant owners, and the issuance of a number of administrative notices of violation to power plant owners alleging NSR violations. Neither EME nor any of its subsidiaries has been named as a defendant in these lawsuits and have not received any administrative Notices of Violation alleging NSR violations at any of their facilities.

In response to conflicting court decisions concerning the applicable emissions test used to determine whether an operational or physical change at an electric generating station would require the plant to install additional pollution controls, the US EPA, on October 13, 2005, proposed a change to the NSR program. The proposal put forth several options for a new emissions test based on the impact of a facility modification on a facility's maximum hourly emissions or its emissions per unit of energy produced. The existing NSR emissions test is based on the impact of a modification on a generating station's net annual emissions.

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In October 2005, the US EPA announced a revised NSR strategy to take account of recent US EPA rulemakings, such as the CAIR and regional haze rules, affecting coal-fired power plants. Under the revised strategy, while the US EPA will continue to pursue filed cases and cases in active negotiation, it intends to shift its future enforcement focus from coal-fired power plants to other sectors where compliance assurance activities have the potential to produce significant environmental benefits.

Clean Water Act—Cooling Water Intake Structures

On July 9, 2004, the US EPA published the final Phase II rule implementing Section 316(b) of the Clean Water Act establishing standards for cooling water intake structures at existing electrical generating stations that withdraw more than 50 million gallons of water per day and use more than 25% of that water for cooling purposes. The purpose of the regulation is to reduce substantially the number of aquatic organisms that are pinned against cooling water intake structures or drawn into cooling water systems. Pursuant to the regulation, a demonstration study must be conducted when applying for a new or renewed National Pollutant Discharge Elimination System (NPDES) wastewater discharge permit. If one can demonstrate that the costs of meeting the presumptive standards set forth in the regulation are significantly greater than the costs that the US EPA assumed in its rule making or are significantly disproportionate to the expected environmental benefits, a site-specific analysis may be performed to establish alternative standards. Depending on the findings of the demonstration studies, cooling towers and/or other mechanical means of reducing impingement/ entrainment may be required. EME has begun to collect impingement and entrainment data at its potentially affected Midwest Generation facilities in Illinois to begin the process of determining what corrective actions may need to be taken.

After the final promulgation of the Phase II cooling water intake structure regulation, legal challenges were filed by environmental groups, the attorneys general for six states, a utility trade association and several individual electric power generating companies. These cases have been consolidated and transferred to the United States Court of Appeals for the Second Circuit. A briefing schedule has been established for the case and a decision is not expected until sometime in 2006. The final requirements of the Phase II rule will not be fully known until these appeals are resolved and, if necessary, the regulation is revised by the US EPA. Although the Phase II rule could have a material impact on EME's operations, EME cannot reasonably determine the financial impact on it at this time because it is in the beginning stages of collecting the data required by the regulation and due to the legal challenges mentioned above which may affect the obligations imposed by the rule.

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Federal Legislative Initiatives

Environmental Remediation

With respect to EME's potential liabilities arising under CERCLA or similar laws for the investigation and remediation of contaminated property, EME accrues a liability to the extent the costs are probable and can be reasonably estimated. Midwest Generation has accrued approximately $2 million at December 31, 2005 for estimated environmental investigation and remediation costs for the Illinois Plants. This estimate is based upon the number of sites, the scope of work and the estimated costs for environmental activity where such expenditures could be reasonably estimated. Future estimated costs may vary based on changes in regulations or requirements of federal, state, or local governmental agencies, changes in technology, and actual costs of disposal. In addition, future remediation costs will be affected by the nature and extent of contamination discovered at the sites that requires remediation. Given the prior history of the operations at its facilities, EME cannot be certain that the existence or extent of all contamination at its sites has been fully identified. However, based on available information, management believes that future costs in excess of the amounts disclosed on all known and quantifiable environmental contingencies will not be material to EME's financial position.

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the Homer City facilities with respect to specified environmental liabilities. See "—Commercial Commitments—Guarantees and Indemnities" for a discussion of these indemnities.

State—Illinois

Air Quality

Beginning with the 2003 ozone season (May 1 through September 30), EME has been required to comply with an average NOx emission rate of 0.25 lb NOx/mmBtu of heat input. This limitation is commonly referred to as the East St. Louis State Implementation Plan. This regulation is a State of Illinois requirement. Each of the Illinois Plants complied with this standard in 2004. Beginning with the 2004 ozone season, the Illinois Plants became subject to the federally mandated "NOx SIP Call" regulation that provided ozone-season NOx emission allowances to a 19-state region east of the Mississippi. This program provides for NOx allowance trading similar to the SO2 (acid rain) trading program already in effect. EME has qualified for early reduction allowances by reducing NOx emissions at various plants ahead of the imposed deadline. Additionally, the installation of emission control technology at certain plants has demonstrated over-compliance at those individual plants with the pending NOx emission limitations. Finally, NOx emission trading will be utilized, as needed, to comply with any shortfall at plants where installation of emission control technology has demonstrated reductions at levels short of the NOx limitations.

During 2004, the Illinois Plants stayed within their NOx allocations by augmenting their allocation with early reduction credits generated within the fleet. In 2005, the Illinois Plants used banked allowances, along with some purchased allowances, to stay within their NOx allocations. After 2005, EME plans to continue to purchase allowances while evaluating the costs and benefits of various technologies to determine whether any additional pollution controls should be installed at the Illinois facilities.

On January 5, 2006, Illinois Governor Rod Blagojevich announced that he was directing the Illinois Environmental Protection Agency to draft rules that would impose state limits on mercury emissions from coal-fired power plants which would be more stringent than the US EPA's CAMR issued in May 2005. Illinois is required to submit a state implementation plan (SIP) for CAMR to the US EPA by November 17, 2006. The Governor or his spokespersons have said that rules to be submitted to the Illinois Pollution Control Board will require a 90% reduction in mercury emissions averaged across company-owned Illinois generators and a minimum reduction of 75% for individual generating units by June 30, 2009. A 90% reduction at each generating unit would be required by 2013. Buying or selling of emission allowances under the CAMR federal cap and trade program would be prohibited. The Pollution Control Board must act on proposed rules submitted by the Illinois EPA after evidentiary hearings, including the presentation and cross-examination of expert testimony. After the Pollution Control Board adopts rules, they must be submitted to the General Assembly's Joint Committee on Administrative Rules for notice, hearing, and adoption, rejection or modification. Rules adopted through such state proceedings are also subject to court appeal. EME is not able at this time to predict the final form of these rules or provide an estimate of their financial impact.

During 2006, the Illinois EPA is expected to begin the process of developing a SIP to implement the federal CAIR which requires reductions in NOx and SO2. This SIP is to be submitted to the US EPA by September 11, 2006. The Illinois EPA has also begun to develop SIPs to meet National Ambient Air Quality Standards for 8-hour ozone and fine particulates. These SIPs will be developed with the intent of bringing non-attainment areas, such as Chicago, into attainment. They are expected to deal with all emission sources, not just power generators, and to address emissions of NOx, SO2, and Volatile Organic Carbon. These SIPs are to be submitted to the US EPA by June 15, 2007 for

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8-hour ozone, and by April 5, 2008 for fine particulates. EME is not able at this time to predict the final form of the SIPs or to estimate their financial impact.

Water Quality

The Illinois EPA is reviewing the water quality standards for the Des Plaines River adjacent to the Joliet Station and immediately downstream of the Will County Station to determine if the use classification should be upgraded. An upgraded use classification could result in more stringent limits being applied to wastewater discharges to the river from these plants. If the existing use classification is changed, the limits on the temperature of the discharges from the Joliet and Will County plants may be made more stringent. The Illinois EPA has also begun a review of the water quality standards for the Chicago River and Chicago Sanitary and Ship Canal which are adjacent to the Fisk and Crawford Stations. Proposed changes to the existing standards are still being developed. Accordingly, EME is not able to estimate the financial impact of potential changes to the water quality standards. However, the cost of additional cooling water treatment, if required, could be substantial.

State—Pennsylvania

Air Quality

During 2006, the Pennsylvania Department of Environmental Protection (PADEP) is expected to begin the process of developing a SIP to implement the federal CAIR which requires reductions in NOx and SO2. This SIP is to be submitted to the US EPA by September 11, 2006. The Ozone Transport Commission, of which Pennsylvania is a member, is developing a model rule that would continue to allow SO2 and NOx emissions trading, but would impose more stringent limits on SO2 and NOx emissions and would phase in these reductions more quickly than is required by CAIR. EME does not know whether the northeast states will ultimately agree to this model rule or whether Pennsylvania will implement such a rule. Pennsylvania is also required to develop a SIP to implement the federal CAMR, which SIP is to be submitted to the US EPA by November 17, 2006. With respect to mercury, the PADEP has recently announced that it plans to issue a proposed rule that would require coal-fired power plants to reduce mercury emissions by 80% by 2010 and 90% by 2015. The proposed rule would not allow the use of emissions trading to achieve compliance. However, the proposal would apparently allow facilities to comply with the mercury regulation by installing specific pollution control technology for sulfur dioxide and nitrogen oxides and by burning 100% bituminous coal. EME is not able at this time to predict the final form of the SIPs or to estimate their financial impact.

Water Quality

The discharge from the treatment plant receiving the wastewater stream from EME's Unit 3 flue gas desulfurization system at the Homer City facilities has exceeded the stringent, water-quality based limits for selenium in the station's NPDES permit. As a result, EME was notified in April 2002 by PADEP that it was included in the Quarterly Noncompliance Report submitted to the US EPA. EME investigated a number of technical alternatives for maximizing the level of selenium removal in the discharge and performed various pilot studies. While some of the pilot studies improved the performance of the treatment system, the discharge still was not able to consistently meet the selenium effluent limits. EME identified additional options for achieving the selenium limits, and, with PADEP's approval, has undertaken a pilot program utilizing biological treatment. EME prepared a draft of a consent order and agreement addressing the selenium issue and presented it to PADEP for consideration in connection with the renewal of the station's NPDES permit. PADEP has included civil penalties in consent agreements related to other facilities with selenium treatment issues, but the amount of civil penalties that may be assessed against EME cannot be estimated at this time.

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Climate Change

There have been several petitions from states and other parties to compel the US EPA to regulate greenhouse gases under the Clean Air Act. Also, in 2004, several states and environmental organizations brought a complaint in federal court in New York, alleging that several electric utility corporations are jointly and severally liable under a theory of public nuisance for damages caused by the alleged contribution to global warming resulting from carbon dioxide emissions from coal-fired power plants owned and operated by these companies or their subsidiaries. Neither EME nor its subsidiaries were named as defendants in the complaint. The case was dismissed and is currently on appeal with the United States Court of Appeals for the Second Circuit.

On December 20, 2005, seven northeastern states entered into a Memorandum of Understanding to create a regional initiative to establish a cap and trade greenhouse gas program for electric generators, referred to as the Regional Greenhouse Gas Initiative, or RGGI. The model RGGI rule is scheduled to be announced within the next few months. The current proposal is to commence the program in 2009 by setting a cap (for the 2009 to 2015 period) on allowances based on carbon dioxide emissions from 2000 to 2004 and reducing emissions by 10% between 2015 and 2020. The Memorandum of Understanding provides that at least 25% of the state allowance allocations be set aside for public purposes, suggesting that from the commencement of the program, generators subject to the RGGI may receive allowances that are materially less than their carbon dioxide emissions. Illinois and Pennsylvania are not signatories to the RGGI, although Pennsylvania has participated as an observer of the process. If Pennsylvania were to join the RGGI, this could have a material impact on EME's Homer City facility.

In California, Governor Schwarzenegger issued an executive order on June 1, 2005, setting forth targets for greenhouse gas reductions. The targets call for a reduction of greenhouse gas emissions to 2000 levels by 2010; a reduction of greenhouse gas emissions to 1990 levels by 2020; and a reduction of greenhouse gas emissions to 80% below 1990 levels by 2050. The California Public Utilities Commission is addressing climate change related issues in various regulatory proceedings.

The ultimate outcome of the climate change debate could have a significant economic effect on EME. Any legal obligation that would require EME to reduce substantially its emissions of carbon dioxide would likely require extensive mitigation efforts and would raise considerable uncertainty about the future viability of fossil fuels, particularly coal, as an energy source for new and existing electric generating facilities.

Note 17. Lease Commitments

EME leases office space, property and equipment under noncancelable lease agreements that expire in various years through 2030.

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Future minimum payments for operating leases at December 31, 2005 are:

Years Ending December 31,	Operating Leases
	(in millions)
2006	$	363
2007		360
2008		358
2009		354
2010		340
Thereafter		2,991

Total future commitments	$	4,766

The minimum commitments do not include contingent rentals with respect to the wind projects which may be paid under certain leases on the basis of a percentage of sales calculation if this is in excess of the stipulated minimum amount.

Operating lease expense amounted to $201 million, $210 million and $234 million in 2005, 2004 and 2003, respectively.

Sale-Leaseback Transactions

On December 7, 2001, a subsidiary of EME completed a sale-leaseback of EME's Homer City facilities to third-party lessors for an aggregate purchase price of $1.6 billion, consisting of $782 million in cash and assumption of debt (the fair value of which was $809 million). Under the terms of the 33.67-year leases, EME's subsidiary is obligated to make semi-annual lease payments on each April 1 and October 1. If a lessor intends to sell its interest in the Homer City facilities, EME has a right of first refusal to acquire the interest at fair market value. Minimum lease payments (included in the table above) are $152 million in 2006, $152 million in 2007, $152 million in 2008, $151 million in 2009, and $155 million in 2010, and the total remaining minimum lease payments are $2.0 billion. The gain on the sale of the facilities has been deferred and is being amortized over the term of the leases.

On August 24, 2000, a subsidiary of EME completed a sale-leaseback of EME's Powerton and Joliet power facilities located in Illinois to third-party lessors for an aggregate purchase price of $1.4 billion. Under the terms of the leases (33.75 years for Powerton and 30 years for Joliet), EME's subsidiary makes semi-annual lease payments on each January 2 and July 2, which began January 2, 2001. EME guarantees its subsidiary's payments under the leases. If a lessor intends to sell its interest in the Powerton or Joliet power facility, EME has a right of first refusal to acquire the interest at fair market value. Minimum lease payments (included in the table above) are $185 million each year in 2006 through 2009, and $170 million in 2010, and the total remaining minimum lease payments are $942 million. The gain on the sale of the power facilities has been deferred and is being amortized over the term of the leases.

Note 18. Related Party Transactions

Specified administrative services such as payroll and employee benefit programs, all performed by Edison International or Southern California Edison Company employees, are shared among all affiliates of Edison International, and the costs of these corporate support services are allocated to all affiliates, including EME. Costs are allocated based on one of the following formulas: percentage of time worked, equity in investment and advances, number of employees, or multi-factor (operating revenues, operating expenses, total assets and number of employees). In addition, services of Edison

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International or Southern California Edison employees are sometimes directly requested by EME and these services are performed for EME's benefit. Labor and expenses of these directly requested services are specifically identified and billed at cost. EME believes the allocation methodologies utilized are reasonable. EME made reimbursements for the cost of these programs and other services, which amounted to $84 million, $60 million and $63 million in 2005, 2004 and 2003, respectively. At December 31, 2005 and 2004, the amount due to Edison International was $7 million and $26 million, respectively.

EME participates in the insurance program of Edison International, including property, general liability, workers compensation and various other specialty policies. EME's insurance premiums are generally based on EME's share of risk related to each policy. In connection with the property insurance program, a portion of the risk is reinsured by a captive insurance subsidiary of Edison International.

EME records accruals for tax liabilities and/or tax benefits which are settled quarterly according to a series of tax-allocation agreements as described in Note 2. Under these agreements, EME recognized tax liabilities (benefits) applicable to continuing operations of $268 million, $(379) million and $(99) million for 2005, 2004 and 2003, respectively. See Note 13—Income Taxes. Amounts included in Accounts payable—affiliates associated with the tax liabilities totaled $22 million at December 31, 2005. Amounts included in Accounts receivable—affiliates associated with the tax benefits totaled $46 million at December 31, 2004.

Edison Mission Operation & Maintenance, Inc., an indirect, wholly owned affiliate of EME, has entered into operation and maintenance agreements with partnerships in which EME has a 50% or less ownership interest. Pursuant to the negotiated agreements, Edison Mission Operation & Maintenance is to perform all operation and maintenance activities necessary for the production of power by these partnerships' facilities. The agreements continue until terminated by either party. Edison Mission Operation & Maintenance is paid for all costs incurred with operating and maintaining such facilities and may also earn an incentive compensation as set forth in the agreements. EME recorded revenues under the operation and maintenance agreements of $24 million for each year in 2005, 2004 and 2003. Accounts receivable—affiliates for Edison Mission Operation & Maintenance totaled $7 million and $6 million at December 31, 2005 and 2004, respectively.

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Note 19. Supplemental Statements of Cash Flows Information

		Years Ended December 31,
		2005		2004		2003
		(in millions)
Cash paid
	Interest (net of amount capitalized)	$	309	$	307	$	280
	Income taxes (receipts)		149		6		(102	)
	Cash payments under plant operating leases		293		240		271
Details of assets acquired
	Fair value of assets acquired	$	154	$	—	$	3
	Liabilities assumed		—		—		—

	Net cash paid for acquisitions	$	154	$	—	$	3

Non-cash activities from consolidation of variable interest entity
	Assets	$	37	$	—	$	—
	Liabilities		27		—		—
Non-cash activities from de-consolidation of variable interest entity
	Assets	$	—	$	220	$	—
	Liabilities		—		254		—

During the year ended December 31, 2005, EME received a capital contribution of $20 million from its parent for investments in an entity which was previously owned by EME's affiliate, Edison Capital. This entity holds interests in various wind projects.

During the year ended December 31, 2004, EME declared a dividend payable to MEHC totaling $305 million.

Note 20. Quarterly Financial Data (unaudited)

2005	First		Second		Third(i)			Fourth			Total
	(in millions)
Operating revenues	$	517	$	421	$	680		$	647		$	2,265
Operating income		125		18		277			263			683
Income from continuing operations		57		19		173	(ii)		165			414
Discontinued operations, net(iii)		7		21		27			(26	)		29
Income before accounting change		64		40		200			139			443
Net income		64		40		200			138			442

2004	First			Second			Third(i)			Fourth			Total
Operating revenues	$	393		$	363		$	511		$	386		$	1,653
Operating income (loss)		(17	)		(977	)(iv)		101	(v)		(44	)(vi)		(937	)
Income (loss) from continuing operations		(13	)		(610	)(iv)		90	(v)		(27	)(vi)		(560	)
Discontinued operations, net(iii)		46			26			498	(vii)		120	(vii)		690
Net income (loss)		33			(584	)		588			93			130

(i): Reflects EME's seasonal pattern, in which the majority of earnings from domestic projects are earned and recorded in the third quarter of each year.

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(ii): Reflects a $55 million pre-tax ($34 million, after tax) impairment loss on equity method investment related to the March Point project.
(iii): See Note 8. Divestitures—Discontinued Operations for more information.
(iv): Reflects a $951 million pre-tax ($585 million, after tax) loss on termination of the lease related to the Collins Station and the return of its ownership to EME.
(v): Reflects asset impairment charge of $29 million pre-tax ($18 million, after tax) related to impairment of six of the eight remaining small peaking units in Illinois.
(vi): Reflects a $56 million pre-tax ($34 million, after tax) charge related to an estimate of possible future payments under a contract indemnity agreement related to asbestos claims with respect to activities at the Illinois Plants prior to their acquisition in 1999.
(vii): Reflects gain on sale of international projects. See Note 8. Divestitures—Discontinued Operations for further explanation.

Note 21. Subsequent Events

Transfer of Wind Projects from an Affiliate

On April 1, 2006, EME received, as a capital contribution, ownership interests in a portfolio of wind projects located in Iowa and Minnesota and a small biomass project. The acquisition was accounted for as a transaction between entities under common control. As such, the assets and liabilities of the projects acquired were recorded at historical cost on the acquisition date for a net book value of approximately $76 million. The principal components of the net book value of assets and liabilities at April 1, 2006 are current assets ($8 million), property, plant and equipment, net ($156 million), other non-current assets ($42 million), deferred income ($56 million) and deferred income taxes ($59 million). EME's historical financial statements have been adjusted for all periods presented to reflect the acquisition as though EME had always owned the projects. Summarized results of the projects acquired for periods presented prior to the acquisition date of April 1, 2006 are as follows:

	Years Ended December 31,
	Years Ended December 31,									Three Months Ended March 31, 2006
	2003			2004			2005			Three Months Ended March 31, 2006
	(in millions)									(in millions) (unaudited)
Total operating revenues	$	2		$	14		$	17		$	4
Income (loss) before income taxes and minority interest		(8	)		3			(3	)		(1	)
Benefit for income taxes		(7	)		(5	)		(13	)		(3	)
Income (loss) from continuing operations		(1	)		8			10			2

MISO Revenue Sufficiency Guarantee Charges

F-77

offers for RSG charges, it violated the terms of its tariff. The FERC order then proceeded to require the MISO to recalculate the RSG charges back to April 1, 2005, and to make refunds to customers, with interest, reflecting the recalculated charges. In order to make such refunds, it is likely that the MISO will attempt to impose retroactively RSG charges on those who submitted virtual supply offers during the recalculation period. EMMT made virtual supply offers in the MISO during this period on which no RSG charges were imposed, and thus may be subject to a claim for refunds from the MISO (which claim will be contested by EMMT). Because calculation of any claimed liability for refunds depends on information not currently available to it, EMMT cannot reasonably estimate a range of loss related to this matter. In addition, the FERC's April 25 order has been challenged by the MISO and other parties, including EMMT, and as the FERC has issued an extension of time to comply with the requirements of the order until after the date of issuance of an order on rehearing, the eventual outcome of these proceedings is unclear.

F-78

SCHEDULE I

EDISON MISSION ENERGY AND SUBSIDIARIES
CONDENSED FINANCIAL INFORMATION OF PARENT
Condensed Balance Sheets
(In millions)

	December 31,
	2005		2004
Assets
Cash and cash equivalents	$	800	$	1,976
Short-term investments		183		120
Affiliate receivables		2		48
Assets under energy trading and price risk management		—		—
Other current assets		7		27

Total current assets		992		2,171
Investments in subsidiaries		4,302		6,018
Investment in discontinued operations		—		—
Other long-term assets		88		39

Total Assets	$	5,382	$	8,228

Liabilities and Shareholder's Equity
Accounts payable and accrued liabilities	$	81	$	467
Affiliate payables		286		2,927
Short-term obligations		—		—
Current maturities of long-term debt		—		—

Total current liabilities		367		3,394
Long-term obligations		1,598		1,598
Long-term affiliate debt		1,440		1,442
Deferred taxes and other		67		49

Total Liabilities		3,472		6,483
Common Shareholder's Equity		1,910		1,745

Total Liabilities and Shareholder's Equity	$	5,382	$	8,228

F-79

SCHEDULE I

EDISON MISSION ENERGY AND SUBSIDIARIES
CONDENSED FINANCIAL INFORMATION OF PARENT
Condensed Statements of Income
(In millions)

	Years Ended December 31,
	2005			2004			2003
Net gains (losses) from energy trading and price risk management	$	—		$	(26	)	$	—
Operating expenses		(110	)		(138	)		(108	)

Operating loss		(110	)		(164	)		(108	)
Equity in income from continuing operations of subsidiaries		680			360			181
Equity in income (loss) from discontinued operations of subsidiaries		—			—			1
Interest expense and other		(270	)		(389	)		(295	)

Income (loss) before income taxes		300			(193	)		(221	)
Benefit for income taxes		(142	)		(323	)		(240	)

Net income	$	442		$	130		$	19

F-80

SCHEDULE I

EDISON MISSION ENERGY AND SUBSIDIARIES
CONDENSED FINANCIAL INFORMATION OF PARENT
Condensed Statements of Cash Flows
(In millions)

	Years Ended December 31,
	2005			2004			2003
Net cash provided by (used in) operating activities	$	(2,594	)	$	1,997		$	998
Net cash provided by (used in) financing activities		(378	)		(52	)		—
Net cash provided by (used in) investing activities		1,796			(85	)		(930	)

Net increase (decrease) in cash and cash equivalents		(1,176	)		1,860			68
Cash and cash equivalents at beginning of period		1,976			116			48

Cash and cash equivalents at end of period	$	800		$	1,976		$	116

Cash dividends received from subsidiaries	$	250		$	529		$	974

F-81

SCHEDULE II

EDISON MISSION ENERGY AND SUBSIDIARIES
VALUATION AND QUALIFYING ACCOUNTS
(In millions)

			Additions
Description	Balance at Beginning of Year		Charged to Costs and Expenses		Charged to Other Accounts		Deductions		Balance at End of Year
Year Ended December 31, 2005 Allowance for doubtful accounts	$	—	$	—	$	—	$	—	$	—
Year Ended December 31, 2004 Allowance for doubtful accounts	$	—	$	—	$	—	$	—	$	—
Year Ended December 31, 2003 Allowance for doubtful accounts(1)	$	8.9	$	—	$	—	$	8.9	$	—

(1): Excludes allowance for doubtful accounts of discontinued operations of $6.5 million at December 31, 2003.

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No dealer, salesperson or other person is authorized to give any information or to represent anything not contained in this prospectus. You must not rely on any unauthorized information or representations. This prospectus does not offer to sell or ask for offers to buy any securities other than those to which this prospectus relates and it does not constitute an offer to sell or ask for offers to buy any of the securities in any jurisdiction where it is unlawful, where the person making the offer is not qualified to do so, or to any person who cannot legally be offered the securities. The information contained in this prospectus is current only as of its date.

Each broker-dealer that receives new notes for its own account pursuant to the exchange offer must acknowledge that it will deliver a prospectus in connection with any resale of such new notes. By so acknowledging and by delivering a prospectus, a broker-dealer will not be deemed to admit that it is an "underwriter" within the meaning of the Securities Act. This prospectus, as it may be amended or supplemented from time to time, may be used by a broker-dealer in connection with resales of new notes received in exchange for old notes where such old notes were acquired by such broker-dealer as a result of market-making activities or other trading activities. Edison Mission Energy, for a period of 90 days after the consummation of the exchange offer, will make this prospectus available to any broker-dealer for use in connection with any such resale. See "Plan of Distribution."

Table of Contents

		Page
About This Prospectus		i
Where You Can Find More Information		i
Forward-Looking Statements		ii
Industry And Market Data		iii
Notice To New Hampshire Residents		iii
Summary		1
Risk Factors		11
The Exchange Offer		20
Use Of Proceeds		27
Capitalization		28
Selected Consolidated Financial Data		29
Management's Discussion And Analysis Of Financial Condition And Results Of Operations		32
Quantitative And Qualitative Disclosures About Market Risk		97
Business		97
Management		117
Executive Compensation		119
Certain Relationships And Related Transactions		128
Description Of The Notes		129
Material U.S. Federal Income Tax Consequences		140
Plan of Distribution		143
Changes In And Disagreements With Accountants On Accounting And Financial Disclosure		144
Legal Matters		144
Experts		144
Index To Consolidated Financial Statements		F-1

EDISON MISSION ENERGY

Offer to exchange $500,000,000 aggregate
principal amount of 7.50% Senior Notes
due 2013 (CUSIPs 281023 AL 5,
U27811 AC 9 and 281023 AM 3)
for $500,000,000 7.50% Senior
Notes due 2013
which have been registered under the
Securities Act of 1933, as amended,
and $500,000,000 aggregate principal amount
of 7.75% Senior Notes due 2016 (CUSIPs
281023 AP 6, U27811 AD 7
and 281023 AQ 4) for $500,000,000 7.75% Senior Notes due 2016 which have
been registered under
the Securities Act

PROSPECTUS

Dated October 12, 2006

PART II

INFORMATION NOT REQUIRED IN PROSPECTUS

ITEM 20. Indemnification of Directors and Officers

We are a Delaware corporation. Section 102 of the Delaware General Corporation Law, or the "DGCL," as amended, allows a corporation to eliminate the personal liability of directors of a corporation to the corporation or its stockholders for monetary damages for breach of fiduciary duty as a director, except where the director breached the duty of loyalty, failed to act in good faith, engaged in intentional misconduct or knowingly violated a law, authorized the payment of a dividend or approved a stock repurchase in violation of Delaware corporate law or obtained an improper personal benefit.

Section 145 of the DGCL provides, among other things, that we may indemnify any person who was or is a party or is threatened to be made a party to any threatened, pending or completed action, suit or proceeding—other than an action by or in the right of the corporation—by reason of the fact that the person is or was a director, officer, agent, or employee of the corporation, or is or was serving at our request as a director, officer, agent or employee of another corporation, partnership, joint venture, trust or other enterprise against expenses, including attorneys' fees, judgments, fines and amounts paid in settlement actually and reasonably incurred by the person in connection with such action, suit or proceeding. The power to indemnify applies (a) if such person is successful on the merits or otherwise in defense of any action, suit or proceeding or (b) if such person acting in good faith and in a manner he reasonably believed to be in the best interest, or not opposed to the best interest, of the corporation, and with respect to any criminal action or proceeding had no reasonable cause to believe his or her conduct was unlawful. The power to indemnify applies to actions brought by or in the right of the corporation as well but only to the extent of defense expenses, including attorneys' fees but excluding amounts paid in settlement, actually and reasonably incurred and not to any satisfaction of judgment or settlement of the claim itself, and with the further limitation that in such actions no indemnification shall be made in the event of any adjudication of liability to the corporation, unless the court believes that in light of all the circumstances indemnification should apply.

Section 174 of the DGCL provides, among other things, that a director, who willfully or negligently approves of an unlawful payment of dividends or an unlawful purchase or redemption of stock, may be held liable for such actions. A director who was either absent when the unlawful actions were approved or dissented at the time, may avoid liability by causing his or her dissent to such actions to be entered in the books containing minutes of the meetings of the board of directors at the time such action occurred or immediately after such absent director receives notice of the unlawful acts.

Our certificate of incorporation provides that the liability of the directors of our corporation for monetary damages shall be eliminated to the fullest extent permissible under Delaware Law. Our by-laws provides that any indemnification thereunder shall be made by the corporation only as authorized in the specific case upon a determination that indemnification of the director or officer is proper in the circumstances because such person has met the applicable standard of conduct set forth in the by-laws.

Insofar as indemnification for liabilities arising under the Securities Act may be permitted to directors, officers or persons controlling the registrant pursuant to the foregoing provisions, the registrant has been advised that in the opinion of the Commission such indemnification is against public policy as expressed in the Securities Act and is, therefore, unenforceable. In the event that a claim for indemnification against such liabilities (other than the payment by the registrant of expenses incurred or paid by a director, officer or controlling person of the registrant in the successful defense of any action, suit or proceeding) is asserted by such director, officer or controlling person in

II-1

connection with the securities being registered, the registrant will, unless in the opinion of its counsel the matter has been settled by controlling precedent, submit to a court of appropriate jurisdiction the question whether such indemnification by it is against public policy as expressed in the Securities Act and will be governed by the final adjudication of such issue.

ITEM 21. Exhibits and Financial Statement Schedules

(a): Exhibits

See the Exhibit Index, which is incorporated by reference herein.

ITEM 22. Undertakings

(a): The undersigned registrant hereby undertakes:

(1) To file, during any period in which offers or sales are being made, a post-effective amendment to this registration statement:

(i) To include any prospectus required by section 10(a)(3) of the Securities Act of 1933, or the Securities Act.

(ii) To reflect in the prospectus any facts or events arising after the effective date of the registration statement (or the most recent post-effective amendment thereof) which, individually or in the aggregate, represent a fundamental change in the information set forth in the registration statement. Notwithstanding the foregoing, any increase or decrease in volume of securities offered (if the total dollar value of securities offered would not exceed that which was registered) and any deviation from the low or high end of the estimated maximum offering range may be reflected in the form of the prospectus filed with the Commission pursuant to Rule 424(b) if, in the aggregate, the changes in volume and price represent no more than a 20% change in the maximum aggregate offering price set forth in the "Calculation of Registration Fee" table in the effective registration statement;

(iii) To include any material information with respect to the plan of distribution not previously disclosed in the registration statement or any material change to such information in the registration statement.

(2) That, for the purpose of determining any liability under the Securities Act, each such post-effective amendment shall be deemed to be a new registration statement relating to the securities offered therein, and the offering of such securities at that time shall be deemed to be the initial bona fide offering thereof.

(3) To remove from registration by means of a post-effective amendment any of the securities being registered which remain unsold at the termination of the offering.

(4) Insofar as indemnification for liabilities arising under the Securities Act may be permitted to directors, officers and controlling persons of the registrant pursuant to the foregoing provisions, or otherwise, the registrant has been advised that in the opinion of the Securities and Exchange Commission such indemnification is against public policy as expressed in the Act and is, therefore, unenforceable. In the event that a claim for indemnification against such liabilities (other than the payment by the registrant of expenses incurred or paid by a director, officer or controlling person, if any, of the registrant in the successful defense of any action, suit, or proceeding) is asserted by such director, officer or controlling person in connection with the securities being registered, the registrant will, unless in the opinion of its counsel the matter has been settled by controlling precedent, submit to a court of appropriate jurisdiction the question whether such indemnification by it is against public policy as expressed in the Act and will be governed by the final adjudication of such issue.

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(5) The undersigned registrant hereby undertakes to supply by means of post-effective amendment all information concerning a transaction, and the company being acquired involved therein, that was not the subject of and included in the registration statement when it became effective.

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SIGNATURES

Pursuant to the requirements of the Securities Act of 1933, the registrant has duly caused this registration statement to be signed on its behalf by the undersigned, thereunto duly authorized, in the City of Irvine, State of California, on this 12th day of October 2006.

		EDISON MISSION ENERGY


		By:		/s/ W. James Scilacci W. James Scilacci Senior Vice President and Chief Financial Officer

Each person whose signature appears below hereby severally constitutes and appoints W. James Scilacci and Mark C. Clarke, and each of them singly, as his true and lawful attorneys-in-fact and agents with full power of substitution and resubstitution for him and in his name, place and stead, and in any and all capacities to sign any and all amendments (including pre-effective and post-effective amendments) to this registration statement, and to file the same with all exhibits thereto, and other documents in connection therewith, with the Securities and Exchange Commission, and hereby grants to such attorneys-in-fact and agents full power and authority to do and perform each and every act and thing requisite and necessary to be done, as fully to all intents and purposes as he might or could do in person, hereby ratifying and confirming all that said attorneys-in-fact and agents, or their substitute or substitutes may lawfully do or cause to be done by virtue hereof.

Pursuant to the requirements of the Securities Act of 1933, this registration statement has been signed below by the following persons on behalf of the registrant and in the capacities and on the dates indicated.

Signature	Title	Date

/s/ Theodore F. Craver, Jr. Theodore F. Craver, Jr.	Director, Chairman of the Board, President and Chief Executive Officer (Principal Executive Officer)	October 12, 2006

/s/ Mark C. Clarke Mark C. Clarke	Vice President and Controller (Controller or Principal Accounting Officer)	October 12, 2006

/s/ Thomas R. McDaniel Thomas R. McDaniel	Director	October 12, 2006

/s/ Jacob A. Bouknight, Jr. Jacob A. Bouknight, Jr.	Director	October 12, 2006

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EXHIBIT INDEX

Exhibit No.		Description
2.1		Asset Purchase Agreement, dated August 1, 1998, between Pennsylvania Electric Company, NGE Generation, Inc., New York State Electric & Gas Corporation and Mission Energy Westside, Inc., incorporated by reference to Exhibit 2.4 to Edison Mission Energy's Form 10-K for the year ended December 31, 1998.
2.2		Asset Sale Agreement, dated March 22, 1999, between Commonwealth Edison Company and Edison Mission Energy as to the Fossil Generating Assets, incorporated by reference to Exhibit 2.5 to Edison Mission Energy's Form 10-K for the year ended December 31, 1998.
2.3		Purchase and Sale Agreement, dated May 10, 2000, between Edison Mission Energy, P & L Coal Holdings Corporation and Gold Fields Mining Corporation, incorporated by reference to Exhibit 2.9 to Edison Mission Energy's 10-Q for the quarter ended September 30, 2000.
2.4		Stock Purchase Agreement, dated November 17, 2000 between Mission Del Sol, LLC and Texaco Inc., incorporated by reference to Exhibit 2.11 to Edison Mission Energy's Form 10-K for the year ended December 31, 2000.
2.5		Purchase Agreement, dated July 20, 2004, between Edison Mission Energy and Origin Energy New Zealand Limited, incorporated by reference to Exhibit 2.1 to Edison Mission Energy's Form 8-K dated September 30, 2004.
2.6		Purchase Agreement, dated July 29, 2004, by and among Edison Mission Energy, IPM Eagle LLP, International Power plc, Mitsui & Co., Ltd. and the other sellers on the signature page thereto, incorporated by reference to Exhibit 2.1 to Edison Mission Energy's Form 10-Q for the quarter ended September 30, 2004.
3.1		Certificate of Incorporation of Edison Mission Energy, dated August 14, 2001, incorporated by reference to Exhibit 3.1 to Edison Mission Energy's Form 8-K dated October 26, 2001.
3.1.1		Certificate of Amendment to the Certificate of Incorporation of Edison Mission Energy dated May 4, 2004, incorporated by reference to Exhibit 3.1.1 to Edison Mission Energy's Form 10-Q for the quarter ended March 31, 2004.
3.2		By-Laws of Edison Mission Energy dated May 4, 2004, incorporated by reference to Exhibit 3.1.1 to Edison Mission Energy's Form 10-Q for the quarter ended March 31, 2004.
4.1		Indenture, dated as of June 6, 2006, between Edison Mission Energy and Wells Fargo Bank, National Association, as trustee, incorporated by reference to Exhibit 4.1 to Edison Mission Energy's Form 8-K dated June 8, 2006.
4.1.1		First Supplemental Indenture, dated as of June 6, 2006, between Edison Mission Energy and Wells Fargo Bank, National Association, as trustee, supplementing the Indenture, dated as of June 6, 2006, incorporated by reference to Exhibit 4.1.1 to Edison Mission Energy's Form 8-K dated June 8, 2006.
4.1.2		Second Supplemental Indenture, dated as of June 6, 2006, between Edison Mission Energy and Wells Fargo Bank, National Association, as trustee, supplementing the Indenture, dated as of June 6, 2006, incorporated by reference to Exhibit 4.1.2 to Edison Mission Energy's Form 8-K dated June 8, 2006.
4.2†		Registration Rights Agreement, dated as of June 6, 2006, between Edison Mission Energy and J.P. Morgan Securities Inc., as representatives of the Initial Purchasers.

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4.3		Indenture, dated as of August 10, 2001, among Edison Mission Energy and The Bank of New York as Trustee, incorporated by reference to Exhibit 4.1 to Edison Mission Energy's Registration Statement on Form S-4 to the Securities and Exchange Commission on August 29, 2001.
4.3.1		First Supplemental Indenture, dated as of May 17, 2006, by and among EME and The Bank of New York, as trustee, supplementing the Indenture, dated as of August 10, 2001, pursuant to which EME's 10% Senior Notes due 2008 were issued, incorporated by reference to Exhibit 4.1 to Edison Mission Energy's Form 8-K dated May 19, 2006.
4.3.2		Form of 10% Senior Note due 2008 (included in Exhibit 4.1 to Edison Mission Energy's Registration Statement on Form S-4 to the Securities and Exchange Commission on August 29, 2001).
4.4		Registration Rights Agreement, dated as of August 7, 2001, among Edison Mission Energy, Credit Suisse First Boston Corporation, BMO Nesbitt Burns Corp., Salomon Smith Barney Inc., SG Cowen Securities Corporation, TD Securities (USA) Inc. and Westdeutsche Landesbank Girozentrale (Düsseldorf), incorporated by reference to Exhibit 4.2 to Edison Mission Energy's Registration Statement on Form S-4 to the Securities and Exchange Commission on August 29, 2001.
4.5		Indenture, dated as of April 5, 2001, among Edison Mission Energy and United States Trust Company of New York as Trustee, incorporated by reference to Exhibit 4.20 to Edison Mission Energy's and Midwest Generation LLC's Registration Statement on Form S-4 to the Securities and Exchange Commission on April 20, 2001.
4.5.1		First Supplemental Indenture, dated as of May 17, 2006, by and among EME and The Bank of New York, as trustee, supplementing the Indenture, dated as of April 5, 2001, pursuant to which EME's 9.875% Senior Notes due 2011 were issued, incorporated by reference to Exhibit 4.2 to Edison Mission Energy's Form 8-K dated May 19, 2006.
4.5.2		Form of 9.875% Senior Note due 2011 (included in Exhibit 4.2 to Edison Mission Energy's Registration Statement on Form S-4 to the Securities and Exchange Commission on April 24, 2001).
4.6		Registration Rights Agreement, dated as of April 2, 2001, among Edison Mission Energy and Credit Suisse First Boston Corporation and Westdeutsche Landesbank Girozentrale (Düsseldorf) as representatives of the Initial Purchasers, incorporated by reference to Exhibit 4.2 to Edison Mission Energy's Registration Statement on Form S-4 to the Securities and Exchange Commission on April 24, 2001.
4.7		Guarantee, dated as of August 17, 2000, made by Edison Mission Energy, as Guarantor in favor of Powerton Trust I, as Owner Lessor, incorporated by reference to Exhibit 4.9 to Edison Mission Energy's and Midwest Generation LLC's Registration Statement on Form S-4 to the Securities and Exchange Commission on April 20, 2001.
4.7.1		Schedule identifying substantially identical agreement to Guarantee constituting Exhibit 4.7 hereto, incorporated by reference to Exhibit 4.9.1 to Edison Mission Energy's and Midwest Generation LLC's Registration Statement on Form S-4 to the Securities and Exchange Commission on April 20, 2001.
4.8		Guarantee, dated as of August 17, 2000, made by Edison Mission Energy, as Guarantor in favor of Joliet Trust I, as Owner Lessor, incorporated by reference to Exhibit 4.10 to Edison Mission Energy's and Midwest Generation LLC's Registration Statement on Form S-4 to the Securities and Exchange Commission on April 20, 2001.

II-6

4.8.1		Schedule identifying substantially identical agreement to Guarantee constituting Exhibit 4.8 hereto, incorporated by reference to Exhibit 4.10.1 to Edison Mission Energy's and Midwest Generation LLC's Registration Statement on Form S-4 to the Securities and Exchange Commission on April 20, 2001.
4.9		Registration Rights Agreement, dated as of August 17, 2000, among Edison Mission Energy, Midwest Generation, LLC and Credit Suisse First Boston Corporation and Lehman Brothers Inc., as representatives of the Initial Purchasers, incorporated by reference to Exhibit 4.11 to Edison Mission Energy's and Midwest Generation LLC's Registration Statement on Form S-4 to the Securities and Exchange Commission on April 20, 2001.
4.10		Participation Agreement (T1), dated as of August 17, 2000, by and among, Midwest Generation, LLC, Powerton Trust I, as the Owner Lessor, Wilmington Trust Company, as the Owner Trustee, Powerton Generation I, LLC, as the Owner Participant, Edison Mission Energy, United States Trust Company of New York, as the Lease Indenture Trustee, and United States Trust Company of New York, as the Pass Through Trustees, incorporated by reference to Exhibit 4.12 to Edison Mission Energy's and Midwest Generation LLC's Registration Statement on Form S-4 to the Securities and Exchange Commission on April 20, 2001.
4.10.1		Schedule identifying substantially identical agreement to Participation Agreement constituting Exhibit 4.10 hereto, incorporated by reference to Exhibit 4.12.1 to Edison Mission Energy's and Midwest Generation LLC's Registration Statement on Form S-4 to the Securities and Exchange Commission on April 20, 2001.
4.11		Participation Agreement (T1), dated as of August 17, 2000, by and among, Midwest Generation, LLC, Joliet Trust I, as the Owner Lessor, Wilmington Trust Company, as the Owner Trustee, Joliet Generation I, LLC, as the Owner Participant, Edison Mission Energy, United States Trust Company of New York, as the Lease Indenture Trustee and United States Trust Company of New York, as the Pass Through Trustees, incorporated by reference to Exhibit 4.13 to Edison Mission Energy's and Midwest Generation LLC's Registration Statement on Form S-4 to the Securities and Exchange Commission on April 20, 2001.
4.11.1		Schedule identifying substantially identical agreement to Participation Agreement constituting Exhibit 4.11 hereto, incorporated by reference to Exhibit 4.13.1 to Edison Mission Energy's and Midwest Generation LLC's Registration Statement on Form S-4 to the Securities and Exchange Commission on April 20, 2001.
4.12		Indenture, dated as of June 28, 1999, between Edison Mission Energy and The Bank of New York, as Trustee, incorporated by reference to Exhibit 4.1 to Edison Mission Energy's Registration Statement on Form S-4 to the Securities and Exchange Commission on February 18, 2000.
4.12.1		First Supplemental Indenture, dated as of June 28, 1999, to Indenture dated as of June 28, 1999, between Edison Mission Energy and The Bank of New York, as Trustee, incorporated by reference to Exhibit 4.2 to Edison Mission Energy's Registration Statement on Form S-4 to the Securities and Exchange Commission on February 18, 2000.
4.13		Registration Rights Agreement, dated as of June 23, 1999, between Edison Mission Energy and the Initial Purchasers specified therein, incorporated by reference to Exhibit 10.1 to Edison Mission Energy's Registration Statement on Form S-4 to the Securities and Exchange Commission on February 18, 2000.

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4.14		Promissory Note ($499,450,800), dated as of August 24, 2000, by Edison Mission Energy in favor of Midwest Generation, LLC, incorporated by reference to Exhibit 4.5 to Edison Mission Energy's Form 10-K for the year ended December 31, 2000.
4.14.1		Schedule identifying substantially identical agreements to Promissory Note constituting Exhibit 4.14 hereto, incorporated by reference to Exhibit 4.5.1 to Edison Mission Energy's Form 10-K for the year ended December 31, 2000.
4.15		Participation Agreement, dated as of December 7, 2001, among EME Homer City Generation L.P., Homer City OL1 LLC, as Facility Lessor and Ground Lessee, Wells Fargo Bank Northwest National Association, General Electric Capital Corporation, The Bank of New York as the Security Agent, The Bank of New York as Lease Indenture Trustee, Homer City Funding LLC and The Bank of New York as Bondholder Trustee, incorporated by reference to Exhibit 4.4 to the EME Homer City Generation L.P. Form 10-K for the year ended December 31, 2001.
4.15.1		Schedule identifying substantially identical agreements to Participation Agreement constituting Exhibit 4.15 hereto, incorporated by reference to Exhibit 4.4.1 to the EME Homer City Generation L.P. Form 10-K for the year ended December 31, 2001.
4.15.2		Appendix A (Definitions) to the Participation Agreement constituting Exhibit 4.15 hereto, incorporated by reference to Exhibit 4.4.2 to the EME Homer City Generation L.P. Form 10-K for the year ended December 31, 2004.
4.16		Open-End Mortgage, Security Agreement and Assignment of Rents, dated as of December 7, 2001, among Homer City OLI LLC, as the Owner Lessor to The Bank of New York, as Security Agent and Mortgagee, incorporated by reference to Exhibit 4.9 to the EME Homer City Generation L.P. Form 10-K for the year ended December 31, 2001.
4.16.1		Schedule identifying substantially identical agreements to Open-End Mortgage, Security Agreement and Assignment of Rents constituting Exhibit 4.16 hereto, incorporated by reference to Exhibit 4.9.1 to the EME Homer City Generation L.P. Form 10-K for the year ended December 31, 2003.
5.1†		Form of Opinion of Skadden, Arps, Slate, Meagher & Flom LLP.
10.1		Credit Agreement, dated as of June 15, 2006, between Edison Mission Energy, the Lenders referred to therein, the Issuing Lenders referred to therein and Citicorp North America, Inc., as Administrative Agent for the Lenders and the Issuing Lenders party thereto, incorporated by reference to Exhibit 10.1 to Edison Mission Energy's Form 8-K dated June 21, 2006.
10.2		Security Agreement, dated as of June 15, 2006, between Edison Mission Energy and Citicorp North America, Inc., as Administrative Agent, incorporated by reference to Exhibit 10.2 to Edison Mission Energy's Form 8-K dated June 21, 2006.
10.3		Guarantee, dated August 1, 1998, between Edison Mission Energy, Pennsylvania Electric Company, NGE Generation, Inc. and New York State Electric & Gas Corporation, incorporated by reference to Exhibit 10.54 to Edison Mission Energy's Form 10-K for the year ended December 31, 1998.

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10.4		Amended and Restated Guarantee and Collateral Agreement, dated as of December 7, 2001, made by EME Homer City Generation L.P. in favor of The Bank of New York as successor to United States Trust Company of New York, as Collateral Agent, incorporated by reference to Exhibit 10.16.4 to EME Homer City Generation L.P.'s Form 10-K for the year ended December 31, 2001.
10.5		Amended and Restated Security Deposit Agreement, dated as of December 7, 2001, among EME Homer City Generation L.P. and The Bank of New York as Collateral Agent, incorporated by reference to Exhibit 10.18.2 to the EME Homer City Generation L.P. Form 10-K for the year ended December 31, 2001.
10.6		Intercompany Loan Subordination Agreement, dated March 18, 1999, among Edison Mission Holdings Co., Edison Mission Finance Co., Homer City Property Holdings, Inc., Chestnut Ridge Energy Co., Mission Energy Westside, Inc., EME Homer City Generation L.P. and United States Trust Company of New York, incorporated by reference to Exhibit 10.60.3 to Amendment No. 2 of Edison Mission Holdings Co.'s Registration Statement on Form S-4 to the Securities and Exchange Commission on February 29, 2000.
10.7		Exchange and Registration Rights Agreement, dated as of May 27, 1999, by and among the Initial Purchasers named therein, the Guarantors named therein and Edison Mission Holdings Co., incorporated by reference to Exhibit 10.1 to Edison Mission Holdings Co.'s Registration Statement on Form S-4 to the Securities and Exchange Commission on December 3, 1999.
10.8		Reimbursement Agreement, dated as of October 26, 2001, between Edison Mission Energy and Midwest Generation, LLC, incorporated by reference to Exhibit 10.15 to Edison Mission Energy's Form 10-Q for the quarter ended March 31, 2004.
10.9		Credit Agreement, dated as of April 27, 2004, among Edison Mission Energy, the Lenders referred to therein, the Issuing Lenders referred to therein and Citicorp North America, Inc., as Administrative Agent for the Lenders and the Issuing Lenders party thereto, incorporated by reference to Exhibit 10.13 to Edison Mission Energy's Form 10-Q for the quarter ended March 31, 2004.
10.9.1		Amendment One to Credit Agreement (amending the Credit Agreement listed as Exhibit 10.9 herein) dated as of April 22, 2005, by and among Edison Mission Energy, the Lenders referred to therein, and Citicorp North America, Inc., as Administrative Agent for the Lenders, incorporated by reference to Exhibit 10.3 to Edison Mission Energy's Form 10-Q for the quarter ended March 31, 2005.
10.9.2		Amendment Two to Credit Agreement (amending the Credit Agreement listed as Exhibit 10.9 herein) dated as of December 9, 2005, between Edison Mission Energy and Citicorp North America, Inc., as Administrative Agent, incorporated by reference to Exhibit 10.7.2 to Edison Mission Energy's Form 10-K for the year ended December 31, 2005.
10.10		Security Agreement, dated as of April 27, 2004, between Edison Mission Energy and Citicorp North America, Inc., as Administrative Agent, incorporated by reference to Exhibit 10.14 to Edison Mission Energy's Form 10-Q for the quarter ended March 31, 2004.
10.11		Tax Allocation Agreement, dated July 2, 2001, by and between Mission Energy Holding Company and Edison Mission Energy, incorporated by reference to Exhibit 10.106 to Edison Mission Energy's Form 10-Q for the quarter ended September 30, 2002.

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10.12		Administrative Agreement Re Tax Allocation Payments, dated July 2, 2002, among Edison International and subsidiary parties, incorporated by reference to Exhibit 10.107 to Edison Mission Energy's Form 10-Q for the quarter ended September 30, 2002.
12.1†		Computation of Ratio of Earnings to Fixed Charges.
21†		List of Subsidiaries of Edison Mission Energy.
23.1†		Consent of Skadden, Arps, Slate, Meagher & Flom LLP (included in Exhibit 5.1)
23.2*		Consent of PricewaterhouseCoopers, LLP.
24.1*		Powers of Attorney (included on signature page).
25.1†		Statement of Eligibility and Qualification on Form T-1 of Wells Fargo Bank, National Association, as Trustee for the 7.50% Senior Notes due June 15, 2013 and for the 7.75% Senior Notes due June 15, 2016
99.1*		Form of Letter to Clients
99.2*		Form of Letter to Brokers, Dealers, Commercial Banks, Trust Companies and Other Nominees

* Filed herewith.

† Previously filed.

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