UNITED STATES
SECURITIES AND EXCHANGE COMMISSIONWashington, D.C. 20549

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FORM 10-KANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d)
OF THE SECURITIES EXCHANGE ACT OF 1934

For the fiscal year ended December 31, 2005

Commission File Number 333-68632

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

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

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

Securities
registered pursuant to Section 12(b) of the Act:

|None             |  | Not Applicable                             
|---------------- |  | -------------------------------------------
|(Title of Class) |  | (Name of each exchange on which registered)

Securities registered pursuant to Section 12(g) of the Act:

| |  | None             |  | 
| |  | ---------------- |  | 
| |  | (Title of Class) |  | 

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Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act.
YES o NO ý

Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Act.
YES o NO ý

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

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

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer or a non-accelerated filer. See definition of
"accelerated filer" and "large accelerated filer" in Rule 12b-2 of the Exchange Act. (Check one):        Large accelerated
filer o    Accelerated filer o    Non-accelerated
filer ý

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act).
YES o NO ý

Aggregate market value of the registrant's Common Stock held by non-affiliates of the registrant as of June 30, 2005: $0. Number of shares
outstanding of the registrant's Common Stock as of February 28, 2006: 1,000 shares (all shares held by an affiliate of the registrant).



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DOCUMENTS INCORPORATED BY REFERENCE

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

|(1) | Designated portions of Edison Mission Energy's Amendment to Form 10-K for the year ended December 31, 2005 Part III        |  | 
|--- | -------------------------------------------------------------------------------------------------------------------------- |  | 
|(2) | Designated portions of the Proxy Statement relating to Edison International's 2006 Annual Meeting of Shareholders Part III |  | 

Each of Mission Energy Holding Company (MEHC) and Edison Mission Energy is an indirect wholly owned subsidiary of Edison International. Although
Edison International is a large accelerated filer as defined under Exchange Act Rule 12b-2, MEHC and Edison Mission Energy are
non-accelerated filers. MEHC and Edison Mission Energy are filing their respective annual reports on Form 10-K concurrently with Edison International's filing of its
annual report on Form 10-K. MEHC and Edison Mission Energy have been advised by Edison International that, prior to March 31, 2006, Edison International will file with the
Securities and Exchange Commission a definitive proxy statement containing information relating to executive compensation. Edison Mission Energy will file an amendment to its
Form 10-K relating to the compensation of Edison Mission Energy's executive officers concurrently with Edison International's filing of its definitive proxy statement. The amendment
will include some of the executive compensation information included in Edison International's definitive proxy statement as such information pertains to Edison Mission Energy's executive officers.

Because
MEHC officers receive compensation from Edison Mission Energy or Edison International and receive no compensation from MEHC, the above-mentioned portions of Edison Mission
Energy's amendment to its Form 10-K for the year ended December 31, 2005 and Proxy Statement relating to Edison International 2006 Annual Meeting of Shareholders, when filed,
will become incorporated by reference into parts of this annual report.

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TABLE OF CONTENTS

|         |  |                                                                                       |  | Page
|-------- |  | ------------------------------------------------------------------------------------- |  | ----
|         |  | PART I                                                                                |  |     
|Item 1.  |  | Business                                                                              |  | 1   
|Item 1A. |  | Risk Factors                                                                          |  | 21  
|Item 1B. |  | Unresolved Staff Comments                                                             |  | 26  
|Item 2.  |  | Properties                                                                            |  | 26  
|Item 3.  |  | Legal Proceedings                                                                     |  | 27  
|Item 4.  |  | Submission of Matters to a Vote of Security Holders                                   |  | 27  
|         |  | Executive Officers of the Registrant                                                  |  | 28  
|         |  | PART II                                                                               |  |     
|Item 5.  |  | Market for Registrant's Common Equity and Related Stockholder Matters                 |  | 29  
|Item 6.  |  | Selected Financial Data                                                               |  | 30  
|Item 7.  |  | Management's Discussion and Analysis of Financial Condition and Results of Operations |  | 32  
|Item 7a. |  | Quantitative and Qualitative Disclosures about Market Risk                            |  | 90  
|Item 8.  |  | Financial Statements and Supplementary Data                                           |  | 91  
|Item 9.  |  | Changes in and Disagreements with Accountants on Accounting and Financial Disclosure  |  | 91  
|Item 9A. |  | Controls and Procedures                                                               |  | 91  
|Item 9B. |  | Other Information                                                                     |  | 91  
|         |  | PART III                                                                              |  |     
|Item 10. |  | Directors and Executive Officers of the Registrant                                    |  | 145 
|Item 11. |  | Executive Compensation                                                                |  | 146 
|Item 12. |  | Security Ownership of Certain Beneficial Owners and Management                        |  | 146 
|Item 13. |  | Certain Relationships and Related Transactions                                        |  | 147 
|Item 14. |  | Principal Accounting Fees and Services                                                |  | 147 
|         |  | PART IV                                                                               |  |     
|Item 15. |  | Exhibits and Financial Statement Schedules                                            |  | 148 
|         |  | Signatures                                                                            |  | 154 

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PART I

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

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

ITEM 1.    BUSINESS

The Company

MEHC was formed as a wholly owned subsidiary of Edison Mission Group Inc., which is a wholly owned subsidiary of Edison International. MEHC was formed to
hold the common stock of EME. On July 2, 2001, Edison Mission Group contributed to MEHC all the outstanding common stock of EME. The contribution of EME's common stock to MEHC has been
accounted for as a transfer of ownership of companies under common control. MEHC's only substantive liabilities are its obligations under the senior secured notes and corporate overhead, including
fees of its legal counsel, auditors and other advisors. MEHC does not have any substantive operations other than through EME and its subsidiaries and other investments.

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

MEHC's
Annual Reports on Form 10-K, Quarterly Reports on Form 10-Q, Current Reports on Form 8-K, and amendments to those reports,
are electronically filed or furnished pursuant to Section 13(a) or 15(d) of the Securities Exchange Act of 1934 and are available on the Securities and Exchange Commission's internet web site
at http://www.sec.gov.

EME Restructuring Activities

During 2004 and early 2005, EME sold assets totaling 6,452 megawatts (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:

1

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See
"Item 7. 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, have combined their management teams located in Irvine, California and combined their wind development efforts. In this regard, EME and Edison Capital have 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.

Forward-Looking Statements

This annual report on Form 10-K contains "forward-looking statements" within the meaning of the Private Securities Litigation Reform Act of
1995. These statements reflect MEHC's current expectations and projections about future events based on MEHC's knowledge of present facts and circumstances and assumptions about future events and
include any statement that does not directly relate to a historical or current fact. Other information distributed by MEHC that is incorporated in this annual report, or that refers to or incorporates
this annual report, may also contain forward-looking statements. In this annual report and elsewhere, the words "expects," "believes," "anticipates," "estimates," "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 statements necessarily involve risks and uncertainties that could cause actual results to differ materially from those anticipated. Some of the risks, uncertainties and other important factors
that could cause results to differ, or that otherwise could impact MEHC or its subsidiaries, include but are not limited to:

2

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Certain
of the risk factors listed above are discussed in more detail in "Item 1A. Risk Factors" below and in "Item 7. Management's Discussion and Analysis of Financial
Condition and Results of OperationsMarket Risk Exposures." Additional information about the risk factors listed above and other risks and uncertainties is contained throughout this annual
report. Readers are urged to read this entire annual report, including the information incorporated by reference, and carefully consider the risks, uncertainties and other factors that affect MEHC's
business. Forward-looking statements speak only as of the date they are made, and MEHC is not obligated to publicly update or revise forward-looking statements. Readers should review future reports
filed by MEHC with the Securities and Exchange Commission.

Description of the Industry

Electric Power Industry

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 annual report, 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 annual report, 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.

3

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As
part of the regulatory developments discussed above, the Federal Energy Regulatory Commission, referred to as the FERC in this annual report, encouraged the formation of independent
system operators (ISOs) and regional transmission organizations (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 annual report,
and the Homer City electric generating station located in Pennsylvania, which is referred to as the Homer City facilities in this annual report. 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 (Midwest
Generation), with respect to the Illinois Plants, and EME Homer City Generation L.P. (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 (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 "Item 7. Management's Discussion and Analysis of Financial Condition and
Results of OperationsMarket Risk Exposures."

4

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Competition

EME is subject to intense competition from energy marketers, utilities, 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 operates in one line of business, independent power production, with all 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 the Illinois Plants and the Homer City facilities. EME is headquartered in Irvine, California with additional
offices located in Chicago, Illinois and Boston, Massachusetts.

5

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Overview of Facilities

As of December 31, 2005, EME's operations consisted of ownership or leasehold interests in the following operating power plants:

|Power Plants            |                               | Location          |               | Primary
Electric
Purchaser(3) |       | 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      |                               | PJM   |           | Coal/Oil/Gas |                    | 100% |                               | 5,876 |                                      
|                        | Homer City(1)                 |                   | Pennsylvania  |                               | PJM   |           | Coal         |                    | 100% |                               | 1,884 |                                      
|Contracted Power Plants |                               |                   |               |                               |       |           |              |                    |      |                               |       |                                      
|Domestic                |                               |                   |               |                               |       |           |              |                    |      |                               |       |                                      
|                        | Big 4 Projects                |                   |               |                               |       |           |              |                    |      |                               |       |                                      
|                        |                               | Kern River(1)     |               | California                    |       | SCE       |              | Natural Gas        |      | 50%                           |       | 300                                  
|                        |                               | Midway-Sunset(1)  |               | California                    |       | SCE       |              | Natural Gas        |      | 50%                           |       | 225                                  
|                        |                               | Sycamore(1)       |               | California                    |       | SCE       |              | Natural Gas        |      | 50%                           |       | 300                                  
|                        |                               | Watson            |               | California                    |       | SCE       |              | Natural Gas        |      | 49%                           |       | 385                                  
|                        | Westside Projects             |                   |               |                               |       |           |              |                    |      |                               |       |                                      
|                        |                               | Coalinga(1)       |               | California                    |       | PG&E      |              | Natural Gas        |      | 50%                           |       | 38                                   
|                        |                               | Mid-Set(1)        |               | California                    |       | PG&E      |              | Natural Gas        |      | 50%                           |       | 38                                   
|                        |                               | Salinas River(1)  |               | California                    |       | PG&E      |              | Natural Gas        |      | 50%                           |       | 38                                   
|                        |                               | Sargent Canyon(1) |               | California                    |       | PG&E      |              | Natural Gas        |      | 50%                           |       | 38                                   
|                        | American Bituminous(1)        |                   | West Virginia |                               | MPC   |           | Waste Coal   |                    | 50%  |                               | 80    |                                      
|                        | March Point                   |                   | Washington    |                               | PSE   |           | Natural Gas  |                    | 50%  |                               | 140   |                                      
|                        | Sunrise(1)                    |                   | California    |                               | CDWR  |           | Natural Gas  |                    | 50%  |                               | 572   |                                      
|                        | San Juan Mesa(1)              |                   | New Mexico    |                               | SPS   |           | Wind         |                    | 100% | (2)                           | 120   |                                      
|International           |                               |                   |               |                               |       |           |              |                    |      |                               |       |                                      
|                        | Doga(1)                       |                   | Turkey        |                               | TEDAS |           | Natural Gas  |                    | 80%  |                               | 180   |                                      
|                        |                               |                   |               |                               |       |           |              |                    |      |                               |       |                                      
|                        |                               | Total             |               |                               |       |           |              |                    |      |                               |       | 10,214                               
|                        |                               |                   |               |                               |       |           |              |                    |      |                               |       |                                      

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PJM

PJM Interconnection, LLCSCE

Southern California Edison CompanyPG&E

Pacific Gas & Electric CompanyMPC

Monongahela Power CompanyPSE

Puget Sound Energy, Inc.CDWR

California Department of Water ResourcesSPS

Southwestern Public ServiceTEDAS

Türkiye Elektrik Dagitim Anonim Sirketi


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.

6

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Illinois Plants

On December 15, 1999, Midwest Generation completed a transaction with Commonwealth Edison Company (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

MegawattsElectric Generating FacilitiesCrawford Station

Chicago, Illinois

owned

coal

542Fisk Station

Chicago, Illinois

owned

coal

326Joliet Unit 6

Joliet, Illinois

owned

coal

290Joliet Units 7 and 8

Joliet, Illinois

leased

coal

1,044Powerton Station

Pekin, Illinois

leased

coal

1,538Waukegan Station

Waukegan, Illinois

owned

coal

789Will County Station

Romeoville, Illinois

owned

coal

1,092
(1)Peaking UnitsFisk

Chicago, Illinois

owned

oil/gas

163Waukegan

Waukegan, Illinois

owned

oil/gas

92Total







5,876Other Plant or SiteCollins Station(2)

Grundy County, IllinoisCrawford peaker(3)

Chicago, IllinoisJoliet peaker(4)

Joliet, IllinoisCalumet peaker(4)

Chicago, IllinoisElectric Junction peaker(4)

Aurora, IllinoisLombard peaker(4)

Lombard, IllinoisSabrooke peaker(4)

Rockford, Illinois


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As part of the purchase of the Illinois Plants, EME assigned its right to purchase the Collins Station to third-party entities and Midwest
Generation simultaneously entered into a long-term lease 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.

7

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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 control of the use of the power plants during the
terms of the leases. See "Off-Balance Sheet Transactions" section in "Item 7. 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
(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. (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 "Item 7. 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" (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.

8

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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 demanding evidentiary hearings by the FERC.
Pending further orders of 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 "Item 7. Management's Discussion and Analysis of Financial Condition and
Results of OperationsMarket Risk Exposures."

Fuel Supply

Coal is used to fuel 5,621 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 255 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
"Item 7. 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 annual report), 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.

9

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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 "Item 7. Management's
Discussion and Analysis of Financial Condition and Results of OperationsLiquidity and Capital ResourcesOff-Balance Sheet Transactions."

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
"Item 7. 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
"Item 7. 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 "Item 7. 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 MEHC. 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

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these projects collectively and refers to them as the Big 4 projects. See "Item 8. Financial Statements and Supplementary DataMission Energy Holding Company and Subsidiaries Notes
to Consolidated Financial StatementsNote 2. Summary of Significant Accounting Policies," for discussion of EME's accounting for this entity.

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. (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 (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, subject to approval by the California Public Utilities Commission (CPUC). If approved by the
CPUC, this contract will replace the RSO#1 with Southern California Edison, which is currently in effect.

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 both electricity to Southern California
Edison, Aera Energy LLC (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 both 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 both 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.

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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.

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 both 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 "Item 7. 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 power purchase and steam sales agreements expired in May 2004.
Mid-Set Cogeneration continues to sell electricity to Pacific Gas & Electric under the "as available" rates. In March 2005, the parties agreed to a five-year
extension for the sale of electricity under the "as available rates." The original steam agreement remains effective on a month-to-month basis pending the execution of a
long-term steam agreement that is expected to be entered into during the first quarter of 2006.

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 2027.

San Juan Mesa Wind Power Plant

EME owns a 100% interest in Mission Wind New Mexico, which owns a 120 MW wind ranch located near Elida, New Mexico, which EME refers to as the San Juan Mesa wind
project. The San Juan Mesa wind project uses wind to generate electricity from turbines, which is sold to Southwestern Public

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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.

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 the Energy Policy Act of
2005, referred to as EPAct 2005. EME has undertaken a number of key activities with respect to wind projects, including the following:

Thermal Business Development

EME also expects to make investments in thermal projects during the next several years. As part of this development effort, EME has begun the process of obtaining
permits for two sites in Southern California for peaker plants and has responded to several requests for proposals to build or acquire generation. It is expected that the thermal projects in which EME
invests will sell electricity under long-term power purchase contracts. EME is also working in partnership with a subsidiary of BP to assess the feasibility of constructing and operating
an integrated gasification combined cycle facility which would burn hydrogen gas derived from petroleum coke at BP's refinery in Carson, California.

Discontinued Operations

For a description of discontinued operations, see "Item 8. Financial Statements and Supplementary DataMission Energy Holding Company and
Subsidiaries Notes to Consolidated Financial StatementsNote 8. Divestitures."

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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:

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

To
manage credit risk, EME looks at the risk of a potential default by its counterparties. Credit risk is measured by the loss EME would record if its counterparties failed to perform
pursuant to the terms of their contractual obligations. EME has established controls to determine and monitor the creditworthiness of counterparties and uses master netting agreements whenever
possible to mitigate its exposure to counterparty risk. EME 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

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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 "Item 1A. 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 70%, 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 36% 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.

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

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participation
agreements which permits it to maintain its current insurance coverage through June 1, 2006.

Seasonality

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.

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.

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 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.

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

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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 (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 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.

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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 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.

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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.

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

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transmitting
utilities; and (3) section 1233 of EPAct 2005, which defines the native load service obligation.

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 "Item 7. Management's Discussion and Analysis of Financial Condition and Results of
OperationsLiquidity and Capital ResourcesEnvironmental Matters and Regulations."

Employees

MEHC has no full-time employees. At December 31, 2005, EME and its subsidiaries employed 1,745 people, including:

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

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

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ITEM 1A.    RISK FACTORS

MEHC depends upon cash flows from EME to service its debt.

MEHC's principal asset is the common stock of EME. In July 2001, MEHC issued $800 million of 13.50% senior secured notes due 2008. 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 would result in a
change in control of EME which could have a material adverse effect on MEHC. Dividends from EME are limited based on its earnings and cash flow, the terms of restrictions contained in EME's corporate
credit facility, business and tax considerations and restrictions imposed by applicable law. For a discussion of contractual restrictions that could constrain the ability of EME's subsidiaries to pay
dividends or distributions to EME, see "Item 7. Management's Discussion and Analysis of Financial Condition and Results of OperationsLiquidity and Capital
ResourcesDividend Restrictions in Major Financings."

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

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

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 EME's 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 EME's

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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
EME. See "Item 7. Management's Discussion and Analysis of Financial Condition and Results of OperationsMarket Risk ExposuresCommodity Price Risk."

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

EME's business is subject to changes in fuel costs, which may negatively affect its 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 EME's expectations.

Although
EME attempts to purchase fuel based on its known fuel requirements, it is 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 EME can sell its energy may not rise or fall at the same rate as a corresponding rise or fall in fuel costs. See "Item 7. Management's Discussion and Analysis of Financial Condition and
Results of OperationsMarket Risk ExposuresCommodity Price Risk."

EME may not be able to hedge market risks effectively.

EME is exposed to market risks through its ownership and operation of merchant energy power plants and through its 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. EME uses 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
EME's exposure, expose EME to other risks.

The
effectiveness of EME's 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, EME could be exposed to the following:

As
a result of these and other factors, EME cannot predict with precision the effect that risk management decisions may have on its businesses, operating results or financial position.
See "Item 7. Management's Discussion and Analysis of Financial Condition and Results of OperationsLiquidity and Capital ResourcesMargin, Collateral Deposits and Other
Credit Support for Energy Contracts."

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EME is exposed to credit and performance risk from third parties under supply and transportation contracts.

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

EME is subject to extensive energy industry regulation.

EME's operations are subject to extensive regulation by governmental agencies. EME's 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. For more information, see "Item 1.
BusinessRegulatory Matters."

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

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

EME's operations are subject to extensive environmental regulation. EME is required to obtain and comply with conditions established by licenses, permits and
other approvals in order to construct, operate or modify its facilities. Failure to comply with these requirements could subject EME to civil or criminal liability, the imposition of liens or fines,
or actions by regulatory agencies seeking to curtail EME's operations. EME may also be exposed to risks arising from past, current or future contamination at its former or existing facilities or with
respect to off-site waste disposal sites that have been used in its operations.

EME
devotes significant resources to environmental monitoring, pollution control equipment and emission allowances to comply with environmental regulatory requirements. 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, 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 EME conducts its business and could cause it to make substantial
additional capital expenditures. There is no assurance that EME would be able to recover these increased costs from its customers or that its business, financial position and results of operations
would not be materially adversely affected.

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Environmental
advocacy groups and regulatory agencies in the United States have been focusing considerable attention on carbon dioxide emissions from coal-fired power plants
and their potential role in climate change. The adoption of laws and regulations to implement carbon dioxide controls could adversely affect EME's coal-fired plants. 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 EME operates are
contemplating air pollution control regulations that are more stringent than existing and proposed federal regulations. Changing environmental regulations could require EME to purchase additional
emission allowances or install additional pollution control technology, and could make some units uneconomical to maintain or operate. If EME cannot comply with all applicable regulations, it could be
required to retire or suspend operations at its facilities, or restrict or modify the operations of its facilities, and its business, results of operations and financial condition could be adversely
affected. See "Item 7. Management's Discussion and Analysis of Financial Condition and Results of OperationsLiquidity and Capital ResourcesEnvironmental Matters and
Regulations."

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

The ability of EME's largest subsidiary, Midwest Generation, LLC, to make distributions is restricted.

Midwest Generation, which owns or leases the Illinois Plants, has entered into financing documents that contain restrictions on its ability to pay dividends. See
"Item 7. Management's Discussion and Analysis of Financial Condition and Results of OperationsLiquidity and Capital Resources."

EME
is the guarantor of the Powerton and Joliet leases and is obligated under intercompany notes to make debt service payments to Midwest Generation. Each intercompany note is a general
corporate obligation of EME and payments on it are made from distributions from subsidiaries and other sources of cash received by EME. Accordingly, EME must continue to make payments under the
intercompany notes regardless of whether or not Midwest Generation makes distributions to EME. If EME were not able to satisfy its 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 the results of operations and cash flow of EME.

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

As of December 31, 2005, consolidated debt of EME was $3.4 billion. In addition, EME's subsidiaries have $4.6 billion of
long-term power plant lease obligations that are due over a period ranging up to 29 years. The substantial amount of consolidated debt and financial obligations presents the risk
that EME and its subsidiaries might not have sufficient cash to service their indebtedness or long-term lease obligations and that the existing corporate debt, project debt and lease
obligations could limit the ability of EME and its subsidiaries to grow their business, to compete effectively or operate successfully under adverse economic conditions. If EME's or a subsidiary's
cash flows and capital resources were insufficient to allow it to make scheduled payments on its debt, EME or its subsidiaries might have to reduce or delay capital expenditures, sell assets, seek
additional capital, or restructure or refinance the debt. The terms of EME's or its subsidiaries' debt may not allow these alternative

24

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measures,
the debt or equity may not be available on acceptable terms, and these alternative measures may not satisfy all scheduled debt service obligations.

Competition could adversely affect EME's 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 EME does. 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 EME operates.

Newer
plants owned by EME's competitors are often more efficient than EME's facilities. This may put some of EME's facilities at a competitive disadvantage to the extent that its
competitors are able to produce more power from each increment of fuel than EME's 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 EME's
ability to compete effectively in the markets in which those entities operate.

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

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

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

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

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

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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 EME's projects or significantly increase the costs
of operating them, and could also result in EME's 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 EME's obligations as they become due and could
have a material adverse effect on EME. A default under a financing obligation of a project entity could result in a loss of EME's interest in the project.

EME's future acquisitions and development projects may not be successful.

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

In
addition to the competition already existing in the markets in which EME presently operates or may consider operating in the future, EME is 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 EPAct 2005. EME may be unable to identify
attractive acquisition or development opportunities and/or to complete and integrate them on a successful and timely basis.

ITEM 1B.    UNRESOLVED STAFF COMMENTS

Inapplicable.

ITEM 2.    PROPERTIES

MEHC's principal office is in Irvine, California.

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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
MEHC's income before tax or is one in which EME has an investment balance greater than $50 million. Most of these properties are subject to mortgages or other liens or encumbrances granted to
the lenders providing financing for the plant or project.

Description of Properties

|Plant           |  | 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-fired cogeneration facility  
|Midway-Sunset   |  | Fellows, California      |  | Leased           |  | Natural gas-fired cogeneration facility  
|Sunrise         |  | Fellows, California      |  | Leased           |  | Combined cycle generation facility       
|Sycamore        |  | Oildale, California      |  | Leased           |  | Natural gas-fired cogeneration facility  
|Watson          |  | Carson, California       |  | Leased           |  | Natural gas-fired cogeneration facility  

ITEM 3.    LEGAL PROCEEDINGS

No material legal proceedings are presently pending against MEHC.

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

Inapplicable.

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Pursuant to Form 10-K's General Instruction G(3), the following information is included as an additional item in Part I of this annual
report:

EXECUTIVE OFFICERS OF THE REGISTRANT

Listed below are MEHC's current executive officers and their ages and positions as of December 31, 2005.

Name, Position and Age

Position Held
Continuously
Since

Term
ExpiresThomas R. McDaniel, 56
Chief Executive Officer and President

2005

2006Barbara E. Mathews, 53
Secretary and Assistant General Counsel

2001

2006W. James Scilacci, 50
Senior Vice President and Chief Financial Officer

2005

2006Raymond W. Vickers, 63
Senior Vice President and General Counsel

2001

2006


Business Experience

Below is a description of the principal business experience during the past five years of each of the executive officers named above.

Mr. McDanielhas been chief executive officer and president of Mission Energy Holding Company since January 2005.
Mr. McDaniel has been executive vice president, chief financial officer and treasurer of Edison International since January 2005. From August 2002 until January 2005,
Mr. McDaniel was president and chief executive officer of Edison Mission Energy. From 1987 until January 2005, Mr. McDaniel served as chief executive officer of Edison Capital.

Ms. Mathewshas been secretary and assistant general counsel of Mission Energy Holding Company since June 2001.
Ms. Mathews has been vice president, associate general counsel, chief governance officer and corporate secretary of Edison International and Southern California Edison Company since
September 2005. From May 2005 until September 2005, Ms. Mathews was vice president and associate general counsel for Edison International and Southern California Edison
Company. From April 2002 until May 2005, Ms. Mathews served as associate general counsel for Edison International and Southern California Edison Company. Ms. Mathews was an
assistant general counsel of Edison International and Southern California Edison Company from August 1996 through April 2002.

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

Mr. Vickershas been senior vice president and general counsel of Mission Energy Holding Company since June 2001.
Mr. Vickers has been senior vice president and general counsel of Edison Mission Energy since March 1999.

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PART II

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

All the outstanding common stock of MEHC is, as of the date hereof, owned by MEHC's direct parent, Edison Mission Group Inc., a wholly owned subsidiary of
Edison International. There is no market for the common stock. Dividends on the common stock will be paid when declared by MEHC's board of directors. MEHC did not pay any dividends in 2005 and 2004.
Dividends may be limited based on its earnings and cash flow, terms of restrictions contained in MEHC's senior secured notes, business and tax considerations, and restrictions imposed by applicable
law.

MEHC's
subsidiary, EME, made cash dividend payments totaling $360 million in 2005, which included the $305 million declared in 2004, and $74 million in 2004. A total
of $11.5 million in dividends was paid in January 2006. Dividends from EME may be limited based on its earning and cash flow, terms of restrictions contained in EME's corporate credit facility,
business and tax considerations, and restrictions imposed by applicable law. See "Item 7. Management's Discussion and Analysis of Financial Condition and Results of
OperationsLiquidity and Capital ResourcesMEHC's Liquidity" for more information about dividend restrictions in EME's corporate credit facility.

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ITEM 6.    SELECTED FINANCIAL DATA

The selected financial data was derived from MEHC's audited financial statements and is qualified in its entirety by the more detailed information and financial
statements, including notes to these financial statements, included in this annual report. EME's international operations are accounted for as discontinued operations, except the Doga project in
Turkey, which is accounted for as an equity investment. Continuing operations include EME's Illinois Plants and Homer City facilities, energy trading, equity investments in power projects primarily
located in California, the Doga project, corporate interest expense and general and administrative expenses. See "Item 7. Management's Discussion and Analysis of Financial Condition and Results
of OperationsResults of OperationsResults of Continuing Operations" and "Results of Discontinued Operations" for more information about the sale of EME's
international operations and loss on lease termination, asset impairment and other charges in 2005, 2004 and 2003, and "Item 7. Management's Discussion and Analysis of Financial Condition and
Results of OperationsResults of OperationsResults of Continuing OperationsCumulative Effect of Change in Accounting Principle" for further explanation of
accounting changes.

|                                                                                                                                                                         |                                                                           | Years Ended December 31, |      
|------------------------------------------------------------------------------------------------------------------------------------------------------------------------ | ------------------------------------------------------------------------- | ------------------------ | -----
|
|
|INCOME STATEMENT DATA                                                                                                                                                    |                                                                           |                          |      
|Operating revenues                                                                                                                                                       |                                                                           | $                        | 2,248
|Operating expenses                                                                                                                                                       |                                                                           |                          |      
|                                                                                                                                                                         | Fuel, plant operations and plant operating lease                          |                          |      
|                                                                                                                                                                         | Loss on lease termination, asset impairment and other charges and credits |                          |      
|                                                                                                                                                                         | Depreciation and amortization                                             |                          |      
|                                                                                                                                                                         | Administrative and general                                                |                          |      
|                                                                                                                                                                         |                                                                           |                          |      
|                                                                                                                                                                         |                                                                           |                          | 1,564
|                                                                                                                                                                         |                                                                           |                          |      
|Operating income (loss)                                                                                                                                                  |                                                                           |                          | 684  
|Equity in income from unconsolidated affiliates                                                                                                                          |                                                                           |                          | 227  
|Impairment loss on equity method investment                                                                                                                              |                                                                           |                          | (55  
|Interest and other income                                                                                                                                                |                                                                           |                          | 45   
|Interest expense                                                                                                                                                         |                                                                           |                          | (410 
|                                                                                                                                                                         |                                                                           |                          |      
|Income (loss) from continuing operations before income taxes and minority interest                                                                                       |                                                                           |                          | 491  
|Provision (benefit) for income taxes                                                                                                                                     |                                                                           |                          | 169  
|Minority interest                                                                                                                                                        |                                                                           |                          |     
|                                                                                                                                                                         |                                                                           |                          |      
|Income (loss) from continuing operations                                                                                                                                 |                                                                           |                          | 322  
|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 |                                                                           |                          | 29   
|                                                                                                                                                                         |                                                                           |                          |      
|Income (loss) before accounting change                                                                                                                                   |                                                                           |                          | 351  
|Cumulative effect of change in accounting, net of tax                                                                                                                    |                                                                           |                          | (1   
|                                                                                                                                                                         |                                                                           |                          |      
|Net income (loss)                                                                                                                                                        |                                                                           | $                        | 350  
|                                                                                                                                                                         |                                                                           |                          |      

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

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

This Management's Discussion and Analysis of Financial Condition and Results of Operations (MD&A) contains "forward-looking statements"
within the meaning of the Private Securities Litigation Reform Act of 1995. These statements reflect MEHC's current expectations and projections about future events based on MEHC's knowledge of
present facts and circumstances and assumptions about future events and include any statement that does not directly relate to a historical or current fact. Other information distributed by MEHC that
is incorporated in this MD&A, or that refers to or incorporates this MD&A, may also contain forward-looking statements. In this MD&A 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 statements necessarily involve risks and uncertainties that could cause actual results to differ materially from those anticipated. See
"Item 1. BusinessForward-Looking Statements" and "Item 1A. Risk Factors" for a discussion of some of the risks, uncertainties and other important factors that could cause
results to differ, or otherwise could impact MEHC or its subsidiaries. Additional information about risks and uncertainties is contained throughout this MD&A. Readers are urged to read this entire
annual report, including the information incorporated by reference, and carefully consider the risks, uncertainties and other factors that affect MEHC's business. Forward-looking statements speak only
as of the date they are made and MEHC is not obligated to publicly update or revise forward-looking statements. Readers should review future reports filed by MEHC with the Securities and Exchange
Commission.

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

This
MD&A is presented in five sections:

|                                                     |  | Page
|---------------------------------------------------- |  | ----
|Management's Overview; Critical Accounting Estimates |  | 32  
|Results of Operations                                |  | 39  
|Liquidity and Capital Resources                      |  | 53  
|Market Risk Exposures                                |  | 78  
|Recent Development                                   |  | 90  

MANAGEMENT'S OVERVIEW; CRITICAL ACCOUNTING ESTIMATES

Management's Overview

Introduction

MEHC has a 100% ownership interest in EME, which itself operates through its subsidiaries and affiliates as described further below. MEHC has no business
activities other than through its ownership interest in EME and has outstanding approximately $800 million of 13.50% senior secured notes due in 2008. MEHC's ability to honor its obligations
under the senior secured notes is entirely dependent upon

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the
receipt of dividends from EME and receipt of tax-allocation payments from MEHC's parent, Edison Mission Group Inc., and ultimately Edison International. Dividends to MEHC from
EME are limited based on EME's earnings and cash flow, terms of restrictions contained in EME's corporate credit facility, business and tax considerations, and restrictions imposed by applicable law.

EME
has not guaranteed the senior secured notes, which are non-recourse to EME. The MEHC financing documents contain restrictions on EME's ability and the ability of EME's
subsidiaries to enter into specified transactions or engage in specified business activities and require, in some instances, that EME obtains the approval of MEHC's board of directors. EME's
certificate of incorporation binds it to the restrictions in MEHC's financing documents by restricting EME's ability to enter into specified transactions or engage in specified business activities,
other than as permitted in MEHC's financing documents, without shareholder approval.

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 December 31, 2005, EME's subsidiaries and affiliates owned or leased
interests in 19 domestic 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.

EME Restructuring Activities

During 2004 and early 2005, EME sold 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.

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, have combined their management teams located in Irvine, California and combined their wind development efforts. In this regard, EME and Edison Capital have 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,

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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.

Merchant Operations

The majority of EME's power plants 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 during 2005 from its merchant operations 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 its 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 $195 million during 2005. Volatile market conditions during 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. This trading activity is limited by the risk management policies of EME, including
a limit on value at risk. During 2005, EME's maximum value at risk associated with trading of over-the-counter products and exchange-traded products was $1.9 million,
using a 95% confidence interval and assuming a one-day holding period. As of December 31, 2005, margin and collateral posted to support trading activities of EMMT was approximately
$75 million. This amount includes collateral posted with 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 Plans

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:

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Thermal Business Development

EME also expects to make investments in thermal projects during the next several years. As part of this development effort, EME has begun the process of obtaining
permits for two sites in Southern California for peaker plants and has responded to several requests for proposals to build or acquire generation. It is expected that the thermal projects in which EME
invests will sell electricity under long-term power purchase contracts. EME is also working in partnership with a subsidiary of BP to assess the feasibility of constructing and operating
an integrated gasification combined cycle facility which would burn hydrogen gas derived from petroleum coke at BP's refinery in Carson, California.

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" (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.

35

---



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" (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

36

---



Obligations,
Commitments and ContingenciesOperating Lease Obligations." Each of these transactions was completed and accounted for by EME as an operating lease in its consolidated
financial statements in accordance with Statement of Financial Accounting Standards No. 98 "Sale-Leaseback Transactions Involving Real Estate" (SFAS No. 98), which requires,
among other things, that all 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. EME also
provided an indemnity to IPM (a consortium comprised of International Power plc (70%) and Mitsui & Co., Ltd. (30%)) for matters arising out of the exercise by one of EME's 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. At December 31, 2005, EME recorded an estimated liability related to these matters of $122 million.

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 December 31, 2005, Midwest Generation recorded a liability related to this contract indemnity of $67 million.

37

---



Income Taxes

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

As
part of the process of preparing its consolidated financial statements, EME is required to estimate its income taxes in each 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 "Mission Energy Holding Company and Subsidiaries Notes to Consolidated Financial StatementsNote 2.
Summary of Significant Accounting Policies."

38

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RESULTS OF OPERATIONS

Introduction

This section discusses operating results in 2005, 2004 and 2003. Continuing operations include EME's Illinois Plants and Homer City facilities, energy trading,
equity investments in power projects primarily located in California, corporate interest expense and general and administrative expenses. Discontinued operations include all of EME's international
operations, except the Doga project. This section also discusses the effect of new accounting pronouncements on EME's consolidated financial statements. It is organized under the following headings:

PageNet Income Summary

39Results of Continuing Operations

40Results of Discontinued Operations

50Related Party Transactions

51New Accounting Pronouncements

51Proposed Accounting Pronouncements

52


Net Income Summary

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

Years Ended December 31,2005

2004

2003(in millions)MEHC (parent company):Loss from continuing operations

$
(82
)
$
(98
)
$
(99
)EME and its Consolidated Subsidiaries:Income (loss) from continuing operations

$
404

$
(568
)
$
(95
)Income from discontinued operations


29


690


124Cumulative changes in accounting principle


(1
)




(9
)Net Income (Loss)

$
350

$
24

$
(79
)


MEHC's 2005 decrease in loss from continuing operations was attributable to lower interest expense primarily related to the repayment of the
$385 million term loan ($100 million of the term loan was repaid in July 2004 and the remaining $285 million of the term loan was repaid in January 2005). This
decrease was partially offset by a $12 million, after tax, loss on early extinguishment of debt recorded in 2005.

EME's
2005 loss from a change in accounting principle resulted from the adoption of a new accounting standard for conditional asset retirement obligations. EME's 2003 loss from a change
in accounting principle resulted from the adoption of a new accounting standard for asset retirement obligations. See "Results of Continuing OperationsCumulative Effect of Change in
Accounting Principle" for further discussion of these changes in accounting.

39

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EME's
income (loss) from continuing operations during the three year period ended December 31, 2005 included the following items:

Years Ended December 31,2005

2004

2003(in millions)Loss on lease termination, asset impairment and other charges (see "Results of Continuing OperationsEarnings from Consolidated OperationsIllinois Plants," and "Results of Continuing
OperationsEarnings from Unconsolidated AffiliatesAsset Impairment Charges")

$


$
(608
)
$
(186
)Impairment loss on equity method investment (see "Results of Continuing OperationsEarning from Unconsolidated AffiliatesImpairment Loss on Equity Method Investment")

$
(34
)
$


$
Gain on sale of assets (see "Results of Continuing OperationsEarnings from Unconsolidated AffiliatesFour Star Oil & Gas")

$


$
29

$



The 2005 increase in income from continuing operations after considering the above items, was primarily attributable to higher energy trading
income and higher wholesale energy prices at the Illinois Plants. The 2004 decrease in income from continuing operations after considering the above items, was primarily due to the absence of 2004
earnings from Four Star Oil & Gas (sold on January 7, 2004) compared to 2003, lower earnings from the Homer City facilities due to lower generation and higher fuel costs related to
emission allowances, and lower earnings from the Illinois Plants primarily due to a $56 million charge related to a contract indemnity agreement related to asbestos claims with respect to
activities at the Illinois Plants prior to their acquisition in 1999. Further details regarding income from continuing operations is set forth below.

Results of Continuing Operations

Overview

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.

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

40

---



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 312005

2004

2003(in millions)Income (Loss) before Taxes and Minority Interest(Earnings/Losses)(1)Consolidated operationsIllinois Plants

$
547

$
(881
)
$
(112
)Homer City


74


77


137Energy Trading(2)


195


23


34Doga





6


13Other


(3
)

2


3Unconsolidated affiliatesBig 4 projects


158


142


135Four Star Oil & Gas








43Sunrise


29


28


35March Point


9


17


10Impairment loss on equity method investment


(55
)




Doga


7


1


Asset impairment charges








(59
)Other


12


11


973


(574
)

239MEHC and EME corporate interest expense


(383
)

(441
)

(452
)MEHC and EME corporate administrative and general


(126
)

(149
)

(138
)Gain on sale of assets





43


Loss on early extinguishment of debt


(24
)




EME corporate interest income and other expense, net


51


(7
)

(16
)Income (Loss) from Continuing Operations Before Income Taxes and Minority Interest

$
491

$
(1,128
)
$
(367
)


---

41

---



Earnings from Consolidated Operations

Illinois Plants

|                                    |                                                               | Years Ended December 31        |    
|----------------------------------- | ------------------------------------------------------------- | ------------------------------ | ---
|
|
|Operating Revenues                  |                                                               |                                |    
|                                    | Energy revenues                                               |                                | $  
|                                    | Capacity revenues                                             |                                |    
|                                    | Other revenues                                                |                                |    
|                                    | Net losses from price risk management                         |                                |    
|                                    |                                                               |                                |    
|                                    | Total operating revenues                                      |                                |    
|                                    |                                                               |                                |    
|Operating Expenses                  |                                                               |                                |    
|                                    | Fuel(1)                                                       |                                |    
|                                    | Sale of emission allowances(2)                                |                                |    
|                                    | Plant operations                                              |                                |    
|                                    | Plant operating leases                                        |                                |    
|                                    | Depreciation and amortization                                 |                                |    
|                                    | Loss on lease termination, asset impairment and other charges |                                |    
|                                    | Administrative and general                                    |                                |    
|                                    |                                                               |                                |    
|                                    | Total operating expenses                                      |                                |    
|                                    |                                                               |                                |    
|Operating Income (Loss)             |                                                               |                                | 551
|                                    |                                                               |                                |    
|Other Income (Expense)              |                                                               |                                |    
|                                    | Interest income from note receivable from EME                 |                                |    
|                                    | Interest expense and other                                    |                                |    
|                                    |                                                               |                                |    
|                                    | Total other income (expense)                                  |                                |    
|                                    |                                                               |                                |    
|Income (Loss) Before Taxes          |                                                               | $                              | 547
|                                    |                                                               |                                |    
|StatisticsCoal-Fired Generation(3) |                                                               |                                |    
|                                    | Generation (in GWh):                                          |                                |    
|                                    |                                                               | Merchant                       |    
|                                    |                                                               | Power purchase agreement       |    
|                                    |                                                               |                                |    
|                                    |                                                               | Total coal-fired generation    |    
|                                    |                                                               |                                |    
|                                    | Equivalent availability(4)                                    |                                |    
|                                    | Forced outage rate(5)                                         |                                |    
|                                    | Average energy price/MWh:                                     |                                |    
|                                    |                                                               | Merchant                       |    
|                                    |                                                               | Power purchase agreement       |    
|                                    |                                                               | Total coal-fired generation(6) |    
|                                    | Average fuel costs/MWh                                        |                                | $  

---

42

---





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:

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:

Partially
offset by:

43

---



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

Partially
offset by:

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.

44

---



Homer City

Years Ended December 31,2005

2004

2003(in millions)Operating RevenuesEnergy revenues

$
632

$
486

$
491Capacity revenues


18


28


30Net gains (losses) from price risk management


(58
)

(17
)

10Total operating revenues


592


497


531Operating ExpensesFuel(1)


288


215


199Sale of emission allowances(2)


(4
)




(6
)Plant operations


112


88


82Plant operating leases


102


102


102Depreciation and amortization


16


15


15Administrative and general


6


3


1Total operating expenses


520


423


393Operating Income


72


74


138Other Income (Expense)Interest expense


(1
)

(1
)

(2
)Interest and other income (expense)


3


4


1Total other income (expense)


2


3


(1
)Income Before Taxes

$
74

$
77

$
137StatisticsGeneration (in GWh)


13,637


13,292


14,403Equivalent 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

$
34.02Average fuel costs/MWh

$
21.08

$
16.15

$
13.79


---

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

45

---



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.

46

---



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.

47

---



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.

On
August 17, 2005, EME entered into a purchase agreement to sell its 80% interest in the Doga project to EME's co-investor in the Doga project, Doga Enerji Yatirim
Isletme ve Ticaret Limited Sirketi, which would have acquired an additional 30% interest in the Doga project, and The Kansai Electric Power Co., Inc., which would have acquired a 50% interest
in the Doga project. The transaction did not close and has been terminated.

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.

48

---



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.

MEHC and EME Corporate Interest Expense

Years Ended December 31,2005

2004

2003(in millions)MEHC (excluding EME) interest expense to third parties

$
113

$
158

$
160EME's interest expense to third parties


157


170


179EME's interest expense to Midwest Generation


113


113


113Total corporate interest expense

$
383

$
441

$
452


MEHC (excluding EME) Interest Expense to Third Parties

MEHC's interest expense (excluding EME) decreased $45 million in 2005, compared to the corresponding period of 2004. The 2005 decrease was attributable to
the repayment of the $385 million term loan ($100 million of the term loan was repaid in July 2004 and the remaining $285 million of the term loan was repaid in
January 2005).

MEHC and EME Corporate Administrative and General Expenses

Administrative and general expenses decreased $23 million in 2005 from 2004, and increased $11 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 $24 million in 2005. Extinguishment of debt consisted of a $20 million loss related to the early repayment
of MEHC's $385 million term loan and a $4 million loss related to the early repayment of EME's junior subordinated debentures, each of which was recorded during the first quarter of
2005.

EME Corporate Interest Income and Other, Net

EME corporate interest income and other (net) increased $58 million in 2005 from 2004 and $9 million in 2004 from 2003. The 2005 increase was
primarily attributable to higher interest income

49

---



resulting
from higher average cash balances in 2005 compared to 2004 due largely to cash proceeds received from the sale of international operations.

Income Taxes

MEHC's income tax provision (benefit) from continuing operations was $169 million in 2005, $(463) million in 2004 and $(175) 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

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.

Results of Discontinued Operations

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:

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

50

---



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:

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

Previously Reported Discontinued Operations

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 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. EME
estimates remaining distributions (expected by the end of 2006) will be approximately $100 million and the 2006 net income impact of distributions to be approximately $75 million. Because taxes
in the United Kingdom have not been finalized, the actual amount of distributions and the impact on net income may vary materially from the above estimates. 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

In November 2004, the Financial Accounting Standards Board (FASB) issued SFAS No. 151, "Inventory Costs." SFAS No. 151 requires that abnormal
amounts of idle facility expense, freight,

51

---



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.

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.

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.

Proposed Accounting Pronouncements

In July 2005, the FASB published an exposure draft of a proposed interpretation that seeks to clarify 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 proposed effective date is January 1, 2007. The FASB is expected to issue a final
interpretation in the first quarter of 2006. EME is currently assessing the potential impact of the proposed interpretation on its results of operations and financial condition.

52

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LIQUIDITY AND CAPITAL RESOURCES

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

PageMEHC's Liquidity

53EME's Liquidity

54Midwest Generation Financing

54Capital Expenditures

54MEHC's Historical Consolidated Cash Flow

55Credit Ratings

57Margin, Collateral Deposits and Other Credit Support for Energy Contracts

57EME's Liquidity as a Holding Company

58Dividend Restrictions in Major Financings

60Contractual Obligations, Commitments and Contingencies

62Off-Balance Sheet Transactions

66Environmental Matters and Regulations

69


MEHC's Liquidity

MEHC's ability to honor its obligations under the senior secured notes is substantially dependent upon the receipt of dividends from EME and the receipt of
tax-allocation payments from MEHC's parent, Edison Mission Group, and ultimately Edison International. See "EME's Liquidity as a Holding CompanyIntercompany
Tax-Allocation Agreement." Dividends to MEHC from EME are limited based on EME's earnings and cash flow, terms of restrictions contained in EME's corporate credit facility, business and
tax considerations and restrictions imposed by applicable law.

At
December 31, 2005, MEHC had cash and cash equivalents of $43 million (excluding amounts held by EME and its subsidiaries). On April 5, 2004, the lenders under
MEHC's $385 million term loan exercised their right to require MEHC to repurchase $100 million of principal amount at par on July 2, 2004. The $100 million principal, plus
interest, was paid on July 2, 2004. The remaining $285 million of principal, plus interest, was paid on January 3, 2005.

Dividends to MEHC

In January 2005, EME made total dividend payments of $360 million to MEHC. A portion of these payments was used to repay the remaining
$285 million of the term loan plus interest, as discussed above. In 2004, EME made dividend payments totaling $74 million to MEHC. These payments were used together with cash on hand to
repurchase $100 million of the principal amount of the term loan, as discussed above.

Dividend Restriction in EME's Corporate Credit Agreement

EME's corporate credit agreement restricts EME's ability to make distributions if an event of default were to occur and be continuing after giving effect to the
distribution. As of December 31, 2005, EME had no borrowings outstanding under this credit agreement.

53

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EME's Liquidity

At December 31, 2005, EME and its subsidiaries had cash and cash equivalents and short-term investments of $1.3 billion, and EME had
available the full amount of borrowing capacity under its $98 million corporate credit facility. EME's consolidated debt at December 31, 2005 was $3.4 billion. In addition, EME's
subsidiaries had $4.6 billion of long-term lease obligations related to the sale-leaseback transactions that are due over periods ranging up to 29 years.

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).

As
of December 31, 2005, Midwest Generation had $333 million outstanding under its term loan and a $500 million working capital facility available for working
capital requirements, including credit support for hedging activities. As of December 31, 2005, approximately $175 million was utilized under the working capital facility.

Capital Expenditures

The estimated capital and construction expenditures of EME's subsidiaries are $390 million, $175 million and $28 million for 2006, 2007 and
2008, respectively. The non-environmental portion of these expenditures relates to the construction of the Wildorado 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 $8 million for 2006, $6 million for 2007 and $6 million for 2008. 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
subsidiaries may also make substantial additional capital expenditures as described under "Environmental Matters and RegulationsFederalUnited States of
AmericaClean Air ActMercury Regulation."

54

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MEHC's Historical Consolidated Cash Flow

Consolidated Cash Flows from Operating Activities

Net cash provided by (used in) operating activities:

Years Ended December 31,2005

2004

2003(in millions)Continuing operations

$
(290
)
$
(507
)
$
470Discontinued operations


20


(434
)

243$
(270
)
$
(941
)
$
713


Cash used in operating activities from continuing operations decreased $217 million in 2005 from 2004, and increased $977 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 by EME 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, MEHC received
$22 million and $61 million in tax-allocation payments in 2004 and 2003, respectively. 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

Net cash used in financing activities:

Years Ended December 31,2005

2004

2003(in millions)Continuing operations

$
(689
)
$
(22
)
$
(475
)Discontinued operations





(144
)

153$
(689
)
$
(166
)
$
(322
)


Cash used in financing activities from continuing operations increased $667 million in 2005 from 2004, and decreased $453 million in
2004 from 2003. The 2005 increase was primarily attributable to the repayment of the remaining $285 million of MEHC's term loan, $11 million paid for the call

55

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premium
on the retirement of the term loan and the repayment of EME's junior subordinated debentures of $150 million, all in January 2005. In addition, there was 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, and $100 million related to
the $385 million MEHC term loan in July 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 an acquisition of a power station, partially offset by repayment of debt.

Consolidated Cash Flows from Investing Activities

Net cash provided by (used in) investing activities:

Years Ended December 31,2005

2004

2003(in millions)Continuing operations

$
(130
)
$
2,713

$
(83
)Discontinued operations


5


18


(413
)$
(125
)
$
2,731

$
(496
)


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:

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.

56

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Credit Ratings

Overview

The credit ratings for MEHC and its subsidiaries, EME, Midwest Generation and EMMT, are as follows:

Moody's Rating

S&P RatingMEHC

B2

CCC+EME

B1

B+Midwest Generation:First priority senior secured rating

Ba3

BB-Second priority senior secured rating

B1

BEMMT

Not Rated

B+


MEHC 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. MEHC 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.

MEHC
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

57

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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
December 31, 2005, EMMT had deposited $543 million in cash with brokers in margin accounts in support of futures contracts and had deposited $155 million with counterparties in
support of forward energy and transmission contracts. In addition, EME had issued letters of credit of $12 million in support of commodity contracts at December 31, 2005.

Margin
and collateral deposits increased substantially in 2005 due to higher wholesale energy prices and increased megawatt hours hedged under contracts requiring margin and collateral.
Future cash collateral requirements may be higher than the margin and collateral requirements at December 31, 2005, if wholesale energy prices increase further or the amount hedged increases.
EME estimates that margin and collateral requirements for energy contracts outstanding as of December 31, 2005 could increase during 2006 by approximately $180 million using a 95%
confidence level.

Midwest
Generation has a $500 million working capital facility to support margin requirements specifically related to contracts entered into by EMMT related to the Illinois
Plants. At December 31, 2005, Midwest Generation had borrowed $170 million under this credit facility to finance margin advances to EMMT of $328 million. The balance of the
margining advances by Midwest Generation was
provided through cash on hand. In addition, EME has cash on hand and a $98 million working capital facility to provide credit support to subsidiaries. See "EME's Liquidity as a Holding Company"
for further discussion.

EME's Liquidity as a Holding Company

Overview

At December 31, 2005, EME had corporate cash and cash equivalents and short-term investments of $1.1 billion to meet liquidity needs.
See "EME's Liquidity." 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."

As
security for its obligations under EME's corporate credit facility, EME has 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 are deposited. EME is free to use these distributions unless and until an event of default occurs under its corporate credit facility.

At
December 31, 2005, EME also had available $74 million under Midwest Generation EME, LLC's $100 million letter of credit facility with Citibank, N.A., as Issuing
Bank, that expires in December 2006. Under the terms of this letter of credit facility, Midwest Generation EME is required to deposit cash in a bank account in order to cash collateralize any
letters of credit that may be outstanding under the facility. The bank account is pledged to the Issuing Bank. Midwest Generation EME owns 100% of Edison Mission Midwest Holdings, which in turn owns
100% of Midwest Generation, LLC.

58

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Historical Distributions Received By EME

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

|                                                      |                                                              | Years Ended December 31, |    
|----------------------------------------------------- | ------------------------------------------------------------ | ------------------------ | ---
|
|
|Distributions from Consolidated Operating Projects:   |                                                              |                          |    
|                                                      | Edison Mission Midwest Holdings (Illinois Plants)            |                          | $  
|                                                      | EME Homer City Generation L.P. (Homer City facilities)       |                          |    
|                                                      | Holding companies of other consolidated generating projects  |                          |    
|Distributions from Unconsolidated Operating Projects: |                                                              |                          |    
|                                                      | Edison Mission Energy Funding Corp. (Big 4 Projects)(3)      |                          |    
|                                                      | Four Star Oil & Gas Company                                  |                          |    
|                                                      | Sunrise Power Company                                        |                          |    
|                                                      | Holding company for Doga project                             |                          |    
|                                                      | Holding companies for Westside projects                      |                          |    
|                                                      | Holding companies of other unconsolidated operating projects |                          |    
|                                                      |                                                              |                          |    
|Total Distributions                                   |                                                              | $                        | 598
|                                                      |                                                              |                          |    

---

Intercompany Tax-Allocation Agreement

MEHC and EME are included in the consolidated federal and combined state income tax returns of Edison International and are eligible to participate in
tax-allocation payments with other subsidiaries of Edison International in circumstances where domestic tax losses are incurred. The right of MEHC and EME to receive and the amount of and
timing of tax-allocation payments are dependent on the inclusion of MEHC and EME, respectively, in the consolidated income tax returns of Edison International and its subsidiaries and
other factors, including the consolidated taxable income of Edison International and its subsidiaries, the amount of net operating losses and other tax items of MEHC, EME, its subsidiaries, and other
subsidiaries of Edison International and specific procedures regarding allocation of state taxes. MEHC and EME receive tax-allocation payments for tax losses when and to the extent that
the consolidated Edison International group generates sufficient taxable income in order to be able to utilize MEHC's tax losses or the tax losses of EME in the consolidated income tax returns for
Edison International and its subsidiaries. Based on the application of the factors cited above, MEHC and EME are obligated during periods they generate taxable income to make payments under the
tax-allocation agreements. MEHC received $93 million and $22 million in tax-allocation payments from Edison International during 2005 and 2004, respectively. EME paid
tax-allocation payments to Edison International of $129 million and $7 million during 2005 and 2004, respectively.

59

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Dividend Restrictions in Major Financings

General

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

Key Ratios of MEHC and EME's Principal Subsidiaries Affecting Dividends

Set forth below are key ratios of MEHC and EME's principal subsidiaries required by financing arrangements for the twelve months ended December 31, 2005:

|Subsidiary                                             |  | Financial Ratio                    |  | Covenant                           |  | Actual   
|------------------------------------------------------ |  | ---------------------------------- |  | ---------------------------------- |  | ---------
|Mission Energy Holding Company                         |  | Interest Coverage Ratio            |  | Greater than 2.0 to 1              |  | 2.79 to 1
|Midwest Generation, LLC (Illinois Plants)              |  | Interest Coverage Ratio            |  | Greater than or equal to 1.40 to 1 |  | 6.40 to 1
|Midwest Generation, LLC (Illinois Plants)              |  | Secured Leverage Ratio             |  | Less than or equal to 7.25 to 1    |  | 1.99 to 1
|EME Homer City Generation L.P. (Homer City facilities) |  | Senior Rent Service Coverage Ratio |  | Greater than 1.7 to 1              |  | 2.59 to 1

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:

60

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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 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.

In
January 2005, Midwest Generation made a distribution of $61 million and, as required under its credit agreement, Midwest Generation offered to prepay $20 million
of the term loan, of which $5 million was accepted by certain lenders and repaid on January 24, 2005. Midwest Generation subsequently made a voluntary prepayment, as provided under the
credit agreement, of $15 million on January 28, 2005. In April 2005 and October 2005, Midwest Generation made additional distributions of $109 million and
$160 million, respectively.

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 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.

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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 December 31, 2005, EME had no borrowings outstanding under this credit facility.

Contractual Obligations, Commitments and Contingencies

Contractual Obligations

The following table summarizes MEHC'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 yearsMEHC-only long-term debt(1)

$
1,124

$
108

$
1,016

$


$
EME's long-term debt(1)


4,921


328


1,088


1,006


2,499EME's operating lease obligations


4,755


362


717


693


2,983EME's purchase obligations:Capital improvements


8


8








Turbine commitments(2)


192


114


78





Fuel supply contracts


1,031


367


487


158


19Gas transportation agreements


100


8


16


16


60Coal transportation


680


226


301


153


Other contractual obligations


55


12


22


21


EME's employee benefit plan contribution(3)


15


15








Total Contractual Obligations

$
12,881

$
1,548

$
3,725

$
2,047

$
5,561


---

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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 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.

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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 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 liability at December 31, 2005 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.

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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

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, EME had recorded a liability of $122 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 December 31, 2005, EME had recorded a liability of $8 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

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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

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

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.

Tax Matters

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

Off-Balance Sheet Transactions

Introduction

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

Investments Accounted for under the Equity Method

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.

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Historically,
EME has invested in qualifying facilities, those which produce electrical energy and steam, or other forms of energy, and which meet the requirements set forth in the
Public Utility Regulatory Policies Act. See "Item 1. BusinessRegulatory MattersU.S. Federal Energy Regulation." 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, 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.

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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
|---------------- |  | ----------------- | ----- | --------------- | -------------------------------------------- | ------------------------------------------ | - | ------------------------------------------ |  | ----------------------------
|
|Powerton/Joliet  |  | $                 | 1,367 |                 | PSEG/ Citigroup, Inc.                        |                                            | $ | 238                                        |  | $                           
|Homer City       |  |                   | 1,591 |                 | GECC/ Metropolitan Life Insurance Company(1) |                                            |   | 798                                        |  | $                           

---

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

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

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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

$
1162007


3


113


1162008


4


112


1162009


4


112


1162010


5


112


117Thereafter


1,343


512


1,855Total

$
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 (CAIR) was published in the Federal Register. The CAIR requires 28 eastern states and the District of Columbia to address ozone
attainment issues by

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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 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

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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

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 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.

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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.

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.

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

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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.

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.

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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.

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
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.

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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 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

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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.

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 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

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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 CPUC
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.

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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.

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

PageCommodity Price Risk

78Credit Risk

87Interest Rate Risk

88Fair Value of Financial Instruments

89


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:

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

Introduction

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.

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, Midwest Generation's and EMMT'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

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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 has generally been sold into the PJM market. Capacity prices for merchant energy sales within PJM are,
and are expected in the near term to remain, substantially lower than those Midwest Generation received under the power purchase agreements with Exelon Generation.

Prior
to May 1, 2004, the primary markets available to Midwest Generation for wholesale sales of electricity from the Illinois Plants were direct "wholesale customers" and broker
arranged "over-the-counter customers." Effective May 1, 2004, the transmission system of Commonwealth Edison was placed under the control of PJM as the Northern Illinois
control area, and on October 1, 2004, the transmission system of AEP was integrated into PJM, linking eastern PJM and the Northern Illinois control areas of the PJM system and allowing the
Illinois Plants to be dispatched into the broader PJM market. Further, on April 1, 2005, the 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.

Midwest
Generation sells its power into PJM at spot prices based upon locational marginal pricing and is no longer required to arrange and pay separately for transmission when making
sales to wholesale buyers within the PJM system. Hedging transactions related to the generation of the Illinois units are entered into at the Northern Illinois Hub in PJM, the AEP/Dayton Hub in PJM
and, with the advent of MISO, at the Cinergy Hub in MISO. Because of proximity, the Illinois Plants are primarily hedged with transactions at the Northern Illinois Hub, but from time to time may be
hedged in limited amounts at the AEP/Dayton Hub and the Cinergy Hub. These trading hubs have been the most liquid locations for these 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.

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

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

2005(1)

2004January

$
38.36

$
27.88
(2)February


34.92


29.98
(2)March


45.75


30.66
(2)April


38.98


27.88
(2)May


33.60


34.05
(1)June


42.45


28.58
(1)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


---

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.

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The
following table sets forth the forward month-end market prices for energy per megawatt-hour for the calendar year 2006 and calendar year 2007 "strips," which
are defined as energy purchases for the entire calendar year, as quoted for sales into the Northern Illinois Hub during 2005:

24-Hour Northern Illinois Hub
Forward Energy Prices*2006

2007January 31, 2005

$
34.67

$
33.85February 28, 2005


36.52


35.61March 31, 2005


41.49


40.49April 29, 2005


41.52


39.73May 31, 2005


40.15


39.45June 30, 2005


42.73


42.17July 29, 2005


44.66


43.17August 31, 2005


51.29


46.79September 30, 2005


52.74


47.61October 31, 2005


49.52


43.38November 30, 2005


53.75


47.73December 30, 2005


53.08


46.66


---

The following table summarizes Midwest Generation's hedge position (primarily based on prices at the Northern Illinois Hub) at December 31,
2005:

2006

2007Megawatt hours


15,047,414


11,004,000Average price/MWh(1)

$
44.29

$
48.04


---

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. The PJM pool 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.

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

|               |  | Historical Energy Prices*
24-Hour PJM
|-------------- |  | -------------------------------------
|
|
|January        |  | $                                    
|February       |  |                                      
|March          |  |                                      
|April          |  |                                      
|May            |  |                                      
|June           |  |                                      
|July           |  |                                      
|August         |  |                                      
|September      |  |                                      
|October        |  |                                      
|November       |  |                                      
|December       |  |                                      
|               |  |                                      
|Yearly Average |  | $                                    
|               |  |                                      

---

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.

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The
following table sets forth the forward month-end market prices for energy per megawatt-hour for the calendar 2006 and 2007 "strips," which are defined as
energy purchases for the entire calendar year, as quoted for sales into the PJM West Hub during 2005:

24-Hour PJM West Hub
Forward Energy Prices*2006

2007January 31, 2005

$
46.11

$
44.48February 28, 2005


48.17


46.84March 31, 2005


53.07


50.80April 29, 2005


50.26


49.16May 31, 2005


50.05


49.56June 30, 2005


53.66


52.71July 29, 2005


55.88


54.35August 31, 2005


65.31


59.81September 30, 2005


72.01


62.18October 31, 2005


69.26


60.86November 30, 2005


75.58


66.16December 30, 2005


73.74


68.62


---

The following table summarizes Homer City's hedge position at December 31, 2005:

2006

2007Megawatt hours


8,526,000


5,280,000Average price/MWh(1)

$
53.42

$
67.30


---

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.

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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 known as the PJM West Hub in the case of the Homer City facilities and for a settlement point known as 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:

Under
the PJM market design, locational marginal pricing, which establishes hourly prices at specific locations throughout PJM by considering factors including generator bids, load
requirements, transmission congestion and losses, can cause the price 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 by EME as "basis risk." 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 4%
during 2004. The monthly average difference during 2005 ranged from zero to 20%, which occurred in August 2005. In contrast to the Homer City facilities, during 2005, 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 future contracts and forward contracts using the PJM West Hub and the Northern Illinois Hub (or other similar trading hubs) as the settlement points, EME is
exposed to basis risk as described above. In order to mitigate basis risk, EME has participated in purchasing financial transmission rights in PJM, and may continue to do so in the future. A financial
transmission right is a financial instrument that entitles the holder to receive actual spot prices at one point of delivery and pay prices at another point of delivery that are pegged to prices at
the first point of delivery, plus or minus a fixed amount. Accordingly, EME's price risk management activities include using financial transmission rights alone or in combination with forward
contracts to manage 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 from mines located near the facilities in Pennsylvania. Coal
purchases are made under a variety of supply agreements with terms

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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 December 31, 2005.

Percent of Coal Requirements
Under Contract2006

2007

2008

2009

2010Illinois Plants

100%

91%

32%

32%

33%Homer City facilities

101%

94%

39%

15%

0%


EME is subject to price risk for purchases of coal that are not under contract. Prices of Northern Appalachian (NAPP) coal, which is purchased for
the Homer City facilities, have increased considerably during 2004 and 2005. 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 has been largely attributed to
greater demand from domestic power producers and increased international shipments of coal to Asia. Prices of Powder River Basin (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 December 30, 2005, the Energy Information Administration reported
the price of coal to be $18.48 per ton, which compares to 2004 prices of generally below $7 per ton.

During
2005, the rail lines that bring coal from the PRB to EME's Illinois Plants were damaged from derailments caused by heavy rains. The railroads are in the process of making repairs
to these rail lines. During 2005, Midwest Generation received sufficient quantities to meet generation requirements. Rail line maintenance is expected to continue in 2006. Based on communication with
the transportation provider, EME expects to continue receiving a sufficient amount of coal to generate power at historical levels while these repairs are being completed.

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. 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. The increase in the price of SO2 allowances has been attributed to reduced numbers of
both allowance sellers and prior year allowances.

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

86

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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 December 31, 2005, the amount of exposure, broken down by the credit ratings of EME's
counterparties, was as follows:

S&P Credit Rating

December 31, 2005(in millions)A or higher

$
6A-


230BBB+


45BBB


28BBB-


3Below investment grade


Total

$
312


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

87

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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 markets or transact capacity on a bilateral basis. Sales into the PJM pool
accounted for approximately 70% of EME's consolidated operating revenues for the year ended December 31, 2005. 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.

Interest Rate Risk

The fair market value of MEHC's parent only total long-term obligations was $1.0 billion at December 31, 2005, compared to the carrying
value of $792 million. A 10% increase or decrease in market interest rates at December 31, 2005 would result in a decrease or increase in the fair value of total long-term
obligations by approximately $13 million.

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 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
2006 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
MEHC's total long-term obligations (including current portion) was $4.7 billion at December 31, 2005, compared to the carrying value of $4.1 billion. A 10% increase in
market interest rates at December 31, 2005 would result in a decrease in the fair value of MEHC's total long-term obligations by approximately $138 million. A 10% decrease in
market interest rates at December 31, 2005 would result in an increase in the fair value of MEHC's total long-term obligations by approximately $154 million.

88

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Fair Value of Financial Instruments

Non-Trading Derivative Financial Instruments

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

December 31,
2005

December 31,
2004Commodity price:Electricity

$
(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 as of December 31, 2005 (in millions):

Total Fair
Value

Maturity
<1 year

Maturity
1 to 3
years

Maturity
4 to 5
years

Maturity
>5 yearsPrices actively quoted

$
(434
)
$
(354
)
$
(80
)
$


$



Energy Trading Derivative Financial Instruments

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

December 31, 2005

December 31, 2004Assets

Liabilities

Assets

LiabilitiesElectricity

$
127

$
27

$
125

$
36Other


1








Total

$
128

$
27

$
125

$
36


The change in the fair value of trading contracts for the year ended December 31, 2005, was as follows (in millions):

Fair value of trading contracts at January 1, 2005

$
89Net gains from energy trading activities


202Amount realized from energy trading activities


(203
)Other changes in fair value


13Fair value of trading contracts at December 31, 2005

$
101


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.

89

---



Quoted
market prices are used to determine the fair value of the financial instruments related to energy trading activities, except for a power sales agreement with an unaffiliated
electric utility that EME's subsidiary purchased and restructured and a long-term power supply agreement with another unaffiliated party. EME's subsidiary recorded these agreements at fair
value based upon a discounting of future electricity prices derived from a proprietary model using a discount rate equal to the cost of borrowing the non-recourse debt incurred to finance
the purchase of the power supply agreement. The following table summarizes the maturities, the valuation method and the related fair value of energy trading assets and liabilities (as of
December 31, 2005) (in millions):

Total Fair
Value

Maturity
<1 year

Maturity
1 to 3
years

Maturity
4 to 5
years

Maturity
>5 yearsPrices actively quoted

$
12

$
12

$


$


$
Prices based on models and other valuation methods


89


2


9


15


63Total

$
101

$
14

$
9

$
15

$
63


RECENT DEVELOPMENT

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. No fire
occurred and there were no injuries as a result of the equipment failure. EME Homer City has secured a replacement transformer and currently expects remedial and replacement activities to be completed
in a manner which will permit Unit 3 to return to service in April 2006. EME Homer City plans to adjust its previously planned outage schedules for Unit 3 and the other Homer City units in
order to minimize overall outage activities over the next fifteen months. Although the unplanned outage will reduce generation and hence revenues and net income during the first quarter of 2006,
because of the change in outage schedules generation for the year as a
whole should not be significantly affected. In order to mitigate the effects of the outage on EME Homer City's cash flow for the first quarter of 2006, EME and EMMT have arranged with EME Homer City
to advance to EME Homer City such funds, if any, as may be necessary to enable EME Homer City to meet its ongoing operating obligations during the period affected by the outage. It is anticipated that
these funds, if any, will be recovered by EME and EMMT during the balance of the year.

ITEM 7A.    QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

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

90

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ITEM 8.    FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA

|Financial Statements: |                                                                                                      | 
|--------------------- | ---------------------------------------------------------------------------------------------------- | 
|                      | Report of Independent Registered Public Accounting Firm                                              | 
|                      | Consolidated Statements of Income (Loss) for the years ended December 31, 2005, 2004 and 2003        | 
|                      | Consolidated Balance Sheets at December 31, 2005 and 2004                                            | 
|                      | Consolidated Statements of Shareholder's Equity for the years ended December 31, 2005, 2004 and 2003 | 
|                      | Consolidated Statements of Comprehensive Income for the years ended December 31, 2005, 2004 and 2003 | 
|                      | Consolidated Statements of Cash Flows for the years ended December 31, 2005, 2004 and 2003           | 
|                      | Notes to Consolidated Financial Statements                                                           | 

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

None.

ITEM 9A.    CONTROLS AND PROCEDURES

Disclosure Controls and Procedures

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

Internal Control Over Financial Reporting

There were no changes in MEHC's internal control over financial reporting (as such term is defined in Rules 13a-15(f) or 15d-15(f)
under the Exchange Act) during the fourth fiscal quarter of 2005 that have materially affected, or are reasonably likely to materially affect, MEHC's internal control over financial reporting.

ITEM 9B.    OTHER INFORMATION

None.

91

---



MISSION ENERGY HOLDING COMPANY AND SUBSIDIARIES
REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To
the Board of Directors and Shareholder of Mission Energy Holding Company

In
our opinion, the consolidated financial statements listed in the accompanying index present fairly, in all material respects, the financial position of Mission Energy Holding Company
and its subsidiaries at December 31, 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 listed in the index appearing under
Item 15(a)(2) 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.

PricewaterhouseCoopers
LLP
Los Angeles, California
March 6, 2006

92

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

|                                                                                                                              |                                                                                    | Years Ended December 31,     |    
|----------------------------------------------------------------------------------------------------------------------------- | ---------------------------------------------------------------------------------- | ---------------------------- | ---
|
|Operating Revenues                                                                                                            |                                                                                    |                              |    
|                                                                                                                              | Electric revenues                                                                  |                              | $  
|                                                                                                                              | Net gains from price risk management and energy trading                            |                              |    
|                                                                                                                              | Operation and maintenance services                                                 |                              |    
|                                                                                                                              |                                                                                    |                              |    
|                                                                                                                              |                                                                                    | Total operating revenues     |    
|                                                                                                                              |                                                                                    |                              |    
|Operating Expenses                                                                                                            |                                                                                    |                              |    
|                                                                                                                              | Fuel                                                                               |                              |    
|                                                                                                                              | Plant operations                                                                   |                              |    
|                                                                                                                              | Plant operating leases                                                             |                              |    
|                                                                                                                              | Operation and maintenance services                                                 |                              |    
|                                                                                                                              | Depreciation and amortization                                                      |                              |    
|                                                                                                                              | Loss on lease termination, asset impairment and other charges                      |                              |    
|                                                                                                                              | Administrative and general                                                         |                              |    
|                                                                                                                              |                                                                                    |                              |    
|                                                                                                                              |                                                                                    | Total operating expenses     |    
|                                                                                                                              |                                                                                    |                              |    
|                                                                                                                              | Operating income (loss)                                                            |                              |    
|                                                                                                                              |                                                                                    |                              |    
|Other Income (Expense)                                                                                                        |                                                                                    |                              |    
|                                                                                                                              | Equity in income from unconsolidated affiliates                                    |                              |    
|                                                                                                                              | Impairment loss on equity method investment                                        |                              |    
|                                                                                                                              | Interest and other income                                                          |                              |    
|                                                                                                                              | Gain on sale of assets                                                             |                              |    
|                                                                                                                              | Loss on early extinguishment of debt                                               |                              |    
|                                                                                                                              | Interest expense                                                                   |                              |    
|                                                                                                                              | Dividends on preferred securities                                                  |                              |    
|                                                                                                                              |                                                                                    |                              |    
|                                                                                                                              |                                                                                    | Total other income (expense) |    
|                                                                                                                              |                                                                                    |                              |    
|                                                                                                                              | Income (loss) from continuing operations before income taxes and minority interest |                              |    
|                                                                                                                              | Provision (benefit) for income taxes                                               |                              |    
|                                                                                                                              | Minority interest                                                                  |                              |    
|                                                                                                                              |                                                                                    |                              |    
|Income (Loss) From Continuing Operations                                                                                      |                                                                                    |                              | 322
|Income from operations of discontinued subsidiaries (including gain on disposal of $533 million in 2004), net of tax (Note 8) |                                                                                    |                              | 29 
|                                                                                                                              |                                                                                    |                              |    
|Income (Loss) Before Accounting Change                                                                                        |                                                                                    |                              | 351
|Cumulative effect of change in accounting, net of tax (Note 3)                                                                |                                                                                    |                              | (1 
|                                                                                                                              |                                                                                    |                              |    
|Net Income (Loss)                                                                                                             |                                                                                    | $                            | 350
|                                                                                                                              |                                                                                    |                              |    

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

93

---



MISSION ENERGY HOLDING COMPANY AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
(In millions)

|                                         |                                                                                | December 31,                     
|---------------------------------------- | ------------------------------------------------------------------------------ | ---------------------------------
|
|Assets                                   |                                                                                |                                  
|Current Assets                           |                                                                                |                                  
|                                         | Cash and cash equivalents                                                      |                                  
|                                         | Short-term investments                                                         |                                  
|                                         | Accounts receivabletrade                                                      |                                  
|                                         | Accounts receivableaffiliates                                                 |                                  
|                                         | Inventory                                                                      |                                  
|                                         | Assets under price risk management and energy trading                          |                                  
|                                         | Margin and collateral deposits                                                 |                                  
|                                         | Deferred taxes                                                                 |                                  
|                                         | Prepaid expenses and other                                                     |                                  
|                                         |                                                                                |                                  
|                                         |                                                                                | Total current assets             
|                                         |                                                                                |                                  
|Investments in Unconsolidated Affiliates |                                                                                |                                  
|                                         |                                                                                |                                  
|Property, Plant and Equipment            |                                                                                |                                  
|                                         | Less accumulated depreciation and amortization                                 |                                  
|                                         |                                                                                |                                  
|                                         |                                                                                | Net property, plant and equipment
|                                         |                                                                                |                                  
|Other Assets                             |                                                                                |                                  
|                                         | Deferred financing costs                                                       |                                  
|                                         | Long-term assets under price risk management and energy trading                |                                  
|                                         | Restricted cash                                                                |                                  
|                                         | Rent payments in excess of levelized rent expense under plant operating leases |                                  
|                                         | Long-term margin and collateral deposits                                       |                                  
|                                         | Other long-term assets                                                         |                                  
|                                         |                                                                                |                                  
|                                         |                                                                                | Total other assets               
|                                         |                                                                                |                                  
|Assets of Discontinued Operations        |                                                                                |                                  
|                                         |                                                                                |                                  
|Total Assets                             |                                                                                | $                                
|                                         |                                                                                |                                  

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

94

---



MISSION ENERGY HOLDING COMPANY AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
(In millions)

|                                                                     |                                                                                                                                        | December 31,              |      
|-------------------------------------------------------------------- | -------------------------------------------------------------------------------------------------------------------------------------- | ------------------------- | -----
|
|Liabilities and Shareholder's Equity                                 |                                                                                                                                        |                           |      
|Current Liabilities                                                  |                                                                                                                                        |                           |      
|                                                                     | Accounts payableaffiliates                                                                                                            |                           | $    
|                                                                     | Accounts payable and accrued liabilities                                                                                               |                           |      
|                                                                     | Liabilities under price risk management and energy trading                                                                             |                           |      
|                                                                     | Interest payable                                                                                                                       |                           |      
|                                                                     | Current maturities of long-term obligations                                                                                            |                           |      
|                                                                     |                                                                                                                                        |                           |      
|                                                                     |                                                                                                                                        | Total current liabilities |      
|                                                                     |                                                                                                                                        |                           |      
|Long-term obligations net of current maturities                      |                                                                                                                                        |                           | 4,095
|Deferred taxes and tax credits                                       |                                                                                                                                        |                           | 176  
|Long-term liabilities under price risk management and energy trading |                                                                                                                                        |                           | 83   
|Other long-term liabilities                                          |                                                                                                                                        |                           | 540  
|Liabilities of discontinued operations                               |                                                                                                                                        |                           | 4    
|                                                                     |                                                                                                                                        |                           |      
|Total Liabilities                                                    |                                                                                                                                        |                           | 5,767
|                                                                     |                                                                                                                                        |                           |      
|Minority Interest                                                    |                                                                                                                                        |                           | 24   
|                                                                     |                                                                                                                                        |                           |      
|Commitments and Contingencies(Notes 11, 12, 16 and 17)               |                                                                                                                                        |                           |      
|Shareholder's Equity                                                 |                                                                                                                                        |                           |      
|                                                                     | Common stock, par value $0.01 per share; 1,000 shares authorized; 1,000 shares issued and outstanding as of December 31, 2005 and 2004 |                           |      
|                                                                     | Additional paid-in capital                                                                                                             |                           |      
|                                                                     | Retained deficit                                                                                                                       |                           |      
|                                                                     | Accumulated other comprehensive income (loss)                                                                                          |                           |      
|                                                                     |                                                                                                                                        |                           |      
|Total Shareholder's Equity                                           |                                                                                                                                        |                           | 1,048
|                                                                     |                                                                                                                                        |                           |      
|Total Liabilities and Shareholder's Equity                           |                                                                                                                                        | $                         | 6,839
|                                                                     |                                                                                                                                        |                           |      

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

95

---



MISSION ENERGY HOLDING COMPANY AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF SHAREHOLDER'S EQUITY
(In millions)

|                             |                                                                                           | Additional
Paid-in
Capital |       | Retained
Deficit |   | Accumulated
Other
Comprehensive
Income (Loss) |     | Shareholder's
Equity |     
|---------------------------- | ----------------------------------------------------------------------------------------- | -------------------------- | ----- | ---------------- | - | --------------------------------------------- | --- | -------------------- | ----
|Balance at December 31, 2002 |                                                                                           |                            | 2,218 |                  |   | (1,265                                        | )   |                      | (217
|                             | Net loss                                                                                  |                            |       |                  |   |                                               | (79 | )                    |     
|                             | Other comprehensive income                                                                |                            |       |                  |   |                                               |     |                      |     
|                             |                                                                                           |                            |       |                  |   |                                               |     |                      |     
|Balance at December 31, 2003 |                                                                                           |                            | 2,218 |                  |   | (1,344                                        | )   |                      | (25 
|                             | Net income                                                                                |                            |       |                  |   |                                               | 24  |                      |     
|                             | Other comprehensive income                                                                |                            |       |                  |   |                                               |     |                      |     
|                             | Payments to Edison International for stock option price appreciation on options exercised |                            |       | (8               | ) |                                               |     |                      |     
|                             | Other stock transactions, net                                                             |                            |       | 5                |   |                                               |     |                      |     
|                             |                                                                                           |                            |       |                  |   |                                               |     |                      |     
|Balance at December 31, 2004 |                                                                                           |                            | 2,215 |                  |   | (1,320                                        | )   |                      | 17  
|                             | Net income                                                                                |                            |       |                  |   |                                               | 350 |                      |     
|                             | Other comprehensive loss                                                                  |                            |       |                  |   |                                               |     |                      |     
|                             | Non-cash equity contribution                                                              |                            |       | 20               |   |                                               |     |                      |     
|                             | Payments to Edison International for stock option price appreciation on options exercised |                            |       | (4               | ) |                                               |     |                      |     
|                             | Other stock transactions, net                                                             |                            |       | (2               | ) |                                               |     |                      |     
|                             |                                                                                           |                            |       |                  |   |                                               |     |                      |     
|Balance at December 31, 2005 |                                                                                           | $                          | 2,229 |                  | $ | (970                                          | )   | $                    | (211
|                             |                                                                                           |                            |       |                  |   |                                               |     |                      |     

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

96

---



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

|                                        |                                                                         | Years Ended December 31,                                                                                                                                       |     
|--------------------------------------- | ----------------------------------------------------------------------- | -------------------------------------------------------------------------------------------------------------------------------------------------------------- | ----
|
|Net Income (Loss)                       |                                                                         | $                                                                                                                                                              | 350 
|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                                               |     
|                                        |                                                                         | Reclassification adjustments for sale of investment in a foreign subsidiary                                                                                    |     
|                                        | Minimum pension liability adjustment, net of income tax effect          |                                                                                                                                                                |     
|                                        | 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), $(4) and $3 for 2005, 2004 and 2003, respectively |     
|                                        |                                                                         | Reclassification adjustments included in net income (loss), net of income tax expense (benefit) of $107, $(64) and $(1) for 2005, 2004 and 2003, respectively  |     
|                                        |                                                                         |                                                                                                                                                                |     
|Other comprehensive income              |                                                                         |                                                                                                                                                                | (228
|                                        |                                                                         |                                                                                                                                                                |     
|Comprehensive Income                    |                                                                         | $                                                                                                                                                              | 122 
|                                        |                                                                         |                                                                                                                                                                |     

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

97

---



MISSION ENERGY HOLDING COMPANY AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CASH FLOWS
(In millions)

|                                                                        |                                                                                         | Years Ended December 31,                                        |       
|----------------------------------------------------------------------- | --------------------------------------------------------------------------------------- | --------------------------------------------------------------- | ------
|
|Cash Flows From Operating Activities                                    |                                                                                         |                                                                 |       
|                                                                        | Net income (loss)                                                                       |                                                                 | $     
|                                                                        | Less: Income from discontinued operations                                               |                                                                 |       
|                                                                        |                                                                                         |                                                                 |       
|                                                                        | Income (loss) from continuing operations, net                                           |                                                                 |       
|                                                                        | Adjustments to reconcile income to net cash provided by (used in) operating activities: |                                                                 |       
|                                                                        |                                                                                         | Equity in income from unconsolidated affiliates                 |       
|                                                                        |                                                                                         | Distributions from unconsolidated affiliates                    |       
|                                                                        |                                                                                         | Depreciation and amortization                                   |       
|                                                                        |                                                                                         | Amortization of discount on long-term obligations               |       
|                                                                        |                                                                                         | Minority interest                                               |       
|                                                                        |                                                                                         | Deferred taxes and tax credits                                  |       
|                                                                        |                                                                                         | Gain on sale of assets                                          |       
|                                                                        |                                                                                         | Loss on early extinguishment of debt                            |       
|                                                                        |                                                                                         | Impairment charges                                              |       
|                                                                        |                                                                                         | Cumulative effect of change in accounting, net of tax           |       
|                                                                        | Changes in operating assets and liabilities:                                            |                                                                 |       
|                                                                        |                                                                                         | Increase in margin and collateral deposits                      |       
|                                                                        |                                                                                         | Increase in accounts receivable                                 |       
|                                                                        |                                                                                         | Decrease (increase) in inventory                                |       
|                                                                        |                                                                                         | Decrease in prepaid expenses and other                          |       
|                                                                        |                                                                                         | Increase in rent payments in excess of levelized rent expense   |       
|                                                                        |                                                                                         | Increase (decrease) in accounts payable and accrued liabilities |       
|                                                                        |                                                                                         | Increase (decrease) in interest payable                         |       
|                                                                        |                                                                                         | Decrease in net assets under risk management                    |       
|                                                                        |                                                                                         | Other operatingassets                                          |       
|                                                                        |                                                                                         | Other operatingliabilities                                     |       
|                                                                        |                                                                                         |                                                                 |       
|                                                                        |                                                                                         |                                                                 | (290  
|                                                                        | Operating cash flow from discontinued operations                                        |                                                                 |       
|                                                                        |                                                                                         |                                                                 |       
|                                                                        |                                                                                         | Net cash provided by (used in) operating activities             |       
|                                                                        |                                                                                         |                                                                 |       
|Cash Flows From Financing Activities                                    |                                                                                         |                                                                 |       
|                                                                        | Borrowing on long-term debt and lease swap agreements                                   |                                                                 |       
|                                                                        | Payments on long-term debt agreements                                                   |                                                                 |       
|                                                                        | Payments for price appreciation on stock options exercised                              |                                                                 |       
|                                                                        | Financing costs                                                                         |                                                                 |       
|                                                                        |                                                                                         |                                                                 |       
|                                                                        |                                                                                         |                                                                 | (689  
|                                                                        | Financing cash flow from discontinued operations                                        |                                                                 |       
|                                                                        |                                                                                         |                                                                 |       
|                                                                        |                                                                                         | Net cash used in financing activities                           |       
|                                                                        |                                                                                         |                                                                 |       
|Cash Flows From Investing Activities                                    |                                                                                         |                                                                 |       
|                                                                        | Investments in and loans to energy projects                                             |                                                                 |       
|                                                                        | Purchase of common stock of acquired companies                                          |                                                                 |       
|                                                                        | Capital expenditures                                                                    |                                                                 |       
|                                                                        | Proceeds from sale of interest in projects                                              |                                                                 |       
|                                                                        | Proceeds from sale of discontinued operations                                           |                                                                 |       
|                                                                        | Purchase of short-term investments                                                      |                                                                 |       
|                                                                        | Sales of short-term investments                                                         |                                                                 |       
|                                                                        | Decrease in restricted cash                                                             |                                                                 |       
|                                                                        | Turbine deposits                                                                        |                                                                 |       
|                                                                        | Proceeds from (investments in) other assets                                             |                                                                 |       
|                                                                        |                                                                                         |                                                                 |       
|                                                                        |                                                                                         |                                                                 | (130  
|                                                                        | Investing cash flow from discontinued operations                                        |                                                                 |       
|                                                                        |                                                                                         |                                                                 |       
|                                                                        |                                                                                         | Net cash provided by (used in) investing activities             |       
|                                                                        |                                                                                         |                                                                 |       
|Effect of exchange rate changes on cash                                 |                                                                                         |                                                                 |      
|Effect on cash from deconsolidation of subsidiary                       |                                                                                         |                                                                 |      
|                                                                        |                                                                                         |                                                                 |       
|Net increase (decrease) in cash and cash equivalents                    |                                                                                         |                                                                 | (1,084
|Cash and cash equivalents at beginning of period                        |                                                                                         |                                                                 | 2,274 
|                                                                        |                                                                                         |                                                                 |       
|Cash and cash equivalents at end of period                              |                                                                                         |                                                                 | 1,190 
|Cash and cash equivalents classified as part of discontinued operations |                                                                                         |                                                                 | (1    
|                                                                        |                                                                                         |                                                                 |       
|Cash and cash equivalents of continuing operations                      |                                                                                         | $                                                               | 1,189 
|                                                                        |                                                                                         |                                                                 |       

---

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

98

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MISSION ENERGY HOLDING COMPANY AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Note 1. General

Organization

Mission Energy Holding Company (MEHC) 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. Through MEHC's ownership of Edison Mission Energy (EME) and its subsidiaries, MEHC
is engaged in the business of developing, acquiring, owning or leasing, operating and selling energy and capacity from independent power production facilities. Through EME, MEHC also conducts price
risk management and energy trading activities in power markets open to competition.

Note 2. Summary of Significant Accounting Policies

Basis of Consolidation

The consolidated financial statements include the accounts of MEHC 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

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 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.

Management's Use of Estimates

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

99

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Cash Equivalents

Cash equivalents include time deposits and other investments totaling $1.2 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 $436 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 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 yearsLeasehold improvements

Life of leaseEmission allowances

25-34.5 yearsEquipment, furniture and fixtures

3-7 yearsCapitalized leased equipment

5 years


100

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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

$
410

$
451

$
462Interest capitalized








(7
)$
410

$
451

$
455


Income Taxes

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

MEHC
accounts for deferred income taxes using the asset-and-liability method, wherein deferred tax assets and liabilities are recognized for future tax
consequences of temporary differences between the carrying amounts and the tax bases of assets and liabilities using enacted 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.

101

---



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 $33 million in 2005 and $47 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 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,

102

---



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 (loss), as all options granted
under those plans had an exercise price equal to the market value of the underlying common stock on the date of grant. The following table illustrates the effect on net income (loss) if EME had used
the fair value accounting method.

Years Ended December 31,2005

2004

2003(in millions)Net income (loss), as reported

$
350

$
24

$
(79
)Add: Stock-based compensation expense included in reported net income, net of related tax effects


13


14


6Deduct: Total stock-based employee compensation expense determined under fair value based method, net of related tax effects


(10
)

(12
)

(6
)Pro forma net income (loss)

$
353

$
26

$
(79
)


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.

103

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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

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.

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.

104

---



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

$
4Cumulative effect of accounting change


2





Accretion expense








1Ending 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

$
65Spare parts, materials and supplies


43


42Total

$
120

$
107


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.

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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 $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) |    
|---------------------------- | --------------- | -------------------------------- | --- | --------------------------------------------- | - | ------------------------------------ | ---- | --------------------------------------------- | ---
|
|Balance at December 31, 2003 |                 | $                                | 145 |                                               | $ | (159                                 | )    | $                                             | (11
|                             | Change for 2004 |                                  |     | (145                                          | ) |                                      | 177  |                                               |    
|                             |                 |                                  |     |                                               |   |                                      |      |                                               |    
|Balance at December 31, 2004 |                 |                                  |    |                                               |   | 18                                   |      |                                               | (1 
|                             | Change for 2005 |                                  |     |                                              |   |                                      | (228 | )                                             |    
|                             |                 |                                  |     |                                               |   |                                      |      |                                               |    
|Balance at December 31, 2005 |                 | $                                |    |                                               | $ | (210                                 | )    | $                                             | (1 
|                             |                 |                                  |     |                                               |   |                                      |      |                                               |    

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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.

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

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.

107

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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). 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.

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.

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

108

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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

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.

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.

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

109

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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 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

$
1,403Income (loss) before income taxes and minority interest


(20
)

256


252Provision (benefit) for income taxes


(44
)

48


90Minority interest





51


38Income from operations of discontinued foreign subsidiaries


24


157


124Gain 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 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

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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 AffiliatesEquity investment

$
365

$
428Loan receivable


26


26Total

$
391

$
454


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.

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

Three Months Ended
March 31, 2004(in millions)Revenues

$
62Expenses


66Net income

$
(4
)March 31, 2004Current assets

$
66Noncurrent assets


419Total assets

$
485Current liabilities

$
105Noncurrent liabilities


497Equity


(117
)Total liabilities and equity

$
485


111

---



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

Years Ended December 31,2005

2004

2003(in millions)Revenues

$
1,830

$
1,617

$
1,988Expenses


1,452


1,192


1,529Income before accounting change


378


425


459Cumulative effect of change in accounting, net of tax








(7
)Net income

$
378

$
425

$
452


December 31,2005

2004(in millions)Current assets

$
665

$
624Noncurrent assets


1,145


1,224Total assets

$
1,810

$
1,848Current liabilities

$
439

$
347Noncurrent liabilities


644


674Equity


727


827Total 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
MEHC's income before tax or in which MEHC has an investment balance greater than $50 million.

|Unconsolidated
Affiliates |  | Location        |  | Investment at
December 31,
2005 |     | EME's Ownership
Interest at
December 31, 2005 |     | Operating Status
|------------------------- |  | --------------- |  | ------------------------------- | --- | --------------------------------------------- | --- | ----------------
|
|Sunrise                   |  | Fellows, CA     |  | $                               | 107 |                                               | 50% |                 
|Watson                    |  | Carson, CA      |  |                                 | 85  |                                               | 49% |                 
|Midway-Sunset             |  | Fellows, CA     |  |                                 | 53  |                                               | 50% |                 
|Sycamore                  |  | Bakersfield, CA |  |                                 | 50  |                                               | 50% |                 
|Kern River                |  | Bakersfield, CA |  |                                 | 37  |                                               | 50% |                 

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

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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.

Note 10. Property, Plant and Equipment

Property, plant and equipment consist of the following:

December 31,2005

2004(in millions)Power plant facilities

$
2,131

$
1,966Leasehold improvements


90


80Emission allowances


1,305


1,305Construction in progress


34


33Equipment, furniture and fixtures


92


108Capitalized leased equipment


1


13,653


3,493Less accumulated depreciation and amortization


798


709Net property, plant and equipment

$
2,855

$
2,784


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.

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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. MEHC used the common stock of EME as security for MEHC's senior secured notes. MEHC senior secured notes are non-recourse to Edison International and EME and its
subsidiaries and, accordingly, none of Edison International, EME or EME's subsidiaries has any obligation under the senior secured notes. The senior secured notes contain restrictions on MEHC's
ability to pay dividends unless it has an interest coverage ratio of at least 2.0 to 1.0 as defined in the indenture. At December 31, 2005, its interest coverage ratio was 2.79 to 1.0. At
December 31, 2005, recourse debt to EME totaled $1.7 billion and non-recourse project debt totaled $1.7 billion. At December 31, 2005, EME had no 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)Corporate debt (with recourse to MEHC)MEHC (parent only)Senior Secured Notes, net due 2008 (13.5%)

$
792

$
789Term Loan due 2006(LIBOR+7.5%) (9.52% at 12/31/04)





282RecourseEME (parent only)Senior Notes, netdue 2008 (10.0%)

$
400

$
400due 2009 (7.73%)


598


598due 2011 (9.875%)


600


600Long-Term ObligationsAffiliate


78


78Junior Subordinated Debentures





155Non-recourseDue to EME Funding Corp.Long-Term Obligation due 2005-2008
(7.33%)


92


139EME CP Holdings Co.Note Purchase Agreement due 2015 (7.31%)


79


81Midwest Generation, LLCSecond Priority Senior Secured Notes due 2034 (8.75%)


1,000


1,000Credit 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


3


Subtotal

$
4,145

$
4,789Less current maturities of long-term obligations


50


496Total

$
4,095

$
4,293


114

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MEHC Term Loan

On January 3, 2005, MEHC completed the repayment of the remaining $285 million of principal, plus interest, due under the $385 million term
loan due in 2006 at 104% of par as permitted under the credit agreement. In connection with the repayment, MEHC recorded a $20 million loss on early extinguishment of debt during the first
quarter of 2005.

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.

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).

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.

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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$50 million; 2007$129 million; 2008$1,216 million; 2009$610 million; and 2010$11 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.

Restricted Cash

Several cash balances are restricted primarily to pay amounts required for debt payments and letter of credit expenses. The total restricted cash included in
MEHC's consolidated balance sheet was $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.

MEHC
is organized as a legal entity separate and apart from EME and its other subsidiaries. Assets of EME and its subsidiaries may not be available to satisfy MEHC's obligations.

116

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Fair Values of Non-Derivative Financial Instruments

The carrying amount of cash and cash equivalents, trade accounts receivables and payables contained in MEHC'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, 2004Carrying
Amount

Fair Value

Carrying
Amount

Fair ValueInstrumentsNon-derivatives:Long-term obligations

$
4,145

$
4,670

$
4,789

$
5,487


In assessing the fair value of MEHC's financial instruments, MEHC uses a variety of methods and assumptions that are based on market conditions
and 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, 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

117

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interest
rate swaps, interest rate options or other hedging mechanisms for a number of EME's project financings.

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'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.

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
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 70%, 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.

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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 36% in 2004 and 40% in 2003 of EME's consolidated operating revenues.

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.

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, 2004Carrying
Amount

Fair Value

Carrying
Amount

Fair ValueCommodity 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.

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, 2004Assets

Liabilities

Assets

LiabilitiesElectricity

$
127

$
27

$
125

$
36Other


1








Total

$
128

$
27

$
125

$
36


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.

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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.

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:CurrentFederal

$
186

$
(364
)
$
(112
)State


30


(77
)

(49
)Foreign


(1
)

(1
)

6Total current


215


(442
)

(155
)DeferredFederal

$
(36
)
$
(13
)
$
(24
)State


(10
)

(8
)

2Foreign








2Total deferred


(46
)

(21
)

(20
)Provision (benefit) for income taxes from continuing operations


169


(463
)

(175
)Discontinued operations


(40
)

47


91Change in accounting


(1
)




(4
)Total

$
128

$
(416
)
$
(88
)


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 OperationsU.S.

$
483

$
(1,134
)
$
(379
)Foreign


8


6


12Total, continuing operations


491


(1,128
)

(367
)Discontinued operations


(11
)

788


252Change in accounting


(2
)




(13
)Total

$
478

$
(340
)
$
(128
)


120

---



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

|                                                               |                                                | Years Ended December 31, |    
|-------------------------------------------------------------- | ---------------------------------------------- | ------------------------ | ---
|
|
|Expected provision for federal income taxes                    |                                                | $                        | 172
|Increase (decrease) in the provision for taxes resulting from: |                                                |                          |    
|                                                               | State taxnet of federal deduction             |                          |    
|                                                               | Dividends received deduction                   |                          |    
|                                                               | Taxes on foreign operations at different rates |                          |    
|                                                               | Resolution of IRS audit issue                  |                          |    
|                                                               | Other                                          |                          |    
|                                                               |                                                |                          |    
|                                                               | Provision (benefit) for income taxes           |                          | $  
|                                                               |                                                |                          |    
|                                                               | Effective tax rate                             |                          |    
|                                                               |                                                |                          |    

The components of the net accumulated deferred income tax liability are:

December 31,2005

2004(in millions)Deferred tax assetsAccrued charges

$
126

$
67Price risk management


162


(12
)Deferred income


5


3Other





1Total


293


59Deferred tax liabilitiesBasis differences

$
297

$
246Tax credits, net


11


12State taxes


5


5Other


1


Total


314


263Deferred taxes and tax credits, net

$
21

$
204Classification of accumulated deferred income taxes:Included in current assets

$
155

$
Included in non-current liabilities

$
176

$
204


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.

MEHC
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 MEHC's opinion, it is unlikely
that the resolution of any such matters will have a material adverse effect upon MEHC's financial condition or results of operations.

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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 obligationProjected benefit obligation at beginning of year

$
153

$
119Service cost


16


16Interest cost


8


7Actuarial (gain) loss


(10
)

11Benefits paid


(8
)

Projected benefit obligation at end of year

$
159

$
153Accumulated benefit obligation at end of year

$
137

$
123Change in plan assetsFair value of plan assets at beginning of year

$
77

$
53Actual return on plan assets


9


7Employer contributions


13


17Benefits paid


(8
)

Fair value of plan assets at end of year

$
91

$
77Funded status

$
(68
)
$
(76
)Unrecognized net loss


14


29Unrecognized prior service cost


1


2Recorded liability

$
(53
)
$
(45
)


122

---



Additional detail of amounts recognized in balance sheets:Intangible asset

$
1

$
1Accumulated other comprehensive income


(5
)

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

$
159

$
99Accumulated benefit obligation


137


72Fair value of plan assets


91


45Weighted-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

$
14Interest cost


8


7


6Expected return on plan assets


(6
)

(4
)

(4
)Net amortization and deferral


1


1


2Total expense recognized

$
19

$
20

$
18Change 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 20062005

2004United 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.

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---



On
December 8, 2003, President Bush signed the Medicare Prescription Drug, Improvement and Modernization Act of 2003. The Act authorized a federal subsidy to be provided to plan
sponsors for certain prescription drug benefits under Medicare. EME 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 obligationBenefit obligation at beginning of year

$
58

$
54Service cost


2


2Interest cost


4


3Amendments





1Actuarial loss (gain)


9


(1
)Benefits paid


(1
)

(1
)Benefit obligation at end of year

$
72

$
58Change in plan assetsFair value of plan assets at beginning of year

$


$
Employer contributions


1


1Benefits paid


(1
)

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

$


$
Funded status

$
(72
)
$
(58
)Unrecognized net loss


22


14Unrecognized 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


2010Weighted-average assumptions at end of year:Discount rate


5.50%


5.75%


124

---



Expense components of postretirement benefits are:

Years Ended December 31,2005

2004

2003(in millions)Service cost

$
2

$
2

$
2Interest cost


4


3


3Net amortization and deferral





(1
)

(1
)Total expense

$
6

$
4

$
4Assumed 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


2008Weighted-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:

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---



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.

126

---



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(1)(in millions)2006

$
5

$
12007


6


12008


7


22009


8


22010


9


22011-2015


70


16




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

2003Expected years until exercise

9-10

9-10

10Risk-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%


127

---



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 PriceOutstanding, December 31, 2002

2,181,812

$
9.10 - $28.94

$
18.60Granted

1,020,910

$
11.88 - $18.87

$
12.37Transferred from (to) affiliates

(32,351
)
$
9.57 - $28.94

$
17.70Forfeited

(315,788
)
$
9.57 - $28.94

$
23.09Exercised

(69,769
)
$
9.10 - $20.19

$
14.12Outstanding, December 31, 2003

2,784,814

$
9.10 - $28.94

$
15.95Granted

1,212,026

$
21.88 - $29.09

$
22.02Transferred from (to) affiliates

(69,924
)
$
12.29 - $28.13

$
15.85Forfeited

(104,975
)
$
9.57 - $23.14

$
18.16Exercised

(691,988
)
$
9.10 - $28.13

$
14.52Outstanding, December 31, 2004

3,129,953

$
9.15 - $29.09

$
18.44Granted

693,578

$
31.94 - $40.52

$
31.99Transferred from (to) affiliates

790,394

$
12.29 - $46.47

$
21.56Forfeited

(172,595
)
$
12.29 - $31.94

$
19.58Exercised

(814,965
)
$
9.15 - $31.94

$
16.81Outstanding, 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
|----- | -------------- | ----------- | --------- | -----------
|
|      | $9.57 -$13.99  |             | 751,790   |            
|      | $14.00 -$20.99 |             | 626,597   |            
|      | $21.00 -$31.49 |             | 1,451,454 |            
|      | $31.50 -$46.47 |             | 796,524   |            
|      |                |             |           |            
|Total |                | 3,626,365   |           | 7.15       
|      |                |             |           |            

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

128

---



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 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

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. Based on the
committed coal volumes in the fuel supply contracts described above, these minimum commitments are currently estimated to aggregate $680 million in the next five years,

129

---



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

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

130

---



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.

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

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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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 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

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.

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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.

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 (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 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.

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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

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 state implementation plans are

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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.

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 (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

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 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.

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

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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 8-hour ozone, and by

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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

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 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 2019.

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Future
minimum payments for operating leases at December 31, 2005 are:

Years Ending December 31,

Operating
Leases(in millions)2006

$
3622007


3602008


3572009


3532010


340Thereafter


2,983Total future commitments

$
4,755


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 MEHC. Costs are allocated based on one
of the following formulas: percentage of time worked, equity in investment and advances, number of employees, or multi-factor (operating revenues, operating expenses, total assets and number of
employees). In addition, services of Edison International or Southern California Edison employees are sometimes directly requested by MEHC and these services are performed for MEHC's benefit. Labor
and expenses of these directly requested services are specifically identified and billed at cost. EME believes the allocation methodologies utilized are reasonable. MEHC 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

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December 31,
2005 and 2004, the amount due to Edison International was $7 million and $26 million, respectively.

MEHC
participates in the insurance program of Edison International, including property, general liability, workers compensation and various other specialty policies. MEHC's insurance
premiums are generally based on MEHC's share of risk related to each policy. In connection with the property insurance program, a portion of the risk is reinsured by a captive insurance subsidiary of
Edison International.

MEHC
records accruals for tax liabilities and/or tax benefits which are settled quarterly according to a series of tax-allocation agreements as described in Note 2.
Under these agreements, MEHC recognized tax liabilities (benefits) applicable to continuing operations of $216 million, $(441) million and $(161) 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 $89 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.

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.

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Note 19. Supplemental Statements of Cash Flows Information

Years Ended December 31,2005

2004

2003(in millions)Cash paidInterest (net of amount capitalized)

$
422

$
452

$
427Income taxes (receipts)


61


(16
)

(163
)Cash payments under plant operating leases


293


240


271Details of assets acquiredFair value of assets acquired

$
154

$


$
3Liabilities assumed








Net cash paid for acquisitions

$
154

$


$
3Non-cash activities from consolidation of variable interest entityAssets

$
37

$


$
Liabilities


27





Non-cash activities from de-consolidation of variable interest entitiesAssets

$


$
220

$
Liabilities





254





During the year ended December 31, 2005, MEHC 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 |  
|---------------------------------------- |  | ----- | --- | ------ | - | -------- | ----- | ------ | --- | ----- | -
|
|Operating revenues                       |  | $     | 511 |        | $ | 417      |       | $      | 677 |       | $
|Operating income                         |  |       | 124 |        |   | 17       |       |        | 278 |       |  
|Income (loss) from continuing operations |  |       | 25  |        |   |         |       |        | 154 | (ii)  |  
|Discontinued operations, net (iii)       |  |       | 7   |        |   | 21       |       |        | 27  |       |  
|Income (loss) before accounting change   |  |       | 32  |        |   | 21       |       |        | 181 |       |  
|Net income (loss)                        |  |       | 32  |        |   | 21       |       |        | 181 |       |  
|                                         |  |       |     |        |   |          |       |        |     |       |  
|
|Operating revenues                       |  | $     | 389 |        | $ | 359      |       | $      | 509 |       | $
|Operating income (loss)                  |  |       | (16 | )      |   | (976     | )(iv) |        | 95  | (v)   |  
|Income (loss) from continuing operations |  |       | (39 | )      |   | (636     | )(iv) |        | 61  | (v)   |  
|Discontinued operations, net (iii)       |  |       | 46  |        |   | 26       |       |        | 498 | (vii) |  
|Net income (loss)                        |  |       | 7   |        |   | (610     | )     |        | 559 |       |  

---

143

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144

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PART III

ITEM 10.    DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANT

Information concerning executive officers of Mission Energy Holding Company is set forth in Part I in accordance with General Instruction G(3), pursuant to
Instruction 3 to Item 401(b) of Regulation S-K. Other information responding to Item 10 is set forth below.

Directors

Name and Age

Director
Continuously
Since

Term
ExpiresJohn E. Bryson, 62

2001

2006Frank B. Bilotta, 45

2001

2006Jacob A. Bouknight, Jr., 61

2005

2006Thomas R. McDaniel, 56

2005

2006


Business Experience

Below is a description of the principal business experience during the past five years of each of the directors named above and the name of each public company in
which each is a director.

Mr. Brysonhas been director and chairman of the board of Mission Energy Holding Company since June 2001. Since
January 2003, Mr. Bryson has been chairman of the board, president and chief executive officer of Edison International and chairman of the board of Southern California Edison Company.
From January 2000 through December 2002, Mr. Bryson was chairman of the board, president and chief executive officer of Edison International (only). Mr. Bryson was director
and chairman of the board of Edison Mission Energy from January 2000 through December 2002. Mr. Bryson has been a director of Edison International since 1990. Mr. Bryson
was a director of Southern California Edison Company from 1990 through 1999 and from January 2003 to date. Mr. Bryson is a director of The Boeing Company and The Walt Disney Company, and
a director/trustee for three funds in the Western Asset funds complex.

Mr. Bilottahas been director of Mission Energy Holding Company since June 2001 and serves as Mission Energy Holding
Company's independent director. Mr. Bilotta has over 20 years of diversified accounting and legal experience with an emphasis in asset-backed securities. Prior to joining Global
Securitization Services in September of 2000, Mr. Bilotta served as senior vice president at Lord Securities Corporation. He also served as an independent director on a variety of structured
finance vehicles.

Mr. Bouknighthas been director of Mission Energy Holding Company 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 and Johnson
since 1994.

Refer
to "Executive Officers of the Registrant" set forth in Part I for Mr. McDaniel's business experience.

145

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Audit Committee Financial Expert

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

Ethics and Compliance Code for Principal Officers

Mission Energy Holding Company has adopted a Ethics and Compliance Code that applies to its principal executive officer, principal financial officer, principal
accounting officer or controller, or persons performing similar functions. The Ethics and Compliance Code is posted on the Internet website maintained by Mission Energy Holding Company's parent,
Edison International, at www.edisonethics.com. Any amendment to or waiver from a provision of the Ethics and Compliance Code that must be disclosed under rules and forms of the Securities and Exchange
Commission will be disclosed at the same Internet website address within four business days following the date of the amendment or waiver.

ITEM 11.    EXECUTIVE COMPENSATION

MEHC officers receive compensation from EME or Edison International and receive no compensation from MEHC. For information concerning the chief executive officer
and four most highly paid executive officers, other than the chief executive officer, of EME and Edison International, see Item 11 of EME's Amendment to Form 10-K for the
year ended December 31, 2005 and the Summary Compensation Table in the Executive Compensation section of Edison International's definitive proxy statement relating to its 2006 Annual Meeting of
Shareholders, respectively, which will be incorporated herein by reference when filed. EME's Amendment to Form 10-K for the year ended December 31, 2005 will be filed with
the Securities and Exchange Commission concurrently with Edison International's filing of its definitive proxy statement.

Compensation of Directors

MEHC's directors do not receive any compensation for serving on its board of directors or attending meetings. Global Securitization Services, LLC received an
annual fee of $3,500 for the independent directorship services rendered by their employee, Frank B. Bilotta.

ITEM 12.    SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT

Certain Beneficial Owners

Set forth below is certain information regarding each person who is known to MEHC to be the beneficial owner of more than five percent of MEHC's common stock.

|Title of Class                          |  | Name and Address
of Beneficial Owner                                          |  | Amount and Nature of
Beneficial Ownership                                 |  | Percent of Class
|--------------------------------------- |  | ----------------------------------------------------------------------------- |  | ------------------------------------------------------------------------- |  | ----------------
|Common Stock, $0.01 per share par value |  | Edison Mission Group Inc.
2244 Walnut Grove Avenue
Rosemead, California 91770 |  | 1,000 shares held directly and with exclusive voting and investment power |  | 100%            

146

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For information concerning the number of equity securities of Edison International beneficially owned by all directors and executive officers of
EME and Edison International, individually and as a group, see Item 12 of EME's Amendment to Form 10-K for the year ended December 31, 2005 and the table entitled
"Stock Ownership of Directors, Director Nominee, and Executive Officers" of Edison International's definitive proxy statement relating to its 2006 Annual Meeting of Shareholders, respectively, which
will be incorporated herein by reference when filed. EME's Amendment to Form 10-K for the year ended December 31, 2005 will be filed with the Securities and Exchange
Commission concurrently with Edison International's filing of its definitive proxy statement.

Equity Compensation Plans

Item 201(d) of Regulation S-K, "Securities Authorized For Issuance Under Equity Compensation Plans," is not applicable because MEHC has no
compensation plans under which equity securities of MEHC are authorized for issuance.

ITEM 13.    CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS

For information concerning transactions between MEHC and specified security holders, see "Item 7. 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 "Item 8. Financial Statements and Supplementary DataNotes to Consolidated Financial
StatementsNote 18. Related Party Transactions."

ITEM 14.    PRINCIPAL ACCOUNTING FEES AND SERVICES

INDEPENDENT ACCOUNTANT FEES

The following table sets forth the aggregate fees billed to MEHC (consolidated total including MEHC and its subsidiaries), for the fiscal years ended
December 31, 2005 and December 31, 2004, by PricewaterhouseCoopers LLP:

MEHC
and Subsidiaries
($000)2005

2004Audit Fees

$
2,986

$
4,611Audit Related Fees(1)


44


204Tax Fees(2)


926


2,123All Other Fees





Total

$
3,956

$
6,938


---

The Edison International Audit Committee reviews with management and pre-approves all audit services to be performed by the
independent accountants and all non-audit services that are not prohibited and that require pre-approval under the Securities Exchange Act. The Edison International Audit
Committee's pre-approval responsibilities may be delegated to one or more Edison International Audit Committee members, provided that such delegate(s) presents any pre-approval
decisions to the Edison International Audit Committee at its next meeting. The independent auditors must assure that all audit and non-audit services provided to MEHC and its subsidiaries
have been approved by the Edison International Audit Committee.

During
the fiscal year ended December 31, 2005, all services performed by the independent accountants were pre-approved by the Edison International Audit Committee,
regardless of whether the services required pre-approval under the Securities Exchange Act.

147

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PART IV

ITEM 15.    EXHIBITS AND FINANCIAL STATEMENT SCHEDULES



PageSchedule ICondensed Financial Information of Parent

155Schedule IIValuation and Qualifying Accounts

158




|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 Form 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         |  | Amended and Restated Certificate of Incorporation, as amended, of Mission Energy Holding Company, incorporated by reference to Exhibit 3.1 to Mission Energy Holding Company's Registration Statement on Form S-4 to the Securities and Exchange
Commission on August 29, 2001.                                     
|            |  |                                                                                                                                                                                                                                                                                                                     

148

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|3.2   |  | By-laws of Mission Energy Holding Company, incorporated by reference to Exhibit 3.2 to Mission Energy Holding Company's Registration Statement on Form S-4 to the Securities and Exchange Commission on August 29, 2001.                                                                                                                                                                                                                            
|----- |  | ----------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
|3.3   |  | Certificate of Incorporation of Edison Mission Energy dated August 14, 2001, incorporated by reference to Exhibit 3.1 to Edison Mission Energy's Form 8-K dated October 26, 2001.                                                                                                                                                                                                                                                                   
|3.3.1 |  | 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.                                                                                                                                                                                                                      
|3.4   |  | 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 July 2, 2001, by and between Mission Energy Holding Company and Wilmington Trust Company with respect to $800 million aggregate principal amount of 13.50% Senior Secured Notes due 2008, incorporated by reference to Exhibit 4.1
to Mission Energy Holding Company's Registration Statement on Form S-4 to the Securities and Exchange Commission on August 29, 2001.                                                      
|4.2   |  | Registration Rights Agreement, dated as of July 2, 2001, by and between Mission Energy Holding Company and Goldman, Sachs & Co., incorporated by reference to Exhibit 4.2 to Mission Energy Holding Company's Registration Statement on Form S-4 to
the Securities and Exchange Commission on August 29, 2001.                                                                                                                                      
|4.3   |  | Indenture Escrow and Security Agreement, dated as of July 2, 2001, by and among Mission Energy Holding Company, Wilmington Trust Company, as Trustee, and Wilmington Trust Company, as Indenture Escrow Agent, incorporated by reference to Exhibit 4.3 to
Mission Energy Holding Company's Registration Statement on Form S-4 to the Securities and Exchange Commission on August 29, 2001.                                                        
|4.4   |  | Loan Escrow and Security Agreement, dated as of July 2, 2001, by and among Mission Energy Holding Company, Goldman, Sachs & Co., as Collateral Agent, Goldman Sachs Credit Partners L.P., as Administrative Agent, and Wilmington Trust Company, as
Loan Escrow Agent, incorporated by reference to Exhibit 4.5 to Mission Energy Holding Company's Registration Statement on Form S-4 to the Securities and Exchange Commission on August 29, 2001.
|4.5   |  | Pledge and Security Agreement, dated as of July 2, 2001, by and among Mission Energy Holding Company, Goldman Sachs Credit Partners L.P., as Administrative Agent, and Wilmington Trust Company, as Trustee and Joint Collateral Agent, incorporated by
reference to Exhibit 4.6 to Mission Energy Holding Company's Registration Statement on Form S-4 to the Securities and Exchange Commission on August 29, 2001.                               
|4.6   |  | 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.                                                                                                                                                                       
|4.6.1 |  | Form of 10% Senior Note due 2008 (included in Exhibit 4.1 to Edison Mission Energy's Registration Statement on Form S-4 to the Securities and Exchange Commission on August 29, 2001).                                                                                                                                                                                                                                                              
|      |  |                                                                                                                                                                                                                                                                                                                                                                                                                                                     

149

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|4.7    |  | 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.
|------ |  | -------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
|4.8    |  | 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.                                                                                                                                              
|4.8.1  |  | Form of 9.875% Senior Note due 2011 (included in Exhibit 4.2 to Edison Mission Energy's Registration Statement on Form S-4 to the Securities and Exchange Commission on April 24, 2001).                                                                                                                                                                                                                                                                                 
|4.9    |  | 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.                                                                 
|4.10   |  | 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.                                                                                                                                      
|4.10.1 |  | Schedule identifying substantially identical agreement to Guarantee constituting Exhibit 4.10 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.                                                                                                                                                                 
|4.11   |  | Guarantee, dated as of August 17, 2000, made by Edison Mission Energy, as Guarantor in favor of Joliet Trust I, as Owner Lessor, incorporated by reference to Exhibit 4.10 to Edison Mission Energy's and Midwest Generation LLC's Registration Statement
on Form S-4 to the Securities and Exchange Commission on April 20, 2001.                                                                                                                                       
|4.11.1 |  | Schedule identifying substantially identical agreement to Guarantee constituting Exhibit 4.11 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.                                                                                                                                                                
|4.12   |  | 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.                                    
|       |  |                                                                                                                                                                                                                                                                                                                                                                                                                                                                          

150

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|4.13   |  | 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.
|------ |  | ---------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
|4.13.1 |  | Schedule identifying substantially identical agreement to Participation Agreement constituting Exhibit 4.13 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.                                                                                                                                                                                                                                                                                                    
|4.14   |  | 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.     
|4.14.1 |  | Schedule identifying substantially identical agreement to Participation Agreement constituting Exhibit 4.14 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.                                                                                                                                                                                                                                                                                                    
|4.15   |  | 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.                                                                                                                                                                                                                                                                                                                                           
|4.15.1 |  | 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.                                                                                                                                                                                                                                                                                
|4.16   |  | Registration Rights Agreement, dated as of June 23, 1999, between Edison Mission Energy and the Initial Purchasers specified therein, incorporated by reference to Exhibit 10.1 to Edison Mission Energy's Registration Statement on Form S-4 to the
Securities and Exchange Commission on February 18, 2000.                                                                                                                                                                                                                                                                                                              
|4.17   |  | 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.                                                                                                                                                                                                                                                                                                                                                                             
|4.17.1 |  | Schedule identifying substantially identical agreements to Promissory Note constituting Exhibit 4.17 hereto, incorporated by reference to Exhibit 4.5.1 to Edison Mission Energy's Form 10-K for the year ended December 31, 2000.                                                                                                                                                                                                                                                                                                                                                                                         
|       |  |                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                            

151

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|4.18   |  | 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.
|------ |  | ------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
|4.18.1 |  | Schedule identifying substantially identical agreements to Participation Agreement constituting Exhibit 4.18 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.                                                                                                                                                                                                                                                                                           
|4.18.2 |  | Appendix A (Definitions) to the Participation Agreement constituting Exhibit 4.18 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.                                                                                                                                                                                                                                                                                                                      
|4.19   |  | 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.                                                                                                                                                                                                             
|4.19.1 |  | Schedule identifying substantially identical agreements to Open-End Mortgage, Security Agreement and Assignment of Rents constituting Exhibit 4.19 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.                                                                                                                                                                                                                                                     
|10.1   |  | Guarantee, dated August 1, 1998, between Edison Mission Energy, Pennsylvania Electric Company, NGE Generation, Inc. and New York State Electric & Gas Corporation, incorporated by reference to Exhibit 10.54 to Edison Mission Energy's
Form 10-K for the year ended December 31, 1998.                                                                                                                                                                                                                                                        
|10.2   |  | 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.                                                                                                                                                                   
|10.3   |  | 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.                                                                                                                                                                                                                                            
|10.4   |  | Intercompany Loan Subordination Agreement, dated March 18, 1999, among Edison Mission Holdings Co., Edison Mission Finance Co., Homer City Property Holdings, Inc., Chestnut Ridge Energy Co., Mission Energy Westside, Inc., EME Homer City Generation
L.P. and United States Trust Company of New York, incorporated by reference to Exhibit 10.60.3 to Amendment No. 2 of Edison Mission Holdings Co.'s Registration Statement on Form S-4 to the Securities and Exchange Commission on February 29,
2000.                                   
|       |  |                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                 

152

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|10.5   |  | 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.                             
|------ |  | ------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
|10.6   |  | 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.                                                                                                                                                         
|10.7   |  | 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.      
|10.7.1 |  | Amendment One to Credit Agreement (amending the Credit Agreement listed as Exhibit 10.7 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.
|10.7.2 |  | Amendment Two to Credit Agreement (amending the Credit Agreement listed as Exhibit 10.7 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.                                                   
|10.8   |  | 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.                                                                                                                                  
|10.9   |  | Tax Allocation Agreement, dated July 2, 2001, by and between Mission Energy Holding Company and Edison Mission Energy, incorporated by reference to Exhibit 10.106 to Edison Mission Energy's Form 10-Q for the quarter ended September 30,
2002.                                                                                                                                               
|10.10  |  | Administrative Agreement Re Tax-Allocation Payments, dated July 2, 2002, among Edison International and subsidiary parties, incorporated by reference to Exhibit 10.107 to Edison Mission Energy's Form 10-Q for the quarter ended September 30,
2002.                                                                                                                                          
|18.1   |  | Preferability Letter Regarding Change in Accounting Principle for Major Maintenance Costs, incorporated by reference to Exhibit 18.1 to Edison Mission Energy's Form 10-Q for the quarter ended March 31, 2000.                                                                                                                                                                                 
|21*    |  | List of Subsidiaries of Mission Energy Holding Company.                                                                                                                                                                                                                                                                                                                                         
|31.1*  |  | Certification of the Chief Executive Officer pursuant to Section 302 of the Sarbanes-Oxley Act.                                                                                                                                                                                                                                                                                                 
|31.2*  |  | Certification of the Chief Financial Officer pursuant to Section 302 of the Sarbanes-Oxley Act.                                                                                                                                                                                                                                                                                                 
|32*    |  | Statement Pursuant to 18 U.S.C. Section 1350.                                                                                                                                                                                                                                                                                                                                                   

---

153

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SIGNATURES

Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its
behalf by the undersigned, thereunto duly authorized.

| |  | MISSION ENERGY HOLDING COMPANY(REGISTRANT)
| |  | ------------------------------------------
| |  | By:                                       
| |  | Date:                                     

Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the
registrant and in the capacities and on the dates indicated.

|Signature                                          |  | Title                                                                         |  | Date         
|-------------------------------------------------- |  | ----------------------------------------------------------------------------- |  | -------------
|                                                   |  |                                                                               |  |              
|/s/ Thomas R. McDanielThomas R. McDaniel           |  | Director, President and Chief Executive Officer
(Principal Executive Officer) |  | March 6, 2006
|/s/ Mark C. ClarkeMark C. Clarke                   |  | Vice President and Controller
(Controller or Principal Accounting Officer)    |  | March 6, 2006
|/s/ John E. BrysonJohn E. Bryson                   |  | Director and Chairman of the Board                                            |  | March 6, 2006
|/s/ Jacob A. Bouknight, Jr.Jacob A. Bouknight, Jr. |  | Director                                                                      |  | March 6, 2006

154

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SCHEDULE I

MISSION ENERGY HOLDING COMPANY AND SUBSIDIARIES
CONDENSED FINANCIAL INFORMATION OF PARENT(1)
Condensed Balance Sheets
(In millions)

|                                                           |  | December 31,
|---------------------------------------------------------- |  | ------------
|
|Assets                                                     |  |             
|Cash and cash equivalents                                  |  | $           
|Affiliate receivables                                      |  |             
|                                                           |  |             
|Total current assets                                       |  |             
|Investments in subsidiaries                                |  |             
|Investment in discontinued operations                      |  |             
|Other long-term assets                                     |  |             
|                                                           |  |             
|Total Assets                                               |  | $           
|                                                           |  |             
|Liabilities and Shareholder's Equity                       |  |             
|Accounts payable and accrued liabilities                   |  | $           
|Liabilities under price risk management and energy trading |  |             
|Current portion of long-term obligations                   |  |             
|                                                           |  |             
|Total current liabilities                                  |  |             
|Long-term obligations                                      |  |             
|Deferred taxes and other                                   |  |             
|                                                           |  |             
|Total Liabilities                                          |  |             
|Common Shareholder's Equity                                |  |             
|                                                           |  |             
|Total Liabilities and Shareholder's Equity                 |  | $           
|                                                           |  |             

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155

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SCHEDULE I

MISSION ENERGY HOLDING COMPANY AND SUBSIDIARIES
CONDENSED FINANCIAL INFORMATION OF PARENT(1)
Condensed Statements of Income (Loss)
(In millions)

|                                                                   |  | Years Ended December 31, |     
|------------------------------------------------------------------ |  | ------------------------ | ----
|
|Operating expenses                                                 |  | $                        |    
|                                                                   |  |                          |     
|Operating loss                                                     |  |                          |    
|Equity in income (loss) from continuing operations of subsidiaries |  |                          | 402 
|Equity in income from discontinued operations of subsidiaries      |  |                          | 29  
|Interest expense and other                                         |  |                          | (133
|                                                                   |  |                          |     
|Income (loss) before income taxes                                  |  |                          | 298 
|Benefit for income taxes                                           |  |                          | (52 
|                                                                   |  |                          |     
|Net income (loss)                                                  |  | $                        | 350 
|                                                                   |  |                          |     

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156

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SCHEDULE I

MISSION ENERGY HOLDING COMPANY AND SUBSIDIARIES
CONDENSED FINANCIAL INFORMATION OF PARENT(1)
Condensed Statements of Cash Flows
(In millions)

|                                                     |                                           | Years Ended December 31,
|---------------------------------------------------- | ----------------------------------------- | ------------------------
|
|Net cash provided by (used in) operating activities  |                                           | $                       
|Net cash provided by (used in) financing activities  |                                           |                         
|Net cash provided by (used in) investing activities  |                                           |                         
|                                                     |                                           |                         
|Net increase (decrease) in cash and cash equivalents |                                           |                         
|Cash and cash equivalents at beginning of period     |                                           |                         
|                                                     |                                           |                         
|Cash and cash equivalents at end of period           |                                           | $                       
|                                                     |                                           |                         
|Other Cash Flow Data:                                |                                           |                         
|                                                     | Cash dividends received from subsidiaries |                         
|                                                     |                                           |                         

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157

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SCHEDULE II

MISSION ENERGY HOLDING COMPANY AND SUBSIDIARIES
VALUATION AND QUALIFYING ACCOUNTS
(In millions)

|                             |                                    |  |   | Additions |  |   |   | 
|---------------------------- | ---------------------------------- |  | - | --------- |  | - | - | 
|
|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       |  | $ |  | 

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158

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