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, 2004

Commission File Number 333-68632

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

|Delaware(State or other jurisdiction of incorporation or organization)                      |  | 95-4867576(I.R.S. Employer Identification No.)
|------------------------------------------------------------------------------------------- |  | ----------------------------------------------
|2600 Michelson Drive, Suite 1700
Irvine, California(Address of principal executive offices) |  | 92612(Zip Code)                               
|Registrant's telephone number, including area code:(949) 852-3576                          

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

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

Indicate by check mark whether the registrant is an accelerated filer (as defined in Rule 12b-2 of the 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, 2004: $0. Number of shares
outstanding of the registrant's Common Stock as of March 10, 2005: 1,000 shares (all shares held by an affiliate of the registrant).

DOCUMENTS INCORPORATED BY REFERENCE

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

|(1) |  | Designated portions of Edison Mission Energy's Form 10-K for the year ended December 31, 2004                           |  | Part III
|--- |  | ----------------------------------------------------------------------------------------------------------------------- |  | --------
|(2) |  | Designated portions of the Joint Proxy Statement relating to Edison International's 2005 Annual Meeting of Shareholders |  | Part III



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TABLE OF CONTENTS

|         |  |                                                                                       |  | Page
|-------- |  | ------------------------------------------------------------------------------------- |  | ----
|         |  | PART I                                                                                |  |     
|Item 1.  |  | Business                                                                              |  | 1   
|Item 2.  |  | Properties                                                                            |  | 22  
|Item 3.  |  | Legal Proceedings                                                                     |  | 22  
|Item 4.  |  | Submission of Matters to a Vote of Security Holders                                   |  | 23  
|         |  | PART II                                                                               |  |     
|Item 5.  |  | Market for Registrant's Common Equity and Related Stockholder Matters                 |  | 24  
|Item 6.  |  | Selected Financial Data                                                               |  | 25  
|Item 7.  |  | Management's Discussion and Analysis of Financial Condition and Results of Operations |  | 27  
|Item 7a. |  | Quantitative and Qualitative Disclosures about Market Risk                            |  | 99  
|Item 8.  |  | Financial Statements and Supplementary Data                                           |  | 99  
|Item 9.  |  | Changes in and Disagreements with Accountants on Accounting and Financial Disclosure  |  | 99  
|Item 9A. |  | Controls and Procedures                                                               |  | 99  
|Item 9B. |  | Other Information                                                                     |  | 99  
|         |  | PART III                                                                              |  |     
|Item 10. |  | Directors and Executive Officers of the Registrant                                    |  | 158 
|Item 11. |  | Executive Compensation                                                                |  | 160 
|Item 12. |  | Security Ownership of Certain Beneficial Owners and Management                        |  | 160 
|Item 13. |  | Certain Relationships and Related Transactions                                        |  | 160 
|Item 14. |  | Principal Accounting Fees and Services                                                |  | 161 
|         |  | PART IV                                                                               |  |     
|Item 15. |  | Exhibits and Financial Statement Schedules                                            |  | 162 
|         |  | Signatures                                                                            |  | 247 

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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 $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 Inc. contributed to MEHC all the outstanding common stock of EME. The contribution of EME's common stock to MEHC has
been accounted for as a transfer of ownership of companies under common control, which is similar to a pooling of interest. This means that MEHC's historical financial results of operations and
financial position will include the historical financial results and results of operations of EME and its subsidiaries as though MEHC had such ownership throughout the periods presented. MEHC's only
substantive liabilities are its obligations under the senior secured
notes 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.

During
2004 and early 2005, EME completed the sale of substantially all its international assets totaling 6,452 MW as part of the restructuring plan announced during the fourth quarter
of 2003 designed to reduce debt and improve liquidity. Highlights of these activities are described below.

See
"Item 7. Management's Discussion and Analysis of Financial Condition and Results of OperationsManagement's Overview, Risks Related to the Business and Critical
Accounting Estimates" for further details on EME's asset sales.

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

Mission
Energy Holding Company'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.

Forward-Looking Statements

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

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

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annual
report is subject to change without notice, and MEHC is not obligated to publicly update or revise forward-looking statements. Readers should review future reports filed by MEHC with the
Securities and Exchange Commission.

Description of 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. As a result, a significant market
for electric power produced by independent power producers, such as EME, developed in the United States.

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
systems 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 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."

EME's
largest power plants are located in Illinois and Pennsylvania and sell power into PJM Interconnection, LLC, commonly referred to as PJM. PJM is the largest centrally dispatched
electric control area in North America. As reported on the PJM website (www.pjm.com) on March 1, 2005, PJM consists of about 1,000 generating units with a total installed capacity of
approximately 137,490 MW, serves approximately 45.3 million people, and covers portions of Pennsylvania, New Jersey, Maryland, Delaware, the District of Columbia, Illinois, Indiana, Kentucky,
Michigan, Ohio, Tennessee, West Virginia and Virginia. PJM operates the 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) and EME Homer City Generation L.P.
(EME Homer City), may participate in PJM's capacity markets or transact capacity on a bilateral basis.

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Competition and Market Condition Generally

EME is subject to intense competition from energy marketers, utilities, industrial companies and other independent power producers. In prior years, the
restructuring of energy markets led to the sale of utility-owned assets to EME and its competitors. More recently, in response to market conditions, EME has changed its focus from acquisition and
growth to reducing debt and operating, maintaining, and maximizing the value of its current asset base. Accordingly, EME has engaged in asset sales, has canceled, deferred or sold new development
projects, and has taken a number of actions to decrease capital expenditures, including reductions in operating costs and decommissioning of operations at several power plants.

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.
EME's customers include large electric utilities or regional distribution companies. In some cases, the electric utilities and distribution companies have their own generation capacity, including
nuclear generation, that affects the amount of generation available to meet demand and may affect the price of electricity in a particular market.

The
proposed introduction of a new standard market design structure by the FERC in those regions not currently organized into centralized power markets and the continued expansion by
utilities of unbundled retail distribution services could lead to increased competition in the U.S. independent power market. See "Regulatory MattersRetail Competition."

Operating Segments

EME continues to operate in one line of business, electric power generation, with all of its continuing operations located in the United States, except the Doga
project in Turkey. Operating revenues are primarily related to the sale of power generated from the Illinois Plants and Homer City facilities. EME is headquartered in Irvine, California with
additional offices located in Chicago, Illinois and Boston, Massachusetts. As a result of the sale of EME's interest in Contact Energy Limited and most of the remainder of its portfolio of
international assets (which made up the reportable segments in Asia Pacific and Europe), EME does not meet the criteria for segment reporting.

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Overview of Domestic Facilities

As of December 31, 2004, EME's continuing operations consisted of ownership or leasehold interests in the following domestic operating power plants:

|Power Plants            |                               | Location          |               | Primary
Electric
Purchaser(2) |           | 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/NYISO |           | Coal         |                    | 100% |                               | 1,884 |                                      
|Contracted Power Plants |                               |                   |               |                               |           |           |              |                    |      |                               |       |                                      
|                        | 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   |                                      
|                        |                               |                   |               |                               |           |           |              |                    |      |                               |       |                                      
|                        |                               | Total             |               |                               |           |           |              |                    |      |                               |       | 9,914                                
|                        |                               |                   |               |                               |           |           |              |                    |      |                               |       |                                      

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CDWR

California Department of Water ResourcesPJM

PJM Interconnection, LLCMPC

Monongahela Power CompanyPG&E

Pacific Gas & Electric CompanyPJM/NYISO

PJM Interconnection, LLC/New York Independent System OperatorPSE

Puget Sound Energy, Inc.SCE

Southern California Edison Company


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.

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 Commonwealth Edison's fossil-fuel power plants located in Illinois, which are collectively referred to as the Illinois Plants in this annual report. These power
plants are located in the Mid-America Interconnected Network, which has transmission connections to the East Central Area Reliability Council and other regional markets.

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The
Illinois Plants include the following:

|Operating Plant or Site        |  | Location                |  | Leased/
Owned |  | Fuel    |  | Megawatts |    
|------------------------------ |  | ----------------------- |  | ------------- |  | ------- |  | --------- | ---
|Electric Generating Facilities |  |                         |  |               |  |         |  |           |    
|Crawford Station               |  | Chicago, Illinois       |  | owned         |  | coal    |  | 542       |    
|Fisk Station                   |  | Chicago, Illinois       |  | owned         |  | coal    |  | 326       |    
|Joliet Unit 6                  |  | Joliet, Illinois        |  | owned         |  | coal    |  | 290       |    
|Joliet Units 7 and 8           |  | Joliet, Illinois        |  | leased        |  | coal    |  | 1,044     |    
|Powerton Station               |  | Pekin, Illinois         |  | leased        |  | coal    |  | 1,538     |    
|Waukegan Station               |  | Waukegan, Illinois      |  | owned         |  | coal    |  | 789       |    
|Will County Station            |  | Romeoville, Illinois    |  | owned         |  | coal    |  | 1,092     | (1)
|Peaking Units                  |  |                         |  |               |  |         |  |           |    
|Fisk                           |  | Chicago, Illinois       |  | owned         |  | oil/gas |  | 163       |    
|Waukegan                       |  | Waukegan, Illinois      |  | owned         |  | oil/gas |  | 92        |    
|                               |  |                         |  |               |  |         |  |           |    
|                               |  |                         |  |               |  | Total   |  | 5,876     |    
|                               |  |                         |  |               |  |         |  |           |    
|Other Plant or Site            |  |                         |  |               |  |         |  |           |    
|Collins Station(2)             |  | Grundy County, Illinois |  |               |  |         |  |           |    
|Crawford peaker(3)             |  | Chicago, Illinois       |  |               |  |         |  |           |    
|Joliet peaker(3)               |  | Joliet, Illinois        |  |               |  |         |  |           |    
|Calumet peaker(3)              |  | Chicago, Illinois       |  |               |  |         |  |           |    
|Electric Junction peaker(3)    |  | Aurora, Illinois        |  |               |  |         |  |           |    
|Lombard peaker(3)              |  | Lombard, Illinois       |  |               |  |         |  |           |    
|Sabrooke peaker(3)             |  | 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. On September 30, 2004, Midwest Generation
permanently ceased operations of the Collins Station. 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. See "Termination of the Collins Station Lease" section in Item "7. Management's Discussion and Analysis of Financial Condition
and Results of OpeationsLiquidity and Capital Resources."

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 and entered into long-term leases of the facilities from these third parties to repay corporate debt while maintaining control of the use of the power plants during the terms of
the leases. See "Off-Balance Sheet Transactions" section in "Item 7.

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Management's
Discussion and Analysis of Financial Condition and Results of OperationsLiquidity and Capital Resources."

Illinois Power Markets

In connection with the acquisition of the Illinois Plants, Midwest Generation entered into three separate five-year power purchase agreements with
Commonwealth Edison, which were subsequently assigned to its affiliate, Exelon Generation Company LLC (Exelon Generation). The Collins Station power purchase agreement was terminated on
September 30, 2004 and the other two power purchase agreements expired on December 31, 2004. During each of 2000, 2001 and 2002, approximately 99% of Midwest Generation's energy and
capacity revenues were derived under the power purchase agreements. In 2003 and 2004, the percentage decreased to approximately 65% and 53%, respectively, with the balance coming from sales by Midwest
Generation into the wholesale power markets.

Beginning
in 2005, all the energy and capacity from the Illinois Plants are sold under terms, including price and quantity, negotiated by Edison Mission Marketing &
Trading, Inc., 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.
These arrangements generally have terms of two years or less. Thus, EME is subject to market risks related to the price of energy and capacity from the Illinois Plants. As discussed further below,
sales of electricity from the Illinois Plants now include sales into PJM. 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." Wholesale customer transactions are bilateral sales to regional buyers, including investor-owned utilities, municipal utilities,
rural electric cooperatives and retail energy suppliers. Wholesale customer transactions include real-time, daily and longer term structured sales; they are not arranged through brokers
and may be tailored to meet the specific requirements of wholesale electricity consumers. Over-the-counter markets are generally accessed through third-party brokers and
electronic exchanges, and include forward sales of electricity. The most liquid over-the-counter markets in the Midwest region have historically been sales into the control
area of Cinergy, referred to as "Into
Cinergy," and, to a lesser extent, sales into the control areas of Commonwealth Edison and American Electric Power, referred to as "Into ComEd" and "Into AEP," respectively. "Into ComEd" and "Into
AEP" were bilateral markets for the sale or purchase of electrical energy for future delivery. Due to geographic proximity, "Into ComEd" was the primary market for Midwest Generation.

On
May 1, 2004 and October 1, 2004, respectively, operational control of the control area systems of Commonwealth Edison and AEP was transferred to PJM, which is now the
primary market available to Midwest Generation. This transfer resulted in the conversion of the "Into ComEd" and "Into AEP" trading hubs to locational marginal pricing, which has further facilitated
transparency of prices and provided liquidity to support risk management strategies. Performance of transactions in these markets is subject to contracts that generally provide for liquidated damages
supported by a variety of credit requirements, which may include independent credit assessment, parent company guarantees, letters of credit and cash margining arrangements. However, liquidity in all
of these markets has been adversely affected by the financial problems of trading and marketing entities.

Following
the transfer of control of the control area systems of Commonwealth Edison and AEP to PJM, sales of electricity from the Illinois Plants now include bilateral and spot sales
into PJM, with spot

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sales
being based on locational marginal pricing. These sales into the expanded PJM replaced sales previously made as bilateral sales and spot sales "Into ComEd" and "Into AEP." The Northern Illinois
Hub is the primary trading hub for Midwest Generation produced power due to geographic proximity and high pricing correlation to the plants' output locations.

The
Midwest Independent Transmission System Operator, an RTO authorized pursuant to the FERC's Order No. 2000, commonly referred to as the MISO, which will control the former
control areas of Alliant Energy Corporation (Wisconsin Power and Light Co. and Interstate Power and Light Co.), Aquila, Inc., Ameren Corporation, Cinergy Corp., Kentucky Utilities Company, LG&E
Energy LLC, Vectren Corporation and Xcel Energy, Inc., among others, is scheduled to begin operation of its locational marginal pricing market on April 1, 2005. It is anticipated that
the opening of the MISO market will provide increased liquidity in the Midwest electricity markets. "Into Cinergy" will become a locational marginal pricing location in MISO at that time. See
"Regulatory Matters" for a more detailed discussion of recent developments regarding Commonwealth Edison and AEP joining PJM. See "Transmission" below for additional discussion.

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

Historically, sales of power produced by Midwest Generation required using transmission that had to be obtained from Commonwealth Edison. An ISO did not yet
oversee operations of the Commonwealth Edison control area; however, effective May 1, 2004 such operations were placed under the control of PJM. Furthermore, the transmission system of AEP was
integrated into PJM on October 1, 2004, which linked the Northern Illinois and eastern portions of the PJM system and permitted the Illinois Plants to be dispatched into the broader PJM market.
In addition, a number of other utilities in the region participate in the MISO where a bilateral market with a single rate for transmission within the RTO already exists. The regional market is
further supported by open access transmission under various utility company transmission tariffs that are not within the MISO. The open access transmission tariffs of the MISO and others in the region
allow Midwest Generation to utilize their transmission and distribution systems to sell power at wholesale on a non-discriminatory basis relative to the system's owners. Such tariffs are
vital to allow Midwest Generation to compete in the deregulated electricity markets because they provide a uniform set of prices and standards of transmission service that have been approved by
regulatory agencies and are publicly available.

On
November 18, 2004, the FERC issued an order eliminating regional through and out transmission rates in the region encompassed by PJM (as recently expanded) and the MISO. The
effect of this order was to eliminate so-called rate pancaking between PJM and the MISO. 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 the impact of such mechanism 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 such elimination. On November 30, 2004, the FERC clarified that SECAs can be
recovered for lost revenues associated with elimination on intra-RTO pancaking.

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The
response to the November 18 and November 30 orders from the parties liable for the SECAs has been strongly negative, and a rehearing has been 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 such order 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. In
its tariff filing, PJM imposes SECAs only on load-serving entities, and not on other transmission customers such as Midwest Generation, but the MISO tariff provision imposes SECAs on all
such customers. That provision does not directly affect Midwest Generation because it is not a transmission customer of the MISO; however,
the issue of which entities should bear SECAs is one of the many points that have been raised in the protests described above and have become the subject of hearings ordered by the FERC.

Pending
further orders of the FERC and/or the outcome of the hearings described above, 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 coal is purchased under a number of supply agreements ranging from one year to four years in length. 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, 2004, Midwest
Generation leased approximately 3,800 railcars to transport the coal from the mines to the generating stations and the leases have remaining terms that range from as short as 6 months up to
15 years, with options to extend the leases for or purchase some railcars at the end of the terms. The coal is transported nearly 1,200 miles from the mines to the stations.

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.

Approximately
255 MW of Midwest Generation's peaking capacity is 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.

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Emission Allowances

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 Illinois Plants. Additional allowances are purchased by Midwest Generation when
operations make this necessary and are sold by Midwest Generation when it has 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.

Homer City Facilities

On March 18, 1999, EME completed a transaction with GPU, Inc., New York State Electric & Gas Corporation and their respective affiliates to
acquire the 1,884 MW Homer City Electric Generating Station. These facilities consist of three coal-fired boilers and steam turbine-generator units (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. The Homer City generating units have direct, high voltage interconnections to both PJM and the New York Independent System Operator, which controls the transmission grid and energy and
capacity markets for New York State and is commonly known as the NYISO. The NYISO was established in 1999 to operate a competitive, non-discriminatory wholesale power market in response to
the FERC's Open Access Rules and includes bid-based electricity and transmission usage markets. The market-clearing price for NYISO's day-ahead and real-time energy
markets is set by supplier generation bids and customer demand bids. For a discussion of the market risks related to the
sale of electricity from the Homer City facilities, see "Item 7. Management's Discussion and Analysis of Financial Condition and Results of OperationsMarket Risk Exposures."

On
December 7, 2001, EME's subsidiary completed a sale-leaseback of the Homer City facilities to third-party lessors. EME sold the Homer City facilities to provide
capital to repay corporate debt and entered into long-term leases to continue to operate the facilities during the terms of the leases. See "Item 7. Management's Discussion and Analysis of
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 tons of mid-range sulfur coal per year. Approximately 90% to 95% of this coal is
obtained under contracts with suppliers within approximately 100 miles of the Homer City facilities and the remainder is purchased in the spot market. All of this coal is delivered to the site by
truck. The raw coal purchased for consumption by Units 1 and 2 is 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 from local suppliers under long-term contracts.
All coal purchased for Unit 3 is delivered to the site by truck. A wet scrubber flue gas desulfurization system for Unit 3 enables this

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unit
to be able to burn less expensive, higher sulfur coal, while still meeting environmental standards for emission control.

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 contracts.

Emission Allowances

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. Additional allowances are purchased by EME Homer City when
operations make this necessary and are sold by EME Homer City when it has 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 have similar economic characteristics and have been used, collectively, to obtain bond financing by Edison Mission Energy Funding Corp.,
a special purpose entity. See "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. Due to similar economic characteristics and the bond financing related to its equity investments, EME views these projects collectively and refers to
them as the Big 4 projects.

Kern River Cogeneration Plant

EME owns a 50% partnership interest in Kern River Cogeneration Company, which owns a 300 MW natural gas-fired cogeneration facility located near
Bakersfield, California, which EME refers to as the Kern River project. Kern River Cogeneration sells electricity to Southern California Edison Company under a power purchase agreement that expires in
August 2005 and sells steam to Texaco Exploration and Production Inc. (TEPI), a wholly owned subsidiary of ChevronTexaco Corporation, under a steam supply agreement that expires in
June 2005. As of December 31, 2004, the partnership was in negotiations to continue electricity and steam sales (to Southern California Edison and TEPI, respectively) beyond the
expiration of the current agreements. Although the partnership expects to reach agreements with both Southern California Edison and TEPI, the combined revenues of these arrangements are likely to be
substantially below those provided under the current agreements.

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

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

Sycamore Cogeneration Plant

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

Watson Cogeneration Plant

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

Other Power Plants

Sunrise Power Plant

EME owns a 50% interest in Sunrise Power Company, LLC, which owns a 572 MW natural gas-fired facility in Kern County, California, which EME refers to
as the Sunrise project. The Sunrise project was constructed in two phases. Phase 1 achieved commercial operation in June 2001 and consisted of a 320 MW simple-cycle peaking facility. Phase 2, a
combined-cycle gas-fired facility, converted the simple-cycle peaking facility to a 572 MW combined cycle plant. Phase 2 achieved commercial operation in June 2003. Sunrise Power
entered into a long-term power purchase agreement with the California Department of Water Resources in June 2001, which expires in 2012. For further discussion related to this
agreement, see "Item 3. Legal ProceedingsSunrise Power Company Lawsuits."

March Point Cogeneration Plant

EME owns a 50% partnership interest in March Point Cogeneration Company, which owns a 140 MW natural gas-fired cogeneration facility located in
Anacortes, Washington, which EME refers to as the March Point project. The March Point project consists of two phases. Phase 1 is an 80 MW gas turbine cogeneration facility and Phase 2 is a 60 MW gas
turbine combined cycle facility. March Point Cogeneration sells electricity to Puget Sound Energy, Inc. under a power purchase agreement that expires in 2011 and sells steam to Equilon
Enterprises, LLC under a steam supply agreement that also expires in 2011.

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

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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 is continuing to sell electricity to Pacific Gas & Electric under the "as available" rates and is selling steam to
TEPI under an extension of the expired steam sales agreement. As of December 31, 2004, negotiations were underway to secure new power purchase and steam sales agreements for this project.

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.

International Project

Doga Cogeneration Plant

EME owns an 80% interest in Doga Enerji, which owns a 180 MW gas-fired cogeneration plant near Istanbul, Turkey, which EME refers to as the Doga
project. Doga Enerji sells electricity to Türkiye Elektrik Dagitim Anonim Sirketi, commonly known as TEDAS, under a power purchase agreement that expires in 2019. See
"Item 7. Management's Discussion and Analysis of Financial Condition and Results of OperationsLiquidity and Capital ResourcesContractual Obligations, Commitments and
ContingenciesContingencies" for information regarding regulatory developments affecting the Doga project.

During
the third quarter of 2004, EME reclassified its international activities which were then under contracts for sale as discontinued operations. Subsequently, EME completed the sale
of these operations as described above, except for the Doga project, which is no longer under a contract for sale. While EME continues to seek to sell its ownership interest in this project, there is
no assurance that such efforts will result in a sale during the twelve-month period prescribed under Statement of Financial Accounting Standards No. 144, "Accounting for the Impairment or
Disposal of Long-Lived Assets." As a result, EME reclassified the Doga project to continuing operations during the fourth quarter of 2004, and, accordingly, it is reflected as part of
continuing operations for all periods presented.

Discontinued Operations

For a description of discontinued operations see "Mission Energy Holding Company and Subsidiaries Notes to Consolidated Financial
StatementsNote 7. Discontinued Operations."

Price Risk Management and Trading Activities

EME's power marketing and trading organization, Edison Mission Marketing & Trading, Inc., markets the energy and capacity of EME's merchant
generating fleet and, in connection with this activity, trades electric power and energy and related commodity and financial products, including forwards, futures, options and swaps. Almost all of
this trading activity is related either to realizing value from the sale of energy and capacity from EME's merchant plants or to risk management activities related to

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preserving
the value of this marketing activity. EME segregates its marketing and trading activities into two categories:

Edison
Mission Marketing & Trading is divided into front-, middle-, and back-office segments, with specified duties segregated for control purposes. Edison Mission
Marketing & Trading also has a wholesale power scheduling group that operates on a 24-hour basis.

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

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

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continuously
monitoring its credit exposure to its counterparties, EME also takes appropriate steps to limit or lower credit exposure. Despite this, there can be no assurance that EME's actions to
mitigate risk will be wholly successful or that collateral pledged will be adequate.

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

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 based on changes in the market price of the underlying contract under specific terms) or letters of credit or guarantees. To manage its liquidity, EME
assesses the potential impact of future price changes in determining the amount of collateral requirements under existing or anticipated forward contracts. There is no assurance that EME's liquidity
will be adequate to meet margin calls from counterparties in the case of extreme market changes or that the failure to meet such cash requirements would not have a material adverse effect on its
liquidity. See "Item 7. Management's Discussion and Analysis of Financial Condition and Results of OperationsManagement's Overview, Risks Related to the Business and Critical Accounting
EstimatesRisks Related to the Business."

Significant Customer

In the past three fiscal years, EME 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, which began on December 15, 1999. The Collins Station power purchase agreement was terminated on September 30, 2004 and the
other power purchase agreements expired on December 31, 2004. Exelon Generation accounted for approximately 36%, 40% and 66% of EME's consolidated operating revenues for the years ended
December 31, 2004, 2003 and 2002, 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. An investment grade affiliate of BP Energy has guaranteed payment of amounts due under the related contracts.

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.

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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.

Seasonality

EME's third quarter electric revenues are materially higher than revenues related to other quarters of the year. Due to higher electric demand resulting from
warmer weather during the summer months, electric revenues generated from the Homer City facilities and the Illinois Plants are generally higher during the third quarter of each year.

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 under the Federal Power
Act and with respect to certain interstate sales, transportation and storage of natural gas under the Natural Gas Act of 1938. The Securities and Exchange Commission has regulatory powers with respect
to upstream owners of electric and natural gas utilities under the Public Utility Holding Company Act of 1935, or PUHCA. The enactment of PURPA and the adoption of regulations under that Act by the
FERC provided incentives for the development of cogeneration facilities and small power production facilities using alternative or renewable fuels by establishing certain exemptions from the Federal
Power Act and PUHCA for the owners of qualifying

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facilities.
The passage of the Energy Policy Act in 1992 further encouraged independent power production by providing additional exemptions from PUHCA for exempt wholesale generators and foreign
utility companies.

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

An
"exempt wholesale generator" under PUHCA is an entity determined by the FERC to be exclusively engaged, directly or indirectly, in the
business of owning and/or operating specified eligible facilities and selling electric energy at wholesale or, if located in a foreign country, at wholesale or retail.

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

Federal Power Act

The Federal Power Act grants the FERC exclusive jurisdiction over the rates, terms and conditions of wholesale sales of electricity and transmission services in
interstate commerce, including ongoing, as well as initial, rate jurisdiction. This jurisdiction allows the 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. As noted,
most qualifying facilities are exempt from the ratemaking and several other provisions of the Federal Power Act. Exempt wholesale generators and other non-qualifying facility independent
power projects are subject to the Federal Power Act and to the 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 in some cases, jurisdiction over the issuance of securities or the assumption of specified liabilities and some
interlocking directorates. In granting authority to make sales at market-based rates, the FERC typically also grants blanket approval for the issuance of securities and partial waiver of the
restrictions on interlocking directorates.

As
of December 31, 2004, 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 Holding Company Act of 1935

Edison International, EME's ultimate parent company, is a holding company because it owns Southern California Edison, an electric utility company. However, Edison
International and its subsidiaries are exempt for all provisions, except Section 9(a)(2), of the Public Utility Holding Company

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Act
of 1935 (PUHCA) on the basis that Edison International and Southern California Edison are incorporated in the same state and their utility businesses are predominantly intrastate in character and
carried on substantially in their state of incorporation. Section 9(a)(2) provides, in substance, that Edison International may not directly or indirectly acquire 5% or more of the voting
securities of a public utility company other than Southern California Edison, unless the acquisition has been approved by the Securities and Exchange Commission. Consequently, EME is not a subsidiary
of a registered holding company so long as Edison International continues to be exempt from registration pursuant to Section 3(a)(1) or another of the exemptions enumerated in
Section 3(a).

EME
is not a holding company under PUHCA, because its interests in power generation facilities are exclusively in qualifying cogeneration facilities, facilities owned by exempt wholesale
generators and facilities owned by foreign utility companies. All projects that EME might develop or acquire will be non-qualifying facility independent power projects. Loss of exempt
wholesale generator, qualifying cogeneration facility or foreign utility company status for one or more projects could result in EME's becoming a holding company subject to registration and regulation
under PUHCA and could trigger defaults under the covenants in EME's project agreements. Becoming a holding company could, on a retroactive basis, lead to, among other things, fines and penalties and
could cause certain of EME's project agreements and other contracts to be voidable.

Public Utility Regulatory Policies Act of 1978

PURPA provides two primary benefits to qualifying facilities. First, ownership of qualifying cogeneration facilities will not cause a company to be deemed an
electric utility company for purposes of PUHCA. In addition, all cogeneration facilities that are qualifying facilities are exempt from most 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, and that the utilities sell back up power to the qualifying facility on a nondiscriminatory basis. The FERC's regulations define "avoided cost" as the incremental cost to an
electric utility of electric energy or capacity, or both, which, but for the purchase from the qualifying facility or qualifying facilities, the utility would generate itself or purchase from another
source. The 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 under PUHCA and the Federal Power Act. As a result, the project could become subject to rate regulation by the FERC under the Federal Power Act, and EME
could inadvertently become a holding company under PUHCA. Under Section 26(b) of PUHCA, any project contracts that are entered into in violation of PUHCA, including contracts entered into
during any period of non-compliance with the registration requirement, could be determined by the courts or the Securities and Exchange Commission to be void. If a project were to lose its
qualifying facility status, EME could attempt to avoid holding company status on a prospective basis by qualifying the project owner as an exempt wholesale generator. However, assuming this changed
status would be permissible under the terms of the applicable power sales agreement, rate approval from the FERC would be required. In addition, the project would be required to cease selling
electricity to any retail customers, in order to qualify for

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exempt
wholesale generator status, and could become subject to additional state regulation. Loss of qualifying facility status by one project could also potentially cause other projects with the same
partners to lose their qualifying facility status to the extent those partners became electric utilities, electric utility holding companies or affiliates of such companies for purposes of the
ownership criteria applicable to qualifying facilities. Loss of qualifying facility status could also trigger defaults under covenants to maintain qualifying facility status in the project's power
sales agreements, steam sales agreements and financing agreements and result in termination, penalties or acceleration of indebtedness under such agreements. If a power purchaser were to cease taking
and paying for electricity or were to seek to obtain refunds of past amounts paid because of the loss of qualifying facility status, EME cannot provide assurance that the costs incurred in connection
with the project could be recovered through sales to other purchasers. Moreover, EME's business and financial condition could be adversely affected if regulations or legislation were modified or
enacted that changed the standards for maintaining qualifying facility status or that eliminated or reduced the benefits, such as the mandatory purchase provisions of PURPA and exemptions currently
enjoyed by qualifying facilities. Loss of qualifying facility status on a retroactive basis could lead to, among other things, fines and penalties, or claims by a utility customer for the refund of
payments previously made.

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.

Over
the past few years, the U.S. Congress has considered various legislative proposals to restructure the electric industry that would require, among other things, retail customer
choice, repeal of PUHCA and reform of PURPA. A number of other proposals have been introduced in Congress that relate to restructuring electricity markets. Different versions of such legislation
passed both houses of Congress late in the 108th Congress (2003-2004) but no comprehensive energy legislation was enacted. Similar comprehensive legislation has been introduced in the 109th Congress
(2005-2006), but the chances for passage of such legislation remain unclear at this time. Efforts were made in the 108th Congress to enact portions of the comprehensive energy bill on an individual
basis, but, with the exception of certain tax provisions, they were unsuccessful because the Congressional leadership and administration opposed such efforts. Similar efforts are possible in the 109th
Congress, but their chances for success remain unclear at this time.

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

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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. Among other things, the Energy Policy Act expanded 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 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
non-discriminatory open access on utility transmission lines on a comparable basis to the utilities' own use of the lines. In addition, the Open Access Rules 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. The FERC also issued Order No. 889, which required those transmitting utilities to abide
by specified standards of conduct when using their own transmission systems to make wholesale sales of power, and to post specified transmission information, including information about transmission
requests and availability, on a publicly available computer bulletin board.

In
December 1999, the FERC issued Order No. 2000, which required all jurisdictional transmission-owning utilities to file by December 15, 2000, a statement of their
plans with respect to placing functional control over their transmission assets under an RTO, meeting certain criteria set forth in the Order. Although Order No. 2000 did not mandate that a
utility join an RTO, it set forth various incentives for voluntary joining and required utilities to explain in detail their reasons for deviating from the objectives set forth in the Order. RTOs
meeting the FERC's criteria in Order No. 2000 were required to be operationally independent of the transmission-owning utilities whose assets they controlled and to possess other essential
attributes, such as regional scope and configuration, the authority to receive and rule upon requests for service, a separate tariff governing all transactions of the RTO, a market monitoring
capability, and other features.

In
subsequent orders, the FERC has progressively tightened its policies in favor of RTO formation, including an explicit proposal that approvals of market-based rate authority for
affiliates of utilities owning transmission should be tied to such utilities' placing functional control over their transmission assets in an RTO meeting the criteria of Order No. 2000. On
January 15, 2003, the FERC proposed to allow additional percentage points on a utility's return on equity in its transmission rates when it participates in an RTO, divests its
RTO-operated transmission assets, or pursues additional measures that promote efficient operation and expansion of the transmission grid. As outlined below, the FERC has also proposed to
establish a standard market design that would govern transmission service and energy trading arrangements in all regions of the country.

On
July 31, 2002, the FERC issued a Notice of Proposed Rulemaking having the stated purpose of remedying the remaining opportunities for undue discrimination in transmission and
establishing a standardized transmission service and wholesale market design, or SMD, that would provide a "level playing field" for all entities that seek to participate in wholesale electric
markets. The SMD proposal included a number of features that, taken together, should provide a flexible transmission service and an open and transparent spot market design that convey the right
pricing signals for investment in transmission and generation facilities, and for other purposes. Comments on certain features of the SMD

20

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proposal
were filed by interested parties in October 2002 and during the first quarter of 2003. The SMD proposal engendered considerable comment, and in some cases opposition, including in the
U.S. Congress.

In
April 2003, the FERC attempted to address some more controversial aspects of its SMD proposal in a "White Paper," which set forth the elements of its SMD proposal that it
regarded as the most fundamental features of a sound wholesale market "platform" and modified its proposal as to other aspects that it regarded as subject to regional variation. Currently, the SMD
policies are being implemented in different degrees and on different schedules in various parts of the country, and are the subject of active consideration and focus by stakeholders in wholesale
markets in the Midwest. These and other regulatory initiatives by the FERC are ongoing, and it is not possible to predict the extent of future developments or how they might affect the wholesale power
business.

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

Retail Competition

In response to pressure from retail electric customers, particularly large industrial users, the state commissions or state legislatures of many states have
considered whether to open the retail electric power market to competition. Retail competition is possible when a customer's local utility agrees, or is required, to unbundle its distribution service
(for example, the delivery of electric power through its local distribution lines) from its transmission and generation service (for example, the provision of electric power from the utility's
generating facilities or wholesale power purchases). Several state commissions and legislatures have issued orders or passed legislation requiring utilities to offer unbundled retail distribution
service. Volatility in California and other regional power markets has resulted in several states slowing, and in some cases reversing or reassessing, their plans to allow retail competition.

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, 2004, EME and its subsidiaries employed 1,768 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, an electric utility that serves customers in California.

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ITEM 2.    PROPERTIES

MEHC's principal office is in Irvine, California.

EME
leases its principal office in Irvine, California. This lease covers approximately 87,000 square feet and expires on December 31, 2005. EME also leases office space in
Chicago, Illinois; Chantilly, Virginia; Fairfax, 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. The Fairfax lease is for approximately 16,000 square feet and expires on September 30, 2005.
The Boston lease is for approximately 37,000 square feet and expires on July 31, 2007. The Washington D.C. lease is immaterial. At December 31, 2004, approximately 22% of the above space
was subleased.

The
following table shows, as of December 31, 2004, 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                        
|--------------- |  | ------------------------ |  | ---------------- | --- | -----------------------------------------
|CBK             |  | Manila, Philippines      |  | Leased           | (1) | Hydro generation facility                
|Homer City      |  | Pittsburgh, Pennsylvania |  | Owned            |     | Coal fired generation facility           
|Illinois Plants |  | Northeast Illinois       |  | Owned            |     | Coal, oil/gas fired generation facilities
|March Point     |  | Anacortes, Washington    |  | Leased           |     | Natural gas turbine cogeneration facility
|Midway-Sunset   |  | Fellows, California      |  | Leased           |     | Natural gas-turbine cogeneration facility
|Sunrise         |  | Fellows, California      |  | Leased           |     | Combined cycle generation facility       
|Watson          |  | Carson, California       |  | Leased           |     | Natural gas-turbine cogeneration facility

---

ITEM 3.    LEGAL PROCEEDINGS

Sunrise Power Company Lawsuits

Sunrise Power Company, in which a wholly owned subsidiary of EME owns a 50% interest, sells all its output to the California Department of Water Resources under a
power purchase agreement entered into on June 25, 2001. On February 25, 2002, the California Public Utilities Commission and the California Electricity Oversight Board filed complaints
with the FERC against all sellers of power under long-term contracts to the California Department of Water Resources, including Sunrise Power Company. The California Public Utilities
Commission complaint alleged that the contracts were "unjust and unreasonable" on price and other terms, and requested that the contracts be abrogated. The California Electricity Oversight Board
complaint made a similar allegation and requested that the contracts be deemed voidable at the request of the California Department of Water Resources or, in the alternative, abrogated as of a future
date, to allow for the possibility of renegotiation. In January 2003, the California Public Utilities Commission and the California Electricity Oversight Board dismissed their complaints
against Sunrise Power Company pursuant to a global settlement that also involved a restructuring of Sunrise Power Company's long-term contract with the California Department of Water
Resources. On

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December 31,
2002, Sunrise Power Company restructured its contract with the California Department of Water Resources. The restructured agreement reduced by 5% the capacity payments to be made
to Sunrise Power Company as compensation for having power available when needed. In addition, Sunrise Power Company's option to extend the agreement for one year beyond December 31, 2011 was
terminated; however, the term of the restructured agreement was extended until June 30, 2012.

On
May 15, 2002, Sunrise Power Company was served with a complaint filed in the Superior Court of the State of California, City and County of San Francisco, by James M. Millar,
"individually, and on behalf of the general public and as a representative taxpayer suit" against sellers of long-term power to the California Department of Water Resources, including
Sunrise Power Company. The lawsuit alleges that the defendants, including Sunrise Power Company, engaged in unfair and fraudulent business practices by knowingly taking advantage of a manipulated
power market to obtain unfair contract terms. The lawsuit seeks to enjoin enforcement of the "unfair and oppressive terms and conditions" in the contracts, as well as restitution by the defendants of
excessive monies obtained by the defendants. Plaintiffs in several other class action lawsuits pending in Northern California have filed petitions seeking to have the Millar lawsuit consolidated with
those lawsuits. The defendants in the Millar lawsuit and other class action suits removed all the lawsuits to the U.S. District Court, Northern District of California, and filed a motion to stay all
proceedings pending final resolution of the jurisdictional issue. On July 9, 2003, Judge Whaley of the U.S. District Court concluded the federal court lacked jurisdiction and remanded the case
to the originating San Francisco Superior Court. In December 2003, James Millar filed a First Amended Class Action and Representative Action Complaint which contains allegations similar to
those in the earlier complaint but also alleges a class action. One of the newly added parties removed the lawsuit to federal court, and the court ordered remand to the San Francisco Superior Court.
Defendants expect to file a responding pleading by April 2005. EME believes that the outcome of this litigation will not have a material adverse effect on its consolidated financial
position or results of operations.

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

Inapplicable.

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PART II

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

All the outstanding common stock of Mission Energy Holding Company (MEHC) is, as of the date hereof, owned by MEHC's direct parent, 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 2004, 2003 and 2002. MEHC's wholly owned subsidiary, Edison Mission Energy (EME), amended its certificate of incorporation and bylaws in May 2004 to eliminate
the so-called "ring-fencing" provisions that were implemented in early 2001 during the California energy crisis, which had included restrictions on dividends. EME made cash
dividend payments totaling $74 million and declared a dividend payable to MEHC totaling $305 million during 2004. A total of $360 million in dividends was paid in
January 2005, which included the $305 million dividend payment. EME did not pay or declare any dividends to MEHC during 2003 and 2002.

During
the first two years of MEHC's operations, when debt interest payments were funded with restricted cash, MEHC was permitted to distribute to its direct parent, Edison Mission
Group Inc., dividends MEHC received from EME, less MEHC's overhead costs subject to compliance with limitations contained in the senior secured notes indenture and in the term loan. Limitations
on MEHC's ability to pay dividends and make other distributions to its parent are now significantly more restrictive than the restrictions applicable during the first two years of its operations.
Dividends from EME may be limited based on its earnings and cash flow, terms of restrictions contained in EME's corporate credit facility, business and tax considerations, and restrictions imposed by
applicable law.

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ITEM 6.    SELECTED FINANCIAL DATA

All of EME's international operations are accounted for as discontinued operations, except the Doga project. Continuing operations include EME's Illinois Plants
and Homer City facilities, equity investments in power projects primarily located in California, the Doga project in Turkey, corporate interest expense and general and administrative expenses. See
"Item 7. Management's Discussion and Analysis of Financial Condition and Results of OperationsManagement's Overview, Risks Related to the Business and Critical Accounting
EstimatesManagement's Overview" for more information about the sale of EME's international operations and loss on lease termination, asset impairment and other charges in 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                                                                                                                                                       |                                                                           | $                        | 1,639 
|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                                                |                          |       
|                                                                                                                                                                         |                                                                           |                          |       
|                                                                                                                                                                         |                                                                           |                          | 2,583 
|                                                                                                                                                                         |                                                                           |                          |       
|Operating income (loss)                                                                                                                                                  |                                                                           |                          | (944  
|Equity in income from unconsolidated affiliates                                                                                                                          |                                                                           |                          | 215   
|Interest and other income                                                                                                                                                |                                                                           |                          | 52    
|Interest expense                                                                                                                                                         |                                                                           |                          | (451  
|                                                                                                                                                                         |                                                                           |                          |       
|Income (loss) from continuing operations before income taxes                                                                                                             |                                                                           |                          | (1,128
|Provision (benefit) for income taxes                                                                                                                                     |                                                                           |                          | (463  
|Minority interest                                                                                                                                                        |                                                                           |                          | (1    
|                                                                                                                                                                         |                                                                           |                          |       
|Income (loss) from continuing operations                                                                                                                                 |                                                                           |                          | (666  
|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 |                                                                           |                          | 690   
|                                                                                                                                                                         |                                                                           |                          |       
|Income (loss) before accounting change                                                                                                                                   |                                                                           |                          | 24    
|Cumulative effect of change in accounting, net of tax                                                                                                                    |                                                                           |                          |      
|                                                                                                                                                                         |                                                                           |                          |       
|Net income (loss)                                                                                                                                                        |                                                                           | $                        | 24    
|                                                                                                                                                                         |                                                                           |                          |       

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

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

The
MD&A is presented in four major sections:

PageManagement's Overview; Risks Related to the Business and Critical Accounting Estimates

27Results of Operations

42Liquidity and Capital Resources

58Market Risk Exposures

87


MANAGEMENT'S OVERVIEW, RISKS RELATED TO THE BUSINESS AND CRITICAL ACCOUNTING ESTIMATES

Management's Overview

MEHC as a Holding Company

MEHC has a 100% ownership interest in EME, which itself operates through its subsidiaries and affiliates. EME continues to operate predominantly in one line of
business, electric power generation with all of its continuing operations located in the United States. MEHC has no business activities other than through its ownership interest in EME. During 2001,
MEHC issued $800 million of 13.50% senior secured notes due 2008 and borrowed $385 million under a term loan (as discussed below, $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's ability to honor its obligations under the senior secured notes is entirely dependent
upon the receipt of dividends from EME and receipt of tax-allocation payments
from MEHC's parent, Edison Mission Group Inc., and ultimately Edison International. See "Liquidity and Capital ResourcesEME's Liquidity as a Holding
CompanyIntercompany Tax-Allocation Agreement." Dividends from EME are limited based on its earnings and cash flow, business and tax considerations, and restrictions imposed by
applicable law.

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

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remaining
$285 million of principal, plus interest, was paid on January 3, 2005. 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. Since the beginning of 2004, MEHC's principal source of liquidity
has been cash dividends from EME.

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 the 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. See "Risks Related to the Business."

MEHC
is subject to the informational requirements of the Securities Exchange Act of 1934 and, in accordance with these requirements, files reports, information statements and other
information with the Securities and Exchange Commission.

Dividends to MEHC

In 2004, EME made dividend payments of $74 million to MEHC. These payments were used together with cash on hand to meet the Term Loan
Put-Option payment discussed above. 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 discussed above.

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

Dividend Restriction in EME's Corporate Credit Agreement

On April 27, 2004, EME replaced its $145 million corporate credit agreement with a new $98 million secured corporate credit agreement. As of
December 31, 2004, EME had no borrowings outstanding under this credit agreement. EME would not be able to make a distribution if an event of default were to occur and be continuing after
giving effect to the distribution.

EME Introduction

EME is a holding company which operates primarily through its subsidiaries and affiliates which are engaged in the business of owning or leasing, operating and
selling energy and capacity from electric power generation facilities. EME's subsidiaries or affiliates have typically been formed to own all of 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, 2004, EME's subsidiaries and affiliates owned or leased
interests in 18 power plants.

EME
has financed the development and construction or acquisition of its projects by contributions of equity from EME and the incurrence of so-called project financed debt
obligations by the 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,

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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, EME completed the restructuring of indebtedness related to the Illinois Plants and completed the sale of most of its international operations. These
transactions were undertaken as part of a restructuring plan that was announced in late 2003.

Refinancing of Indebtedness Associated with the Illinois Plants

In April 2004, Midwest Generation, LLC (Midwest Generation) completed a private offering of $1 billion aggregate principal amount of its 8.75%
second priority senior secured notes due 2034. Concurrently with the issuance of the notes, Midwest Generation borrowed $700 million under a new first priority senior secured term loan
facility. Midwest Generation also entered into a new five-year $200 million working capital facility that replaced a prior facility. Midwest Generation used the proceeds of the
notes issuance and the term loan to refinance $693 million of indebtedness (plus accrued interest and fees) owed by its direct parent, Edison Mission Midwest Holdings Co., which had been
guaranteed by Midwest Generation and was due in December 2004, and to make the termination payment under the Collins Station lease described below.

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

Disposition of International Operations

EME's international operations, except the Doga project, 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 financial statements and the discussion set forth herein have been adjusted to this format of reporting.

EME
has now completed the sale of most of its international operations through the following transactions:

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In
connection with the above transactions, together with cash in hand, EME:

A
substantial portion of the proceeds derived from the above transactions has been retained by EME to meet future debt obligations, support working capital requirements and for other
corporate purposes discussed further below. At February 28, 2005, EME had corporate cash and cash equivalents of $1.8 billion. While EME will continue to seek to sell its ownership
interest in the Doga project, there is no assurance that such efforts will result in a sale.

EME Domestic Operations

EME's domestic project portfolio may be grouped into two categories: contracted plants and merchant plants. At December 31, 2004, EME owned interests in 11
contracted power plants that sell a majority of their power to customers under long-term sales arrangements (greater than five years) consisting of power purchase agreements or hedge
contracts. While operating these projects involves a number of risks, their long-term sales arrangements generally provide a stable and predictable revenue stream which results in
reasonably predictable cash distributions to EME.

EME
owns seven merchant power plants (the Illinois Plants and the Homer City facilities) which operate in whole or in part without long-term sales arrangements. EME's
merchant plants represent approximately 88% of EME's project portfolio based on capacity. Although the generation of the Illinois Plants was at the time of their acquisition in late 1999 subject to
sale under contracts with Exelon Generation Company LLC (Exelon Generation), all of these contracts had expired at the end of 2004. Output from merchant plants (as well as excess output from
contracted plants) which is not committed to be sold under long-term sales arrangements is subject, in terms of price and volume, to market forces which determine the actual amount and
price of power sold from these power plants.

Beginning
in 2003, a significant factor affecting merchant generators was the substantial increase in the price of natural gas, especially when compared to the less volatile cost of
coal. For the years 2003 and 2004, natural gas prices at Henry Hub (a major natural gas trading hub) averaged $5.48 and $5.91, respectively, per million British thermal units, commonly referred to as
MMBtu, compared to $3.37 per

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MMBtu
for 2002. Based upon data from the New York Mercantile Exchange (NYMEX) as of December 28, 2004, the calendar year 2005 forward natural gas price at Henry Hub was $6.34 per MMBtu.
Increases in natural gas prices during 2003 resulted in higher wholesale electricity prices (since natural gas is the primary fuel for many generation plants). The increase in natural gas prices was a
positive factor for low-cost merchant coal facilities in markets dominated by gas-fired plants and somewhat positive for coal facilities in those markets more dependent on low-cost coal and nuclear
facilities. These conditions adversely affected certain of the Illinois Plants, specifically the Collins Station and small peaking units. A description of these market forces and the risks associated
with them is included under "Market Risk Exposures."

Expansion of PJM in Illinois

The Illinois Plants are located within the service territory of Exelon Generation's affiliate, Commonwealth Edison Company (Commonwealth Edison), which on
April 27, 2004 was granted approval by the Federal Energy Regulatory Commission (FERC) to join PJM Interconnection, LLC (PJM) effective May 1, 2004. On October 1, 2004, American
Electric Power (AEP) was also integrated into PJM. As a result, as of October 1, 2004, Midwest Generation has direct access to a fully interconnected market that covers twelve states and the
District of Columbia, and serves a peak load of over 107,000 MW over 49,300 miles of transmission lines. For further discussion, see "Item 1. BusinessRegulatory Matters."

Overview of EME's 2004 Financial Performance from Continuing Operations

EME's financial performance from continuing operations in 2004 and 2003 included a number of important items:

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Excluding
these items, EME's 2004 income from continuing operations was $13 million compared to $91 million during 2003. Key items affecting EME's operating performance
included:

Partially
offset by:

Management Focus

Management's focus in 2005 is on the following key items:

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Dispositions of Investments in Other Energy Plants

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

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

Risks Related to the Business

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

MEHC's principal asset is the common stock of EME. In July 2001, MEHC issued $800 million of 13.50% senior secured notes due 2008. 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 EME. See "Item 1. BusinessEME's Relationship With Certain Affiliated Companies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 "Liquidity and Capital ResourcesDividend Restrictions in Major Financings."

If
MEHC were no longer included in the consolidated tax returns of Edison International as a result of Edison International no longer continuing to own, directly or indirectly, at least
80% of the voting power of the stock of such company and at least 80% of the value of such stock, such company would no longer be eligible to participate in tax-allocation payments with
other subsidiaries of Edison

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International.
The arrangements are subject to the terms of tax allocation and payment agreements among Edison International, MEHC, EME and other Edison International subsidiaries. The agreement to
which MEHC is a party may be terminated by the immediate parent company of MEHC at any time, by notice given before the first day of the first year with respect to which the termination is to be
effective. However, termination does not relieve any party of any obligations with respect to any tax year beginning prior to the notice. If MEHC did not participate in the tax-allocation
agreement, it would not be entitled to receive tax-allocation payments if payments were due under the agreement. See "Liquidity and Capital ResourcesEME's Liquidity as a
Holding CompanyIntercompany Tax-Allocation Agreement."

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

EME's merchant energy power plants do not have long-term power purchase agreements. Because the output of these power plants is not committed to be
sold under long-term contracts, these projects are subject to market forces which determine the amount and price of power sold from the power plants.

Among
the factors that influence future market prices for energy and capacity in PJM are:

There
is no assurance that EME's merchant energy power plants will be successful in selling power into their markets or that the prices received for such power will generate positive
cash flows. If EME's merchant energy power plants are not successful, 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 "Market Risk ExposuresCommodity Price Risk."

EME is subject to extensive energy industry regulation.

EME's operations are subject to extensive regulation by governmental agencies. EME's domestic projects are also subject to federal laws and regulations that
govern, among other things, transactions by and with purchasers of power, including utility companies, the operations of a power plant, the ownership of a power plant and various aspects related to
transmission access. 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, among other things, the geographical

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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. In addition, if any projects were to lose their status as a
qualifying facility, exempt wholesale generator or foreign utility company under U.S. federal regulations, EME could become subject to regulation as a "holding company" under the Public Utility
Holding Company Act of 1935. If that were to occur, EME would be required to divest all operations not functionally related to the operation of a single integrated utility system and would be required
to obtain approval of the Securities and Exchange Commission for various actions. See "Item 1. BusinessRegulatory MattersU.S. Federal Energy Regulation."

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

EME's operations are subject to extensive environmental regulation by foreign, 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 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.

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.

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 and sulfur oxides, mercury and particulates are potentially subject to increased controls and mitigation expenses. Changing environmental regulations could require EME to
purchase additional emission allowances or make some units uneconomical to maintain or operate. In addition, EME has an equity interest in and operates an electric generating plant in Turkey, which
plant could be impacted by greenhouse gas emission reduction requirements under the Kyoto Protocol if Turkey ratifies the Protocol. If EME cannot comply with all applicable regulations, its business,
results of operations and financial condition could be adversely affected. See "Environmental Matters and Regulations."

35

---



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. EME
is the guarantor of the Powerton and Joliet leases and is obligated under intercompany notes to Midwest Generation to make debt service payments. Each intercompany note is a general corporate
obligation of EME and payments on it are made from distributions from subsidiaries and other sources of cash received by EME. Accordingly, EME must continue to make payments under the intercompany
notes 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, 2004, consolidated debt of EME was $3.7 billion. In addition, EME's subsidiaries have $5.0 billion of
long-term lease obligations that are due over a period ranging up to 30 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 compete effectively or to operate successfully under adverse economic conditions.

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.

36

---



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

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

There
is no assurance that the occurrence of one or more of the events listed above would not significantly decrease or eliminate revenues generated by EME's projects or significantly
increase the costs of operating them. Equipment and plant warranties and insurance may not be adequate 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.

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

37

---



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

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

Determining
the fair value of derivatives under SFAS No. 133 is a critical accounting estimate because the fair value of a derivative is susceptible to significant change
resulting from a number of factors, including: volatility of energy prices, 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. Such transactions are reported net in the balance sheet in accordance with FASB 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 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 2004 and 2003, EME recorded impairment charges of $35 million and
$304 million, respectively, related to specific assets included in continuing

38

---



operations.
See "Results of Continuing OperationsEarnings from Consolidated OperationsIllinois Plants" and "Results of Continuing OperationsEarnings from
Unconsolidated AffiliatesAsset Impairment Charges."

Off-Balance Sheet Financing

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

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

Pensions and Other Postretirement Benefits

Pension and other postretirement obligations and the related effects on results of operations are calculated using actuarial models. Two critical assumptions,
discount rate and expected return on assets, are important elements of plan expense and liability measurement. Additionally, health care cost trend rates are critical assumptions for postretirement
health care plans. These critical assumptions are evaluated at least annually. Other assumptions, such as retirement, mortality and turnover, are evaluated periodically and updated to reflect actual
experience.

The
discount rate enables EME to state expected future cash flows at a present value on the measurement date. At the December 31, 2004 measurement date, EME used discount rates of
5.5% for pensions and 5.75% for postretirement benefits other than pensions (PBOP) that represented the market interest rate for high-quality fixed income investments.

To
determine the expected long-term rate of return on pension plan assets, current and expected asset allocations are considered, as well as historical and expected returns
on plan assets. The expected rate of return on plan assets was 7.5% for pensions. Actual returns on the pension plan assets were 12.2%, 5.0% and 11.9% for the one-year,
five-year and ten-year periods ended December 31, 2004, respectively.

39

---



Accounting
principles provide that differences between expected and actual returns are recognized over the average future service of employees.

At
December 31, 2004, EME's pension plans had a $153 million projected benefit obligation (PBO), a $123 million accumulated benefit obligation (ABO) and
$77 million in plan assets. A 1% decrease in the discount rate would increase the PBO by $14 million, and a 1% increase would decrease the PBO by $13 million, with corresponding
changes in the ABO. A 1% decrease in the expected rate of return on plan assets would increase pension expense by $1 million.

Annually,
EME reviews all pension plans to determine if the ABO exceeds the fair value of the plan's assets. If the ABO exceeds the fair value of the plan assets, EME records an
additional minimum pension liability, with a corresponding charge to other comprehensive income. EME may incur additional minimum pension liabilities in future periods.

At
December 31, 2004, EME's PBOP plans had a $58 million PBO. Total expense for these plans was $4 million for 2004. Increasing the health care cost trend rate by 1%
would increase the accumulated obligation as of December 31, 2004 by $11 million and annual aggregate service and interest costs by $1 million. Decreasing the health care cost
trend rate by 1% would decrease the accumulated obligation as of December 31, 2004 by $9 million and annual aggregate service and interest costs by $1 million.

See
"Results of OperationsNew Accounting Pronouncements" for information on the effects of FASB Staff Position 106-2, "Accounting and Disclosure Requirements
Related to the Medicare Prescription Drug, Improvement and Modernization Act of 2003."

Asset Dispositions and Contract Indemnities

During 2004, EME completed the sale of the majority of its international operations and recorded a gain on sale. Computing the after-tax gain on sale involved a
number of critical accounting estimates requiring management's judgment, including determining the fair value of contract indemnities and income taxes under new regulations as described below:

At
December 31, 2004, EME recorded a liability of $158 million related to the above matters which was included in determining the gain on sale of the international
projects.

In
addition to the foregoing items related to asset sales, Midwest Generation has agreed to reimburse Commonwealth Edison and Exelon Generation for 50% of specific existing asbestos
claims and expenses

40

---



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 with
extensive experience in performing asbestos studies to estimate future losses based on the claims experience and other information available. 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, 2004, Midwest Generation had $69 million recorded as a liability related to this contract indemnity.

Income Taxes

SFAS No. 109, "Accounting for Income Taxes" (SFAS No. 109), requires the asset and liability approach for financial accounting and reporting for
deferred income taxes. EME uses the asset and liability method of accounting for deferred income taxes and provides deferred income taxes for all significant income tax temporary differences. See
Note 12 to the "Mission Energy Holding Company and Subsidiaries Notes to Consolidated Financial Statements" for additional details.

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

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."

41

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RESULTS OF OPERATIONS

Introduction

This section discusses operating results in 2004, 2003 and 2002. In 2004, all of EME's international operations are accounted for as discontinued operations.
Continuing operations include EME's Illinois Plants and Homer City facilities, equity investments in power projects primarily located in California, corporate interest expense and general and
administrative expenses. This section also discusses the effect of new accounting pronouncements on EME's consolidated financial statements. It is organized under the following headings:

PageNet Income Summary

42Results of Continuing Operations

43Discontinued Operations

53New Accounting Pronouncements

54


Net Income Summary

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

Years Ended December 31,2004

2003

2002(in millions)Mission Energy Holding Company (parent company):Loss from continuing operations

$
(98
)
$
(99
)
$
(93
)Edison Mission Energy and its Consolidated Subsidiaries:Income (loss) from continuing operations

$
(568
)
$
(95
)
$
17Income from discontinued operations


690


124


22Cumulative changes in accounting principle





(9
)

(14
)Net Income (Loss)

$
24

$
(79
)
$
(68
)


MEHC's loss from continuing operations in 2004 was $98 million compared to $99 million in 2003 and $93 million in 2002. There
was no significant change in loss from continuing operations in 2004 from 2003. The 2003 increase in loss from continuing operations was primarily due to lower interest income and higher consulting
fees in 2003.

EME's
2003 loss from a change in accounting principle resulted from the adoption of a new accounting standard for asset retirement obligations. EME's 2002 loss from a change in
accounting principle results from the adoption of a new accounting standard for goodwill. See "Results of Continuing OperationsCumulative Effect of Change in Accounting Principle" for
further discussion of these changes in accounting.

42

---



EME's
income (loss) from continuing operations for the three years ended December 31, 2004 is comprised of:

Years Ended December 31,2004

2003

2002(in millions)Income (Loss) from Continuing Operations

$
(568
)
$
(95
)
$
17Discrete Items (after tax)Loss on lease termination, asset impairment and other charges (in "Results of Continuing Operations" see "Illinois Plants" and "Charges Related to Cancellation of Turbine Orders/Leases" in "Earnings from
Consolidated Operations," and "Earnings from Unconsolidated AffiliatesAsset Impairment Charges")


(608
)

(186
)

(79
)Gain on sale of assets (see "Results of Continuing OperationsEarnings from Unconsolidated AffiliatesFour Star Oil & Gas")


29





Settlement of postretirement employee benefit liability (see "Results of Continuing OperationsEarnings from Consolidated OperationsIllinois Plants")








43Other


(2
)




Income from Continuing Operations (excluding discrete items)

$
13

$
91

$
53


EME's income from continuing operations, excluding discrete items, in 2004 was $13 million compared to $91 million in 2003 and
$53 million in 2002. The 2004 decrease was primarily attributable to lower earnings due to the absence of earnings from Four Star Oil & Gas during 2004 (sold on January 7, 2004),
lower earnings from EME's Homer City facilities due to lower generation and higher fuel costs related to emission allowances and lower earnings from EME's 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.

The
2003 increase in income from continuing operations, excluding discrete items, was primarily attributable to higher earnings from EME's Homer City facilities due to higher energy
prices, improved profitability of EME's interest in Four Star Oil & Gas and the Big 4 projects due to higher natural gas prices, and the start of operations at Phase 2 of the Sunrise project in
June 2003. Partially offsetting these items were lower capacity revenues at EME's Illinois Plants.

Results of Continuing Operations

Overview

EME operates in one line of business, electric power generation. Operating revenues are primarily related to the sale of power generated from the Illinois Plants
and Homer City facilities. Intercompany

43

---



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.

The
following section provides a summary of the operating results for the three years ended December 31, 2004 together with discussions of the contributions by specific projects
and of other significant factors affecting these results.

Years Ended December 312004

2003

2002(in millions)Income (Loss) before Taxes and Minority Interest (Earnings/Losses)(1)Consolidated operationsIllinois Plants

$
(881
)
$
(112
)
$
232Homer City


77


137


37Doga


6


13


17Charges related to cancellation of turbine orders/leases








(61
)Other


25


37


39Unconsolidated affiliatesBig 4 projects


142


135


94Four Star Oil & Gas





43


20Sunrise


28


35


16March Point


17


10


18Doga


1





Asset impairment charges





(59
)

Other


11





25(574
)

239


437MEHC and EME corporate interest expense


(441
)

(452
)

(462
)EME corporate and regional administrative and general


(149
)

(138
)

(118
)Gain on sale of assets


43





EME corporate depreciation and other, net


(7
)

(16
)

(13
)Loss from Continuing Operations Before Income Taxes

$
(1,128
)
$
(367
)
$
(156
)


---

44

---



Earnings from Consolidated Operations

Illinois Plants

|                                    |                                                               | Years Ended December 31     |     
|----------------------------------- | ------------------------------------------------------------- | --------------------------- | ----
|
|
|Operating Revenues                  |                                                               |                             |     
|                                    | Energy revenues                                               |                             | $   
|                                    | Capacity revenues                                             |                             |     
|                                    | Net losses from price risk management                         |                             |     
|                                    |                                                               |                             |     
|                                    | Total operating revenues                                      |                             |     
|                                    |                                                               |                             |     
|Operating Expenses                  |                                                               |                             |     
|                                    | Fuel(1)                                                       |                             |     
|                                    | Plant operations                                              |                             |     
|                                    | Plant operating leases                                        |                             |     
|                                    | Settlement of postretirement employee benefit liability       |                             |     
|                                    | Depreciation and amortization                                 |                             |     
|                                    | Loss on lease termination, asset impairment and other charges |                             |     
|                                    | Administrative and general                                    |                             |     
|                                    |                                                               |                             |     
|                                    | Total operating expenses                                      |                             |     
|                                    |                                                               |                             |     
|Operating Income (Loss)             |                                                               |                             | (893
|                                    |                                                               |                             |     
|Other Income (Expense)              |                                                               |                             |     
|                                    | Interest income from note receivable from EME                 |                             |     
|                                    | Interest expense                                              |                             |     
|                                    |                                                               |                             |     
|                                    | Total other income (expense)                                  |                             |     
|                                    |                                                               |                             |     
|Income (Loss) Before Taxes          |                                                               | $                           | (881
|                                    |                                                               |                             |     
|StatisticsCoal-Fired Generation(2) |                                                               |                             |     
|                                    | Generation (in GWhr):                                         |                             |     
|                                    |                                                               | Power purchase agreement    |     
|                                    |                                                               | Merchant                    |     
|                                    |                                                               |                             |     
|                                    |                                                               | Total coal-fired generation |     
|                                    |                                                               |                             |     
|                                    | Equivalent Availability(5)                                    |                             |     
|                                    | Forced outage rate(6)                                         |                             |     
|                                    | Average realized energy price/MWhr:                           |                             |     
|                                    |                                                               | Power purchase agreement    |     
|                                    |                                                               | Merchant                    |     
|                                    |                                                               | Total coal-fired generation |     

---

45

---



Losses from the Illinois Plants increased $769 million in 2004 compared to 2003, and decreased $344 million in 2003 compared to
2002. Discrete items affecting the income (loss) of the Illinois Plants include:

Earnings
from the Illinois Plants, excluding the above discrete items, decreased $24 million in 2004 compared to 2003, and $98 million in 2003 compared to 2002. The 2004
decrease in earnings is due to the following factors:

46

---



Partially
offset by:

The
2003 decrease in earnings is primarily due to an approximately $221 million decrease in capacity revenue resulting from the reduction in megawatts contracted under the power
purchase agreements with Exelon Generation, partially offset by an approximately $126 million increase in energy revenue due to the shift to merchant generation. The merchant generation
currently earns minimal capacity revenues but earns higher energy revenues due to higher average realized energy prices as compared to the energy prices set forth in the power purchase agreements
previously in effect.

During
2003 and 2004, the Illinois Plants had one unit at the Collins Station 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. In addition, the
Illinois Plants permanently ceased operations at all units at the Collins Station on September 30, 2004 after termination of the lease.

Losses
from price risk management were $4 million, $3 million and $1 million in 2004, 2003 and 2002, respectively. The 2004 losses primarily related to power
contracts that did not qualify for hedge accounting under SFAS No. 133. The 2003 losses primarily reflect a mark-to-market adjustment for $3 million related to an
option in which Midwest Generation had to purchase energy from Calumet Energy Team LLC, which is accounted for as a derivative under SFAS No. 133. The 2002 losses were primarily due to the
realized loss recognized on futures contracts that expired in August 2002 that did not qualify for hedge accounting under SFAS No. 133.

The
earnings (losses) of the Illinois Plants included interest income of $113 million, $113 million and $119 million in 2004, 2003 and 2002, respectively, related to
loans to EME. In August 2000, Midwest Generation, which owns or leases the Illinois Plants, entered into a sale-leaseback transaction of the Powerton-Joliet facilities. The proceeds
from the sale of these facilities were loaned to EME, which also provided a guarantee of the related lease obligations of Midwest Generation. The Powerton-Joliet sale-leaseback is recorded
as an operating lease for accounting purposes. See "Management's Overview, Risks Related to the Business and Critical Accounting EstimatesCritical Accounting
EstimatesOff-Balance Sheet Financing" for further discussion of these leases.

47

---



Homer City

Years Ended December 31,2004

2003

2002(in millions)Operating RevenuesEnergy revenues

$
486

$
491

$
348Capacity revenues


28


30


41Net gains (losses) from price risk management


(17
)

10


(2
)Total operating revenues


497


531


387Operating ExpensesFuel(1)


215


193


148Plant operations


88


82


87Plant operating leases


102


102


102Depreciation and amortization


15


15


15Administrative and general


3





Total operating expenses


423


392


352Operating Income


74


139


35Other Income (Expense)Interest expense


4





2Other income (expense)


(1
)

(2
)

Total other income (expense)


3


(2
)

2Income Before Taxes

$
77

$
137

$
37StatisticsGeneration (in GWhr)


13,292


14,403


12,111Availability(2)


85.1%


88.7%


76.8%Forced outage rate(3)


5.3%


5.1%


16.0%Average realized energy price/MWhr

$
36.20

$
34.02

$
28.70


---

Earnings from Homer City decreased $60 million in 2004 compared to 2003 and increased $100 million in 2003 compared to 2002. 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 (these factors are
discussed further below). Homer City also had lower energy revenues in 2004 due to lower generation and availability, which was mostly offset by increased average realized energy prices. During the
first quarter of 2004, an unplanned outage at Unit 1 contributed to lower generation and higher maintenance costs. During the third quarter of 2004, coal deliveries under contracts with four fuel
suppliers to Homer City were temporarily interrupted. As a result of these interruptions, Homer City reduced generation during off-peak periods when power prices were lower and

48

---



purchased
coal from alternative suppliers at spot prices which were substantially higher than the contract prices from these four fuel suppliers. See "Contractual Obligations, Commitments
and ContingenciesContractual ObligationsFuel Supply Dispute" for more information regarding the fuel supply interruptions and the dispute with two of the suppliers.

The
price of emission allowances, particularly SO2 allowances issued through the Acid Rain Program of the United States Environmental Protection Agency, also increased substantially in
2004. The average cost of SO2 allowances increased from $170 per ton during 2003 to $436 per ton in 2004. The market for SO2 allowances also experienced increased volatility, with prices ranging from
$220 to $740 per ton (in contrast to a range of $100 to $220 between 1998 and 2003). These developments have been attributed to reduced numbers of both allowance sellers and prior vintage allowances.
The total cost to purchase SO2 emission allowances during 2004 increased to $43 million from $15 million in 2003.

The
2003 increase in earnings is due to increased generation and higher energy prices. The increase in generation primarily resulted from an unplanned outage on Unit 3 and extended
outages on Units 1 and 2 during the first half of 2002. On February 10, 2002, Homer City experienced a major unplanned outage due to a collapse of the SCR ductwork of one of the units, known as
Unit 3. The unit was restored to operation on April 4, 2002 and operated with the SCR bypassed until June 19, 2003, when it was returned to service. As a result of the Unit 3 ductwork
collapse, EME reviewed the similar structures on Units 1 and 2 and determined that as a precaution it would be appropriate to install additional reinforcement in these structures. The additional
reinforcement extended the duration of planned outages for these units, which had been scheduled to end on June 2, 2002. Unit 1 returned to service on June 28, 2002 and Unit 2 returned
to service on June 26, 2002.

Power
prices in 2004 and 2003 were favorably affected by higher natural gas prices in the United States. The 24-hour PJM market price (at the Homer City busbar) was $40.79,
$35.08 and $25.63 per megawatt hour in 2004, 2003 and 2002, respectively. The increase in market prices improved the profitability of the Homer City plant in each year.

Losses
from price risk management activities increased $27 million in 2004 compared to 2003 and decreased $12 million in 2003 compared to 2002. A significant portion of the
2004 increase and 2003 decrease was attributable to the ineffective portion of forward and futures contracts which are derivatives that qualify as cash flow hedges under SFAS No. 133. Also
included in the 2004 losses are realized losses related mostly to futures contracts that did not qualify for hedge accounting under SFAS No. 133. 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. Homer City
recorded net gains (losses) of approximately $(14) million, $11 million and $(2) million in 2004, 2003 and 2002, respectively, representing the amount of cash flow hedges' ineffectiveness. The
ineffective gains (losses) from Homer City were partially attributable to changes in the difference between energy prices at PJM West Hub (the delivery point under forward contracts) and the energy
prices at the delivery point where power generated by the Homer City facilities is delivered into the transmission system (referred to as the Homer City busbar). In addition, Homer City recognized
gains (losses) on the ineffective portion related to forward contracts that expired during the respective periods. See "Market Risk ExposuresCommodity Price Risk" for more
information regarding forward market prices.

Charges Related to Cancellation of Turbine Orders/Leases

In December 2000, EME entered into a master lease and related agreements which together initially provided for the construction of new projects using a
total of nine turbines on order from Siemens

49

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Westinghouse.
Due to unfavorable market conditions, EME decided to terminate its obligation to cause the completion of three of the four projects and recorded a loss of $25 million during the
year ended December 31, 2001. In September 2002, EME notified Siemens Westinghouse of its election to terminate all of the equipment purchase contracts for nine turbines effective
October 25, 2002, in light of lower wholesale energy prices during 2002. Accordingly, EME recorded approximately $61 million to write-off capitalized costs associated with
the termination of these contracts during the year ended December 31, 2002.

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. See "New Accounting PronouncementsStatement of Financial Accounting Standards Interpretation No. 46(R)," for discussion of EME's accounting for this 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 $7 million in 2004 compared to 2003, and increased $41 million in 2003 compared to 2002. The 2004 and 2003 changes in earnings
were largely due to higher energy prices in 2004 and 2003. The impact of the higher energy prices in 2004 was partially offset due to planned outages at the Sycamore Cogeneration plant and the Watson
Cogeneration plant in March 2004.

The
earnings from the Big 4 projects included interest expense of Edison Mission Energy Funding of $12 million, $16 million and $19 million in 2004, 2003 and 2002,
respectively.

Four Star Oil & Gas

EME's share of earnings from its ownership interest in Four Star Oil & Gas Company was $43 million and $20 million in 2003 and 2002,
respectively, with no earnings from its ownership interest recorded in 2004 due to the sale of the project. 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 decreased $7 million in 2004 from 2003 and increased $19 million in 2003 from 2002. The 2004 decrease primarily
resulted from higher interest expense due to the completion of the Sunrise project financing in September 2003. The 2003 increase in earnings primarily resulted from additional earnings from
the completion of Phase 2 of the Sunrise project in June 2003.

March Point

Earnings from March Point increased $7 million in 2004 from 2003 and decreased $8 million in 2003 from 2002. The change in earnings in these periods
was primarily due to the ineffective portion of fuel contracts entered into by March Point, which are derivatives that qualified as cash flow hedges

50

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under
SFAS No. 133. 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.

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. Revenues included in EME's consolidated statements of income from the Doga project were
$29 million (representing the first quarter of 2004) in 2004, $124 million in 2003, and $111 million in 2002. Beginning April 1, 2004, EME recorded its interest in the Doga project on the
equity method of accounting.

Earnings
from the Doga project were $6 million in 2004, $13 million in 2003 and $17 million during 2002. Earnings from the Doga project decreased in 2004 from 2003 primarily due to lower
generation and higher major maintenance costs due to plant outages, and write-off of uncollectible receivables. Earnings from the Doga project also decreased in 2003 from 2002 due to updated
levelization of revenue and higher value-added taxes.

Asset Impairment Charges

Asset impairment charges were none in 2004, $59 million in 2003 and none in 2002. 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.

Other

Earnings from other projects (consolidated subsidiaries) decreased $12 million in 2004 from 2003 and $2 million in 2003 from 2002. Included in these
earnings were gains from energy trading activities of $29 million, $40 million and $42 million in 2004, 2003 and 2002, respectively. The net gains from energy trading activities
were the result of proprietary trading in the power markets in which EME has power plants. Gains from proprietary energy trading activities in 2004 were lower than in 2003 due to less favorable market
conditions (prices and volatility). Earnings from other projects (unconsolidated affiliates) increased $11 million in 2004 from 2003 and decreased $25 million in 2003 from 2002. The 2004
increase was primarily due to higher earnings from the TM Star project due to mark-to-market losses recorded in 2003. The 2003 decrease was partially due to lower earnings from
the Westside projects due to mark-to-market gains recorded in 2002 and losses from the TM Star project due to a change in market value of natural gas contracts that did not
qualify for hedge accounting under SFAS No. 133.

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.

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MEHC and EME Corporate Interest Expense

Years Ended December 31,2004

2003

2002(in millions)MEHC (excluding EME) interest expense to third parties

$
158

$
160

$
160EME's interest expense to third parties


170


179


183EME's interest expense to Midwest Generation


113


113


119Total corporate interest expense

$
441

$
452

$
462


MEHC and EME Corporate and Regional Administrative and General Expenses

Administrative and general expenses increased $11 million in 2004 from 2003, and $20 million in 2003 from 2002. 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. The 2003 increase was primarily due to higher costs incurred
for performance-based compensation.

Income Taxes

MEHC's income tax benefit from continuing operations was $463 million in 2004, $175 million in 2003 and $82 million in 2002. The increase in
the income tax benefit was due to losses related to the termination of the Collins lease and impairment charges. Income tax benefits are recognized pursuant to a tax-allocation agreement with Edison
International. See "Liquidity and Capital ResourcesIntercompany Tax-Allocation Agreement."

Cumulative Effect of Change in Accounting Principle

Statement of Financial Accounting Standards No. 143

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

Statement of Financial Accounting Standards No. 142

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

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the
first quarter of 2002 were restated to reflect the accounting change as of January 1, 2002. Since 2002, there have been no changes related to goodwill classified as part of continuing
operations and the balance is immaterial to EME's consolidated balance sheet.

Discontinued Operations

Income from operations of discontinued subsidiaries, net of tax, were $690 million in 2004, $124 million in 2003 and $22 million in 2002.
During 2004 and the beginning of 2005, EME completed the sale of most of its international operations through the following transactions:

The
aggregate after-tax gain on the sale of the above-referenced international projects was $533 million. Subsequent to December 31, 2004, EME completed the
following additional sales:

During
the third quarter of 2004, EME reclassified its international activities which were then under contracts for sale as discontinued operations. Subsequently, EME completed the sale
of these operations as described above, except for the Doga project, which is no longer under a contract for sale. While EME continues to seek to sell its ownership interest in this project, there is
no assurance that such efforts will result in a sale during the twelve-month period prescribed under Statement of Financial Accounting Standards No. 144, "Accounting for the Impairment or Disposal of
Long-Lived Assets." As a result, EME reclassified the Doga project to continuing operations during the fourth quarter of 2004, and, accordingly, it is reflected as part of continuing operations for
all periods presented.

Previously Reported Discontinued Operations

Ferrybridge and Fiddler's Ferry Plants

On December 21, 2001, EME completed the sale of the Ferrybridge and Fiddler's Ferry coal-fired power plants located in the United Kingdom to
two wholly owned subsidiaries of American Electric Power. In addition, as part of the transactions, the purchasers acquired other assets and assumed specified liabilities associated with the plants.
The sale was the result of a competitive bidding process. EME acquired the plants in 1999 from PowerGen UK plc for £1.3 billion.

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Lakeland Project

In 2001, EME ceased consolidating the activities of Lakeland Power Ltd. when an administrative receiver was appointed following a default by Norweb
Energi Ltd., the counterparty to a long-term power sales agreement. The consolidated financial statements have been restated to conform to discontinued operations treatment for all
historical periods presented. In 2003, a third party completed the purchase of the Lakeland power plant from the administrative receiver for £24 million. The proceeds from the sale
and existing cash were used to fund partial repayment of the outstanding debt owed to secured creditors of the project. Lakeland Power Ltd.'s administrative receiver has filed a claim against
Norweb Energi Ltd. for termination of the power purchase agreement. Norweb Energi Ltd. is a subsidiary of TXU (UK) Holdings Limited (TXU UK) and is an indirect subsidiary of TXU Europe
Group plc (TXU Europe). On November 19, 2002, TXU UK and TXU Europe, together with a related entity, TXU Europe Energy Trading Limited (TXU Energy), entered into formal administration
proceedings in the United Kingdom (similar to bankruptcy proceedings in the United States). To the extent that Lakeland Power receives payment under its claim, such amounts will first be used to repay
amounts due to its creditors. In October 2004, for approximately £6 million, EME purchased from Lakeland's secured creditors the debt owed them by Lakeland Power. The
purchase of the outstanding bank debt was completed to maximize EME's recovery from the proceeds ultimately received from the claim against Norweb Energi. Based on the settlement of claims currently
being discussed as part of the TXU Europe administration proceeding, the secured debt of Lakeland Power is expected to be repaid in full. In addition, depending on the outcome of the TXU Europe
administration proceedings, EME may receive additional cash from the settlement of the claims.

See
"Mission Energy Holding Company and Subsidiaries Notes to Consolidated Financial StatementsNote 7. Discontinued Operations" for additional details related to
discontinued operations.

New Accounting Pronouncements

Introduction

A number of changes in accounting standards or interpretations were issued or effective during 2004, including the following items that were relevant to EME.

Statement of Financial Accounting Standards Interpretation No. 46(R)

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

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Deconsolidation of Special Purpose Entities

In accordance with FIN 46R, EME deconsolidated the following two financing entities:

Deconsolidation of Variable Interest Entities

In accordance with FIN 46R, EME determined that it was not the primary beneficiary of the Doga and Kwinana projects and, accordingly, deconsolidated these
projects at March 31, 2004. The Kwinana project was sold on December 16, 2004 as part of the sale of international operations to IPM, and accordingly, is included in discontinued
operations.

Variable Interest Entities

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

|Variable Interest Entity |  | Location        |  | Investment at
December 31, 2004 |    | EME's Ownership
Interest at
December 31, 2004 |    | Description
|------------------------ |  | --------------- |  | ------------------------------- | -- | --------------------------------------------- | -- | -----------
|Sunrise                  |  | Fellows, CA     |  | $                               | 97 |                                               | 50 | %          
|Watson                   |  | Carson, CA      |  |                                 | 88 |                                               | 49 | %          
|Sycamore                 |  | Bakersfield, CA |  |                                 | 48 |                                               | 50 | %          
|Midway-Sunset            |  | Fellows, CA     |  |                                 | 51 |                                               | 50 | %          
|Kern River               |  | Bakersfield, CA |  |                                 | 37 |                                               | 50 | %          

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

FASB Staff Position FAS 106-2

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

Emerging Issues Task Force Issue No. 02-14

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

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. 153

In December 2004, the FASB issued SFAS No. 153, "Exchanges of Nonmonetary Assets, an amendment of APB Opinion No. 29, Accounting for
Nonmonetary Transactions." SFAS No. 153 amends and clarifies that exchanges of nonmonetary assets should be measured based on the fair value of the assets exchanged. Further, SFAS
No. 153 eliminates the narrow exception for nonmonetary exchanges of similar productive assets and replaces it with a broader exception for exchanges of nonmonetary assets that do not have
commercial substance. SFAS No. 153 is effective for nonmonetary asset exchanges occurring beginning in the third quarter of 2005. EME does not expect the adoption of this standard to have a
material impact on EME's consolidated financial statements.

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Statement of Financial Accounting Standards No. 123(R)

In December 2004, the FASB reissued SFAS No. 123(R), "Share-Based Payment." This is a revision of SFAS No. 123, "Accounting for Stock-Based
Compensation," and supersedes APB No. 25, "Accounting for Stock Issued to Employees." SFAS No. 123(R) establishes accounting standards for transactions in which an entity receives
employee services in exchange for (a) equity instruments of the entity or (b) liabilities that are based on the fair value of the entity's equity instruments or that may be settled by
the issuance of equity instruments. The standard, effective July 1, 2005, will require EME to recognize the grant-date fair value of stock options and equity based compensation
issued to employees in the statement of operations. The statement also requires that such transactions be accounted for using the fair value based method, thereby eliminating use of the intrinsic
value method of accounting in APB No. 25, which was permitted under Statement 123, as originally issued. EME currently uses the intrinsic value accounting method for stock-based
compensation. The difference in expense between the two methods is reflected in the pro forma table in Note 2Summary of Significant Accounting PoliciesStock-Based
Compensation to the "Edison Mission Energy and Subsidiaries Notes to Consolidated Financial Statements." EME is currently in the process of evaluating the impact of SFAS No. 123(R) on its
consolidated financial statements and has not yet selected a transition method for adoption of the new standard.

FASB Staff Position FAS 109-1

In December 2004, the FASB issued FASB Staff Position FAS 109-1, "Application of FASB Statement No. 109, 'Accounting for Income
Taxes,' to the Tax Deduction on Qualified Production Activities Provided by the American Jobs Creation Act of 2004." The primary objective of this Position
is to provide guidance on the application of SFAS No. 109 to the provision within the American Jobs Creation Act of 2004 that provides a tax deduction on qualified production activities. Under
FAS 109-1, recognition of the tax deduction on qualified production activities, which include the production of electricity, is ordinarily reported in the year it is earned. This
FASB Staff Position had no impact on EME's consolidated financial statements. EME is evaluating the effect that the tax deduction will have in subsequent years.

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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

58EME's Liquidity

59Key Financing Developments

59Termination of the Collins Station Lease

602005 Capital Expenditures

60MEHC's Historical Consolidated Cash Flow

60EME's Credit Ratings

62EME's Liquidity as a Holding Company

63Dividend Restrictions in Major Financings

65MEHC's Interest Coverage Ratio

68Contractual Obligations, Commitments and Contingencies

70Off-Balance Sheet Transactions

76Environmental Matters and Regulations

79


MEHC's Liquidity

MEHC's ability to honor its obligations under the senior secured notes and to pay overhead is substantially dependent upon the receipt of dividends from EME and
receipt of tax-allocation payments from MEHC's parent, Edison Mission Group, and ultimately Edison International. See "EME's Liquidity as a Holding CompanyIntercompany
Tax-Allocation Agreement." Dividends from EME are limited based on its 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, 2004, MEHC had cash and cash equivalents of $2 million (excluding amounts held by EME and its subsidiaries). On April 5, 2004, the lenders under
MEHC's $385 million term loan due in 2006 exercised their right to require MEHC to repurchase $100 million of principal amount at par on July 2, 2004 (referred to as the "Term
Loan Put-Option"). The $100 million principal, plus interest, was paid on July 2, 2004. The remaining $285 million of principal, plus interest, was paid on
January 3, 2005.

Dividends to MEHC

In 2004, EME made dividend payments of $74 million to MEHC. These payments were used together with cash on hand to meet the Term Loan
Put-Option payment discussed above. 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 discussed above.

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

Dividend Restriction in EME's Corporate Credit Agreement

On April 27, 2004, EME replaced its $145 million corporate credit agreement with a new $98 million secured corporate credit agreement. As of
December 31, 2004, EME had no borrowings

58

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outstanding
under this credit agreement. EME would not be able to make a distribution if an event of default were to occur and be continuing after giving effect to the distribution.

EME's Liquidity

At December 31, 2004, EME and its subsidiaries had cash and cash equivalents of $2.3 billion, including $2.0 billion received from the sale
of its international assets to IPM in December 2004, and EME had available the full amount of borrowing capacity under a $98 million corporate credit facility. EME's consolidated debt at
December 31, 2004 was $3.7 billion. In addition, EME's subsidiaries had $5.0 billion of long-term lease obligations that are due over periods ranging up to
30 years.

Key Financing Developments

EME Financing Developments

On October 5, 2004, EME's subsidiary, Mission Energy Holdings International, Inc., repaid $600 million of the $800 million secured loan with
the majority of the proceeds received from the sale of Contact Energy and cash on hand. In December 2004, EME completed the repayment of the remaining $200 million secured loan at
Mission Energy Holdings International, Inc. Accordingly, this credit agreement has been terminated.

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

Midwest Generation Financing Developments

On April 27, 2004, Midwest Generation completed a private offering of $1 billion aggregate principal amount of its 8.75% second priority senior
secured notes due 2034. Holders of the notes may require Midwest Generation to repurchase, or Midwest Generation may elect to repay, the notes on May 1, 2014 and on each one-year
anniversary thereafter at 100% of their principal amount, plus accrued and unpaid interest. Concurrent with the issuance of the notes, Midwest Generation borrowed $700 million under a new first
priority senior secured term loan facility. The term loan has a final maturity of April 27, 2011 and bears interest at LIBOR plus 3.25% per annum. Midwest Generation has agreed to repay
$1,750,000 of the term loan on each quarterly payment date. Midwest Generation also entered into a new five-year $200 million working capital facility that replaced a prior
facility. The new working capital facility also provides for the issuance of letters of credit. As of December 31, 2004, Midwest Generation had no borrowings outstanding under the working
capital facility and had reimbursement obligations under a letter of credit for approximately $3 million that expires in 2005. Midwest Generation used the proceeds of the notes issuance and the
term loan to refinance $693 million of indebtedness (plus accrued interest and fees) owed by its direct parent, Edison Mission Midwest Holdings Co., which had been guaranteed by Midwest
Generation and was due in December 2004, and to make the termination payment under the Collins Station lease in the amount of approximately $960 million.

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

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

Termination of the Collins Station Lease

On April 27, 2004, Midwest Generation terminated the Collins Station lease through a negotiated transaction with the lease equity investor. Midwest
Generation made a lease termination payment of approximately $960 million. This amount represented the $774 million of lease debt outstanding, plus accrued interest, and the amount owed
to the lease equity investor for early termination of the lease. Midwest Generation received title to the Collins Station as part of the transaction. EME recorded a pre-tax loss of
approximately $951 million (approximately $585 million after tax) due to termination of the lease and the planned decommissioning of the asset.

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.

2005 Capital Expenditures

The estimated capital and construction expenditures of EME's subsidiaries are $78 million, $20 million and $24 million for 2005, 2006 and
2007, respectively. Non-environmental expenditures relate to upgrades to dust collection/mitigation systems, coal handling system and component replacement projects. These expenditures are
planned to be financed by existing subsidiary credit agreements and cash generated from their operations. Included in the estimated expenditures are environmental expenditures of $28 million
for 2005 and $1 million for 2006. In late 2004, Midwest Generation returned Will County Units 1 and 2 to service. As part of returning these units to service, Midwest Generation expects to
install environmental improvements of approximately $10 million in 2005. In addition, Homer City plans to spend approximately $18 million in 2005 related to environmental projects such
as selective catalytic reduction system improvements on all three units and ash removal improvements on two of the units.

MEHC's Historical Consolidated Cash Flow

Consolidated Cash Flows from Operating Activities

Cash used in operating activities increased $977 million in 2004 from 2003, and cash provided by operating activities decreased $246 million in 2003
from 2002. The 2004 increase was primarily attributable to the $960 million lease termination payment in 2004 related to the Collins Station lease

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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. For further discussion of the tax-allocation
payments, see "EME's Liquidity as a Holding CompanyIntercompany Tax-Allocation Agreement." In addition, distributions from unconsolidated affiliates 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.

The
2003 decrease is due to lower tax-allocation payments received from Edison International. MEHC received $61 million and $89 million in
tax-allocation payments in 2003 and 2002, respectively. Partially offsetting this decrease was higher distributions from EME's unconsolidated affiliates primarily due to the receipt of
$151 million from the completion of the Sunrise project financing in September 2003.

Consolidated Cash Flows from Financing Activities

Cash used in financing activities decreased $453 million in 2004 from 2003, and increased $204 million in 2003 from 2002. 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 term
loan in July 2004.

The
2003 increase was due to higher levels of payments on long-term debt agreements in 2003 from 2002, including debt service payments of $911 million related to
Tranche A and $116 million related to Tranche B of Edison Mission Midwest Holdings' credit facility, repayment of $167 million on the Coal and Capex facility guaranteed by
EME, and debt service payments of $118 million related to
three of EME's subsidiaries. Partially offsetting this increase were higher levels of borrowings in 2003 from 2002 due to the $800 million secured loan received by Mission Energy Holdings
International, Inc.

Consolidated Cash Flows from Investing Activities

Cash provided by investing activities increased $2.8 billion in 2004 from 2003, and cash used in investing activities decreased $126 million in 2003
from 2002. The 2004 increase was due to a combination of the following:

The
2003 decrease was due to a $300 million payment in 2002 for the Illinois Plants' peaking units that were subject to a lease included in capital expenditures, partially offset
by $255 million received in 2002 as a repayment of a note receivable held by EME. There were no comparable cash receipts in 2003.

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Also
included in capital expenditures in 2002 were payments for three turbines purchased under EME's Master Turbine Lease with funds from restricted cash of $61 million.

Net Changes in Cash of Discontinued Operations

Net changes in cash of discontinued operations for 2004 was $(512) million which primarily related to the reduction in working capital resulting from the
sale of substantially all of the international projects described under "Results of OperationsDiscontinued Operations." The gross proceeds from the sale of the international
projects is reflected as cash flow from investing activities in the Statement of Cash Flows, whereby the cash from discontinued operations acquired by the purchasing entity (approximately
$145 million) and income taxes resulting from the sale of the projects (approximately $400 million) are reflected as a decrease in cash of discontinued operations.

EME's Credit Ratings

Overview

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

Moody's Rating

S&P RatingEME

B1

BMidwest Generation, LLC:First priority senior secured rating

Ba3

B+Second priority senior secured rating

B1

B-Edison Mission Marketing & Trading

Not Rated

B


On August 6, 2004, Moody's raised EME's credit rating to B1 from B2. EME cannot provide assurance that its current credit ratings or the
credit ratings of its subsidiaries will remain in effect for any given period of time or that one or more of these ratings will not be lowered. EME notes that these credit ratings are not
recommendations to buy, sell or hold its securities and may be revised at any time by a rating agency.

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

The
credit ratings of EME are below investment grade and, accordingly, EME has historically provided collateral in the form of cash and letters of credit for the benefit of
counterparties for its price risk management and trading activities related to accounts payable and unrealized losses. As a result of Midwest Generation's new working capital facility, Midwest
Generation now provides credit support for forward contracts entered into by Edison Mission Marketing & Trading related to the Illinois Plants.

Edison
Mission Marketing & Trading has provided credit for the benefit of counterparties in the form of cash and letters of credit ($79 million as of December 31,
2004) for EME's price risk management and domestic trading activities (including Midwest Generation and Homer City) related to accounts payable and unrealized losses.

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EME expects to have higher merchant generation in 2005 than in previous years, as a result of the expiration in 2004 of the power purchase agreements between Midwest Generation and
Exelon Generation. The increased merchant generation will increase the potential for margin and collateral requirements. Changes in forward market prices and the strategies adopted for merchant
generation could further increase the need for credit support for price risk management activities related to EME's projects. Using common industry analytics, EME estimates that total margin and
collateral requirements to support price risk management could increase to approximately $400 million in 2005 if 50% of merchant generation from the Illinois Plants and Homer City facilities is
sold forward for one year and power prices subsequently increased. Midwest Generation is expected to have cash on hand and a $200 million working capital facility that can be used to provide
credit support for forward contracts entered into on behalf of the Illinois Plants. In addition, EME is expected to have cash on hand and a $98 million working capital facility that can be used
to provide credit support for its subsidiaries. See "EME's Liquidity" for further discussion.

Credit Rating of Edison Mission Marketing & Trading

The Homer City sale-leaseback documents restrict EME Homer City Generation L.P.'s (EME Homer City's) ability to enter into trading activities, as
defined in the documents, with Edison Mission Marketing & Trading to sell forward the output of the Homer City facilities if Edison Mission Marketing & Trading 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 of the output from the Homer City facilities through Edison Mission Marketing & Trading, which has a below investment grade credit rating, and EME Homer City is not rated. Therefore,
in order for EME to continue to sell forward the output of the Homer City facilities, either: (1) EME must obtain consent from the sale-leaseback owner participant to permit EME
Homer City to sell directly into the market or through Edison Mission Marketing & Trading; or (2) Edison Mission Marketing & Trading must provide assurances of performance
consistent with the requirements of the sale-leaseback documents. EME has obtained a consent from the sale-leaseback owner participant that will allow EME Homer City to enter
into such sales, under specified conditions, through December 31, 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 Edison Mission Marketing & Trading and
EME Homer City that had been entered into while the consent was still in effect. EME is permitted to sell the output of the Homer City facilities into the spot market at any time. See "Market Risk
ExposuresCommodity Price RiskEnergy Price Risk Affecting Sales from the Homer City Facilities."

EME's Liquidity as a Holding Company

Overview

At December 31, 2004, EME had corporate cash and cash equivalents of $1.9 billion to meet liquidity needs. See "EME's Liquidity." EME
had no borrowings outstanding or letters of credit outstanding on the $98 million secured line of credit at December 31, 2004. During 2004, EME's cash position increased primarily due to
proceeds received from the sale of most of its international assets and an increase of distributions received from its consolidated subsidiaries. Cash distributions from EME's subsidiaries and
partnership investments, and unused capacity under its corporate credit facility represent

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EME's
major sources of liquidity to meet its cash requirements. The timing and amount of distributions from EME's subsidiaries may be affected by many factors beyond its control. See
"Dividend Restrictions in Major Financings."

EME's
secured corporate credit facility provides credit available in the form of cash advances or letters of credit. In addition to the interest payments, EME pays a commitment fee of
0.50% on the unutilized portion of the facility. EME has agreed to maintain a minimum interest coverage ratio and a minimum recourse debt to recourse capital ratio (as such ratios are defined in the
credit agreement). At December 31, 2004, EME met both these ratio tests.

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

At
December 31, 2004, EME also had available $87 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 it. 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.

Historical Domestic Distributions Received By EME

The following table is presented as an aid in understanding the cash flow of EME's domestic 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:   |                                                              |                         
|                                                      | EME Homer City Generation L.P. (Homer City facilities)       |                         
|                                                      | Edison Mission Midwest Holdings (Illinois Plants)            |                         
|                                                      | Holding companies of other consolidated operating projects   |                         
|Distributions from Unconsolidated Operating Projects: |                                                              |                         
|                                                      | Edison Mission Energy Funding Corp. (Big 4 Projects)(2)      |                         
|                                                      | Four Star Oil & Gas Company                                  |                         
|                                                      | Sunrise Power Company                                        |                         
|                                                      | Holding companies for Westside projects                      |                         
|                                                      | Holding companies of other unconsolidated operating projects |                         
|                                                      |                                                              |                         
|Total Distributions                                   |                                                              | $                       
|                                                      |                                                              |                         

---

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Intercompany Tax-Allocation Agreement

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

Dividend Restrictions in Major Financings

General

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

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Key Ratios of EME's Principal Subsidiaries Affecting Dividends

Set forth below are key ratios of EME's principal subsidiaries for the twelve months ended December 31, 2004:

|Subsidiary                                             |  | Financial Ratio                    |  | Covenant                           |  | Actual       
|------------------------------------------------------ |  | ---------------------------------- |  | ---------------------------------- |  | -------------
|Midwest Generation, LLC (Illinois Plants)              |  | Interest Coverage Ratio            |  | Greater than or equal to 1.25 to 1 |  | 2.28 to 1 (1)
|Midwest Generation, LLC (Illinois Plants)              |  | Secured Leverage Ratio             |  | Less than or equal to 8.75 to 1    |  | 6.00 to 1    
|EME Homer City Generation L.P. (Homer City facilities) |  | Senior Rent Service Coverage Ratio |  | Greater than 1.7 to 1              |  | 2.33 to 1    
|Edison Mission Energy Funding Corp. (Big 4 Projects)   |  | Debt Service Coverage Ratio        |  | Greater than or equal to 1.25 to 1 |  | 2.63 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, its credit agreement requires that it be in compliance with the covenants specified under its credit
agreement, including maintaining the following two financial performance requirements:

In
addition, Midwest Generation's distributions are limited in amount. The aggregate amount of distributions made by Midwest Generation since April 27, 2004 may not exceed the sum
of (i) 75% of

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

In
October 2004, Midwest Generation made a distribution of $88 million and as required under its credit agreement, Midwest Generation offered to prepay $29 million
of its term loan, of which $5 million was accepted by certain lenders and repaid in October 2004. Midwest Generation subsequently made a voluntary prepayment, as provided under the
credit agreement, of $24 million in December 2004.

In
January 2005, Midwest Generation made a distribution of $62 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.

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 Generation L.P. (Homer City facilities)

EME Homer City Generation L.P. completed a sale-leaseback of the Homer City facilities in December 2001. In order to make a distribution, EME
Homer City must be in compliance with the
covenants specified in the lease agreements, including the following financial performance 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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Edison Mission Energy Funding Corp. (Big 4 Projects)

EME's subsidiaries, which EME refers to in this context as the guarantors, that hold EME's interests in the Big 4 projects completed a $450 million secured
financing in December 1996. Edison Mission Energy Funding Corp., a special purpose Delaware corporation, issued notes ($260 million which was paid in September 2003) and bonds
($190 million of which $139 million was the remaining balance at December 31, 2004), the net proceeds of which were lent to the guarantors in exchange for a note. The guarantors
have pledged their cash proceeds from the Big 4 projects to Edison Mission Energy Funding as collateral for the note. All distributions receivable by the guarantors from the Big 4 projects are
deposited into trust accounts from which debt service payments are made on the obligations of Edison Mission Energy Funding and from which distributions may be made to EME if the guarantors and Edison
Mission Energy Funding are in compliance with the terms of the covenants in their financing documents, including the following requirements measured on the date of distribution:

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

EME Secured Credit Agreement Restrictions on Distributions from Subsidiaries

EME's secured credit agreement 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 secured credit agreement 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 will be deposited. EME is free to use these distributions
unless and until an event of default occurs under the credit agreement.

As
of December 31, 2004, EME had no borrowings outstanding under this credit agreement.

MEHC's Interest Coverage Ratio

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

MEHC's
interest coverage ratio equals Funds Flow from Operations divided by Interest Expense and is comprised of interest income and expense related to its holding company activities and
the

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consolidated
financial information of EME. The following table sets forth MEHC's interest coverage ratio for the years ended December 31, 2004 and 2003:

|                                                           |                                                                 | December 31,
2004      |      | December 31,
2003 |    
|---------------------------------------------------------- | --------------------------------------------------------------- | ---------------------- | ---- | ----------------- | ---
|
|Funds Flow from Operations:                                |                                                                 |                        |      |                   |    
|                                                           | Operating Cash Flow(1) from Consolidated Operating Projects(2): |                        |      |                   |    
|                                                           |                                                                 | Illinois Plants        |      | $                 | 214
|                                                           |                                                                 | Homer City             |      |                   | 95 
|                                                           |                                                                 | First Hydro            |      |                   | 48 
|Other consolidated operating projects                      |                                                                 |                        | 128  |                   |    
|Price risk management and energy trading                   |                                                                 |                        | 1    |                   |    
|Distributions from unconsolidated Big 4 projects           |                                                                 |                        | 108  |                   |    
|Distributions from other unconsolidated operating projects |                                                                 |                        | 131  |                   |    
|Interest income                                            |                                                                 |                        | 8    |                   |    
|Operating expenses                                         |                                                                 |                        | (167 | )                 |    
|                                                           |                                                                 |                        |      |                   |    
|Total EME funds flow from operations                       |                                                                 | $                      | 566  |                   | $  
|Operating cash flow from unrestricted subsidiaries         |                                                                 |                        | 1    |                   |    
|Funds flow from operations of projects sold                |                                                                 |                        | (195 | )                 |    
|MEHC                                                       |                                                                 |                        | (2   | )                 |    
|                                                           |                                                                 |                        |      |                   |    
|                                                           |                                                                 | $                      | 370  |                   | $  
|                                                           |                                                                 |                        |      |                   |    
|Interest Expense:                                          |                                                                 |                        |      |                   |    
|                                                           | EME                                                             |                        | $    | 265               |    
|                                                           | EMEaffiliate debt                                              |                        |      | 1                 |    
|                                                           | MEHC interest expense                                           |                        |      | 158               |    
|                                                           | Interest savings on projects sold                               |                        |      | (110              | )  
|                                                           |                                                                 |                        |      |                   |    
|                                                           |                                                                 | Total interest expense |      | $                 | 314
|                                                           |                                                                 |                        |      |                   |    
|Interest Coverage Ratio                                    |                                                                 |                        | 1.18 |                   |    
|                                                           |                                                                 |                        |      |                   |    

---

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

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Contractual Obligations, Commitments and Contingencies

Contractual Obligations

The following table summarizes certain EME consolidated contractual obligations as of December 31, 2004.

|                                            |                               | Payments Due by Period (in millions) |       |    
|------------------------------------------- | ----------------------------- | ------------------------------------ | ----- | ---
|
|
|Long-term debt (excluding EME)(1)           |                               | $                                    | 400   |    
|EME's long-term debt(1)                     |                               |                                      | 499   |    
|EME's operating lease obligations           |                               |                                      | 317   |    
|EME's purchase obligations:                 |                               |                                      |       |    
|                                            | Capital improvements          |                                      |       | 25 
|                                            | Fuel supply contracts         |                                      |       | 326
|                                            | Gas transportation agreements |                                      |       | 8  
|                                            | Coal transportation           |                                      |       | 202
|                                            | Other contractual obligations |                                      |       | 10 
|EME's employee benefit plan contribution(2) |                               |                                      | 13    |    
|                                            |                               |                                      |       |    
|Total Contractual Obligations               |                               | $                                    | 1,800 |    
|                                            |                               |                                      |       |    

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Operating Lease Obligations

At December 31, 2004, minimum operating lease payments were primarily related to long-term leases for the Powerton, Joliet and Homer City power
plants. 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 $293 million in 2005, $337 million in 2006, $336 million in 2007, $337 million in 2008,
$336 million in 2009, and the minimum lease payments due after 2009 are $3.2 billion. For further discussion, see "Off-Balance Sheet
TransactionsSale-Leaseback Transactions."

Fuel Supply Contracts

At December 31, 2004, EME's subsidiaries had contractual commitments to purchase coal. The remaining contracts' lengths range from one year to eight years.
The minimum commitments are based on the contract provisions, which consist of fixed prices, subject to adjustment clauses.

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Fuel
Supply Dispute

During
2004, EME Homer City experienced interruptions of supply under two agreements with Unionvale Coal Company and Genesis, Inc. On December 21, 2004, Unionvale and
Genesis gave EME Homer City written notice of an event of force majeure at the Genesis No. 17 Mine in Pennsylvania, which is a source of coal under both of the agreements. The claimed force
majeure event is the result of alleged geologic conditions that, in the suppliers' opinion, prevent the delivery of coal under the agreements. These two agreements together provide for the delivery to
EME Homer City of 1,290,000 tons of coal in 2005.

Unionvale
and Genesis also seek to terminate one of the agreements, which was scheduled to run through December 2007, under a provision that allows either party to the agreement
to terminate if an event of force majeure lasts 30 days or more. Unionvale and Genesis allege that the geologic problems encountered at the mine prevent mining and will continue beyond a
30-day period. The parties' second agreement with a term through December 2006 does not contain a similar termination provision, and the suppliers have requested contract
modifications to the term, quantity, quality and price provisions of the agreement.

EME
Homer City disputes the force majeure claim as it relates to both agreements and has filed suit against Unionvale and Genesis in Pennsylvania state court. EME Homer City's complaint
seeks equitable relief by way of an order requiring the defendants to fulfill their contracted obligations and such other monetary relief as is just and proper. Contracts have been awarded and
inventory strategies adjusted to reflect and offset the delivery shortfall for 2005. As of December 31, 2004, EME Homer City had not contracted for the resultant potential shortfalls in 2006
and 2007.

Gas Transportation Agreements

At December 31, 2004, 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 term of 15 years.

Coal Transportation Agreements

At December 31, 2004, Midwest Generation had contractual commitments for the transport of coal to its facilities. As of December 31, 2004, the
contracts range from three years to seven years in length. The contractual commitments are based on the committed coal volumes included under "Fuel Supply Contracts."

Other Contractual Obligations

At December 31, 2004, 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 LLC at prices based primarily on operations and maintenance and
fuel costs.

EME
Homer City entered into a Coal Cleaning Agreement with Homer City Coal Processing Corporation to operate and maintain a coal cleaning plant owned by EME Homer City. Under the terms
of the agreement, EME Homer City is obligated to reimburse Homer City Coal Processing Corporation for the actual costs incurred in the operations and maintenance of the coal cleaning plant, a fixed
general

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and
administrative service fee of approximately $260 thousand per year, and an operating fee that ranges from $.20 to $.35 per ton depending on the level of tonnage. The agreement expired on
August 31, 2002 and was renewed with the same terms through December 31, 2005, with a two-year extension option.

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.

Standby Letters of Credit

As of December 31, 2004, standby letters of credit aggregated to $16 million and were scheduled to expire during 2005.

Guarantees and Indemnities

Tax
Indemnity Agreements

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

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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 130 and 170 cases for which Midwest Generation was
potentially liable and that had not been settled and dismissed by the end of 2004. At December 31, 2004, Midwest Generation had $9 million recorded as a liability for asserted claims
related to this matter and had made $5 million in payments through December 31, 2004.

In
view of its experience since 2003, Midwest Generation engaged an independent actuary in the fourth quarter of 2004 to determine if a reasonable estimate of future losses could be made
based on claims and other available information. After review, the actuary determined that an estimate could be prepared, and, accordingly, Midwest Generation engaged the actuary to complete an
estimate of future losses. Based on the actuary's analysis, Midwest Generation recorded an undiscounted $56 million pre-tax charge for its indemnity for future asbestos claims
through 2045. 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 no asbestos claims will be filed after 2045.

The
$56 million pre-tax charge was recorded as part of plant operations on EME's consolidated income statement and reduced net income by $34 million. Midwest
Generation anticipates obtaining periodic updates of the estimate of future losses. On a quarterly basis, Midwest Generation will monitor actual experience against the number of forecasted claims to
be received and expected claim payments. Adjustments to the estimate will be recorded quarterly, if necessary.

The
amounts recorded by Midwest Generation for the asbestos-related liability were based upon known facts at the time the report was prepared. Projecting 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 as specified in the Asset Purchase Agreement dated August 1, 1998. EME guaranteed the obligations of EME Homer City. Due to the nature of the obligation under this indemnity
provision, it is not subject to a maximum potential liability and does not have an expiration date. Payments would be triggered under this indemnity by a claim from the sellers. EME has not recorded a
liability related to this indemnity.

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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. 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, 2004, EME had recorded a liability of $87 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 holds 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 2006. At December 31, 2004, EME had recorded a liability of $11 million related to this indemnity.

Capacity
Indemnification Agreements

EME
has guaranteed, jointly and severally with Texaco Inc., the obligations of March Point Cogeneration Company under its project power sales agreements to repay capacity payments
to the project's power purchaser in the event that the power sales agreements terminate, March Point Cogeneration Company abandons the project, or the project fails to return to normal operations
within a reasonable time after a complete or partial shutdown, during the term of the power contracts. In addition, subsidiaries of EME have guaranteed the obligations of Kern River Cogeneration
Company and Sycamore Cogeneration Company under their project power sales agreements to repay capacity payments to the projects' power purchaser in the event that the projects unilaterally terminate
their performance or reduce their electric power producing capability during the term of the power contracts. The obligations under the indemnification agreements as of December 31, 2004, if
payment were required, would be $153 million. EME has no reason to believe that any of these projects will either cease operations or reduce its electric power producing capability during the
term of its power contract. EME has not recorded a liability related to this indemnity.

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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

Legal Developments Affecting Sunrise Power Company

Sunrise Power Company, in which EME's wholly owned subsidiary owns a 50% interest, sells all its output to the California Department of Water Resources. On
May 15, 2002, Sunrise Power Company was served with a complaint filed in the Superior Court of the State of California, City and County of San Francisco, by James M. Millar,
"individually, and on behalf of the general public and as a representative taxpayer suit" against sellers of long-term power to the California Department of Water Resources, including
Sunrise Power Company. The lawsuit alleges that the defendants, including Sunrise Power Company, engaged in unfair and fraudulent business practices by knowingly taking advantage of a manipulated
power market to obtain unfair contract terms. The lawsuit seeks to enjoin enforcement of the "unfair and oppressive terms and conditions" in the contracts, as well as restitution by the defendants of
excessive monies obtained by the defendants. Plaintiffs in several other class action lawsuits pending in Northern California have filed petitions seeking to have the Millar lawsuit consolidated with
those lawsuits. In December 2003, James Millar filed a First Amended Class Action and Representative Action Complaint which contains allegations similar to those in the earlier complaint but
also alleges a class action. One of the newly added parties removed the lawsuit to federal court, and the court ordered remand to the San Francisco Superior Court. Defendants expect to file a
responding pleading by April 2005. EME believes that the outcome of this litigation will not have a material adverse effect on its consolidated financial position or results of operations.

Regulatory Developments Affecting Doga Project

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

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

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increase
in its tariff or, under certain circumstances, request a buyout of the project by the Ministry of Energy and Natural Resources.

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

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

Litigation

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

Off-Balance Sheet Transactions

Introduction

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

Investments Accounted for under the Equity Method

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

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

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

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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, 2004, entities which EME has accounted for under the equity method had indebtedness of $681 million, of which $303 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 plants 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 of the risk and rewards of ownership of assets be transferred
to a new owner without continuing involvement in the
assets by the former owner other than as normal for a lessee. These transactions were entered into to provide a source of capital either to fund the original acquisition of the assets or to repay
indebtedness previously incurred for the acquisition. In each of these transactions, the assets 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. Also, 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 its subsidiaries as part of the
sale-leaseback transactions. These guarantees do not preclude EME from recording these transactions as operating leases in its consolidated financial statements, but constitute continuing
involvement under SFAS No. 98 that precludes EME's subsidiaries from utilizing this accounting treatment in their separate subsidiary financial statements. Instead, each subsidiary continues to
record the power plants as assets in a similar manner to a capital lease and records the obligations under the leases as lease financings. EME's subsidiaries, therefore, record depreciation expense
from the power plants and interest expense from the lease financing in lieu of an operating lease expense which EME uses in preparing its consolidated financial statements. The treatment of these
leases as an operating lease in its consolidated financial statements in lieu of a lease financing, which is recorded by EME's subsidiaries, results in an increase in consolidated net income by
$73 million, $81 million and $89 million in 2004, 2003 and 2002, respectively.

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

Power Station(s)

Acquisition
Price

Equity
Investor

Equity Investment
in Owner/Lessor

Amount of
Lessor Debt

Maturity Date
of Lessor Debt(in millions)Powerton/Joliet

$
1,367

PSEG/
Citicapital

$
238

$
333.5
813.5

2009
2016Homer City


1,591

GECC


798


300
530

2019
2026


---

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

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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, 2004 and 2003,
prepaid rent on these leases was $277 million and $214 million, respectively. To the extent that EME's cash rent payments are less than the amount levelized, EME reduces the amount of
prepaid rent.

In
the event of a default under the leases, each lessor can exercise all of its rights under the applicable lease, including repossessing the power plant and seeking monetary damages.
Each lease sets forth a termination value payable upon termination for default and in certain other circumstances, which
generally declines over time and in the case of default may be reduced by the proceeds arising from the sale of the repossessed power plant. A default under the terms of the 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." Also see "Termination of the Collins Station Lease."

EME's Obligations to Midwest Generation

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

Years Ending December 31,

Principal Amount

Interest Amount

Total(in millions)2005

$
2

$
113

$
1152006


3


113


1162007


3


113


1162008


4


112


1162009


4


112


116Thereafter


1,348


740


2,088Total

$
1,364

$
1,303

$
2,667


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

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Environmental Matters and Regulations

Introduction

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

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

StateIllinois

Air Quality

In June 2001, Illinois passed legislation mandating the Illinois Environmental Protection Agency, or Illinois EPA, to evaluate and issue a report to the
Illinois legislature addressing the need for further emissions controls on fossil fuel-fired electric generating stations, including the potential need for additional controls on nitrogen
oxides, sulfur dioxide and mercury. The report was issued on September 30, 2004. The report concluded, "It is clear that power plant emissions are a considerable source of air pollution and
that reducing emissions will benefit public health. However, moving forward with a state-specific regulatory or legislation strategy without fully understanding all the critical impacts on jobs and
Illinois' economy overall as well as consumer utility rates and reliability of the power grid would be irresponsible." Consequently, the Illinois EPA recommended "that the Governor continue demanding
that the federal government act nationally to reduce power plant emissions. Further, the Illinois EPA recommends that the Governor insist that the competing issues of health, jobs, electric service
reliability and affordable consumer rates be fully and completely reconciled in light of the many unanswered questions presented in this report. While this work is already underwayand
will continueit can ultimately only be completed once the national emission reduction strategy solidifies and the timing and features of a national program are known." While the law
allows the Illinois EPA to propose regulations based on its findings no sooner than 90 days after the issuance of its findings, and requires the Illinois Pollution Control Board to act within
one year on such proposed regulations, the report's recommendations indicate that the State will focus its efforts on impacting the federal regulatory process rather than recommending state-specific
regulations. At this time, EME cannot evaluate the potential impact of State action on EME's facilities since it will depend on the content of federal regulations.

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

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commonly
referred to as the East St. Louis State Implementation Plan (SIP). This regulation is a State of Illinois requirement. Compliance with this standard was met by each of the Illinois Plants 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 current SO2 (acid rain) trading program already in effect. EME has already 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
will use banked allowances, along with some purchased allowances, to stay within their NOx allocations. After 2005, EME plans to continue to purchase allowances while evaluating various technologies
to determine whether any additional pollution controls should be installed at the Illinois Plants.

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. One of the limitations for discharges to the river that could be made more stringent if the existing use classification is changed would be the temperature of the discharges from the Joliet
and Will County plants. 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. At this time no standards have been proposed, so EME cannot estimate the financial
impact of this review. However, the cost of additional cooling water treatment, if required, could be substantial.

StatePennsylvania

Water Quality

The discharge from the treatment plant receiving the wastewater stream from EME's Unit 3 flue gas desulfurization system at the Homer City facilities has
exceeded the stringent, water-quality based limits for selenium in the station's NPDES permit. As a result, EME was notified in April 2002 by the Pennsylvania Department of Environmental
Protection (PADEP) that it has been included in the Quarterly Noncompliance Report submitted to the United States Environmental Protection Agency (US EPA). EME has met with the contractor responsible
for the Unit 3 flue gas desulfurization system to discuss approaches to resolving the water quality issues and is investigating technical alternatives for maximizing the level of selenium
removal in the discharge. EME has also discussed these approaches for resolving the water quality issues with PADEP. While pilot studies have been completed which have improved the performance of the
treatment system, the discharge has not been able to consistently meet its effluent limitation. Chemicals are being added to the system to continue to improve its performance which has come very close
to meeting the very tight water quality based limitation. Plans are being made to conduct an additional pilot test if the new chemical addition procedure fails to achieve consistent compliance. After
the station achieves consistent compliance, EME will meet with PADEP to

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discuss
the drafting of a consent agreement to address the selenium issue and then instruct the contractor to make the necessary improvements. The consent agreement may include the payment of civil
penalties, but the amount cannot be estimated at this time.

FederalUnited States of America

Clean Air Act

EME expects that compliance with the Clean Air Act and the regulations and revised State Implementation Plans developed as a consequence of the Act will result in
increased capital expenditures and operating expenses. EME's approach to meeting these obligations will consist of a blending of capital expenditure and emission allowance purchases that will be based
on an ongoing assessment of the dynamics of its market conditions.

Mercury Regulation

In December 2000, the US EPA announced its intent to regulate mercury emissions and other hazardous air pollutants from coal-fired electric
power plants under Section 112 of the Clean Air Act, and indicated that it would propose a rule to regulate these emissions. On January 30, 2004, the US EPA published rules for
regulating mercury emissions from coal fired power plants. The US EPA proposed two rule options for public comment: 1) regulate mercury as a hazardous air pollutant under Clean Air Act Sec.
112(d); or 2) rescind the US EPA's December 2000 finding regarding a need to control coal power plant mercury emissions as a hazardous air pollutant, and instead, promulgate a new "cap
and trade" emissions regulatory program to reduce mercury emissions in two phases by years 2010 and 2018. On March 16, 2004, the US EPA published a Supplemental Notice of Proposed Rulemaking
that provides more details on its emissions cap and trade proposal for mercury, and on November 30, 2004, the US EPA issued a Notice of Data Availability (NODA) requesting comments on additional
modeling and other data the US EPA was considering in development of its final rule. The NODA public comment period closed on January 2, 2005. At this time, the US EPA anticipates finalizing the
regulations on March 15, 2005, with controls required to be in place on existing units by March 15, 2008 (if the technology-based standard is chosen) and 2010 (when Phase I of the cap and trade
approach would be implemented if this approach is chosen).

Management's
preliminary estimate is that the anticipated mercury regulations, along with the other Clean Air Act developments described below, may require EME to spend approximately
$300 million for capital improvements at its Homer City facilities in the 2006-2010 timeframe, although the timing will depend on which mercury proposal is adopted. Until the
mercury regulations are finalized, EME cannot determine the potential impact of these regulations on the operations of its other facilities. Additional capital costs, particularly on the Illinois coal
units, related to these regulations could be required in the future and they could be material, depending upon the final standards adopted by the US EPA.

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

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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.

In
December 2003, the US EPA proposed rules that would require states to revise their implementation plans to address alleged contributions to downwind areas that are not in
attainment with the revised standards for ozone and fine particulate matter. The proposed "Clean Air Interstate Rule" is designed to be completed before states must revise their implementation plans
to address local reductions needed to meet the new ozone and fine particulate matter standards. The proposed rule would establish a two-phase, regional cap and trade program for sulfur
dioxide and nitrogen oxide. The proposed rule would affect 27 states, including Illinois and Pennsylvania. The proposed rule would require sulfur dioxide emissions and nitrogen oxide emissions to be
reduced in two phases (by 2010 and 2015), with emissions reductions for each pollutant of 65% by 2015.

On
March 10, 2005, the acting administrator of the US EPA signed the final Clean Air Interstate Rule. According to information provided by the US EPA, Phase I nitrogen oxides reductions
would come into effect in 2009 rather than 2010. In addition, the emissions budgets for sulfur dioxides and nitrogen oxides in the final rule appear to have been slightly modified from the proposed
regulation. EME has not had an opportunity to review the text of the final Clean Air Interstate Rule regulation. In addition, any additional obligations on EME's facilities to further reduce their
emissions of sulfur dioxide, nitrogen oxides 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 financial impacts resulting from required capital
improvements or operational changes.

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. 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

On November 3, 1999, the United States Department of Justice filed the first of a number of suits against electric utilities and power generating
facilities for alleged violations of the Clean Air Act's "new source review" (NSR) requirements related to modifications of air emissions sources at electric generating stations. In addition to the
suits filed, the US EPA has issued a number of administrative Notices of Violation to electric utilities alleging NSR violations. EME and its subsidiaries have not 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.

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Several
of the named utilities have reached formal agreements or agreements-in-principle with the United States to resolve alleged NSR violations. These
settlements involved installation of additional pollution controls, supplemental environment projects, and the payment of civil penalties. The agreements provided for a phased approach to achieving
required emission reductions over the next 10 to 15 years, and some called for the retirement or repowering of coal-fired generating units. The total cost of some of these
settlements exceeded $1 billion; the civil penalties agreed to by these utilities generally range between $1 million and $10 million. Because of the uncertainty created by the
Bush administration's review of the NSR regulations and NSR enforcement proceedings, some of these settlements have not been finalized. However, the Department of Justice review released in
January 2002 concluded "EPA has a reasonable basis for arguing that the enforcement actions are consistent with both the Clean Air Act and the Administrative Procedure Act." No change in the
Department of Justice's position regarding pending NSR legal actions has been announced as a result of the US EPA's proposed NSR reforms (discussed immediately below).

On
December 31, 2002, the US EPA finalized a rule to improve the NSR program. This rule is intended to provide additional flexibility with respect to NSR by, among other things,
modifying the method by which a facility calculates the emissions' increase from a plant modification; exempting, for a period of ten years, units that have complied with NSR requirements or otherwise
installed pollution control technology that is equivalent to what would have been required by NSR; and allowing a facility to make modifications without being required to comply with NSR if the
facility maintained emissions below plant-wide applicability limits. Although states, industry groups and environmental organizations have filed litigation challenging various aspects of
the rule, it became effective March 3, 2003. To date, the rule remains in effect, although the pending litigation could still result in changes to the final rule.

A
federal district court, ruling on a lawsuit filed by the US EPA, found on August 7, 2003, that the Ohio Edison Company violated requirements of the NSR within the Clean Air Act
by upgrading certain coal-fired power plants without first obtaining the necessary pre-construction permits. On August 26, 2003, another federal district court ruling in
an NSR enforcement action against Duke Energy Corporation, adopted a different interpretation of the NSR provisions that could limit liability for similar upgrade projects. This decision is currently
on appeal before the United States Court of Appeals for the Fourth Circuit.

On
October 27, 2003, the US EPA issued a final rule revising its regulations to define more clearly a category of activities that are not subject to NSR requirements under the
"routine maintenance, repair and replacement" exclusion. This clearer definition of "routine maintenance, repair and replacement," would provide EME greater guidance in determining what investments
can be made at its existing plants to improve the safety, efficiency and reliability of its operations without triggering NSR permitting requirements, and might mitigate the potential impact of the
Ohio Edison decision. However, on December 24, 2003, the United States Court of Appeals for the D.C. Circuit blocked implementation of the "routine maintenance, repair and replacement" rule,
pending further judicial review.

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. Midwest Generation has provided
responses to several portions of this request and, in cooperation with Commonwealth Edison, is obtaining the data necessary for the final response. Under date of February 1, 2005, the US EPA
submitted a request for some additional information to Midwest Generation. Midwest Generation is currently collecting available information responsive to this request. 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.

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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's 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 substantially reduce 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 NPDES 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 Illinois Plants 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 aforementioned legal challenges 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 certain pollutants from electric
utility generating stations. These bills would mandate reductions in emissions of nitrogen oxides, sulfur dioxide and mercury. Some bills would also impose limitations on carbon dioxide emissions. The
various proposals differ in many details, including the timing of any required reductions; the extent of required reductions; and the relationship of any new obligations that would be imposed by these
bills with existing legal requirements. There is significant uncertainty as to whether any of the proposed legislative initiatives will pass in their current form or whether any compromise can be
reached that would facilitate passage of legislation. Accordingly, EME is not able to evaluate the potential impact of these proposals at this time.

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

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damage,
personal injury, natural resource damages, and investigation and remediation costs incurred by these parties in connection with these releases or threatened releases. Many of these laws,
including the Comprehensive Environmental Response, Compensation and Liability Act of 1980, commonly referred to as CERCLA, as amended by the Superfund Amendments and Reauthorization Act of 1986,
impose liability without regard to whether the owner knew of or caused the presence of the hazardous substances, and courts have interpreted liability under these laws to be strict and joint and
several.

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

With
respect to EME's 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 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 "Commercial CommitmentsGuarantees and Indemnities" for a discussion of these indemnities.

Climate Change

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

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ratification
of the Kyoto Protocol in December 2004, the Protocol officially came into effect on February 16, 2005.

EME
has an equity interest in and operates the Doga generating plant in Turkey. Turkey is classified as an Annex 1 or "developed" country and is subject to national greenhouse gas
emission reduction targets during the period of 2008-2012 (i.e., Phase 1). To date, Turkey has not yet ratified the
Kyoto Protocol. Because Turkey is anxious to be admitted as a member of the European Union and the European Union is such a proponent of the Protocol, it is expected that the European Union will exert
pressure on Turkey to ratify the Protocol.

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

In
addition, there have been several petitions from states and other parties to compel the US EPA to regulate greenhouse gases under the Clean Air Act. The US EPA denied on
September 3, 2003, a petition by Massachusetts, Maine and Connecticut to compel the US EPA under the Clean Air Act to require the US EPA to establish a national ambient air quality standard for
carbon dioxide. Since that time, 11 states and other entities have filed suits against the US EPA in the United States Court of Appeals for the D.C. Circuit (D.C. Circuit). The D.C. Circuit has
granted intervention requests from 10 states that support the US EPA's ruling. The D.C. Circuit has not yet ruled on this matter.

On
July 21, 2004, Connecticut, New York, California, Iowa, New Jersey, Rhode Island, Vermont, Wisconsin, the City of New York and certain environmental organizations brought
lawsuits 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 their alleged
contribution to global warming resulting from carbon dioxide emissions from coal-fired power plants owned and operated by these companies or their subsidiaries. The lawsuits seek
injunctive relief in the form of a mandatory cap on carbon dioxide emissions to be phased in over several years. The defendants in these suits have filed motions to dismiss, which have not yet been
ruled upon by the court. Neither EME nor its subsidiaries have been named as defendants in these lawsuits.

The
ultimate outcome of the climate change debate could have a significant economic effect on EME. Any legal obligation that would require EME to substantially reduce 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 from and the procurement of fuel for its uncontracted generating plants. These
market risks arise from fluctuations in electricity, capacity and fuel prices, emission allowances, transmission rights, and interest rates. EME manages these risks in part by using derivative
financial instruments in accordance with established policies and procedures. See "Management's Overview, Risks Related to the Business and Critical Accounting Estimates" and "Liquidity and Capital
ResourcesEME's Credit Ratings" for a discussion of market developments and their impact on EME's credit and the credit of its counterparties.

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

PageCommodity Price Risk

87Credit Risk

95Interest Rate Risk

96Fair Value of Financial Instruments

97


Commodity Price Risk

General Overview

EME's revenues and 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. Among the factors that influence the price of power
in these markets are:

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

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Energy Price RiskIntroduction

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

EME's
merchant operations expose it to commodity price risk, which represents the potential loss that can be caused by a change in the market value of a particular commodity. Commodity
price risks are actively monitored by a risk management committee to ensure compliance with EME's risk management policies. Policies are in place which define risk tolerance, 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
performs a "value at risk" analysis in its daily business 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.

Energy Price Risk Affecting Sales from the Illinois Plants

Status of the Exelon Generation Power Purchase Agreements

Energy generated at the Illinois Plants was historically sold under three power purchase agreements between Midwest Generation and 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 these plants and taken by Exelon Generation. The power purchase
agreements began on December 15, 1999. The power purchase agreement for the Collins Station was terminated effective September 30, 2004; the other two contracts (for
coal-fired generation and peaking units) expired on December 31, 2004. The capacity payments provided the units under contract with revenue for fixed charges, and the energy
payments compensated those units for all, or a portion of, variable costs of production.

Approximately
53% of the energy and capacity sales from the Illinois Plants in 2004 were to Exelon Generation under the power purchase agreements.

Merchant Sales

Beginning in 2005, all the energy and capacity from the Illinois Plants are sold under terms, including price and quantity, negotiated by Edison Mission
Marketing & Trading with customers through a combination of bilateral agreements, forward energy sales and spot market sales. These arrangements generally have terms of two years or less. Thus,
EME is subject to the market risks related to the price of energy and capacity from the Illinois Plants. Capacity prices for merchant energy sales are, and are expected in the near term to remain,
substantially lower than those Midwest Generation historically received under the 1999 power purchase agreements with Exelon Generation. EME expects that lower revenues resulting from lower capacity
prices will be offset in part by energy prices, which EME believes

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will,
in the near term, be higher for merchant energy sales than those historically received under the Exelon Generation power purchase agreements, as indicated below in the table of forward-looking
prices. EME intends to manage this price risk, in part, by accessing both the wholesale customer and over-the-counter markets described below, as well as using derivative
financial instruments in accordance with established policies and procedures. Edison Mission Marketing & Trading may also, from time to time, participate in auctions for "full requirement
service" in various states for the procurement of power for electric utilities' bundled customers, in which Edison Mission Marketing & Trading would contract for the sale of power to end users
over delivery periods defined in each auction. For instance, Edison Mission Marketing & Trading participated in the New Jersey Basic Generation Auction of February 2005 and was the
winning bidder on some sales to large industrial customers for a one-year term.

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

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

Into ComEd*Historical Energy PricesOn-Peak(1)

Off-Peak(1)

24-HrJanuary

$
43.30

$
15.18

$
27.88February


43.05


18.85


29.98March


40.38


21.15


30.66April


39.50


16.76


27.88Four-Month Average

$
41.56

$
17.99

$
29.10


---

Following the transfer of control of the control area systems of Commonwealth Edison and AEP to PJM, on May 1, 2004 and October 1,
2004, respectively, sales of electricity from the Illinois Plants now include bilateral and spot sales into PJM, with spot sales being based on locational marginal pricing. These sales into the
expanded PJM, the primary market currently available to Midwest Generation, replaced sales previously made as bilateral sales and spot sales "Into ComEd" and "Into AEP." See "Item 1.
BusinessRegulatory Matters" for a more detailed discussion of recent developments regarding Commonwealth Edison's joining PJM and "Energy Price Risk Affecting Sales from the
Homer City Facilities" below for a discussion of locational marginal pricing.

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The
following table depicts the historical average market prices for energy per megawatt-hour at the Northern Illinois Hub since it became a part of PJM's service territory
on May 1, 2004.

24-Hour Historical
Northern Illinois
Hub Energy Prices*May

$
34.05June


28.58July


30.92August


26.31September


27.98October


30.93November


29.15December


29.90Eight-Month Average

$
29.73


---

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 is affected by weather and economic growth, plant outages in the region, and the amount of existing and planned power plant capacity. The
actual spot prices for electricity delivered by the Illinois Plants into these markets may vary materially from the forward market prices set forth in the table below.

The
following table sets forth the forward month-end market prices for energy per megawatt-hour for the calendar year 2005 and calendar year 2006 "strips," which
are defined as energy purchases for the entire calendar year, as quoted for sales into the Northern Illinois Hub during 2004:

24-Hour Northern Illinois Hub Forward Energy Prices*2005

2006January 31, 2004

$
26.15

$
26.22February 29, 2004


29.45


30.72March 31, 2004


31.45


32.35April 30, 2004


31.13


31.41May 31, 2004


34.64


34.55June 30, 2004


33.09


32.32July 31, 2004


33.07


32.33August 31, 2004


31.34


30.80September 30, 2004


32.82


32.85October 31, 2004


36.60


36.95November 30, 2004


34.47


34.19December 31, 2004


33.05


33.44


---

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Midwest Generation intends to hedge a portion of its merchant portfolio risk through Edison Mission Marketing & Trading. The following
table summarizes Midwest Generation's hedge position (primarily based on prices at the Northern Illinois Hub) at December 31, 2004:

2005

2006Megawatt hours


12,234,078


619,150Average price/MWhr(1)

$
39.44

$
32.30


---

To the extent Midwest Generation does not hedge its merchant portfolio, the unhedged portion will be subject to the risks and benefits of spot
market price movements. The extent to which Midwest Generation will hedge its market price risk through forward over-the-counter sales depends on several factors. First,
Midwest Generation will evaluate over-the-counter market prices to determine whether sales at forward market prices are sufficiently attractive compared to assuming the risk
associated with spot market sales. Second, Midwest Generation's ability to enter into hedging transactions will depend upon its and Edison Mission Marketing & Trading's credit capacity and upon
the over-the-counter forward sales markets having sufficient liquidity to enable Midwest Generation to identify counterparties who are able and willing to enter into hedging
transactions. Midwest Generation is permitted to use its new working capital facility and cash on hand to provide credit support for forward contracts entered into by Edison Mission Marketing &
Trading for capacity and energy generation by Midwest Generation under an energy services agreement between the two companies. Utilization of this credit facility in support of such forward contracts
is expected to provide additional liquidity support for implementation of Midwest Generation's contracting strategy for the Illinois Plants. See "Credit Risk," below.

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

Effective
May 1, 2004, the control area system of Commonwealth Edison was placed under the control of PJM. Furthermore, the transmission system of AEP was integrated into PJM on
October 1, 2004, which linked eastern PJM and the Northern Illinois control areas of the PJM system and improved access from the Illinois Plants into the broader PJM market. Under the PJM
tariff, Midwest Generation is no longer required to arrange and pay separately for transmission when making sales to wholesale buyers located within the PJM system. Under another order of the FERC
effective December 1, 2004, Midwest Generation may make sales to customers located in the MISO without incurring the "through-and-out rate" that was previously imposed
on transactions between those two regional transmission organizations. Transition mechanisms intended to compensate transmission owners for loss of these "through-and-out"
revenues do not apply to Midwest Generation under the current PJM tariff, but the costs and other issues regarding these transition mechanisms have been controversial and may become the subject of
hearings at the FERC. The ultimate outcome of any such proceedings cannot be predicted.

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

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working
to minimize such issues, Midwest Generation cannot determine how quickly or how effectively such issues will be resolved.

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

Energy Price Risk Affecting Sales from the Homer City Facilities

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

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

24-Hour
PJM Historical Energy Prices*2004

2003

2002January

$
51.12

$
36.56

$
20.52February


47.19


46.13


20.62March


39.54


46.85


24.27April


43.01


35.35


25.68May


44.68


32.29


21.98June


36.72


27.26


24.98July


40.09


36.55


30.01August


34.76


39.27


30.40September


40.62


28.71


29.00October


37.37


26.96


27.64November


35.79


29.17


25.18December


38.59


35.89


27.33Yearly Average

$
40.79

$
35.08

$
25.63


---

As shown on the above table, the average historical market prices at the Homer City busbar (delivery point) during 2004 were higher than the
average historical market prices during 2003. Forward market prices in PJM fluctuate as a result of a number of factors, including natural gas prices, transmission congestion, changes in market rules,
electricity demand which is affected by weather and economic growth, plant outages in the region, and the amount of existing and planned power plant capacity. The actual spot prices for electricity
delivered into these markets may vary materially from the forward market prices set forth in the table below.

Sales
made in the real-time or day-ahead market receive the actual spot prices at the Homer City busbar. In order to mitigate price risk from changes in spot
prices at the Homer City busbar, EME may enter into forward contracts with counterparties for energy to be delivered in future periods. Currently, there is not a liquid market for entering into
forward contracts at the Homer City busbar. A liquid

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market
does exist for a delivery point known as the PJM West Hub, which EME's price risk management activities use to enter into forward contracts. EME's revenues with respect to such forward
contracts include:

Under
the PJM market design, locational marginal pricing (sometimes referred to as LMP), which establishes hourly prices at specific locations throughout PJM by considering factors
including generator bids, load requirements, transmission congestion and losses, can cause the price of a specific delivery point to be raised or lowered relative to other locations depending on how
the point is impacted by transmission constraints. During the past 12 months, transmission congestion in PJM has resulted in prices at the PJM West Hub (the primary trading hub in PJM) being
higher than those at Homer City by an average of 4%.

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

The
following table sets forth the forward month-end market prices for energy per megawatt-hour for the calendar 2005 and 2006 "strips," which are defined as
energy purchases for the entire calendar year, as quoted for sales into the PJM West Hub during 2004:

24-Hour PJM West Hub
Forward Energy Prices*2005

2006January 31, 2004

$
36.65

$
37.01February 29, 2004


38.53


36.07March 31, 2004


40.79


39.62April 30, 2004


41.65


40.97May 31, 2004


44.43


42.43June 30, 2004


44.40


42.31July 31, 2004


44.76


42.99August 31, 2004


44.23


43.19September 30, 2004


46.19


44.81October 31, 2004


49.35


47.13November 30, 2004


46.68


44.88December 31, 2004


44.41


44.41


---

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The following table summarizes Homer City's hedge position at December 31, 2004:

2005Megawatt hours


9,288,000Average price/MWhr(1)

$
44.96


---

The average price/MWhr for Homer City's hedge position is based on PJM West Hub. Energy prices at the PJM West Hub have averaged 4% higher than
energy prices at the Homer City busbar during the past twelve months. A discussion of the basis risk between PJM West Hub and Homer City is set forth above.

Coal Price Risk

The Illinois Plants use 16 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 tons of coal annually, obtained from mines located near the facilities in Pennsylvania. Coal purchases are made under a variety
of supply agreements ranging from one year to five years in length. The following table summarizes the percent of expected coal requirements by year that are under contract at December 31,
2004.

2005

2006

2007

2008

2009Percent of coal requirements under contract

92
%
64
%
39
%
14
%
2
%


EME is subject to price risk for purchases of coal that are not under contract. Prices of Northeast coal have risen considerably in 2004. The
price of Northern Appalachian coal with 13,000 British thermal units (Btu) content for delivery in calendar year 2005 has risen from $35.10 per ton to $57.88 per ton between January 2004 and
December 2004. This 65% increase in price has been largely attributed to greater demand from domestic power producers and increased international shipments partly driven by a decline in the
value of the U.S. dollar. The prices of the Powder River Basin coal have been largely static. The price of Powder River Basin coal with 8,800 Btu content for calendar year 2005 delivery has
fluctuated between $6.06 per ton and $7.83 per ton during the course of the year, with the price of $6.32 per ton at December 30, 2004. See "Liquidity and Capital
ResourcesContractual Obligations, Commitments and ContingenciesContractual ObligationsFuel Supply Dispute" for more information regarding fuel supply
interruptions and the dispute with two suppliers.

For
forecasted 2005 coal purchases in which EME has not entered into contracts, EME expects that a 10% change in the market price of coal at December 31, 2004 would increase or
decrease pre-tax income in 2005 by approximately $2 million.

Emission Allowances Price Risk

Under the federal Acid Rain Program (which requires electric generating stations to hold sulfur dioxide allowances) and Illinois and Pennsylvania regulations
implementing the federal NOx SIP Call requirement, 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

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allowances
that have been or are allocated to these plants. The net cost of sulfur dioxide (SO2) and nitrogen oxide (NOx) emission allowances purchased during 2004 to meet the regulatory requirements
was $17 million.

The
price of emission allowances, particularly SO2 allowances issued through the US EPA Acid Rain Program, also increased substantially in 2004. The average cost of SO2 allowances
increased from $170 per ton during 2003 to $436 per ton in 2004. The market for SO2 allowances also experienced increased volatility in 2004, with prices ranging from $220 to $740 per ton (in contrast
to a range of $100 to $220 per ton between 1998 and 2003). These developments have been attributed to reduced numbers of both allowance sellers and prior vintage allowances.

EME
expects that a 10% change in the price of SO2 emission allowances at December 31, 2004 would increase or decrease pre-tax income in 2005 by approximately $5
million. See "Liquidity and Capital ResourcesEnvironmental Matters and Regulations" for a discussion of environmental regulations related to emissions.

Credit Risk

In conducting EME's price risk management and trading activities, EME contracts with a number of utilities, energy companies, financial institutions, and other
companies, collectively referred to as counterparties. In the event a counterparty were to default on its trade obligation, EME would be exposed to the risk of possible loss associated with
re-contracting the product at a price different from the original contracted price if the non-performing counterparty were unable to pay the resulting liquidated damages owed
to EME. Further, EME would be exposed to the risk of non-payment of accounts receivable accrued for products delivered prior to the time such counterparty defaulted.

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

EME
measures credit risk exposure from counterparties of its merchant energy activities 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

95

---



is
based on net exposure under these agreements. At December 31, 2004, the amount of exposure, broken down by the credit ratings of EME's counterparties was as follows:

S&P Credit Rating

December 31, 2004(in millions)A or higher

$
37A-


11BBB+


70BBB


16BBB-


4Below investment grade


2Total

$
140


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 affect on the operations of such power plant.

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. An investment grade affiliate of BP Energy has guaranteed payment of amounts due under the related contracts.

Interest Rate Risk

The fair market value of MEHC's parent only total long-term obligations was $1.3 billion at December 31, 2004, compared to the carrying
value of $1.1 billion. A 10% increase in market interest
rates at December 31, 2004 would result in a decrease in the fair value of total long-term obligations by approximately $16 million. A 10% decrease in market interest rates
at December 31, 2004 would result in an increase in the fair value of total long-term obligations by approximately $16 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, 2004, a 100-basis-point change in interest rates at December 31, 2004 would increase or decrease
2005 income before taxes by approximately $7 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 $5.5 billion at December 31, 2004, compared to the carrying value of $4.8 billion. A 10% increase in
market interest rate at December 31, 2004 would result in a decrease in the fair value of total long-term obligations by approximately $162 million. A 10% decrease in market
interest rates at December 31, 2004 would result in an increase in the fair value of total long-term obligations by approximately $180 million.

96

---



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 and instrument type (in millions):

December 31,
2004

December 31,
2003Commodity price:Electricity

$
10

$
(7
)Interest rate:Interest rate swaps

$


$
(5
)


In assessing the fair value of EME's non-trading derivative financial instruments, EME uses a variety of methods and assumptions based
on the market conditions and associated risks existing at each balance sheet date. The fair value of commodity price contracts takes into account quoted market prices, time value of money, volatility
of the underlying commodities and other factors. The fair value of outstanding derivative commodity price contracts that would be expected after a 10% decrease in the market price at
December 31, 2004 is $94 million. The following table summarizes the maturities, the valuation method and the related fair value of EME's commodity price risk management assets and
liabilities as of December 31, 2004 (in millions):

Total Fair
Value

Maturity
<1 year

Maturity
1 to 3
years

Maturity
4 to 5
years

Maturity
>5 yearsPrices actively quoted

$
10

$
11

$
(1
)
$


$



Energy Trading Derivative Financial Instruments

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

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

December 31, 2004

December 31, 2003Assets

Liabilities

Assets

LiabilitiesElectricity

$
125

$
36

$
104

$
11Other











1Total

$
125

$
36

$
104

$
12


97

---



The fair value of trading contracts that would be expected after a 10% decrease in the market price at December 31, 2004 is shown in the
table below (in millions):

Fair Value

Fair Value After
10% Price
DecreaseElectricity

$
89

$
91Other





Total

$
89

$
91


The change in the fair value of trading contracts for the year ended December 31, 2004, was as follows (in millions):

Fair value of trading contracts at January 1, 2004

$
92Net gains (losses) from energy trading activities


(36
)Amount realized from energy trading activities


33Fair value of trading contracts at December 31, 2004

$
89


Quoted market prices are used to determine the fair value of the financial instruments related to energy trading activities, except for the power
sales agreement with an unaffiliated electric utility that EME's subsidiary purchased and restructured and a long-term power supply agreement with another unaffiliated party. EME's
subsidiary recorded these agreements at fair value based upon a discounting of future electricity prices derived from a proprietary model using a discount rate equal to the cost of borrowing the
non-recourse debt incurred to finance the purchase of the power supply agreement. The following table summarizes the maturities, the valuation method and the related fair value of energy
trading assets and liabilities (as of December 31, 2004) (in millions):

Total Fair
Value

Maturity
<1 year

Maturity
1 to 3
years

Maturity
4 to 5
years

Maturity
>5 yearsPrices actively quoted

$
(2
)
$
(2
)
$


$


$
Prices based on models and other valuation methods


91


(2
)

7


12


74Total

$
89

$
(4
)
$
7

$
12

$
74


98

---





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."

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, 2004, 2003 and 2002               | 
|                      | Consolidated Balance Sheets at December 31, 2004 and 2003                                                   | 
|                      | Consolidated Statements of Shareholder's Equity for the years ended December 31, 2004, 2003 and 2002        | 
|                      | Consolidated Statements of Comprehensive Income (Loss) for the years ended December 31, 2004, 2003 and 2002 | 
|                      | Consolidated Statements of Cash Flows for the years ended December 31, 2004, 2003 and 2002                  | 
|                      | 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 2004 that have materially affected, or are reasonably likely to materially affect, MEHC's internal control over financial reporting.

ITEM 9B.    OTHER INFORMATION

None.

99

---





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, 2004 and December 31, 2003, and the results of their operations and their cash flows for each of the three years in the period ended
December 31, 2004 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
explained in Note 2 to the financial statements, the Company changed its method of accounting for goodwill and other intangible assets effective January 1, 2002, for
derivative instruments and hedging activities effective April 1, 2002, for asset retirement obligations effective January 1, 2003, and for variable interest entities effective
December 31, 2003 and March 31, 2004.

|                                       |  | PricewaterhouseCoopers LLP
|-------------------------------------- |  | --------------------------
|Los Angeles, California
March 15, 2005 |  |                           

100

---





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                                 |                          |                             
|                                                                                                                              | Settlement of postretirement employee benefit liability       |                          |                             
|                                                                                                                              | 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               |                          |                             
|                                                                                                                              | Interest and other income                                     |                          |                             
|                                                                                                                              | Gain on sale of assets                                        |                          |                             
|                                                                                                                              | Interest expense                                              |                          |                             
|                                                                                                                              | Dividends on preferred securities                             |                          |                             
|                                                                                                                              |                                                               |                          |                             
|                                                                                                                              |                                                               |                          | Total other income (expense)
|                                                                                                                              |                                                               |                          |                             
|                                                                                                                              | Loss from continuing operations before income taxes           |                          |                             
|                                                                                                                              | Benefit for income taxes                                      |                          |                             
|                                                                                                                              | Minority interest                                             |                          |                             
|                                                                                                                              |                                                               |                          |                             
|Loss From Continuing Operations                                                                                               |                                                               |                          | (666                        
|Income from operations of discontinued subsidiaries
(including gain on disposal of $533 million in 2004), net of tax (Note 7) |                                                               |                          | 690                         
|                                                                                                                              |                                                               |                          |                             
|Income (Loss) Before Accounting Change                                                                                        |                                                               |                          | 24                          
|Cumulative effect of change in accounting, net of tax (Note 2)                                                                |                                                               |                          |                            
|                                                                                                                              |                                                               |                          |                             
|Net Income (Loss)                                                                                                             |                                                               | $                        | 24                          
|                                                                                                                              |                                                               |                          |                             

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

101

---





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                                                 |                                  
|                                         | Assets under price risk management and energy trading                          |                                  
|                                         | Inventory                                                                      |                                  
|                                         | 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 |                                  
|                                         | 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.

102

---





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        |                                                                                                       |                           | 4,293
|Deferred taxes and tax credits                         |                                                                                                       |                           | 204  
|Other long-term liabilities                            |                                                                                                       |                           | 492  
|Liabilities of discontinued operations                 |                                                                                                       |                           | 5    
|                                                       |                                                                                                       |                           |      
|Total Liabilities                                      |                                                                                                       |                           | 5,976
|                                                       |                                                                                                       |                           |      
|Minority interest                                      |                                                                                                       |                           |     
|                                                       |                                                                                                       |                           |      
|Commitments and Contingencies(Notes 10, 11, 15 and 16) |                                                                                                       |                           |      
|Shareholder's Equity                                   |                                                                                                       |                           |      
|                                                       | Common stock, par value $0.01 per share; 1,000 shares authorized; 1,000 shares issued and outstanding |                           |      
|                                                       | Additional paid-in capital                                                                            |                           |      
|                                                       | Retained deficit                                                                                      |                           |      
|                                                       | Accumulated other comprehensive income (loss)                                                         |                           |      
|                                                       |                                                                                                       |                           |      
|Total Shareholder's Equity                             |                                                                                                       |                           | 912  
|                                                       |                                                                                                       |                           |      
|Total Liabilities and Shareholder's Equity             |                                                                                                       | $                         | 6,888
|                                                       |                                                                                                       |                           |      

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

103

---





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, 2001 |                                                      | $                          | 2,216 |                  | $ | (1,197                                        | )   | $                    | (303
|                             | Net loss                                             |                            |       |                  |   |                                               | (68 | )                    |     
|                             | Other comprehensive income                           |                            |       |                  |   |                                               |     |                      |     
|                             | Capital contributions from parent                    |                            |       | 1                |   |                                               |     |                      |     
|                             | Other stock transactions, net                        |                            |       | 1                |   |                                               |     |                      |     
|                             |                                                      |                            |       |                  |   |                                               |     |                      |     
|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                           |                            |       |                  |   |                                               |     |                      |     
|                             | Stock option price appreciation on options exercised |                            |       | (8               | ) |                                               |     |                      |     
|                             | Other stock transactions, net                        |                            |       | 5                |   |                                               |     |                      |     
|                             |                                                      |                            |       |                  |   |                                               |     |                      |     
|Balance at December 31, 2004 |                                                      | $                          | 2,215 |                  | $ | (1,320                                        | )   | $                    | 17  
|                             |                                                      |                            |       |                  |   |                                               |     |                      |     

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

104

---





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

|                                        |                                                                         | Years Ended December 31,                                                                                                                                    |   
|--------------------------------------- | ----------------------------------------------------------------------- | ----------------------------------------------------------------------------------------------------------------------------------------------------------- | --
|
|Net Income (Loss)                       |                                                                         | $                                                                                                                                                           | 24
|Other comprehensive income, net of tax: |                                                                         |                                                                                                                                                             |   
|                                        | Foreign currency translation adjustments:                               |                                                                                                                                                             |   
|                                        |                                                                         | Foreign currency translation adjustments, net of income tax expense of $4, $5 and $4 for 2004, 2003 and 2002, 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: |                                                                                                                                                             |   
|                                        |                                                                         | Cumulative effect of change in accounting for derivatives, net of income tax expense (benefit) of $6 for 2002                                               |   
|                                        |                                                                         | Other unrealized holding gains (losses) arising during period, net of income tax expense (benefit) of $(4), $3 and $6 for 2004, 2003 and 2002, respectively |   
|                                        |                                                                         | Reclassification adjustments included in net income (loss), net of income tax expense (benefit) of $64, $(1) and $4 for 2004, 2003 and 2002, respectively   |   
|                                        |                                                                         |                                                                                                                                                             |   
|Other comprehensive income              |                                                                         |                                                                                                                                                             | 42
|                                        |                                                                         |                                                                                                                                                             |   
|Comprehensive Income                    |                                                                         | $                                                                                                                                                           | 66
|                                        |                                                                         |                                                                                                                                                             |   

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

105

---





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

|                                                                        |                                                                                         | Years Ended December 31,                                        |      
|----------------------------------------------------------------------- | --------------------------------------------------------------------------------------- | --------------------------------------------------------------- | -----
|
|Cash Flows From Operating Activities                                    |                                                                                         |                                                                 |      
|                                                                        | Loss from continuing operations, after accounting change, 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 obligations                         |      
|                                                                        |                                                                                         | Minority interest                                               |      
|                                                                        |                                                                                         | Deferred taxes and tax credits                                  |      
|                                                                        |                                                                                         | Gain on sale of assets                                          |      
|                                                                        |                                                                                         | Asset impairment charges                                        |      
|                                                                        |                                                                                         | Cumulative effect of change in accounting, net of tax           |      
|                                                                        |                                                                                         | Settlement of postretirement employee benefit liability         |      
|                                                                        | Changes in operating assets and liabilities:                                            |                                                                 |      
|                                                                        |                                                                                         | Decrease (increase) in accounts receivable                      |      
|                                                                        |                                                                                         | Decrease (increase) in inventory                                |      
|                                                                        |                                                                                         | Decrease (increase) in prepaid expenses and other               |      
|                                                                        |                                                                                         | Increase in rent payments in excess of levelized rent expense   |      
|                                                                        |                                                                                         | Increase (decrease) in accounts payable and accrued liabilities |      
|                                                                        |                                                                                         | Increase in interest payable                                    |      
|                                                                        |                                                                                         | Decrease (increase) in net assets under risk management         |      
|                                                                        |                                                                                         | Other operatingassets                                          |      
|                                                                        |                                                                                         | Other operatingliabilities                                     |      
|                                                                        |                                                                                         |                                                                 |      
|                                                                        |                                                                                         | 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                                                   |                                                                 |      
|                                                                        | Short-term financing and lease swap agreements, net                                     |                                                                 |      
|                                                                        | Contributions from parent                                                               |                                                                 |      
|                                                                        | Cash dividends to minority shareholders                                                 |                                                                 |      
|                                                                        | Payments for price appreciation on stock options exercised                              |                                                                 |      
|                                                                        | Financing costs                                                                         |                                                                 |      
|                                                                        |                                                                                         |                                                                 |      
|                                                                        |                                                                                         | 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                                          |                                                                 |      
|                                                                        | Purchase of power sales agreement                                                       |                                                                 |      
|                                                                        | Capital expenditures                                                                    |                                                                 |      
|                                                                        | Proceeds from return of capital and loan repayments                                     |                                                                 |      
|                                                                        | Proceeds from sale of interest in projects                                              |                                                                 |      
|                                                                        | Proceeds from sales of discontinued operations                                          |                                                                 |      
|                                                                        | Purchase of short term investments, net                                                 |                                                                 |      
|                                                                        | Decrease in restricted cash                                                             |                                                                 |      
|                                                                        | Proceeds from (investments in) other assets                                             |                                                                 |      
|                                                                        |                                                                                         |                                                                 |      
|                                                                        |                                                                                         | Net cash provided by (used in) investing activities             |      
|                                                                        |                                                                                         |                                                                 |      
|Net changes in cash of discontinued operations                          |                                                                                         |                                                                 | (512 
|                                                                        |                                                                                         |                                                                 |      
|Effect of exchange rate changes on cash                                 |                                                                                         |                                                                 |     
|Effect on cash from deconsolidation of subsidiary                       |                                                                                         |                                                                 | (32  
|                                                                        |                                                                                         |                                                                 |      
|Net increase (decrease) in cash and cash equivalents                    |                                                                                         |                                                                 | 1,640
|Cash and cash equivalents at beginning of period                        |                                                                                         |                                                                 | 634  
|                                                                        |                                                                                         |                                                                 |      
|Cash and cash equivalents at end of period                              |                                                                                         |                                                                 | 2,274
|Cash and cash equivalents classified as part of discontinued operations |                                                                                         |                                                                 | (2   
|                                                                        |                                                                                         |                                                                 |      
|Cash and cash equivalents of continuing operations                      |                                                                                         | $                                                               | 2,272
|                                                                        |                                                                                         |                                                                 |      

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

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MISSION ENERGY HOLDING COMPANY AND SUBSIDIARIES  NOTES TO CONSOLIDATED FINANCIAL STATEMENTS  (Dollars in millions)

Note 1. General

Organization

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

Note 2. Summary of Significant Accounting Policies

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 "New Accounting PronouncementsStatement of
Financial Accounting Standards Interpretation No. 46(R)." 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. Such reclassifications include the
reclassification of income from continuing operations to discontinued operations for EME's international operations. Refer to Note 7Discontinued Operations. Except as indicated,
amounts reflected in the notes to the consolidated financial statements relate to continuing operations of MEHC.

Management's Use of Estimates

The preparation of financial statements in conformity with generally accepted accounting principles requires MEHC to make estimates and assumptions that affect
the reported amounts of assets and

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liabilities
and disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reported period. Actual results
could differ from those estimates.

Cash Equivalents

Cash equivalents include time deposits and other investments totaling $2.2 billion and $331 million at December 31, 2004 and 2003,
respectively, with original maturities of three months or less. All investments are classified as available-for-sale.

Short-term Investments

Short-term investments consist of marketable securities that are categorized as available-for-sale under Statement of Financial Accounting Standards No. 115,
"Accounting for Certain Investments in Debt and Equity Securities." At December 31, 2004 and 2003, the fair values of short-term investments were approximately $140 million and $20 million,
respectively, 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. The contractual maturity dates of the
auction rate securities held at December 31, 2004 varied from 2009 to 2043; however, since the interest rates are reset periodically in an auction process, these securities are considered
liquid investments and managed on an integral basis with cash and cash equivalents. Purchases and sales of auction rate securities were $301 million and $181 million in 2004,
respectively, and $318 million and $298 million in 2003, respectively. Unrealized gains and losses from investments in these securities were not material.

Property, Plant and Equipment

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

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

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

Power plant facilities

3-34.5 yearsLeasehold improvements

Life of leaseEmission allowances

25-34.5 yearsEquipment, furniture and fixtures

3-10 yearsCapitalized leased equipment

5 years


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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 16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 31,2004

2003

2002Interest incurred

$
451

$
462

$
462Interest capitalized





(7
)

(4
)$
451

$
455

$
458


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 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 12Income Taxes.

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Maintenance Accruals

Certain of EME's plant facilities' major pieces of equipment require major maintenance on a periodic basis. These costs are expensed as incurred.

Project Development Costs

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

Deferred Financing Costs

Bank, legal and other direct costs incurred in connection with obtaining financing are deferred and amortized as interest expense on a basis which approximates
the effective interest rate method over the term of the related debt. Accumulated amortization of these costs amounted to $31 million in 2004 and $99 million in 2003.

Revenue Recognition

EME is primarily an independent power producer, operating a portfolio of wholly owned plants and plants which are accounted for under the equity method. In
conjunction with its electric generation business, EME produces, as a by-product, thermal energy for sale to customers, principally steam hosts at cogeneration sites. 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 Investments 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. Accordingly, 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,

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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, fair value hedges and hedges of the net investment in a foreign operation. 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. SFAS No. 133 provides that the changes in fair value of derivatives designated as fair value hedges and the corresponding changes in the fair value of the hedged risk
attributable to a recognized asset, liability, or unrecognized firm commitment be recorded in earnings. If the fair value hedge is effective, the amounts recorded will offset in earnings. SFAS
No. 133 provides that the effective portion of the gain or loss on an instrument designated and qualifying as a hedge of the net investment in a foreign operation be reported as foreign
currency translation adjustments included as a component of other comprehensive income.

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 (losses) from price risk management and energy trading in the accompanying Consolidated Income Statements in the period of change. Assets from price risk
management and energy trading activities include the fair value of open financial positions related to trading activities and the present value of net amounts receivable from structured transactions.
Liabilities from price risk management and energy trading activities include the fair value of open financial positions related to trading activities 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.

Cumulative Effect of Change in Accounting Principle

For the year ended December 31, 2002, EME recorded a $6 million, after tax, increase to other comprehensive income as the cumulative effect of
adoption of SFAS No. 133 as a result of a revised interpretation effective April 1, 2002.

Stock-Based Compensation

At December 31, 2004, Edison International has three stock-based employee compensation plans, which are described more fully in
Note 14Stock Compensation Plans. EME accounts for those plans using the intrinsic value method. Upon grant, no stock-based employee compensation cost has been reflected in net
income (loss), as all options granted under those plans had an exercise price equal to the

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market
value of the underlying common stock on the date of grant. The following table illustrates the effect on net income if EME had used the fair value accounting method.

Years Ended December 31,2004

2003

2002Net income (loss), as reported

$
24

$
(79
)
$
(68
)Add: Stock-based compensation expense included in reported net income, net of related tax effects


14


6


3Deduct: Total stock-based employee compensation expense determined under fair value based method for all awards, net of related tax effects


(12
)

(6
)

(3
)Pro forma net income (loss)

$
26

$
(79
)
$
(68
)


See "New Accounting PronouncementsStatement of Financial Accounting Standards No. 123(R)" below for further
discussion.

Cumulative Effect of Change in Accounting Principles

Statement of Financial Accounting Standards No. 142

Effective January 1, 2002, EME adopted Statement of Financial Accounting Standards No. 142, "Goodwill and Other Intangible Assets." SFAS
No. 142 establishes accounting and reporting standards requiring goodwill not to be amortized but rather tested for impairment at least annually at the reporting unit level. During the third
quarter of 2002, EME concluded that fair value of the goodwill related to the Citizens Power LLC acquisition was impaired by $14 million, net of $9 million of income tax benefit and,
accordingly, reported this amount as a cumulative change in accounting. In accordance with SFAS No. 3, "Reporting Accounting Changes in Interim Financial Statements," EME's financial statements
for the first quarter of 2002 were restated to reflect the accounting change as of January 1, 2002. Since 2002, there have been no changes related to goodwill classified as part of continuing
operations and the balance is immaterial to EME's consolidated balance sheet.

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.

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

Initial asset retirement obligation as of January 31, 2003

$
4Accretion expense


1Balance of asset retirement obligation as of December 31, 2003


5Accretion expense


Balance of asset retirement obligation as of December 31, 2004

$
5


Had SFAS No. 143 been applied retroactively in the year ended December 31, 2002, it would not have had a material effect upon EME's
results of operations. The pro forma liability for asset retirement obligation is not shown due to the immaterial impact on EME's consolidated balance sheet.

New Accounting Pronouncements

Statement of Financial Accounting Standards Interpretation No. 46(R)

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

Deconsolidation
of Special Purpose Entities

In
accordance with FIN 46, EME deconsolidated the following two financing entities:

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Deconsolidation
of Variable Interest Entities

In
accordance with FIN 46R, EME determined that it was not the primary beneficiary of the Doga and Kwinana projects and, accordingly, deconsolidated these projects at March 31,
2004. The Kwinana project was sold on December 16, 2004 as part of the sale of international operations to IPM and, accordingly, is included in discontinued operations.

Variable
Interest Entities

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

|Variable Interest Entity |  | Location        |  | Investment at
December 31, 2004 |    | EME's Ownership
Interest at
December 31, 2004 |    | Description
|------------------------ |  | --------------- |  | ------------------------------- | -- | --------------------------------------------- | -- | -----------
|Sunrise                  |  | Fellows, CA     |  | $                               | 97 |                                               | 50 | %          
|Watson                   |  | Carson, CA      |  |                                 | 88 |                                               | 49 | %          
|Sycamore                 |  | Bakersfield, CA |  |                                 | 48 |                                               | 50 | %          
|Midway-Sunset            |  | Fellows, CA     |  |                                 | 51 |                                               | 50 | %          
|Kern River               |  | Bakersfield, CA |  |                                 | 37 |                                               | 50 | %          

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

Emerging Issues Task Force Issue No. 02-14

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

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-

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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. 153

In December 2004, the FASB issued SFAS No. 153, "Exchanges of Nonmonetary Assets, an amendment of APB Opinion No. 29, Accounting for
Nonmonetary Transactions." SFAS No. 153 amends and clarifies that exchanges of nonmonetary assets should be measured based on the fair value of the assets exchanged. Further, SFAS
No. 153 eliminates the narrow exception for nonmonetary exchanges of similar
productive assets and replaces it with a broader exception for exchanges of nonmonetary assets that do not have commercial substance. SFAS No. 153 is effective for nonmonetary asset exchanges
occurring beginning in the third quarter of 2005. 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)

In December 2004, the FASB reissued SFAS No. 123(R), "Share-Based Payment." This is a revision of SFAS No. 123, "Accounting for Stock-Based
Compensation," and supersedes APB No. 25, "Accounting for Stock Issued to Employees." SFAS No. 123(R) establishes accounting standards for transactions in which an entity receives
employee services in exchange for (a) equity instruments of the entity or (b) liabilities that are based on the fair value of the entity's equity instruments or that may be settled by
the issuance of equity instruments. The standard, effective July 1, 2005, will require EME to recognize the grant-date fair value of stock options and equity based compensation
issued to employees in the statement of operations. The statement also requires that such transactions be accounted for using the fair value based method, thereby eliminating use of the intrinsic
value method of accounting in APB No. 25, which was permitted under Statement 123, as originally issued. EME currently uses the intrinsic value accounting method for stock-based compensation.
The difference in expense between the two methods is reflected in the pro forma table in "Stock-Based Compensation" above. EME is currently in the process of evaluating the impact of SFAS
No. 123(R) on its consolidated financial statements and has not yet selected a transition method for adoption of the new standard.

FASB Staff Position FAS 109-1

In December 2004, the FASB issued FASB Staff Position FAS 109-1, "Application of FASB Statement No. 109, "Accounting for Income
Taxes,' to the Tax Deduction on Qualified Production Activities Provided by the American Jobs Creation Act of 2004." The primary objective of this Position is to provide guidance on the application of
SFAS No. 109 to the provision within the American Jobs Creation Act of 2004 that provides a tax deduction on qualified production activities. Under FAS 109-1, recognition of
the tax deduction on qualified production activities, which include the production of electricity, is ordinarily reported in the year it is earned. This FASB Staff Position had no impact on EME's
consolidated financial statements. EME is evaluating the effect that the tax deduction will have in subsequent years.

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Note 3. Inventory

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

2004

2003Coal and fuel oil

$
65

$
83Spare parts, materials and supplies


42


44Total

$
107

$
127


Note 4. Loss on Lease Termination, Asset Impairment and Other Charges

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

Following
the termination of the Collins Station lease, Midwest Generation announced plans on May 28, 2004 to permanently cease operations at the Collins Station by
December 31, 2004 and decommission the plant. By the fourth quarter of 2004, the Collins Station was decommissioned and all units were
permanently retired from service, disconnected from the grid, and rendered inoperable, with all operating permits surrendered. In September 2004, EME recorded a pre-tax impairment
charge of $5 million resulting from the termination of the power purchase agreement effective September 30, 2004 for the two units at 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 marketplace of its eight remaining small peaking units in Illinois. Based on this
analysis and regulatory approval, planning efforts are in progress 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). At September 30, 2004, the fair value of the small peaking units was $3.5 million.

During
2003, EME recorded asset impairment charges of $304 million, consisting of $245 million related to eight small peaking plants owned by Midwest Generation in Illinois
and $53 million and $6 million to write-down the estimated net proceeds from the planned sale of the Brooklyn Navy Yard and Gordonsville projects, respectively. The
impairment charge related to the peaking plants in Illinois resulted from a revised long-term outlook for capacity revenues from the peaking plants. The lower capacity revenue outlook is
the result of a number of factors, including higher long-term natural gas prices and current generation overcapacity. The book value of these assets was written down from

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$286 million
to an estimated fair market value of $41 million. The estimated fair market value was determined based on discounting estimated future pretax cash flows using a 17.5%
discount rate.

During
2002, EME recorded asset impairment and other charges of $131 million, consisting of $61 million relating to the write-off of capitalized costs
associated with the termination of equipment purchase contracts with Siemens Westinghouse, $25 million related to the write-off of capitalized costs associated with the suspension
of the Powerton Station SCR major capital improvement project at the Illinois Plants, and $45 million from a settlement agreement that terminated the obligation to build additional generation
in Chicago.

Note 5. Accumulated Other Comprehensive Income (Loss)

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

|                             |  | Currency
Translation
Adjustments |      | Unrealized Gains
(Losses) on Cash
Flow Hedges |   | Minimum
Pension Liability
Adjustment |   | Accumulated Other
Comprehensive
Income (Loss) |    
|---------------------------- |  | -------------------------------- | ---- | --------------------------------------------- | - | ------------------------------------ | - | --------------------------------------------- | ---
|Balance at December 31, 2003 |  | $                                | 145  |                                               | $ | (159                                 | ) | $                                             | (11
|Current period change        |  |                                  | (145 | )                                             |   | 177                                  |   |                                               | 10 
|                             |  |                                  |      |                                               |   |                                      |   |                                               |    
|Balance at December 31, 2004 |  | $                                |     |                                               | $ | 18                                   |   | $                                             | (1 
|                             |  |                                  |      |                                               |   |                                      |   |                                               |    

---

The amount of commodity hedges included in unrealized gains (losses) on cash flow hedges, net of tax, at December 31, 2004, was a gain of
$26 million. The amount of interest rate hedges included in unrealized gains (losses) on cash flow hedges, net of tax, at December 31, 2004, was a loss of $8 million. Unrealized
gains (losses) included both continuing and discontinued operations as follows:

As
EME's hedged positions for continuing operations are realized, approximately $11 million, after tax, of the net unrealized gains on cash flow hedges at December 31, 2004 are expected
to be reclassified into earnings during the next 12 months. Management expects that reclassification of net unrealized gains will offset energy revenue recognized at market prices. Actual
amounts ultimately reclassified into earnings over the next 12 months could vary materially from this estimated amount as a result of changes in market conditions. The maximum period over which
a cash flow hedge is designated is through December 31, 2006.

The
unrealized losses for discontinued operations were reclassified into earnings upon the completion of the sale of the CBK project in January 2005.

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

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---



recognized
in earnings. EME recorded net gains (losses) of approximately $(13) million, $11 million and $(2) million in 2004, 2003 and 2002, respectively, representing the amount of cash flow
hedges' ineffectiveness for continuing operations, reflected in net gains (losses) from price risk management and energy trading in EME's consolidated income statement.

Interest
rate swaps entered into to hedge the floating interest rate risk on the $385 million term loan qualified for treatment as cash flow hedges under SFAS No. 133 with
appropriate adjustments made to other comprehensive income. At December 31, 2003, MEHC recorded a decrease of approximately $3 million, after tax, to other comprehensive income resulting
from unrealized holding losses on these contracts. On July 2, 2004, the interest rate swaps were terminated. During 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 6. Dispositions of Domestic Investments in Energy Plants

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

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

On
November 21, 2003, Gordonsville Energy Limited Partnership, in which EME owns a 50% interest, completed the sale of the Gordonsville cogeneration facility to Virginia Electric
and Power Company. Proceeds from the sale, including distribution of a debt service reserve fund, were $36 million. EME recorded an impairment charge of $6 million during the second
quarter of 2003 related to the planned disposition of this investment.

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

Note 7. Discontinued Operations

CBK Project

On January 10, 2005, EME completed the sale of 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 completed the sale of 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 a consortium comprised of International Power plc (70%) and Mitsui & Co., Ltd. (30%), referred to as 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.

On
February 3, 2005, EME sold its 25% equity interest in the Tri Energy project to IPM for approximately $20 million.

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Contact Energy

On September 30, 2004, EME completed the sale of 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$1,101.4 million (approximately
US$739 million) in cash and NZ$535 million (approximately US$359 million) of debt assumed by the purchaser.

Lakeland Project

In 2001, EME ceased consolidating the activities of Lakeland Power Ltd. when an administrative receiver was appointed following a default by Norweb
Energi Ltd., the counterparty to a long-term power sales agreement. The consolidated financial statements have been restated to conform to discontinued operations treatment for all
historical periods presented. In 2003, a third party completed the purchase of the Lakeland power plant from the administrative receiver for £24 million. The proceeds from the sale
and existing cash were used to fund partial repayment of the outstanding debt owed to secured creditors of the project. Lakeland Power Ltd.'s administrative receiver has filed a claim against
Norweb Energi Ltd. for termination of the power purchase agreement. Norweb Energi Ltd. is a subsidiary of TXU (UK) Holdings Limited (TXU UK) and is an indirect subsidiary of TXU Europe
Group plc (TXU Europe). On November 19, 2002, TXU UK and TXU Europe, together with a related entity, TXU Europe Energy Trading Limited (TXU Energy), entered into formal administration
proceedings in the United Kingdom (similar to bankruptcy proceedings in the United States). To the extent that Lakeland Power receives payment under its claim, such amounts will first be used to repay
amounts due to its creditors. In October 2004, for approximately £6 million, EME purchased from Lakeland's secured creditors the debt owed them by Lakeland Power. The
purchase of the outstanding bank debt was completed to maximize EME's recovery from the proceeds ultimately received from the claim against Norweb Energi. Based on the settlement of claims currently
being discussed as part of the TXU Europe administration proceeding, the secured debt of Lakeland Power is expected to be repaid in full. In addition, depending on the outcome of the TXU Europe
administration proceedings, EME may receive additional cash from the settlement of the claims.

Ferrybridge and Fiddler's Ferry Plants

On December 21, 2001, EME completed the sale of the Ferrybridge and Fiddler's Ferry coal-fired power plants located in the United Kingdom to
two wholly owned subsidiaries of American Electric Power. In addition, as part of the transactions, the purchasers acquired other assets and assumed specified liabilities associated with the plants.
The sale was the result of a competitive bidding process. EME acquired the plants in 1999 from PowerGen UK plc for £1.3 billion.

Other Projects

On December 12, 2003, EME completed the sale of its 40% interest in a development project in Thailand to a third party. Proceeds from the sale were
$13 million.

Summarized Financial Information for Discontinued Operations

In accordance with SFAS No. 144, all of the projects discussed above are classified as discontinued operations in the accompanying consolidated statements
of income (loss). Previously issued statements of

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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 31,2004

2003

2002Total operating revenues

$
1,281

$
1,403

$
1,111Income before income taxes and minority interest


256


252


91Provision for income taxes


48


90


44Minority interest


51


38


25Income from operations of discontinued foreign subsidiaries


157


124


22Gain on sale before income taxes


532





Gain on sale after income taxes


533








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

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

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

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

December 31,2004

2003Cash and cash equivalents

$
2

$
191Accounts receivabletrade, net of allowance of $6 million in 2003





204Other current assets


2


182Total current assets


4


577Investments in unconsolidated affiliates


107


1,080Net property, plant and equipment





4,413Goodwill





865Other long-term assets





303Total other assets





1,168Assets of discontinued operations

$
111

$
7,238Accounts payable and accrued liabilities

$
1

$
210Interest payable





56Current maturities of long-term obligations





70Other current liabilities





184Total current liabilities


1


520Long-term obligations net of current maturities





2,566Deferred taxes and tax credits





638Deferred revenue


4


488Other long-term liabilities





340Total long-term deferred liabilities


4


1,466Liabilities of discontinued operations

$
5

$
4,552


Assets and liabilities of foreign operations were translated at end of period rates of exchange, and the income statements were translated at the
monthly average rates of exchange. Gains or losses from translation of foreign currency financial statements are included in comprehensive income in shareholder's equity.

Note 8. Investments in Unconsolidated Affiliates

Investments in unconsolidated affiliates, generally 50% or less owned partnerships and corporations, are accounted for by the equity method. These investments are
primarily in energy and oil and gas projects. For 2003 and 2002, 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 and 2002, the summarized financial information also included Gordonsville
Energy and Brooklyn Navy Yard. EME sold its interests in Gordonsville Energy and Brooklyn Navy Yard on November 21, 2003 and March 31, 2004, respectively. Therefore, Gordonsville Energy,
Brooklyn Navy Yard and Four Star Oil & Gas are not included in the balances for 2004. The difference between the carrying value of these investments and the underlying equity in the net assets
amounted to $2 million at December 31, 2004. The differences

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are
being amortized over the life of the energy projects. The following table presents summarized financial information of the investments in unconsolidated affiliates:

2004

2003Investments in Unconsolidated AffiliatesEquity investment

$
428

$
365Loan receivable


26


162Total

$
454

$
527


EME's subsidiaries have provided loans or advances related to certain projects. The loan receivable at December 31, 2004 consists of a
$26 million, 5% interest promissory note, interest payable semiannually, due April 2008.

The
undistributed earnings of investments accounted for by the equity method were $160 million in 2004 and $157 million in 2003.

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, 2004Revenues

$
62Expenses


66Net income

$
(4
)


March 31, 2004Current assets

$
66Noncurrent assets


419Total assets

$
485Current liabilities

$
105Noncurrent liabilities


497Equity


(117
)Total liabilities and equity

$
485


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

Years Ended December 31,2004

2003

2002Revenues

$
1,264

$
1,988

$
1,454Expenses


928


1,529


1,082Income before accounting change


336


459


372Cumulative effect of change in accounting, net of tax





(7
)

Net income

$
336

$
452

$
372


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December 31,2004

2003Current assets

$
624

$
717Noncurrent assets


1,224


1,954Total assets

$
1,848

$
2,671Current liabilities

$
347

$
439Noncurrent liabilities


674


1,418Equity


827


814Total liabilities and equity

$
1,848

$
2,671


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, 2004, 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,
2004 |    | EME's Ownership
Interest at
December 31, 2004 |    | Operating Status
|------------------------- |  | ------------- |  | ------------------------------- | -- | --------------------------------------------- | -- | ----------------
|Sunrise                   |  | Fellows, CA   |  | $                               | 97 |                                               | 50 | %               
|Watson                    |  | Carson, CA    |  |                                 | 88 |                                               | 49 | %               
|March Point               |  | Anacortes, WA |  |                                 | 64 |                                               | 50 | %               
|Midway-Sunset             |  | Fellows, CA   |  |                                 | 51 |                                               | 50 | %               

Note 9. Property, Plant and Equipment

Property, plant and equipment consist of the following:

December 31,2004

2003Power plant facilities

$
1,966

$
2,067Leasehold improvements


80


63Emission allowances


1,305


1,305Construction in progress


33


36Equipment, furniture and fixtures


108


101Capitalized leased equipment


1


13,493


3,573Less accumulated depreciation and amortization


709


564Net property, plant and equipment

$
2,784

$
3,009


In connection with Midwest Generation's financing activities, Midwest Generation has given first and second priority security interests in
substantially all of the facilities owned by Midwest Generation and the assets relating to those plants, including a pledge of the intercompany notes from EME (approximately $1.4 billion at
December 31, 2004). In addition, Edison Mission Marketing & Trading pledged an account representing payables owed to Midwest Generation. The amount of assets pledged or mortgaged totals
approximately $3 billion at December 31, 2004. In addition to these assets, Midwest

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Generation's
membership interests and the capital stock of Edison Mission Midwest Holdings were pledged. Emission allowances were not pledged.

Note 10. 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 the security for MEHC's corporate debt obligations. The senior secured notes and the term loan are non-recourse to Edison
International and EME and its subsidiaries and, accordingly, none of Edison International, EME or EME's subsidiaries has any obligation under the senior secured notes or the term loan. The senior
secured notes and the term loan contain restrictions on MEHC paying dividends unless it has an interest coverage ratio of at least 2.0 to 1.0 as defined in the respective agreements. At
December 31, 2004, its interest coverage ratio was 1.18 to 1.0. At December 31, 2004, recourse debt to EME totaled $1.8 billion and non-recourse project debt totaled
$1.9 billion. At December 31, 2004, 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 31,2004

2003Corporate debt (with recourse to MEHC)MEHC (parent only)Senior Notes, net due 2008 (13.5%)

$
789

$
787Term Loan due 2006
(LIBOR+7.5%) (9.52% at 12/31/04)


282


379RecourseEME (parent only)Senior Notes, netdue 2008 (10.0%)

$
400

$
400due 2009 (7.73%)


598


597due 2011 (9.875%)


600


600Pounds Sterling Coal and Capex Facility due 2004
(Sterling LIBOR+2.25%+0.0098%)
(6.28% at 12/31/03)





28


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---



Long-Term ObligationsAffiliate


78


78Junior Subordinated Debentures


155


155Non-recourse (unless otherwise noted)Due to EME Funding Corp.Long-Term Obligation due 2004-2008 (7.33%)


139


190EME CP Holdings Co.Note Purchase Agreement due 2015 (7.31%)


81


83Edison Mission Midwest Holdings Co.Tranche B due 2004 (LIBOR+2.0%) (3.25% at 12/31/03)





693Midwest Generation, LLCSecond Priority Senior Secured Notes due 2034 (8.75%)


1,000


Credit Agreement due 2011 (LIBOR+3.25%) (5.4% at 12/31/04)


667


Mission Energy Holdings International, Inc.Credit Agreement due 2006 (LIBOR+5.0%) (7.0% at 12/31/03)





796Doga project
Finance Agreement between Doga and OPIC due 2010 (11.2%)





62NCM Credit Agreement due 2010
(U.S. LIBOR+1.25%) (2.31% at 12/31/03)





22Subtotal

$
4,789

$
4,870Less current maturities of long-term obligations


496


785Total

$
4,293

$
4,085


MEHC Term Loan

On April 5, 2004, the lenders under MEHC's $385 million term loan exercised their right to require MEHC to repurchase $100 million of the
principal amount at par on July 2, 2004 (referred to as the "Term Loan Put-Option"). The $100 million of principal, plus interest, was paid on July 2, 2004. The
remaining $285 million of principal, plus interest, was paid on January 3, 2005.

Midwest Generation, LLC Financing

On April 27, 2004, Midwest Generation completed a private offering of $1 billion aggregate principal amount of its 8.75% second priority senior
secured notes due 2034. Holders of the notes may require Midwest Generation to repurchase, or Midwest Generation may elect to repay, the notes on May 1, 2014 and on each one-year
anniversary thereafter at 100% of their principal amount, plus accrued and unpaid interest. Concurrent with the issuance of the notes, Midwest Generation borrowed $700 million under a new first
priority senior secured term loan facility. The term loan has a final maturity of April 27, 2011 and bears interest at LIBOR plus 3.25% per annum. Midwest Generation has agreed to repay
$1,750,000 of the term loan on each quarterly payment date. Midwest Generation also entered into a new five-year $200 million working capital facility that replaced a prior
facility. The new working capital facility also provides for the issuance of letters of credit. As of December 31, 2004, Midwest Generation had no borrowings outstanding under the working
capital facility and had reimbursement obligations under a letter of credit for approximately $3 million that expires in 2005. Midwest Generation used the proceeds of the notes issuance and the
term loan to refinance $693 million of indebtedness (plus accrued interest and fees) owed by its direct parent, Edison Mission Midwest

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Holdings
Co., which had been guaranteed by Midwest Generation and was due in December 2004, and to make the termination payment under the Collins Station lease in the amount of approximately
$960 million.

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

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

Mission Energy Holdings International, Inc. Financing

On December 11, 2003, EME's subsidiary, Mission Energy Holdings International, Inc., received funding under a three-year,
$800 million secured loan from Citigroup, Credit Suisse First Boston, JPMorganChaseBank, and Lehman Brothers. Interest on this secured loan is based on LIBOR (with a LIBOR floor of 2%) plus 5%.
After payment of transaction expenses, a portion of the net proceeds from this financing was used to make an equity contribution of $550 million to Edison Mission Midwest Holdings which,
together with cash on hand, was used to repay Edison Mission Midwest Holdings' $781 million indebtedness due December 11, 2003. The remaining net proceeds from this financing were used
to make a deposit of cash collateral of approximately $67 million under the new letter of credit facility described below and to repay approximately $160 million of indebtedness of a
foreign subsidiary under the Coal and Capex facility guaranteed by EME. Mission Energy Holdings International owns substantially all of EME's international operations through its subsidiary, MECIBV.
During the fourth quarter of 2004, EME repaid the $800 million indebtedness with the majority of the proceeds received from the sale of Contact Energy and cash on hand.

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% (2.32% at December 31, 2004). The note was subsequently exchanged for two notes with the same terms and conditions and
assigned to other subsidiaries of Edison International.

Junior Subordinated Debentures

In November 1994, Mission Capital, L.P., a limited partnership of which EME is the sole general partner, issued 3.5 million 9.875% Cumulative
Monthly Income Preferred Securities, Series A at a price of $25 per security and invested the proceeds in 9.875% junior subordinated deferrable interest debentures due 2024 which were issued by
EME in November 1994. The Series A securities are redeemable at the option of Mission Capital, in whole or in part, with mandatory redemption in 2024 at a redemption price of $25 per
security, plus accrued and unpaid distributions. None of these securities had been redeemed as of December 31, 2004. On January 25, 2005 all of these securities were redeemed

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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. The Series B securities are redeemable at the option of Mission Capital, in whole or in part, with mandatory redemption in
2025 at a redemption price of $25 per security, plus accrued and unpaid distributions. None of these securities had been redeemed as of December 31, 2004. 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. EME issued a guarantee in
favor of the holders of the preferred securities, which guarantees the payments of distributions declared on the preferred securities, payments upon a liquidation of Mission Capital and payments on
redemption with respect to any preferred securities called for redemption by Mission Capital. As described in Note 2Summary of Significant Accounting Policies, EME no longer
consolidates Mission Capital and includes the junior subordinated debentures in its consolidated balance sheet. In January 2005, the junior subordinated debentures were repaid and, in turn, the
Monthly Income Preferred Securities were repurchased.

Coal and Capex Facility

As part of the financing of the Ferrybridge and Fiddler's Ferry plants, EME had entered into a 359 million pounds sterling Coal and Capex Facility due
January 2004 and July 2004, respectively. Following the completion of the sale of the power plants in December 2001, this facility was cancelled. During 2002, EME made total
payments of $86 million from settlement of assets and liabilities of EME's discontinued operations. During 2003, EME made total payments of approximately $160 million with proceeds from
the $800 million credit agreement entered into by Mission Energy Holdings International, Inc. In addition, EME completed the repayment of the remaining $28 million due under the
Coal and Capex facility (guaranteed by EME) in April 2004. Accordingly, this credit agreement has been terminated and EME no longer has a contingent liability related to this credit agreement.

Annual Maturities on Long-Term Debt

Annual maturities on long-term debt at December 31, 2004, for the next five years are summarized as follows:
2005$496 million; 2006$50 million; 2007$132 million; 2008$1.2 billion; and 2009$613 million.

Standby Letters of Credit

As of December 31, 2004, standby letters of credit aggregated to $16 million and were scheduled to expire during 2005.

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 $155 million at December 31, 2004 and $206 million at December 31, 2003. Included in restricted cash are debt service reserves of
$76 million and $102 million at December 31, 2004 and 2003, respectively, and collateral reserves of $79 million and $104 million at December 31, 2004 and
2003, 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.

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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 EME's consolidated balance sheet approximates fair value.
The following table summarizes the carrying amounts and fair values for outstanding non-derivative financial instruments:

December 31, 2004

December 31, 2003Carrying
Amount

Fair Value

Carrying
Amount

Fair ValueInstrumentsNon-derivatives:Long-term obligations

$
4,789

$
5,487

$
4,870

$
4,866


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, including junior subordinated debentures.

Note 11. Risk Management and Derivative Financial Instruments

EME's risk management policy allows for the use of derivative financial instruments to limit financial exposure on EME's investments and to manage exposure from
fluctuations in electricity, 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 tolerance, and procedures exist which allow for
monitoring of all commitments and positions with regular reviews by EME's risk management committee. In order to provide more predictable earnings and cash flow, EME may hedge a portion of the
electric output of its merchant plants. 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

MEHC mitigated the risk of interest rate fluctuations associated with the $385 million term loan ($100 million paid July 2, 2004 and
$285 million paid January 3, 2005) by arranging for variable rate financing with interest rate swaps. Swaps covering interest accrued from January 2, 2002 to January 2,
2003 expired on January 2, 2003. Subsequently, MEHC entered into swaps that covered interest accrued from January 2, 2003 to July 2, 2004 and April 2, 2003 to
July 2, 2004. Under MEHC's variable to fixed swap agreements, MEHC paid counterparties interest at a weighted average fixed rate of 2.84% at December 31, 2003. Counterparties paid MEHC
interest at a weighted average variable rate based on LIBOR of 1.15% at December 31, 2003. MEHC did not enter into any new interest rate swaps associated with the $285 million portion of
the term loan for periods beyond July 2, 2004. The remaining $285 million portion of the term loan was paid on January 3, 2005.

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Interest
rate changes affect the cost of capital needed to operate EME's projects. EME mitigates the risk of interest rate fluctuations by arranging for fixed rate financing or variable
rate financing with interest rate swaps, interest rate options or other hedging mechanisms for a number of EME's project financings.

Credit Risk

In conducting EME's price risk management and trading activities, EME contracts with a number of utilities, energy companies and 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 such counterparty defaulted.

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

EME'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
affect on the operations of such power plant.

In
the past three fiscal years, EME 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. 2004 was the final contract year under these power purchase agreements. Exelon Generation accounted for 36%, 40% and 66% of EME's consolidated operating revenues
in 2004, 2003 and 2002, 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. An investment grade affiliate of BP Energy has guaranteed payment of amounts due under the related contracts.

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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 and instrument type:

December 31, 2004

December 31, 2003Carrying
Amount

Fair Value

Carrying
Amount

Fair ValueCommodity price:Electricity

$
10

$
10

$
(7
)
$
(7
)Interest rate:Interest rate swaps

$


$


$
(5
)
$
(5
)


In assessing the fair value of EME's non-trading derivative financial instruments, EME uses a variety of methods and assumptions based
on the market conditions and associated risks existing at each balance sheet date. The fair value of 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's risk management and trading operations are conducted by its subsidiary, Edison Mission Marketing & Trading. As a result of a number of industry and
credit-related factors, Edison Mission Marketing & Trading has minimized its price risk management and trading activities not related to EME's power plants or investments in energy projects. To
the extent Edison Mission Marketing & Trading engages in trading activities, Edison Mission Marketing & Trading seeks to manage price risk and to create stability of future income by
selling electricity in the forward markets and, to a lesser degree, to generate profit from price volatility of electricity and fuels by buying and selling these commodities in wholesale markets. EME
generally balances forward sales and purchase contracts and manages its exposure through a value at risk analysis.

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

December 31, 2004

December 31, 2003Assets

Liabilities

Assets

LiabilitiesElectricity

$
125

$
36

$
104

$
11Other











1Total

$
125

$
36

$
104

$
12


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.

130

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EME
recorded net gains of approximately $29 million, $40 million and $42 million in 2004, 2003 and 2002, respectively, arising from energy trading activities
reflected in net gains (losses) from price risk management and energy trading in EME's consolidated income statement.

Note 12. Income Taxes

Current and Deferred Taxes

The provision (benefit) for income taxes is comprised of the following:

Years Ended December 31,2004

2003

2002Continuing Operations:CurrentFederal

$
(364
)
$
(112
)
$
(186
)State


(77
)

(49
)

(84
)Foreign


(1
)

6


8Total current


(442
)

(155
)

(262
)DeferredFederal

$
(13
)
$
(24
)
$
156State


(8
)

2


26Foreign





2


(2
)Total deferred


(21
)

(20
)

180Provision (benefit) for income taxes from continuing operations


(463
)

(175
)

(82
)Discontinued operations


47


91


44Change in accounting





(4
)

(9
)Total

$
(416
)
$
(88
)
$
(47
)


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 31,2004

2003

2002Continuing OperationsU.S.

$
(1,134
)
$
(379
)
$
(173
)Foreign


6


12


17Total, continuing operations


(1,128
)

(367
)

(156
)Discontinued operations


788


252


91Change in accounting





(13
)

(23
)Total

$
(340
)
$
(128
)
$
(88
)


131

---



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                    |                                                | $                        | (394
|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 |                          |     
|                                                               | Other                                          |                          |     
|                                                               |                                                |                          |     
|                                                               | Provision (benefit) for income taxes           |                          | $   
|                                                               |                                                |                          |     
|                                                               | Effective tax rate                             |                          |     
|                                                               |                                                |                          |     

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

December 31,2004

2003Deferred tax assetsItems deductible for book not currently deductible for tax

$
67

$
1Net operating losses


3


11Deferred income


3


40Other


1


Subtotal


74


52Valuation allowance


(3
)

(11
)Total


71


41Deferred tax liabilitiesBasis differences

$
246

$
668Tax credits, net


12


13Price risk management


12


(6
)Other


5


22Total


275


697Deferred taxes and tax credits, net

$
204

$
656


State loss carryforwards for various states total $45 million and $189 million at December 31, 2004 and 2003, respectively,
with expiration dates, beginning in 2006. State capital loss carryforwards total $33 million at December 31, 2003.

The
$8 million reversal of valuation allowance is primarily due to the sale of a subsidiary whose state net operating losses were previously determined to be unrealizable.

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.

132

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Note 13. 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, 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 charge to accumulated other comprehensive income would be restored through shareholders' equity in future periods to the extent the fair value of the plan assets exceeds the
accumulated benefit obligation.

The
expected contributions (all by the employer) are approximately $12 million for the year ended December 31, 2005. 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 31,2004

2003Change in projected benefit obligationProjected benefit obligation at beginning of year

$
119

$
104Service cost


16


14Interest cost


7


6Amendments





Actuarial loss


11


2Benefits paid





(7
)Projected benefit obligation at end of year

$
153

$
119Accumulated benefit obligation at end of year

$
123

$
90Change in plan assetsFair value of plan assets at beginning of year

$
53

$
39Actual return on plan assets


7


10Employer contributions


17


11Benefits paid





(7
)Fair value of plan assets at end of year

$
77

$
53Funded status

$
(76
)
$
(66
)Unrecognized net loss


29


23Unrecognized transition obligation





1Unrecognized prior service cost


2


2Recorded liability

$
(45
)
$
(40
)


133

---



Years Ended December 31,2004

2003Additional detail of amounts recognized in balance sheets:Intangible asset

$
1

$
Accumulated other comprehensive income


(2
)

Pension plans with an accumulated benefit obligation in excess of plan assets:Projected benefit obligation

$
99

$
24Accumulated benefit obligation


72


14Fair value of plan assets


45


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


5.50%


6.00%Rate of compensation increase


5.00%


5.00%


Components of pension expense are:

Years Ended December 31,2004

2003

2002Service cost

$
16

$
14

$
13Interest cost


7


6


5Expected return on plan assets


(4
)

(4
)

(3
)Net amortization and deferral


1


2


1Total expense recognized

$
20

$
18

$
16Change in accumulated other comprehensive income

$
(2
)




Weighted-average assumptions:Discount rate


6.00%


6.50%


7.00%Rate of compensation increase


5.00%


5.00%


5.00%Expected return on plan assets


7.50%


8.50%


8.50%


Asset allocations for plans are:

December 31,Target
for 2005

2004

2003United States equity

45%

47%

46%Non-United States equity

25%

25%

26%Private equity

4%

2%

3%Fixed income

26%

26%

25%


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.

134

---



Employees
in union-represented positions at the Illinois Plants were covered by a retirement health care and other benefits plan that expired on June 15, 2002. In
October 2002, Midwest Generation reached an agreement with its union-represented employees on new benefits plans, which extend from January 1, 2003 through June 15, 2006. Midwest
Generation continued to provide benefits at the same level as those in the expired agreement until December 31, 2002. The accounting for postretirement benefits liabilities has been determined
on the basis of a substantive plan under Statement of Financial Accounting Standards No. 106, "Employers' Accounting for Postretirement Benefits Other Than Pensions." A substantive plan means
that Midwest Generation assumed, for accounting purposes, that it would provide for postretirement health care benefits to union-represented employees following conclusion of negotiations to replace
the current benefits agreement, even though Midwest Generation had no legal obligation to do so. Under the new agreement, postretirement health care benefits will not be provided. Accordingly, Midwest
Generation treated this as a plan termination under SFAS No. 106 and recorded a pre-tax gain of $71 million during the fourth quarter of 2002.

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. EME's 2004 expense decreased by approximately $0.4 million as a result of the subsidy.

The
expected contributions (all by the employer) for the postretirement benefits other than pensions are $1 million for the year ended December 31, 2005. 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 31,2004

2003Change in benefit obligationBenefit obligation at beginning of year

$
54

$
57Service cost


2


2Interest cost


3


3Amendments


1


(14
)Actuarial loss (gain)


(1
)

7Benefits paid


(1
)

(1
)Benefit obligation at end of year

$
58

$
54Change 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

$


$



135

---



Funded status

$
(58
)
$
(54
)Unrecognized net loss


14


17Unrecognized prior service cost


(12
)

(15
)Recorded liability

$
(56
)
$
(52
)Assumed health care cost trend rates:Rate assumed for following year


10.00%


12.00%Ultimate rate


5.00%


5.00%Year ultimate rate reached


2010


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


5.75%


6.25%


Expense components of postretirement benefits are:

Years Ended
December 31,2004

2003

2002Service cost

$
2

$
2

$
5Interest cost


3


3


8Settlement








(71
)Net amortization and deferral


(1
)

(1
)

Total expense

$
4

$
4

$
(58
)Assumed health care cost trend rates:Current year


12.00%


9.75%


10.50%Ultimate rate


5.00%


5.00%


5.00%Year ultimate rate reached


2010


2008


2008Weighted-average assumptions:Discount rate


6.25%


6.40%


7.25%


Increasing the health care cost trend rate by one percentage point would increase the accumulated obligation as of December 31, 2004, by
$11 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, 2004, by $9 million and annual aggregate service and interest costs by $1 million.

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.

136

---



Allowable
investment types include:

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 plan's 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.

137

---



Estimated Future Benefits Payable

Estimated future benefits payable under the pension and other postretirement benefits as of December 31, 2004 are as follows:

Years Ended December 31,

Pension Plans

Other
Postretirement
Benefits2005

$
4

$
12006


4


12007


5


12008


6


12009


7


12010-2014


59


11Total

$
85

$
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 $5 million in
2004, $6 million in 2003 and $6 million in 2002.

Note 14. 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 14 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 and 2004 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:

2004

2003

2002Expected years until exercise

9-10

10

7-10Risk-free interest rate

4.0% to 4.3%

3.8% to 4.5%

4.7% to 6.1%Expected dividend yield

2.7% to 3.7%

1.8%

1.8%Expected volatility

19% to 22%

44% to 53%

18% to 54%


The weighted-average fair value of options granted during 2004, 2003 and 2002 was $6.60 per share option, $7.31 per share option and $7.88 per
share option, respectively.

138

---



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, 2001

1,747,011

$
9.10 - $29.34

$
19.07Granted

967,405

$
10.60 - $18.73

$
18.61Transferred from EME to Edison International

(22,046
)
$
9.15 - $28.94

$
21.33Forfeited

(466,382
)
$
9.10 - $29.34

$
20.09Exercised

(44,176
)
$
15.18 - $18.80

$
16.75Outstanding, December 31, 2002

2,181,812

$
9.10 - $28.94

$
18.60Granted

1,020,910

$
11.88 - $18.87

$
12.37Transferred from EME to Edison International

(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 EME to Edison International

(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

$
18.44


A summary of stock options outstanding at December 31, 2004 is as follows:

|      |                 | Outstanding |           | Exercisable
|----- | --------------- | ----------- | --------- | -----------
|
|      | $9.15 -$12.99   |             | 971,912   |            
|      | $13.00 - $18.99 |             | 687,130   |            
|      | $19.00 - $29.09 |             | 1,470,911 |            
|      |                 |             |           |            
|Total |                 | 3,129,953   |           | 7.60       
|      |                 |             |           |            

The number of options exercisable and their weighted-average exercise prices at December 31, 2003 and 2002 were 863,116 at $19.26 and
731,009 at $21.29, respectively.

Other Equity-Based Awards

Performance shares were awarded in January 2002, January 2003 and January 2004 and vest at the end of December 2004, 2005 and 2006,
respectively. The number of common shares paid out from the performance share awards depends on the performance of Edison International common stock relative to the stock performance of a specified
group of companies.

EME
measures compensation expense related to stock-based compensation by the intrinsic value method. Compensation expense recorded under the stock compensation program was approximately

139

---



$24 million,
$11 million and $4 million for the years ended December 31, 2004, 2003 and 2002, respectively.

Note 15. Commitments and Contingencies

Capital Improvements

At December 31, 2004, EME's subsidiaries had firm commitments to spend approximately $25 million on capital expenditures in 2005 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, 2004, EME's subsidiaries had contractual commitments to purchase coal. The remaining contracts' lengths range from one year to eight years.
Based on the contract provisions, which consist of fixed prices, subject to adjustment clauses, these minimum commitments are currently estimated to aggregate $743 million in the next five
years summarized as follows: 2005$326 million; 2006$198 million; 2007$133 million; 2008$54 million; and
2009$32 million.

Fuel Supply Dispute

During 2004, EME Homer City experienced interruptions of supply under two agreements with Unionvale Coal Company and Genesis, Inc. On December 21,
2004, Unionvale and Genesis gave EME Homer City written notice of an event of force majeure at the Genesis No. 17 Mine in Pennsylvania, which is a source of coal under both of the agreements.
The claimed force majeure event is the result of alleged geologic conditions that, in the suppliers' opinion, prevent the delivery of coal under the agreements. These two agreements together provide
for the delivery to EME Homer City of 1,290,000 tons of coal in 2005.

Unionvale
and Genesis also seek to terminate one of the agreements, which was scheduled to run through December 2007, under a provision that allows either party to the agreement
to terminate if an event of force majeure lasts 30 days or more. Unionvale and Genesis allege that the geologic problems encountered at the Mine prevent mining and will continue beyond a
30-day period. The parties' second agreement with a term through December 2006 does not contain a similar termination provision, and the suppliers have requested contract
modifications to the term, quantity, quality and price provisions of the agreement.

EME
Homer City disputes the force majeure claim as it relates to both agreements and has filed suit against Unionvale and Genesis in Pennsylvania state court. EME Homer City's complaint
seeks equitable relief by way of an order requiring the defendants to fulfill their contracted obligations and such other monetary relief as is just and proper. Contracts have been awarded and
inventory strategies adjusted to reflect and offset the delivery shortfall for 2005. As of December 31, 2004, EME Homer City had not contracted for the resultant potential shortfalls in 2006
and 2007.

Gas Transportation Agreements

At December 31, 2004, 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 term of 15 years, is currently estimated to aggregate $40 million in the next five years, 2005 through 2009, $8 million each year.

140

---



Coal Transportation Agreements

At December 31, 2004, EME had contractual commitments for the transport of coal to its facilities. The remaining contracts' lengths range from three years
to seven years. Based on the committed coal volumes in the fuel supply contracts described above, these minimum commitments are currently estimated to aggregate $492 million in the next four
years, summarized as follows: 2005$202 million; 2006$160 million; 2007$94 million; and 2008$36 million.

Other Contractual Obligations

At December 31, 2004, 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 LLC at prices based primarily on operations and maintenance and
fuel costs.

EME
Homer City entered into a Coal Cleaning Agreement with Homer City Coal Processing Corporation to operate and maintain a coal cleaning plant owned by EME Homer City. Under the terms
of the agreement, EME Homer City is obligated to reimburse Homer City Coal Processing Corporation for the actual costs incurred in the operations and maintenance of the coal cleaning plant, a fixed
general and administrative service fee of approximately $260 thousand per year, and an operating fee that ranges from $.20 to $.35 per ton depending on the level of tonnage. The agreement
expired on August 31, 2002 and was renewed with the same terms through December 31, 2005, with a two-year extension option.

At
December 31, 2004, other contractual obligations are summarized as follows: 2005$10 million; 2006$4 million;
2007$4 million; 2008$4 million; and 2009$4 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.

Guarantees and Indemnities

Tax
Indemnity Agreements

In
connection with the sale-leaseback transactions that EME has entered into related to the Collins Station and the Powerton and Joliet Stations in Illinois and the Homer
City facilities in Pennsylvania, EME or one of its subsidiaries entered into tax indemnity agreements. Under these tax indemnity agreements, these entities agreed to indemnify the lessors in the
sale-leaseback transactions for specified adverse tax consequences that could result in certain situations set forth in each tax indemnity agreement, including specified defaults under the
respective leases. The potential indemnity obligations under these tax indemnity agreements could be significant. Due to the nature of these potential obligations, EME cannot determine a maximum
potential liability which would be triggered by a valid claim from the lessors. EME has not recorded a liability related to these indemnities. In connection with the termination of the lease for the
Collins Station (See Note 4Loss on Lease Termination, Asset

141

---



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 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 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 130 and 170 cases for which Midwest Generation was potentially liable and that had not been settled and dismissed by the end of 2004. At December 31,
2004, Midwest Generation had $9 million recorded as a liability for asserted claims related to this matter and had made $5 million in payments through December 31, 2004.

In
view of its experience since 2003, Midwest Generation engaged an independent actuary in the fourth quarter of 2004 to determine if a reasonable estimate of future losses could be made
based on claims and other available information. After review, the actuary determined that an estimate could be prepared, and, accordingly, Midwest Generation engaged the actuary to complete an
estimate of future losses. Based on the actuary's analysis, Midwest Generation recorded an undiscounted $56 million pre-tax charge for its indemnity for future asbestos claims
through 2045. 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 no asbestos claims will be filed after 2045.

The
$56 million pre-tax charge was recorded as part of plant operations on EME's consolidated income statement and reduced net income by $34 million. Midwest
Generation anticipates obtaining periodic updates of the estimate of future losses. On a quarterly basis, Midwest Generation will monitor actual experience against the number of forecasted claims to
be received and expected claim payments. Adjustments to the estimate will be recorded quarterly, if necessary.

The
amounts recorded by Midwest Generation for the asbestos-related liability were based upon known facts at the time the report was prepared. Projecting future events, such as the
number of new

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

Indemnities
Provided under Asset Sale Agreements

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. 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, 2004, EME had recorded a liability of $87 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 holds 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 2006. At December 31, 2004, EME had recorded a liability of $11 million related to this indemnity.

Capacity
Indemnification Agreements

EME
has guaranteed, jointly and severally with Texaco Inc., the obligations of March Point Cogeneration Company under its project power sales agreements to repay capacity payments
to the project's power purchaser in the event that the power sales agreements terminate, March Point

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Cogeneration
Company abandons the project, or the project fails to return to normal operations within a reasonable time after a complete or partial shutdown, during the term of the power contracts. In
addition, subsidiaries of EME have guaranteed the obligations of Kern River Cogeneration Company and Sycamore Cogeneration Company under their project power sales agreements to repay capacity payments
to the projects' power purchaser in the event that the projects unilaterally terminate their performance or reduce their electric power producing capability during the term of the power contracts. The
obligations under the indemnification agreements as of December 31, 2004, if payment were required, would be $153 million. EME has no reason to believe that any of these projects will
either cease operations or reduce its electric power producing capability during the term of its power contract. EME has not recorded a liability related to this indemnity.

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

Legal Developments Affecting Sunrise Power Company

Sunrise Power Company, in which EME's wholly owned subsidiary owns a 50% interest, sells all its output to the California Department of Water Resources. On
May 15, 2002, Sunrise Power Company was served with a complaint filed in the Superior Court of the State of California, City and County of San Francisco, by James M. Millar, "individually, and
on behalf of the general public and as a representative taxpayer suit" against sellers of long-term power to the California Department of Water Resources, including Sunrise Power Company.
The lawsuit alleges that the defendants, including Sunrise Power Company, engaged in unfair and fraudulent business practices by knowingly taking advantage of a manipulated power market to obtain
unfair contract terms. The lawsuit seeks to enjoin enforcement of the "unfair and oppressive terms and conditions" in the contracts, as well as restitution by the defendants of excessive monies
obtained by the defendants. Plaintiffs in several other class action lawsuits pending in Northern California have filed petitions seeking to have the Millar lawsuit consolidated with those lawsuits.
In December 2003, James Millar filed a First Amended Class Action and Representative Action Complaint which contains allegations similar to those in the earlier complaint but also alleges a
class action. One of the newly added parties removed the lawsuit to federal court, and the court ordered remand to the San Francisco Superior Court. Defendants expect to file a responding
pleading by April 2005. EME believes that the outcome of this litigation will not have a material adverse effect on its consolidated financial position or results of operations.

Regulatory Developments Affecting Doga Project

On August 4, 2002, a new Electricity Market License Regulation was implemented in Turkey. The new regulation contains, among other things, a requirement
that each generator obtain a generation license. Historically, Doga's Implementation Contract has been its sole license. The new regulation contemplates an initial fixed license fee and a yearly
license fee based on the amount of energy

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generated,
which will increase the project's costs of operation by an undetermined amount. In addition, the new regulation allows the possibility of insertion of provisions in a new license which may
be different from those in the Implementation Contract.

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

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

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

Litigation

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

Environmental Matters and Regulations

Introduction

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

Typically,
environmental laws and regulations require a lengthy and complex process for obtaining licenses, permits and approvals prior to construction, operation or modification of a
project or generating

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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.

StateIllinois

Air Quality

In June 2001, Illinois passed legislation mandating the Illinois Environmental Protection Agency, or Illinois EPA, to evaluate and issue a report to the
Illinois legislature addressing the need for further emissions controls on fossil fuel-fired electric generating stations, including the potential need for additional controls on nitrogen
oxides, sulfur dioxide and mercury. The report was issued on September 30, 2004. The report concluded, "It is clear that power plant emissions are a considerable source of air pollution and
that reducing emissions will benefit public health. However, moving forward with a state-specific regulatory or legislation strategy without fully understanding all the critical impacts on jobs and
Illinois' economy overall as well as consumer utility rates and reliability of the power grid would be irresponsible." Consequently, the Illinois EPA recommended "that the Governor continue demanding
that the federal government act nationally to reduce power plant emissions. Further, the Illinois EPA recommends that the Governor insist that the competing issues of health, jobs, electric service
reliability and affordable consumer rates be fully and completely reconciled in light of the many unanswered questions presented in this report. While this work is already underwayand
will continueit can ultimately only be completed once the national emission reduction strategy solidifies and the timing and features of a national program are known." While the law
allows the Illinois EPA to propose regulations based on its findings no sooner than 90 days after the issuance of its findings, and requires the Illinois Pollution Control Board to act within
one year on such proposed regulations, the report's recommendations indicate that the State will focus its efforts on impacting the federal regulatory process rather than recommending state-specific
regulations. At this time, EME cannot
evaluate the potential impact of State action on EME's facilities since it will depend on the content of federal regulations.

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 (SIP). This regulation is a State of Illinois requirement. Compliance with this standard was met by each of
EME's Illinois power plants in 2004. Beginning with the 2004 ozone season, Midwest Generation facilities 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 current SO2 (acid rain) trading program already in
effect. EME has already 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 EME stations stayed within their NOx allocations by augmenting their allocation with early reduction credits generated within the fleet. In 2005, the Illinois
EME stations will use banked allowances, along with some purchased allowances, to stay within their NOx allocations. After 2005, EME plans to continue to purchase allowances while evaluating various
technologies to determine whether any additional pollution controls should be installed at the Illinois facilities.

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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. One of the limitations for discharges to the river that could be made more stringent if the existing use classification is changed would be the temperature of the discharges from the Joliet
and Will County plants. 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. At this time no standards have been proposed, so EME cannot estimate the financial impact of this review. However, the
cost of additional cooling water treatment, if required, could be substantial.

StatePennsylvania

Water Quality

The discharge from the treatment plant receiving the wastewater stream from EME's Unit 3 flue gas desulfurization system at the Homer City facilities has exceeded
the stringent, water-quality based limits for selenium in the station's NPDES permit. As a result, EME was notified in April 2002 by the Pennsylvania Department of Environmental Protection
(PADEP) that it has been included in the Quarterly Noncompliance Report submitted to the United States Environmental Protection Agency (US EPA). EME has met with the contractor responsible for the
Unit 3 flue gas desulfurization system to discuss approaches to resolving the water quality issues and is investigating technical alternatives for maximizing the level of selenium removal in the
discharge. EME has also discussed these approaches for resolving the water quality issues with PADEP. While pilot studies have been completed which have improved the performance of the treatment
system, the discharge has not been able to consistently meet its effluent limitation. Chemicals are being added to the system to continue to improve its performance which has come very close to
meeting the very tight water quality based limitation. Plans are being made to conduct an additional pilot test if the new chemical addition procedure fails to achieve consistent compliance. After the
station achieves consistent compliance, EME will meet with PADEP to discuss the drafting of a consent agreement to address the selenium issue and then instruct the contractor to make the necessary
improvements. The consent agreement may include the payment of civil penalties, but the amount cannot be estimated at this time.

FederalUnited States of America

Clean Air Act

EME expects that compliance with the Clean Air Act and the regulations and revised State Implementation Plans developed as a consequence of the Act will result in
increased capital expenditures and operating expenses. EME's approach to meeting these obligations will consist of a blending of capital expenditure and emission allowance purchases that will be based
on an ongoing assessment of the dynamics of its market conditions.

Mercury Regulation

In December 2000, the US EPA announced its intent to regulate mercury emissions and other hazardous air pollutants from coal-fired electric
power plants under Section 112 of the Clean Air Act, and indicated that it would propose a rule to regulate these emissions. On January 30, 2004, US EPA

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published
rules for regulating mercury emissions from coal fired power plants. US EPA proposed two rule options for public comment: 1) regulate mercury as a hazardous air pollutant under Clean
Air Act Sec. 112(d); or 2) rescind US EPA's December 2000 finding regarding a need to control coal power plant mercury emissions as a hazardous air pollutant, and instead,
promulgate a new "cap and trade" emissions regulatory program to reduce mercury emissions in two phases by years 2010 and 2018. On March 16, 2004, the US EPA published a Supplemental Notice of
Proposed Rulemaking that provides more details on its emissions cap and trade proposal for mercury, and on November 30, 2004, the US EPA issued a Notice of Data Availability (NODA) requesting comments
on additional modeling and other data the US EPA was considering in development of its final rule. The NODA public comment period closed on January 2, 2005. At this time, the US EPA anticipates
finalizing the regulations on March 15, 2005, with controls required to be in place on existing units by March 15, 2008 (if the technology-based standard is chosen) and 2010 (when Phase I of the cap
and trade approach would be implemented if this approach is chosen).

Management's
preliminary estimate is that the anticipated mercury regulations, along with the other Clean Air Act developments described below, may require EME to spend approximately
$300 million for capital improvements at its Homer City facilities in the 2006-2010 timeframe, although the timing will depend on which mercury proposal is adopted. Until the
mercury regulations are finalized, EME cannot determine the potential impact of these regulations on the operations of its other facilities. Additional capital costs, particularly on the Illinois coal
units, related to these regulations could be required in the future and they could be material, depending upon the final standards adopted by the US EPA.

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.

In
December 2003, the US EPA proposed rules that would require states to revise their implementation plans to address alleged contributions to downwind areas that are not in
attainment with the revised standards for ozone and fine particulate matter. The proposed "Clean Air Interstate Rule" is designed to be completed before states must revise their implementation plans
to address local reductions needed to meet the new ozone and fine particulate matter standards. The proposed rule would establish a two-phase, regional cap and trade program for sulfur
dioxide and nitrogen oxide. The proposed rule would affect 27 states, including Illinois and Pennsylvania. The proposed rule would require sulfur dioxide emissions and nitrogen oxide emissions
to be reduced in two phases (by 2010 and 2015), with emissions reductions for each pollutant of 65% by 2015.

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On March 10, 2005, the acting administrator of the US EPA signed the final Clean Air Interstate Rule. According to information provided by the US EPA, Phase I nitrogen oxides reductions
would come into effect in 2009 rather than 2010. In addition, the emissions budgets for sulfur dioxides and nitrogen oxides in the final rule appear to have been slightly modified from the proposed
regulation. EME has not had an opportunity to review the text of the final Clean Air Interstate Rule regulation. In addition, any additional obligations on EME's facilities to further reduce their
emissions of sulfur dioxide, nitrogen oxides 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 financial impacts resulting from required capital
improvements or operational changes.

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. 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

On November 3, 1999, the United States Department of Justice filed the first of a number of suits against electric utilities and power generating
facilities for alleged violations of the Clean Air Act's "new source review" (NSR) requirements related to modifications of air emissions sources at electric generating stations. In addition to the
suits filed, US EPA has issued a number of administrative Notices of Violation to electric utilities alleging NSR violations. EME and its subsidiaries have not 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.

Several
of the named utilities have reached formal agreements or agreements-in-principle with the United States to resolve alleged NSR violations. These
settlements involved installation of additional pollution controls, supplemental environment projects, and the payment of civil penalties. The agreements provided for a phased approach to achieving
required emission reductions over the next 10 to 15 years, and some called for the retirement or repowering of coal-fired generating units. The total cost of some of these
settlements exceeded $1 billion; the civil penalties agreed to by these utilities generally range between $1 million and $10 million. Because of the uncertainty created by the
Bush administration's review of the NSR regulations and NSR enforcement proceedings, some of these settlements have not been finalized. However, the Department of Justice review released in
January 2002 concluded "EPA has a reasonable basis for arguing that the enforcement actions are consistent with both the Clean Air Act and the Administrative Procedure Act." No change in the
Department of Justice's position regarding pending NSR legal actions has been announced as a result of US EPA's proposed NSR reforms (discussed immediately below).

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On
December 31, 2002, the US EPA finalized a rule to improve the NSR program. This rule is intended to provide additional flexibility with respect to NSR by, among other things,
modifying the method by which a facility calculates the emissions' increase from a plant modification; exempting, for a period of ten years, units that have complied with NSR requirements or otherwise
installed pollution control technology that is equivalent to what would have been required by NSR; and allowing a facility to make modifications without being required to comply with NSR if the
facility maintained emissions below plant-wide applicability limits. Although states, industry groups and environmental organizations have filed litigation challenging various aspects of
the rule, it became effective March 3, 2003. To date, the rule remains in effect, although the pending litigation could still result in changes to the final rule.

A
federal district court, ruling on a lawsuit filed by US EPA, found on August 7, 2003, that the Ohio Edison Company violated requirements of the NSR within the Clean Air Act by
upgrading certain coal-fired power plants without first obtaining the necessary pre-construction permits. On August 26, 2003, another federal district court ruling in an
NSR enforcement action against Duke Energy Corporation, adopted a different interpretation of the NSR provisions that could limit liability for similar upgrade projects. This decision is currently on
appeal before the United States Court of Appeals for the Fourth Circuit.

On
October 27, 2003, US EPA issued a final rule revising its regulations to define more clearly a category of activities that are not subject to NSR requirements under the
"routine maintenance, repair and replacement" exclusion. This clearer definition of "routine maintenance, repair and replacement,"
would provide EME greater guidance in determining what investments can be made at its existing plants to improve the safety, efficiency and reliability of its operations without triggering NSR
permitting requirements, and might mitigate the potential impact of the Ohio Edison decision. However, on December 24, 2003, the United States Court of Appeals for the D.C. Circuit blocked
implementation of the "routine maintenance, repair and replacement" rule, pending further judicial review.

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. Midwest Generation has provided
responses to several portions of this request and, in cooperation with Commonwealth Edison, is obtaining the data necessary for the final response. Under date of February 1, 2005, US EPA
submitted a request for some additional information to Midwest Generation. Midwest Generation is currently collecting available information responsive to this request. 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.

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

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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 substantially
reduce 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 NPDES 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 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 aforementioned legal challenges 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 certain pollutants from electric
utility generating stations. These bills would mandate reductions in emissions of nitrogen oxides, sulfur dioxide and mercury. Some bills would also impose limitations on carbon dioxide emissions. The
various proposals differ in many details, including the timing of any required reductions; the extent of required reductions; and the relationship of any new obligations that would be imposed by these
bills with existing legal requirements. There is significant uncertainty as to whether any of the proposed legislative initiatives will pass in their current
form or whether any compromise can be reached that would facilitate passage of legislation. Accordingly, EME is not able to evaluate the potential impact of these proposals at this time.

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

With
respect to EME's 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 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 "Commercial CommitmentsGuarantees and Indemnities" for a discussion of these indemnities.

Climate Change

Since the adoption of the United Nations Framework Convention on Climate Change in 1992, there has been worldwide attention with respect to greenhouse gas
emissions. In December 1997, the Clinton administration participated in the Kyoto, Japan negotiations, where the basis of a Climate Change treaty was formulated. Under the treaty, known as the
Kyoto Protocol, the United States would be required, by 2008-2012, to reduce its greenhouse gas emissions by 7% from 1990 levels. As a result of Russia's ratification of the Kyoto Protocol
in December 2004, the Protocol officially came into effect on February 16, 2005.

EME
has an equity interest in and operates the Doga generating plant in Turkey. Turkey is classified as an Annex 1 or "developed" country and is subject to national greenhouse gas
emission reduction targets during the period of 2008-2012 (i.e., Phase 1). To date, Turkey has not yet ratified the Kyoto Protocol. Because Turkey is anxious to be admitted as a member of
the European Union and the

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European
Union is such a proponent of the Protocol, it is expected that the European Union will exert pressure on Turkey to ratify the Protocol.

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

In
addition, there have been several petitions from states and other parties to compel the US EPA to regulate greenhouse gases under the Clean Air Act. The US EPA denied on
September 3, 2003, a petition by Massachusetts, Maine and Connecticut to compel US EPA under the Clean Air Act to require US EPA to establish a national ambient air quality standard for carbon
dioxide. Since that time, 11 states and other entities have filed suits against US EPA in the United States Court of Appeals for the D.C. Circuit (D.C. Circuit). The D.C. Circuit has granted
intervention requests from 10 states that support US EPA's ruling. The D.C. Circuit has not yet ruled on this matter.

On
July 21, 2004, Connecticut, New York, California, Iowa, New Jersey, Rhode Island, Vermont, Wisconsin, the City of New York and certain environmental organizations brought
lawsuits 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. The lawsuits seek
injunctive relief in the form of a mandatory cap on carbon dioxide emissions to be phased in over several years. The defendants in these suits have filed motions to dismiss, which have not yet been
ruled upon by the court. Neither EME nor its subsidiaries have been named as defendants in these lawsuits.

The
ultimate outcome of the climate change debate could have a significant economic effect on EME. Any legal obligation that would require EME to substantially reduce 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 16. 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, 2004, are:

Years Ending December 31,

Operating
Leases2005

$
3172006


3552007


3532008


3522009


348Thereafter


3,300Total future commitments

$
5,025


Operating lease expense amounted to $210 million, $234 million and $227 million in 2004, 2003 and 2002, 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 2005, $152 million in 2006,
$151 million in 2007, $152 million in 2008, $151 million in 2009, and the total remaining minimum lease payments are $2.1 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 $141 million in 2005,
$185 million in 2006, $185 million in 2007, $185 million in 2008, $185 million in 2009, and the total remaining minimum lease payments are $1.1 billion. The gain on
the sale of the power facilities has been deferred and is being amortized over the term of the leases.

Note 17. 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

154

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reasonable.
MEHC made reimbursements for the cost of these programs and other services, which amounted to $60 million, $63 million and $53 million in 2004, 2003 and 2002,
respectively. At December 31, 2004 and 2003, the amount due to Edison International was $26 million and $3 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 benefits applicable to continuing operations of $441 million, $161 million and $270 million for 2004, 2003 and 2002, respectively. See
Note 12Income Taxes. Amounts included in Accounts receivableaffiliates associated with these tax benefits totaled $89 million and $18 million at
December 31, 2004 and 2003, respectively.

Edison
Mission Operation & Maintenance, Inc., an indirect, wholly owned affiliate of EME, has entered into operation and maintenance agreements with partnerships in which
EME has a 50% or less ownership interest. Pursuant to the negotiated agreements, Edison Mission Operation & Maintenance is to perform all operation and maintenance activities necessary for the
production of power by these partnerships' facilities. The agreements continue until terminated by either party. Edison Mission Operation & Maintenance is paid for all costs incurred with
operating and maintaining such facilities 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, $24 million and $22 million in 2004, 2003 and 2002, respectively. Accounts receivableaffiliates for Edison Mission Operation & Maintenance totaled
$6 million at December 31, 2004 and 2003.

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 $824 million, $754 million and
$548 million in 2004, 2003 and 2002, respectively.

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Note 18. Supplemental Statements of Cash Flows Information

Years Ended December 31,2004

2003

2002Cash paidInterest (net of amount capitalized)

$
452

$
427

$
420Income taxes (receipts)


(16
)

(163
)

(478
)Cash payments under plant operating leases


240


271


272Details of assets acquiredFair value of assets acquired

$


$
3

$
Liabilities assumed








Net cash paid for acquisitions

$


$
3

$
Non-cash activities from de-consolidation of variable interest entityAssets

$
133





Liabilities


165








Note 19. Quarterly Financial Data (unaudited)

|2004                                     |  | First |     | Second |   | Third(i) |       | Fourth |     | Total |  
|---------------------------------------- |  | ----- | --- | ------ | - | -------- | ----- | ------ | --- | ----- | -
|Operating revenues                       |  | $     | 389 |        | $ | 359      |       | $      | 509 |       | $
|Operating income (loss)                  |  |       | (16 | )      |   | (976     | )(ii) |        | 95  | (iii) |  
|Income (loss) from continuing
operations |  |       | (39 | )      |   | (636     | )(ii) |        | 61  | (iii) |  
|Discontinued operations, net(vii)        |  |       | 46  |        |   | 26       |       |        | 498 | (vi)  |  
|Net income (loss)                        |  |       | 7   |        |   | (610     | )     |        | 559 |       |  
|
|Operating revenues                       |  | $     | 402 |        | $ | 388      |       | $      | 633 |       | $
|Operating income (loss)                  |  |       | (15 | )      |   | (265     | )(v)  |        | 216 |       |  
|Income (loss) from continuing
operations |  |       | (54 | )      |   | (192     | )(v)  |        | 138 |       |  
|Discontinued operations, net(vii)        |  |       | 22  |        |   | 1        |       |        | 38  |       |  
|Income (loss) before accounting
change   |  |       | (32 | )      |   | (191     | )     |        | 176 |       |  
|Net income (loss)                        |  |       | (41 | )      |   | (191     | )     |        | 176 |       |  






156

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157

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PART III

ITEM 10.    DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANT

Positions with Mission Energy Holding Company

Listed below are MEHC's directors and executive officers and their ages and positions as of March 1, 2005.

|Name, Position and Age                                                  |  | Director
Continuously
Since |  | Term
Expires |  | Position Held
Continuously
Since |  | Term
Expires
|----------------------------------------------------------------------- |  | --------------------------- |  | ------------ |  | -------------------------------- |  | ------------
|John E. Bryson, 61
Director, Chairman of the Board                      |  | 2001                        |  | 2005         |  |                                 |  |            
|Frank B. Bilotta, 44
Director                                           |  | 2001                        |  | 2005         |  |                                 |  |            
|Bryant C. Danner, 67(1)
Director                                        |  | 2001                        |  | 2005         |  |                                 |  |            
|Thomas R. McDaniel, 55
Director, Chief Executive Officer and President  |  | 2005                        |  | 2005         |  | 2005                             |  | 2005        
|Barbara Mathews, 52
Secretary and Assistant General Counsel             |  |                            |  |             |  | 2001                             |  | 2005        
|Kevin M. Smith, 46(2)
Senior Vice President and Chief Financial Officer |  |                            |  |             |  | 2001                             |  | 2005        
|Raymond W. Vickers, 62
Senior Vice President and General Counsel        |  |                            |  |             |  | 2001                             |  | 2005        

---

Business Experience

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

Mr. 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. 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 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.

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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. Dannerhas been director of Mission Energy Holding Company since June 2001. Mr. Danner has been director of
Edison Mission Energy since May 1993. Mr. Danner has been executive vice president and general counsel of Edison International since June 1995.

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

Ms. Mathewshas been secretary and assistant general counsel of Mission Energy Holding Company since June 2001.
Ms. Mathews has been an associate general counsel for Edison International and Southern California Edison Company since April 2002. Ms. Mathews was an assistant general counsel of
Edison International and Southern California Edison from August 1996 through April 2002.

Mr. Smithhas been senior vice president and chief financial officer of Mission Energy Holding Company since September 2001.
Mr. Smith has been senior vice president and chief financial officer of Edison Mission Energy since May 1999. Mr. Smith has also served as treasurer of Edison Mission Energy from
September 1992 to February 2000 and from May 2002 until June 2004.

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. Prior to joining Edison Mission Energy, Mr. Vickers was a partner with
the law firm of Skadden, Arps, Slate, Meagher & Flom LLP concentrating on international business transactions, particularly cross-border capital markets and investment transactions, project
implementation and finance.

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.

Code of Business Conduct and Ethics for Principal Officers

Mission Energy Holding Company has adopted a Code of Business Conduct and Ethics that applies to its principal executive officer, principal financial officer,
principal accounting officer or controller, or persons performing similar functions. The Code of Business Conduct and Ethics is posted under the heading "Corporate Governance" on the Internet website
maintained by Mission Energy Holding Company's parent, Edison International, at www.edisoninvestor.com. Any amendment to or waiver from a

159

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provision
of the Code of Business Conduct and Ethics 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 Form 10-K for the year ended
December 31, 2004 and the Summary Compensation Table
in the Executive Compensation section of Edison International's Proxy Statement relating to its 2005 Annual Meeting of Shareholders, respectively, which are incorporated by reference.

Compensation of Directors

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

For information concerning the number of equity securities of Edison International beneficially owned by all directors and executive officers of
EME and Edison International, individually and as a group, see Item 12 of EME's Form 10-K for the year ended December 31, 2004 and the table entitled "Stock Ownership of
Directors and Executive Officers" of Edison International's Proxy Statement relating to its 2005 Annual Meeting of Shareholders, respectively, which are incorporated by reference.

ITEM 13.    CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS

None.

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ITEM 14.    PRINCIPAL ACCOUNTING FEES AND SERVICES

INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM FEES

The following table sets forth the aggregate fees billed to Mission Energy Holding Company (consolidated total including Mission Energy Holding Company and its
subsidiaries), for the fiscal years ended December 31, 2004 and December 31, 2003, by PricewaterhouseCoopers LLP:

Mission Energy Holding
Company and Subsidiaries
($000)2004

2003Audit Fees

$
4,611

$
2,555Audit Related Fees(1)


204


551Tax Fees(2)


2,123


1,318Totals

$
6,938

$
4,424


---

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 Mission Energy Holding
Company and its subsidiaries have been approved by the Edison International Audit Committee.

During
the fiscal year ended December 31, 2004, 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.

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PART IV

ITEM 15.    EXHIBITS AND FINANCIAL STATEMENT SCHEDULES

|(a) |  | (1) |  | List of Financial Statements                                                                                                                                                                                                                               
|--- |  | --- |  | -----------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
|    |  |     |  | See Index to Consolidated Financial Statements at Item 8 of this report.                                                                                                                                                                                   
|    |  | (2) |  | List of Financial Statement Schedules                                                                                                                                                                                                                      
|    |  |     |  | The following items are filed as a part of this report pursuant to Item 15(d) of Form 10-K:                                                                                                                                                                
|
|    |  |     |  |                                                                                                                                                                                                                                                            
|    |  |     |  | Investment in Unconsolidated Affiliates Financial Statements:                                                                                                                                                                                              
|    |  |     |  |                                                                                                                                                                                                                                                            
|    |  |     |  |                                                                                                                                                                                                                                                            
|    |  |     |  |                                                                                                                                                                                                                                                            
|    |  |     |  |                                                                                                                                                                                                                                                            
|    |  |     |  |                                                                                                                                                                                                                                                            
|    |  |     |  | Schedule ICondensed Financial Information of Parent                                                                                                                                                                                                       
|    |  |     |  | Schedule IIValuation and Qualifying Accounts                                                                                                                                                                                                              
|    |  |     |  | All other schedules have been omitted since the required information is not present in amounts sufficient to require submission of the schedule, or because the required information is included in the consolidated financial statements or notes
thereto.



|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.                                                                                         
|            |  |                                                                                                                                                                                                                                                                                                              

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|2.5   |  | Agreement relating to the sale and purchase of the business carried on at Fiddler's Ferry Power Station, Warrington, Cheshire, dated October 6, 2001, among Edison First Power Limited, AEP Energy Services UK Generation Limited, AEPR Global
Holland Holding BV, and American Electric Power Company, Inc., incorporated by reference to Exhibit 2.12 to Edison Mission Energy's Form 8-K dated December 21, 2001.       
|----- |  | ---------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
|2.6   |  | Agreement relating to the sale and purchase of the business carried on at Ferrybridge "C" Power Station, Knottingley, West Yorkshire, dated October 6, 2001, among Edison First Power Limited, AEP Energy Services UK Generation Limited, AEPR Global
Holland Holding BV, and American Electric Power Company, Inc., incorporated by reference to Exhibit 2.13 to Edison Mission Energy's Form 8-K dated December 21, 2001.
|2.7   |  | 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.                                                                                                                                                                                                       
|2.8   |  | 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.                                                                                                                                            
|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.                                                                                                             
|      |  |                                                                                                                                                                                                                                                                                                                                                                                                                            

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|4.3   |  | Indenture Escrow and Security Agreement, dated as of July 2, 2001, by and among Mission Energy Holding Company, Wilmington Trust Company, as Trustee, and Wilmington Trust Company, as Indenture Escrow Agent, incorporated by reference to
Exhibit 4.3 to Mission Energy Holding Company's Registration Statement on Form S-4 to the Securities and Exchange Commission on August 29, 2001.                                                                                                                          
|----- |  | ----------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
|4.4   |  | Amended and Restated Credit Agreement, dated as of July 3, 2001, by and among Mission Energy Holding Company, the lenders party thereto from time to time, Goldman Sachs Credit Partners L.P., as sole Lead Arranger, as Administrative Agent and as
Term Loan Collateral Agent, and Lehman Commercial Paper Inc., as Syndication Agent, incorporated by reference to Exhibit 4.4 to Mission Energy Holding Company's Registration Statement on Form S-4 to the Securities and Exchange
Commission on August 29, 2001.
|4.5   |  | Loan Escrow and Security Agreement, dated as of July 2, 2001, by and among Mission Energy Holding Company, Goldman, Sachs & Co., as Collateral Agent, Goldman Sachs Credit Partners L.P., as Administrative Agent, and Wilmington Trust
Company, as Loan Escrow Agent, incorporated by reference to Exhibit 4.5 to Mission Energy Holding Company's Registration Statement on Form S-4 to the Securities and Exchange Commission on August 29, 2001.                                                                  
|4.6   |  | Pledge and Security Agreement, dated as of July 2, 2001, by and among Mission Energy Holding Company, Goldman Sachs Credit Partners L.P., as Administrative Agent, and Wilmington Trust Company, as Trustee and Joint Collateral Agent, incorporated
by reference to Exhibit 4.6 to Mission Energy Holding Company's Registration Statement on Form S-4 to the Securities and Exchange Commission on August 29, 2001.                                                                                                 
|4.7   |  | Indenture, dated as of August 10, 2001, among Edison Mission Energy and The Bank of New York as Trustee, incorporated by reference to Exhibit 4.1 to Edison Mission Energy's Registration Statement on Form S-4 to the Securities and
Exchange Commission on August 29, 2001.                                                                                                                                                                                                                                         
|4.7.1 |  | Form of 10% Senior Note due 2008 (included in Exhibit 4.1 to Edison Mission Energy's Registration Statement on Form S-4 to the Securities and Exchange Commission on August 29, 2001).                                                                                                                                                                                                                                                                                                                                
|4.8   |  | Registration Rights Agreement, dated as of August 7, 2001, among Edison Mission Energy, Credit Suisse First Boston Corporation, BMO Nesbitt Burns Corp., Salomon Smith Barney Inc., SG Cowen Securities Corporation, TD Securities
(USA) Inc. and Westdeutsche Landesbank Girozentrale (Düsseldorf), incorporated by reference to Exhibit 4.2 to Edison Mission Energy's Registration Statement on Form S-4 to the Securities and Exchange Commission on August 29,
2001.                                             
|4.9   |  | Indenture, dated as of April 5, 2001, among Edison Mission Energy and United States Trust Company of New York as Trustee, incorporated by reference to Exhibit 4.20 to Edison Mission Energy's and Midwest Generation LLC's Registration
Statement on Form S-4 to the Securities and Exchange Commission on April 20, 2001.                                                                                                                                                                                           
|4.9.1 |  | Form of 9.875% Senior Note due 2011 (included in Exhibit 4.2 to Edison Mission Energy's Registration Statement on Form S-4 to the Securities and Exchange Commission on April 24, 2001).                                                                                                                                                                                                                                                                                                                              
|      |  |                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                       

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|4.10   |  | Registration Rights Agreement, dated as of April 2, 2001, among Edison Mission Energy and Credit Suisse First Boston Corporation and Westdeutsche Landesbank Girozentrale (Düsseldorf) as representatives of the Initial Purchasers,
incorporated by reference to Exhibit 4.2 to Edison Mission Energy's Registration Statement on Form S-4 to the Securities and Exchange Commission on April 24, 2001.                                                                                                                                                                                                                   
|------ |  | ---------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
|4.11   |  | Guarantee, dated as of August 17, 2000, made by Edison Mission Energy, as Guarantor in favor of Powerton Trust I, as Owner Lessor, incorporated by reference to Exhibit 4.9 to Edison Mission Energy's and Midwest Generation LLC's Registration
Statement on Form S-4 to the Securities and Exchange Commission on April 20, 2001.                                                                                                                                                                                                                                                                                        
|4.11.1 |  | Schedule identifying substantially identical agreement to Guarantee constituting Exhibit 4.11 hereto, incorporated by reference to Exhibit 4.9.1 to Edison Mission Energy's and Midwest Generation LLC's Registration Statement on Form S-4
to the Securities and Exchange Commission on April 20, 2001.                                                                                                                                                                                                                                                                                                                   
|4.12   |  | Guarantee, dated as of August 17, 2000, made by Edison Mission Energy, as Guarantor in favor of Joliet Trust I, as Owner Lessor, incorporated by reference to Exhibit 4.10 to Edison Mission Energy's and Midwest Generation LLC's Registration
Statement on Form S-4 to the Securities and Exchange Commission on April 20, 2001.                                                                                                                                                                                                                                                                                         
|4.12.1 |  | Schedule identifying substantially identical agreement to Guarantee constituting Exhibit 4.12 hereto, incorporated by reference to Exhibit 4.10.1 to Edison Mission Energy's and Midwest Generation LLC's Registration Statement on
Form S-4 to the Securities and Exchange Commission on April 20, 2001.                                                                                                                                                                                                                                                                                                                  
|4.13   |  | Registration Rights Agreement, dated as of August 17, 2000, among Edison Mission Energy, Midwest Generation, LLC and Credit Suisse First Boston Corporation and Lehman Brothers Inc., as representatives of the Initial Purchasers, incorporated
by reference to Exhibit 4.11 to Edison Mission Energy's and Midwest Generation LLC's Registration Statement on Form S-4 to the Securities and Exchange Commission on April 20, 2001.                                                                                                                                                                                      
|4.14   |  | Participation Agreement (T1), dated as of August 17, 2000, by and among, Midwest Generation, LLC, Powerton Trust I, as the Owner Lessor, Wilmington Trust Company, as the Owner Trustee, Powerton Generation I, LLC, as the Owner Participant, Edison
Mission Energy, United States Trust Company of New York, as the Lease Indenture Trustee, and United States Trust Company of New York, as the Pass Through Trustees, incorporated by reference to 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.
|4.14.1 |  | Schedule identifying substantially identical agreement to Participation Agreement constituting Exhibit 4.14 hereto, incorporated by reference to Exhibit 4.12.1 to Edison Mission Energy's and Midwest Generation LLC's Registration Statement
on Form S-4 to the Securities and Exchange Commission on April 20, 2001.                                                                                                                                                                                                                                                                                                    
|4.15   |  | Participation Agreement (T1), dated as of August 17, 2000, by and among, Midwest Generation, LLC, Joliet Trust I, as the Owner Lessor, Wilmington Trust Company, as the Owner Trustee, Joliet Generation I, LLC, as the Owner Participant, Edison
Mission Energy, United States Trust Company of New York, as the Lease Indenture Trustee and United States Trust Company of New York, as the Pass Through Trustees, incorporated by reference to Exhibit 4.13 to Edison Mission Energy's and Midwest
Generation LLC's Registration Statement on Form S-4 to the Securities and Exchange Commission on April 20, 2001.     
|       |  |                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                            

165

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|4.15.1 |  | Schedule identifying substantially identical agreement to Participation Agreement constituting Exhibit 4.15 hereto, incorporated by reference to Exhibit 4.13.1 to Edison Mission Energy's and Midwest Generation LLC's Registration Statement
on Form S-4 to the Securities and Exchange Commission on April 20, 2001.                                                                                                                                                                                                                         
|------ |  | ------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
|4.16   |  | 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.                                                                                                                                                                                                                                                                
|4.16.1 |  | 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.                                                                                                                                                                                                     
|4.17   |  | 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.                                                                                                                                                                                                                                   
|4.18   |  | 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.                                                                                                                                                                                                                                                                                                  
|4.18.1 |  | Schedule identifying substantially identical agreements to Promissory Note constituting Exhibit 4.18 hereto, incorporated by reference to Exhibit 4.14 to Edison Mission Energy's Form 10-K for the year ended December 31,
2000.                                                                                                                                                                                                                                                                                                               
|4.19   |  | 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.
|4.19.1 |  | Schedule identifying substantially identical agreements to Participation Agreement constituting Exhibit 4.19 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.                                                                                                                                                                                                                                                                                           
|4.19.2 |  | Appendix A (Definitions) to the Participation Agreement constituting Exhibit 4.19 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.                                                                                                                                                                                                                                                                                                                      
|4.20   |  | 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.                                                                                                                                                                                                             
|4.20.1 |  | Schedule identifying substantially identical agreements to Open-End Mortgage, Security Agreement and Assignment of Rents constituting Exhibit 4.20 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.                                                                                                                                                                                                                                                     
|       |  |                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                 

166

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|10.1  |  | Transition Power Purchase Agreement, dated August 1, 1998, between New York State Electric & Gas Corporation and Mission Energy Westside, Inc, incorporated by reference to Exhibit 10.52 to Edison Mission Energy's Form 10-K for
the year ended December 31, 1998.                                                                                                                                                                                                                                         
|----- |  | -------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
|10.2  |  | 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.                                                                                                                                                                                                                     
|10.3  |  | 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.                                                                                                                                
|10.4  |  | 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.                                                                                                                                                                                                         
|10.5  |  | Intercompany Loan Subordination Agreement, dated March 18, 1999, among Edison Mission Holdings Co., Edison Mission Finance Co., Homer City Property Holdings, Inc., Chestnut Ridge Energy Co., Mission Energy Westside, Inc., EME Homer
City Generation L.P. and United States Trust Company of New York, incorporated by reference to Exhibit 10.60.3 to Amendment No. 2 of Edison Mission Holdings Co.'s Registration Statement on Form S-4 to the Securities and Exchange
Commission on February 29, 2000.
|10.6  |  | 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.                                                                                                                                          
|10.7  |  | 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.                                                                                                                                                                                                                                                                      
|10.8  |  | Credit Agreement, dated December 11, 2003, among Mission Energy Holdings International, Inc., Initial Lenders and Citicorp North America, Inc. as Administrative Agent, incorporated by reference to Exhibit 10.1 to Edison Mission
Energy's Form 8-K dated December 11, 2003.                                                                                                                                                                                                                               
|10.9  |  | Credit Agreement, dated as of April 27, 2004, among Edison Mission Energy, the Lenders referred to therein, the Issuing Lenders referred to therein and Citicorp North America, Inc., as Administrative Agent for the Lenders and the Issuing
Lenders party thereto, incorporated by reference to Exhibit 10.13 to Edison Mission Energy's Form 10-Q for the quarter ended March 31, 2004.                                                                                                                   
|10.10 |  | Security Agreement, dated as of April 27, 2004, between Edison Mission Energy and Citicorp North America, Inc., as Administrative Agent, incorporated by reference to Exhibit 10.14 to Edison Mission Energy's Form 10-Q for the
quarter ended March 31, 2004.                                                                                                                                                                                                                                               
|      |  |                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                              

167

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|10.11**   |  | Executive Supplemental Benefit Program as amended January 30, 1990, incorporated by reference to Exhibit 10.2 Edison International's Form 10-Q for the quarter ended September 30, 1999 (File No. 1-9936).                                                        
|--------- |  | ------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
|10.12**   |  | Executive Disability and Survivor Benefit Program effective January 1, 1994, incorporated by reference to Exhibit 10.22 to Edison International's Form 10-K for the year ended December 31, 1994 (File No. 1-9936).                                               
|10.13**   |  | Terms and conditions for 1993-1995 long-term compensation awards under the Officer Long-Term Incentive Compensation Plan, incorporated by reference to Exhibit 10.21.1 to Edison International's Form 10-K for the year ended December 31,
1995 (File No. 1-9936).
|10.14**   |  | Executive Grantor Trust Agreement dated August 1995, incorporated by reference to Exhibit 10.12 to Edison International's Form 10-K for the year ended December 31, 1995 (File No. 1-9936).                                                                       
|10.14.1** |  | Executive Grantor Trust Agreement Amendment 2002-1, effective May 14, 2002, incorporated by reference to Exhibit 10.3 to Edison International's Form 10-Q for the quarter ended June 30, 2002 (File No. 1-9936).                                                  
|10.15**   |  | Executive Deferred Compensation Plan as amended and restated January 1, 1998, incorporated by reference to Exhibit 10. 2 to Edison International's Form 10-Q for the quarter ended March 31, 1998 (File No. 1-9936).                                              
|10.15.1** |  | Executive Deferred Compensation Plan Amendment No. 1 effective January 1, 2003, incorporated by reference to Exhibit 10.2 to Edison International's Form 10-Q for the quarter ended March 31, 1998 (File
No. 1-9936).                                             
|10.16**   |  | Executive Retirement Plan as restated April 1, 1999, incorporated by reference to Exhibit 10.1 to Edison International's Form 10-Q for the quarter ended September 30, 1999 (File No. 1-9936).                                                                    
|10.16.1** |  | Executive Retirement Plan Amendment 2001-1, incorporated by reference to Exhibit 10.1 to Edison International's Form 10-Q for the quarter ended March 31, 2001 (File No. 1-9936).                                                                                 
|10.16.2** |  | Executive Retirement Plan Amendment 2002-1 effective January 1, 2003, incorporated by reference to Exhibit 10.10.2 to Edison International's Form 10-K for the year ended December 31, 2002 (File No. 1-9936).                                                    
|10.17**   |  | Estate and Financial Planning Program as amended April 23, 1999, incorporated by reference to Exhibit to Form 10-Q filed by Edison International for the quarter ended June 30, 1999 (File No 1-9936).                                                            
|10.18**   |  | Executive Incentive Compensation Plan effective January 1, 1997, incorporated by reference to Exhibit 10.12 to Edison International's Form 10-K for the year ended December 31, 1997 (File No. 1-9936).                                                           
|10.19**   |  | Officer Long-Term Incentive Compensation Plan as amended January 1, 1998, incorporated by reference to Exhibit 10.3 to Edison International's Form 10-Q for the quarter ended March 31, 1998 (File No. 1-9936).                                                   
|10.20**   |  | Equity Compensation Plan as restated effective January 1, 1998, incorporated by reference to Exhibit 10.1 to Edison International's Form 10-Q for the quarter ended June 30, 1998 (File No. 1-9936).                                                              
|          |  |                                                                                                                                                                                                                                                                   

168

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|10.20.1** |  | Equity Compensation Plan Amendment No. 1 effective May 18, 2000, incorporated by reference to Exhibit 10.3 to Edison International's Form 10-Q for the quarter ended June 30, 2000 (File No. 1-9936).                                                             
|--------- |  | ------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
|10.21**   |  | Option Gain Deferral Plan as restated September 15, 2000, incorporated by reference to Exhibit 10.25 to Edison International's Form 10-K for the year ended December 31, 2000 (File No. 1-9936).                                                                  
|10.22**   |  | Terms and conditions for 1996 long-term compensation awards under the Officer Long-Term Incentive Compensation Plan, incorporated by reference to Exhibit 10.16.2 to Edison International's Form 10-K for the year ended December 31, 1996
(File No. 1-9936).     
|10.23**   |  | Terms and conditions for 1997 long-term compensation awards under the Officer Long-Term Incentive Compensation Plan, incorporated by reference to Exhibit 10.16.3 to Edison International's Form 10-K for the year ended December 31, 1997
(File No. 1-9936).     
|10.24**   |  | Terms and conditions for 1998 long-term compensation awards under the Equity Compensation Plan, incorporated by reference to Exhibit 10.4 to Edison International's Form 10-Q for the quarter ended June 30, 1998 (File
No. 1-9936).                              
|10.25**   |  | Terms and conditions for 1999 long-term compensation awards under the Equity Compensation Plan, incorporated by reference to Exhibit 10.1 to Edison International's Form 10-Q for the quarter ended March 31, 1999 (File
No. 1-9936).                             
|10.26**   |  | Terms and conditions for 2000 basic long-term incentive compensation awards under the Equity Compensation Plan, as restated, incorporated by reference to Exhibit 10.2 to Edison International's Form 10-Q for the quarter ended March 31,
2000 (File No. 1-9936).
|10.27**   |  | Form of Agreement for 2000 Employee Awards under the Equity Compensation Plan, incorporated by reference to Exhibit 10.78 to Edison Mission Energy's Form 10-Q for the quarter ended March 31, 2000.                                                              
|10.28**   |  | Terms and conditions for 2000 special stock option awards under the Equity Compensation Plan and 2000 Equity Plan, incorporated by reference to Exhibit 10.2 to Edison International's Form 10-Q for the quarter ended June 30, 2000 (File
No. 1-9936).           
|10.29**   |  | Restatement of Terms of 2000 basic long-term incentive awards under the Equity Compensation Plan or the 2000 Equity Plan, incorporated by reference to Exhibit 10.2 to Edison International's Form 10-Q for the quarter ended March 31,
2001 (File No. 1-9936).   
|10.30**   |  | Edison International 2000 Equity Plan, effective May 18, 2000, incorporated by reference to Exhibit 10.1 to Edison International's Form 10-Q for the quarter ended June 30, 2000 (File No. 1-9936).                                                               
|10.31**   |  | Option Gain Deferral Plan as restated September 15, 2000, incorporated by reference to Exhibit 10.27 to Edison International's Form 10-K for the year ended December 31, 2000 (File No. 1-9936).                                                                  
|10.32**   |  | Terms of 2001 basic long-term incentive awards under the Equity Compensation Plan or the 2000 Equity Plan, incorporated by reference to Exhibit 10.3 to Edison International's Form 10-Q for the quarter ended March 31, 2001 (File
No. 1-9936).                  
|10.33**   |  | Terms of 2001 special long-term incentive awards under the Equity Compensation Plan or the 2000 Equity Plan, incorporated by reference to Exhibit 10.4 to Edison International's Form 10-Q for the quarter ended March 31, 2001 (File
No. 1-9936).                
|          |  |                                                                                                                                                                                                                                                                   

169

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|10.34** |  | Terms of 2001 retention incentives under the Equity Compensation Plan, incorporated by reference to Exhibit 10.5 to Edison International's Form 10-Q for the quarter ended March 31, 2001 (File No. 1-9936).                                                                                  
|------- |  | ----------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
|10.35** |  | Terms of 2002 stock option and performance share awards under the Equity Compensation Plan or the 2000 Equity Plan, incorporated by reference to Exhibit 10.1 to Edison International's Form 10-Q for the quarter ended March 31, 2002
(File No. 1-9936).                                     
|10.36** |  | Terms of 2003 stock option and performance share awards under the Equity Compensation Plan or the 2000 Equity Plan, incorporated by reference to Exhibit 10.1 to Edison International's Form 10-Q for the quarter ended March 31, 2003
(File No. 1-9936).                                     
|10.37** |  | Terms and conditions for 2004 long-term compensation awards under the Equity Compensation Plan and the 2000 Equity Plan, incorporated by reference to Exhibit 10.12 to Edison International's Form 10-Q for the quarter ended March 31,
2004 (File No. 1-9936).                               
|10.38** |  | Edison Mission Energy Exchange Offer Circular, dated as of July 3, 2000, incorporated by reference to Exhibit 10.93 to Edison Mission Energy's Form 10-K for the year ended December 31, 2001.                                                                                                
|10.39** |  | Edison Mission Energy Option Exchange Offer Summary of Deferred Compensation Alternatives, dated as of July 3, 2000, incorporated by reference to Exhibit 10.94 to Edison Mission Energy's Form 10-K for the year ended December 31,
2001.                                                    
|10.40** |  | Terms and conditions for 2001 exchange offer deferred stock units under the Equity Compensation Plan, incorporated by reference to Attachment C of Exhibit (a)(1) to Edison International's Schedule TO-I dated October 26, 2001 (File
No. 1-9936).                                           
|10.41** |  | Executive Severance Plan as adopted effective January 1, 2001, incorporated by reference to Exhibit 10.34 to Edison International's Form 10-K for the year ended December 31, 2001 (File No. 1-9936).                                                                                         
|10.42** |  | Performance and Retention Incentive Agreement between Thomas R. McDaniel and Edison Mission Energy, incorporated by reference to Exhibit 10.108 to Edison Mission Energy's Form 10-K for the year ended December 31, 2002.                                                                    
|10.43** |  | Appendix A to the Edison International Affiliate Option Deferred Compensation Plan effective August 7, 2000, applicable to Edison Mission Energy employees in Singapore, incorporated by reference to Exhibit 10.55 to Edison Mission Energy's
Form 10-K for the year ended December 31, 2003.
|10.44** |  | Edison Mission Energy BV Sale Incentive Plan, effective as of February 19, 2004, incorporated by reference to Exhibit 10.1 to Edison Mission Energy's Form 10-Q for the quarter ended March 31, 2004.                                                                                         
|10.45** |  | Edison Mission Energy BV Sale Severance Plan, effective as of February 19, 2004, incorporated by reference to Exhibit 10.2 to Edison Mission Energy's Form 10-Q for the quarter ended March 31, 2004.                                                                                         
|10.46** |  | Edison Mission Energy BV Sale Incentive PlanAustralia, effective as of February 19, 2004, incorporated by reference to Exhibit 10.3 to Edison Mission Energy's Form 10-Q for the quarter ended March 31, 2004.                                                                               
|10.47** |  | Edison Mission Energy BV Sale Retention PlanAustralia, effective as of February 19, 2004, incorporated by reference to Exhibit 10.4 to Edison Mission Energy's Form 10-Q for the quarter ended March 31, 2004.                                                                               
|        |  |                                                                                                                                                                                                                                                                                               

170

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|10.48** |  | Edison Mission Energy BV Sale Severance PlanAustralia, effective as of February 19, 2004, incorporated by reference to Exhibit 10.5 to Edison Mission Energy's Form 10-Q for the quarter ended March 31, 2004.                                       
|------- |  | ------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
|10.49** |  | Edison Mission Energy BV Sale Incentive PlanSingapore, effective as of February 19, 2004, incorporated by reference to Exhibit 10.6 to Edison Mission Energy's Form 10-Q for the quarter ended March 31, 2004.                                       
|10.50** |  | Edison Mission Energy BV Sale Retention PlanSingapore, effective as of February 19, 2004, incorporated by reference to Exhibit 10.7 to Edison Mission Energy's Form 10-Q for the quarter ended March 31, 2004.                                       
|10.51** |  | Edison Mission Energy BV Sale Severance PlanSingapore, effective as of February 19, 2004, incorporated by reference to Exhibit 10.8 to Edison Mission Energy's Form 10-Q for the quarter ended March 31, 2004.                                       
|10.52** |  | Edison Mission Energy BV Sale Incentive PlanUK, effective as of February 19, 2004, incorporated by reference to Exhibit 10.9 to Edison Mission Energy's Form 10-Q for the quarter ended March 31, 2004.                                              
|10.53** |  | Edison Mission Energy BV Sale Retention PlanUK, effective as of February 19, 2004, incorporated by reference to Exhibit 10.10 to Edison Mission Energy's Form 10-Q for the quarter ended March 31, 2004.                                             
|10.54** |  | Edison Mission Energy BV Sale Severance PlanUK, effective as of February 19, 2004, incorporated by reference to Exhibit 10.11 to Edison Mission Energy's Form 10-Q for the quarter ended March 31, 2004.                                             
|10.55   |  | 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.     
|10.56   |  | 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.                                                                                                                                                                                                         

---

171

---



The
financial statements referred to in (a)(2) above represent the entities, or a combination of those entities, that are Investments in Unconsolidated Affiliates, which were 50% or less
owned by EME and
that met the requirements of Rule 3-09 of Regulation S-X. Financial statements with respect to PT Paiton Energy which meet the requirements of Rule 3-09 of
Regulation S-X are to be filed by amendment no later than 90 days after December 31, 2004 as permitted for non-accelerated filers. Financial statements with respect to ISAB Energy S.r.l. which meet
the definition of a foreign business as defined in Rule 1-02(l) of Regulation S-X are to be filed by amendment not later than six months after December 31,
2004 pursuant to Rule 3-09 of Regulation S-X.

172

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Report of Independent Registered Public Accounting Firm

To the Board of Directors of
Edison Mission Energy and ChevronTexaco Corporation

In
our opinion, the accompanying combined balance sheets and the related combined statements of comprehensive income, cash flows and changes in equity present fairly, in all material
respects, the combined financial position of Kern River Cogeneration Company, Sycamore Cogeneration Company, Coalinga Cogeneration Company, Mid-Set Cogeneration Company, Salinas River
Cogeneration Company, Sargent Canyon Cogeneration Company, Sunrise Power Company, LLC, and Mission de las Estrellas, LLC (together, the California Power Group) at
December 31, 2004 and 2003, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2004 in conformity with accounting
principles generally accepted in the United States of America. These financial statements are the responsibility of the California Power Group's management. Our responsibility is to express an opinion
on these financial statements based on our audits. We conducted our audits of these statements in accordance with 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 2 to the combined financial statements, the California Power Group changed the manner in which it accounts for asset retirement costs as of January 1,
2003.

|                                  |  | PricewaterhouseCoopers LLP
|--------------------------------- |  | --------------------------
|Irvine, California
March 14, 2005 |  |                           

173

---





CALIFORNIA POWER GROUP  COMBINED BALANCE SHEETS  December 31, 2004 and 2003  (In thousands)

|                                                        |                                                    | 2004            |         | 2003  
|------------------------------------------------------- | -------------------------------------------------- | --------------- | ------- | ------
|Assets                                                  |                                                    |                 |         |       
|Current assets                                          |                                                    |                 |         |       
|                                                        | Cash and cash equivalents                          |                 | $       | 24,233
|                                                        | Restricted cash                                    |                 |         | 28,641
|                                                        | Trade receivables                                  |                 |         |       
|                                                        |                                                    | Related party   |         |       
|                                                        |                                                    | Other           |         |       
|                                                        | Inventories                                        |                 |         | 17,912
|                                                        | Fair value of gas swaps                            |                 |         | 13,680
|                                                        | Prepaids and other current assets                  |                 |         | 2,182 
|                                                        |                                                    |                 |         |       
|                                                        |                                                    |                 | 195,524 |       
|                                                        |                                                    |                 |         |       
|Property, plant and equipment, net                      |                                                    |                 | 595,053 |       
|                                                        |                                                    |                 |         |       
|Other assets                                            |                                                    |                 |         |       
|                                                        | Restricted cash                                    |                 |         | 34,606
|                                                        | Fair value of gas swaps, net of current portion    |                 |         | 9,378 
|                                                        | Deferred financing costs, net                      |                 |         | 5,921 
|                                                        | Water entitlement, net                             |                 |         | 6,169 
|                                                        | Notes receivable, net of current portion           |                 |         | 3,871 
|                                                        | Emission credits, net                              |                 |         | 2,472 
|                                                        |                                                    |                 |         |       
|                                                        |                                                    |                 | 62,417  |       
|                                                        |                                                    |                 |         |       
|                                                        |                                                    | $               | 852,994 |       
|                                                        |                                                    |                 |         |       
|Liabilities and Equity                                  |                                                    |                 |         |       
|Current liabilities                                     |                                                    |                 |         |       
|                                                        | Current portion of project financing loans payable |                 | $       | 36,432
|                                                        | Accounts payable                                   |                 |         |       
|                                                        |                                                    | Related party   |         |       
|                                                        |                                                    | Trade and other |         |       
|                                                        | Accrued interest                                   |                 |         | 3,514 
|                                                        |                                                    |                 |         |       
|                                                        |                                                    |                 | 139,026 |       
|Project financing loans payable, net of current portion |                                                    |                 | 257,646 |       
|Long-term liabilities                                   |                                                    |                 | 168     |       
|Asset retirement obligation                             |                                                    |                 | 16,212  |       
|                                                        |                                                    |                 |         |       
|                                                        |                                                    |                 | 413,052 |       
|Commitments and contingencies (Notes 7 and 8)           |                                                    |                 |         |       
|Equity                                                  |                                                    |                 | 439,942 |       
|                                                        |                                                    |                 |         |       
|                                                        |                                                    | $               | 852,994 |       
|                                                        |                                                    |                 |         |       

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

174

---



CALIFORNIA POWER GROUP  COMBINED STATEMENTS OF COMPREHENSIVE INCOME  Years Ended December 31, 2004, 2003 and 2002  (In thousands)

|                                                                              |                                                    | 2004 |         | 2003    |   | 2002    |        
|----------------------------------------------------------------------------- | -------------------------------------------------- | ---- | ------- | ------- | - | ------- | -------
|Operating revenues                                                            |                                                    |      |         |         |   |         |        
|                                                                              | Sales of energy                                    |      | $       | 657,698 |   | $       | 618,350
|                                                                              | Sales of steam                                     |      |         | 193,234 |   |         | 160,715
|                                                                              |                                                    |      |         |         |   |         |        
|                                                                              |                                                    |      | 850,932 |         |   | 779,065 |        
|                                                                              |                                                    |      |         |         |   |         |        
|Operating expenses                                                            |                                                    |      |         |         |   |         |        
|                                                                              | Fuel expense                                       |      |         | 468,064 |   |         | 417,723
|                                                                              | Other operating expenses                           |      |         | 56,847  |   |         | 42,290 
|                                                                              | Administrative and general expenses                |      |         | 13,184  |   |         | 11,101 
|                                                                              | Depreciation, amortization and accretion           |      |         | 31,965  |   |         | 28,652 
|                                                                              | Asset impairment loss                              |      |         | 4,000   |   |         |       
|                                                                              |                                                    |      |         |         |   |         |        
|                                                                              |                                                    |      | 574,060 |         |   | 499,766 |        
|                                                                              |                                                    |      |         |         |   |         |        
|                                                                              | Income from operations                             |      |         | 276,872 |   |         | 279,299
|                                                                              |                                                    |      |         |         |   |         |        
|Other income (expense)                                                        |                                                    |      |         |         |   |         |        
|                                                                              | Interest and other income                          |      |         | 2,214   |   |         | 707    
|                                                                              | Interest expense                                   |      |         | (23,182 | ) |         | (7,468 
|                                                                              |                                                    |      |         |         |   |         |        
|                                                                              |                                                    |      | (20,968 | )       |   | (6,761  | )      
|                                                                              |                                                    |      |         |         |   |         |        
|Income before change in accounting principle                                  |                                                    |      | 255,904 |         |   | 272,538 |        
|                                                                              |                                                    |      |         |         |   |         |        
|Cumulative effect of change in accounting for asset retirement costs (Note 2) |                                                    |      |        |         |   | (9,156  | )      
|                                                                              |                                                    |      |         |         |   |         |        
|Net income                                                                    |                                                    |      | 255,904 |         |   | 263,382 |        
|                                                                              |                                                    |      |         |         |   |         |        
|Other comprehensive income                                                    |                                                    |      |         |         |   |         |        
|                                                                              | Unrealized holding gain arising during the period  |      |         | 12,408  |   |         | 7,072  
|                                                                              | Reclassification adjustment included in net income |      |         | (7,168  | ) |         | 8,038  
|                                                                              |                                                    |      |         |         |   |         |        
|                                                                              |                                                    |      | 5,240   |         |   | 15,110  |        
|                                                                              |                                                    |      |         |         |   |         |        
|Comprehensive income                                                          |                                                    | $    | 261,144 |         | $ | 278,492 |        
|                                                                              |                                                    |      |         |         |   |         |        

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

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CALIFORNIA POWER GROUP  COMBINED STATEMENTS OF CASH FLOWS  Years Ended December 31, 2004, 2003 and 2002  (In thousands)

|                                     |                                                                              | 2004                                                |                             | 2003     |        | 2002    |         
|------------------------------------ | ---------------------------------------------------------------------------- | --------------------------------------------------- | --------------------------- | -------- | ------ | ------- | --------
|Cash flows from operating activities |                                                                              |                                                     |                             |          |        |         |         
|                                     | Net income                                                                   |                                                     | $                           | 255,904  |        | $       | 263,382 
|                                     | Adjustments to reconcile net income to cash provided by operating activities |                                                     |                             |          |        |         |         
|                                     |                                                                              | Cumulative effect of change in accounting principle |                             |          |       |         |         
|                                     |                                                                              | Unrealized loss (gain) on derivative instruments    |                             |          | 5,023  |         |         
|                                     |                                                                              | Depreciation, amortization and accretion            |                             |          | 31,969 |         |         
|                                     |                                                                              | Asset impairment loss                               |                             |          | 4,000  |         |         
|                                     |                                                                              | Amortization of deferred financing cost             |                             |          | 866    |         |         
|                                     |                                                                              | Changes in assets and liabilities                   |                             |          |        |         |         
|                                     |                                                                              |                                                     | Trade and other receivables |          |        | (19,791 | )       
|                                     |                                                                              |                                                     | Inventories                 |          |        | 3,545   |         
|                                     |                                                                              |                                                     | Prepaids and other assets   |          |        | 99      |         
|                                     |                                                                              |                                                     | Other assets                |          |        |        |         
|                                     |                                                                              |                                                     | Accounts payable            |          |        | 20,339  |         
|                                     |                                                                              |                                                     | Accrued interest            |          |        | (355    | )       
|                                     |                                                                              |                                                     | Unearned revenue            |          |        |        |         
|                                     |                                                                              |                                                     | Long-term liabilities       |          |        | (67     | )       
|                                     |                                                                              |                                                     |                             |          |        |         |         
|                                     | Cash provided by operating activities                                        |                                                     |                             | 301,532  |        |         | 301,013 
|                                     |                                                                              |                                                     |                             |          |        |         |         
|Cash flows from investing activities |                                                                              |                                                     |                             |          |        |         |         
|                                     | Capital expenditures, net                                                    |                                                     |                             | (2,719   | )      |         | (95,939 
|                                     | Changes in restricted cash                                                   |                                                     |                             | (4,754   | )      |         | (57,948 
|                                     |                                                                              |                                                     |                             |          |        |         |         
|                                     | Cash used by investing activities                                            |                                                     |                             | (7,473   | )      |         | (153,887
|                                     |                                                                              |                                                     |                             |          |        |         |         
|Cash flows from financing activities |                                                                              |                                                     |                             |          |        |         |         
|                                     | Proceeds from issuance of long term debt                                     |                                                     |                             |         |        |         | 345,000 
|                                     | Loan repayments                                                              |                                                     |                             | (33,327  | )      |         | (27,495 
|                                     | Debt issuance costs                                                          |                                                     |                             | (17      | )      |         | (7,053  
|                                     | Issuance of notes receivable, net                                            |                                                     |                             | (633     | )      |         | (3,822  
|                                     | Contributions from partners                                                  |                                                     |                             |         |        |         | 93,984  
|                                     | Distributions to partners                                                    |                                                     |                             | (269,650 | )      |         | (550,430
|                                     |                                                                              |                                                     |                             |          |        |         |         
|                                     | Cash used for financing activities                                           |                                                     |                             | (303,627 | )      |         | (149,816
|                                     |                                                                              |                                                     |                             |          |        |         |         
|Cash and cash equivalents            |                                                                              |                                                     |                             |          |        |         |         
|                                     | Net decrease                                                                 |                                                     |                             | (9,568   | )      |         | (2,690  
|                                     | Beginning of year                                                            |                                                     |                             | 33,801   |        |         | 36,491  
|                                     |                                                                              |                                                     |                             |          |        |         |         
|                                     | End of year                                                                  |                                                     | $                           | 24,233   |        | $       | 33,801  
|                                     |                                                                              |                                                     |                             |          |        |         |         
|Supplemental cash flow information:  |                                                                              |                                                     |                             |          |        |         |         
|                                     | Cash paid during the year for interest                                       |                                                     | $                           | 22,667   |        | $       | 3,359   

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

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CALIFORNIA POWER GROUP  COMBINED STATEMENTS OF CHANGES IN EQUITY  Years Ended December 31, 2004, 2003 and 2002  (In thousands)

|                              |  | Edison
Mission
Energy
affiliates |          | Chevron
Texaco
affiliates |   | Total    |  
|----------------------------- |  | -------------------------------- | -------- | ------------------------- | - | -------- | -
|Balances at December 31, 2001 |  | $                                | 399,829  |                           | $ | 356,599  |  
|Cash distributions            |  |                                  | (204,100 | )                         |   | (204,100 | )
|Cash contributions            |  |                                  | 33,925   |                           |   | 33,925   |  
|Net income                    |  |                                  | 105,162  |                           |   | 105,162  |  
|                              |  |                                  |          |                           |   |          |  
|Balances at December 31, 2002 |  |                                  | 334,816  |                           |   | 291,586  |  
|Cash distributions            |  |                                  | (275,215 | )                         |   | (275,215 | )
|Cash contributions            |  |                                  | 46,992   |                           |   | 46,992   |  
|Net income                    |  |                                  | 131,691  |                           |   | 131,691  |  
|Other comprehensive income    |  |                                  | 7,555    |                           |   | 7,555    |  
|                              |  |                                  |          |                           |   |          |  
|Balances at December 31, 2003 |  |                                  | 245,839  |                           |   | 202,609  |  
|Cash distributions            |  |                                  | (131,275 | )                         |   | (131,275 | )
|Receivable from partner       |  |                                  | (7,100   | )                         |   |         |  
|Net income                    |  |                                  | 127,952  |                           |   | 127,952  |  
|Other comprehensive income    |  |                                  | 2,620    |                           |   | 2,620    |  
|                              |  |                                  |          |                           |   |          |  
|Balances at December 31, 2004 |  | $                                | 238,036  |                           | $ | 201,906  |  
|                              |  |                                  |          |                           |   |          |  

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

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CALIFORNIA POWER GROUP  NOTES TO COMBINED FINANCIAL STATEMENTS  Years Ended December 31, 2004, 2003 and 2002

General

Edison Mission Energy ("EME"), an indirect wholly owned non-utility subsidiary of Edison International ("EIX"), and affiliates of ChevronTexaco
Corporation ("Chevron") jointly own six cogeneration projects, one power project and a purchasing entity located in California:



The
eight projects are together referred to as the California Power Group. The six cogeneration projects are together referred to as the Cogeneration Partnerships.

Principles of Combination

These combined financial statements include the accounts of the California Power Group. The financial statements include substantial transactions with related
parties. All significant intercompany transactions and balances have been eliminated. The combined financial statements have been prepared for purposes of EME's compliance with certain reporting
requirements of the Securities and Exchange Commission.

Nature of Operations

The Cogeneration Partnerships were organized under California law during the period from 1983 to 1989 to design, construct, own and operate qualifying
cogeneration facilities for the purpose of selling steam for use in oil field operations and providing electric energy under long-term contracts with two regulated utilities in California.
The facilities were certified as "qualifying facilities" under the Public Utility Regulatory Policies Act of 1978 and the regulations promulgated there under, as amended ("PURPA"), and management
believes that the facilities have fulfilled all requirements to receive continued qualifying facility status.

The
Cogeneration Partnerships are organized as general partnerships between subsidiaries of EME and Chevron. The income or loss from each of the projects is allocated equally to the
partners. Each of the partnerships shall terminate on the latter of the date the steam and electric contracts expire (from 2004 through 2007) or the date the individual partnership elects to cease
operations, unless terminated at an earlier date pursuant to the general partnership agreement.

Westside Cogeneration Projects

Coalinga, Mid-Set, Salinas River and Sargent Canyon (together, the "Westsides") each own and operate natural gas-fired cogeneration
facilities, ranging in output from 36 to 38 megawatts ("MWs"). The Westsides sell electric energy to Pacific Gas & Electric Company ("PG&E") for resale to its retail electric customers. The
plants also sell steam to subsidiaries of Chevron and/or Aera Energy LLC ("Aera") for use in oil recovery operations.

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Eastside Cogeneration Projects

Kern River and Sycamore (together, the "Eastsides") each own and operate 300 MW natural gas-fired cogeneration facilities located in Kern County,
California. The Eastsides sell electric energy to Southern California Edison Company ("SCE"), a wholly owned subsidiary of EIX, for resale to its retail electric customers, and sell steam to a
subsidiary of Chevron for use in its enhanced oil recovery operations in the Kern River oil field. Prior to July 1, 2002, the Eastsides also sold electric energy to Chevron for use in its Kern
River oil field operations.

Sunrise

Subsidiaries of EME and Chevron organized Sunrise as a Delaware limited liability company on May 29, 2001 to complete construction of, own and operate a
gas-fired electric generation facility located in Kern County, California. The facility was constructed in two phases. The first phase achieved commercial operation on June 29,
2001, and consisted of a 320 MW simple-cycle peaking facility. Phase II, which achieved commercial operation on June 1, 2003, converted the facility to a 572 MW combined cycle facility, which
consists of an additional steam turbine generator and two heat recovery steam generators. Sunrise sells electric energy to the California Department of Water Resources ("CDWR") for resale to electric
consumers in California. Income or loss is allocated equally between the members.

Estrellas

Estrellas is a Delaware limited liability company established on March 28, 2001 and assigned to Sunrise at formation. Estrellas was formed for the purpose
of purchasing equipment, primarily for related party entities. Estrellas receives a sales tax rebate from the City of Shafter based on the dollar volume of equipment sales transacted in Shafter.

Subsidiaries
of EME and Chevron reorganized Estrellas as a separate Delaware limited liability company on June 27, 2003. This reorganization had no impact on the combined
financial statements.

Use of Estimates

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

Cash and Cash Equivalents

Cash and cash equivalents include cash on hand and highly liquid investments with original maturities of three months or less. The carrying amount of cash and
cash equivalents approximates fair value because of the short maturity of these instruments. The cash and cash equivalents balance includes $23,859,000 and $28,668,000 of short-term
investments held by Chevron on behalf of the California Power Group at December 31, 2004 and 2003, respectively.

Restricted Cash

In accordance with the terms of it financing agreement, Sunrise is required to maintain on deposit in escrow accounts an amount equal to $62,811,000 and
$58,057,000 at December 31, 2004 and 2003, respectively (Note 5). The funds in these restricted accounts will be maintained until such time that the terms of the financing agreement are
fully satisfied. All restricted cash accounts earn interest at the

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current
market rate. Upon authorization from certain parties to the financing, funds from the restricted accounts may be used for items other than their designated purpose.

Inventories

Inventories primarily consist of spare parts for the operation of the generating facilities. Inventories are stated at the lower of the moving average cost,
repair cost or market.

Risk Management

The Westsides utilize gas swap agreements to mitigate their exposure to fluctuations in gas prices (Note 6). Mid-Set's swap agreement
terminated as scheduled in May 2004.

Property, Plant and Equipment

Property, plant and equipment are stated at cost. Depreciation is calculated on a straight-line basis. The operating facilities and related equipment
were depreciated over their estimated useful lives, which ranged from 27 to 30 years. As of January 1, 2005, management decreased the depreciable lives of the operating facilities owned
by the Westsides by 10 years (Note 4).

Expenditures
for maintenance, repairs and renewals are expensed as incurred. Expenditures for additions and improvements are capitalized. The facilities require major maintenance,
including inspections and overhauls, on a periodic basis. These costs are also expensed as incurred.

Impairment of Long-lived Assets

Long-lived assets are reviewed for impairment whenever events or changes in circumstances indicate that the carrying amount of an asset may not be
fully recoverable. Recoverability of assets to be held and used is measured by a comparison of the carrying amount of the assets to their fair value, which is normally determined through analysis of
the future net cash flows expected to be generated by the assets. If such assets are considered to be impaired, the impairment to be recognized is measured by the amount that the carrying amount of
the assets exceeds the fair value of the assets (Note 4).

Deferred Financing Costs

Legal and financing fees associated with project financing were deferred and are being amortized using the effective interest method over the respective terms of
the financings. Deferred financing costs are presented net of accumulated amortization of $1,149,000 and $283,000 at December 31, 2004 and 2003, respectively. Amortization expense was
approximately $866,000, $350,000 and $107,000 in 2004, 2003 and 2002, respectively. The estimated annual amortization expense for the next five years ended December 31, 2005 through 2009 is
$884,000 per year.

Water Entitlement

During 2003, Sunrise financed the West Kern Water District's ("WKWD") purchase of 6,500 acre-feet of annual State Water Project entitlement from the
Berrenda Mesa Water District for $6,500,000. The WKWD dedicated the entitlement to Sunrise for a term of 29 years. The entitlement was purchased to meet the California Energy Commission's
requirement that Sunrise secure out-of-basin water supplies for its power generation needs. The water entitlement expires in 2032 and is being amortized on a
straight-line basis over the useful life of Sunrise's facility. The water entitlement is presented net of accumulated amortization of $331,000 and $97,000 at December 31, 2004 and
2003, respectively. Amortization expense was approximately $234,000 and $97,000 in 2004 and 2003, respectively. The estimated annual amortization expense for the next five years ended
December 31, 2005 through 2009 is $234,000 per year.

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Notes Receivable

The WKWD did not have the necessary physical facilities to provide, transport and measure the water service delivery required by Sunrise's Phase 2 project. As a
result, Sunrise constructed necessary facilities and improvements together with certain upgrades for the benefit of the WKWD to provide water service delivery to Sunrise. As part of the water district
improvements, Sunrise provided cash contributions on WKWD's behalf in exchange for a $3,900,000 promissory note. The note matures in 2013, bears interest at 9% and is payable in monthly installments
of $50,000. Payments are made through credits to Sunrise's water bills. The fair value approximates the carrying value of $3,556,000 and $3,822,000 at December 31, 2004 and 2003, respectively.

Pursuant
to the Joint Interconnect Agreement between Sunrise and La Paloma Generating Company LLC ("La Paloma"), executed on September 9, 2000, Sunrise holds a 23.75%
interest in a joint interconnection facility with La Paloma. During 2004, La Paloma and PG&E entered into a settlement agreement relating to the Generator Special Facilities Agreement ("GFSA") which
sets forth the terms and conditions governing construction, operation and maintenance of certain facilities necessary to connect the Sunrise facility to PG&E's transmission system. Under the terms of
the settlement, PG&E agreed to refund approximately $6,392,000 to La Paloma through a note bearing interest at 4% compounded quarterly and maturing in 2007. Sunrise's 23.75% share of the settlement is
recorded as a note receivable. The fair value approximates the carrying value of $911,000 at December 31, 2004.

Emission Credits

During 2002 and 2003, Sunrise purchased $1,900,000 of emission credits, including $1,200,000 from subsidiaries of Chevron. The remaining emission credits were
purchased in prior years by the Cogeneration Partnerships from several unrelated parties. All emission credits are amortized on a straight-line basis over their estimated useful lives.
Emission credits are presented net of accumulated amortization of $1,742,000 and $1,550,000 at December 31, 2004 and 2003, respectively. Amortization expense was approximately $192,000,
$167,000 and $125,000 in 2004, 2003 and 2002, respectively. The estimated annual amortization expense for the next five years is $210,000 in 2005, $210,000 in 2006, $113,000 in 2007, $113,000 in 2008
and $113,000 in 2009.

Asset Retirement Obligations

On January 1, 2003, the California Power Group adopted Statement of Financial Accounting Standards ("SFAS") No. 143, Accounting for Asset Retirement
Obligations, which requires entities to record the fair value of a liability for an asset retirement obligation in the
period in which it is incurred. When the liability is initially recorded, the entity capitalizes the cost by increasing the carrying amount of the related long-lived asset. Over time, the
liability is increased to its present value each
period, and the capitalized cost is depreciated over the useful life of the related asset. Upon settlement of the liability, an entity either settles the obligation for its recorded amount or incurs a
gain or loss upon settlement.

Under
certain of its leases, the California Power Group is legally required to dismantle and remove the operating facilities at the end of the lease terms. As of January 1, 2003,
the California Power Group recognized a liability of $14,540,000 for asset retirement obligations and a loss of $9,200,000 related to unrecognized accretion and depreciation expense. If
SFAS 143 had been adopted on January 1, 2002, the pro forma effect of the accounting change on the income statement would have resulted in a decrease in net income of $900,000 during the
year ended December 31, 2002.

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The California Power Group recognized accretion expense of $857,000 and $815,000 associated with its asset retirement obligations in 2004 and 2003, respectively. There were no other
changes to the asset retirement obligations. This accretion expense is classified as part of Depreciation, amortization and accretion.

Partner Receivable

In December 2004, the California Power Group approved and paid a cash distribution to EME and Chevron in the amount of $14,200,000. Management subsequently
determined that the distribution should not have occurred and requested reimbursement from the partners. Chevron repaid its share of the distribution in December 2004 and the remaining balance
was received from EME in January 2005. The receivable from partner is shown as a decrease to equity at December 31, 2004.

Revenues

Revenue and related costs are recorded as electricity and steam are generated or services are provided.

Income Taxes

The California Power Group includes partnerships and limited liability companies and its income is included in the income tax returns of the partners and members.
Therefore, no provision (benefit) for income taxes has been included in the accompanying financial statements.

Accounting for Derivative Instruments and Hedging Activities

In accordance with SFAS No. 133,Accounting for Derivative Instruments and Hedging Activities, as amended,
all derivative instruments, except those meeting specific exceptions, are recognized in the balance sheet at their fair value. Changes in fair value are recognized immediately in earnings unless
specific hedge accounting criteria are met. For derivatives that qualify for hedge accounting, depending on the nature of the hedge, changes in fair value are either offset by changes in the fair
value of the hedged assets, liabilities or firm commitments through earnings, or recognized in other comprehensive income until the hedged item is recognized in earnings.

Management
has determined that the California Power Group's energy and capacity sales commitments and physical gas purchases qualify for the normal purchases and normal sales exception
provided by SFAS 133 and related guidance issued by the Derivatives Implementation Group. This exception applies to physical sales and purchases of power or fuel where it is probable that
physical delivery will occur, the pricing provisions are clearly and closely related to the contracted prices and the SFAS 133 documentation requirements are met. In April 2003, the
Financial Accounting Standards Board issued SFAS No. 149,Amendment of Statement 133 on Derivative Instruments and Hedging Activities.SFAS 149 changed the guidance related to the application of the normal purchases and normal sales exception to electricity contracts. This change had no impact on the designation of the
California Power Group's electricity contracts as normal.

Management
also determined that the Cogeneration Partnership's steam sales do not meet the definition of a derivative and are, therefore, not subject to the requirements of the standard.
During 2001, the Westsides entered into certain gas swaps that are subject to the requirements of SFAS 133 (Note 6).

Reclassifications

Certain prior year accounts have been reclassified to conform to the current year presentation.

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The
California Power Group has entered into agreements for the sale of contract capacity and net energy and steam generated by the facilities as follows:

|               |  | Energy and Capacity |  | Steam     
|-------------- |  | ------------------- |  | ----------
|
|
|Kern River     |  | SCE                 |  | 08/09/2005
|Sycamore       |  | SCE                 |  | 12/31/2007
|Coalinga       |  | PG&E                |  | 03/05/2007
|Salinas River  |  | PG&E                |  | 03/06/2007
|Sargent Canyon |  | PG&E                |  | 02/22/2007
|Sunrise        |  | CDWR                |  | 06/30/2012

Energy and Capacity

Eastsides

The Eastsides have entered into Parallel Generation Agreements ("PGA") with SCE for long-term sales of contract capacity and net energy. Under the
terms of the agreements, payments for energy are based on a rate calculated using a short-run-avoided-cost based formula ("SRAC Floor Formula") that contains a
prescribed energy rate indexed to the Southern California Border spot price of natural gas, and the quantity of kilowatts delivered during on-peak, mid-peak,
off-peak and super off-peak hours.

SCE
also pays the Eastsides for firm capacity based on a contracted amount per kilowatt year, as defined in the PGA. In the event Kern River or Sycamore unilaterally terminates the PGA
prior to the termination date or fails to meet certain performance requirements, the Eastsides would be required to repay certain capacity payments to SCE. Under these provisions, as of
December 31, 2004, the Eastsides have a total obligation of $35,575,000. EME and Chevron have jointly and severally guaranteed the repayment of this amount. Management has no reason to believe
that either one of the Eastsides will terminate its PGA or fail to meet the performance requirements during the remaining term.

Prior
to July 1, 2002, Kern River had an agreement to sell contract capacity and net energy to Texaco Exploration and Production Inc. ("TEPI"), a wholly owned subsidiary of
Chevron. This agreement was terminated as of July 1, 2002. Kern River sold $5,974,000 to TEPI under this agreement during the year ended December 31, 2002. As a result of the termination
of the TEPI agreement, effective December 6, 2002, Kern River increased the contract capacity dedicated to SCE under the PGA from 274 MW to 280 MW. The dedicated contract capacity was
further increased to 290 MW on July 1, 2003 and to 295 MW on February 1, 2004. The additional capacity payments are calculated at a rate of $143/kW-year.

In
March 1999, the Eastsides entered into an agreement (the "Agreement") with the Midway Sunset Cogeneration Company ("MSCC"), a related party partnership jointly owned by
affiliates of EME and Chevron. The Agreement supports a mutually beneficial settlement agreement related to energy prices approved by the CPUC. The Agreement provides for payment of specified amounts
from the Eastsides to MSCC, contingent upon MSCC's deliveries to SCE. Under the terms of the Agreement, the Eastsides paid MSCC $1,636,000, $1,476,000 and $2,080,000 in 2004, 2003 and 2002,
respectively.

The
Agreement was to remain in effect until the California Power Exchange was fully functioning; however, due to the demise of the California Power Exchange, there is no current
termination date. The parties are currently in discussions to establish a termination date for the Agreement which will coincide with the termination date of the Eastsides' respective PGAs.

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Westsides

Coalinga, Salinas River and Sargent Canyon each have a Power Purchase Agreement ("PPA") with PG&E for the sale of contract capacity and net energy. Under the
terms of the agreements, prior to October 1, 2001, payments for energy were based on an SRAC rate calculated based on PG&E's 1995 average price with an adjustment to reflect the monthly changes
in spot natural gas prices at the California border. As a result of the July 31, 2001 amendments to the PPAs, effective October 1, 2001, the energy price was changed to a fixed price for
the remaining term of the contracts. The fixed price is adjusted based on the amounts of energy delivered during on-peak hours. As of December 31, 2004, the average fixed energy
price was $53.70 per megawatt hour ("MWh").

PG&E
also pays the Westsides for firm capacity based on a contracted amount per kilowatt year, as defined in the PPAs. In the event one of the Westsides unilaterally terminates its PPA
prior to the termination date or fail to meet certain performance requirements, the Westsides would be required to repay certain capacity payments to PG&E. Under these provisions, as of
December 31, 2004, the Westsides have a total obligation of $9,087,000. Management has no reason to believe that any of the Westsides will terminate its PPA or fail to meet the performance
requirements during the remaining term.

Mid-Set
also had a PPA with PG&E which expired in May 2004. Subsequent to the expiration of the original power purchase agreement (PPA), Mid-Set executed
an extension with PG&E under Standard Offer 1(SO-1) pricing terms that provide for the payment of capacity on an as-delivered basis. The extension expired on
December 31, 2004; however, the contract was renewed on a month-to-month basis pending the execution of a new long-term PPA. In early March 2005, the
parties agreed to a five year extension under the SO-1 pricing.

Sunrise

Sunrise has a Power Purchase Agreement with CDWR (the "CDWR PPA") for the sale of contract capacity. In January 2003, Sunrise agreed to restructure the
second phase of the CDWR PPA which extends through June 30, 2012. Under the terms of the amended agreement, Sunrise receives capacity payments at a rate of $170.60 per kilowatt year. Sunrise is
also eligible for summer and annual availability bonuses. Sunrise received availability bonuses totaling $6,227,000, $6,324,000 and $4,359,000, during 2004, 2003 and 2002, respectively. In addition,
Sunrise is compensated for the number of times the plant is started, which is at the discretion of the State of California. Sunrise is paid a variable operation and maintenance payment of $3.00 per
megawatt hour based on net electrical output delivered to the CDWR. Sunrise received variable operation and maintenance payments totaling $9,565,000, $4,492,000 and $915,000, during 2004, 2003, and
2002, respectively.

Sunrise
has no firm contracts for fuel supply. Prior to October 1, 2003, Sunrise procured fuel on CDWR's behalf. CDWR reimbursed Sunrise for all costs, expenses and charges
incurred by Sunrise for fuel management, procurement, transportation, storage and delivery of fuel used by the Sunrise facility for the generation of electricity on behalf of CDWR. The fuel costs and
related CDWR reimbursements are presented in the Combined Statement of Comprehensive Income as Fuel expense and Sales of energy, respectively. Effective October 1, 2003, a third party now
procures fuel for Sunrise and all fuel costs are paid directly by CDWR.

Steam Sales

The counterparties to the steam sales agreements pay a steam fuel charge based on the quantity and quality of steam delivered during the month. Pricing for the
steam varies as follows:



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The
prices also generally include a processing charge per MMBtu as defined in the agreements. The amount of steam sold under these agreements is expected to be sufficient for the
Cogeneration Partnerships to continue to maintain qualifying facility status.

Mid-Set's
steam contract expired in May 2004 coterminous with the expiration of its power purchase agreement. Prior to the expiration of the contract, the steam
pricing was based on either Mid-Set's weighted average monthly cost of fuel gas or the Midway-Sunset Field posted crude oil gas price on an MMBtu equivalent basis. Subsequent to the
expiration of the steam agreement, Mid-Set executed an extension through December 31, 2004 with steam-fuel pricing terms based 100% on natural gas and other terms
reflecting the expired contract. Subsequent to December 31, 2004, the steam agreement has been renewed on a month-to-month basis pending the execution of a long term
steam agreement.

Property,
plant and equipment consist of the following:

(In thousands)

2004

2003Operating facilities

$
886,456

$
887,409Other property and equipment


25,552


25,642912,008


913,051Accumulated depreciation


(317,791
)

(287,247
)Construction work in progress


836


1,216$
595,053

$
627,020


Depreciation expense was approximately $30,686,000, $27,573,000 and $22,652,000 in 2004, 2003 and 2002, respectively.

Mid-Set Impairment

During 2004, the California Power Group recorded asset impairment charges of $4,000,000 related to Mid-Set. The impairment charge resulted from a
revised long-term outlook for the facility and differences in value between the expiring and new five-year power purchase and steam agreements with PG&E and Chevron affiliates,
respectively (Note 3). In addition, in January 2005, management decided to shorten the useful life of the facility to 20.5 years, to coincide with the end of the new power
purchase agreement. The change is based on management's expectation that Mid-Set will not be successful in entering into another contract after the expiration of the new agreement with
PG&E. The change will be applied prospectively as of January 1, 2005.

Change in Depreciable Lives

The power purchase agreements for the other Westsides expire in the first quarter of 2007. Management expects that these partnerships will face the same
competitive pricing environment and that future agreements will be priced on terms similar to the new Mid-Set power purchase agreement. Furthermore, management does not expect future
contracts to extend beyond an additional five year term. Therefore, based on the expected reduction in economic life, in January 2005 management decreased the depreciable lives of the Westsides
and will be depreciating the plants over the revised 20 year life.

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The
Kern River power purchase agreement expires in August 2005 and management is currently in the process of negotiating a new contract. Due to the size and location of the Kern
River and Sycamore facilities, management expects to continue to operate the facilities profitably beyond the current contract period and no change has been made to the depreciable lives at this time.

Operational Risks

The depreciable lives of the operating facilities, other than Mid-Set, exceed the term of the related purchase power agreements. The viability of the
facilities subsequent to the expiration of the power purchase agreements is dependent upon the California Power Group's ability to enter into new contracts at terms that would allow the facilities to
operate profitability.

In
January 2004, the California Public Utilities Commission adopted a new Energy Procurement Framework for the state's investor owned utilities, including PG&E and SCE. The
framework includes provisions to extend qualifying facilities contracts expiring prior to December 21, 2005 for five years. The framework does not address pricing or other specific terms of the
proposed contracts. Management continues to evaluate its operational options at the conclusion of the contract lives. Based on these evaluations and discussions with its counterparties, management
believes the adjusted useful lives are appropriate and that the facilities will continue to operate profitably subsequent to the expiration of the respective power purchase agreements. However, if
management subsequently determines that the plants will not be able to operate profitably beyond the term of the power purchase agreements, management may make additional changes in the depreciable
lives and an impairment charge may be required.

In
September 2003, Sunrise entered into a $345,000,000 project financing loan payable with the Bank of New York as the administrative agent. Half of the financing was provided by
a syndicate of fourteen unrelated lenders with the remaining amount from Chevron Capital Corporation, a wholly owned subsidiary of Chevron. The project financing loan payable is repaid in
semi-annual installments on the last day of April and October based on a percentage of the unpaid principal, with the final payment of $22,908,000 due on October 31, 2011. The loan
bears interest at 7.09% per annum, which is paid semi-annually with the principal payment. Annual principle maturities of Sunrise's project financing loan payable are $36,432,000 in 2005,
$37,260,000 in 2006, $39,675,000 in 2007, $42,159,000 in 2008, $42,711,000 in 2009 and $95,841,000 thereafter.

The
Sunrise project financing loan payable is secured by substantially all the assets of Sunrise and places certain restrictions on cash, capital distributions and permitted investments.
As of December 31, 2004, pledged assets total approximately $364,417,000. In addition, Sunrise is required to maintain on deposit
in escrow accounts an amount equal to the next principal payment and six months interest and $500,000 for major maintenance.

The
Sunrise project financing loan payable currently contains various restrictive covenants covering ratios relating to restricted cash, restrictions on distributions, use of proceeds
and other customary covenants. For the year ended December 31, 2004, Sunrise was in compliance with all the covenants under the project financing loan payable.

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Fair value

The fair value of Sunrise's project financing loan payable is estimated based on the quoted market prices for the same or similar issues or on the current rates
offered to Sunrise for debt of the same remaining maturities. The fair value of the project financing loan payable at December 31, 2004 and 2003 is $287,762,000 and $327,405,000, respectively.

The
Cogeneration Partnerships are exposed to price risk associated with the purchase of natural gas for the cogeneration facilities. Market risk arises from the potential change in the
value of financial instruments and physical commodities based on fluctuations in commodity prices and bases. Market risk is also affected by changes in the volatility and liquidity in markets in which
these instruments are traded.

In
general, the Cogeneration Partnerships procure natural gas through fuel management agreements with Texeco Natural Gas, Inc. ("TNGI"), whereby TNGI procures gas on a spot basis for the
Cogeneration Partnerships, seeking the lowest possible price balanced with the need for secure supply. The agreements continue until the termination of the power purchase agreements.

Westsides

The Westsides manage approximately 55% of their exposure to fluctuations in the price of natural gas through the use of natural gas swap agreements. The remaining
fuel gas requirements are purchased on the spot market by TNGI in its role as fuel manager for the Westsides. Effective November 1, 2001, the Westsides entered into 24,000 MMBtu per day forward
fixed natural gas contacts purchased on the
NYMEX exchange with basis swaps at Permian, Southern California Border and San Juan in an attempt to mitigate price variability through May 31, 2004 (Mid-Set) and
September 30, 2006 (Sargent Canyon, Salinas River and Coalinga). Under the agreements, the Westsides make or receive payment on a specific quantity of natural gas based on the differential
between a specified fixed price and the market price of gas at Permian, Southern California Border or San Juan. The gains and losses related to these derivative instruments will offset fluctuations in
the Westsides natural gas costs.

Prior
to January 1, 2003, the gas swap agreements were not formally designated as cash flow hedges; therefore, unrealized gains or losses on the gas swaps were recorded as part of
Fuel expense in the Statements of Comprehensive Income. As of January 1, 2003, management designated the contracts as cash flow hedges; therefore, during 2003 and on a go forward basis gains or
losses associated with the effective portion of the hedges are recorded in other comprehensive income. The ineffective portion of the cash flow hedges is recorded directly in the income statement as
part of fuel expense. The Westsides recorded a loss of $166,000 and income of $473,000 related to ineffectiveness during 2004 and 2003, respectively. In addition, the Westsides recorded expense of
$7,168,000 and $8,038,000 related to the reversal of unrealized gains recognized in prior years during 2004 and 2003, respectively. During the year ending December 31, 2005, the Westsides
expect to reclassify $13,680,000 of gains into earnings.

Accumulated Other Comprehensive Income

As of December 31, 2004 and 2003, the equity balances included Accumulated Other Comprehensive Income of $20,350,000 and $15,110,000, respectively. The changes in
accumulated other comprehensive income during the periods are attributable to activity associated with the Westsides' gas cash flow hedges.

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Fair value

In assessing the fair value of the Westsides' commodity derivative instruments, management uses a variety of methods and assumptions that are based on market
conditions and risk existing at each balance sheet date. The fair value of the commodity price contracts considers quoted market prices, time value, and other factors. The fair market value may not be
representative of the actual gains or losses that will be recorded when these instruments mature due to future fluctuations in the markets in which they are traded.

The
fair value of financial derivative instruments is determined through dealer quotes and may not be representative of actual gains and losses that will be recorded when these
instruments mature due to future fluctuations in the markets in which they are traded.

Eastsides and Sunrise

Under the terms of their parallel generation agreements, the Eastsides receive payments for energy based on a formula that is indexed to the Southern California
Border spot price of natural gas. This pricing formula reduces the Eastsides' exposure to changes in gas prices. Under the terms of its power purchase agreement, Sunrise is not responsible for the
procurement of fuel; therefore, Sunrise is not exposed to price risk associated with gas purchases.

Operating
expenses include the following amounts paid to related parties:

|(In thousands)                           |                                                 | 2004 |         | 2003    |   | 2002   
|---------------------------------------- | ----------------------------------------------- | ---- | ------- | ------- | - | -------
|Fuel expense                             |                                                 |      |         |         |   |        
|                                         | Texaco Natural Gas, Inc.                        |      | $       | 467,054 |   | $      
|                                         | Edison Mission Marketing & Trading, Inc.        |      |         | 333     |   |        
|Other operations and maintenance expense |                                                 |      |         |         |   |        
|                                         | Edison Mission Operations and Maintenance, Inc. |      |         | 13,953  |   |        
|                                         | EME and affiliates                              |      |         | 1,876   |   |        
|                                         | Other                                           |      |         | 194     |   |        
|Administrative and general               |                                                 |      |         |         |   |        
|                                         | Chevron USA                                     |      |         | 7,346   |   |        
|                                         | Texaco Power and Gasification Holdings Inc      |      |         | 1,161   |   |        
|                                         |                                                 |      |         |         |   |        
|                                         |                                                 | $    | 491,917 |         | $ | 439,570
|                                         |                                                 |      |         |         |   |        

Fuel Management Agreements

The Cogeneration Partnerships have entered into fuel management agreements with TNGI whereby TNGI receives a fixed service fee per MMBtu of fuel gas supplied to
the Cogeneration Partnerships, subject to escalation as defined by the agreements. The Cogeneration Partnerships paid service fees of approximately $2,050,000, $2,244,000 and $2,998,000 for 2004, 2003
and 2002, respectively.

Sunrise
is party to an Energy Service Agreement with Edison Mission Marketing & Trading, Inc. ("EMMT"), a wholly owned subsidiary of EME, whereby EMMT, among other
services, is responsible for purchasing and/or nominating fuel for and related transportation to the Sunrise facility. EMMT received a fixed service fee of $0.005 per MMBtu of fuel gas supplied to
Sunrise, subject to escalation as defined by the agreement. The purchase, nomination and transportation of fuel function was terminated effective October 1, 2003 and fuel management
responsibilities were assumed by the CDWR.

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Operations and Maintenance Agreements

The members of the California Power Group have entered into agreements with Edison Mission Operation and Maintenance, Inc. ("EMOM"), a wholly owned
subsidiary of EME, whereby EMOM performs all operations and maintenance activities necessary for the production of electricity and steam. The agreements will continue until terminated by either party
(the Sunrise agreement requires ninety day prior written notice). EMOM is paid for all costs incurred in connection with operating and maintaining the facilities and may earn incentive compensation as
set forth in the agreements. Amounts paid to EMOM by the California Power Group under these agreements included incentive compensation of $992,000, $1,058,000 and $926,000 for 2004, 2003 and 2002,
respectively.

Emission Credits

As part of their initial capital contribution, subsidiaries of Chevron contributed their rights to certain emission offset credits to Kern River, Sycamore and
Mid-Set. EME contributed cash equal to the agreed upon fair value for the credits of $43,300,000. These emission credits have been accounted for at their historical cost of $0 in the
accompanying financial statements.

Land Leases

Certain of the entities in the California Power Group have entered into long-term land leases with Chevron as follows:

|              |  | Termination
date |  | Renewal options                                     
|------------- |  | ---------------- |  | ----------------------------------------------------
|
|Kern River    |  | 04/30/2009       |  | Kern River can extend indefinitely                  
|Mid-Set       |  | 07/15/2006       |  | Mid-Set has the option to extend at any time        
|Salinas River |  | 08/01/2008       |  | Parties may agree to up to 15 one year extensions   
|Sunrise       |  | 11/30/2025       |  | Sunrise has a one-time option to extend for 25 years
|Sycamore      |  | 01/18/2019       |  | None                                                

Lease payments are indexed to fluctuations in the gross domestic product as defined in the agreements. In addition, the Sunrise lease is subject
to a 3% annual increase and Chevron may charge Sunrise additional amounts for property taxes or government assessments. Lease payments are included in "Other" costs on the table above.

Engineering and Administrative Agreements

The Cogeneration Partnerships have agreements with Texaco Inc., a wholly owned subsidiary of Chevron, whereby Texaco Inc. shall perform work
consisting of engineering and administrative activities required for operation of the Cogeneration Partnerships. Under the terms of the agreement, Texaco Inc. is paid for all costs incurred in
connection with the engineering and administration of the Cogeneration Partnerships. The agreements shall remain in effect until terminated by either party. Effective November 1, 2002, the
rights and obligations of these agreements were assigned to Chevron USA.

Sunrise
has an agreement with Texaco Power and Gasification Holdings Inc. ("TPGHI"), a wholly owned subsidiary of Chevron, whereby TPGHI performs all engineering and
administrative activities required by the Sunrise facility. Under the terms of the agreement, TPGHI is paid for all costs incurred in connection with engineering and administrating the Sunrise
facility. The agreement became effective June 25, 2001 and shall remain in effect until terminated by either party with ninety days prior written notice.

189

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Ship or Pay

Pursuant to the terms of the Security of Supply Agreement (the "Security Agreement") dated December 1, 1994, the Eastsides and Mid-Set agreed
to underwrite a portion of firm transportation capacity that had been obtained by TNGI from El Paso Gas Pipeline Company ("El Paso") under an agreement dated February 15, 1989 (the "El Paso
Agreement") and from Mojave Pipeline Company ("Mojave") under an agreement dated February 15, 1989 (the "Mojave Agreement"). The terms of the El Paso and Mojave Agreements extend to
April 1, 2007. Under the original terms of the Security Agreement, the Eastsides and Mid-Set are required to transport the lesser of 75% of each facility's annual fuel gas
requirement or 52,012,500 MMBtu under the terms of the El Paso and Mojave Agreements or to pay the reservation portion of the transportation fee under each of the transportation agreements to meet the
volumetric commitment. The reservation fees under the two transportation agreements total $0.64 per MMBtu.

As
a consequence of a capacity reallocation program on the El Paso system mandated by the FERC in 2002, the volume obligations of the Eastsides and Mid-Set under the Security
Agreement with respect to the El Paso Agreement were modified. Effective November 1, 2002, the volumetric obligations were revised such that Kern River and Sycamore are each financially
responsible for 38,986 MMBtu per day of capacity and Mid-Set is financially responsible for 6,000 MMBtu per day of capacity. The Mid-Set obligation expired on May 1,
2004, at which time Kern River and Sycamore each assumed responsibility for one-half of the former Mid-Set obligation. The Kern River obligation extends to August 9,
2005 and the Sycamore obligation extends to April 1, 2007.

On
July 20, 1990, the Eastsides agreed to accept and underwrite a portion of Chevron's transportation agreement between Chevron and Northwest Pipeline Company extending through
the term of the Eastsides' sales agreements with SCE. Under the terms of the agreement, the Eastsides are responsible for 9,500 MMBtu per day of firm capacity at a demand cost of $0.28 per MMBtu. The
capacity was brokered to a third party at full cost recovery through October 31, 2003. The capacity was subsequently brokered to a third party for the period of November 2003 through
October 2005 at a cost recovery level of $0.10 per MMBtu. The cost recovery deficit in 2004 and 2003 was $624,000 and $104,000, respectively. There was no deficit in cost recovery in 2002.

Firm Transportation Agreement

Sunrise previously held an agreement with the Kern River Gas Transmission Company effective May 2003 and extending for 15 years thereafter, for the
right to firm transportation capacity of 85,000 MMBtu per day of natural gas on the Kern River Gas Transmission pipeline between the Rockies-Opal and the Sunrise facility. The
transportation rates paid by Sunrise were in
accordance with Kern River Gas Transmission's tariff schedule filed with the FERC. The reservation fee under the tariff for 15 year expansion capacity is currently $0.447 per MMBtu of gas. CDWR
reimbursed Sunrise for all costs associated with the agreement from May 1, 2003 to September 1, 2003. The agreement was assigned to CDWR effective September 1, 2003 and Sunrise no
longer has any responsibility or liability under the agreement.

Long-term Service Agreement

Sunrise has a long-term service agreement with General Electric International, Inc. ("GEI"), a wholly owned affiliate of General Electric, to
help manage the costs of major maintenance repairs. The agreement terminates on June 28, 2019. Under the terms of the agreement, GEI provides planned and unplanned major maintenance services
and materials. Sunrise pays an annual fee of $250,000 plus a variable fee based on fired hours and factored starts. All fees are subject to escalations based on the

190

---



consumer
price index. Sunrise also pays for materials priced at a 15% discount to GE's list price and services based on time and materials, discounted at 7%. GE earns an incentive fee based on the
availability of the turbines and is required to pay Sunrise if the turbines do not attain an annual availability factor of 97.5% during the peak period and 97.3% during the off-peak
period. There is a $3,000,000 cap on the incentive and availability fees. Sunrise made a $442,000 and $870,000 bonus payment to GEI during 2004 and 2003, respectively for the 2004, 2003 and 2002
contract periods.

Credit Risk

The California Power Group is exposed to credit risk related to potential nonperformance by counter parties to its energy and capacity and steam sales. The
California Power Group's sales are concentrated among five primary counter parties:

|(In thousands)                           |  | 2004 |         | 2003 |   | 2002   
|---------------------------------------- |  | ---- | ------- | ---- | - | -------
|Southern California Edison Company       |  | $    | 451,796 |      | $ | 419,948
|Affiliates of Chevron                    |  |      | 167,915 |      |   | 137,555
|California Department of Water Resources |  |      | 116,919 |      |   | 110,023
|Pacific Gas & Electric Company           |  |      | 88,983  |      |   | 88,379 
|Aera Energy, LLC                         |  |      | 25,319  |      |   | 23,160 
|                                         |  |      |         |      |   |        
|                                         |  | $    | 850,932 |      | $ | 779,065
|                                         |  |      |         |      |   |        

Due to the concentration of credit risk, the California Power Group's liquidity could be impacted by financial difficulties experienced by its
counter parties. As a result of the energy crisis in California, SCE and PG&E suspended payment of amounts due to the Cogeneration Partnerships in December 2000; however, all past due amounts
have now been repaid.

191

---





Report of Independent Auditors

The
Management Committee of
Watson Cogeneration Company

We
have audited the accompanying balance sheets of Watson Cogeneration Company (the Company) as of December 31, 2004 and 2003, and the related statements of income, partners'
capital, and cash flows for each of the three years ended December 31, 2004. These financial statements are the responsibility of the Company's management. Our responsibility is to express an
opinion on these financial statements based on our audits.

We
conducted our audits in accordance with auditing standards generally accepted in the United States. Those standards require that we plan and perform the audit to obtain reasonable
assurance about whether the financial statements are free of material misstatement. We were not engaged to perform an audit of the Company's internal control over financial reporting. Our audit
includes consideration of internal control over financial reporting as a basis for designing audit procedures that are appropriate in the circumstances, but not for the purpose of expressing an
opinion on the effectiveness of the Company's internal control over financial reporting. Accordingly, we express no such opinion. An audit also 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.

In
our opinion, the financial statements referred to above present fairly, in all material respects, the financial position of Watson Cogeneration Company at December 31, 2004 and
2003, and the results of its operations and cash flows for each of the three years ended December 31, 2004, in conformity with accounting principles generally accepted in the United States.

| |  |                  
| |  | -----------------
| |  | Ernst & Young LLP

Los Angeles, California
February 21, 2005

192

---





WATSON COGENERATION COMPANY  BALANCE SHEETS

|                                        |                            | December 31                                     
|--------------------------------------- | -------------------------- | ------------------------------------------------
|
|
|Assets                                  |                            |                                                 
|Current assets:                         |                            |                                                 
|                                        | Cash and cash equivalents  |                                                 
|                                        | Receivables:               |                                                 
|                                        |                            | Southern California Edison Company              
|                                        |                            | BP West Coast Products LLC                      
|                                        |                            | Other receivables                               
|                                        | Inventories                |                                                 
|                                        | Prepaid expenses           |                                                 
|                                        |                            |                                                 
|Total current assets                    |                            |                                                 
|Property, plant and equipment, net      |                            |                                                 
|Intangible assets, net                  |                            |                                                 
|                                        |                            |                                                 
|Total assets                            |                            | $                                               
|                                        |                            |                                                 
|Liabilities and partners' capital       |                            |                                                 
|Current liabilities:                    |                            |                                                 
|                                        | Accounts payable           |                                                 
|                                        | Payables:                  |                                                 
|                                        |                            | Southern California Edison Company              
|                                        |                            | BP West Coast Products LLC and BP Energy Company
|                                        | Interest payable           |                                                 
|                                        |                            |                                                 
|Total current liabilities               |                            |                                                 
|Long-term debt:                         |                            |                                                 
|                                        | Camino Energy Company      |                                                 
|                                        | Atlantic Richfield Company |                                                 
|Partners' capital                       |                            |                                                 
|                                        |                            |                                                 
|Total liabilities and partners' capital |                            | $                                               
|                                        |                            |                                                 

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

193

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WATSON COGENERATION COMPANY  STATEMENTS OF INCOME

|               |                                                                       | Year ended December 31            
|-------------- | --------------------------------------------------------------------- | ----------------------------------
|
|
|Revenues:      |                                                                       |                                   
|               | Sales:                                                                |                                   
|               |                                                                       | BP West Coast Products LLC        
|               |                                                                       | Southern California Edison Company
|               |                                                                       | CPC Cogeneration LLC              
|               | Interest income                                                       |                                   
|               |                                                                       |                                   
|Total revenues |                                                                       |                                   
|Expenses:      |                                                                       |                                   
|               | Fuel purchases from BP West Coast                                     |                                   
|               |                                                                       | Products LLC and BP Energy Company
|               | Fuel transportation costs                                             |                                   
|               | Other operating                                                       |                                   
|               | Depreciation and amortization                                         |                                   
|               | Personnel compensation and other benefits
BP West Coast Products LLC |                                   
|               | Property taxes                                                        |                                   
|               | Interconnection fee to Southern California Edison Company             |                                   
|               | Services fees to BP West Coast Products LLC                           |                                   
|               | Interest                                                              |                                   
|               | Miscellaneous expenses, net                                           |                                   
|               |                                                                       |                                   
|Total expenses |                                                                       |                                   
|               |                                                                       |                                   
|Net income     |                                                                       | $                                 
|               |                                                                       |                                   

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

194

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WATSON COGENERATION COMPANY  STATEMENTS OF CHANGES IN PARTNERS' CAPITAL

|                             |                       | Camino
Energy
Company |         | Products
Cogeneration
Company |   | Carson
Cogeneration
Company |        | Total |        
|---------------------------- | --------------------- | --------------------- | ------- | ----------------------------- | - | --------------------------- | ------ | ----- | -------
|
|Balance at December 31, 2001 |                       | $                     | 133,373 |                               | $ | 5,444                       |        | $     | 133,373
|                             | Capital distributions |                       |         | (99,470                       | ) |                             | (4,060 | )     |        
|                             | Net income            |                       |         | 32,626                        |   |                             | 1,332  |       |        
|                             |                       |                       |         |                               |   |                             |        |       |        
|Balance at December 31, 2002 |                       |                       | 66,529  |                               |   | 2,716                       |        |       | 66,529 
|                             | Capital distributions |                       |         | (50,806                       | ) |                             | (2,074 | )     |        
|                             | Net income            |                       |         | 48,978                        |   |                             | 2,000  |       |        
|                             |                       |                       |         |                               |   |                             |        |       |        
|Balance at December 31, 2003 |                       |                       | 64,701  |                               |   | 2,642                       |        |       | 64,701 
|                             | Capital distributions |                       |         | (51,925                       | ) |                             | (2,119 | )     |        
|                             | Net income            |                       |         | 47,166                        |   |                             | 1,925  |       |        
|                             |                       |                       |         |                               |   |                             |        |       |        
|Balance at December 31, 2004 |                       | $                     | 59,942  |                               | $ | 2,448                       |        | $     | 59,942 
|                             |                       |                       |         |                               |   |                             |        |       |        

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

195

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WATSON COGENERATION COMPANY  STATEMENTS OF CASH FLOWS

|                                                     |                                                                                   | Year ended December 31                       |                                                         
|---------------------------------------------------- | --------------------------------------------------------------------------------- | -------------------------------------------- | --------------------------------------------------------
|
|
|Operating activities                                 |                                                                                   |                                              |                                                         
|                                                     | Net income                                                                        |                                              | $                                                       
|                                                     | Adjustments to reconcile net income to net cash provided by operating activities: |                                              |                                                         
|                                                     |                                                                                   | Depreciation and amortization                |                                                         
|                                                     |                                                                                   | Changes in operating assets and liabilities: |                                                         
|                                                     |                                                                                   |                                              | Receivables                                             
|                                                     |                                                                                   |                                              | Inventories                                             
|                                                     |                                                                                   |                                              | Prepaid expenses                                        
|                                                     |                                                                                   |                                              | Accounts payable                                        
|                                                     |                                                                                   |                                              | Affiliate payables                                      
|                                                     |                                                                                   |                                              | Advance payments from Southern California Edison Company
|                                                     |                                                                                   |                                              |                                                         
|                                                     |                                                                                   |                                              |                                                         
|                                                     |                                                                                   |                                              |                                                         
|Investing activities                                 |                                                                                   |                                              |                                                         
|Additions to property, plant and equipment           |                                                                                   |                                              | (2,876                                                  
|                                                     |                                                                                   |                                              |                                                         
|Net cash used in investing activities                |                                                                                   |                                              | (2,876                                                  
|                                                     |                                                                                   |                                              |                                                         
|Financing activities                                 |                                                                                   |                                              |                                                         
|Distributions to partners                            |                                                                                   |                                              | (105,969                                                
|                                                     |                                                                                   |                                              |                                                         
|Net cash used in financing activities                |                                                                                   |                                              | (105,969                                                
|                                                     |                                                                                   |                                              |                                                         
|Net increase (decrease) in cash and cash equivalents |                                                                                   |                                              | (87                                                     
|Cash and cash equivalents at beginning of year       |                                                                                   |                                              | 4,720                                                   
|                                                     |                                                                                   |                                              |                                                         
|Cash and cash equivalents at end of year             |                                                                                   | $                                            | 4,633                                                   
|                                                     |                                                                                   |                                              |                                                         
|Supplemental information                             |                                                                                   |                                              |                                                         
|Interest paid                                        |                                                                                   | $                                            | 2,687                                                   
|                                                     |                                                                                   |                                              |                                                         

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

196

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WATSON COGENERATION COMPANY  NOTES TO FINANCIAL STATEMENTS  December 31, 2004

Watson
Cogeneration Company (WCC) is a general partnership among Products Cogeneration Company (PCC), a wholly owned subsidiary of Atlantic Richfield Company, a wholly owned subsidiary
of BP America Inc. (BP); Carson Cogeneration Company (CCC), a wholly owned subsidiary of CH-Twenty, Inc., a majority-owned subsidiary of Atlantic Richfield Company; and
Camino Energy Company (CEC), a wholly owned subsidiary of Edison Mission Energy, a wholly owned subsidiary of Mission Energy Holding Company, a wholly owned subsidiary of The Mission Group, a wholly
owned non-utility subsidiary of Edison International, the parent holding company of Southern California Edison Company (SCE). PCC, CCC and CEC own 2%, 49% and 49% of the partnership,
respectively. The WCC partnership agreement provides for its termination at the termination of the power purchase agreement with SCE in 2008, unless otherwise extended by the partners.

WCC
was organized under California law in 1986 to design, construct, own and operate a cogeneration facility (Facility), which became fully operational in 1988. WCC, which operates in
one business segment, produces and sells electric energy to SCE for resale to its customers, produces and sells electric energy to CPC Cogeneration LLC (CPC), a limited liability company, owned by
PCC, CCC and CEC 2%, 49% and 49%, respectively. CPC sells power to BP West Coast Products LLC (BPWCP), pursuant to a Power Purchase and Sale Agreement, which was assigned to CPC from WCC. CPC was
terminated effective at the close of business December 31, 2002, and all agreements were assigned back to WCC. WCC also produces and sells steam to BPWCP for use at its Carson refinery, and
purchases water and fuel gas from BPWCP's Carson refinery.

PCC
serves as the managing partner. Insurance coverage is provided by PCC and CEC. WCC reimburses PCC's affiliate BPWCP for personnel compensation and other benefits for operating and
maintaining the Facility. Additionally, BPWCP provides other ancillary services to the partnership under a services contract for a fee.

The
Facility is located on the property of the Carson Refinery of BPWCP. The right to use the property, the refinery infrastructure, and other related rights were contributed by PCC to
WCC at its formation. The rights expire in 2008.

The
results of WCC's operations and its financial position may be significantly different without its relationships with its partners.

Cash and Cash Equivalents

Cash and cash equivalents include highly liquid investments with original maturities of less than 90 days.

Revenue Recognition

Electrical energy and steam revenue and related costs are recognized upon transmission to the customer.

Inventories

Inventories are comprised of materials and supplies, and are stated at their lower of average cost or market.

197

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Property, Plant and Equipment

Property, plant and equipment are stated at cost and are depreciated over the estimated useful lives on a straight-line basis with asset lives ranging
from 5 to 20 years.

Intangible Assets

Intangible assets are recorded at cost and are amortized on a straight-line basis over 20 years.

Repair and Maintenance

Repair and maintenance costs, including major maintenance activities at the cogeneration facility, are expensed when incurred.

Estimates

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

The
receivable from SCE at December 31, 2001, represents amounts due for power sales for the period from November 30, 2000 to March 25, 2001. During
August 2001, an advance payment agreement was reached between SCE and WCC, whereby SCE must pay WCC for power purchases in advance. The
outstanding receivables balance from November 2000 to March 2001 and accrued interest was paid by SCE in March 2002. In 2002 WCC recorded interest income of approximately
$1,497,000, on the outstanding receivables. Subsequent to March 2002, WCC no longer charged interest to SCE on its outstanding balance.

Property,
plant and equipment consists of the following:

2004

2003(In Thousands)Plant

$
303,765

$
304,304Construction-in-progress


390


1,239Other


5,698


5,747309,853


311,290Less accumulated depreciation


(177,361
)

(169,482
)$
132,492

$
141,808


Depreciation expense amounted to approximately $12,193,000, $12,747,000 and $10,472,000 for 2004, 2003 and 2002, respectively.

Intangible
assets, net of accumulated amortization of approximately $26,904,000 and $24,167,000 at December 31, 2004 and 2003, respectively, consist of outside boundary limit
facilities, refinery infrastructure, environmental permits, and land use, which was contributed to the partnership at its

198

---



formation.
Amortization expense was approximately $2,737,000, for each of the three years ended December 31, 2004, respectively. Amortization for the next four years is estimated at $2,737,000
per year and approximately $684,000 in 2008.

The
related party debt matures in 2008 and payments of interest only, at a rate of 5%, are due semiannually on April 1 and October 1.

Power Purchase Contract with SCE

Under the terms of the Power Purchase Contract with SCE (SCE Power Purchase Contract), WCC has contracted to sell power generated by the Facility, but not sold to
BPWCP, to SCE at contract rates recognized by the Public Utilities Commission of the State of California. The SCE Power Purchase Contract is for a period which ends in 2008.

Power, Steam, Fuel, and Water Contracts with BP Affiliates

WCC entered into a Power Purchase and Sale Agreement with BPWCP (as successor to Atlantic Richfield Company), which was assigned, via an Assignment Agreement, to
CPC following CPC's formation. The agreement contains provisions to sell power generated by the Facility to BPWCP's Carson refinery under terms similar to the SCE Power Purchase Contract. Under the
terms of the Water and Steam Purchase and Sale Agreement with BPWCP, WCC contracted to sell steam generated by the Facility to, and to purchase water from, BPWCP's Carson refinery.

In
addition, WCC and CPC agreed to enter into an Energy Sales Agreement (ESA) under which WCC sells power to CPC. The assignment of the Power Purchase and Sale Agreement and the
consummation of the ESA has not had a material effect on the companies.

CPC
was terminated effective at the close of business December 31, 2002. Effective upon the termination of CPC, the Assignment Agreement was terminated, thereby restoring the
Power Purchase and Sale Agreement as a contract between WCC and BPWCP. At the same time, the Energy Sales Agreement between WCC and CPC was terminated, as well as the Services Agreement between WCC
and CPC.

Interconnection Facilities Agreement

Under the terms of an Interconnection Facilities Agreement, WCC shall pay a monthly charge to SCE, as defined in the contract, for a portion of the
Interconnection Facilities, which are owned, operated and maintained by SCE.

Other

WCC has entered into water and fuel (natural gas, refinery gas, butane and chemicals) purchase agreements with BP West Coast Products LLC and BP Energy Company.
WCC purchases under these agreements amounted to approximately $229,000,000, $191,000,000 and $121,000,000 during 2004, 2003 and 2002, respectively.

WCC
reimburses PCC's affiliate BPWCP for personnel compensation and other benefits for operating and maintaining the Facility. Additionally, BPWCP provides other ancillary services to
the partnership under a services contract for a fee.

199

---



Income
taxes are not recorded by the partnership since the net income or loss is allocated to the partners and included in their respective income tax returns.

The
fair value of WCC's long-term debt was estimated based on current rates of the same or similar issues. The fair value of the long-term debt was approximately
$53,221,000 and $50,168,000 at December 31, 2004 and 2003, respectively.

WCC
invests its cash primarily in deposits with major banks. Certain deposits may, at times, be in excess of federally insured limits. WCC has not incurred losses related to such cash
balances.

In
2003, WCC entered into several multi-year contracts with gas turbine parts suppliers. The parts subject to these agreements are scheduled to be delivered from 2005 through
2007. The total
remaining value of these contracts is approximately $11,400,000. Early termination of the agreements could result in a cancellation charge.

200

---





Report of Independent Registered Public Accounting Firm

To the Management Committee of
Midway-Sunset Cogeneration Company

In
our opinion, the accompanying balance sheets and the related statements of income, partners' equity, and cash flows present fairly, in all material respects, the financial position of
Midway-Sunset Cogeneration Company at December 31, 2004 and December 31, 2003, and the results of its operations and its cash flows for each of the three years in the period ended
December 31, 2004 in conformity with accounting principles generally accepted in the United States of America. These financial statements are the responsibility of the Partnership's management.
Our responsibility is to express an opinion on these financial statements based on our 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 2 to the financial statements, the Partnership changed the manner in which it accounts for asset retirement costs as of January 1, 2003.

|                                  |  | PricewaterhouseCoopers LLP
|--------------------------------- |  | --------------------------
|Irvine, California
March 14, 2005 |  |                           

201

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MIDWAY-SUNSET COGENERATION COMPANY  BALANCE SHEETS  December 31, 2004 and 2003  (In thousands)

|                                       |                                                    | 2004                                   |        | 2003  
|-------------------------------------- | -------------------------------------------------- | -------------------------------------- | ------ | ------
|Assets                                 |                                                    |                                        |        |       
|Current assets                         |                                                    |                                        |        |       
|                                       | Cash and cash equivalents                          |                                        | $      | 3,094 
|                                       | Accounts receivable from affiliates                |                                        |        |       
|                                       |                                                    | Southern California Edison             |        |       
|                                       |                                                    | Aera Energy LLC                        |        |       
|                                       |                                                    | Other affiliates                       |        |       
|                                       | Accounts receivable from others                    |                                        |        | 918   
|                                       | Accounts receivable from California Power Exchange |                                        |        | 35,973
|                                       | Inventory                                          |                                        |        | 2,891 
|                                       |                                                    |                                        |        |       
|                                       |                                                    | Total current assets                   |        |       
|Plant and equipment, net               |                                                    |                                        | 75,121 |       
|Other assets                           |                                                    |                                        |        |       
|                                       | Emission offsets, net                              |                                        |        | 1,517 
|                                       | Deposits                                           |                                        |        | 268   
|                                       |                                                    |                                        |        |       
|                                       |                                                    | Total assets                           |        | $     
|                                       |                                                    |                                        |        |       
|Liabilities and Partners' Equity       |                                                    |                                        |        |       
|Current liabilities                    |                                                    |                                        |        |       
|                                       | Accounts payable to affiliates                     |                                        |        |       
|                                       |                                                    | Southern California Edison             |        |       
|                                       |                                                    | Other affiliates                       |        |       
|                                       | Accounts payable to others                         |                                        |        | 16,673
|                                       |                                                    |                                        |        |       
|                                       |                                                    | Total current liabilities              |        |       
|Asset retirement obligation            |                                                    |                                        | 1,468  |       
|                                       |                                                    |                                        |        |       
|                                       |                                                    | Total liabilities                      |        |       
|                                       |                                                    |                                        |        |       
|Commitments and contingencies (Note 7) |                                                    |                                        |        |       
|Partners' equity                       |                                                    |                                        |        |       
|                                       | San Joaquin Energy Company                         |                                        |        | 51,035
|                                       | Aera Energy LLC                                    |                                        |        | 51,035
|                                       |                                                    |                                        |        |       
|                                       |                                                    | Total partners' equity                 |        |       
|                                       |                                                    |                                        |        |       
|                                       |                                                    | Total liabilities and partners' equity |        | $     
|                                       |                                                    |                                        |        |       

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

202

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MIDWAY-SUNSET COGENERATION COMPANY  STATEMENTS OF INCOME  For the Years Ended December 31, 2004, 2003 and 2002  (In thousands)

|                                                                                                   |                                          | 2004                       |     | 2003    |         | 2002  
|-------------------------------------------------------------------------------------------------- | ---------------------------------------- | -------------------------- | --- | ------- | ------- | ------
|Operating Revenues                                                                                 |                                          |                            |     |         |         |       
|                                                                                                   | Sales of electricity to affiliates       |                            | $   | 142,453 |         | $     
|                                                                                                   | Sales of electricity to others           |                            |     | 3,650   |         |       
|                                                                                                   |                                          |                            |     |         |         |       
|                                                                                                   |                                          | Total sales of electricity |     |         | 146,103 |       
|                                                                                                   | Sales of steam to affiliate              |                            |     | 49,670  |         |       
|                                                                                                   |                                          |                            |     |         |         |       
|                                                                                                   |                                          | Total operating revenues   |     |         | 195,773 |       
|                                                                                                   |                                          |                            |     |         |         |       
|Operating Expenses                                                                                 |                                          |                            |     |         |         |       
|                                                                                                   | Fuel                                     |                            |     | 136,088 |         |       
|                                                                                                   | Plant and other operating                |                            |     | 11,122  |         |       
|                                                                                                   | Property taxes                           |                            |     | 1,982   |         |       
|                                                                                                   | Write-off of development costs           |                            |     |        |         |       
|                                                                                                   | Depreciation, amortization and accretion |                            |     | 8,569   |         |       
|                                                                                                   |                                          |                            |     |         |         |       
|                                                                                                   |                                          | Total operating expenses   |     |         | 157,761 |       
|                                                                                                   |                                          |                            |     |         |         |       
|                                                                                                   |                                          | Income from operations     |     |         | 38,012  |       
|                                                                                                   |                                          |                            |     |         |         |       
|Other Income (Expense)                                                                             |                                          |                            |     |         |         |       
|Interest and other income                                                                          |                                          |                            | 162 |         |         | 99    
|                                                                                                   |                                          |                            |     |         |         |       
|                                                                                                   | Total other income                       |                            |     | 162     |         |       
|                                                                                                   |                                          |                            |     |         |         |       
|Cumulative effect on prior years of change in accounting for asset retirement obligations (Note 2) |                                          |                            |    |         |         | (1,037
|                                                                                                   | Net income                               |                            | $   | 38,174  |         | $     
|                                                                                                   |                                          |                            |     |         |         |       

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

203

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MIDWAY-SUNSET COGENERATION COMPANY  STATEMENTS OF PARTNERS' EQUITY  December 31, 2004, 2003 and 2002  (In thousands)

|                             |  | San Joaquin
Energy
Company |         | Aera Energy
LLC |   | Total   |  
|---------------------------- |  | -------------------------- | ------- | --------------- | - | ------- | -
|Balance at December 31, 2001 |  | $                          | 77,261  |                 | $ | 77,261  |  
|Allocation of income         |  |                            | 14,405  |                 |   | 14,405  |  
|Cash distributions           |  |                            | (40,500 | )               |   | (40,500 | )
|                             |  |                            |         |                 |   |         |  
|Balance at December 31, 2002 |  |                            | 51,166  |                 |   | 51,166  |  
|Allocation of income         |  |                            | 17,782  |                 |   | 17,782  |  
|Cash distributions           |  |                            | (17,500 | )               |   | (17,500 | )
|                             |  |                            |         |                 |   |         |  
|Balance at December 31, 2003 |  |                            | 51,448  |                 |   | 51,448  |  
|Allocation of income         |  |                            | 19,087  |                 |   | 19,087  |  
|Cash distributions           |  |                            | (19,500 | )               |   | (19,500 | )
|                             |  |                            |         |                 |   |         |  
|Balance at December 31, 2004 |  | $                          | 51,035  |                 | $ | 51,035  |  
|                             |  |                            |         |                 |   |         |  

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

204

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MIDWAY-SUNSET COGENERATION COMPANY  STATEMENTS OF CASH FLOWS  For the Years Ended December 31, 2004, 2003 and 2002  (In thousands)

|                                                     |                                                                                   | 2004                                                |                                       | 2003                                      |       | 2002    |        
|---------------------------------------------------- | --------------------------------------------------------------------------------- | --------------------------------------------------- | ------------------------------------- | ----------------------------------------- | ----- | ------- | -------
|Cash flows from operating activities                 |                                                                                   |                                                     |                                       |                                           |       |         |        
|                                                     | Net income                                                                        |                                                     | $                                     | 38,174                                    |       | $       | 35,563 
|                                                     | Adjustments to reconcile net income to net cash provided by operating activities: |                                                     |                                       |                                           |       |         |        
|                                                     |                                                                                   | Depreciation, amortization and accretion            |                                       |                                           | 8,569 |         |        
|                                                     |                                                                                   | Loss (gain) on disposal of asset                    |                                       |                                           | 20    |         |        
|                                                     |                                                                                   | Write-off of development costs                      |                                       |                                           |      |         |        
|                                                     |                                                                                   | Cumulative effect of change in accounting principle |                                       |                                           |      |         |        
|                                                     |                                                                                   | Changes in assets and liabilities                   |                                       |                                           |       |         |        
|                                                     |                                                                                   |                                                     | Accounts receivable                   |                                           |       | (12,775 | )      
|                                                     |                                                                                   |                                                     | Inventory                             |                                           |       | 105     |        
|                                                     |                                                                                   |                                                     | Deposits                              |                                           |       | (101    | )      
|                                                     |                                                                                   |                                                     | Accounts payable                      |                                           |       | 3,607   |        
|                                                     |                                                                                   |                                                     | Other liabilities                     |                                           |       |        |        
|                                                     |                                                                                   |                                                     |                                       |                                           |       |         |        
|                                                     |                                                                                   |                                                     |                                       | Net cash provided by operating activities |       |         | 37,599 
|                                                     |                                                                                   |                                                     |                                       |                                           |       |         |        
|Cash flows from investing activities:                |                                                                                   |                                                     |                                       |                                           |       |         |        
|                                                     | Capital expenditures                                                              |                                                     |                                       | (1,466                                    | )     |         | (4,483 
|                                                     | Proceeds from sale of equipment                                                   |                                                     |                                       | 22                                        |       |         | 37     
|                                                     |                                                                                   |                                                     |                                       |                                           |       |         |        
|                                                     |                                                                                   |                                                     | Net cash used in investing activities |                                           |       | (1,444  | )      
|                                                     |                                                                                   |                                                     |                                       |                                           |       |         |        
|Cash flows from financing activities:                |                                                                                   |                                                     |                                       |                                           |       |         |        
|                                                     | Distributions to partners                                                         |                                                     |                                       | (39,000                                   | )     |         | (35,000
|                                                     |                                                                                   |                                                     |                                       |                                           |       |         |        
|Net (decrease) increase in cash and cash equivalents |                                                                                   |                                                     | (2,845                                | )                                         |       | 3,309   |        
|Cash and cash equivalents, beginning of year         |                                                                                   |                                                     | 5,939                                 |                                           |       | 2,630   |        
|                                                     |                                                                                   |                                                     |                                       |                                           |       |         |        
|Cash and cash equivalents, end of year               |                                                                                   | $                                                   | 3,094                                 |                                           | $     | 5,939   |        
|                                                     |                                                                                   |                                                     |                                       |                                           |       |         |        

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

205

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MIDWAY-SUNSET COGENERATION COMPANY  NOTES TO FINANCIAL STATEMENTS  December 31, 2004, 2003 and 2002

Midway-Sunset Cogeneration Company (the "Partnership") is a California general partnership between San Joaquin Energy Company ("San Joaquin"), holding a
50 percent general partnership interest and Aera Energy LLC ("Aera"), a California limited liability company whose members are (i) SWEPI LP and (ii) Shell Onshore
Ventures, Inc. (affiliates of Shell Oil Company) and (iii) Mobil California Exploration and Producing Asset Company (affiliate of ExxonMobil), holding a combined 50 percent
general partnership interest. San Joaquin is a wholly owned subsidiary of Edison Mission Energy ("Mission"), an indirect wholly owned subsidiary of Edison International.

The
Partnership was organized to design, construct, own and operate a qualifying cogeneration facility (the "Facility"), as defined in the Public Utility Regulatory Policies Act of 1978
and the regulations promulgated thereunder, all as amended ("PURPA"), located in Kern County, California. The Facility currently sells most of the electricity generated to Southern California Edison
Company ("SCE"), a wholly owned subsidiary of Edison International, for resale to its customers and sells all steam produced to Aera for use in its Midway-Sunset oil field operations. The Facility was
certified as a "qualifying facility" under PURPA prior to the start of operations, and management believes they have fulfilled all requirements to receive continued "qualifying facility" status.

The
Facility consists of three combustion turbine generators producing electricity and steam sequentially using one fuel source. The Facility is designed to have the capacity of
generating 228 megawatts of electricity and 1.2 million pounds of steam per hour.

The
Partnership, unless sooner dissolved or extended pursuant to the terms of the partnership agreement, will be dissolved on May 8, 2010.

Use of Estimates

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

Cash and Cash Equivalents

The Partnership considers cash and cash equivalents to include cash and short-term investments with an original maturity of three months or less. The
carrying amount of cash and cash equivalents approximates fair value because of the short maturity of these investments.

Inventory

Inventory is stated at the lower of weighted average cost or market.

206

---



Inventory
consists of the following at December 31, 2004 and 2003:

2004

2003Natural gas

$
52

$
406Materials and spare parts


2,839


2,590$
2,891

$
2,996


Plant and Equipment

Plant and equipment are stated at cost. Depreciation is computed on a straight-line basis over the following estimated useful lives:

Power plant facilities

12 to 30 yearsFurniture and office equipment

3 to 7 years


Expenditures
for maintenance, repairs and renewals are expensed as incurred. Expenditures for additions and improvements are capitalized. The facilities require major maintenance,
including inspections and overhauls, on a periodic basis. These costs are also expensed as incurred.

Impairment of Long-lived Assets

Long-lived assets are reviewed for impairment whenever events or changes in circumstances indicate that the carrying amount of an asset may not be
fully recoverable. Recoverability of assets to be held and used is measured by a comparison of the carrying amount of the assets to their fair value, which is normally determined through analysis of
the future net cash flows expected to be generated by the assets. If such assets are considered to be impaired, the impairment to be recognized is measured by the amount that the carrying amount of
the assets exceeds the fair value of the assets.

Emission Offsets

Emission offsets contributed to the Partnership were valued at an amount agreed upon by the partners and are being amortized on a straight-line basis
over a period of 20 years. Emission offsets consist of the following at December 31, 2004 and 2003:

2004

2003Cost

$
7,000

$
7,000Less: Accumulated amortization


(5,483
)

(5,133
)$
1,517

$
1,867


Amortization
expense was $350,000 in 2004, 2003 and 2002.

Financial Instruments

Financial instruments that potentially subject the Partnership to significant concentrations of credit or valuation risk consist principally of cash equivalents
and accounts receivable.

The
carrying amounts, reported in the balance sheets for cash and cash equivalents, and accounts receivable, approximate fair value.

207

---



Accounting for Derivative Instruments and Hedging Activities

In accordance with SFAS No. 133, "Accounting for Derivative Instruments and Hedging Activities," as amended, all derivative instruments, except those
meeting specific exceptions, are recognized in the balance sheet at their fair value. Changes in fair value are recognized immediately in earnings unless specific hedge accounting criteria to met. For
derivatives that qualify for hedge accounting, depending on the nature of the hedge, changes in fair value are either offset by changes in the fair value of the hedged assets, liabilities or firm
commitments through earnings, or recognized in other comprehensive income until the hedged item is recognized in earnings.

Management
has determined that the Partnership's energy and capacity sales commitments qualify for the normal purchases and normal sales exception provided by SFAS 133 and related
guidance issued by the Derivatives Implementation Group. This exception applies to physical sales and purchases of power where it is probable that physical delivery will occur, the pricing provisions
are clearly and closely related to the contracted prices and the SFAS 133 documentation requirements are met. In April 2003, the Financial Accounting Standards Board issues SFAS
No. 149, "Amendment of Statement 133 on Derivative Instruments and Hedging Activities." SFAS 149 changed the guidance related to the application of the normal purchases and normal sales
exception to electricity contracts. This change had no impact on the designation of the Partnership's electricity contracts as normal.

Management
also determined that the Partnership's steam sales do not meet the definition of a derivative and are, therefore, not subject to the requirements of the standard.

Revenue Recognition

Revenue is recognized as delivered under the provisions of three power purchase agreements which have varying terms of approximately four to twenty years.
Electricity revenue is calculated based on power output and established prices, as defined in the power purchase agreements. Steam revenue is calculated based on steam output and established prices,
as defined in the steam sale and purchase agreement. Revenue is also recognized as billable under the provisions of a steam sale and purchase agreement.

Income Taxes

The Partnership is treated as a partnership for income tax purposes and the income or loss of the Partnership is included in the income tax returns of the
individual partners. Accordingly, no recognition has been given to income taxes in the financial statements.

Asset Retirement Obligation

Effective January 1, 2003, the Partnership adopted Statement of Financial Accounting Standards ("SFAS") No. 143, "Accounting for Asset Retirement
Obligations." SFAS No. 143 requires entities to record the fair value of a liability for an asset retirement obligation in the period in which it is incurred. When the liability is initially
recorded, the entity capitalizes a cost by increasing the carrying amount of the related long-lived asset. Over time, the liability is increased to its present value each period, and the
capitalized cost is depreciated over the useful life of the related asset. Upon settlement of the liability, an entity either settles the obligation for its recorded amount or incurs a gain or loss
upon settlement. On January 1, 2003, the Partnership recorded a $1,037,000 decrease to net income as the cumulative effect of adoption of SFAS No. 143. Accretion expense is classified as
part of depreciation, amortization and accretion.

208

---



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

Initial asset retirement obligation as of January 1, 2003

$
1,239Accretion expense


109Balance of asset retirement obligation as of December 31, 2003


1,348Accretion expense


119Balance of asset retirement obligation as of December 31, 2004

$
1,467


Had
SFAS No. 143 been applied retroactively in the year ended December 31, 2002 it would not have had a material effect upon the Partnership's results.

Plant
and equipment consists of the following at December 31, 2004 and 2003:

2004

2003Power plant facilities

$
169,826

$
168,640Furniture and office equipment


1,295


1,357171,121


169,997Less: accumulated depreciation and amortization


(96,365
)

(88,397
)Construction in process


365


197$
75,121

$
81,797


The
depreciable life of the operating facility exceeds the term of the related power purchase agreements. The viability of the facility subsequent to the expiration of the power purchase
agreements is dependent upon the Partnership's ability to enter into new contracts at terms that would allow the facility to operate at a profit.

Management
continues to evaluate its operational options at the conclusion of the contract lives. Management believes the useful lives are appropriate and that the facility will continue
to operate profitably subsequent to the expiration of the power purchase agreements. However, if management subsequently determines that the facility will not be able to operate profitably beyond the
term of the purchase agreements, management may make additional changes in the depreciable lives and an impairment charge may be required.

The
partnership is required to maintain a deposit with the California ISO and the Automated Power Exchange to ensure monthly liquidity requirements as a scheduling coordinator. Deposits
are held at the
California ISO for Scheduling Coordinator security and at the Automated Power Exchange for security on the refund period. Total deposits are held at the two locations. Deposits totaled $268,000 and
$167,000 at December 31, 2004, and December 31, 2003, respectively.

In
addition to the related party transactions discussed in Notes 3, 7 and 9, the Partnership entered into certain contracts and agreements with San Joaquin, Aera and certain other
related parties.

209

---



Power Purchase Agreements

Under the terms of a Power Purchase Agreement ("PPA"), SCE agreed to purchase up to 200 megawatts of the electric power generated by the Facility for a period of
20 years. The PPA expires in 2009. SCE operates as a regulated utility and is a sister company of Mission. The Partnership is paid for energy based on an energy rate that is calculated using a
Short Run Avoided Cost ("SRAC") based formula that contains a prescribed energy rate indexed to the Southern California Border Spot Price of natural gas. At such time as the California Public
Utilities Commission ("CPUC") issues an order determining that the California Power Exchange, or equivalent, is functioning properly, as defined in the amendment, the SRAC based energy rate will be
compared to a price determined by taking 95 percent of the energy rate posted by the California Power Exchange (PX). The higher of the two rates will be used to calculate energy payments due
the Partnership. SCE also pays the Partnership for firm capacity based upon a contracted amount per kilowatt year, as determined in the Power Purchase Agreement.

In
March 1999, the Partnership entered into an agreement (the "Agreement") with Kern River Cogeneration Company ("Kern River") and Sycamore Cogeneration Company ("Sycamore"), Kern River
and Sycamore are related parties jointly owned by affiliates of EME and Chevron. The Agreement supports a mutually beneficial settlement agreement related to energy prices approved by the CPUC. The
Agreement provides for payment of specified amounts from Kern River and Sycamore to the Partnership, contingent upon the Partnership's deliveries to SCE. Under the terms of the Agreement, Kern River
and Sycamore paid the Partnership $1,636,000, $1,476,000 and $2,080,000 in 2004, 2003 and 2002, respectively.

Effective
April 30, 1997, the Partnership entered into an agreement with Aera to sell 9 megawatts of excess electric energy generated by the Facility. The terms of the agreement
require Aera to pay for
electric energy based on a formula defined in the agreement but provided for a rebate at the conclusion of the contract if cumulative payments exceeded a certain threshold. Accordingly, the
Partnership paid Aera $12 million during 2002.

The
Partnership recognized total electricity sales to affiliates of $142,453,000, $131,448,000 and $95,267,000 in 2004, 2003 and 2002, respectively, under these contracts. The
Partnership has a payable of $34,586,000 to SCE which is wholly offset by a receivable from the California Power Exchange. For further discussion of this situation refer to Note 7. Receivable
from California Power Exchange.

Steam Sale and Purchase Agreement

Under the terms of a Steam Sale and Purchase Agreement, Aera purchases 8.6 billion pounds of steam per year generated by the Facility through May 1,
2009. The Partnership is paid a steam fuel charge based upon the quantity and quality of steam delivered during the month, which is priced at the weighted average of the Partnership's cost of fuel and
a processing charge per MMBtu, as defined in the Steam Sale and Purchase Agreement. The Partnership sold $49,670,000, $45,332,000 and $30,633,000 of steam in 2004, 2003 and 2002, respectively, under
this agreement which is included within sales of steam in the accompanying statements of income. The quantity of steam sold under this agreement is sufficient for the Partnership to meet qualifying
facility status.

Operation and Maintenance Agreement

Under the terms of an Operation and Maintenance Agreement, employees of Edison Mission Operations and Maintenance, Inc. ("EMOM"), a wholly owned subsidiary
of Mission, perform all necessary functions to operate and maintain the Facility.

210

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The
Partnership pays for direct costs of these services, plus an increment to cover overhead and benefits. In addition, effective January 1992, the Agreement was amended to
include payment to EMOM of certain annual fees. Pursuant to this Agreement, the Partnership incurred costs of $3,389,000, $3,028,000 and $3,032,000 which included annual fees earned by EMOM of
$336,000 in 2004, 2003 and 2002, respectively, which are included in contract labor in the accompanying statements of income.

Other Agreements

Under the terms of the Partnership Agreement, including a Gas Management Services Agreement, employees of Aera perform services for the Partnership. The
Partnership pays for direct costs of these services, plus an increment to cover overhead and benefits. Pursuant to this arrangement, the Partnership incurred costs of $357,000, $350,000 and $311,000
in 2004, 2003 and 2002, respectively.

Under
the terms of a Financial Services Agreement, San Joaquin provides certain financial, accounting and other services for an annual fee of $125,000 in 2004, 2003 and 2002.

Under
the terms of a Surface Lease Agreement, the Partnership leases approximately 13 acres of land from Aera, which serves as the Facility site. The initial term of the lease extends
through October 1, 2009, with an annual rental, amended as of January 1998, of $1,000.

The
Partnership is owed $35,973,000 included in Accounts Receivable as of December 31, 2004, by the PX for power sold into the California ISO during 2000 and 2001 that was not
collected as a result of the PX bankruptcy in 2001. The PX, upon receiving funds from its debtors, will pay the Partnership an amount adjusted for wind down charges. The Partnership will then
pro-rate the receipt and reimburse the following parties as follows: SCE $34,586,000, PG&E $867,000, included in Accounts Payable, for previous power sales. The Partnership is obligated to
reimburse SCE and Pacific Gas and Electric (PG&E), only if funds are received from the PX.

Effective
November 1989, the Partnership entered into a 20 year Power Purchase Agreement with PG&E, a public utility, whereby the utility agreed to purchase excess
on-peak and partial peak electricity from the Facility. This excess electricity consists of the facility output less station use, Aera field use and the initial 200 megawatts generated for
sale to SCE. Upon request by the utility, the Facility may deliver during off-peak and super off-peak periods. The Partnership sold $3,159,000, $2,090,000 and $2,046,000 of
electricity in 2004, 2003 and 2002, respectively, under this agreement which is included within sales of electricity to others in the accompanying statements of income.

The
Partnership has agreed to pay PG&E maintenance and other fees during the term of the Interconnection contract for the transmission facilities used to transport the electric power
generated to SCE, PG&E and others. The Partnership incurred maintenance fees of $1,181,000 for these services in 2004, 2003 and 2002.

On
December 30, 2003, the Reorganized California Power Exchange Corporation ("CPX") filed a lawsuit against its former officers and directors, including the Executive Director of the
Partnership, in his capacity as a Governor of the Power Exchange Corporation, related to certain actions/inactions purportedly taken by them during their tenure with respect to collateral posted in
support of transactions with the CPX. The Partnership has agreed to indemnify the Executive Director with respect to this lawsuit. At this time the Partnership cannot estimate what the ultimate cost
will be under this indemnity.

211

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Credit Risk

The Partnership is exposed to credit risk related to potential nonperformance by counterparties to its energy, capacity and steam sales. The Partnership's sales
are concentrated among two primary counterparties:

2004

2003SCE

$
130,767,000

$
120,686,000Aera


61,355,000


56,095,000$
192,122,000

$
176,781,000


Due to the concentration of credit risk, the Partnership's liquidity could be impacted by financial difficulties experienced by its
counterparties. As a result of the energy crisis in California, SCE suspended payment of amounts due to the Partnership in December 2000; however, all past due amounts have been repaid.

212

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Report of Independent Registered Public Accounting Firm

To the Management Committee of
March Point Cogeneration Company

In
our opinion, the accompanying balance sheets and the related statements of income and comprehensive income, partners' equity, and cash flows present fairly, in all material respects,
the financial position of March Point Cogeneration Company at December 31, 2004 and 2003, and the results of its operations and its cash flows for each of the three years in the period ended
December 31, 2004 in conformity with accounting principles generally accepted in the United States of America. These financial statements are the responsibility of the Partnership's management.
Our responsibility is to express an opinion on these financial statements based on our 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.

|                                  |  | PricewaterhouseCoopers LLP
|--------------------------------- |  | --------------------------
|Irvine, California
March 14, 2005 |  |                           

213

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MARCH POINT COGENERATION COMPANY  BALANCE SHEETS  December 31, 2004 and 2003

|                                               |                                           | 2004                     |                                        | 2003      
|---------------------------------------------- | ----------------------------------------- | ------------------------ | -------------------------------------- | ----------
|Assets                                         |                                           |                          |                                        |           
|Current assets                                 |                                           |                          |                                        |           
|                                               | Cash and cash equivalents                 |                          | $                                      | 11,027,000
|                                               | Receivables                               |                          |                                        |           
|                                               |                                           | Equilon and subsidiaries |                                        |           
|                                               |                                           | Puget Sound Energy       |                                        |           
|                                               |                                           | Other                    |                                        |           
|                                               | Note receivable                           |                          |                                        | 4,948,000 
|                                               | Current portion of escrow account         |                          |                                        |          
|                                               | Inventory                                 |                          |                                        | 5,449,000 
|                                               |                                           |                          |                                        |           
|                                               |                                           |                          | Total current assets                   |           
|                                               |                                           |                          |                                        |           
|Operating facility and equipment, at cost, net |                                           |                          | 79,071,000                             |           
|                                               |                                           |                          |                                        |           
|Other assets                                   |                                           |                          |                                        |           
|                                               | Deferred loan fees                        |                          |                                        |          
|                                               | Gas purchase agreements at fair value     |                          |                                        | 36,243,000
|                                               |                                           |                          |                                        |           
|                                               |                                           |                          | Total other assets                     |           
|                                               |                                           |                          |                                        |           
|                                               |                                           |                          | Total assets                           |           
|                                               |                                           |                          |                                        |           
|Liabilities and Partners' Equity               |                                           |                          |                                        |           
|Current liabilities                            |                                           |                          |                                        |           
|                                               | Current portion of project financing loan |                          |                                        |          
|                                               | Working capital loan                      |                          |                                        |          
|                                               | Payables                                  |                          |                                        |           
|                                               |                                           | Related parties          |                                        |           
|                                               |                                           | Trade and other payables |                                        |           
|                                               | Other current liabilities                 |                          |                                        | 9,000     
|                                               |                                           |                          |                                        |           
|                                               |                                           |                          | Total current liabilities              |           
|                                               |                                           |                          |                                        |           
|Commitments and contingencies (Note 8)         |                                           |                          |                                        |           
|Partners' equity                               |                                           |                          | 136,661,000                            |           
|                                               |                                           |                          |                                        |           
|                                               |                                           |                          | Total liabilities and partners' equity |           
|                                               |                                           |                          |                                        |           

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

214

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MARCH POINT COGENERATION COMPANY  STATEMENTS OF INCOME AND COMPREHENSIVE INCOME  December 31, 2004, 2003 and 2002

|                                                   |                                   | 2004 |             | 2003       |   | 2002        |           
|-------------------------------------------------- | --------------------------------- | ---- | ----------- | ---------- | - | ----------- | ----------
|Operating revenues                                 |                                   |      |             |            |   |             |           
|Sales of energy to Puget Sound Energy              |                                   | $    | 62,306,000  |            | $ | 64,903,000  |           
|Sales of steam to Equilon                          |                                   |      | 13,588,000  |            |   | 13,699,000  |           
|                                                   |                                   |      |             |            |   |             |           
|                                                   | Total operating revenues          |      |             | 75,894,000 |   |             | 78,602,000
|                                                   |                                   |      |             |            |   |             |           
|Operating expenses                                 |                                   |      |             |            |   |             |           
|Fuel expense                                       |                                   |      | 35,214,000  |            |   | 45,975,000  |           
|Plant and other operating expenses                 |                                   |      | 6,043,000   |            |   | 6,184,000   |           
|Depreciation and amortization                      |                                   |      | 4,764,000   |            |   | 4,783,000   |           
|General and administrative expenses                |                                   |      | 334,000     |            |   | 315,000     |           
|                                                   |                                   |      |             |            |   |             |           
|                                                   | Total operating expenses          |      |             | 46,355,000 |   |             | 57,257,000
|                                                   |                                   |      |             |            |   |             |           
|                                                   | Income from operations            |      |             | 29,539,000 |   |             | 21,345,000
|                                                   |                                   |      |             |            |   |             |           
|Other income (expense)                             |                                   |      |             |            |   |             |           
|Interest and other income                          |                                   |      | 782,000     |            |   | 417,000     |           
|Interest expense                                   |                                   |      | (253,000    | )          |   | (638,000    | )         
|                                                   |                                   |      |             |            |   |             |           
|                                                   | Total other income (expense)      |      |             | 529,000    |   |             | (221,000  
|                                                   |                                   |      |             |            |   |             |           
|                                                   | Net income                        |      |             | 30,068,000 |   |             | 21,124,000
|                                                   |                                   |      |             |            |   |             |           
|Other comprehensive income (loss)                  |                                   |      |             |            |   |             |           
|Unrealized gain (loss) arising during the period   |                                   |      | 7,462,000   |            |   | 31,291,000  |           
|Reclassification adjustment included in net income |                                   |      | (13,219,000 | )          |   | (10,823,000 | )         
|                                                   |                                   |      |             |            |   |             |           
|                                                   | Other comprehensive income (loss) |      |             | (5,757,000 | ) |             | 20,468,000
|                                                   |                                   |      |             |            |   |             |           
|                                                   | Comprehensive income              |      | $           | 24,311,000 |   | $           | 41,592,000
|                                                   |                                   |      |             |            |   |             |           

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

215

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MARCH POINT COGENERATION COMPANY  STATEMENTS OF PARTNERS' EQUITY  December 31, 2004, 2003 and 2002

|                                   |  | Equilon
Enterprises
LLC |            | Texaco
March Point
Holdings Inc. |   | San Juan
Energy
Company |   | Total |           
|---------------------------------- |  | ----------------------- | ---------- | -------------------------------- | - | ----------------------- | - | ----- | ----------
|Balances at December 31, 2001      |  |                         | 19,647,000 |                                  |   | 19,806,000              |   |       | 39,452,000
|Allocation of comprehensive income |  |                         | 8,037,000  |                                  |   | 8,101,000               |   |       | 16,138,000
|Distributions                      |  |                         | (3,050,000 | )                                |   | (3,075,000              | ) |       | (6,125,000
|                                   |  |                         |            |                                  |   |                         |   |       |           
|Balances at December 31, 2002      |  |                         | 24,634,000 |                                  |   | 24,832,000              |   |       | 49,465,000
|Allocation of comprehensive income |  |                         | 10,356,000 |                                  |   | 10,440,000              |   |       | 20,796,000
|Distributions                      |  |                         | (2,814,000 | )                                |   | (2,836,000              | ) |       | (5,650,000
|                                   |  |                         |            |                                  |   |                         |   |       |           
|Balances at December 31, 2003      |  |                         | 32,176,000 |                                  |   | 32,436,000              |   |       | 64,611,000
|Allocation of comprehensive income |  |                         | 6,053,000  |                                  |   | 6,102,000               |   |       | 12,156,000
|Distributions                      |  |                         | (1,245,000 | )                                |   | (1,255,000              | ) |       | (2,500,000
|Merger with TM Star (Note 3)       |  |                         | (2,956,000 | )                                |   | (2,980,000              | ) |       | (5,937,000
|                                   |  |                         |            |                                  |   |                         |   |       |           
|Balances at December 31, 2004      |  | $                       | 34,028,000 |                                  | $ | 34,303,000              |   | $     | 68,330,000
|                                   |  |                         |            |                                  |   |                         |   |       |           

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

216

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MARCH POINT COGENERATION COMPANY  STATEMENTS OF CASH FLOWS  December 31, 2004, 2003 and 2002

|                                                                                 |                                                     | 2004        |                                                      | 2003        |            | 2002        |          
|-------------------------------------------------------------------------------- | --------------------------------------------------- | ----------- | ---------------------------------------------------- | ----------- | ---------- | ----------- | ---------
|Cash flows from operating activities                                             |                                                     |             |                                                      |             |            |             |          
|Net income                                                                       |                                                     | $           | 30,068,000                                           |             | $          | 21,124,000  |          
|Adjustments to reconcile net income to net cash provided in operating activities |                                                     |             |                                                      |             |            |             |          
|                                                                                 | Depreciation and amortization                       |             |                                                      | 4,764,000   |            |             | 4,783,000
|                                                                                 | Loss on Canwest settlement                          |             |                                                      | 853,000     |            |             |         
|                                                                                 | Loss on disposal of equipment                       |             |                                                      | 56,000      |            |             | 9,000    
|                                                                                 | Reclassification of discontinued hedge              |             |                                                      | (10,008,000 | )          |             |         
|                                                                                 | Unrealized gains and losses on derivative contracts |             |                                                      | (2,932,000  | )          |             | (715,000 
|                                                                                 | Changes in operating assets and liabilities         |             |                                                      |             |            |             |          
|                                                                                 |                                                     | Receivables |                                                      |             | 4,387,000  |             |          
|                                                                                 |                                                     | Inventory   |                                                      |             | (3,014,000 | )           |          
|                                                                                 |                                                     | Payables    |                                                      |             | 3,003,000  |             |          
|                                                                                 |                                                     |             |                                                      |             |            |             |          
|                                                                                 |                                                     |             | Net cash provided by operating activities            |             |            | 27,177,000  |          
|Cash flows from investing activities                                             |                                                     |             |                                                      |             |            |             |          
|Additions to operating facility and equipment                                    |                                                     |             | (339,000                                             | )           |            | (420,000    | )        
|                                                                                 |                                                     |             |                                                      |             |            |             |          
|Cash flows from financing activities                                             |                                                     |             |                                                      |             |            |             |          
|Proceeds from working capital loan                                               |                                                     |             |                                                     |             |            | 5,000,000   |          
|Payment on project financing loan                                                |                                                     |             | (13,724,000                                          | )           |            | (13,684,000 | )        
|Payment on working capital loan                                                  |                                                     |             | (5,000,000                                           | )           |            | (5,000,000  | )        
|Proceeds from escrow account                                                     |                                                     |             | 936,000                                              |             |            | 684,000     |          
|Change in overdrafts                                                             |                                                     |             | (389,000                                             | )           |            | 360,000     |          
|Distributions to partners                                                        |                                                     |             | (5,000,000                                           | )           |            | (11,300,000 | )        
|                                                                                 |                                                     |             |                                                      |             |            |             |          
|                                                                                 |                                                     |             | Net cash used in financing activities                |             |            | (23,177,000 | )        
|                                                                                 |                                                     |             |                                                      |             |            |             |          
|                                                                                 |                                                     |             | Net increase (decrease) in cash and cash equivalents |             |            | 3,661,000   |          
|Cash and cash equivalents                                                        |                                                     |             |                                                      |             |            |             |          
|Beginning of year                                                                |                                                     |             | 7,366,000                                            |             |            | 7,323,000   |          
|                                                                                 |                                                     |             |                                                      |             |            |             |          
|End of year                                                                      |                                                     | $           | 11,027,000                                           |             | $          | 7,366,000   |          
|                                                                                 |                                                     |             |                                                      |             |            |             |          
|Supplemental disclosure of cash flow information                                 |                                                     |             |                                                      |             |            |             |          
|Cash payments for interest                                                       |                                                     | $           | 261,000                                              |             | $          | 590,000     |          
|                                                                                 |                                                     |             |                                                      |             |            |             |          

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

217

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MARCH POINT COGENERATION COMPANY  NOTES TO FINANCIAL STATEMENTS  December 31, 2004, 2003 and 2002

March
Point Cogeneration Company (the "Partnership") is a general partnership between Texaco March Point Holdings Inc. ("TMPHI"), an indirect wholly-owned subsidiary of
ChevronTexaco Corporation ("Chevron"), San Juan Energy Company ("SJEC"), an indirect wholly-owned subsidiary of Edison International ("Edison") and Equilon Enterprises LLC ("Equilon"), a
subsidiary of Shell Oil Products US. The Partnership was organized under California law on July 28, 1989. During the years ended December 31, 2004, 2003 and 2002, the SJEC, TMPHI and
Equilon ownership ratios were 50%, 25.1% and 24.9%, respectively.

The
Partnership was organized to design, construct, own and operate a qualifying cogeneration facility (the "Facility"), as defined in the Public Utility Regulatory Policies Act of 1978
and the regulations promulgated thereunder, all as amended ("PURPA"), located in Skagit County, Washington. The Partnership currently sells all the electric energy generated by the facility under an
agreement extending until December 31, 2011 to Puget Sound Energy, Inc. ("Puget Sound Energy") for resale to its customers, and sells all steam produced to Equilon for use in its crude
oil refining operations in its Puget Sound Refinery ("PSR"). The Facility was certified as a "qualifying facility" under PURPA prior to the start of operations, and management believes they have
fulfilled all requirements to receive continued "qualifying facility" status.

Comprehensive
income (loss) is allocated to the partners in proportion to their ownership percentages. The Partnership shall terminate, unless terminated at an earlier date pursuant to
the general partnership agreement, on the latter of December 31, 2011 or the date the Partnership elects to cease operations.

Construction
of the Facility was done in two Phases (Phase I and Phase II). Phase I of the Facility consists of two gas combustion turbine-generators, which exhaust heat into two heat
recovery steam generators ("HRSG") producing electricity and steam sequentially using one fuel source. Phase II consists of one gas combustion turbine-generator, which exhausts heat into a HRSG, and a
steam turbine-generator which accepts steam from Phase I and II to produce additional electricity. The Facility is designed to support the nominally rated production of 140 megawatts of electric
energy and 476,000 pounds per hour of steam (exclusive of supplementary firing of the boilers), with Phase I nominally producing 80 megawatts and 320,000 pounds per hour and Phase II producing 60
megawatts and 156,000 pounds per hour.

Use of Estimates

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

218

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Cash and Cash Equivalents

The Partnership considers short-term temporary cash investments with an original maturity of three months or less to be cash equivalents. The carrying
amount of cash and cash equivalents approximates fair value because of the short maturity of these instruments. The majority of Partnership's short-term investments are held by Chevron on
behalf of the Partnership. The balance of the short-term investments held by Chevron at December 31, 2004 and 2003 is $11,026,000 and $7,365,000, respectively.

Inventory

The Partnership's inventory consists of spare parts, materials and supplies and is valued at the lower of average cost or market.

Operating Facility and Equipment

The Facility and related equipment are stated at cost. The plant balance includes all costs incurred prior to commercial operation of the plants, net of revenue
earned during the pre-commission phase. The Facility and related equipment are being depreciated on a straight-line basis, over 30 years, the estimated life of the
Facility. Computer equipment is depreciated on a straight-line basis, over 3 years and other property and equipment is depreciated over 5 years.

Expenditures
for maintenance, repairs and renewals are expensed as incurred. Expenditures for additions and improvements are capitalized. The operating facility requires major
maintenance, including inspections and overhauls, on a periodic basis. These costs are also expensed as incurred.

Impairment of Long-lived Assets

Long-lived assets are reviewed for impairment whenever events or changes in circumstances indicate that the carrying amount of an asset may not be
fully recoverable. Recoverability of assets to be held and used is measured by a comparison of the carrying amount of the assets to their fair value, which is normally determined through analysis of
the future net cash flows expected to be generated by the assets. If such assets are considered to be impaired, the impairment to be recognized is to be measured by the amount that the carrying amount
of the assets exceeds the fair value of the assets.

Deferred Loan Fees

All legal and financial fees associated with the Loan and Credit Agreement (Note 5) were deferred and were being amortized, using the effective interest
method, over the term of the loan. At December 31, 2004, the Company paid the entire balance of the loan and no longer has any deferred loan fees. Deferred loan fees were presented net of
accumulated amortization of $1,908,000 at December 31, 2003.
Amortization expense was approximately $21,000, $63,000 and $105,000 in 2004, 2003 and 2002, respectively.

Other Current Liabilities

Other current liabilities is comprised of book overdrafts.

Revenue Recognition

Revenue is recognized as the product being sold is delivered.

219

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Income Taxes

The Partnership's income is included in the income tax returns of the partners. Therefore, no provision (benefit) for income taxes has been included in the
accompanying financial statements.

Fair Value of Financial Instruments

The carrying amount of the short-term investments approximates fair value due to the short maturity of those instruments. The project financing loan
payable and the working capital loan payable were variable interest rate loans and, based on the borrowing rates currently available to the Partnership for long-term debt with similar
terms and maturities, the carrying amount of these loans approximated fair value.

Risk Management and Hedging Activities

The Partnership accounts for derivative instruments in accordance with Financial Accounting Standards Board Statement No. 133 ("SFAS 133"), Accounting for
Derivative Instruments and Hedging Activities, and related guidance issued by the Derivatives Implementation Group ("DIG"). Under
SFAS 133, all derivative instruments, except those meeting specific exceptions, are recognized in the balance sheet at their fair value. Changes in fair value are recognized immediately in
earnings unless specific hedge accounting criteria are met. For derivatives that qualify for hedge accounting, depending on the nature of the hedge, changes in fair value are either offset by changes
in the fair value of the hedged assets, liabilities or firm commitments through earnings, or recognized in other comprehensive income until the hedged item is recognized in earnings.

Management
has determined that the Partnership's energy and capacity sales commitments qualify for the normal purchases and normal sales exception provided by SFAS 133 and the
related DIG guidance. This exception applies to physical sales and purchases of power or fuel where it is probable that physical delivery will occur, the pricing provisions are clearly and closely
related to the contracted prices and the SFAS 133 documentation requirements are met. In April 2003, the Financial Accounting Standards Board issued SFAS No. 149
("SFAS 149"),Amendment of Statement 133 on Derivative Instruments and Hedging Activities. SFAS 149 changed the guidance related to the
application of the normal purchases and normal sales exception to electricity contracts. This change had no impact on the designation of the Partnership's electricity contract as normal. Management
also determined that the Partnership's steam sales agreement does not meet the definition of a derivative and is, therefore, not subject to the requirements of the standard.

The
Partnership's primary market risk exposures arise from fluctuations in the price of natural gas. Management manages these risks in part by entering into forward natural gas purchase
contracts (Note 6).

Asset Retirement Obligations

On January 1, 2003, the Partnership adopted Financial Accounting Standards Board Statement No. 143 ("SFAS 143"), Accounting for Asset Retirement
Obligations. In accordance with its site lease agreement (Note 7), the Partnership is required to restore the
site or transfer ownership of the Facility to the lessor at the termination of the lease. The lessor can decline to accept ownership, thereby requiring site restoration. Although the Partnership could
be required to restore the site, management believes that this is remote, due to the isolated location and the other needs for the facility and equipment. Therefore, no asset retirement obligation was
recorded upon adoption of SFAS 143 and management continues to assess this exposure.

220

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Reclassifications

Certain prior period amounts have been reclassified to conform with the current period presentation.

Prior
to January 16, 2004, the Partnership purchased natural gas under a long-term contract with TM Star Fuel Company ("TM Star"), a general partnership between Texaco
Cogeneration Fuel Company, an indirect wholly owned subsidiary of Chevron, and Southern Sierra Gas Company, an affiliate of Edison.

During
2003, the Partnership entered into a Merger Agreement with TM Star. The merger was consummated on January 16, 2004. Under the terms of the agreement, the Partnership is the
surviving partnership and TM Star ceased to exist. The percentage ownership of the Partnership remains unchanged under the new entity structure. However, due to differences in ownership between TM
Star and the Partnership, a subsidiary of Chevron made a capital contribution to TM Star and TM Star made a payment to Equilon in the amount of $3,968,000. There was no other cash exchanged as a
result of the merger.

TM
Star's sole business was comprised of the fuel supply agreement with the Partnership and three fuel purchase agreements with outside suppliers. As a result of the merger, the gas
supply agreement with TM Star was terminated and the Partnership acquired TM Star's three fuel purchase agreements. There were no other assets or liabilities transferred as of the purchase date. The
contracts are accounted for as derivatives in accordance with SFAS 133. As of the acquisition date, the fair value of the contracts was $44,345,000, which is $11,873,000 lower than the
$56,218,000 value of the cancelled TM Star contract. The difference in value was accounted for as an adjustment to Partners' equity.

The
Operating Facility and Equipment consists of the following:

2004

2003Operating facility

$
133,616,000

$
133,685,000Other property and equipment


2,774,000


2,766,000136,390,000


136,451,000Accumulated depreciation


(58,009,000
)

(53,302,000
)Construction work in progress


690,000


383,000$
79,071,000

$
83,532,000


Depreciation
expense was approximately $4,743,000, $4,719,000 and $4,708,000 in 2004, 2003 and 2002, respectively.

On
December 1, 1992, the Partnership entered into a Loan and Credit Agreement (the "Agreement") with several banks for a combination of commitments, including a recurring
$5 million short-term working capital loan, to extend loans aggregating up to $132 million (the "Commitment"). The Agreement placed certain restrictions on capital
distributions and permitted investments. Substantially all of the assets of the Partnership were pledged as collateral for the Agreement. The interest rate on the outstanding loan balances at
December 31, 2003 was 2.47%. The loan balance was payable in quarterly installments, with the final payment made on December 1, 2004.

221

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Throughout
the term of the Agreement, the Partnership was required to maintain in an escrow account an amount equal to six months' interest expense, computed at ten percent of the
aggregate balance outstanding. The balance of the escrow account as of December 31, 2003 was $936,000.

Amendment to Loan and Credit Agreement

As an incentive to the Partnership's lenders to grant consents and waivers to the Loan and Credit Agreement with regards to the TM Star merger (Note 3),
the Partnership agreed to additional debt covenants. The additional covenants restricted distributions to the owners until the Partnership fully funded a debt service reserve account with an amount
equal to all scheduled payments of principal, interest and fees due for the coming six months. Distributions were also restricted unless the Partnership maintained a debt service coverage ratio, as
defined, of greater than or equal to 1.4. The Partnership deferred distributions until December 2004 when the debt was fully paid off.

The
Partnership is exposed to price risk associated with the purchase of natural gas. Market risk arises from the potential change in the value of financial instruments and physical
commodities based on fluctuations in commodity prices and bases. Market risk is also affected by changes in the volatility and liquidity in markets in which these instruments are traded.

Fuel Supply Agreements

The Partnership manages a portion of its exposure to natural gas price fluctuations through long-term fuel supply agreements. As a result of the TM
Star merger, the Partnership's contract with TM Star was terminated and the Partnership acquired three new long-term gas supply contracts.

Williams Power Company, Inc.

The Partnership has a long-term agreement to purchase gas from Williams Power Company, Inc. ("Williams"). The daily contract quantity available
under the Williams agreement is 5,000 MMBtu per day, priced at $1.80 per MMBtu adjusted annually by the Gross Domestic Product Implicit Deflator ("GDP"), as defined ($2.24 per MMBtu as of
December 31, 2004). The agreement expires June 30, 2011. After the expiration date, the contract will automatically extend on a year-to-year basis until cancelled
by either party with written notice as required by the contract.

CanWest Gas Supply, Inc.

The Partnership has an agreement to purchase gas from CanWest Gas Supply, Inc. ("Canwest"). The daily contract quantity available under the CanWest
agreement is 10,000 MMBtu per day, priced at $1.83 per MMBtu adjusted annually by the GDP, as defined ($2.82 per MMBtu as of December 31, 2004). The original contract extended through
March 31, 2008.

During
2004, the parties entered into an agreement to truncate the CanWest contract to October 31, 2005. Under the termination agreement, Canwest agreed to settle the original
obligation for principal payments totaling $8,994,000. The settlement was based on an average of market quotes obtained from multiple specified counterparties. The remaining balance due as of
December 31, 2004 is reflected as a note receivable and will be repaid during 2005. The note bears interest at 6% per annum. The Partnership recorded a loss of approximately $850,000 as a
result of the termination.

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Texaco Exploration and Production

The Partnership has an agreement to purchase gas from Texaco Exploration and Production ("TEPI"). TEPI is an indirect wholly owned subsidiary of Chevron. The
daily contract quantity available under the TEPI agreement is 2,500 MMBtu per day, priced at $1.80 per MMBtu adjusted annually by the GDP, as defined ($2.25 per MMBtu as of December 31, 2004).
The agreement expires December 31, 2007. After the expiration date, the TEPI contract may be extended on an annual basis with written agreement by both parties.

Equilon Refinery Fuels Supply Agreement

The Equilon Refinery Fuels Supply Agreement provides for a firm supply of manufactured refinery gas ("MRG") from PSR to the Partnership. The Partnership must
accept a minimum daily delivery of 10,000 MMBtu per day of MRG from Equilon in preference to other fuels. Additional interruptible MRG may be supplied at various volume tiers up to a final tier for
total volumes over 16,000 MMBtu per day all as defined in the agreement. The pricing of MRG is based upon the weighted averages of the gas costs to the Partnership with discount factors applying to
the various tiers, all as defined in the agreement ($2.71 per MMBtu as of December 31, 2004). This agreement terminates on the earlier of December 31, 2011 or the mutual written consent
of the parties. Management has determined that this agreement does not meet the definition of a derivative; therefore, this contract is not recorded at fair value in the financial statements.

TM Star

Prior to the TM Star merger, the Partnership had a long-term agreement to purchase gas from TM Star. The daily contract quantity available under the
TM Star agreement was 20,500 MMBtu per day. The price paid for gas under this contract consisted of a transportation charge and a commodity charge, per MMBtu. Beginning January 1, 1993, the
price paid for the commodity charge was $2.05 per MMBtu adjusted annually by the GDP, as defined ($2.50 per MMBtu as of December 31, 2003). The
agreement required the Partnership to pay for the shortfall between the price received by TM Star and the contracted price of this agreement for any volume of gas, up to the daily contract quantity,
not nominated by the Partnership. This agreement terminated as a result of the TM Star merger.

Cash Flow Hedges

Management has designated the TEPI gas supply agreement as a cash flow hedge of the Partnership's exposure to fluctuations in the price of natural gas. As a
result of this designation, future changes in the fair value associated with the effective portion of the hedges will be recorded in other comprehensive income. Any hedge ineffectiveness will be
included in Fuel expense as part of the Statements of Income. The CanWest and Williams contracts are not formally designated as financial accounting cash flow hedges due to duration and counterparty
credit risk, respectively; therefore, unrealized gains and losses on these contracts are recorded as part of Fuel expense in the Statements of Income.

As
the Partnership's hedged positions are realized, approximately $2,893,000 of the net unrealized gains on cash flow hedges at December 31, 2004 is expected to be reclassified
into earnings during 2005. Management expects that when the hedged items are recognized in earnings, the net unrealized gains associated with them will be offset. The maximum period over which the
Partnership has designated a cash flow hedge is the remaining life of the contract with TEPI. 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.

223

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The
cancelled TM Star contract was previously accounted for as a cash flow hedge; therefore, amounts related to the cancelled contract that were recorded in accumulated other
comprehensive income will be recognized into income over the period that the underlying purchase of gas is expected to occur. It is expected that within the next twelve months, gains of approximately
$8,885,000 will be reclassified from accumulated other comprehensive income to earnings.

During
the years ended December 31, 2004, 2003 and 2002, the Partnership recorded income of $1,876,000, $715,000 and $14,228,000, respectively, representing hedge ineffectiveness.
The hedge ineffectiveness was recorded as a reduction of fuel expenses.

Accumulated Other Comprehensive Income

As of December 31, 2004 and 2003, the Equity balances included Accumulated Other Comprehensive Income of $29,232,000 and $34,989,000, respectively. The
changes in accumulated other comprehensive income during the periods are attributable to activity associated with the Partnership's gas cash flow hedges.

Fair Value

In assessing the fair value of the Partnership's commodity derivative instruments, the Partnership uses a variety of methods and assumptions that are based on
market conditions and risk existing at each balance sheet date. The fair value of the commodity contracts considers quoted market prices, time value, volatility of the underlying commodities and other
factors.

The
fair value of financial derivative instruments is determined through dealer quotes and may not be representative of actual gains and losses that will be recorded when these
instruments mature due to future fluctuations in the markets in which they are traded.

Credit Risk

The Partnership is exposed to credit risk related to potential nonperformance by the counterparties to its energy and steam sales. The Partnership's revenues are
concentrated with Puget Sound Energy and Equilon. Sales to Puget Sound Energy comprised 82%, 83% and 83% of total revenues during 2004, 2003 and 2002, respectively. All remaining sales were to
Equilon. Due to this concentration of credit risk, the Partnership's liquidity could be impacted by financial difficulties experienced by Puget Sound Energy or Equilon.

The
Partnership's gas purchases are concentrated with a few suppliers under its long-term gas purchase agreements; therefore, the Partnership is exposed to counterparty
default and credit risk in association with these contracts. Management monitors the risk of counterparty default and does not anticipate any nonperformance by any of its counterparties.

Operational Risk

The depreciable life of the operating facility exceeds the term of the related purchase power agreement. The viability of the facility subsequent to the
expiration of the power purchase agreement is dependent upon the Partnership's ability to enter into new contracts at terms that would allow the facility to operate profitably. Management believes the
useful life is appropriate and that the facility will continue to operate profitably subsequent to the expiration of the purchase power agreements. However, if management subsequently determines that
the plant will not be able to operate profitably beyond the

224

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term
of the purchase power agreement, management may make changes in the depreciable life and an impairment charge may be required.

Operating
expenses include the following amounts incurred to related parties:

|                                   |  | 2004 |            | 2003 |   | 2002      
|---------------------------------- |  | ---- | ---------- | ---- | - | ----------
|Fuel expense                       |  |      |            |      |   |           
|TM Star                            |  | $    | 888,000    |      | $ | 21,456,000
|Equilon                            |  |      | 8,783,000  |      |   | 11,455,000
|TEPI                               |  |      | 7,371,000  |      |   |          
|Plant and other operating expenses |  |      |            |      |   |           
|Equilon and subsidiaries           |  |      | 1,647,000  |      |   | 1,407,000 
|Chevron and subsidiaries           |  |      | 1,287,000  |      |   | 1,309,000 
|                                   |  |      |            |      |   |           
|                                   |  | $    | 19,976,000 |      | $ | 35,627,000
|                                   |  |      |            |      |   |           

The
Partnership purchases gas under long-term agreements from related parties. In addition, the Partnership has related party operating agreements as follows:

Construction, Operating and Other Costs

Edison, Equilon and Chevron as well as their affiliates and subsidiaries are reimbursed for design, construction, operation and other costs incurred on behalf of
the Partnership.

Land Lease

The Partnership entered into a 20-year land lease with Chevron on January 3, 1991, which has been assigned to Equilon. Costs incurred under the
land lease for 2004, 2003 and 2002 were nominal.

Operation and Maintenance Agreement

The Partnership has an agreement with Equilon, whereby Equilon shall perform all operation and routine running maintenance activities necessary for the production
of electrical energy and steam. The
agreement will terminate August 20, 2012 or until terminated by either party. Equilon is paid for all costs incurred in connection with operating and maintaining the Facility.

Steam Purchase and Sale Agreement

The Partnership has entered into an agreement with Equilon, for the sale of steam generated by the Facility. The agreement terminates upon the earlier of
December 31, 2011, or the mutual written agreement of the parties. Equilon pays the Partnership monthly for the steam delivered based upon the weighted average monthly cost of fuel gas and a
steam discount and boiler efficiency factor, as defined in the agreement. Under this agreement, the purchases by Equilon are required to be sufficient for the Partnership to meet qualifying facility
status.

225

---



Related Parties Payables

The related parties payables balances consist of the following:

|                         |                                | 2004 |           | 2003     
|------------------------ | ------------------------------ | ---- | --------- | ---------
|Equilon and subsidiaries |                                | $    | 2,044,000 |          
|Chevron and subsidiaries |                                |      | 1,030,000 |          
|TM Star                  |                                |      |          |          
|                         |                                |      |           |          
|                         | Total related parties payables |      | $         | 3,074,000
|                         |                                |      |           |          

8.    Commitments and Contingencies

Power Purchase Agreements

The Partnership has entered into a Power Purchase Agreement with Puget Sound Energy for each phase of the Facility. The agreement for Phase I was executed and
assigned to the Partnership on June 29, 1989. The agreement for Phase II was executed on December 27, 1990. These agreements will remain in effect until December 31, 2011.
The Partnership provides, under the Phase I agreement, up to 90 megawatts of electrical output to Puget Sound Energy. For the Phase II agreement the Partnership provides approximately 60
megawatts of electrical output. Under Phase I and Phase II, the amount earned by the Partnership is based on the quantity of energy delivered times the sum of the individual variable
rates (which are adjusted annually by the GDP) and the respective fixed rates (which differ during the summer or winter months).

The
Phase I and II agreements contain termination clauses which, upon the occurrence of certain events, could result in the Partnership paying a termination amount, as defined in the
agreements to Puget Sound Energy. If an event of termination occurred as of December 31, 2004, the Partnership would be liable for approximately $118 million. Edison and Chevron have
jointly and severally guaranteed the repayment of this amount. Management has no reason to believe that the project will either terminate its performance or reduce its electric power producing
capability during the term of the power contract in a manner which would result in the payment of a termination amount.

226

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Report of Independent Auditors

To the Board of Directors and shareholders of
EcoEléctrica Holdings, Ltd. and Subsidiaries

In
our opinion, the accompanying consolidated balance sheets and the related consolidated statements of income, comprehensive income, changes in stockholders' equity, and cash flows
present fairly, in all material respects, the financial position of EcoEléctrica Holdings, Ltd. and Subsidiaries (the "Company") as of December 31, 2004 and 2003, and the
results of its operations and its cash flows for the three years in the period ended December 31, 2004, in conformity with accounting principles generally accepted in the United States of
America. These financial statements are the responsibility of the Company's management. Our responsibility is to express an opinion on these financial statements based on our audits. We conducted our
audits of these statements in accordance with auditing standards generally accepted in the United States. 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.

|                                       |  | PricewaterhouseCoopers LLP
|-------------------------------------- |  | --------------------------
|San Juan, Puerto Rico
February 4, 2005 |  |                           

227

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ECOELÉCTRICA HOLDINGS, LTD. AND SUBSIDIARIES  CONSOLIDATED BALANCE SHEETS  December 31, 2004 and 2003

|                                        |                                                                                                                      | 2004             |                                            | 2003    |       
|--------------------------------------- | -------------------------------------------------------------------------------------------------------------------- | ---------------- | ------------------------------------------ | ------- | ------
|
|Assets                                  |                                                                                                                      |                  |                                            |         |       
|Current assets                          |                                                                                                                      |                  |                                            |         |       
|                                        | Cash and cash equivalents                                                                                            |                  | $                                          | 23,378  |       
|                                        | Current portion of restricted cash                                                                                   |                  |                                            | 21,044  |       
|                                        | Receivables                                                                                                          |                  |                                            |         |       
|                                        |                                                                                                                      | Trade            |                                            |         | 78,825
|                                        |                                                                                                                      | Insurance claims |                                            |         | 2,945 
|                                        |                                                                                                                      | Other            |                                            |         | 5     
|                                        | Note from Puerto Rico Electric Power Authority                                                                       |                  |                                            |        |       
|                                        | Inventories                                                                                                          |                  |                                            | 38,283  |       
|                                        | Prepaid expenses                                                                                                     |                  |                                            | 5,858   |       
|                                        |                                                                                                                      |                  |                                            |         |       
|                                        |                                                                                                                      |                  | Total current assets                       |         |       
|                                        |                                                                                                                      |                  |                                            |         |       
|Noncurrent Assets                       |                                                                                                                      |                  |                                            |         |       
|                                        | Restricted cash                                                                                                      |                  |                                            | 7,399   |       
|                                        | Investments, at lower of cost or market                                                                              |                  |                                            | 725     |       
|                                        | Property, plant and equipment, net                                                                                   |                  |                                            | 625,943 |       
|                                        | Debt issue costs, net                                                                                                |                  |                                            | 13,957  |       
|                                        | Deferred tax asset                                                                                                   |                  |                                            | 3,635   |       
|                                        |                                                                                                                      |                  |                                            |         |       
|                                        |                                                                                                                      |                  | Total noncurrent assets                    |         |       
|                                        |                                                                                                                      |                  |                                            |         |       
|                                        |                                                                                                                      |                  | Total assets                               |         | $     
|                                        |                                                                                                                      |                  |                                            |         |       
|Liabilities and Stockholders' Equity    |                                                                                                                      |                  |                                            |         |       
|Current liabilities                     |                                                                                                                      |                  |                                            |         |       
|                                        | Working capital facility                                                                                             |                  | $                                          | 30,000  |       
|                                        | Current portion of loans payable                                                                                     |                  |                                            | 22,632  |       
|                                        | Accounts payable and accrued liabilities                                                                             |                  |                                            | 21,775  |       
|                                        | Fair value of interest rate swap agreements                                                                          |                  |                                            | 14,444  |       
|                                        |                                                                                                                      |                  |                                            |         |       
|                                        |                                                                                                                      |                  | Total current liabilities                  |         |       
|                                        |                                                                                                                      |                  |                                            |         |       
|Long-term liabilities                   |                                                                                                                      |                  |                                            |         |       
|                                        | Working capital facilities                                                                                           |                  |                                            |        |       
|                                        | Loans payable                                                                                                        |                  |                                            | 532,230 |       
|                                        | Deferred tax liability                                                                                               |                  |                                            | 7,480   |       
|                                        | Subordinated notes and accrued interest payable to affiliates                                                        |                  |                                            | 49,450  |       
|                                        | Fair value of interest rate swap agreements                                                                          |                  |                                            | 37,486  |       
|                                        |                                                                                                                      |                  |                                            |         |       
|                                        |                                                                                                                      |                  | 626,646                                    |         |       
|                                        |                                                                                                                      |                  |                                            |         |       
|                                        |                                                                                                                      |                  | Total liabilities                          |         |       
|                                        |                                                                                                                      |                  |                                            |         |       
|Commitments and contingencies (Note 17) |                                                                                                                      |                  |                                            |         |       
|Stockholders' equity                    |                                                                                                                      |                  |                                            |         |       
|                                        | Common stock, Class A, $.01 par value, 500,000 shares authorized, 100 shares issued and outstanding                  |                  |                                            |        |       
|                                        | Common stock, Class B, $.01 par value, 500,000 shares authorized, 100 shares issued and outstanding                  |                  |                                            |        |       
|                                        | Additional paid-in capital                                                                                           |                  |                                            | 67,000  |       
|                                        | Accumulated other comprehensive loss, net of deferred income tax of $3,635 and $4,295 in 2004 and 2003, respectively |                  |                                            | (48,295 | )     
|                                        | Retained earnings                                                                                                    |                  |                                            | 87,795  |       
|                                        |                                                                                                                      |                  |                                            |         |       
|                                        |                                                                                                                      |                  | Total stockholders' equity                 |         |       
|                                        |                                                                                                                      |                  |                                            |         |       
|                                        |                                                                                                                      |                  | Total liabilities and stockholders' equity |         | $     
|                                        |                                                                                                                      |                  |                                            |         |       

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

228

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ECOELÉCTRICA HOLDINGS, LTD. AND SUBSIDIARIES  CONSOLIDATED STATEMENTS OF INCOME  For the Years Ended December 31, 2004, 2003 and 2002

|                                   |                                             | 2004 |         | 2003    |   | 2002    |        
|---------------------------------- | ------------------------------------------- | ---- | ------- | ------- | - | ------- | -------
|
|Revenues                           |                                             | $    | 289,497 |         | $ | 232,979 |        
|                                   |                                             |      |         |         |   |         |        
|Costs and operating expenses       |                                             |      |         |         |   |         |        
|                                   | Liquefied petroleum gas (LPG)               |      |         | 50      |   |         | 209    
|                                   | Liquefied natural gas (LNG)                 |      |         | 124,352 |   |         | 102,719
|                                   | Fuel oil No. 2                              |      |         | 10      |   |         | 154    
|                                   | Depreciation and amortization               |      |         | 29,148  |   |         | 32,993 
|                                   | Salaries and related benefits               |      |         | 6,173   |   |         | 5,764  
|                                   | Technical and professional support          |      |         | 7,534   |   |         | 5,993  
|                                   | Repairs and maintenance                     |      |         | 1,679   |   |         | 3,541  
|                                   | Utilities and communication                 |      |         | 895     |   |         | 985    
|                                   | Insurance                                   |      |         | 8,123   |   |         | 9,876  
|                                   | Operations, maintenance and fuel management |      |         | 1,375   |   |         | 1,520  
|                                   | Taxes other than income                     |      |         | 3,371   |   |         | 3,084  
|                                   | LPG storage and service                     |      |         | 704     |   |         | 702    
|                                   | Administrative services                     |      |         | 813     |   |         | 905    
|                                   | Other operating expenses                    |      |         | 4,916   |   |         | 3,322  
|                                   |                                             |      |         |         |   |         |        
|                                   |                                             |      | 189,143 |         |   | 171,767 |        
|                                   |                                             |      |         |         |   |         |        
|Operating income                   |                                             |      | 100,354 |         |   | 61,212  |        
|                                   |                                             |      |         |         |   |         |        
|Other (income) expense             |                                             |      |         |         |   |         |        
|                                   | Interest expense                            |      |         | 45,529  |   |         | 47,042 
|                                   | Interest income                             |      |         | (309    | ) |         | (312   
|                                   | Other                                       |      |         | 1,609   |   |         | (4,535 
|                                   |                                             |      |         |         |   |         |        
|                                   |                                             |      | 46,829  |         |   | 42,195  |        
|                                   |                                             |      |         |         |   |         |        
|Income before income tax provision |                                             |      | 53,525  |         |   | 19,017  |        
|Deferred income tax provision      |                                             |      | (3,672  | )       |   | (1,452  | )      
|                                   |                                             |      |         |         |   |         |        
|Net income                         |                                             | $    | 49,853  |         | $ | 17,565  |        
|                                   |                                             |      |         |         |   |         |        

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

229

---





ECOELÉCTRICA HOLDINGS, LTD. AND SUBSIDIARIES  CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME  For the Years Ended December 31, 2004, 2003 and 2002

|                            |                                                                                                                                        | 2004 |        | 2003    |   | 2002   |        
|--------------------------- | -------------------------------------------------------------------------------------------------------------------------------------- | ---- | ------ | ------- | - | ------ | -------
|
|Net income                  |                                                                                                                                        | $    | 49,853 |         | $ | 17,565 |        
|                            |                                                                                                                                        |      |        |         |   |        |        
|Other comprehensive loss    |                                                                                                                                        |      |        |         |   |        |        
|                            | Unrealized gain (loss) on interest rate swap agreements, net of deferred income tax of $3,635 in 2004 and $4,295 in 2003, respectively |      |        | 30,847  |   |        | 42,522 
|                            | Reclassification adjustment for losses included in net income interest rate swaps                                                      |      |        | (22,083 | ) |        | (23,802
|                            |                                                                                                                                        |      |        |         |   |        |        
|                            |                                                                                                                                        |      | 8,764  |         |   | 18,720 |        
|                            |                                                                                                                                        |      |        |         |   |        |        
|Comprehensive income (loss) |                                                                                                                                        | $    | 58,617 |         | $ | 36,285 |        
|                            |                                                                                                                                        |      |        |         |   |        |        

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

230

---



ECOELÉCTRICA HOLDINGS, LTD. AND SUBSIDIARIES  CONSOLIDATED STATEMENTS OF CHANGES IN STOCKHOLDERS' EQUITY  For the Years Ended December 31, 2004, 2003 and 2002

|                                                                             |  | Common Stock
Class A |  | Common Stock
Class B |   |  |     |  |   |   |  |   |       
|---------------------------------------------------------------------------- |  | -------------------- |  | -------------------- | - |  | --- |  | - | - |  | - | ------
|
|
|
|Balance at January 1, 2002 (unaudited)                                       |  | 100                  |  | $                    |  |  | 100 |  | $ |  |  | $ | 67,000
|Net income                                                                   |  |                     |  |                      |  |  |    |  |   |  |  |   |      
|Unrealized loss on interest rate protection agreements                       |  |                     |  |                      |  |  |    |  |   |  |  |   |      
|                                                                             |  |                      |  |                      |   |  |     |  |   |   |  |   |       
|Balance at December 31, 2002                                                 |  | 100                  |  |                      |  |  | 100 |  |   |  |  |   | 67,000
|Net income                                                                   |  |                     |  |                      |  |  |    |  |   |  |  |   |      
|Unrealized gain on interest rate protection agreements, net of tax of $4,295 |  |                     |  |                      |  |  |    |  |   |  |  |   |      
|                                                                             |  |                      |  |                      |   |  |     |  |   |   |  |   |       
|Balance at December 31, 2003                                                 |  | 100                  |  |                      |  |  | 100 |  |   |  |  |   | 67,000
|Net income                                                                   |  |                     |  |                      |  |  |    |  |   |  |  |   |      
|Dividends                                                                    |  |                     |  |                      |  |  |    |  |   |  |  |   |      
|Unrealized gain on interest rate protection agreements, net of tax of $3,835 |  |                     |  |                      |  |  |    |  |   |  |  |   |      
|                                                                             |  |                      |  |                      |   |  |     |  |   |   |  |   |       
|Balance at December 31, 2004                                                 |  | 100                  |  | $                    |  |  | 100 |  | $ |  |  | $ | 67,000
|                                                                             |  |                      |  |                      |   |  |     |  |   |   |  |   |       

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

231

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ECOELÉCTRICA HOLDINGS, LTD. AND SUBSIDIARIES  CONSOLIDATED STATEMENTS OF CASH FLOWS  For the Years Ended December 31, 2004, 2003 and 2002

|                                                                                 |                                                                            | 2004                                     |                                           | 2003   |         | 2002    |       
|-------------------------------------------------------------------------------- | -------------------------------------------------------------------------- | ---------------------------------------- | ----------------------------------------- | ------ | ------- | ------- | ------
|
|Cash flows from operating activities                                             |                                                                            |                                          |                                           |        |         |         |       
|Net income                                                                       |                                                                            | $                                        | 49,853                                    |        | $       | 17,565  |       
|                                                                                 |                                                                            |                                          |                                           |        |         |         |       
|Adjustments to reconcile net income to net cash provided by operating activities |                                                                            |                                          |                                           |        |         |         |       
|                                                                                 | Depreciation and amortization                                              |                                          |                                           | 29,148 |         |         | 32,993
|                                                                                 | Dividends received in stock                                                |                                          |                                           | (725   | )       |         |      
|                                                                                 | Deferred income tax provision                                              |                                          |                                           | 3,672  |         |         | 1,452 
|                                                                                 | Loss on disposal of fixed assets                                           |                                          |                                           |       |         |         | 12    
|                                                                                 | Changes in operating assets and liabilities that increase (decrease) cash: |                                          |                                           |        |         |         |       
|                                                                                 |                                                                            | Receivables                              |                                           |        | (13,622 | )       |       
|                                                                                 |                                                                            | Inventories                              |                                           |        | (960    | )       |       
|                                                                                 |                                                                            | Prepaid expenses                         |                                           |        | (2,752  | )       |       
|                                                                                 |                                                                            | Accounts payable and accrued liabilities |                                           |        | (5,314  | )       |       
|                                                                                 |                                                                            | Subordinated accrued interest payable    |                                           |        | (11,135 | )       |       
|                                                                                 |                                                                            |                                          |                                           |        |         |         |       
|                                                                                 |                                                                            |                                          | Total adjustments                         |        |         | (1,688  | )     
|                                                                                 |                                                                            |                                          |                                           |        |         |         |       
|                                                                                 |                                                                            |                                          | Net cash provided by operating activities |        |         | 48,165  |       
|                                                                                 |                                                                            |                                          |                                           |        |         |         |       
|Cash flows from investing activities                                             |                                                                            |                                          |                                           |        |         |         |       
|Capital expenditures                                                             |                                                                            |                                          | (13,064                                   | )      |         | (23,257 | )     
|Collection of notes receivable                                                   |                                                                            |                                          | 5,000                                     |        |         |        |       
|Decrease in restricted cash                                                      |                                                                            |                                          | (6,412                                    | )      |         | (5,762  | )     
|Proceeds from sale of fixed assets                                               |                                                                            |                                          |                                          |        |         | 3       |       
|                                                                                 |                                                                            |                                          |                                           |        |         |         |       
|                                                                                 |                                                                            |                                          | Net cash used in investing activities     |        |         | (14,476 | )     
|                                                                                 |                                                                            |                                          |                                           |        |         |         |       
|Cash flows financing activities                                                  |                                                                            |                                          |                                           |        |         |         |       
|Payments of principal on loans payable                                           |                                                                            |                                          | (20,528                                   | )      |         | (18,695 | )     
|Dividends paid                                                                   |                                                                            |                                          | (7,500                                    | )      |         |        |       
|Payments of subordinated debt                                                    |                                                                            |                                          |                                          |        |         |        |       
|                                                                                 |                                                                            |                                          |                                           |        |         |         |       
|                                                                                 |                                                                            |                                          | Net cash used in financing activities     |        |         | (28,028 | )     
|                                                                                 |                                                                            |                                          |                                           |        |         |         |       
|Net increase (decrease) in cash and cash equivalents                             |                                                                            |                                          | 5,661                                     |        |         | 7,692   |       
|Cash and cash equivalents, beginning of the year                                 |                                                                            |                                          | 17,717                                    |        |         | 10,025  |       
|                                                                                 |                                                                            |                                          |                                           |        |         |         |       
|Cash and cash equivalents, end of the year                                       |                                                                            | $                                        | 23,378                                    |        | $       | 17,717  |       
|                                                                                 |                                                                            |                                          |                                           |        |         |         |       
|Supplemental cash flow information                                               |                                                                            |                                          |                                           |        |         |         |       
|Interest paid                                                                    |                                                                            | $                                        | 56,616                                    |        | $       | 40,221  |       
|                                                                                 |                                                                            |                                          |                                           |        |         |         |       
|Income tax paid                                                                  |                                                                            | $                                        |                                          |        | $       |        |       
|                                                                                 |                                                                            |                                          |                                           |        |         |         |       
|Dividends declared not paid                                                      |                                                                            | $                                        | 7,500                                     |        | $       |        |       
|                                                                                 |                                                                            |                                          |                                           |        |         |         |       

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

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ECOELÉCTRICA HOLDINGS, LTD. AND SUBSIDIARIES  NOTES TO CONSOLIDATED FINANCIAL STATEMENTS  December 31, 2004, 2003 and 2002

1.     Organization

EcoEléctrica Holdings, Ltd. ("Holdings" or "the Company"), a Cayman Islands company, is the 99% limited partner of
EcoEléctrica, L.P. (the "Partnership") and owns 100% of EcoEléctrica, Ltd., also a Cayman Islands company, which is the 1% general partner of
EcoEléctrica Holdings, Ltd. which is 50% owned by IPM del Caribe, a wholly owned subsidiary of Ponoma Holdings Limited, a Cyprus Corporation, which is in turn owned by IPM Eagle
LLP, a joint venture 70% owned by International Power and 30% owned by Mitsui Co., and 50% owned by Buenergía Gas & Power Ltd. ("Buenergía"), a Cayman
Islands company limited by shares, which in turn is wholly-owned by Invergas Puerto Rico, S.A., a subsidiary of Gas Natural SDG, S.A. ("GN").

EcoEléctrica,
L.P. (the "Partnership") is a Bermuda limited partnership formed on August 10, 1994, to develop, design, finance, construct, own and operate a
combined-cycle natural gas-fired cogeneration facility of approximately 507 megawatts, a liquefied natural gas ("LNG") import terminal and storage facility, a desalination facility and
other auxiliary assets (the "Plant") in the Commonwealth of Puerto Rico. The electricity generated is sold to the Puerto Rico Electric Power Authority ("PREPA"), a Commonwealth of Puerto Rico
government instrumentality and one of the largest electric utilities in the United States and its territories, among municipal electric utilities.

On
October 30, 2003 GN purchased Enron's share in Buenergía for $177 million in an auction conducted by the Federal Bankruptcy Court, District of New York.
As part of this purchase GN guaranteed the Partnership's Operations and Fuel Management Agreement and the LPG Storage and Services Agreement described in Note 3, in addition to assuming certain
other guarantees and obligations.

On
December 16, 2004 International Power (IPM) purchased Edison Mission Energy's (EME's) participation in EcoEléctrica, Holdings, Ltd. through the
acquisition of EME's international general portfolio in a 70:30 partnership with Mitsui & Co., Ltd. of Japan for approximately $2.0 billion.

2.     Summary of Significant Accounting Policies

The following is a summary of the accounting policies followed by Holdings in the preparation of the accompanying financial statements.

Basis of Presentation

The accompanying consolidated financial statements, which include Holdings and its subsidiaries EcoEléctrica, Ltd. and the Partnership, have
been prepared in accordance with accounting principles generally accepted in the United States of America. All intercompany balances and transactions have been eliminated in consolidation.

Use of Estimates

The preparation of financial statements in conformity with accounting principles generally accepted in the United States of America requires management to make
estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of

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the
financial statements and the reported amounts of revenues and expenses during the reporting period. Actual results could differ from those estimates.

Revenue Recognition

Energy revenues derived from the conversion of fuel into electricity are recognized based on actual delivery of such converted electricity, in accordance with the
power purchase contract between the Partnership and PREPA. Capacity revenues are recognized when earned.

Revenue
billed is recorded as a current account receivable net of amounts in dispute with PREPA based on management's estimate of realizability.

Fair Value of Financial Instruments

The carrying amounts of cash and cash equivalents, restricted cash, receivables and accounts payable and accrued liabilities, approximate fair value because of
the short maturity of these items. The estimated fair values of working capital facilities, loans payable and subordinated notes payable are based on quoted market values or on current interest rates
offered for similar borrowings and approximate their carrying values. The fair value of interest rate swaps is determined based on dealer quotes, generally the counterparty, or discounted cash flow
models considering the current rate offered on similar instruments.

Statement of Cash Flows

For the purpose of reporting cash flows, Holdings and its consolidated subsidiaries consider all unrestricted highly liquid investments with original maturities
of three months or less to be cash equivalents.

Inventories

Inventories are stated at the lower of cost (determined on a first-in, first-out basis) or market.

Debt Issue Costs

The Partnership capitalized the costs incurred in connection with the issuance of debt. The capitalized debt issue costs are amortized over the term of the
related debt.

Property, Plant and Equipment

Property, plant and equipment are carried at cost (including capitalized interest) less accumulated depreciation and amortization. Depreciation and amortization
are provided on a straight-line basis over the estimated useful lives of the respective assets. Major maintenance expenditures (overhauls) are capitalized and depreciated using the defer
and amortize method over their estimated useful lives (the period of time from the initial overhaul to the next overhaul of the same nature, generally 1.5 to 6 years) while regular maintenance
is expensed as incurred. When property is retired or sold, the cost and the related accumulated depreciation are removed from the accounts and any resulting gain or loss is credited or charged to
operations.

Impairment of Long-Lived Assets

Holdings and its consolidated subsidiaries evaluate their long-lived assets considering continued operating losses or significant and
long-term changes in industry or operating conditions as the primary

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indicators
of potential impairment. An impairment is recognized when the future undiscounted cash flows of each asset is estimated to be insufficient to recover its carrying value. If such carrying
value is not recoverable, the asset is written down to estimated fair value. Considerable management judgment is necessary to estimate future cash flows, accordingly, actual results could vary
significantly from such estimates, requiring periodic revaluation based on current events or changes in circumstances. Based on these evaluations, there were no impairment adjustments to the carrying
values of assets during 2004, 2003 and 2002.

Income Tax

Holdings is treated as a limited partnership in the Cayman Islands for tax purposes and as such, is not a taxable entity in that jurisdiction. The Partnership is
a Bermuda limited partnership, and as such, is not a taxable entity in the United States. Under Puerto Rico law, the Partnership is subject to local taxation. In accounting for income taxes, the
Partnership recognizes deferred tax assets and liabilities for the expected future tax consequences attributable to differences between tax bases of assets and liabilities and their reported amounts
in the financial statements. In estimating future tax consequences, it considers all expected future events other than enactment of changes in the tax law or rates. A valuation allowance is recognized
for any deferred tax asset which, based on management's evaluation, is more likely than not that some portion or all of the deferred tax asset will not be realized.

Comprehensive Income (Loss)

Comprehensive income (loss) includes net income and all changes to stockholders' equity during a period except those arising from transactions with shareholders.
In addition to net income, the Partnership recognizes cash flow hedge gains or losses arising from interest rate swaps in other comprehensive income (loss).

Derivatives

The Partnership recognizes all derivatives as either assets or liabilities in the statement of financial position and measures those instruments at fair value. If
certain conditions are met, a derivative may be specifically designated as (a) a hedge of the exposure to changes in the fair value of a recognized asset or liability or an unrecognized firm
commitment, (b) a hedge of the exposure to variable cash flows of a forecasted transaction, or (c) a hedge of the foreign currency exposure of a net investment in a foreign operation, an
unrecognized firm commitment, an available-for-sale security, or a foreign-currency-denominated forecasted transaction. The accounting for changes in the fair value of a
derivative depends on the intended use of the derivative and the resulting designation. The Partnership designated the interest swaps as a hedge of the cash flow from its variable rate loans.
Accordingly, the fair value of the interest rate swap agreements is presented as a liability and as a component of the stockholders' equity net of related deferred taxes, through "Other Comprehensive
Loss."

Both
the power purchase contract with PREPA and the LNG supply agreement with Tractebel LNG North America, LLC, formerly CABOT LNG Corporation (refer to Note 3), are considered
under either the normal purchase and sales exception under SFAS No. 138 or do not meet the definition of a derivative, therefore are accounted for on the accrual basis.

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Recently Issued Accounting Pronouncements and Interpretations

SFAS No. 123-R "Share-Based Payments"

In December 2004, the FASB issued a revision to SFAS No. 123, "Accounting for Stock-Based Compensation," SFAS No. 123-R,
"Share-Based Payments." SFAS No. 123-R focuses primarily on transactions in which an entity exchanges its equity instruments for employee services and generally establishes
standards for the accounting for transactions in which an entity obtains goods or services in share-based payment transactions. SFAS No. 123-R requires companies to (1) use
fair value to measure stock-based compensation awards and (2) cease using the "intrinsic value" method of accounting, which APB 25 allowed and resulted in no expense for many awards of stock
options for which the exercise price of the option equaled the price of the underlying stock at the grant date. In addition, SFAS No. 123-R retains the modified grant date model
from SFAS No. 123. Under that model, compensation cost is measured at the grant date fair value of the award and adjusted to reflect actual forfeitures and the outcome of certain conditions.
The fair value of an award is not remeasured after its initial estimation on the grant date, except in the case of a liability award or if the award is modified, based on specific criteria included in
SFAS No. 123-R. This Statement is effective as of the beginning of the first interim or annual reporting period that begins after June 15, 2005. Management is currently
evaluating the effect of adoption of SFAS No. 123-R, but does not expect the adoption to have a material effect on Holding's financial condition, results of operations or cash
flows.

SFAS No. 153 "Exchanges of Nonmonetary Assets"

In December 2004, the FASB issued SFAS No. 153, "Exchanges of Nonmonetary Assets, an amendment of APB Opinion No. 29, Accounting for
Nonmonetary Transactions." This statement amends the principle that exchanges of nonmonetary assets should be measured based on the fair value of the assets exchanged and more broadly provides for
exceptions regarding exchanges on nonmonetary assets that do
not have commercial substance. A nonmonetary exchange has commercial substance if the future cash flows of the entity are expected to change significantly as a result of the exchange. The entity's
future cash flows are expected to significantly change if either of the following criteria is met: a) the configuration (risk, timing, and amount) of the future cash flows of the asset(s)
received differs significantly from the configuration of the future cash flows of the asset(s) transferred. b) the entity-specific value of the asset(s) received differs from the
entity-specific value of the asset(s) transferred, and the difference is significant in relation to the fair values of the assets exchanged. A qualitative assessment will, in some cases, be conclusive
in determining that the estimated cash flows of the entity are expected to significantly change as a result of the exchange. SFAS No. 153 is effective for nonmonetary asset exchanges occurring
in fiscal periods beginning after June 15, 2005. The adoption of this statement is not expected to have a material impact on Holding's financial condition, results of operations, or cash flows.

3.     Agreements

Power Purchase Contract

On March 10, 1995, the Partnership and PREPA entered into a power purchase contract (the PPA) under which PREPA is required to make energy and capacity
payments to the Partnership commencing on March 21, 2000 (date in which the Partnership started commercial operations) (COD) and continuing for the 22-year term of the PPA
(operating period). Energy payments are based on the actual output of electric power from the Plant and are intended to cover fuel costs. Capacity payments are intended to cover operating and
maintenance costs, debt service, taxes and a return on investment.

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The PPA requires that the Partnership maintains a minimum working capital of $20 million by the end of the third year after the COD and thereafter. A portion of the minimum
working capital requirement should be in cash deposited in a financial institution. The cash deposit should be reduced by any amount properly invoiced to PREPA under this agreement and not paid when
due. As of December 31, 2004, amounts owed by PREPA to the Partnership exceed the cash deposit requirements.

Total
revenues are presented net of the provision for doubtful accounts provided based on management's estimate of realizability. The basis for this provision is further explained in
Note 4.

Energy
and capacity revenues under the PPA for the years ended December 31, 2004, 2003 and 2002 were as follows (in thousands):

|                                |  | 2004 |         | 2003 |   | 2002    |  
|------------------------------- |  | ---- | ------- | ---- | - | ------- | -
|Energy                          |  | $    | 139,689 |      | $ | 107,412 |  
|Capacity                        |  |      | 152,845 |      |   | 127,306 |  
|Provision for doubtful accounts |  |      | (3,037  | )    |   | (1,739  | )
|                                |  |      |         |      |   |         |  
|                                |  | $    | 289,497 |      | $ | 232,979 |  
|                                |  |      |         |      |   |         |  

Administrative Services Agreement

The Partnership entered into an Administrative Services Agreement as of October 31, 1997, with EME (Administrative Manager), to provide administrative and
other support services in connection with the financing, construction and operation of the Plant.

The
Partnership agreed to pay the Administrative Manager all the reimbursable costs incurred plus $42,000 per month (escalating from January 1, 1997, in accordance with the Puerto
Rico Consumer Price Index (CPI)) during the operating period. The Partnership incurred charges under this agreement of $916,000, $905,000 and $876,000 for the years ended December 31, 2004,
2003 and 2002, respectively.

Operations, Maintenance and Fuel Management Agreement

The Partnership has entered into an Operation, Maintenance and Fuel Management Agreement dated as of October 31, 1997 (the OMF Agreement) with EI Puerto
Rico Operations Inc. (OMF Manager), an indirect wholly-owned subsidiary of Enron, for the management of the operations and maintenance of the Plant, as well as all aspects of the purchase,
transportation, delivery and storage of fuel for the Plant. This Agreement was transferred to GN as part of the acquisition of the Enron participation in Buenergía.

The
Partnership agreed to pay the OMF Manager certain reimbursable costs, and monthly operating and fuel management fees of $42,000 and $29,000, respectively, (escalating from
January 1, 1997, in accordance with the Puerto Rico CPI) during the operating period. The Partnership incurred charges under this agreement of approximately $1,494,000, $1,520,000 and
$1,201,000 for the years ended December 31, 2004, 2003 and 2002, respectively.

LPG Storage and Service Agreement

The Partnership entered into an LPG Storage and Service Agreement (the Agreement) dated as of October 31, 1997, with the ProCaribe Division of the Protane
Corporation (ProCaribe), an indirect wholly-owned subsidiary of Enron. Under the Agreement, ProCaribe will act as a terminal operator mainly providing LPG unloading, storage and redelivery services to
the Partnership. The Agreement, which term extends through December 31, 2020, sets forth an annual compensation for ProCaribe's

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services
comprised of a base annual fee of $75,000, payable on a monthly basis, and reimbursable incremental costs, as defined in the Agreement. The base annual fee of $75,000 will be adjusted each
January 1, according to the increase in the Puerto Rico CPI as compared to the January 1, 1997 index. ProCaribe provided services and charged reimbursable incremental costs to the
Partnership under the Agreement amounting to approximately $704,000, $702,000 and $817,000 for the years ended December 31, 2004, 2003 and 2002, respectively.

In
addition, the Agreement provides for the borrowing and lending of LPG to each other. There were no LPG borrowings during 2004 and 2003.During 2002 ProCaribe purchased LPG from the Partnership for approximately $118,800. In September 2003, the assets of ProCaribe were acquired by Terminal Acquisition Company (TAC), a subsidiary
of Empire Gas Company, a Puerto Rico Corporation. As result of the acquisition TAC assumed the obligations under the LPG Storage and Services Agreement.

LNG Supply Agreement

The Partnership entered into an LNG supply agreement with Tractebel LNG North America, LLC (Tractebel), formerly CABOT LNG Corporation, whereby the Partnership is
committed to purchase and Tractebel committed to supply, an annual supply of LNG, as stipulated in the agreement, until September 2019. Charges under this agreement include a commodity charge
on LNG supplied based on NYMEX and the Puerto Rico CPI, and availability demand charges regardless of actual LNG deliveries. Commodity and demand charges from Tractebel for the years ended
December 31, 2004, 2003 and 2002 were as follows (in thousands):

|          |  | 2004 |         | 2003 |   | 2002   
|--------- |  | ---- | ------- | ---- | - | -------
|Commodity |  | $    | 102,311 |      | $ | 79,267 
|Demand    |  |      | 22,041  |      |   | 23,452 
|          |  |      |         |      |   |        
|          |  | $    | 124,352 |      | $ | 102,719
|          |  |      |         |      |   |        

On December 13, 2002, the Partnership and Tractebel signed a Letter Agreement that amended the LNG supply agreement for the year 2003 only.
This Letter Agreement provided for 100% supply of LNG to the Partnership, a five (5) cents commodity price reduction and the elimination of the commodity surcharge, all for the year 2003 only.
The Lenders were duly notified and did not oppose the execution of the agreement.

On
April 8, 2003, the Partnership and Tractebel signed a second Letter Agreement that amended the LNG supply agreement for the year 2004. This Letter Agreement provides for 100%
supply of LNG to the Partnership, a thirty eight (38) cents commodity price reduction and the elimination of the commodity surcharge, all for the year 2004.

Depository Agreement

On October 31, 1997, the Partnership entered into a depository and disbursement agreement (the Depository Agreement) with a financial institution as
collateral and depository agent, whereby the depository agent will hold and administer monies deposited in the various accounts established at the financial institution as depository bank pursuant to
the Depository Agreement. As part of the Depository Agreement, besides the cash accounts, the following cash reserves are required: an interest reserve, a principal reserve, a major maintenance
reserve, a construction reserve, a distribution reserve, a collateral reserve, a guarantee reserve, an income tax reserve and a fuel supply interruption reserve. The amounts deposited in the interest
reserve shall be applied to pay interest expenses. The principal reserve is a

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short-term
reserve funded throughout each month of the quarter, to pay the corresponding principal installment due at the end of the quarter. The amount deposited in the Major maintenance
reserve account shall be applied to pay for expenditures by the Partnership for regularly scheduled (or reasonably anticipated) major maintenance of the Plant. The amounts deposited in the
subordinated indebtedness account shall be used for principal payments on the notes payable to GN and EME. The amounts deposited in the construction reserve shall be applied to completing certain
construction punchlist items that were pending upon conversion of interim construction loans into term loans. The amounts deposited in the distribution reserve shall be used for payment of dividends
to stockholders. The collateral reserve is a cash deposit reserve held as collateral for increases to the PREPA Operating Security Letter of Credit. The guarantee reserve is a cash deposit with a
surety company as collateral for a bond in favor of PREPA that serve as a guarantee of a back feed power contract. The amounts deposited in the income tax reserve shall be applied to pay income tax.
Amounts deposited in the fuel supply interruption reserve shall be used for payment of principal and interest on the debt in case there is a business interruption. The fuel supply interruption reserve
should increase on a quarterly basis as established in the Credit Agreement (Note 10).

Effective
September 2003, the Lenders agreed that a cash reserve for income tax payments was not necessary until actual income tax payments are made. The Partnership agreed to
convert the income tax reserve to an insurance reserve. The insurance reserve is for $3 million and should be used by the Partnership to cover the costs of uninsured events related to damages
to the combustion turbines caused by transition pieces. This insurance reserve was reduced to $500,000 after the Operations, Plant and Service Agreement was signed on February 25, 2004.

As
of December 31, 2004 and 2003 the balances of the reserves were as follows (in thousands):

|                    |                           | 2004 |        | 2003 
|------------------- | ------------------------- | ---- | ------ | -----
|Current portion     |                           |      |        |      
|                    | Interest reserve          |      | $      | 24   
|                    | Principal reserve         |      |        | 6    
|                    | Major maintenance reserve |      |        | 8,017
|                    | Construction reserve      |      |        |     
|                    | Distribution reserve      |      |        | 7,632
|                    | Subordinared indebtness   |      |        | 19   
|                    | Collateral reserve        |      |        | 4,763
|                    | Guarantee reserve         |      |        | 583  
|                    |                           |      |        |      
|                    |                           | $    | 21,044 |      
|                    |                           |      |        |      
|Non-current portion |                           |      |        |      
|                    | Insurance reserve         |      | $      | 4    
|                    | Fuel management reserve   |      |        | 7,395
|                    |                           |      |        |      
|                    |                           | $    | 7,399  |      
|                    |                           |      |        |      

Operations, Plant and Service Agreement

On February 25, 2004, an Operations, Plant and Service Agreement was signed with Siemens Westinghouse that provide for discounted pricing on new components
(28%), shop repair services (10%) and outage services (5%). The agreement is for 14 years and provides certain annual incentives to Siemens Westinghouse if the minimum contracted availability
is met. As of December 31, 2004, $333,333 has been provided for incentives earned by Siemens Westinghouse for the year 2004.

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Interest Rate Protection Agreements

The Partnership entered into interest rate swap agreements to fix the interest rates on its loans payable. Interest rate swaps are agreements to exchange interest
rate payment streams based on a notional principal amount. The fair value of interest rates swaps is the estimated amount that the Partnership would receive or pay to terminate the swap agreements at
the reporting date, taking into account current interest rates and the current credit worthiness of the swap counterparties.

Under
Interest Rate Protection Agreements with ABN AMRO and Banque Paribas, the Partnership contracted a fixed interest rate of 6.385% and 6.365% over approximately 77% of its
outstanding long-term debt. The provisions of these agreements require payment by ABN AMRO and Banque Paribas to the Partnership for the excess of the current LIBOR rate over the fixed
interest rate or for the Partnership to pay ABN AMRO and Banque Paribas for the difference between the fixed interest rate and the current LIBOR rate, if the latter is lower.

As
of December 31, 2004 and 2003, the Partnership had outstanding interest rate swap agreements, with notional amounts of approximately $435,004,000 and $450,400,000,
respectively. The weighted average rate paid and received on these agreements was 6.383% and 1.45693% in 2004 and 6.383% and 1.23237% in 2003. The net interest rate differentials paid, recorded as
adjustments to interest expense, amounted to approximately $22,083,000 for the year ended December 31, 2004 and approximately $23,802,000 for the year ended December 31, 2003. No hedge
ineffectiveness has been recognized because this hedge is deemed to be 100% effective.

At
December 31, 2004 and 2003, the Interest Rate Protection Agreements mature as follows:

|               |  |            |  |            |  | Notional Amount
|-------------- |  | ---------- |  | ---------- |  | ---------------
|
|
|
|ABN AMRO       |  | 10/2/2000  |  | 12/15/2017 |  | $              
|ABN AMRO       |  | 12/29/2000 |  | 3/31/2016  |  |                
|Banque Paribas |  | 12/15/1999 |  | 12/17/2017 |  |                
|Banque Paribas |  | 10/2/2000  |  | 12/15/2017 |  |                

The fair value of the swap agreements liability at December 31, 2004 and 2003 was $51,930,000 and $61,354,000, respectively. As of
December 31, 2004, the loss deferred in accumulated other comprehensive income expected to be reclassified to income within the next year amounts to $14,444,000.

4.     Accounts Receivable

Accounts Receivable include amounts past due from PREPA that started to accumulate since the beginning of commercial operations and continue to increase as
monthly withholdings continue to be made. There are various reasons for the withholdings by PREPA, which are rooted in the interpretation of various contract provisions. The largest amount withheld
relates to the interpretation of a base value in the Energy Payment formula. Management has been working with PREPA since the withholdings began, to achieve a successful resolution of these disputes,
but no agreement has been reached. As of December 31, 2004 and 2003, $39,412,000 and $28,257,000 of the amounts billed to PREPA were under dispute. The Company has deferred recognition of
revenue on $10,429,000 (2003$7,392,000) based on management's estimate of realizability.

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5.     Insurance Claims Receivable

During 2002, the Partnership suffered losses due to several mechanical failures on its combustion turbines. The Partnership filed claims related to year 2002
under the property damage policy. One of the claims was related to failures in the combustion turbine stator and transition pieces of turbine #2, for which a claim of approximately $1,764,000 was
recorded as of December 31, 2003. A second claim was filed due to failures in the combustion turbine transition pieces of turbine #1 for approximately $1,916,000. As of December 31,
2004, $735,000 had been collected on these claims. These claims have been settled with the insurance company for the amount recorded.

6.     Note and Interest Receivable from PREPA

In December 1997, the Partnership made a $5,000,000 loan to PREPA (the PREPA Loan). This loan matured and was repaid on November 3, 2004. Interest
was payable at LIBOR minus 3% and paid annually. No interest income was earned in 2004 and 2003, due to the fact that the 3% exceeded the LIBOR rate.

7.     Inventories

As of December 31, 2004 and 2003, inventories consist of the following (in thousands):

|                              |  | 2004 |        | 2003
|----------------------------- |  | ---- | ------ | ----
|Liquefied natural gas (LNG)   |  | $    | 16,332 |     
|Liquefied petroleum gas (LPG) |  |      | 2,520  |     
|Fuel oil No. 2                |  |      | 3,842  |     
|Spare parts and supplies      |  |      | 15,589 |     
|                              |  |      |        |     
|                              |  | $    | 38,283 |     
|                              |  |      |        |     

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8.     Property, Plant and Equipment

As of December 31, property, plant and equipment consist of the following:

|                                                |  | Estimated
Useful Lives
(in years) |  | 2004 |          | 2003 |  
|----------------------------------------------- |  | --------------------------------- |  | ---- | -------- | ---- | -
|
|Machinery and equipment                         |  | 35                                |  | $    | 447,175  |      | $
|LNG and LPG facilities and equipment            |  | 22 - 50                           |  |      | 208,953  |      |  
|Buildings                                       |  | 30                                |  |      | 19,184   |      |  
|Major maintenance expenditures                  |  | 1 - 6                             |  |      | 46,603   |      |  
|Fuel oil facilities                             |  | 50                                |  |      | 2,941    |      |  
|Furniture and fixtures                          |  | 10                                |  |      | 915      |      |  
|Leasehold improvements                          |  | 4                                 |  |      | 29       |      |  
|Vehicles and equipment                          |  | 3                                 |  |      | 252      |      |  
|                                                |  |                                   |  |      |          |      |  
|                                                |  |                                   |  |      | 726,052  |      |  
|Less: Accumulated depreciation and amortization |  |                                   |  |      | (107,196 | )    |  
|                                                |  |                                   |  |      |          |      |  
|                                                |  |                                   |  |      | 618,856  |      |  
|Land and land improvements                      |  |                                   |  |      | 5,350    |      |  
|Construction in progress                        |  |                                   |  |      | 1,737    |      |  
|                                                |  |                                   |  |      |          |      |  
|                                                |  |                                   |  | $    | 625,943  |      | $
|                                                |  |                                   |  |      |          |      |  

Major maintenance expeditures are comprised of machinery and equipment.

9.     Working Capital Facilities

Draws on the Working Capital facility of $30,000,000 are subject to a borrowing base tied to the fuel inventory and receivables from PREPA. Also up to $8,000,000
can be drawn and held in a segregated sub-account subject to a lenders' lien to satisfy certain liquidity requirements in the PPA. The Working Capital facilities have an annual, five
consecutive day clean-up feature, for amounts not considered current asset loans, as defined. This clean-up feature does not apply to the $8,000,000. To the extent that the
Working Capital facilities are not refinanced or extended at its initial maturity date, the $8,000,000 of Working Capital loans drawn to satisfy the PPA liquidity requirements may be amortized along
with the Tranche A loans on a pro rata basis (see Note 10). The $30,000,000 Working Capital facilities mature on June 15, 2005, has a commitment fee of .375%, and bears interest at LIBOR
(2.56% and 1.8125%, at December 31, 2004 and 2003, respectively) plus 1.125%.

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10.   Loans Payable

In December 1997, the Partnership obtained a construction/term loan facility of approximately $614,000,000. As of December 31, loans payable is
comprised of the following (in thousands):

|            |                | Maturity             |               | Commitment
Fee |        | Interest Rate
Over LIBOR |              | 2004   |        | 2003
|----------- | -------------- | -------------------- | ------------- | -------------- | ------ | ------------------------ | ------------ | ------ | ------ | ----
|Term loans: |                |                      |               |                |        |                          |              |        |        |     
|            | Tranche A Loan |                      | June 15, 2016 |                | 0.375% |                          | Construction |        | 1.125% |     
|            | Tranche B Loan |                      | June 15, 2018 |                | 0.375% |                          | Years 1-5    |        | 1.375% |     
|            |                |                      |               |                |        | Years 6-10               |              | 1.750% |        |     
|            |                |                      |               |                |        | Years 11-16              |              | 2.000% |        |     
|            |                |                      |               |                |        | Years 16-18              |              | 2.500% |        |     
|            |                | Total loans payable  |               |                |        |                          |              |        |        |     
|            |                | LessCurrent portion |               |                |        |                          |              |        |        |     
|            |                |                      |               |                |        |                          |              |        |        |     
|            |                |                      |               |                |        |                          |              |        |        | $   
|            |                |                      |               |                |        |                          |              |        |        |     

Future maturities of long-term debt are as follows:

|Year       |  | (In thousands)
|---------- |  | --------------
|2005       |  | $             
|2006       |  |               
|2007       |  |               
|2008       |  |               
|2009       |  |               
|Thereafter |  |               
|           |  |               
|           |  | $             
|           |  |               

The construction loans were due 18 months after the Phase I Basic Term-Out date of June 15, 2000. The Phase I and II
construction loans were converted to term loans on September 20, 2001. Quarterly amortization payments for Tranche A commenced in September 2002 and will commence for Tranche B in the
first quarter of the 17th year, after the Basic Term-Out date. The balance on the loan facility is collateralized by the Partnership's assets and bears interest at LIBOR
(2.56% at December 31, 2004) plus 1.250% and 1.375%, on Tranche A and Tranche B, respectively, payable quarterly.

11.   Subordinated Notes and Accrued Interest PayableEME and GN

EME and Enron Development Corp. (EDC), an indirect wholly-owned subsidiary of Enron, and certain of their affiliates incurred costs on behalf of the Partnership
during the construction phase. These costs were recorded as part ofProperty, plant and equipmentwith corresponding amounts recorded as Subordinated notesand relatedAccrued interest payableto EME and EDC. The note payable to EDC was
transferred to GN as part of the acquisition of the Enron participation in Buenergía.

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As
of December 31, 2004 and 2003 outstanding principal and interests were as follows (in thousands):

|                                                            |                                               | 2004 |        | 2003  
|----------------------------------------------------------- | --------------------------------------------- | ---- | ------ | ------
|Subordinated notes payableInternational Power              |                                               | $    | 20,000 |       
|Subordinated notes payableGas Natural SDG, S.A.            |                                               |      | 12,000 |       
|Subordinated accrued interest payableInternational Power   |                                               |      | 14,000 |       
|Subordinated accrued interest payableGas Natural SDG, S.A. |                                               |      | 3,450  |       
|                                                            |                                               |      |        |       
|                                                            | Total subordinated notes and accrued interest |      | $      | 49,450
|                                                            |                                               |      |        |       

The notes bear interest at the lesser of 12 percent compounded quarterly or the maximum non-usurious rate of interest under New
York law. These amounts are subordinated to any amounts due under the Credit Facilities and can only be paid out of cash otherwise available for distribution to the partners. In November 8,
2002, $8,000,000 (including interest of $5,872,000) was paid to EME and EDC. In February 13, 2004 and August 26, 2004 $11,500,000 and $5,750,000 (representing 100% interests),
respectively, were paid to EME and GN.

12.   Debt Service Reserve Loan Facility

The Partnership also obtained a $19 million Debt Service Reserve Loan Facility which acts as an alternative to a funded debt service reserve and is
available to fund debt service shortfalls. In the event that debt service coverage ratios in any one of the three years prior to the maturity of the Debt Service
Reserve Loan Facility are less than 1.4, the facility will be fully drawn and deposited into a Debt Service Reserve Account, with the reimbursement obligation amortized on a pro rata basis with the
Tranche A facility. Otherwise, any draws on the Debt Service Reserve Account will be replenished by all excess cash flow after debt service. The Debt Service Reserve Loan Facility matures
10 years after the completion of construction, has a commitment fee of 0.375%, bears interest at LIBOR plus 2.125% during years 1-5 and LIBOR plus 2.35% during years
6-10. As of December 31, 2004 and 2003, no amounts have been drawn under this facility.

13.   PREPA Letter of Credit Facility

Pursuant to the terms of the PPA, the Partnership has provided an operating security instrument in the form of a standby letter of credit from a financial
institution. The facility may be drawn upon only if the Plant causes a breach under the PPA, up to a maximum of approximately $15,210,000. PREPA's ability to draw on the facility will be reduced by
amounts outstanding under the PREPA Loan (see Note 6). The operating security was issued when the Plant commenced commercial operations and will mature on December 15, 2007. The
obligation with PREPA to replenish any amount drawn on the facility is due within 90 days. The obligation with the financial institution for any amounts drawn on the facility prior to the first
principal payment of the Tranche A Loan is to repay in the same proportion and during the same periods as provided for in the Tranche A Loan amortization schedule. The obligation with the financial
institution for any amounts drawn after the first principal payment date of the Tranche A Loan is to repay based on the remaining principal payment dates with the amortization percentage increased, on
a pro rata basis, by the percentage attributable to each prior principal payment date. The facility has a commitment fee of 0.375% and bears interest at LIBOR plus 1.125% during years 1-5
of operations and LIBOR plus 1.375% during years 6-10 of operations. As of December 31, 2004 and 2003, no amounts were outstanding under this facility.

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The
Partnership is also required, pursuant to the terms of the PPA, to increase the letter of credit at a compound annual escalation rate of 7% throughout the remainder of the facility.
However, as long as the Partnership achieves certain goals, no further escalation shall apply. As of December 31, 2004 and 2003, the letter of credit issued has been escalated to approximately
$19,937,000 and $13,569,000 (net of the $5 million note receivable from PREPA in 2003), for which $4,731,000 and $3,359,000 was posted as cash collateral which is presented, including interest,
as non-currentRestricted cashin the accompanying balance sheet at December 31, 2004 and 2003.

14.   Fuel Performance Letter of Credit Facility

Pursuant to the terms of the LNG Sales Contract entered into between Tractebel and the Partnership, the Partnership is required to purchase certain fuel
requirements of the Plant from Tractebel. The Partnership, as required, has provided a standby letter of credit from a financial institution to Tractebel. The $30 million facility will mature
December 15, 2007, has a commitment fee of 0.375%, bears interest at LIBOR plus 1.125% during years 1-5 of operations and LIBOR plus 1.375% during years 6-8 of
operations. This facility will be used to secure the Partnership's ongoing liabilities to Tractebel in connection with periodic LNG purchases. As fuel expenses are the first expenses paid out of the
Plant's operating account, the facility is not expected to be drawn. However, if drawn, reimbursement obligations will be due within 5 days and will be paid out of the operating account in the
same priority order as fuel expenses. As of December 31, 2004 and 2003, no amounts have been drawn under this facility.

15.   Income Tax

The Partnership is partially exempt from Puerto Rico income and property taxes under the provisions of the Puerto Rico Industrial Incentives Act of 1987, as
amended. This exemption grant is effective for the twenty taxable years succeeding the year of commencement of commercial operations, and provides for a 7% flat rate for income tax and a 90% exemption
from property taxes. Pursuant to the grant's provisions, the Partnership shall have the option to deduct the total costs incurred after January 1, 1998 in the purchase, acquisition,
construction, and/or installation of facilities to be utilized in the cogeneration plant in the taxable year that the cost is incurred. The excess of this deduction over the Partnership's industrial
development income (IDI) subject to the 7% tax rate for the taxable year in which the costs were incurred may be carried forward to offset such IDI in subsequent taxable years, until exhausted. As a
result of this deduction, the Partnership's did not incur in a current income tax liability in 2004 and 2003. A deferred tax liability has been recognized for this deduction.

The
Partnership's effective tax rate differs from the applicable Puerto Rico statutory income tax rate due to the following (in thousands):

|                                                  |  | 2004 |         | 2003 |       | 2002 |  
|------------------------------------------------- |  | ---- | ------- | ---- | ----- | ---- | -
|
|Income tax provision at the statutory rate of 39% |  | $    | 20,875  |      | 39.0  |      | $
|Exemption on industrial development income        |  |      | (17,128 | )    | (32.0 | )    |  
|Other                                             |  |      | (75     | )    | (0.1  | )    |  
|                                                  |  |      |         |      |       |      |  
|Income tax provision                              |  | $    | 3,672   |      | 6.9   |      | $
|                                                  |  |      |         |      |       |      |  

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The components of deferred income tax liabilities or assets as of December 31 are as follows (in thousands):

|                                  |                                     | 2004                       |   | 2003   |       
|--------------------------------- | ----------------------------------- | -------------------------- | - | ------ | ------
|Deferred tax assets (liabilities) |                                     |                            |   |        |       
|                                  | Construction and installation costs |                            | $ | (8,087 | )     
|                                  | Allowance for doubtful accounts     |                            |   | 607    |       
|                                  |                                     |                            |   |        |       
|                                  |                                     | Net deferred tax liability |   | $      | (7,480
|                                  |                                     |                            |   |        |       

The deferred tax asset of $3,635,000 and $4,295,000 at December 31, 2004 and 2003 relates exclusively to unrealized losses on interest rate
swaps agreements included in accumulated other comprehensive loss.

16.   Savings Plan

Effective January 1, 1999, the Partnership established a savings plan for all eligible non-union employees of the Partnership. Participants may
contribute from 1% to 10% of their annual pre-tax compensation up to a maximum of $8,000. The Partnership's matching contribution is 50% of the first 6% of a participant's annual
contribution. Effective January 1, 2002, the Partnership agreed with the United Steel Workers of America to establish a savings plan for all eligible union employees with substantially the same
provisions as the non-union plan. The Partnership's contribution to these plans during 2004, 2003 and 2002 amounted to approximately $88,000, $71,000 and $54,000, respectively, which is
expensed as salaries and related benefits.

17.   Commitments and Contingencies

In addition to the commitments and contingencies disclosed in the other notes to the accompanying financial statements, following are some related to leases and
to legal and administrative procedures.

Leases

The Partnership leases its administrative office facilities under an operating lease agreement expiring in August 2006. During 2004, 2003 and 2002 rental
expense was approximately $123,000, including basic rent plus a proportionate share of taxes, operating and maintenance expenses.

Future
minimum annual lease payments are as follows (in thousands):

|Year |  | Amount
|---- |  | ------
|2005 |  |       
|2006 |  |       
|     |  |       
|     |  | $     
|     |  |       

Contingencies

The Partnership is involved in various legal and administrative actions, generally related to its operations. Management believes that the outcome of such actions
will not have a material adverse effect on the financial position or results of operations of the Partnership.

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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. MCDANIEL |  |                                                                                                      |  |               
|Thomas R. McDaniel     |  | Director, Chairman of the Board, President
and Chief Executive Officer
(Principal Executive Officer) |  | March 14, 2005
|/S/ MARK C. CLARKE     |  |                                                                                                      |  |               
|Mark C. Clarke         |  | Vice President and Controller
(Controller or Principal Accounting
Officer)                           |  | March 14, 2005
|/S/ JOHN E. BRYSON     |  |                                                                                                      |  |               
|John E. Bryson         |  | Director and Chairman of the Board                                                                   |  | March 14, 2005
|/S/ BRYANT C. DANNER   |  |                                                                                                      |  |               
|Bryant C. Danner       |  | Director                                                                                             |  | March 14, 2005

247

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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                                  |  | $            | 2    
|Affiliate receivables                                      |  |              | 348  
|                                                           |  |              |      
|Total current assets                                       |  |              | 350  
|Investments in subsidiaries                                |  |              | 1,558
|Investment in discontinued operations                      |  |              | 106  
|Other long-term assets                                     |  |              | 16   
|                                                           |  |              |      
|Total Assets                                               |  | $            | 2,030
|                                                           |  |              |      
|Liabilities and Shareholder's Equity                       |  |              |      
|Accounts payable and accrued liabilities                   |  | $            | 58   
|Liabilities under price risk management and energy trading |  |              |     
|Current portion of long-term obligations                   |  |              | 285  
|                                                           |  |              |      
|Total current liabilities                                  |  |              | 343  
|Long-term obligations                                      |  |              | 787  
|Deferred taxes and other                                   |  |              | 5    
|                                                           |  |              |      
|Total Liabilities                                          |  |              | 1,135
|Common Shareholder's Equity                                |  |              | 895  
|                                                           |  |              |      
|Total Liabilities and Shareholder's Equity                 |  | $            | 2,030
|                                                           |  |              |      

---

248

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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                                                 |  | $                        | (2  
|                                                                   |  |                          |     
|Operating loss                                                     |  |                          | (2  
|Equity in income (loss) from continuing operations of subsidiaries |  |                          | (568
|Equity in income from discontinued operations of subsidiaries      |  |                          | 690 
|Interest expense and other                                         |  |                          | (157
|                                                                   |  |                          |     
|Loss before income taxes                                           |  |                          | (37 
|Benefit for income taxes                                           |  |                          | (61 
|                                                                   |  |                          |     
|Net income (loss)                                                  |  | $                        | 24  
|                                                                   |  |                          |     

---

249

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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  |                                           | $                        | (123
|Net cash provided by (used in) financing activities  |                                           |                          | (26 
|Net cash provided by (used in) investing activities  |                                           |                          | 1   
|                                                     |                                           |                          |     
|Net increase (decrease) in cash and cash equivalents |                                           |                          | (148
|Cash and cash equivalents at beginning of period     |                                           |                          | 150 
|                                                     |                                           |                          |     
|Cash and cash equivalents at end of period           |                                           | $                        | 2   
|                                                     |                                           |                          |     
|Other Cash Flow Data:                                |                                           |                          |     
|                                                     | Cash dividends received from subsidiaries |                          | $   
|                                                     |                                           |                          |     

---

250

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SCHEDULE II

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

|                             |                                    |  |   | Additions |  |   |   | 
|---------------------------- | ---------------------------------- |  | - | --------- |  | - | - | 
|
|Year Ended December 31, 2004 |                                    |  |   |           |  |   |   | 
|                             | Allowance for doubtful accounts    |  | $ |          |  | $ |  | 
|Year Ended December 31, 2003 |                                    |  |   |           |  |   |   | 
|                             | Allowance for doubtful accounts(1) |  | $ | 8.9       |  | $ |  | 
|Year Ended December 31, 2002 |                                    |  |   |           |  |   |   | 
|                             | Allowance for doubtful accounts(1) |  | $ | 9.4       |  | $ |  | 

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