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



Form 10-Q

(Mark one)ý

QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE
SECURITIES EXCHANGE ACT OF 1934For the Quarterly Period Ended June 30, 2008oro

TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE
SECURITIES EXCHANGE ACT OF 1934For the transition period from
 to


Commission file number 333-68630



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

Delaware

95-4031807(State or other jurisdiction of incorporation
or organization)

(I.R.S. Employer Identification No.)18101 Von Karman Avenue, Suite 1700
Irvine, California

92612(Address of principal executive offices)

(Zip Code)Registrant's telephone number, including area code:(949) 752-5588




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

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer or a smaller reporting
company. See the definitions of "accelerated filer," "large accelerated filer" and "smaller reporting company" in Rule 12b-2 of the Exchange Act. (Check one):

Large accelerated filer o

Accelerated filer o

Non-accelerated filer ý (Do not check if a
smaller reporting company)

Smaller reporting company o


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

Number of shares outstanding of the registrant's Common Stock as of August 8, 2008: 100 shares (all shares held by an affiliate of the registrant).



---





TABLE OF CONTENTS

PageGlossary

iiPART IFinancial InformationItem 1.

Financial Statements

1Item 2.

Management's Discussion and Analysis of Financial Condition and Results of Operations

20Item 3.

Quantitative and Qualitative Disclosures about Market Risk

55Item 4T.

Controls and Procedures

56PART IIOther
InformationItem 1.

Legal Proceedings

57Item 1A.

Risk Factors

58Item 6.

Exhibits

58Signatures

59


i

---





GLOSSARY

When the following terms and abbreviations appear in the text of this report, they have the meanings indicated below.

Btu

British thermal unitsCAIR

Clean Air Interstate RuleCommonwealth Edison

Commonwealth Edison CompanyCONE

cost of new entryEME

Edison Mission EnergyEME Homer City

EME Homer City Generation L.P.EMMT

Edison Mission Marketing & Trading, Inc.FASB

Financial Accounting Standards BoardFERC

Federal Energy Regulatory CommissionFIN No. 39-1

Financial Accounting Standards Board Staff Position No. 39-1, "Amendment of FASB Interpretation No. 39"Fitch

Fitch RatingsFSP SFAS No. 142-3

Financial Accounting Standards Board Staff Position SFAS No. 142-3, "Determination of the Useful Life of Intangible Assets"GAAP

generally accepted accounting principlesGHG

greenhouse gasGWh

gigawatt-hoursIllinois Plants

EME's largest power plants (fossil fuel) located in IllinoisMD&A

Management's Discussion and Analysis of Financial Condition and Results of OperationsMidwest Generation

Midwest Generation, LLCMMBtu

million British thermal unitsMoody's

Moody's Investors Service, Inc.MW

megawattsMWh

megawatt-hoursNOV

Notice of ViolationNOX

nitrogen oxideNYISO

New York Independent System OperatorPJM

PJM Interconnection, LLCPRB

Powder River BasinRPM

reliability pricing modelS&P

Standard & Poor's Ratings ServicesSCE

Southern California Edison CompanySFAS

Statement of Financial Accounting Standards issued by the FASB


ii

---



SFAS No. 133

Statement of Financial Accounting Standards No. 133, "Accounting for Derivative Instruments and Hedging Activities"SFAS No. 141(R)

Statement of Financial Accounting Standards No. 141(R), "Business Combinations"SFAS No. 157

Statement of Financial Accounting Standards No. 157, "Fair Value Measurements"SFAS No. 161

Statement of Financial Accounting Standards No. 161, "Disclosures About Derivative Instruments and Hedging Activities" (an amendment of FASB No. 133)SIP(s)

state implementation plan(s)SO2

sulfur dioxideUS EPA

United States Environmental Protection Agency


iii

---





PART IFINANCIAL INFORMATION

ITEM 1.    FINANCIAL STATEMENTS

EDISON MISSION ENERGY AND SUBSIDIARIES  CONSOLIDATED STATEMENTS OF INCOME (LOSS)  (In millions, Unaudited)

Three Months Ended
June 30,

Six Months Ended
June 30,2008

2007

2008

2007Operating Revenues

$
613

$
570

$
1,332

$
1,243Operating ExpensesFuel


157


152


344


328Plant operations


195


181


331


313Plant operating leases


44


44


88


88Depreciation and amortization


46


41


90


76Gain on buyout of contract and sale of assets (Note 8)








(16
)

Administrative and general


50


45


98


84Total operating expenses


492


463


935


889Operating income


121


107


397


354Other Income (Expense)Equity in income from unconsolidated affiliates


37


54


49


80Dividend income


9


10


10


11Interest income


7


22


15


46Interest expense


(66
)

(69
)

(137
)

(129
)Loss on early extinguishment of debt





(160
)




(160
)Other income (expense), net


(1
)

1


5


Total other income (expense)


(14
)

(142
)

(58
)

(152
)Income (loss) from continuing operations before income taxes


107


(35
)

339


202Provision (benefit) for income taxes


34


(16
)

116


68Income (Loss) From Continuing Operations


73


(19
)

223


134Income (loss) from operations of discontinued subsidiaries, net of tax (Note 5)


(1
)

2


(6
)

5Net Income (Loss)

$
72

$
(17
)
$
217

$
139


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

1

---





EDISON MISSION ENERGY AND SUBSIDIARIES  CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (LOSS)  (In millions, Unaudited)

Three Months Ended
June 30,

Six Months Ended
June 30,2008

2007

2008

2007Net Income (Loss)

$
72

$
(17
)
$
217

$
139Other comprehensive income (loss), net of tax:Pension and postretirement benefits other than pensions:Amortization of prior service, net of tax


1





1


Amortization of net loss, net of tax benefit


(1
)




(1
)

Unrealized gains (losses) on derivatives qualified as cash flow hedges:Other unrealized holding gains (losses) arising during period, net of income tax expense (benefit) of $(212) and $30 for the three months and
$(304) and $(85) for the six months ended June 30, 2008 and 2007, respectively


(316
)

48


(454
)

(121
)Reclassification adjustments included in net income (loss), net of income tax benefit of $95 and $7 for the three months and $89 and $19 for the six months
ended June 30, 2008 and 2007, respectively


143


10


135


25Other comprehensive income (loss)


(173
)

58


(319
)

(96
)Comprehensive Income (Loss)

$
(101
)
$
41

$
(102
)
$
43


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

2

---





EDISON MISSION ENERGY AND SUBSIDIARIES  CONSOLIDATED BALANCE SHEETS  (In millions, Unaudited)

June 30,
2008

December 31,
2007AssetsCurrent AssetsCash and cash equivalents

$
585

$
994Short-term investments


11


81Accounts receivabletrade


301


224Receivables from affiliates


85


35Inventory


172


149Derivative assets


65


56Margin and collateral deposits


177


85Deferred taxes


133


21Prepaid expenses and other


91


89Total current assets


1,620


1,734Investments in Unconsolidated Affiliates


394


387Property, Plant and Equipment


5,250


4,942Less accumulated depreciation and amortization


1,139


1,053Net property, plant and equipment


4,111


3,889Other AssetsDeferred financing costs


39


41Long-term derivative assets


83


91Restricted cash


47


48Rent payments in excess of levelized rent expense under plant operating leases


829


716Other long-term assets


525


366Total other assets


1,523


1,262Total Assets

$
7,648

$
7,272


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

3

---



EDISON MISSION ENERGY AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
(In millions, Unaudited)

June 30,
2008

December 31,
2007Liabilities and Shareholder's EquityCurrent LiabilitiesAccounts payable

$
136

$
73Payables to affiliates


18


17Accrued liabilities


310


289Derivative liabilities


292


28Interest payable


30


30Current maturities of long-term obligations


27


17Total current liabilities


813


454Long-term obligations net of current maturities


3,845


3,806Deferred taxes and tax credits


276


351Deferred revenues


64


65Long-term derivative liabilities


228


88Other long-term liabilities


540


543Total Liabilities


5,766


5,307Minority Interest


69


42Commitments and Contingencies(Note 8)Shareholder's EquityCommon stock, par value $0.01 per share; 10,000 shares authorized; 100 shares issued and outstanding as of June 30, 2008 and December 31, 2007


64


64Additional paid-in capital


1,329


1,326Retained earnings


802


596Accumulated other comprehensive loss


(382
)

(63
)Total Shareholder's Equity


1,813


1,923Total Liabilities and Shareholder's Equity

$
7,648

$
7,272


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

4

---





EDISON MISSION ENERGY AND SUBSIDIARIES  CONSOLIDATED STATEMENTS OF CASH FLOWS  (In millions, Unaudited)

Six Months Ended
June 30,2008

2007Cash Flows From Operating ActivitiesNet income

$
217

$
139Less: (Income) loss from discontinued operations


6


(5
)Income from continuing operations, net

$
223

$
134Adjustments to reconcile income to net cash used in operating activities:Equity in income from unconsolidated affiliates


(48
)

(79
)Distributions from unconsolidated affiliates


40


53Depreciation and amortization


92


83Deferred taxes and tax credits


28


(3
)Gain on buyout of contract and sale of assets


(16
)

Loss on early extinguishment of debt





160Changes in operating assets and liabilities:Increase in margin and collateral deposits


(93
)

(34
)Increase in accounts receivable


(127
)

(130
)Increase in inventory


(23
)

(6
)Decrease in prepaid expenses and other


42


29Increase in rent payments in excess of levelized rent expense


(113
)

(112
)Increase (decrease) in accounts payable and other current liabilities


48


(68
)Increase in interest payable





9Increase in derivative assets and liabilities


(131
)

(93
)Other operatingassets


(33
)

Other operatingliabilities


5


25Operating cash flow from continuing operations


(106
)

(32
)Operating cash flow from discontinued operations


(6
)

5Net cash used in operating activities


(112
)

(27
)Cash Flows From Financing ActivitiesBorrowings on long-term debt


182


2,905Payments on long-term debt agreements


(133
)

(2,117
)Cash dividends to parent





(925
)Payments to affiliates related to stock-based awards


(8
)

(28
)Excess tax benefits related to stock-based awards


1


9Premium paid on extinguishment of debt and financing costs


(1
)

(161
)Net cash provided by (used in) financing activities


41


(317
)Cash Flows From Investing ActivitiesCapital expenditures


(214
)

(244
)Proceeds from return of capital, loan repayments and sale of assets


7


6Proceeds from sale of membership interest


28


Purchase of interest of acquired companies


(7
)

(23
)Purchase of short-term investments





(30
)Maturities and sales of short-term investments


70


270Decrease in restricted cash





30Investments in other assets


(222
)

(237
)Net cash used in investing activities


(338
)

(228
)Net decrease in cash and cash equivalents


(409
)

(572
)Cash and cash equivalents at beginning of period


994


1,213Cash and cash equivalents at end of period

$
585

$
641


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

5

---





EDISON MISSION ENERGY AND SUBSIDIARIES  NOTES TO CONSOLIDATED FINANCIAL STATEMENTS  JUNE 30, 2008  (Unaudited)

Note 1. Summary of Significant Accounting Policies

Basis of Presentation

EME's significant accounting policies were described in Note 1 to its consolidated financial statements included in its annual
report on Form 10-K for the year ended December 31, 2007. EME follows the same accounting policies for interim reporting purposes, with the exception of accounting principles
adopted as of January 1, 2008 as discussed below in "Margin and Collateral Deposits" and "New Accounting Pronouncements." This quarterly report should be read in
conjunction with such financial statements.

In
the opinion of management, all adjustments, including recurring accruals, have been made that are necessary to fairly state the consolidated financial position and results of
operations and cash flows in accordance with accounting principles generally accepted in the United States of America for the
periods covered by this quarterly report on Form 10-Q. The results of operations for the six months ended June 30, 2008 are not necessarily indicative of the operating
results for the full year.

Certain
prior year reclassifications have been made to conform to the current year financial statement presentation mostly pertaining to the adoption of FIN No. 39-1.
Except as indicated, amounts reflected in the notes to the consolidated financial statements relate to continuing operations of EME.

Short-term Investments

At June 30, 2008 and December 31, 2007, EME had classified all marketable debt securities as
held-to-maturity. The securities were carried at amortized cost plus accrued interest which approximated their fair value. Gross unrealized holding gains and losses were not
material.

Held-to-maturity
securities, which all mature within one year, consisted of the following:

June 30,
2008

December 31,
2007(in millions)Commercial paper

$
2

$
32Certificates of deposit


9


41Treasury bills





7Corporate bonds





1Total

$
11

$
81


Intangible Assets

The caption "Prepaid expenses and other" on EME's consolidated balance sheets include emission allowances purchased for use of
$41 million and $45 million at June 30, 2008 and December 31, 2007, respectively.

6

---



The
caption "Other long-term assets" on EME's consolidated balance sheets include the following noncurrent intangible assets:

June 30,
2008

December 31,
2007(in millions)Amortized intangible assets:Gross carrying amount

$
5

$
5Less accumulated amortization


2


1Amortized intangible assetsnet

$
3

$
4Unamortized intangible assets:Project development rights

$
14

$
14Option rights


24


24Purchased emission allowances


70


23Unamortized intangible assets

$
108

$
61


During
the first six months of 2008, EME acquired emission allowances at its Illinois Plants and Homer City facilities. In addition, EME acquired emission allowances related to thermal
projects under development. See "Environmental Matters and Regulations" in Note 8Commitments and Contingencies for further discussion with respect to allowances purchased by
Midwest Generation.

Inventory

Inventory is stated at the lower of weighted average cost or market. Inventory at June 30, 2008 and December 31, 2007
consisted of the following:

June 30,
2008

December 31,
2007(in millions)Coal and fuel oil

$
121

$
100Spare parts, materials and supplies


51


49Total

$
172

$
149


Margin and Collateral Deposits

Margin and collateral deposits include cash deposited with counterparties and brokers as credit support under energy contracts. The
amount of margin and collateral deposits generally varies based on changes in fair value of the related positions. See "New Accounting PronouncementsAccounting Principle's
AdoptedFASB Staff Position FIN No. 39-1" for a discussion of EME's adoption of FIN No. 39-1. In accordance with FIN No. 39-1, EME
presents a portion of its margin and cash collateral deposits net with its derivative positions on EME's consolidated balance sheets. Amounts recognized for cash collateral provided to others that
have been offset against net derivative liabilities totaled $226 million and $36 million at June 30, 2008 and December 31, 2007, respectively. Amounts recognized for cash
collateral received from others that have been offset against net derivative assets totaled $5 million at June 30, 2008.

7

---



New Accounting Pronouncements

Accounting Principles Adopted

FASB Staff Position FIN No. 39-1

In
April 2007, the FASB issued FIN No. 39-1. This pronouncement permits companies to offset fair value amounts recognized for the right to
reclaim cash collateral (a receivable) or the obligation to return cash collateral (a payable) against fair value amounts recognized for derivative instruments executed with the same counterparty
under a master netting arrangement. In addition, upon the adoption, companies were permitted to change their accounting policy to offset or not offset fair value amounts recognized for derivative
instruments under master netting agreements. EME adopted FIN No. 39-1 effective January 1, 2008. The adoption resulted in netting a portion of margin and cash collateral
deposits with derivative positions on EME's consolidated balance sheets, but had no impact on EME's consolidated statements of income. The consolidated balance sheet at December 31, 2007 has
been retroactively restated for the change, which resulted in a decrease in net assets (margin and collateral deposits) of $36 million. The consolidated statements of cash flows for the six
months ended June 30, 2007 has been retroactively restated to reflect the balance sheet changes, which had no impact on total operating cash flow from continuing operations.

Statement of Financial Accounting Standards No. 159

In
February 2007, the FASB issued SFAS No. 159, "Fair Value Option for Financial Assets and Liabilities, Including an Amendment of FASB Statement
No. 115," which provides an option to report eligible financial assets and liabilities at fair value, with changes in fair value recognized in earnings. EME adopted this pronouncement effective
January 1, 2008. The adoption had no impact because EME did not make an optional election to report additional financial assets and liabilities at fair value.

Statement of Financial Accounting Standards No. 157

In
September 2006, the FASB issued SFAS No. 157, which clarifies the definition of fair value, establishes a framework for measuring fair value and
expands the disclosures on fair value measurements. EME adopted SFAS No. 157 effective January 1, 2008. The adoption did not result in any retrospective adjustment to its consolidated
financial statements. The accounting requirements for employers' pension and other postretirement benefit plans are effective at the end of 2008, which is the next measurement date for these benefit
plans. The effective date will be January 1, 2009 for nonfinancial assets and liabilities which are measured or disclosed on a non-recurring basis. For further discussion see
Note 2Fair Value Measurements.

Accounting Principles Not Yet Adopted

Statement of Financial Accounting Standards No. 141(R)

In
December 2007, the FASB issued SFAS No. 141(R), which establishes principles and requirements for how the acquirer in a business combination
recognizes and measures in its financial statements the identifiable assets acquired, the liabilities assumed and any noncontrolling interest in the acquiree at the acquisition date fair value. SFAS
No. 141(R) determines what information to disclose to enable users of the financial statements to evaluate the nature and financial effects of the business combination. SFAS No. 141(R)
applies prospectively to business combinations for which the acquisition date is on or after fiscal years beginning January 1, 2009. Early adoption is not permitted.

Statement of Financial Accounting Standards No. 160

In
December 2007, the FASB issued SFAS No. 160, "Noncontrolling Interests in Consolidated Financial Statements," which requires an entity to present
minority interest that reflects the ownership

8

---



interests
in subsidiaries held by parties other than the entity, within the equity section but separate from the entity's equity in the consolidated financial statements. It also requires the amount
of consolidated net income attributable to the parent and to the noncontrolling interest to be clearly identified and presented on the face of the consolidated statement of income; changes in
ownership interest be accounted for similarly as equity transactions; and when a subsidiary is deconsolidated, any retained noncontrolling equity investment in the former subsidiary and the gain or
loss on the deconsolidation of the subsidiary be measured at fair value. EME will adopt SFAS No. 160 on January 1, 2009. In accordance with this standard, EME will reclassify minority
interest to a component of shareholder's equity (at June 30, 2008 this amount was $69 million).

Statement of Financial Accounting Standards No. 161

In
March 2008, the FASB issued SFAS No. 161, which requires additional disclosures related to derivative instruments, including how and why an entity
uses derivative instruments, how derivative instruments and related hedged items are accounted for and how derivative instruments and related hedged items affect an entity's financial position,
financial performance, and cash flows. SFAS No. 161 is effective for fiscal years beginning after November 15, 2008, with early adoption permitted. EME will adopt SFAS No. 161 in
the first quarter of 2009. SFAS No. 161 will impact disclosures only and will not have an impact on EME's consolidated results of operations, financial condition or cash flows.

FSP SFAS No. 142-3

In
April 2008, the FASB issued FSP SFAS No. 142-3 which amends the factors that should be considered in developing renewal or extension
assumptions used to determine the useful life of a recognized intangible asset under SFAS No. 142, "Goodwill and Other Intangible Assets." The intent of the position is to improve the
consistency between the useful life of a recognized intangible asset under SFAS No. 142 and the period of expected cash flows used to measure
the fair value of the asset under SFAS No. 141(R) and other U.S. GAAP. EME will adopt FSP SFAS No. 142-3 on January 1, 2009. EME is currently evaluating the
impact, if any, that the adoption of this position could have on its consolidated financial statements.

Note 2. Fair Value Measurements

SFAS No. 157 defines fair value as the price that would be received to sell an asset or paid to transfer a liability in an
orderly transaction between market participants at the measurement date (referred to as an "exit price" in SFAS No. 157). SFAS No. 157 clarifies that a fair value measurement for a
liability should reflect the entity's nonperformance risk.

The
standard establishes a hierarchy for fair value measurements. Financial assets and liabilities carried at fair value on a recurring basis are classified and disclosed in the three
categories outlined below:



EME's
assets and liabilities carried at fair value primarily consist of derivative positions. These positions may include forward sales and purchases of physical power, options and
forward price swaps which settle only on a financial basis (including futures contracts). In assessing the fair value of EME's derivative financial instruments, EME uses quoted market prices and
forward market prices adjusted

9

---



for
credit risk. 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.

Level 1
includes derivatives that are exchange traded in active markets. The fair values are determined using quoted exchange transaction market prices.

Level 2
includes traded derivatives using over-the-counter markets and exchange traded derivatives not classified as Level 1. The fair value of
these derivatives is determined using forward market prices adjusted for credit risk. The majority of Level 2 derivatives are entered into for hedging purposes.

Level 3
includes derivatives that trade infrequently such as firm transmission rights and over-the-counter derivatives at illiquid locations and
long-term power agreements. For illiquid firm transmission rights, EME reviews objective criteria related to system congestion on a quarterly basis and other underlying drivers and adjusts
fair value when EME concludes a change in objective criteria would result in a new valuation that better reflects the fair value. Changes in fair values are based on hypothetical sale of illiquid
positions. For illiquid long-term power agreements, fair value is based upon a discounting of future electricity prices derived from a proprietary model using the risk free discount rate
for a similar duration contract, adjusted for credit and liquidity. Changes in fair value are based on changes to forward market prices, including forecasted prices for illiquid forward periods.

In
circumstances where EME cannot verify fair value with observable market transactions, it is possible that a different valuation model could produce a materially different estimate of
fair value. As markets continue to develop and more pricing information becomes available, EME continues to assess valuation methodologies used to determine fair value.

When
appropriate, valuations are adjusted for various factors including liquidity, bid/offer spreads and credit considerations. Such adjustments are generally based on available market
evidence. In the absence of such evidence, management's best estimate is used.

The
following table sets forth EME's financial assets and liabilities that were accounted for at fair value as of June 30, 2008 by level within the fair value hierarchy.

Level 1

Level 2

Level 3

Netting and
Collateral(1)

Total at
June 30, 2008(in millions)Assets at Fair Value
Derivative contracts

$
4

$
21

$
165

$
(5
)
$
185Liabilities at Fair Value
Derivative contracts

$
(7
)
$
(732
)
$
(44
)
$
226

$
(557
)


---

10

---



The following table sets forth a summary of changes in the fair value of EME's Level 3 derivative contracts, net for the three months ended June 30, 2008.

(in millions)Fair value of derivative contracts, net at April 1, 2008

$
111Total realized/unrealized gains (losses):Included in earnings(1)


59Included in accumulated other comprehensive loss


(4
)Purchases and settlements, net


(38
)Transfers in or out of Level 3


(7
)Fair value of derivative contracts, net at June 30, 2008

$
121Change during the quarter in unrealized gains (losses) related to derivative contracts, net held at June 30, 2008(1)

$
34


The following table sets forth a summary of changes in the fair value of EME's Level 3 derivative contracts, net for the six months ended
June 30, 2008.

(in millions)Fair value of derivative contracts, net at January 1, 2008

$
120Total realized/unrealized gains (losses):Included in earnings(1)


92Included in accumulated other comprehensive loss


(6
)Purchases and settlements, net


(75
)Transfers in or out of Level 3


(10
)Fair value of derivative contracts, net at June 30, 2008

$
121Change during the six months ended June 30, 2008 in unrealized gains (losses) related to derivative contracts, net held at June 30, 2008(1)

$
37


---

Note 3. Accumulated Other Comprehensive Loss

Accumulated other comprehensive loss consisted of the following:

Unrealized
Losses on Cash
Flow Hedges

Unrecognized
Losses and Prior
Service Costs, Net(1)

Accumulated Other
Comprehensive Loss(in millions)Balance at December 31, 2007

$
(60
)
$
(3
)
$
(63
)Current period change


(319
)




(319
)Balance at June 30, 2008

$
(379
)
$
(3
)
$
(382
)


---

Unrealized losses on cash flow hedges, net of tax, at June 30, 2008, included unrealized losses on commodity hedges related to Midwest
Generation and EME Homer City futures and forward electricity contracts that qualify for hedge accounting. These losses arise because current forecasts of future electricity prices in these markets
are greater than the contract prices. As EME's hedged positions for continuing operations are realized, $257 million, after tax, of the net unrealized losses on cash flow hedges at
June 30, 2008 are expected to be reclassified into earnings during the next 12 months.

11

---



Management
expects that reclassification of net unrealized losses will decrease 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, 2011.

Under
SFAS No. 133, the portion of a cash flow hedge that does not offset the change in value of the transaction being hedged, which is commonly referred to as the ineffective
portion, is immediately recognized in earnings. EME recorded net losses of $18 million and $9 million during the second quarters of 2008 and 2007, respectively, and $31 million
and $10 million during the six months ended June 30, 2008 and 2007, respectively, representing the amount of cash flow hedges' ineffectiveness for continuing operations, reflected in
operating revenues in EME's consolidated income statements.

Note 4. Variable Interest Entities

EME has a number of wind projects that were consolidated in accordance with FIN 46(R). These projects were funded with
nonrecourse debt totaling $22 million at June 30, 2008. Properties serving as collateral for these loans had a carrying value of $52 million and are classified as property, plant
and equipment on EME's consolidated balance sheet at June 30, 2008.

EME
completed a review of the application of FIN 46(R) to its subsidiaries and affiliates and concluded that it had significant variable interests in variable interest entities as
defined in this Interpretation. As of June 30, 2008, these entities consisted of five equity investments (the Big 4 projects and the Sunrise project) that had interests in natural
gas-fired facilities with a total generating capacity of 1,782 MW. An operations and maintenance subsidiary of EME operates the Big 4 projects, but EME does not supply the fuel consumed or
purchase the power generated by these facilities. EME determined that it is not the primary beneficiary in these entities; accordingly, EME continues to account for its variable interests on the
equity method. EME's maximum exposure to loss in these variable interest entities is generally limited to its investment in these entities, which totaled $350 million as of June 30,
2008.

Note 5. Discontinued Operations

Lakeland Project

EME received a payment of £0.4 million (approximately $1 million) and £4 million
(approximately $8 million) in the first six months of 2008 and 2007, respectively. The after-tax income attributable to the Lakeland project was $0.1 and none in the second quarters
of 2008 and 2007, respectively, and $0.5 million and $5 million for the six months ended June 30, 2008 and 2007, respectively.

Summarized Financial Information for Discontinued Operations

Three Months Ended
June 30,

Six Months Ended
June 30,2008

2007

2008

2007(in millions)Income (loss) before income taxes

$


$
5

$
(6
)
$
11Provision for income taxes


1


3





6Income (loss) from operations of discontinued foreign subsidiaries


(1
)

2


(6
)

5


12

---



Note 6. Compensation and Benefit Plans

Pension Plans and Postretirement Benefits Other Than Pensions

Pension Plans

As of June 30, 2008, EME had made approximately $4 million in contributions to its pension plans and estimates to make
$10 million of contributions in the last six months of 2008. Expected contribution funding in 2008 could vary from anticipated amounts, depending on the funded status at year-end
and tax-deductible funding limitations.

The
following are components of pension expense:

Three Months Ended
June 30,

Six Months Ended
June 30,2008

2007

2008

2007(in millions)Service cost

$
3

$
4

$
8

$
8Interest cost


2


2


6


5Expected return on plan assets


(2
)

(2
)

(5
)

(4
)Total expense

$
3

$
4

$
9

$
9


Postretirement Benefits Other Than Pensions

As of June 30, 2008, EME had made approximately $1 million in contributions to its postretirement benefits other than
pensions and estimates to make $1 million of contributions in the last six months of 2008. Expected contribution funding in 2008 could vary from anticipated amounts, depending on the funded
status at year-end and tax-deductible funding limitations.

The
following are components of postretirement benefits expense:

Three Months Ended
June 30,

Six Months Ended
June 30,2008

2007

2008

2007(in millions)Service cost

$


$


$
1

$
1Interest cost


2


1


3


2Amortization of prior service costs


(1
)

(1
)

(1
)

(1
)Amortization of net loss


1


1


1


1Total expense

$
2

$
1

$
4

$
3


Note 7. Income Taxes

EME's income tax provision from continuing operations was $116 million and $68 million for the six months ended
June 30, 2008 and 2007, respectively. Income tax benefits are recognized pursuant to a tax-allocation agreement with Edison International. During the six months ended
June 30, 2008 and 2007, EME recognized $20 million and $12 million, respectively, of production tax credits related to wind projects and $3 million and $7 million,
respectively, related to estimated state income tax benefits allocated from Edison International.

13

---



Note 8. Commitments and Contingencies

Commitments

Capital Improvements

At June 30, 2008, EME's subsidiaries had firm commitments to spend approximately $259 million during the remainder of
2008 on capital and construction expenditures. The majority of these expenditures relate to the construction of wind projects. These expenditures are planned to be financed by cash on hand, cash
generated from operations or existing subsidiary credit agreements.

Turbine Commitments

EME had entered into various turbine supply agreements with vendors to support its wind and thermal development efforts. At
June 30, 2008, EME had secured 533 wind turbines (1,061 MW) and 5 gas-fired turbines (479 MW) for use in future projects for an aggregate purchase price of $1.6 billion, with
remaining commitments of $407 million in 2008, $557 million in 2009 and $300 million in 2010. At June 30, 2008, EME had recorded wind turbine deposits of
$294 million included in other long-term assets in its consolidated balance sheet.

Fuel Supply Contracts

In connection with the acquisition of the Illinois Plants, Midwest Generation had assumed a long-term coal supply contract
and recorded a liability to reflect the fair value of this contract. In March 2008, Midwest Generation entered into an agreement to buyout its coal obligations for the years 2009 through 2012 under
this contract with a one-time payment to be made in January 2009. Midwest Generation recorded a pre-tax gain of $15 million ($9 million, after tax) during the
first quarter of 2008. The remaining payments due under this contract are $18 million.

Other Contractual Obligations

EME's subsidiaries had entered into contractual agreements during the first six months of 2008 to purchase materials for environmental
controls equipment. These
commitments are currently estimated to be $188 million, summarized as follows: remainder of 2008$7 million, 2009$29 million,
2010$45 million, 2011$45 million, 2012$43 million, and thereafter$19 million.

Standby Letters of Credit

At June 30, 2008, standby letters of credit aggregated $84 million and were scheduled to expire as follows:
$30 million in 2008 and $54 million in 2009.

Guarantees and Indemnities

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

Tax Indemnity Agreements

In connection with the sale-leaseback transactions related to the Homer City facilities in Pennsylvania, the Powerton and
Joliet Stations in Illinois, and, previously, the Collins Station in Illinois, EME and several of its subsidiaries entered into tax indemnity agreements. Although the Collins Station lease terminated
in April 2004, Midwest Generation's tax indemnity agreement with the former lease equity investor is still in effect. Under these tax indemnity agreements, these entities agreed to indemnify the
lessors in the sale-leaseback transactions for specified adverse tax consequences that

14

---



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.

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 takes 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. By letter
dated August 8, 2007, Commonwealth Edison advised EME that Commonwealth Edison believes it is entitled to indemnification for all liabilities, costs, and expenses that it may be required to
bear as a result of the NOV discussed below under "ContingenciesMidwest Generation New Source Review Notice of Violation." By letter dated August 16, 2007, Commonwealth Edison
tendered a request for indemnification to EME for all liabilities, costs, and expenses that Commonwealth Edison may be required to bear if the environmental groups were to file suit. Except as
discussed below, EME has not recorded a liability related to this indemnity.

Midwest
Generation entered into a supplemental agreement with Commonwealth Edison and Exelon Generation Company LLC 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 asbestos claims pending as of February 2003 and related 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 had an initial five-year term with an automatic renewal provision for subsequent one-year terms (subject to
the right of either party to terminate); pursuant to the automatic renewal provision, it has been extended until February 2009. Payments are made under this indemnity upon tender by Commonwealth
Edison of appropriate proof of liability for an asbestos-related settlement, judgment, verdict, or expense. There were approximately 230 cases for which Midwest Generation was potentially liable and
that had not been settled and dismissed at June 30, 2008. Midwest Generation had recorded a $53 million liability at June 30, 2008 related to this matter.

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

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

In connection with the acquisition of the Homer City facilities, EME Homer City agreed to indemnify the sellers with respect to
specific environmental liabilities before and after the date of sale. Payments would be triggered under this indemnity by a valid claim from the sellers. EME guaranteed the obligations of EME Homer
City. Due to the nature of the obligation under this indemnity

15

---



provision,
it is not subject to a maximum potential liability and does not have an expiration date. 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. Not all indemnities under the asset sale
agreements have specific expiration dates. Payments would be triggered under these indemnities by valid claims from the sellers or purchasers, as the case may be. At June 30, 2008, EME had
recorded a liability of $108 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. At June 30, 2008, EME had recorded a liability of
$12 million related to these matters.

Capacity Indemnification Agreements

EME has guaranteed, jointly and severally with Texaco Inc., the obligations of March Point Cogeneration Company under its
project power sales agreements to repay capacity payments to the project's power purchaser in the event that the power sales agreements terminate, March Point Cogeneration Company abandons the
project, or the project fails to return to normal operations within a reasonable time after a complete or partial shutdown, during the term of the power sales agreements. The obligations under this
indemnification agreement as of June 30, 2008, if payment were required, would be $66 million. EME has not recorded a liability related to this indemnity.

Contingencies

RPM Buyers' Complaint

On May 30, 2008, a group of entities referring to themselves as the "RPM Buyers" filed a complaint at the FERC asking that PJM's
RPM, as implemented through the transitional base residual auctions establishing capacity payments for the period from June 1, 2008 through May 31, 2011, be found to have produced unjust
and unreasonable capacity prices. The RPM Buyers alleged that the absence of price discipline provided by new capacity resources, together with the ability of existing resources to withhold some
capacity within the RPM rules, produced capacity prices in the transition period that are not comparable to those that would have been produced in a competitive market or determined under
cost-based regulation, and have requested that the FERC order refunds based on that difference.

On
July 10, 2008, EME responded to the RPM Buyers' complaint asking that the same be dismissed based upon various legal precedents. In particular EME argued that the complaint
represents little more than a collateral attack on the FERC's orders approving the RPM settlement and rules and that all of the major factors the RPM Buyers alleged produced unjust and unreasonable
prices in the base residual auctions were previously litigated and adjudicated in the contested proceedings involving the RPM settlement. A number of other parties, including PJM, also responded to
the RPM Buyers' complaint asking that the same be dismissed. This matter is currently pending before the FERC. EME cannot predict the outcome of this matter.

16

---



Midwest Generation New Source Review Notice of Violation

On August 3, 2007, Midwest Generation received an NOV from the US EPA alleging that, beginning in the early 1990s and into 2003,
Midwest Generation or Commonwealth Edison performed repair or replacement projects at six Illinois coal-fired electric generating stations in violation of the Prevention of Significant
Deterioration requirements and of the New Source Performance Standards of the Clean Air Act, including alleged requirements to obtain a construction permit and to install best available control
technology at the time of the projects. The US EPA also alleges that Midwest Generation and Commonwealth Edison violated certain operating permit requirements under Title V of the Clean Air Act.
Finally, the US EPA alleges violations of certain opacity and particulate matter standards at the Illinois Plants. The NOV does not specify the penalties or other relief that the US EPA seeks for the
alleged violations. Midwest Generation, Commonwealth Edison, the US EPA, and the United States Department of Justice (DOJ) are in talks designed to explore the possibility of a settlement. If the
settlement talks fail and the DOJ files suit, litigation could take many years to resolve the issues alleged in the NOV. As a result, Midwest Generation is investigating the claims made by the US EPA
in the NOV and has identified several defenses which it will raise if the government files suit. Midwest Generation cannot predict the outcome of this matter or estimate the impact on its facilities,
its results of operations, financial position or cash flows.

On
August 13, 2007, Midwest Generation and Commonwealth Edison received a letter signed by several Chicago-based environmental action groups stating that, in light of the NOV, the
groups are examining the possibility of filing a citizen suit against Midwest Generation and Commonwealth Edison based presumably on the same or similar theories advanced by the US EPA in the NOV.

By
letter dated August 8, 2007, Commonwealth Edison advised EME that Commonwealth Edison believes it is entitled to indemnification for all liabilities, costs, and expenses that
it may be required to bear as a result of the NOV. By letter dated August 16, 2007, Commonwealth Edison tendered a request for indemnification to EME for all liabilities, costs, and expenses
that Commonwealth Edison may be required to bear if the environmental groups were to file suit. Midwest Generation and Commonwealth Edison are cooperating with one another in responding to the NOV.

EME Homer City New Source Review Notice of Violation

On June 12, 2008, EME Homer City received an NOV from the US EPA alleging that, beginning in 1988, EME Homer City (or former
owners of the Homer City facilities) performed repair or replacement projects at Homer City Units 1 and 2 without first obtaining construction permits as required by the Prevention of Significant
Deterioration requirements of the Clean Air Act. The US EPA also alleges that EME Homer City has failed to file timely and complete Title V permits. EME Homer City intends to meet with the US EPA to
discuss the alleged violations. EME Homer City is investigating the claims made by the US EPA in the NOV and potential responses and cannot predict at this time what effect this matter may have on its
facilities, its results of operations, financial position or cash flows. EME Homer City has sought indemnification for liability and defense costs associated with the NOV from the sellers under the
asset purchase agreement pursuant to which EME Homer City acquired the Homer City facilities. The sellers responded by denying the indemnity obligation, but accepting the defense of the claims.

Insurance

At June 30, 2008, Midwest Generation had a $10 million receivable recorded related to insurance claims from unplanned
outages, of which $6 million related to business interruption insurance coverage recorded during the first quarter of 2008 and has been reflected in other income (expense), net in EME's
consolidated statements of income (loss).

17

---



Environmental Matters and Regulations

The construction and operation of power plants are subject to environmental regulation by federal, state and local authorities. EME
believes that it is in substantial compliance with existing environmental regulatory requirements. However, possible future developments, such as the promulgation of more stringent environmental laws
and regulations, future proceedings that may be initiated by environmental and other regulatory authorities, cases in which new theories of liability are recognized, and settlements agreed to by other
companies that establish precedent or expectations for the power industry, could affect the costs and the manner in which EME
and its subsidiaries conduct their businesses and could require substantial additional capital or operational expenditures or the ceasing of operations at certain of their facilities. There is no
assurance that EME's financial position and results of operations would not be materially adversely affected. EME is unable to predict the precise extent to which additional laws and regulations may
affect its future operations and capital expenditure requirements.

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 or operational expenditures. If EME fails to comply with applicable environmental laws, it may be subject to injunctive relief or penalties and fines
imposed by federal and state regulatory authorities.

With
respect to EME's potential liabilities arising under the Comprehensive Environmental Response, Compensation and Liability Act of 1980, also known as CERCLA, or similar laws for the
investigation and remediation of contaminated property, EME accrues a liability to the extent the costs are probable and can be reasonably estimated. Midwest Generation had accrued approximately
$5 million at June 30, 2008 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 investigation and/or remediation 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.

In
July 2008, the District of Columbia Circuit Court of Appeals vacated the US EPA's CAIR and remanded it to the US EPA. EME cannot predict whether the US EPA or any other party will
seek a rehearing or appeal of the decision. The decision raises significant questions as to whether the US EPA will be able to design cap-and-trade programs for NOX
and SO2 that are authorized and consistent with the Clean Air Act provisions that address upwind contributions to downwind states' noncompliance with national ambient air quality standards
for ozone and fine particulate matter. Because the CAIR was vacated, the court's decision means that the existing "SIP Call" ozone season NOX cap-and-trade program,
which was due to be replaced by the CAIR, will continue (assuming the decision is upheld).

EME
is in the process of evaluating the impact of the D.C. Circuit's decision on Midwest Generation and EME Homer City. Because Pennsylvania and Illinois promulgated their regulations in
response to the CAIR, there is substantial uncertainty as to the impact of the decision on these state regulations. This is particularly true of Pennsylvania's regulatory program, which is modeled on
the federal CAIR and is dependent on the interstate emissions trading program established by the CAIR. Illinois also adopted the CAIR emissions trading programs, but in addition requires Midwest
Generation to achieve reductions of NOX and SO2 (and mercury) through environmental control

18

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retrofits
and plant shutdowns pursuant to a Combined Pollutant Standard. However, if the US EPA is required to propose a new regulation to address interstate transport of air pollution, EME cannot be
certain that the emissions reductions currently required by the Combined Pollutant Standard will be sufficient to meet such revised regulations. In addition, the US EPA has allowed states to rely on
compliance with the CAIR to satisfy obligations under other Clean Air Act programs, including regional haze regulations and reasonably available control technology requirements. Depending on what
happens with respect to CAIR, the Illinois Plants and the Homer City facilities may be subject to additional requirements pursuant to these programs. For further discussion, see "Note 12.
Commitments and ContingenciesEnvironmental Matters and RegulationsAir Quality RegulationClean Air Interstate Rule" in EME's financial statements included in its
annual report on Form 10-K for the year ended December 31, 2007.

Based
on the CAIR requirements, Midwest Generation purchased $48 million of annual NOX allowances under the new CAIR annual NOX program which was vacated
by the court ruling discussed above. As a result of this decision, the annual NOX allowances may no longer be required. Midwest Generation is currently evaluating the above decision
including whether the purchased annual NOX allowances are impaired which could result in a charge against income during the third quarter ending September 30, 2008.

Note 9. Supplemental Cash Flows Information

Six Months Ended
June 30,2008

2007(in millions)Cash paidInterest (net of amount capitalized)

$
244

$
127Income taxes


142


152Cash payments under plant operating leases


201


200Details of assets acquiredFair value of assets acquired

$


$
29Liabilities assumed








In connection with certain wind projects acquired during the second quarter of 2008 and the first quarter of 2007, the purchase price included
payments that were due upon the start and/or completion of construction. Accordingly, EME accrued for estimated payments during the first six months of 2008 and 2007 which were due upon commencement
of construction and/or completion of construction scheduled during 2008 through 2009.

19

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

This MD&A contains "forward-looking statements" within the meaning of the Private Securities Litigation Reform
Act of 1995. These statements reflect EME's current expectations and projections about future events based on EME's knowledge of present facts and circumstances and assumptions about future events and
include any statement that does not directly relate to a historical or current fact. Other information distributed by EME that is incorporated in this report, or that refers to or incorporates this
report, may also contain forward-looking statements. In this quarterly report on Form 10-Q, the words "expects," "believes," "anticipates," "estimates," "projects," "intends,"
"plans," "probable," "may," "will," "could," "would," "should," and variations of such words and similar expressions, or discussions of strategy or plans, are intended to identify forward-looking
statements. Such statements necessarily involve risks and uncertainties that could cause actual results to differ materially from those anticipated. Some of the risks, uncertainties and other
important factors that could cause results to differ, or that otherwise could impact EME or its subsidiaries, include but are not limited
to:



20

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Additional information about risks and uncertainties, including more detail about the factors described above, is contained throughout this MD&A and in the "Risk
Factors" section included in Part I, Item 1A of EME's annual report on Form 10-K for the year ended December 31, 2007. Readers are urged to read this entire
quarterly report on Form 10-Q and carefully consider the risks, uncertainties and other factors that affect EME's business. Forward-looking statements speak only as of the date they
are made, and EME is not obligated to publicly update or revise forward-looking statements. Readers should review future reports filed by EME with the Securities and Exchange
Commission.

This MD&A discusses material changes in the results of operations, financial condition and other developments of EME since December 31, 2007, and as
compared to the second quarter of 2007 and six months ended June 30, 2007. This discussion presumes that the reader has read or has access to the MD&A included in Item 7 of EME's annual
report on Form 10-K for the year ended December 31, 2007.

This
MD&A is presented in four sections:

PageManagement's Overview; Critical Accounting Policies

21Results of Operations

25Liquidity and Capital Resources

35Market Risk Exposures

43


MANAGEMENT'S OVERVIEW; CRITICAL ACCOUNTING POLICIES

Management's Overview

Introduction

EME is a holding company which operates primarily through its subsidiaries and affiliates which are engaged in the business of
developing, acquiring, owning or leasing, operating, and selling energy and capacity from independent power production facilities. EME's subsidiaries or affiliates have typically been formed to own
all or an interest in one or more power plants and ancillary facilities, with each plant or group of related plants being individually referred to by EME as a project. As of June 30, 2008,
EME's subsidiaries and affiliates owned or leased interests in 31 operating projects and 8 wind projects under construction.

Industry Developments

Commodity Prices

The 24-hour average market prices for energy at the Northern Illinois Hub and PJM West Hub increased 18% and 23%,
respectively, during the six months ended June 30, 2008, compared to the corresponding period in 2007. In addition, the forward energy market prices for 2009 for these locations increased 21%
and 41%, respectively, at June 30, 2008 from December 31, 2007. At June 30, 2008, EME had entered into hedge contracts that are recorded at fair value in its consolidated
financial statements. Since forward energy prices have increased at June 30, 2008, the hedge contracts are reflected as a liability, with the effective portion of the contracts recorded as a
reduction of shareholder's equity ($379 million after tax). Subsequent to June 30, 2008, forward energy market prices decreased (forward market prices for 2009 at July 29, 2008
decreased 18% and 22%, respectively, for the above locations from June 30, 2008) reflecting the volatile nature of commodity

21

---



prices.
See "Market Risk ExposuresCommodity Price Risk" for further discussion. During the three-month period ended June 30, 2008 of historically high forward energy market prices,
EME increased its hedge position by approximately 11.2 million megawatt hours.

Regulatory Developments

In July 2008, the District of Columbia Circuit Court of Appeals vacated the US EPA's CAIR and remanded it to the US EPA. In addition,
because Pennsylvania and Illinois promulgated their regulations in response to the CAIR, there is substantial uncertainty as to the impact of the Court's decision on these state regulations.
Notwithstanding these developments, the Illinois Plants and Homer City facilities continue to be governed by state rules as well as the existing "SIP Call" ozone season NOX
cap-and-trade program (which was due to be replaced by the CAIR). For further discussion, see "Liquidity and Capital ResourcesEnvironmental Matters and
RegulationsAir Quality RegulationClean Air Interstate Rule."

Based
on the CAIR requirements, Midwest Generation purchased $48 million of annual NOX allowances under the new CAIR annual NOX program which was vacated
by the court ruling discussed above. As a result of this decision, the annual NOX allowances may no longer be required. Midwest Generation is currently evaluating the above decision
including whether the purchased annual NOX allowances are impaired which could result in a charge against income during the third quarter ending September 30, 2008.

Extension of Production Tax Credits

New wind projects currently receive federal subsidies in the form of production tax credits. Production tax credits for a
ten-year period are available for new projects placed in service prior to December 31, 2008. There have been proposals to extend the deadline for production tax credits beyond the
end of 2008, but such proposals have not been enacted. Although EME believes there is significant support for extending production tax credits, congressional action may be delayed until next year, and
there can be no guarantee that it will occur at all. EME supports extension of production tax credits, without an interruption, to encourage construction of renewable energy projects and plans to
monitor legislative developments.

Growth Activities

Renewable Energy

At June 30, 2008, EME had 695 MW of wind projects in service and another 390 MW of wind projects under construction, with
scheduled completion dates during 2008. As of the same date, EME had a development pipeline of potential wind projects with an estimated installed capacity of approximately 5,000 MW. The development
pipeline represents potential projects with respect to which EME either owns the project rights or has exclusive acquisition rights. This development pipeline is supported by turbine purchase
commitments totaling 1,061 MW for new wind projects. The majority of the turbines are scheduled to be delivered before the end of 2010.

Key
activities during the second quarter of 2008 with respect to wind projects were:



22

---





Subsequent
to June 30, 2008, EME commenced construction of the 100 MW High Lonesome wind project located in New Mexico and completed construction and commenced operations of the
61 MW Mountain Wind I wind project located in Wyoming.

In
addition, EME submitted bids in competitive solicitations to supply power from solar projects under development in California and has had a number of its proposals short-listed.
Initial site and equipment selection have been completed along with preliminary economic feasibility studies. Further project development activities are underway to obtain transmission
interconnection, control of sites, and construction costs estimates, as well as the negotiation of power sales agreements with local utilities.

Thermal Energy

During the first quarter of 2008, a subsidiary of EME was awarded through a competitive bidding process a ten-year power
sales contract with SCE for the output of a 479 MW gas-peaking facility located in the City of Industry, California, which is referred to as the Walnut Creek project. The power sales
agreement is subject to approval of the California Public Utilities Commission (CPUC) which SCE requested on April 4, 2008. CPUC approval is expected to be granted by late 2008. As an affiliate
transaction, the contract is also subject to FERC approval, which was requested on May 2, 2008. Deliveries under the power sales agreement are expected to commence in 2013. During the second
quarter of 2008, EME and its subsidiary entered into an agreement to purchase major equipment for the project.

Net Income Summary

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

Three Months Ended
June 30,

Six Months Ended
June 30,2008

2007

2008

2007(in millions)Income (loss) from continuing operations


73


(19
)

223


134Income (loss) from discontinued operations


(1
)

2


(6
)

5Net Income (Loss)

$
72

$
(17
)
$
217

$
139


EME's increase in income from continuing operations during the second quarter and six months ended June 30, 2008 was primarily attributable
to a $98 million, after tax, loss on early extinguishment of debt recorded during the second quarter of 2007. EME's improvement in income (loss) from continuing operations was also due to
higher gross margin at the Illinois Plants from higher generation and higher average realized prices and due to higher energy trading income. These increases were

23

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partially
offset by lower gross margin and higher plant maintenance expense at the Homer City facilities due to higher unplanned outages, lower income from the Big 4 projects and lower interest
income. The year-to-date earnings also reflect the buyout of a coal contract at the Illinois Plants.

See
"Results of Operations" for further discussion of EME's operating results.

Critical Accounting Policies

For a discussion of EME's critical accounting policies, refer to "Item 7. Management's Discussion and Analysis of Financial
Condition and Results of OperationsCritical Accounting Policies" of EME's annual report on Form 10-K for the year ended December 31, 2007.

24

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RESULTS OF OPERATIONS

Introduction

This section discusses operating results for the second quarters of 2008 and 2007 and six months ended June 30, 2008 and 2007,
and is organized under the following headings:

PageResults of Continuing Operations

25Results of Discontinued Operations

34New Accounting Pronouncements

34


Results of Continuing Operations

Overview

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

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

25

---



The
following section provides a summary of the operating results for the second quarters of 2008 and 2007 and six months ended June 30, 2008 and 2007 together with discussions of
the contributions by specific projects and of other significant factors affecting these results.

Three Months Ended
June 30,

Six Months Ended
June 30,2008

2007

2008

2007(in millions)Project Earnings (Losses) Before Income Taxes(1)Consolidated operationsIllinois Plants

$
140

$
88

$
393

$
277Homer City


(12
)

38


43


102Energy Trading(2)


51


36


92


62Sleeping Bear


8





7


Wildorado


4


2


8


2San Juan Mesa


3


1


5


3Iowa Wind projects


5


2


7


4Minnesota Wind projects


1


1


2


2Other


3





2


1Unconsolidated affiliatesBig 4 projects


28


45


36


63Sunrise


6


6


5


4Doga


8


10


8


14Other


4


4


8


9249


233


616


543Corporate interest income


4


18


11


38Corporate interest expense


(90
)

(81
)

(180
)

(136
)Corporate administrative and general


(42
)

(36
)

(82
)

(68
)Loss on early extinguishment of debt





(160
)




(160
)Other income (expense), net


(3
)

(2
)

(6
)

(3
)$
118

$
(28
)
$
359

$
214


---

Three Months Ended
June 30,

Six Months Ended
June 302008

2007

2008

2007(in millions)Project earnings (losses)

$
118

$
(28
)
$
359

$
214Less: Production tax credits


(11
)

(7
)

(20
)

(12
)Income (loss) from continuing operations before income taxes

$
107

$
(35
)
$
339

$
202


26

---



Earnings from Consolidated Operations

Illinois Plants

Three Months Ended
June 30,

Six Months Ended
June 30,2008

2007

2008

2007(in millions)Operating Revenues

$
391

$
334

$
859

$
765Operating ExpensesFuel


106


85


224


194Gain on sale of emission allowances(1)


(1
)




(3
)

(4
)Plant operations


125


127


219


216Plant operating leases


18


18


37


37Depreciation and amortization


27


25


52


50Gain on buyout of contract and (gain) loss on sale of assets





1


(16
)

1Administrative and general


5


6


11


11Total operating expenses


280


262


524


505Operating Income


111


72


335


260Other Income (Expense)Interest income on note receivable from EME


28


28


56


56Interest income (expense) and other


1


(12
)

2


(39
)Total other income (expense)


29


16


58


17Income Before Taxes

$
140

$
88

$
393

$
277StatisticsGeneration (in GWh):Energy only contracts


5,533


4,445


12,071


11,143Load requirements services contracts


1,287


1,681


3,132


3,613Total


6,820


6,126


15,203


14,756Aggregate plant performance:Equivalent availability(2)


72.6%


61.5%


77.5%


74.7%Capacity factor(3)


57.2%


50.0%


63.7%


60.5%Load factor(4)


78.7%


81.3%


82.2%


81.1%Forced outage rate(5)


6.5%


6.0%


9.3%


6.0%Average realized price/MWh:Energy only contracts(6)

$
52.67

$
49.04

$
52.94

$
49.06Load requirements services contracts(7)

$
62.48

$
62.58

$
62.40

$
62.21Capacity revenue only (in millions)

$
20

$
4

$
29

$
6Average fuel costs/MWh

$
15.56

$
13.82

$
14.74

$
13.13


---

27

---





Three Months Ended
June 30

Six Months Ended
June 302008

2007

2008

2007(in millions)Operating revenues

$
391

$
334

$
859

$
765Less (plus):Load requirements services contracts


(81
)

(105
)

(196
)

(224
)Unrealized losses (gains)


3


(4
)

8


18Other revenues


(22
)

(7
)

(32
)

(12
)Realized revenues

$
291

$
218

$
639

$
547Generation (in GWh)


5,533


4,445


12,071


11,143Average realized energy price/MWh

$
52.67

$
49.04

$
52.94

$
49.06


Earnings from the Illinois Plants increased $52 million and $116 million in the second quarter and six months ended June 30,
2008, respectively, compared to the corresponding periods of 2007. The increases in earnings were primarily attributable to higher gross margin, as compared to 2007, and lower interest expense in 2008
due to the repayment of debt in May 2007. The increase in gross margin was due to higher generation and higher average realized energy and capacity prices, partially offset by higher coal and
transportation costs per megawatt hour in 2008 mainly due to cost escalations included in the transportation contracts. Earnings for the six months ended June 30, 2008 were also higher due to a
gain of $15 million recorded during the first quarter of 2008 related to a buyout of a fuel contract (see "Liquidity and Capital ResourcesContractual ObligationsFuel
Supply Contracts" for further discussion), and an estimated insurance recovery of approximately $6 million recorded during the first quarter of 2008 primarily related to the outages at the
Powerton Station described below.

Included
in operating revenues were unrealized gains (losses) of $(3) million and $4 million for the second quarters of 2008 and 2007, respectively, and $(8) million and $(18)
million for the six months ended June 30, 2008 and 2007, respectively. In 2008, unrealized losses were primarily attributable to the ineffective portion of forward and futures contracts which
are derivatives that qualify as cash flow hedges under SFAS No. 133. The ineffective portion of hedge contracts at the Illinois Plants was primarily attributable to changes in the difference
between energy prices at NiHub (the settlement point under forward or futures contracts) and the energy prices at the Illinois Plants busbars (the delivery point where power generated by the Illinois
Plants is delivered into the transmission system)

28

---



resulting
from marginal losses. In 2007, unrealized gains (losses) were primarily due to power contracts that did not qualify for hedge accounting under SFAS No. 133 (sometimes referred to as
economic hedges). These energy contracts were entered into to hedge the price risk related to projected sales of power. At June 30, 2008, unrealized losses of $26 million were recognized
primarily from the ineffective portion of cash flow hedges related to subsequent periods and to a lesser extent from economic hedges. See "Market Risk ExposuresCommodity Price Risk" for
more information regarding forward market prices.

The
earnings of the Illinois Plants included interest income of $28 million for each of the second quarters of 2008 and 2007 and $56 million for each of the six months
ended June 30, 2008 and 2007 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.

Powerton
Station Outage

On
December 18, 2007, Unit 6 at the Powerton Station had a duct failure resulting in a suspension of operations at this unit through February 12,
2008. Scheduled maintenance work for the spring of 2008 was accelerated to minimize the aggregate impact of the outage. The duct failure resulted in claims under Midwest Generation's property and
business interruption insurance policies. At June 30, 2008, Midwest Generation had a $10 million receivable recorded primarily related to these claims.

29

---



Homer City

Three Months Ended
June 30,

Six Months Ended
June 30,2008

2007

2008

2007(in millions)Operating Revenues

$
127

$
176

$
312

$
374Operating ExpensesFuel(1)


52


68


124


140Plant operations


57


41


86


75Plant operating leases


26


26


51


51Depreciation and amortization


4


4


8


7Administrative and general


1


1


2


2Total operating expenses


140


140


271


275Operating Income (Loss)


(13
)

36


41


99Other Income (Expense)Interest and other income


1


2


2


4Interest expense











(1
)Total other income


1


2


2


3Income (Loss) Before Taxes

$
(12
)
$
38

$
43

$
102StatisticsGeneration (in GWh)


2,250


3,160


5,442


6,453Equivalent availability(2)


61.6%


83.5%


74.6%


85.0%Capacity factor(3)


54.6%


76.7%


66.0%


78.7%Load factor(4)


88.7%


91.8%


88.6%


92.6%Forced outage rate(5)


12.1%


1.8%


10.6%


3.9%Average realized energy price/MWh(6)

$
53.81

$
54.32

$
55.06

$
56.13Capacity revenue only (in millions)

$
11

$
7

$
19

$
13Average fuel costs/MWh

$
23.23

$
21.62

$
22.84

$
21.72


---

30

---





Three Months Ended
June 30

Six Months Ended
June 302008

2007

2008

2007(in millions)Operating revenues

$
127

$
176

$
312

$
374Less (plus):Unrealized losses


6


3


7


2Other revenues


(11
)

(8
)

(19
)

(14
)Realized revenues

$
122

$
171

$
300

$
362Generation (in GWh)


2,250


3,160


5,442


6,453Average realized energy price/MWh

$
53.81

$
54.32

$
55.06

$
56.13


Earnings from Homer City decreased $50 million and $59 million for the second quarter and six months ended June 30, 2008,
respectively, compared to the corresponding periods of 2007. The decreases in earnings were primarily attributable to lower operating revenues primarily from lower generation and lower average
realized energy prices, and higher plant maintenance expenses. Higher forced outages, lower off-peak dispatch and extended planned overhauls in 2008 contributed to lower generation and
higher maintenance expenses. The average realized energy prices for the second quarter and six months ended June 30, 2008 were below the 24-hour PJM West Hub average market prices
primarily due to effective hedge prices being below current market prices and the impact of higher basis (increase in energy prices at PJM West Hub greater than increase in prices at the Homer City
busbar). For further discussion, see "Market Risk ExposuresCommodity Price RiskEnergy Price Risk Affecting Sales from the Homer City Facilities."

Included
in operating revenues were unrealized losses from hedging activities of $6 million and $3 million for the second quarters of 2008 and 2007, respectively, and
$7 million and $2 million for six months ended June 30, 2008 and 2007, respectively. Unrealized losses were primarily attributable to the ineffective portion of forward and
futures contracts which are derivatives that qualify as cash flow hedges under SFAS No. 133. The ineffective portion of hedge contracts at Homer City was primarily attributable to changes in
the difference between energy prices at PJM West Hub (the settlement point under forward contracts) and the energy prices at the Homer City busbar (the delivery point where power generated by the
Homer City facilities is delivered into the transmission system). At June 30, 2008, unrealized losses of $28 million were recognized primarily from the ineffective portion of cash flow
hedges related to subsequent periods. See "Market Risk ExposuresCommodity Price Risk" for more information regarding forward market prices.

Seasonal Disclosure

Due to higher electric demand resulting from warmer weather during the summer months and cold weather during the winter months,
electric revenues from the Illinois Plants and the Homer City facilities vary substantially on a seasonal basis. In addition, maintenance outages generally are scheduled during periods of lower
projected electric demand (spring and fall) further reducing generation and increasing major maintenance costs which are recorded as an expense when incurred. Accordingly, earnings from the Illinois
Plants and the Homer City facilities are seasonal and have significant variability from quarter to quarter. Seasonal fluctuations may also be affected by changes in market prices. See "Market Risk
ExposuresCommodity Price RiskEnergy Price Risk Affecting Sales from the Illinois Plants" and
"Energy Price Risk Affecting Sales from the Homer City Facilities" for further discussion regarding market prices.

31

---



Energy Trading

EME seeks to generate profit by utilizing its subsidiary, EMMT, to engage in trading activities in those markets in which it is active
as a result of its management of the merchant power plants of Midwest Generation and Homer City. EMMT trades power, fuel, and transmission congestion primarily in the eastern power grid using products
available over the counter, through exchanges, and from independent system operators. Earnings from energy trading activities increased $15 million and $30 million for the second quarter
and six months ended June 30, 2008, respectively, compared to the corresponding periods of 2007. The 2008 increases in earnings from energy trading activities resulted from increased congestion
and market volatility in key markets.

In
April 2008, EMMT entered into three load services requirements contracts in Maryland with local utilities. Under the terms of the load services requirements contracts, EMMT is
obligated to supply a portion of each utility's load at fixed prices that vary based on periods specified in the contracts. EMMT is obligated to pay for the cost of supply at each utility's load zones
including, energy, capacity, ancillary services and renewable energy credits. The estimated load for the period October 1, 2008 through September 30, 2010 is approximately
4 million megawatt hours. EMMT has entered into futures contracts to substantially hedge the energy price risk related to these contracts. The above contracts are recorded as derivatives with
the change in fair value reflected in trading income above.

Sleeping Bear

Earnings from the Sleeping Bear wind project were $8 million and $7 million for the second quarter and six months ended
June 30, 2008, respectively. EME had no comparable results from the Sleeping Bear wind project in 2007. Commercial operation of the Sleeping Bear wind project commenced during October 2007. In
addition, the Sleeping Bear wind project recorded cumulative availability warranty income related to the Suzlon wind turbines at its site during the second quarter of 2008. See "Liquidity and Capital
ResourcesContractual Obligations and ContingenciesTurbine Commitments" for further discussion.

Wildorado

Earnings from the Wildorado wind project increased $2 million and $6 million for the second quarter and six months ended
June 30, 2008, respectively, compared to the corresponding periods of 2007. Commercial operation of the Wildorado wind project commenced during April 2007.

San Juan Mesa

Earnings from the San Juan Mesa wind project increased $2 million for both the second quarter and six months ended
June 30, 2008, compared to the corresponding periods in 2007. The increases in earnings were primarily due to higher capacity factors in 2008 as compared to 2007.

Iowa Wind

Earnings from the Iowa wind projects (consisting of the Storm Lake wind project, Crosswinds wind project and Hardin wind project)
increased $3 million for both the second quarter and six months ended June 30, 2008, compared to the corresponding periods in 2007. The increases in earnings were primarily due to
cumulative availability warranty income recorded during the second quarter of 2008, related to the Suzlon wind turbines at the Crosswinds and Hardin wind project sites. The Hardin and the Crosswinds
wind projects achieved commercial operation in May 2007 and June 2007, respectively.

32

---



Earnings from Unconsolidated Affiliates

Big 4 Projects

Earnings from the Big 4 projects decreased $17 million and $27 million for the second quarter and six months ended
June 30, 2008, respectively, compared to the corresponding periods of 2007. The decreases in earnings were primarily due to lower earnings from the Sycamore and Watson projects due to lower
pricing. The year-to-date decrease was also due to lower earnings from the Kern River project attributable to a planned outage in the first quarter of 2008. For further
discussion regarding power sales from the Sycamore and Watson projects, refer to "Item 1. BusinessOverview of FacilitiesBig 4 Projects" of EME's annual report on
Form 10-K for the year ended December 31, 2007.

Earnings
from the Watson project are based on revised pricing effective January 1, 2008. Watson Cogeneration and SCE have disputed the commencement date of the prior contract
which in turn affected the expiration date (Watson Cogeneration's position is April 2008 whereby SCE's position is December 2007). Watson is considering filing a claim for recovery of lost profits due
to the early expiration date.

Doga

Earnings from the Doga project decreased $2 million and $6 million for the second quarter and six months ended
June 30, 2008, respectively, compared to the corresponding periods of 2007. The decreases in earnings were attributable to EME accounting for its ownership in the Doga project, effective
March 31, 2007, on the cost method (earnings are recognized when cash is distributed from the project).

Seasonal Disclosure

EME's third quarter equity in income from its energy projects is materially higher than equity in income related to other quarters of
the year due to warmer weather during the summer months and because a number of EME's energy projects located on the West Coast have power sales contracts that provide for higher payments during the
summer months.

Corporate Interest Income

EME corporate interest income decreased $14 million and $27 million for the second quarter and six months ended
June 30, 2008, respectively, compared to the corresponding periods of 2007. The decreases were primarily attributable to lower average short-term investment balances and lower
interest rates in 2008 compared to 2007.

Corporate Interest Expense

Three Months Ended
June 30,

Six Months Ended
June 30,2008

2007

2008

2007(in millions)Interest expense to third parties

$
62

$
53

$
123

$
79Interest expense to Midwest Generation(1)


28


28


57


57Total corporate interest expense

$
90

$
81

$
180

$
136


---

33

---



Interest Expense to Third Parties

EME's interest expense to third parties, before capitalized interest, increased $14 million and $51 million for the
second quarter and six months ended June 30, 2008, respectively, compared to the corresponding periods of 2007. The increases primarily resulted from EME's refinancing activities in May 2007.
Capitalized interest increased $5 million and $7 million for the second quarter and six months ended June 30, 2008, respectively, compared to the corresponding periods of 2007,
due to wind projects under construction.

Corporate Administrative and General Expenses

Administrative and general expenses increased $6 million and $14 million for the second quarter and six months ended
June 30, 2008, respectively, compared to the corresponding periods of 2007. The increases were primarily due to higher labor costs and consulting expenses resulting from EME's growth
activities.

Loss on Early Extinguishment of Debt

Loss on early extinguishment of debt was $160 million for the second quarter of 2007 and six months ended June 30, 2007
related to the early repayment of EME's 7.73% senior notes due June 15, 2009 and Midwest Generation's 8.75% second priority senior secured notes due May 1, 2034.

Income Taxes

EME's income tax provision from continuing operations was $116 million and $68 million for the six months ended
June 30, 2008 and 2007, respectively. Income tax benefits are recognized pursuant to a tax-allocation agreement with Edison International. During the six months ended
June 30, 2008 and 2007, EME recognized $20 million and $12 million, respectively, of production tax credits related to wind projects and $3 million and $7 million,
respectively, related to estimated state income tax benefits allocated from Edison International.

Results of Discontinued Operations

Income (loss) from discontinued operations, net of tax, was $(1) million and $2 million for the second quarters of 2008 and
2007, respectively, and $(6) million and $5 million for the six months ended June 30, 2008, respectively, compared to the corresponding periods of 2007. The losses in 2008 were primarily
due to adjustments for foreign exchange losses and interest expense associated with contract indemnities related to EME's sale of its international projects in December 2004. The income in 2007 was
largely attributable to distributions received from the Lakeland project. For further discussion regarding the Lakeland project, refer to "Item 7. Management's Discussion and Analysis of
Financial Condition and Results of OperationsResults of OperationsResults of Discontinued Operations" of EME's annual report on Form 10-K for the year
ended December 31, 2007.

New Accounting Pronouncements

For a discussion of new accounting pronouncements affecting EME, see "Edison Mission Energy and Subsidiaries Notes to Consolidated
Financial StatementsNote 1. Summary of Significant Accounting PoliciesNew Accounting Pronouncements."

34

---



LIQUIDITY AND CAPITAL RESOURCES

Introduction

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

PageEME's Liquidity

35Capital Expenditures

35EME's Historical Consolidated Cash Flow

36Credit Ratings

37Margin, Collateral Deposits and Other Credit Support for Energy Contracts

38EME's Liquidity as a Holding Company

38Dividend Restrictions in Major Financings

38Contractual Obligations and Contingencies

39Off-Balance Sheet Transactions

41Environmental Matters and Regulations

41


For a complete discussion of these issues, read this quarterly report on Form 10-Q in conjunction with EME's annual report on
Form 10-K for the year ended December 31, 2007.

EME's Liquidity

At June 30, 2008, EME and its subsidiaries had cash and cash equivalents and short-term investments of
$596 million, EME had a total of $521 million of available borrowing capacity under its $600 million corporate credit facility, and Midwest Generation had a total of
$447 million of available borrowing capacity under its $500 million working capital facility. EME's consolidated debt at June 30, 2008 was $3.9 billion. In addition, EME's
subsidiaries had $3.7 billion of long-term lease obligations related to the sale-leaseback transactions that are due over periods ranging up to 27 years.

Capital Expenditures

At June 30, 2008, the estimated capital expenditures through 2010 by EME's subsidiaries related to existing projects, corporate
activities and turbine commitments were as follows:

July through
December 2008

2009

2010(in millions)Illinois PlantsPlant capital expenditures

$
40

$
78

$
27Environmental expenditures


47


61


263Homer City FacilitiesPlant capital expenditures


18


63


26Environmental expenditures


7


9


9New ProjectsProjects under construction


157


4


Turbine commitments


407


557


300Other capital expenditures


37


14


9Total

$
713

$
786

$
634


35

---



Expenditures for Existing Projects

Plant capital expenditures relate to non-environmental projects such as upgrades to boiler and turbine controls, railroad
interconnection, replacement of major boiler components, mill inerting projects and ash site disposal development. Environmental expenditures relate to environmental projects such as mercury emission
monitoring and control and a selenium removal system at the Homer City facilities and various projects at the Illinois Plants to achieve specified emissions reductions such as installation of mercury
controls. EME plans to fund these expenditures with debt financings, cash on hand or cash generated from operations. For further discussion regarding these and possible additional capital
expenditures, including environmental control equipment at the Homer City facilities, refer to "Item 7. Management's Discussion and Analysis of Financial Condition and Results of
OperationsManagement's OverviewSignificant Industry and EME DevelopmentsEnvironmental Regulations Affecting Coal Plants," "Management's
OverviewSignificant Industry and EME DevelopmentsIncrease in Equipment and Construction Costs," "Item 7. Management's Discussion and Analysis of Financial Condition
and Results of OperationsLiquidity and Capital ResourcesEnvironmental Matters and RegulationsAir Quality RegulationClean Air Interstate
RuleIllinois," and "Environmental Matters and
RegulationsAir Quality RegulationMercury Regulation" of EME's annual report on Form 10-K for the year ended December 31, 2007.

Expenditures for New Projects

EME expects to make substantial investments in new projects during the next several years. At June 30, 2008, EME had committed
to purchase turbines (as reflected in the above table of capital expenditures) for wind projects that aggregate 1,061 MW. The turbine commitments generally represent approximately
two-thirds of the total capital costs of EME's wind projects. As of June 30, 2008, EME had a development pipeline of potential wind projects with projected installed capacity of
approximately 5,000 MW. The development pipeline represents potential projects with respect to which EME either owns the project rights or has exclusive acquisition rights. Completion of development
of a wind project may take a number of years due to factors that include local permit requirements, willingness of local utilities to purchase renewable power at sufficient prices to earn an
appropriate rate of return, and availability and prices of equipment. Furthermore, successful completion of a wind project is dependent upon obtaining permits, an interconnection agreement(s) or other
agreements necessary to support an investment. There is no assurance that each project included in the development pipeline currently or added in the future will be successfully completed.

In
addition, a subsidiary of EME was awarded through a competitive bidding process a ten-year power sales contract with SCE for the output of the Walnut Creek project. During
the second quarter of 2008, EME and its subsidiary entered into an agreement to purchase major equipment for the project included in turbine commitments in the above table. Subject to obtaining
approval for the power sales contract, EME intends to construct the project with total installed costs, excluding interest during construction, estimated in the range of $500 million to
$600 million.

In
July 2008, the Los Angeles Superior Court found that actions taken by the South Coast Air Quality Management District, in promulgating rules that had made available a "Priority
Reserve" of emissions credits for new power generation projects did not satisfy California environmental laws. EME is in the process of evaluating the potential impact of the decision on its Walnut
Creek project.

EME's Historical Consolidated Cash Flow

Consolidated Cash Flows from Operating Activities

Cash used in operating activities from continuing operations increased $74 million in the first six months of 2008, compared to
the first six months of 2007. The 2008 increase was primarily attributable to an increase in required margin and collateral deposits in 2008 for EME's hedging and trading

36

---



activities
due to an increase in forward market prices. The increase was also due to the purchase of additional NOX emission allowances in 2008 by Midwest Generation.

Consolidated Cash Flows from Financing Activities

Cash provided by financing activities from continuing operations increased $358 million in the first six months of 2008,
compared to the first six months of 2007. The 2008 increase was primarily attributable to tender premiums and related fees of $137 million paid in 2007 associated with the 2007 financing. In
May 2007, net proceeds of $2.7 billion were received from EME's issuance of senior notes, which were mostly used to repay $587 million of EME's outstanding senior notes,
$999.8 million of Midwest Generation's second priority senior secured notes, $327.8 million of Midwest Generation's senior secured term loan facility. In addition, $925 million in
dividend payments were made to MEHC in 2007.

Consolidated Cash Flows from Investing Activities

Cash used in investing activities from continuing operations increased $110 million in the first six months of 2008, compared to
the first six months of 2007. The 2008 increase was primarily due to lower net maturities and sales of marketable securities in 2008, compared to 2007. Partially offsetting this increase were proceeds
from the sale of 33% of EME's membership interest in the Elkhorn Ridge wind project during the second quarter of 2008 and lower capital expenditures in 2008, compared to 2007.

Credit Ratings

Overview

Credit ratings for EME, Midwest Generation and EMMT, at June 30, 2008, were as follows:

Moody's Rating

S&P Rating

Fitch RatingEME

B1

BB-

BB-Midwest Generation

Baa3

BB+

BBB-EMMT

Not Rated

BB-

Not Rated


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

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

Credit Rating of EMMT

The Homer City sale-leaseback documents restrict EME Homer City's ability to enter into trading activities, as defined in
the documents, with EMMT to sell forward the output of the Homer City facilities if EMMT does not have an investment grade credit rating from S&P or Moody's or, in the absence of those ratings, if it
is not rated as investment grade pursuant to EME's internal credit scoring procedures. These documents include a requirement that the counterparty to such transactions, and EME Homer City, if acting
as seller to an unaffiliated third party, be investment grade. EME currently sells all the output from the Homer City facilities through EMMT, which has a below investment grade credit rating, and EME
Homer City is not rated. Therefore, in order for EME to continue to sell forward the output of the Homer City facilities, either: (1) EME must obtain consent from the sale-leaseback
owner participant to permit EME Homer City to sell directly into the market or through

37

---



EMMT;
or (2) EMMT must provide assurances of performance consistent with the requirements of the sale-leaseback documents. EME has obtained a consent from the
sale-leaseback owner participants that will allow EME Homer City to enter into such sales, under specified conditions, through December 31, 2008. EME Homer City continues to be in
compliance with the terms of the consent. EME is permitted to sell the output of the Homer City facilities into the spot market at any time. See "Market Risk ExposuresCommodity Price
RiskEnergy Price Risk Affecting Sales from the Homer City Facilities."

Margin, Collateral Deposits and Other Credit Support for Energy Contracts

In connection with entering into contracts in support of EME's hedging and energy trading activities (including forward contracts,
transmission contracts and futures contracts), EME's subsidiary, EMMT, has entered into agreements to mitigate the risk of nonperformance. EME has entered into guarantees in support of EMMT's hedging
and trading activities; however, because the credit ratings of EMMT and EME are below investment grade, EME has historically also provided collateral in the form of cash and letters of credit for the
benefit of counterparties related to accounts payable and unrealized losses in connection with these hedging and trading activities. At June 30, 2008, EMMT had deposited $51 million in
cash with brokers in margin accounts in support of futures contracts and had deposited $126 million with counterparties in support of forward energy and transmission contracts. In addition, EME
had issued letters of credit of $1 million in support of commodity contracts at June 30, 2008.

Future
cash collateral requirements may be higher than the margin and collateral requirements at June 30, 2008, if wholesale energy prices increase or the amount hedged increases.
EME estimates that margin and collateral requirements for energy contracts outstanding as of June 30, 2008 could increase by approximately $360 million over the remaining life of the
contracts using a 95% confidence level.

Midwest
Generation has cash on hand and a $500 million working capital facility to support margin requirements specifically related to contracts entered into by EMMT related to
the Illinois Plants. At June 30, 2008, Midwest Generation had available $447 million of borrowing capacity under this credit facility. As of June 30, 2008, Midwest Generation had
$151 million in loans receivable from EMMT for margin advances. In addition, EME has cash on hand and $521 million of borrowing capacity available under a $600 million working
capital facility to provide credit support to subsidiaries. See "EME's Liquidity as a Holding Company" for further discussion.

EME's Liquidity as a Holding Company

Overview

At June 30, 2008, EME had corporate cash and cash equivalents and short-term investments of $441 million to
meet liquidity needs. See "EME's Liquidity." Cash distributions from EME's subsidiaries and partnership investments and unused capacity under its corporate credit facility represent EME's
major sources of liquidity to meet its cash requirements. The timing and amount of distributions from EME's subsidiaries may be affected by many factors beyond its control. See "Dividend
Restrictions in Major Financings."

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

38

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arrangements
of the parties, be advanced, loaned, paid as dividends or otherwise distributed or contributed to EME or to its subsidiary holding companies.

Key Ratios of EME's Principal Subsidiaries Affecting Dividends

Set forth below are key ratios of EME's principal subsidiaries required by financing arrangements at June 30, 2008 or for the
12 months ended June 30, 2008:

Subsidiary

Financial Ratio

Covenant

ActualMidwest Generation (Illinois Plants)

Debt to Capitalization Ratio

Less than or equal to 0.60 to 1


0.23 to 1EME Homer City (Homer City facilities)

Senior Rent Service Coverage Ratio

Greater than 1.7 to 1


3.01 to 1


For a more detailed description of the covenants binding EME's principal subsidiaries that may restrict the ability of those entities to make
distributions to EME directly or indirectly through the other holding companies owned by EME, refer to "Item 7. Management's Discussion and Analysis of Financial Condition and Results of
OperationsLiquidity and Capital ResourcesDividend Restrictions in Major Financings" of EME's annual report on Form 10-K for the year ended
December 31, 2007.

Contractual Obligations and Contingencies

Capital Improvements

At June 30, 2008, EME's subsidiaries had firm commitments to spend approximately $259 million during the remainder of
2008 on capital and construction expenditures. The majority of these expenditures relate to the construction of wind projects. These expenditures are planned to be financed by cash on hand, cash
generated from operations or existing subsidiary credit agreements.

Turbine Commitments

EME had entered into various turbine supply agreements with vendors to support its wind and thermal development efforts. At
June 30, 2008, EME had secured 533 wind turbines (1,061 MW) and 5 gas-fired turbines (479 MW) for use in future projects for an aggregate purchase price of $1.6 billion, with
remaining commitments of $407 million in 2008, $557 million in 2009 and $300 million in 2010.

EME
and General Electric Company entered into an agreement during the second quarter of 2008 with respect to the purchase of 200 wind turbines (totaling 300 MW) together with related
services and warranties. The wind turbines are to be delivered in 2010. The agreement contains certain delivery schedules and performance guarantees, along with provisions for liquidated damages if
those guarantees are not met by General Electric. EME may terminate the purchase of individual turbines, or groups of turbines, for convenience; upon such termination, EME would be obligated to pay
agreed termination charges to General Electric.

Included
as part of the wind projects or turbine purchase commitments described above, EME had purchased 325 turbines from Suzlon Wind Energy Corporation (Suzlon), of which 180 are in
service or at project sites under construction, and 71 turbines from Clipper Turbine Works, Inc. (Clipper). Rotor blade cracks were identified on certain Suzlon wind turbines, and rotor blade
and gearbox problems were identified on certain Clipper wind turbines. Clipper, at its cost, has commenced its remediation plans that are designed to correct the current deficiencies. EME is
continuing to work with Suzlon to analyze the root causes of the performance issues and address commercial matters that result from the impact of these issues on EME and its projects. During the
second quarter of 2008, EME signed an agreement with Suzlon supplementing certain of EME's wind turbine agreements with Suzlon, including

39

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providing
EME with enhanced warranty and credit protections with respect to the rotor blade crack issues. Under this agreement, EME obtained the right to elect not to purchase some or all of the wind
turbines that were to be delivered in 2009 without payment of cancellation fees. On May 30, 2008, EME notified Suzlon of its election not to purchase 150 turbines (315 MW) due to the time
needed to complete the root cause analysis. For further discussion, refer to "Item 7. Management's Discussion and Analysis of Financial Condition and Results of OperationsLiquidity
and Capital ResourcesCapital ExpendituresWind Turbine Performance Issues" of EME's annual report on Form 10-K for the year ended December 31, 2007.

Fuel Supply Contracts

In connection with the acquisition of the Illinois Plants, Midwest Generation had assumed a long-term coal supply contract
and recorded a liability to reflect the fair value of this contract. In March 2008, Midwest Generation entered into an agreement to buyout its coal obligations for the years 2009 through 2012 under
this contract with a one-time payment to be made in January 2009. Midwest Generation recorded a pre-tax gain of $15 million ($9 million, after tax) during the
first quarter of 2008. The remaining payments due under this contract are $18 million.

Other Contractual Obligations

EME's subsidiaries had entered into contractual agreements during the first six months of 2008 to purchase materials for environmental
controls equipment. These commitments are currently estimated to be $188 million, summarized as follows: remainder of 2008$7 million, 2009$29 million,
2010$45 million, 2011$45 million, 2012$43 million, and thereafter$19 million.

Contingencies

RPM Buyers' Complaint

On May 30, 2008, a group of entities referring to themselves as the "RPM Buyers" filed a complaint at the FERC asking that PJM's
RPM, as implemented through the transitional base residual auctions establishing capacity payments for the period from June 1, 2008 through May 31, 2011, be found to have produced unjust
and unreasonable capacity prices. The RPM Buyers alleged that the absence of price discipline provided by new capacity resources, together with the ability of existing resources to withhold some
capacity within the RPM rules, produced capacity prices in the transition period that are not comparable to those that would have been produced in a competitive market or determined under
cost-based regulation, and have requested that the FERC order refunds based on that difference.

On
July 10, 2008, EME responded to the RPM Buyers' complaint asking that the same be dismissed based upon various legal precedents. In particular EME argued that the complaint
represents little more than a collateral attack on the FERC's orders approving the RPM settlement and rules and that all of the major factors the RPM Buyers alleged produced unjust and unreasonable
prices in the base residual auctions were previously litigated and adjudicated in the contested proceedings involving the RPM settlement. A number of other parties, including PJM, also responded to
the RPM Buyers' complaint asking that the same be dismissed. This matter is currently pending before the FERC. EME cannot predict the outcome of this matter.

EME Homer City New Source Review Notice of Violation

On June 12, 2008, EME Homer City received an NOV from the US EPA alleging that, beginning in 1988, EME Homer City (or former
owners of the Homer City facilities) performed repair or replacement projects at Homer City Units 1 and 2 without first obtaining construction permits as required by the Prevention of Significant
Deterioration requirements of the Clean Air Act. The US

40

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EPA
also alleges that EME Homer City has failed to file timely and complete Title V permits. EME Homer City intends to meet with the US EPA to discuss the alleged violations. EME Homer City is
investigating the claims made by the US EPA in the NOV and potential responses and cannot predict at this time what effect this matter may have on its facilities, its results of operations, financial
position or cash flows. EME Homer City has sought indemnification for liability and defense costs associated with the NOV from the sellers under the asset purchase agreement pursuant to which EME
Homer City acquired the Homer City facilities. The sellers responded by denying the indemnity obligation, but accepting the defense of the claims.

Off-Balance Sheet Transactions

For a discussion of EME's off-balance sheet transactions, refer to "Item 7. Management's Discussion and Analysis of
Financial Condition and Results of OperationsLiquidity and Capital ResourcesOff-Balance Sheet Transactions" of EME's annual report on Form 10-K
for the year ended December 31, 2007. There have been no significant developments with respect to EME's off-balance sheet transactions that affect disclosures presented in EME's
annual report.

Environmental Matters and Regulations

For a discussion of EME's environmental matters, refer to "Item 7. Management's Discussion and Analysis of Financial Condition
and Results of OperationsLiquidity and Capital ResourcesEnvironmental Matters and Regulations" of EME's annual report on Form 10-K for the year ended
December 31, 2007 and the notes to the consolidated financial statements set forth therein. There have been no
significant developments with respect to environmental matters specifically affecting EME since the filing of EME's annual report, except as follows:

Air Quality Regulation

On July 1, 2008, EME began operating activated carbon injection technology to reduce mercury emissions at the Fisk, Crawford,
and Waukegan stations. EME anticipates that the same technology will be implemented at the rest of the Illinois Plants in the third quarter of 2009 and at the Homer City facilities in 2010.

Ambient Air Quality Standards

On March 12, 2008, the US EPA signed a final rule that implements revisions to the primary and secondary national ambient air
quality standards for ozone, originally proposed on July 11, 2007. With regard to the primary standard for ozone, the US EPA has reduced the 8-hour standard to 0.075 parts per
million (ppm) from the current standard of 0.84 ppm. The rule became effective on May 27, 2008. Attainment dates for the new standards range between 2013 and 2030, depending on the severity of
the non-attainment. Based on 2005-2007 data, Chicago is likely to be in non-attainment with the new standard. Available data indicates that the area in which the
Homer City facilities are located is likely to be in attainment. EME intends to consider the new standards as part of its overall plan for environmental compliance.

Clean Air Interstate Rule

In July 2008, the District of Columbia Circuit Court of Appeals vacated the US EPA's CAIR and remanded it to the US EPA. EME cannot
predict whether the US EPA or any other party will seek a rehearing or appeal of the decision. The decision raises significant questions as to whether the US EPA will be able to design
cap-and-trade programs for NOX and SO2 that are authorized and consistent with the Clean Air Act provisions that address upwind contributions to downwind states'
noncompliance with national ambient air quality standards for ozone and fine particulate matter. Because the CAIR

41

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was
vacated, the court's decision means that the existing "SIP Call" ozone season NOX cap-and-trade program, which was due to be replaced by the CAIR, will continue
(assuming the decision is upheld).

EME
is in the process of evaluating the impact of the D.C. Circuit's decision on Midwest Generation and EME Homer City. Because Pennsylvania and Illinois promulgated their regulations in
response to the CAIR, there is substantial uncertainty as to the impact of the decision on these state regulations. This is particularly true of Pennsylvania's regulatory program, which is modeled on
the federal CAIR and is dependent on the interstate emissions trading program established by the CAIR. Illinois also adopted the CAIR emissions trading programs, but in addition requires Midwest
Generation to achieve reductions of NOX and SO2 (and mercury) through environmental control retrofits and plant shutdowns pursuant to a Combined Pollutant Standard. However, if
the US EPA is required to propose a new regulation to address interstate transport of air pollution, EME cannot be certain that the emissions reductions currently required by the Combined Pollutant
Standard will be sufficient to meet such revised regulations. In addition, the US EPA has allowed states to rely on compliance with the CAIR to satisfy obligations under other Clean Air Act programs,
including regional haze regulations and reasonably available control technology requirements. Depending on what happens with respect to CAIR, the Illinois Plants and the Homer City facilities may be
subject to additional requirements pursuant to these programs.

Based
on the CAIR requirements, Midwest Generation purchased $48 million of annual NOX allowances under the new CAIR annual NOX program which was vacated
by the court ruling discussed above. As a result of this decision, the annual NOX allowances may no longer be required. Midwest Generation is currently evaluating the above decision
including whether the purchased annual NOX allowances are impaired which could result in a charge against income during the third quarter ending September 30, 2008.

Climate Change

Litigation Developments

On February 28, 2008, the Native Village of Kivalina and the City of Kivalina, located off the coast of Alaska, filed a
complaint in federal court in California against 24 defendants, including Edison International, who directly or through subsidiaries engage in electric generating, oil and gas, or coal mining lines of
business. Although EME is not named as a defendant, the complaint identifies EME as a direct or indirect operating subsidiary of Edison International through which Edison International engages in
electric power generation. The complaint contends that the alleged global warming impacts of the GHG emissions associated with the defendants' business activities are destroying the plaintiffs'
village through the melting of Arctic ice that had previously protected the village from winter storms. The plaintiffs further allege that the village will soon need to be abandoned or relocated at a
cost of between $95 million and $400 million. EME cannot predict the outcome of this lawsuit.

42

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MARKET RISK EXPOSURES

Introduction

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

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

PageCommodity Price Risk

43Accounting for Energy Contracts

51Fair Value of Financial Instruments

52Credit Risk

53Interest Rate Risk

55Regulatory Matters

55


For
a complete discussion of these issues, read this quarterly report on Form 10-Q in conjunction with EME's annual report on Form 10-K for the year
ended December 31, 2007.

Commodity Price Risk

Introduction

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

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

EME
uses "earnings at risk" to identify, measure, monitor and control its overall market risk exposure with respect to hedge positions at the Illinois Plants, the Homer City facilities,
and the merchant wind projects, and "value at risk" to identify, measure, monitor and control its overall risk exposure in respect of its trading positions. The use of these measures 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, and earnings at risk measures the potential change in value of an asset or
position, in each case over a given time interval, under normal market conditions, at a given confidence level. Given the inherent limitations of these measures and reliance on a single type of risk
measurement tool, EME supplements these approaches with the use of stress testing and worst-case scenario analysis for key risk factors, as well as stop-loss limits and
counterparty credit exposure limits.

Hedging Strategy

To reduce its exposure to market risk, EME hedges a portion of its electricity sales through EMMT, an EME subsidiary engaged in the
power marketing and trading business. To the extent that

43

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EME
does not hedge its electricity sales, the unhedged portion will be subject to the risks and benefits of spot market price movements. Hedge transactions are primarily implemented
through:



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

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

Energy Price Risk Affecting Sales from the Illinois Plants

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

Midwest
Generation sells its power into PJM at spot prices based upon locational marginal pricing. Hedging transactions related to the generation of the Illinois Plants are generally
entered into at the Northern Illinois Hub or the AEP/Dayton Hub, both in PJM, or may be entered into at other trading hubs, including the Cinergy Hub in the Midwest Independent Transmission System
Operator (MISO). These trading hubs have been the most liquid locations for hedging purposes. See "Basis Risk" below for further discussion.

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

44

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The
following table depicts the average historical market prices for energy per megawatt-hour during the first six months of 2008 and 2007.

24-Hour
Northern Illinois Hub
Historical Energy Prices(1)2008

2007January

$
47.09

$
35.75February


54.46


56.64March


58.58


42.04April


53.87


48.91May


44.49


44.49June


56.06


39.76Six-Month Average

$
52.42

$
44.60


---

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

The
following table sets forth the forward market prices for energy per megawatt-hour as quoted for sales into the Northern Illinois Hub at June 30, 2008:

24-Hour
Northern Illinois Hub
Forward Energy Prices(1)2008July

$
81.00August


77.04September


62.27October


59.88November


56.23December


64.392009 Calendar "strip"(2)

$
62.17


---

45

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The following table summarizes Midwest Generation's hedge position at June 30, 2008:

2008

2009

2010

2011GWh

Average
price/
MWh

GWh

Average
price/
MWh

GWh

Average
price/
MWh

GWh

Average
price/
MWhEnergy Only Contracts(1)Northern Illinois HubAEP/Dayton Hub


5,427

$
61.30


11,378

$
66.53


7,961

$
67.39


203

$
76.20Load Requirements Services Contracts(2)(3)Northern Illinois Hub


2,220


64.37


1,571


63.65











Total estimated GWh


7,647





12,949





7,961





203


---

Energy Price Risk Affecting Sales from the Homer City Facilities

All the energy and capacity from the Homer City facilities is sold under terms, including price and quantity, arranged by EMMT with
customers through a combination of bilateral agreements (resulting from negotiations or from auctions), forward energy sales and spot market sales. Electric power generated at the Homer City
facilities is generally sold into the PJM market. PJM has a short-term market, which establishes an hourly clearing price. The
Homer City facilities are situated in the PJM control area and are physically connected to high-voltage transmission lines serving both the PJM and NYISO markets.

The
following table depicts the average historical market prices for energy per megawatt-hour at the Homer City busbar and in PJM West Hub (EME Homer City's primary trading
hub) during the first six months of 2008 and 2007:

Historical Energy Prices(1)
24-Hour PJMHomer City

West Hub2008

2007

2008

2007January

$
54.32

$
40.30

$
66.80

$
44.63February


61.74


64.27


68.29


73.93March


65.37


55.00


70.48


61.02April


61.99


52.42


69.12


58.74May


49.37


48.12


59.84


53.89June


78.72


45.88


98.50


60.19Six-Month Average

$
61.92

$
51.00

$
72.17

$
58.73


---

46

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

The
following table sets forth the forward market prices for energy per megawatt-hour as quoted for sales into the PJM West Hub at June 30, 2008:

24-Hour
PJM West Hub
Forward Energy Prices(1)2008July

$
113.97August


115.98September


93.37October


90.30November


82.49December


95.452009 Calendar "strip"(2)

$
94.90


---

The following table summarizes EME Homer City's hedge position at June 30, 2008:

2008

2009

2010GWh


3,636


4,096


2,654Average price/MWh(1)

$
60.84

$
82.84

$
90.52


---

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

Capacity Price Risk

On June 1, 2007, PJM implemented the RPM for capacity. The purpose of the RPM is to provide a long-term pricing
signal for capacity resources. The RPM provides a mechanism for PJM to satisfy the region's need for generation capacity, the cost of which is allocated to load-serving entities through a
locational reliability charge.

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The
following table summarizes the status of capacity sales for Midwest Generation and EME Homer City at June 30, 2008:

Fixed Price Capacity SalesThrough RPM
Auction, Net

Non-unit Specific
Capacity Sales

Variable Capacity SalesMW

Price per
MW-day

MW

Price per
MW-day

MW

Price per
MW-dayJuly 1, 2008 to May 31, 2009Midwest Generation


2,978

$
122.36
(1)

880

$
64.35





EME Homer City


820


111.92








905

$
65.76
(2)June 1, 2009 to May 31, 2010Midwest Generation


4,614


102.04


715


71.46





EME Homer City


1,670


191.32











June 1, 2010 to May 31, 2011Midwest Generation


4,929


174.29











EME Homer City


1,813


174.29











June 1, 2011 to May 31, 2012Midwest Generation


4,582


110.00











EME Homer City


1,771


110.00














---

Revenues from the sale of capacity from Midwest Generation and EME Homer City beyond the periods set forth above will depend upon the amount of
capacity available and future market prices either in PJM or nearby markets if EME has an opportunity to capture a higher value associated with those markets. Under PJM's RPM system, the market price
for capacity is generally determined by aggregate market-based supply conditions and an administratively set aggregate demand curve. Among the factors influencing the supply of capacity in any
particular market are plant forced outage rates, plant closings, plant delistings (due to plants being removed as capacity resources and/or to export capacity to other markets), capacity imports from
other markets, and the CONE.

Midwest
Generation entered into hedge transactions in advance of the RPM auctions with counterparties that are settled through PJM. In addition, the load service requirements contracts
entered into by Midwest Generation with Commonwealth Edison include energy, capacity and ancillary services (sometimes referred to as a "bundled product"). Under PJM's business rules, Midwest
Generation sells all of its available capacity (defined as unit capacity less forced outages) into the RPM and is subject to a locational reliability charge for the load under these contracts. This
means that the
locational reliability charge generally offsets the related amounts sold in the RPM, which Midwest Generation presents on a net basis in the table above.

Prior
to the RPM auctions for the relevant delivery periods, EME Homer City sold a portion of its capacity to an unrelated third party for the delivery period of June 1, 2008
through May 31, 2009. EME Homer City is not receiving the RPM auction clearing price for this previously sold capacity. The price EME Homer City is receiving for these capacity sales is a
function of NYISO capacity clearing prices resulting from separate NYISO capacity auctions.

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Basis Risk

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



Under
PJM's market design, locational marginal pricing, which establishes market prices at specific locations throughout PJM by considering factors including generator bids, load
requirements, transmission congestion and losses, can cause the price of a specific delivery point to be higher or lower relative to other locations depending on how the point is affected by
transmission constraints. Effective June 1, 2007, PJM implemented marginal losses which adjust the algorithm that calculates locational marginal prices to include a component for marginal
transmission losses in addition to the component included for congestion. To the extent that, on the settlement date of a hedge contract, spot prices at the relevant busbar are lower than spot prices
at the settlement point, the proceeds actually realized from the related hedge contract are effectively reduced by the difference. This is referred to as "basis risk." During the six months ended
June 30, 2008, transmission congestion in PJM has resulted in prices at the Homer City busbar being lower than those at the PJM West Hub by an average of 14%, compared to 13% during the six
months ended June 30, 2007. The monthly average difference during the 12 months ended June 30, 2008 ranged from 7% to 22%. In contrast to the Homer City facilities, during the
past 12 months, the prices at the Northern Illinois Hub were substantially the same as those at the individual busbars of the Illinois Plants, although the implementation of marginal losses on
June 1, 2007 has lowered energy prices at the Illinois Plants busbars.

By
entering into cash settled futures contracts and forward contracts using the PJM West Hub, the Northern Illinois Hub, and the AEP/Dayton Hub (or other similar trading hubs) as
settlement points, EME is exposed to basis risk as described above. In order to mitigate basis risk, EME may purchase financial transmission rights and basis swaps in PJM for EME Homer City. A
financial transmission right is a financial instrument that entitles the holder to receive the difference of actual spot prices for two delivery points in exchange for a fixed amount. Accordingly,
EME's hedging activities include using financial transmission rights alone or in combination with forward contracts and basis swap contracts to manage basis risk.

Coal and Transportation Price Risk

The Illinois Plants and the Homer City facilities purchase coal primarily obtained from the Southern PRB of Wyoming and from mines
located near the facilities in Pennsylvania, respectively. Coal purchases are made under a variety of supply agreements extending through 2011. The following

49

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table
summarizes the amount of coal under contract at June 30, 2008 for the remainder of 2008 and the following three years.

Amount of Coal Under Contract
in Millions of Tons(1)July through
December 2008

2009

2010

2011Illinois Plants


10.3


11.7


11.7


Homer City facilities(2)


3.2


4.5


0.4


0.1


---

EME is subject to price risk for purchases of coal that are not under contract. Prices of Northern Appalachian coal, which are related to the
price of coal purchased for the Homer City facilities, increased substantially during 2008 from 2007 year-end prices. The price of Northern Appalachian coal (with 13,000 Btu per
pound heat content and <3.0 pounds of SO2 per MMBtu sulfur content) increased to $149 per ton at July 25, 2008 from $55.25 per ton at December 21, 2007, as
reported by the Energy Information Administration. Prices of PRB coal (with 8,800 Btu per pound heat content and 0.8 pounds of SO2 per MMBtu sulfur content) purchased for the Illinois
Plants increased during 2008 from 2007 year-end prices. The price of PRB coal increased to $12.50 per ton at July 25, 2008 from $11.50 per ton at December 21, 2007, as
reported by the Energy Information Administration. The 2008 increase in North Appalachian coal prices were primarily attributable to: 1) increased international and Atlantic basin coal demand,
2) port and rail infrastructure problems and monsoon flooding in Australia, 3) a record cold winter in China, and 4) an energy crisis in South Africa.

EME
has contractual agreements for the transport of coal to its facilities. The primary contract is with Union Pacific Railroad (and various delivering carriers), which extends through
2011. EME is exposed to price risk related to higher transportation rates after the expiration of its existing transportation contracts. Current transportation rates for PRB coal are higher than the
existing rates under contract (transportation costs are more than 50% of the delivered cost of PRB coal to the Illinois Plants).

Emission Allowances Price Risk

The federal Acid Rain Program requires electric generating stations to hold SO2 allowances, and Illinois and Pennsylvania
regulations implemented the federal NOx SIP Call requirement. As part of the acquisition of the Illinois Plants and the Homer City facilities, EME obtained the rights to the emission
allowances that have been or are allocated to these plants. 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.

The
average price of purchased SO2 allowances decreased to $309 per ton during the first six months of 2008 from $512 per ton during 2007. The price of SO2
allowances, determined by obtaining broker quotes and information from other public sources, was $330 per ton as of June 30, 2008. Following the District of Columbia Circuit Court of Appeals'
decision in July 2008, discussed above under "Liquidity and Capital ResourcesEnvironmental Matters and RegulationsAir Quality RegulationClean Air Interstate
Rule," the price of SO2 allowances has further declined.

For
a discussion of environmental regulations related to emissions, refer to "Item 7. Management's Discussion and Analysis of Financial Condition and Results of
OperationsLiquidity and Capital ResourcesEnvironmental Matters and Regulations" of EME's annual report on Form 10-K for the year ended December 31,
2007.

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Accounting for Energy Contracts

EME uses a number of energy contracts to manage exposure from changes in the price of electricity, including forward sales and
purchases of physical power and forward price swaps which settle only on a financial basis (including futures contracts). EME follows SFAS No. 133, and under this Standard these energy
contracts are generally defined as derivative financial instruments. Importantly, SFAS No. 133 requires changes in the fair value of each derivative financial instrument to be recognized in
earnings at the end of each accounting period unless the instrument qualifies for hedge accounting under the terms of SFAS No. 133. For derivatives that do qualify for cash flow hedge
accounting, changes in their fair value are recognized in other comprehensive income until the hedged item settles and is recognized in earnings. However, the ineffective portion of a derivative that
qualifies for cash flow hedge accounting is recognized currently in earnings. For further discussion of derivative financial instruments, refer to "Item 7. Management's Discussion and Analysis
of Financial Condition and Results of OperationsManagement's Overview; Critical Accounting PoliciesCritical Accounting PoliciesDerivative Financial Instruments
and Hedging Activities" of EME's annual report on Form 10-K for the year ended December 31, 2007.

SFAS
No. 133 affects the timing of income recognition, but has no effect on cash flow. To the extent that income varies under SFAS No. 133 from accrual accounting
(i.e., revenue recognition based on settlement of transactions), EME records unrealized gains or losses. EME classifies unrealized gains and losses from energy contracts as part of operating
revenues. The results of derivative activities are recorded as part of cash flows from operating activities in the consolidated statements of cash flows. The following table summarizes unrealized
gains (losses) from non-trading activities for the second quarters of 2008 and 2007 and six months ended June 30, 2008 and 2007:

Three Months Ended
June 30,

Six Months Ended
June 30,2008

2007

2008

2007(in millions)Illinois PlantsNon-qualifying hedges

$
2

$
4

$
2

$
(18
)Ineffective portion of cash flow hedges


(5
)




(10
)

Homer CityNon-qualifying hedges


1


2


2


1Ineffective portion of cash flow hedges


(7
)

(5
)

(9
)

(3
)Total unrealized gains (losses)

$
(9
)
$
1

$
(15
)
$
(20
)


At June 30, 2008, unrealized losses of $54 million were recognized from non-qualifying hedge contracts or the
ineffective portion of cash flow hedges related to subsequent periods ($22 million for the remainder of 2008, $18 million for 2009, and $14 million for 2010).

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Fair Value of Financial Instruments

Non-Trading Derivative Financial Instruments

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

June 30,
2008

December 31,
2007(in millions)Commodity price:Electricity contracts

$
(686
)
$
(137
)


In assessing the fair value of EME's non-trading derivative financial instruments, EME uses quoted market prices and forward market
prices adjusted for credit risk. 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 decrease in fair value of electricity contracts at June 30, 2008 as compared to December 31, 2007 is attributable to an increase in the average market prices for power as compared to
contracted prices at June 30, 2008, which is the valuation date. The following table summarizes the maturities and the related fair value, primarily based on actively traded prices, of EME's
commodity derivative assets and liabilities as of June 30, 2008:

Total Fair
Value

Maturity
<1 year

Maturity
1 to 3
years

Maturity
4 to 5
years

Maturity
>5 years(in millions)Prices actively quoted

$
(683
)
$
(452
)
$
(231
)
$


$
Price based on models and other valuation methods


(3
)

1


(4
)




Total

$
(686
)
$
(451
)
$
(235
)
$


$



Prices actively quoted in the preceding table includes derivatives whose fair value is based on quoted market prices and forward market prices
adjusted for credit risk.

Energy Trading Derivative Financial Instruments

The fair value of the commodity financial instruments related to energy trading activities as of June 30, 2008 and
December 31, 2007, are set forth below:

June 30, 2008

December 31, 2007Assets

Liabilities

Assets

Liabilities(in millions)Electricity contracts

$
231

$
138

$
141

$
9


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The change in the fair value of trading contracts for the six months ended June 30, 2008, was as follows:

(in millions)Fair value of trading contracts at January 1, 2008

$
132Net gains from energy trading activities


95Amount realized from energy trading activities


(121
)Other changes in fair value


(13
)Fair value of trading contracts at June 30, 2008

$
93


EME adopted SFAS No. 157 effective January 1, 2008. The standard established a hierarchy for fair value measurements. See "Edison
Mission Energy and Subsidiaries Notes to Consolidated Financial StatementsNote 2. Fair Value Measurements," for further discussion of EME's adoption of SFAS No. 157.

In
the table below, prices actively quoted includes both exchange traded derivatives and non-exchange traded derivatives which are priced based on forward market prices
adjusted for credit risk. Also in the table, fair value based on models and other valuation methods includes illiquid firm transmission rights and over-the-counter derivatives
at illiquid locations and long-term power agreements which would be considered Level 3 derivative positions. For illiquid firm transmission rights, EME determines fair value based
on the hypothetical sale of illiquid positions. For long-term power agreements, EME's subsidiary recorded these agreements at fair value based upon a discounting of future electricity
prices derived from a proprietary model using the risk free discount rate for a similar duration contract, adjusted for credit and liquidity.

The
following table summarizes the maturities, the valuation method and the related fair value of energy trading assets and liabilities (as of June 30, 2008):

Total Fair
Value

Maturity
<1 year

Maturity
1 to 3
years

Maturity
4 to 5
years

Maturity
>5 years(in millions)Prices actively quoted

$
(31
)
$
(28
)
$
(2
)
$
(1
)
$
Prices based on models and other valuation methods


124


47


21


24


32Total

$
93

$
19

$
19

$
23

$
32


Credit Risk

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

To
manage credit risk, EME looks at the risk of a potential default by counterparties. Credit risk is measured by the loss that would be incurred if counterparties failed to perform
pursuant to the terms of their contractual obligations. EME measures, monitors and mitigates credit risk to the extent possible. To mitigate credit risk from counterparties, master netting agreements
are used whenever possible and counterparties may be required to pledge collateral when deemed necessary. EME also

53

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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.

The
credit risk exposure from counterparties of merchant energy activities (excluding load requirements services contracts) are measured 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 hedging and trading activities which typically provide for
a right of setoff in the event of bankruptcy or default by the counterparty. Accordingly, EME's credit risk exposure from counterparties is based on net exposure under these agreements. At
June 30, 2008, the amount of exposure as described above, broken down by the credit ratings of EME's counterparties, was as follows:

S&P Credit Rating

June 30, 2008(in millions)A or higher

$
14A-


70BBB+


95BBB


18BBB-


38Below investment grade


4Total

$
239


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

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

EME's
merchant plants sell electric power generally into the PJM market by participating in PJM's capacity and energy markets or transact capacity and energy on a bilateral basis. Sales
into PJM accounted for approximately 49% of EME's consolidated operating revenues for the six months ended June 30, 2008. Moody's rates PJM's debt Aa3. PJM, an independent system operator with
over 300 member companies, maintains its own credit risk policies and does not extend unsecured credit to non-investment grade companies. Any losses due to a PJM member default are shared
by all other members based upon a predetermined formula. At June 30, 2008, EME's account receivable due from PJM was $99 million.

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EME
also derived a significant source of its revenues from the sale of energy, capacity and ancillary services generated at the Illinois Plants to Commonwealth Edison under load
requirements services contracts. Sales under these contracts accounted for 15% of EME's consolidated operating revenues during the six months ended June 30, 2008. Commonwealth Edison's senior
unsecured debt ratings are BBB- by S&P and Ba1 by Moody's. At June 30, 2008, EME's account receivable due from Commonwealth Edison was $24 million. For the six months ended
June 30, 2008, a third customer accounted for 11% of EME's consolidated operating revenues.

Interest Rate Risk

Interest rate changes can affect earnings and the cost of capital for capital improvements or new investments in power projects. EME
mitigates the risk of interest rate fluctuations by arranging for fixed rate financing or variable rate financing with interest rate swaps, interest rate options or other hedging mechanisms for a
number of its project financings. The fair market values of long-term fixed interest rate obligations are subject to interest rate risk. The fair market value of EME's consolidated
long-term obligations (including current portion) was $3.7 billion at June 30, 2008, compared to the carrying value of $3.9 billion.

Regulatory Matters

For a discussion of EME's regulatory matters, refer to "Item 1. BusinessRegulatory Matters" of EME's annual report
on Form 10-K for the year ended December 31, 2007. There have been no significant developments with respect to regulatory matters specifically affecting EME since the filing
of EME's annual report on Form 10-K for the year ended December 31, 2007, except as follows:

On
April 4, 2008, the FERC issued an order rejecting PJM's request to revise its RPM to reflect PJM's claimed rise in its CONE values. CONE is one of the two components used by
PJM to determine its Variable Resource Requirement curve for the RPM auction. PJM also proposed to add a new section to its tariff permitting PJM to unilaterally request a CONE increase for use in its
May 2008 RPM auction for the 2011/2012 delivery year. In rejecting the proposal, the FERC found that PJM had not met timing provisions in its existing tariff to provide sufficient time for stakeholder
review of the
analysis and advance planning and that it had also failed to establish that its proposal to revise that provision was necessary on a one-time emergency basis to ensure reliable service.

The
effect of FERC's actions on future RPM auctions cannot be determined at this time. The CONE as established for the May 2008 RPM auction for the 2011/2012 delivery year is lower than
the PJM request.

ITEM 3.    QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

For a discussion of market risk sensitive instruments, refer to "Item 7. Management's Discussion and Analysis of Financial
Condition and Results of OperationsMarket Risk Exposures" of EME's annual report on Form 10-K for the year ended December 31, 2007. Refer to "Market Risk
Exposures" in Item 2 of this quarterly report on Form 10-Q for an update to that disclosure.

55

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ITEM 4T.    CONTROLS AND PROCEDURES

Disclosure Controls and Procedures

EME's management, with the participation of the company's Chief Executive Officer and Chief Financial Officer, has evaluated the
effectiveness of EME's disclosure controls and procedures (as that 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, EME's disclosure controls and procedures are effective.

Internal Control Over Financial Reporting

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

56

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PART IIOTHER INFORMATION

ITEM 1.    LEGAL PROCEEDINGS

For a discussion of EME's legal proceedings, refer to "Item 3. Legal Proceedings" of EME's annual report on
Form 10-K for the year ended December 31, 2007. There have been no significant developments with respect to legal proceedings specifically affecting EME since the filing of
EME's annual report on Form 10-K for the year ended December 31, 2007, except as follows:

FERC Investigatory Proceeding against EMMT

On July 12, 2005, EMMT received a letter from the staff of the FERC Office of Enforcement (FERC Staff) stating that, by the
letter, it was commencing a preliminary, non-public investigation of certain bidding practices of EMMT. In October 2006, EMMT was advised that the FERC Staff was prepared to
recommend that the FERC initiate a formal investigatory proceeding and seek monetary sanctions against EMMT for alleged violation of the Energy Policy Act of 2005 and the FERC's rules regarding market
behavior, all with respect to certain bidding practices previously employed by EMMT. In ensuing exchanges between EMMT and the FERC Staff, EMMT provided information explaining that the business
purpose for its bidding practices was
the sale for risk mitigation purposes of a certain amount of power in the real-time rather than the day-ahead market.

Discussions
with the FERC Staff led to a settlement agreement, which was accepted and adopted by the FERC in an order issued May 19, 2008. In the settlement agreement EMMT,
Midwest Generation, and EME acknowledged that during the course of the investigation, although they had had no intent to mislead the FERC Staff, they had at times failed to provide complete and
accurate information in response to FERC Staff inquiries, as required by FERC's regulation (18 CFR § 35.41(b) (2007)). The settlement agreement required the payment of
$7 million in civil penalties for violation of 18 CFR § 35.41(b) (2007) and development and implementation of a comprehensive regulatory compliance program at an estimated
cost of $2 million. The order and settlement agreement operate to terminate the investigation with no assertion of findings of violation of FERC's rules with respect to the bidding practices
that were the subject of the investigation.

On
June 18 and 19, 2008, various parties, including the Attorney General of the State of Illinois, the Pennsylvania Public Utility Commission, Delaware Public Service Commission,
New Jersey Board of Public Utilities, Indiana Utility Regulatory Commission, the Public Utilities Commission of Ohio, the Virginia State Corporation Commission and the Illinois Commerce Commission,
filed various interventions and protests seeking to intervene in the FERC investigation docket for the purpose of seeking clarification that the order and settlement agreement did not foreclose third
party rights to seek redress against EMMT, Midwest Generation, and EME for any alleged market manipulation as a result of the bidding behavior or, in the alternative, obtaining an order reopening the
investigation docket to allow further investigation into the bidding behavior. On July 3, 2008, EMMT, Midwest Generation, and EME responded to the filings of the various parties by requesting
that the filings should be dismissed based upon the applicable law and case precedent. On July 16, 2008, the FERC issued an order, commonly referred to as a tolling order, that granted
rehearing of the order for the limited purpose of affording additional time for consideration of the matters raised in these filings. Absent the issuance of the tolling order, the timely filed
rehearing requests would be deemed denied by operation of law. In the tolling order, the FERC noted that the pending rehearing requests will be addressed on their merits in a future order.

EME Homer City New Source Review Notice of Violation

On June 12, 2008, EME Homer City received an NOV from the US EPA alleging that, beginning in 1988, EME Homer City (or former
owners of the Homer City facilities) performed repair or replacement projects at Homer City Units 1 and 2 without first obtaining construction permits as

57

---



required
by the Prevention of Significant Deterioration requirements of the Clean Air Act. The US EPA also alleges that EME Homer City has failed to file timely and complete Title V permits.
EME Homer City intends to meet with the US EPA to discuss the alleged violations. EME Homer City is investigating the claims made by the US EPA in the NOV and potential responses and cannot predict at
this time what effect this matter may have on its facilities, its results of operations, financial position or cash flows. EME Homer City has sought indemnification for liability and defense costs
associated with the NOV from the sellers under the asset purchase agreement pursuant to which EME Homer City acquired the Homer City facilities. The sellers responded by denying the indemnity
obligation, but accepting the defense of the claims.

ITEM 1A.    RISK FACTORS

For a discussion of the risks, uncertainties, and other important factors which could materially affect EME's business, financial
condition, or future results, refer to "Item 1A. Risk Factors" of EME's annual report on Form 10-K for the year ended December 31, 2007. The risks described in EME's
annual report on Form 10-K are not the only risks facing EME. Additional risks and uncertainties that are not currently known, or that are currently deemed to be immaterial, also
may materially adversely affect EME's business, financial condition or future results.

ITEM 6.    EXHIBITS

Exhibit No.

Description31.1

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.


58

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SIGNATURES

Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its
behalf by the undersigned thereunto duly authorized.

EDISON MISSION ENERGYBy:

/s/ John P. Finneran, Jr.
John P. Finneran, Jr. Senior Vice President and
Chief Financial OfficerDate:

August 8, 2008


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