EME 2012 Q2
Table of Contents

 

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

FORM 10-Q
(Mark one)
 
x
QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
For the Quarterly Period Ended June 30, 2012
 
or
¨
TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
For the transition period from __________ to __________
Commission File Number 333-68630

_______________________

EDISON MISSION ENERGY
(Exact name of registrant as specified in its charter)
Delaware
(State or other jurisdiction of incorporation
or organization)
95-4031807
(I.R.S. Employer Identification No.)
3 MacArthur Place, Suite 100
Santa Ana, California
(Address of principal executive offices)
92707
(Zip Code)

Registrant's telephone number, including area code: (714) 513-8000
_______________________

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 x NO o
Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files). YES x 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 "large accelerated filer," "accelerated filer" and "smaller reporting company" in Rule 12b-2 of the Exchange Act.
Large accelerated filer o
 
Accelerated filer o
 
Non-accelerated filer x
 
Smaller reporting company o
 
 
 
 
(Do not check if a smaller reporting company)
 
 
Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act). YES o NO x
Number of shares outstanding of the registrant's Common Stock as of July 31, 2012: 100 shares (all shares held by an affiliate of the registrant).
 



Table of Contents

TABLE OF CONTENTS

 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 

i
Table of Contents

 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 

ii
Table of Contents

 
 
 
 
 
 
 

iii
Table of Contents


















(This page has been left blank intentionally.)

iv
Table of Contents

GLOSSARY
When the following terms and abbreviations appear in the text of this report, they have the meanings indicated below.
2010 Tax Relief Act
Tax Relief, Unemployment Insurance Reauthorization and Job Creation Act of 2010
ACI
activated carbon injection
AOI
adjusted operating income (loss)
ARO(s)
asset retirement obligation(s)
BACT
best available control technology
BART
best available retrofit technology
bcf
billion cubic feet
Big 4
Kern River, Midway-Sunset, Sycamore and Watson natural gas power projects
Btu
British thermal units
CAA
Clean Air Act
CAIR
Clean Air Interstate Rule
CAMR
Clean Air Mercury Rule
CARB
California Air Resources Board
CO2
carbon dioxide
coal plants
Midwest Generation coal plants and Homer City electric generating station
Commonwealth Edison
Commonwealth Edison Company
CPS
Combined Pollutant Standard
CPUC
California Public Utilities Commission
CSAPR
Cross-State Air Pollution Rule
EIA
Energy Information Administration
EME
Edison Mission Energy
EMMT
Edison Mission Marketing & Trading, Inc.
ERCOT
Electric Reliability Council of Texas
FASB
Financial Accounting Standards Board
FERC
Federal Energy Regulatory Commission
FGD
flue gas desulfurization
FPA
Federal Power Act
GAAP
United States generally accepted accounting principles
GECC
General Electric Capital Corporation
GHG
greenhouse gas
GWh
gigawatt-hours
Homer City
EME Homer City Generation L.P.
Illinois EPA
Illinois Environmental Protection Agency
ISO(s)
independent system operator(s)
Lehman
Lehman Brothers Commodity Services, Inc. and Lehman Brothers Holdings, Inc.
LIBOR
London Interbank Offered Rate
MATS
Mercury and Air Toxics Standards
Midwest Generation
Midwest Generation, LLC
MISO
Midwest Independent Transmission System Operator
MMBtu
million British thermal units

v
Table of Contents

Moody's
Moody's Investors Service, Inc.
MW
megawatts
MWh
megawatt-hours
NAAQS
National Ambient Air Quality Standard(s)
NAPP
Northern Appalachian
NERC
North American Electric Reliability Corporation
NID
Novel Integrated Desulfurization
NOX
nitrogen oxide
NSR
New Source Review
NYISO
New York Independent System Operator
PADEP
Pennsylvania Department of Environmental Protection
PG&E
Pacific Gas & Electric Company
PJM
PJM Interconnection, LLC
PRB
Powder River Basin
PSD
Prevention of Significant Deterioration
RPM
Reliability Pricing Model
RTO(s)
regional transmission organization(s)
S&P
Standard & Poor's Ratings Services
SCE
Southern California Edison Company
SIP(s)
state implementation plan(s)
SNCR
selective non-catalytic reduction
SO2
sulfur dioxide
US EPA
United States Environmental Protection Agency
U.S. Treasury grants
Cash grants, under the American Recovery and Reinvestment Act of 2009
VIE(s)
variable interest entity(ies)



vi
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PART I - FINANCIAL INFORMATION
ITEM 1. FINANCIAL STATEMENTS

EDISON MISSION ENERGY AND SUBSIDIARIES
 

CONSOLIDATED STATEMENTS OF OPERATIONS
(in millions, unaudited)
 
Three Months Ended
June 30,
 
Six Months Ended
June 30,
 
2012
 
2011
 
2012
 
2011
Operating Revenues
$
406

 
$
536

 
$
849

 
$
1,086

Operating Expenses
 
 
 
 
 
 
 
Fuel
215

 
174

 
421

 
356

Plant operations
172

 
240

 
328

 
432

Plant operating leases
40

 
44

 
78

 
88

Depreciation and amortization
67

 
79

 
135

 
151

Loss on disposal and asset impairments
12

 
8

 
26

 
8

Administrative and general
48

 
45

 
94

 
88

Total operating expenses
554

 
590

 
1,082

 
1,123

Operating loss
(148
)
 
(54
)
 
(233
)
 
(37
)
Other Income (Expense)
 
 
 
 
 
 
 
Equity in income from unconsolidated affiliates
18

 
17

 
17

 
12

Dividend income
11

 
27

 
11

 
28

Interest income
—

 
—

 
—

 
1

Interest expense
(84
)
 
(80
)
 
(170
)
 
(160
)
Other income, net
—

 
2

 
—

 
5

Total other expense
(55
)
 
(34
)
 
(142
)
 
(114
)
Loss from continuing operations before income taxes
(203
)
 
(88
)
 
(375
)
 
(151
)
Benefit for income taxes
(99
)
 
(57
)
 
(190
)
 
(102
)
Loss From Continuing Operations
(104
)
 
(31
)
 
(185
)
 
(49
)
Loss from Operations of Discontinued Subsidiaries, net of tax (Note 13)
—

 
(1
)
 
(1
)
 
(3
)
Net Loss
(104
)
 
(32
)
 
(186
)
 
(52
)
Net Income Attributable to Noncontrolling Interests (Note 3)
(5
)
 
—

 
(7
)
 
—

Net Loss Attributable to Edison Mission Energy Common Shareholder
$
(109
)
 
$
(32
)
 
$
(193
)
 
$
(52
)
Amounts Attributable to Edison Mission Energy Common Shareholder
 
 
 
 
 
 
 
Loss from continuing operations, net of tax
$
(109
)
 
$
(31
)
 
$
(192
)
 
$
(49
)
Loss from discontinued operations, net of tax
—

 
(1
)
 
(1
)
 
(3
)
Net Loss Attributable to Edison Mission Energy Common Shareholder
$
(109
)
 
$
(32
)
 
$
(193
)
 
$
(52
)

The accompanying notes are an integral part of these consolidated financial statements.
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EDISON MISSION ENERGY AND SUBSIDIARIES
 

CONSOLIDATED STATEMENTS OF COMPREHENSIVE LOSS
(in millions, unaudited)

 
Three Months Ended
June 30,
 
Six Months Ended
June 30,
 
2012
 
2011
 
2012
 
2011
Net Loss
$
(104
)
 
$
(32
)
 
$
(186
)
 
$
(52
)
Other comprehensive income (loss), net of tax
 
 
 
 
 
 
 
Pension and postretirement benefits other than pensions
 
 
 
 
 
 
 
Net gain adjustment, net of tax
—

 
—

 
1

 
—

Amortization of net loss and prior service adjustment included in expense, net of tax
—

 
—

 
1

 
1

Unrealized losses on derivatives qualified as cash flow hedges
 
 
 
 
 
 
 
Unrealized holding losses arising during the periods, net of income tax benefit of $19 and $9 for the three months and $2 and $5 for the six months ended June 30, 2012 and 2011, respectively
(28
)
 
(14
)
 
(3
)
 
(8
)
Reclassification adjustments included in net loss, net of income tax benefit of $6 and $6 for the three months and $13 and $12 for the six months ended June 30, 2012 and 2011, respectively
(9
)
 
(7
)
 
(20
)
 
(17
)
Other comprehensive loss, net of tax
(37
)
 
(21
)
 
(21
)
 
(24
)
Comprehensive Loss
(141
)
 
(53
)
 
(207
)
 
(76
)
Comprehensive Income Attributable to Noncontrolling Interests
(5
)
 
—

 
(7
)
 
—

Comprehensive Loss Attributable to Edison Mission Energy Common Shareholder
$
(146
)
 
$
(53
)
 
$
(214
)
 
$
(76
)


The accompanying notes are an integral part of these consolidated financial statements.
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EDISON MISSION ENERGY AND SUBSIDIARIES
 

CONSOLIDATED BALANCE SHEETS
(in millions, unaudited)

 
June 30,
2012
 
December 31,
2011
Assets
 
 
 
Current Assets
 
 
 
Cash and cash equivalents
$
1,009

 
$
1,300

Accounts receivable—trade
107

 
107

Receivables from affiliates
5

 
4

Inventory
232

 
274

Derivative assets
46

 
40

Restricted cash and cash equivalents
110

 
103

Margin and collateral deposits
59

 
41

Prepaid expenses and other
90

 
72

Total current assets
1,658

 
1,941

Investments in Unconsolidated Affiliates
529

 
523

Property, Plant and Equipment, less accumulated depreciation of $1,428 and $1,295 at respective dates
4,463

 
4,472

Other Assets
 
 
 
Deferred financing costs
68

 
71

Long-term derivative assets
52

 
59

Restricted deposits
95

 
48

Rent payments in excess of levelized rent expense under plant operating leases
798

 
760

Deferred taxes
349

 
205

Other long-term assets
242

 
244

Total other assets
1,604

 
1,387

Total Assets
$
8,254

 
$
8,323


EDISON MISSION ENERGY AND SUBSIDIARIES
 

CONSOLIDATED BALANCE SHEETS
(in millions, except share and per share amounts, unaudited)

 
June 30,
2012
 
December 31,
2011
Liabilities and Shareholder's Equity
 
 
 
Current Liabilities
 
 
 
Accounts payable
$
70

 
$
99

Payables to affiliates
91

 
188

Accrued liabilities
133

 
168

Derivative liabilities
—

 
1

Interest payable
30

 
33

Deferred taxes
26

 
2

Current portion of long-term debt
566

 
57

Short-term debt
9

 
—

Total current liabilities
925

 
548

Long-term debt net of current portion
4,430

 
4,855

Deferred revenues
517

 
530

Long-term derivative liabilities
114

 
90

Other long-term liabilities
606

 
636

Total Liabilities
6,592

 
6,659

Commitments and Contingencies (Notes 5, 6, 9 and 10)

 

Equity
 
 
 
Common stock, par value $0.01 per share (10,000 shares authorized; 100 shares issued and outstanding at each date)
64

 
64

Additional paid-in capital
1,309

 
1,327

Retained earnings
160

 
365

Accumulated other comprehensive loss
(115
)
 
(94
)
Total Edison Mission Energy common shareholder's equity
1,418

 
1,662

Noncontrolling Interests
244

 
2

Total Equity
1,662

 
1,664

Total Liabilities and Equity
$
8,254

 
$
8,323




The accompanying notes are an integral part of these consolidated financial statements.
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EDISON MISSION ENERGY AND SUBSIDIARIES
 

CONSOLIDATED STATEMENTS OF CASH FLOWS
(in millions, unaudited)
 
Six Months Ended June 30,
 
2012
 
2011
Cash Flows From Operating Activities
 
 
 
Net loss
$
(186
)
 
$
(52
)
Loss from discontinued operations
1

 
3

Loss from continuing operations, net
(185
)
 
(49
)
Adjustments to reconcile loss to net cash used in operating activities:
 
 
 
Equity in income from unconsolidated affiliates
(17
)
 
(12
)
Distributions from unconsolidated affiliates
6

 
15

Depreciation and amortization
148

 
164

Deferred taxes and tax credits
(112
)
 
(30
)
Loss on disposal and asset impairments
26

 
—

Changes in operating assets and liabilities:
 
 
 
(Increase) decrease in margin and collateral deposits
(18
)
 
9

Increase in receivables
(1
)
 
—

Decrease (increase) in inventory
42

 
(22
)
Increase in prepaid expenses and other
(9
)
 
(12
)
Increase in restricted cash and cash equivalents
(4
)
 
(9
)
Increase in rent payments in excess of levelized rent expense
(38
)
 
(101
)
(Decrease) increase in payables and other current liabilities
(159
)
 
1

Increase in interest payable
3

 
—

Decrease in derivative assets and liabilities
(14
)
 
(23
)
Increase in other operating—assets
9

 
8

Increase in other operating—liabilities
(30
)
 
(31
)
Operating cash flow from continuing operations
(353
)
 
(92
)
Operating cash flow from discontinued operations
(1
)
 
(3
)
Net cash used in operating activities
(354
)
 
(95
)
Cash Flows From Financing Activities
 
 
 
Borrowings on long-term debt
99

 
76

Payments on debt
(25
)
 
(28
)
Borrowings under short-term debt
9

 
32

Cash contributions from noncontrolling interests
242

 
—

Cash dividends to noncontrolling interests
(7
)
 
—

Payments to affiliates related to stock-based awards
(12
)
 
(4
)
Excess tax benefits related to stock-based exercises
1

 
1

Financing costs
(7
)
 
—

Net cash provided by financing activities from continuing operations
300

 
77

Cash Flows From Investing Activities
 
 
 
Capital expenditures
(166
)
 
(219
)
Proceeds from return of capital and loan repayments and sale of assets
5

 
12

Proceeds from settlement of insurance claims
2

 
—

Investments in and loans to unconsolidated affiliates
—

 
(7
)
(Increase) decrease in restricted deposits and restricted cash and cash equivalents
(69
)
 
19

Investments in other assets
(9
)
 
(29
)
Net cash used in investing activities from continuing operations
(237
)
 
(224
)
Net decrease in cash and cash equivalents
(291
)
 
(242
)
Cash and cash equivalents at beginning of period
1,300

 
1,075

Cash and cash equivalents at end of period
$
1,009

 
$
833


The accompanying notes are an integral part of these consolidated financial statements.
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EDISON MISSION ENERGY AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
June 30, 2012
(Unaudited)

Note 1. Summary of Significant Accounting Policies
Liquidity and Restructuring Activities
At June 30, 2012, Edison Mission Energy (EME), and its subsidiaries without contractual dividend restrictions, had corporate cash and cash equivalents of $879 million, which includes Midwest Generation, LLC's (Midwest Generation) cash and cash equivalents of $177 million. EME and Midwest Generation's previous revolving credit agreements have been terminated or expired and no longer are sources of liquidity. At June 30, 2012, EME had $3.7 billion of unsecured notes outstanding, $500 million of which mature in June 2013.
EME is currently experiencing operating losses due to lower realized energy and capacity prices, higher fuel costs and lower generation at the Midwest Generation plants. Forward market prices indicate that these trends are expected to continue for a number of years. As a result, EME expects that it will incur further reductions in cash flow and losses in the current year and in subsequent years. A continuation of these adverse trends coupled with pending debt maturities and the need to retrofit its Midwest Generation plants to comply with governmental regulations will exhaust EME's liquidity. Consequently, EME will need to consider all options available to it, including potential sales of assets, restructuring, reorganization of its capital structure, or conservation of cash that would be otherwise applied to the payment of obligations. EME has entered into non-disclosure and engagement agreements with advisors representing certain of its unsecured bondholders for the purpose of engaging in discussions with such advisors and Edison International regarding EME's financial condition. Absent a restructuring of its obligations, based on current projections, EME is not expected to have sufficient liquidity to repay the $500 million debt obligation due in June 2013. As a result, EME may need to file for protection under Chapter 11 of the U.S. Bankruptcy Code.
Bankruptcy proceedings could lead to a change of control of EME , which would result in the termination of EME's tax-allocation agreement. At June 30, 2012, EME had recognized $323 million of net deferred tax benefits based on continued ownership by Edison International and inclusion of EME in the consolidated income tax returns of Edison International and its subsidiaries. If it is more likely than not that EME would no longer continue to participate as part of the consolidated group of Edison International, EME would record a valuation allowance to reduce the carrying value of its net deferred tax benefit and record a material charge against earnings. The termination of the tax-allocation agreement could adversely affect EME's long-term liquidity because realization of the value of tax benefits generated by EME could be deferred until such time that EME, or a subsequent owner of EME, had the ability to utilize such benefits. There is no assurance as to when, or whether, this might occur.
The accompanying consolidated financial statements have been prepared assuming that EME will continue as a going concern. Financial statements prepared on this basis assume the realization of assets and the satisfaction of liabilities in the normal course of business for the 12-month period following the date of these financial statements. There is no assurance that EME will be able to continue as a going concern.
Basis of Presentation
EME's significant accounting policies were described in "Note 1. Summary of Significant Accounting Policies" on page 68 of EME's annual report on Form 10-K for the year ended December 31, 2011. EME follows the same accounting policies for interim reporting purposes, with the exception of accounting principles adopted as of January 1, 2012, as discussed below in "—New Accounting Guidance." This quarterly report should be read in conjunction with such financial statements and notes.
In the opinion of management, all adjustments, consisting of 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 (GAAP) for the periods covered by this quarterly report on Form 10-Q. The results of operations for the three- and six-month periods ended June 30, 2012 are not necessarily indicative of the operating results for the full year. Except as indicated, amounts reflected in the notes to the consolidated financial statements relate to continuing operations of EME.
The December 31, 2011 condensed consolidated balance sheet data was derived from audited financial statements, but does not include all disclosures required by GAAP.

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The consolidated statement of cash flows for the six months ended June 30, 2011 was revised to correct an error in the presentation of vendor financed property, plant and equipment in the amount of $19 million. This correction, to present the amount on a net rather than gross basis, decreased cash flows used in investing activities and cash flows provided by financing activities by this amount, but had no impact on the net change in cash and cash equivalents. Management believes the revision does not have a material impact on the prior year financial statements.
Cash Equivalents
Cash equivalents included money market funds totaling $873 million and $1.2 billion at June 30, 2012 and December 31, 2011, respectively. The carrying value of cash equivalents equals the fair value as all investments have original maturities of less than three months.
Restricted Cash and Cash Equivalents, and Restricted Deposits
Restricted cash and cash equivalents at June 30, 2012 and December 31, 2011 included $97 million received from a wind project financing that was held in escrow at those dates. At June 30, 2012, restricted deposits included $51 million to support outstanding letters of credit issued under EME's letter of credit facilities.
Inventory
Inventory is stated at the lower of weighted-average cost or market. Inventory is recorded at actual cost when purchased and then expensed at weighted-average cost as used. Inventory consisted of the following:
(in millions)
June 30, 2012
 
December 31, 2011
Coal, fuel oil and other raw materials
$
142

 
$
188

Spare parts, materials and supplies
90

 
86

Total inventory
$
232

 
$
274

Allocation of Net Income or Losses to Investors in Certain Variable Interest Entities
Capistrano Wind Partners' partnership agreements contain complex allocation provisions for taxable income and losses, tax credits and cash distributions. EME allocates net income for this consolidated investment to third-party investors based on the Hypothetical Liquidation Book Value (HLBV) method. HLBV is a balance sheet oriented approach that calculates the change in the claims of each partner on the net assets of the investment at the beginning and end of each period. Each partner's claim is equal to the amount each party would receive or pay if the net assets of the investment were to liquidate at book value and the resulting cash was then distributed to investors in accordance with their respective liquidation preferences. EME reports the net income (loss) attributable to the third-party investors as income (loss) attributable to noncontrolling interests in the consolidated statements of operations. For further information, see Note 3—Variable Interest Entities—Projects or Entities that are Consolidated—Capistrano Wind Equity Capital.
New Accounting Guidance
Accounting Guidance Adopted in 2012
Fair Value Measurement
In May 2011, the Financial Accounting Standards Board (FASB) issued an accounting standards update modifying the fair value measurement and disclosure guidance. This guidance prohibits grouping of financial instruments for purposes of fair value measurement and requires the value be based on the individual security. This amendment also results in new disclosures primarily related to Level 3 measurements including quantitative disclosure about unobservable inputs and assumptions, a description of the valuation processes and a narrative description of the sensitivity of the fair value to changes in unobservable inputs. EME adopted this guidance effective January 1, 2012. For further information, see Note 4—Fair Value Measurements.
Presentation of Comprehensive Income
In June 2011 and December 2011, the FASB issued accounting standards updates on the presentation of comprehensive income. An entity can elect to present items of net income and other comprehensive income in one continuous statement, referred to as the statement of comprehensive income, or in two separate but consecutive statements. EME adopted this

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guidance January 1, 2012 and elected to present two separate but consecutive statements. The adoption of these accounting standards updates did not change the items that constitute net income and other comprehensive income.
Accounting Guidance Not Yet Adopted
Offsetting Assets and Liabilities
In December 2011, the FASB issued an accounting standards update modifying the disclosure requirements about the nature of an entity's rights of offsetting assets and liabilities in the statement of financial position under master netting agreements and related arrangements associated with financial and derivative instruments. The guidance requires increased disclosure of the gross and net recognized assets and liabilities, collateral positions and narrative descriptions of setoff rights. EME will adopt this guidance effective January 1, 2013.

Note 2. Consolidated Statements of Changes in Equity
The following table provides the changes in equity for the six months ended June 30, 2012:
 
EME Shareholder's Equity
 
 
 
 
(in millions)
Common Stock
 
Additional Paid-in Capital
 
Retained Earnings
 
Accumulated Other Comprehensive Loss
 
Non-controlling interest
 
Total Equity
Balance at December 31, 2011
$
64

 
$
1,327

 
$
365

 
$
(94
)
 
$
2

 
$
1,664

Net income (loss)
—

 
—

 
(193
)
 
—

 
7

 
(186
)
Other comprehensive loss
—

 
—

 
—

 
(21
)
 
—

 
(21
)
Payments to Edison International for stock purchases related to stock-based compensation
—

 
—

 
(12
)
 
—

 
—

 
(12
)
Other stock transactions, net
—

 
3

 
—

 
—

 
—

 
3

Contributions from noncontrolling interests1
—

 
—

 
—

 
—

 
242

 
242

Distributions to noncontrolling interests
—

 
—

 
—

 
—

 
(7
)
 
(7
)
Transfers of assets to Capistrano Wind Partners2
—

 
(21
)
 
—

 
—

 
—

 
(21
)
Balance at June 30, 2012
$
64

 
$
1,309

 
$
160

 
$
(115
)
 
$
244

 
$
1,662

1 
Funds contribution by third-party investors related to the Capistrano Wind equity capital raise are reported in noncontrolling interest. For further information, see Note 3—Variable Interest Entities—Projects or Entities that are Consolidated—Capistrano Wind Equity Capital.
2 
Additional paid in capital was reduced by $21 million during the six months ended June 30, 2012 due to a new tax basis in the assets transferred to Capistrano Wind Partners. The tax basis allocation to the transferred assets was updated during the three months ended June 30, 2012. For further information, see Note 3—Variable Interest Entities—Projects or Entities that are Consolidated—Capistrano Wind Equity Capital.

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The following table provides the changes in equity for the six months ended June 30, 2011:
 
EME Shareholder's Equity
 
 
 
 
(in millions)
Common Stock
 
Additional Paid-in Capital
 
Retained Earnings
 
Accumulated Other Comprehensive Loss
 
Non-controlling interest
 
Total Equity
Balance at December 31, 2010
$
64

 
$
1,336

 
$
1,448

 
$
(31
)
 
$
4

 
$
2,821

Net loss
—

 
—

 
(52
)
 
—

 
—

 
(52
)
Other comprehensive loss
—

 
—

 
—

 
(24
)
 
—

 
(24
)
Payments to Edison International for stock purchases related to stock-based compensation
—

 
—

 
(3
)
 
—

 
—

 
(3
)
Excess tax benefits related to stock option exercises
—

 
1

 
—

 
—

 
—

 
1

Other stock transactions, net
—

 
2

 
—

 
—

 
—

 
2

Purchase of noncontrolling interest1
—

 
(4
)
 
—

 
—

 
(1
)
 
(5
)
Balance at June 30, 2011
$
64

 
$
1,335

 
$
1,393

 
$
(55
)
 
$
3

 
$
2,740

1 
During the second quarter of 2011, EME purchased a noncontrolling interest in Pinnacle Wind Force, LLC, which is now 100% owned by EME.

Note 3. Variable Interest Entities
Projects or Entities that are Consolidated
At June 30, 2012 and December 31, 2011, EME consolidated 16 and 13 projects, respectively, with a total generating capacity of 861 MW and 570 MW, respectively, that have noncontrolling interests held by others. Projects consolidated at June 30, 2012 increased from the projects consolidated at December 31, 2011, due to the Capistrano Wind equity capital transaction as discussed below. In determining that EME was the primary beneficiary of the projects that are consolidated, key factors considered were EME's ability to direct commercial and operating activities and EME's obligation to absorb losses of the variable interest entities.
The following table presents summarized financial information of the projects that were consolidated by EME:
(in millions)
June 30,
2012
 
December 31,
2011
Current assets
$
118

 
$
36

Net property, plant and equipment
1,107

 
675

Other long-term assets
22

 
5

Total assets
$
1,247

 
$
716

Current liabilities
$
34

 
$
28

Long-term debt net of current portion
175

 
57

Deferred revenues
173

 
69

Long-term derivative liabilities
22

 
—

Other long-term liabilities
37

 
22

Total liabilities
$
441

 
$
176

Noncontrolling interests
$
244

 
$
2

Assets serving as collateral for the debt obligations had a carrying value of $472 million and $136 million at June 30, 2012 and December 31, 2011, respectively, and primarily consist of property, plant and equipment.

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Table of Contents

Capistrano Wind Equity Capital
As part of its plan to obtain third-party equity capital to finance the development of a portion of EME's wind portfolio, on February 13, 2012, Edison Mission Wind Inc. (Edison Mission Wind) sold its indirect equity interests in the Cedro Hill wind project (150 MW in Texas), the Mountain Wind Power I project (61 MW in Wyoming) and the Mountain Wind Power II project (80 MW in Wyoming) to a new venture, Capistrano Wind Partners. Outside investors provided $238 million of the funding. Capistrano Wind Partners also agreed to acquire the Broken Bow I wind project (80 MW in Nebraska) and the Crofton Bluffs wind project (40 MW in Nebraska) for consideration expected to include $140 million from the same outside investors upon the satisfaction of specified conditions, including commencement of commercial operation and conversion of project debt financing to term loans. In March 2012, EME received a distribution of the proceeds from outside investors, which will be used for general corporate purposes. Through their ownership of Capistrano Wind Holdings, an indirect subsidiary of EME, Edison Mission Wind, and EME's parent company, Mission Energy Holding Company (MEHC), own 100% of the Class A equity interests in Capistrano Wind Partners, and the Class B preferred equity interests are held by outside investors. Under the terms of the formation documents, preferred equity interests receive 100% of the cash available for distribution, up to a scheduled amount to target a certain return and thereafter cash distributions are shared. Cash available for distribution includes 90% of the tax benefits realized by MEHC and contributed to Capistrano Wind Partners.
Edison Mission Wind retains indirect beneficial ownership of the common equity in the projects, net of a $4 million preferred investment made by MEHC, and retains responsibilities for managing the operations of Capistrano Wind Holdings and its projects, and accordingly, EME will continue to consolidate these projects. The $238 million contributed by the third-party interests and the $4 million preferred investment made by MEHC are reflected in noncontrolling interests on EME's consolidated balance sheet at June 30, 2012. This transaction was accounted for as a transfer among entities under common control and, therefore, resulted in no change in the book basis of the transferred assets. However, the transaction did trigger a taxable gain and new tax basis in the assets with a corresponding adjustment to deferred taxes and a reduction to equity of $21 million.

Note 4. Fair Value Measurements
Recurring Fair Value Measurements
Fair value is defined 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"). Fair value of an asset or liability considers assumptions that market participants would use in pricing the asset or liability, including assumptions about nonperformance risk, which was not material as of June 30, 2012 and December 31, 2011.
Assets and liabilities are categorized into a three-level fair value hierarchy based on valuation inputs used to determine fair value. The hierarchy gives the highest priority to unadjusted quoted market prices in active markets for identical assets and liabilities (Level 1 measurements) and the lowest priority to unobservable inputs (Level 3 measurements).
The following table sets forth assets and liabilities that were accounted for at fair value by level within the fair value hierarchy:
 
June 30, 2012
(in millions)
Level 1
 
Level 2
 
Level 3
 
Netting and
Collateral1
 
Total
Assets at Fair Value
 
 
 
 
 
 
 
 
 
Money market funds2
$
873

 
$
—

 
$
—

 
$
—

 
$
873

Derivative contracts
 
 
 
 
 
 
 
 
 
Electricity
$
—

 
$
106

 
$
51

 
$
(59
)
 
$
98

Natural gas
4

 
—

 
—

 
(4
)
 
—

Total derivative contracts
4

 
106

 
51

 
(63
)
 
98

Total assets
$
877

 
$
106

 
$
51

 
$
(63
)
 
$
971

Liabilities at Fair Value
 
 
 
 
 
 
 
 
 
Derivative contracts
 
 
 
 
 
 
 
 
 
Electricity
$
—

 
$
7

 
$
10

 
$
(17
)
 
$
—

Interest rate contracts
—

 
114

 
—

 
—

 
114

Total liabilities
$
—

 
$
121

 
$
10

 
$
(17
)
 
$
114



9
Table of Contents

 
December 31, 2011
(in millions)
Level 1
 
Level 2
 
Level 3
 
Netting and
Collateral1
 
Total
Assets at Fair Value
 
 
 
 
 
 
 
 
 
Money market funds2
$
1,207

 
$
—

 
$
—

 
$
—

 
$
1,207

Derivative contracts
 
 
 
 
 
 
 
 
 
Electricity
$
—

 
$
66

 
$
95

 
$
(62
)
 
$
99

Natural gas
4

 
—

 
—

 
(4
)
 
—

Fuel oil
4

 
—

 
—

 
(4
)
 
—

Total derivative contracts
8

 
66

 
95

 
(70
)
 
99

Total assets
$
1,215

 
$
66

 
$
95

 
$
(70
)
 
$
1,306

Liabilities at Fair Value
 
 
 
 
 
 
 
 
 
Derivative contracts
 
 
 
 
 
 
 
 
 
Electricity
$
—

 
$
8

 
$
12

 
$
(19
)
 
$
1

Interest rate contracts
—

 
90

 
—

 
—

 
90

Total liabilities
$
—

 
$
98

 
$
12

 
$
(19
)
 
$
91

1 
Represents cash collateral and the impact of netting across the levels of the fair value hierarchy. Netting among positions classified within the same level is included in that level.
2 
Money market funds are included in cash and cash equivalents and in restricted cash and cash equivalents on EME's consolidated balance sheets.
The following table sets forth a summary of changes in the fair value of Level 3 net derivative assets and liabilities:
 
Three Months Ended
June 30,
 
Six Months Ended
June 30,
(in millions)
2012
 
2011
 
2012
 
2011
Fair value of net assets at beginning of period
$
24

 
$
83

 
$
83

 
$
91

Total realized/unrealized gains (losses)
 
 
 
 
 
 
 
Included in earnings1
23

 
18

 
8

 
18

Included in accumulated other comprehensive loss2
—

 
(4
)
 
2

 
(3
)
Purchases
13

 
6

 
19

 
11

Settlements
(19
)
 
(19
)
 
(20
)
 
(31
)
Transfers out of Level 33
—

 
—

 
(51
)
 
(2
)
Fair value of net assets at end of period
$
41

 
$
84

 
$
41

 
$
84

Change during the period in unrealized gains (losses) related to assets and liabilities held at end of period1
$
14

 
$
14

 
$
8

 
$
8

1 
Reported in operating revenues on EME's consolidated statements of operations.
2 
Included in reclassification adjustments in EME's consolidated statement of other comprehensive loss.
3 
Transfers out of Level 3 into Level 2 occurred due to significant observable inputs becoming available as the transactions near maturity.
The fair value of transfers in and out of each level is determined at the end of each reporting period. There were no transfers between Levels 1 and 2 during the three and six months ended June 30, 2012 and 2011.

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Table of Contents

Valuation Techniques Used to Determine Fair Value
Level 1
The fair value of Level 1 assets and liabilities is determined using unadjusted quoted prices in active markets that are available at the measurement date for identical assets and liabilities. This level includes exchange-traded derivatives and money market funds.
Level 2
The fair value of Level 2 assets and liabilities is determined using the income approach by obtaining quoted prices for similar assets and liabilities in active markets and inputs that are observable, either directly or indirectly, for substantially the full term of the instrument. This level includes over-the-counter derivatives and interest rate swaps.
Over-the-counter derivative contracts are valued using standard pricing models to determine the net present value of estimated future cash flows. Inputs to the pricing models include forward published or posted clearing prices from exchanges (New York Mercantile Exchange and Intercontinental Exchange) for similar instruments and discount rates. A primary price source that best represents trade activity for each market is used to develop observable forward market prices in determining the fair value of these positions. Broker quotes, prices from exchanges or comparison to executed trades are used to validate and corroborate the primary price source. These price quotations reflect mid-market prices (average of bid and ask) and are obtained from sources believed to provide the most liquid market for the commodity.
Level 3
The fair value of Level 3 assets and liabilities is determined using the income approach through various models and techniques that require significant unobservable inputs. This level includes over-the-counter options and derivative contracts that trade infrequently, such as congestion revenue rights and long-term power agreements.
Assumptions are made in order to value derivative contracts in which observable inputs are not available. Changes in fair value are based on changes to forward market prices, including extrapolation of short-term observable inputs into forecasted prices for illiquid forward periods. In circumstances where fair value cannot be verified with observable market transactions, it is possible that a different valuation model could produce a materially different estimate of fair value. Modeling methodologies, inputs and techniques are reviewed and assessed as markets continue to develop and more pricing information becomes available and the fair value is adjusted when it is concluded that a change in inputs or techniques would result in a new valuation that better reflects the fair value of those derivative contracts.
Level 3 Valuation Process
The process of determining fair value is the responsibility of the risk department, which reports to the chief financial officer. This department obtains observable and unobservable inputs through broker quotes, exchanges and internal valuation techniques and uses both standard and proprietary models to determine fair value. Each reporting period, the risk and key finance departments collaborate to determine the appropriate fair value methodologies and classifications for each derivative. Inputs are validated for reasonableness by comparison against prior prices, other broker quotes and volatility fluctuation thresholds. Inputs used and valuations are reviewed period-over-period and compared with market conditions to determine reasonableness.
The following table sets forth the valuation techniques and significant unobservable inputs used to determine fair value for Level 3 assets and liabilities:
June 30, 2012
 
 
 
Quantitative Information About Level 3 Fair Value Measurements
 
Fair Value (in millions)
 
Valuation Techniques
 
Significant Unobservable Input
 
Range
(Weighted Average)
 
Assets
 
Liabilities
Electricity
 
 
 
 
 
 
 
Congestion contracts
$
73

 
 
$
24

 
 
Latest auction pricing
 
Congestion prices
 
$(15.52) - $23.03 ($0.15)
Power contracts
19

 
 
27

 
 
Discounted cash flows
 
Power prices
 
$16.60 - $58.23
($35.80)
Netting
(41
)
 
 
(41
)
 
 
 
 
 
 
 
Total
$
51

 
 
$
10

 
 
 
 
 
 
 

11
Table of Contents

Level 3 Fair Value Sensitivity
For congestion contracts, generally, an increase (decrease) in congestion prices in the last auction relative to the contract price will increase (decrease) fair value. For power contracts, generally, an increase (decrease) in long-term forward power prices at illiquid locations relative to the contract price will increase (decrease) fair value.
Fair Value of Long-term Debt
The carrying amounts and fair values of EME's long-term debt were as follows:
 
June 30, 2012
 
December 31, 2011
(in millions)
Carrying
Amount
 
Fair Value
 
Carrying
Amount
 
Fair Value
Long-term debt, including current portion
$
4,996

 
$
3,369

 
$
4,912

 
$
3,716

In assessing the fair value of EME's long-term debt, EME primarily uses quoted market prices, except for floating-rate debt for which the carrying amounts were considered a reasonable estimate of fair value. The fair value of EME's long-term debt is classified as Level 2.

Note 5. Debt and Credit Agreements
2012 Project Financings
Broken Bow and Crofton Bluffs
Effective March 30, 2012, EME, through its subsidiaries, Broken Bow Wind, LLC and Crofton Bluffs Wind, LLC, completed two nonrecourse financings of its interests in the Broken Bow and Crofton Bluffs wind projects. The financings included construction loans totaling $79 million that are required to be converted to 15-year amortizing term loans by March 31, 2013, subject to meeting specified conditions, $13.1 million letter of credit facilities and $5.5 million working capital facilities.
Interest under the construction and term loans will accrue at London Interbank Offered Rate (LIBOR) plus 2.875%, with the term loan rate increasing 0.125% after the third, sixth, ninth, and twelfth years. Pursuant to the financing agreements, on April 2, 2012 and April 17, 2012, EME's subsidiaries entered into forward starting interest rate swap agreements at 0.8275% and 0.7825%, respectively, to hedge the majority of the variable interest rate debt beginning December 31, 2012 through December 31, 2013 and at 2.96% and 2.7475%, respectively, to hedge the majority of the variable interest rate debt beginning December 31, 2013 through December 31, 2027.
Upon conversion to a term loan, distributions from such subsidiaries are subject to compliance with the terms and conditions of their financing agreements, including a 12-month historic debt service coverage ratio test as specified in the agreements of at least 1.20 to 1.00.
As of June 30, 2012, $9 million and $6 million were outstanding under the construction loans included in short-term debt on EME's consolidated balance sheet, and letters of credit facilities, respectively.
2011 Project Financings
Tapestry Wind
In December 2011, EME, through its subsidiary, Tapestry Wind, LLC, completed a nonrecourse financing of its interests in the Taloga, Buffalo Bear and Pinnacle wind projects. A total of $97 million of cash proceeds received from the $214 million 10-year partially amortizing term loan was deposited into an escrow account as of December 31, 2011. On February 22, 2012, a neighbor of the Pinnacle project filed a formal complaint with the West Virginia Public Service Commission regarding, among other things, noise emissions and shadow flicker and requested that the Commission order the project to shut down at night due to alleged noise emissions. This complaint was dismissed on June 1, 2012. On June 27, 2012 and on July 3, 2012, nearly identical complaints were filed with the West Virginia Public Service Commission by two other neighbors. In addition, on June 25, 2012, each of the three neighbors filed separate civil complaints in the Circuit Court of Mineral County, West Virginia against Pinnacle Wind, LLC, EME, Edison Mission Operations and Maintenance, Inc., and other non-affiliated defendants. The civil complaints allege, among other things, that the noise emissions and shadow flicker from the Pinnacle wind farm constitute a nuisance and seek compensatory damages, punitive damages and other equitable relief. The release of the loan proceeds in escrow is subject to resolution of the complaints or further due diligence from the lenders.

12
Table of Contents

Big Sky Turbine Financing
In October 2009, EME, through its subsidiary, Big Sky Wind, LLC (Big Sky), entered into turbine financing arrangements totaling approximately $206 million for wind turbine purchase obligations related to the 240 MW Big Sky wind project. The loan has a five-year final maturity, however, specific events, including project performance, may trigger earlier repayment which could occur as early as February 2013. Big Sky's repayment obligations were guaranteed by EME until certain conditions were met, including commercial operations. On February 1, 2012, the lender agreed that all conditions had been satisfied and released EME from such guarantee. The loan is secured by a leasehold mortgage on the project's real property assets, a pledge of all other collateral of the Big Sky wind project, as well as a cash reserve account into which one-third of distributable cash flow, if any, of the Big Sky wind project is to be deposited on a monthly basis. The loan is also secured by pledges of Big Sky's direct and indirect ownership interests in the project.
Big Sky will need to arrange alternative financing, if available, to repay the loan at maturity or reach agreement with the lender to extend the maturity date of the loan as EME does not plan to make an investment in the project and is under no obligation to do so. If these efforts are unsuccessful, the lender may foreclose on the project resulting in a write off of the entire investment in the project. At June 30, 2012, EME's net investment in the Big Sky wind project was $135 million.
Credit Facilities and Letters of Credit
In February 2012, EME terminated its $564 million revolving credit facility. Midwest Generation's $500 million credit facility expired in June 2012 as per its terms. In the first quarter of 2012, EME completed a $100 million letter of credit facility for EME's general corporate needs and for its projects, which expires on June 30, 2014. Letters of credit issued under this facility are secured by cash collateral at least equal to the issued amount.
Letters of credit under EME's and its subsidiaries' credit facilities aggregated $165 million and were scheduled to expire as follows: $59 million in 2012, $75 million in 2013, $3 million in 2014, $10 million in 2017, and $18 million in 2018. Standby letters of credit include $40 million issued in connection with the power purchase agreement with Southern California Edison Company, an affiliate of EME, under the Walnut Creek credit facility. Certain letters of credit are subject to automatic annual renewal provisions. At June 30, 2012, EME had $51 million of cash collateral supporting its letters of credit.

Note 6. Derivative Instruments and Hedging Activities
EME uses derivative instruments to reduce its exposure to market risks that arise from price fluctuations of electricity, capacity, fuel, emission allowances, transmission rights and interest rates. The derivative financial instruments vary in duration, ranging from a few days to several years, depending upon the instrument. To the extent that EME does not use derivative instruments to hedge these market risks, the unhedged portions will be subject to the risks and benefits of spot market price movements.
Risk management positions may be designated as cash flow hedges or economic hedges, which are derivatives that are not designated as cash flow hedges. Economic hedges are accounted for at fair value on EME's consolidated balance sheets as derivative assets or liabilities with offsetting changes recorded on the consolidated statements of operations. For derivative instruments that qualify for hedge accounting treatment, the fair value is recognized on EME's consolidated balance sheets as derivative assets or liabilities with offsetting changes in fair value, to the extent effective, recognized in accumulated other comprehensive loss until reclassified into earnings when the related forecasted transaction occurs. The portion of a cash flow hedge that does not offset the change in the fair value of the transaction being hedged, which is commonly referred to as the ineffective portion, is immediately recognized in earnings.
Derivative instruments that are utilized for trading purposes are measured at fair value and included on the consolidated balance sheets as derivative assets or liabilities, with offsetting changes recognized in operating revenues on the consolidated statements of operations.
The results of derivative activities are recorded in cash flows from operating activities on the consolidated statements of cash flows.
Where EME's derivative instruments are subject to a master netting agreement and the criteria of authoritative guidance are met, EME presents its derivative assets and liabilities on a net basis on its consolidated balance sheets.

13
Table of Contents

Notional Volumes of Derivative Instruments
The following table summarizes the notional volumes of derivatives used for hedging and trading activities:
June 30, 2012
 
 
 
 
 
 
 
 
Hedging Activities
 
Trading
Activities
 
Commodity
 
Instrument
 
Classification
 
Unit of
Measure
 
Cash Flow
Hedges
 
Economic
Hedges
 
 
Electricity
 
Forwards/Futures
 
Sales, net
 
GWh
 
4,630

1 
116

3 
—

  
Electricity
 
Forwards/Futures
 
Purchases, net
 
GWh
 
—

 
—

 
2,201

 
Electricity
 
Capacity
 
Sales, net
 
GW-Day
 
37

2 
—

  
—

 
Electricity
 
Capacity
 
Purchases, net
 
GW-Day
 
—

 
—

 
134

2 
Electricity
 
Congestion
 
Purchases, net
 
GWh
 
—

  
287

4 
331,418

4 
Natural gas
 
Forwards/Futures
 
Purchases, net
 
bcf
 
—

 
—

 
1.7

 
Fuel oil
 
Forwards/Futures
 
Purchases, net
 
barrels
 
—

  
240,000

  
20,000

  
At June 30, 2012, EME had interest rate contracts with notional values totaling $703 million that converted floating rate LIBOR-based debt to fixed rates ranging from 0.79% to 4.29%. These contracts expire May 2013 through March 2026. In addition, at June 30, 2012, EME had forward starting interest rate contracts with notional values totaling $641 million that will convert floating rate LIBOR-based debt to fixed rates ranging from 0.7825% to 4.0025%. These contracts have effective dates beginning December 2012 through December 2021 and expire December 2013 through December 2029.
December 31, 2011
 
 
 
 
 
 
 
 
Hedging Activities
  
Trading
Activities
  
Commodity
 
Instrument
 
Classification
 
Unit of
Measure
 
Cash Flow
Hedges
  
Economic
Hedges
  
  
Electricity
 
Forwards/Futures
 
Sales, net
 
GWh
 
8,320

1 
425

3 
—

  
Electricity
 
Forwards/Futures
 
Purchases, net
 
GWh
 
—

 
—

 
2,926

  
Electricity
 
Capacity
 
Sales, net
 
GW-Day
 
89

2 
—

  
—

 
Electricity
 
Capacity
 
Purchases, net
 
GW-Day
 
—

 
—

  
184

2 
Electricity
 
Congestion
 
Purchases, net
 
GWh
 
—

  
2,528

4 
230,798

4 
Natural gas
 
Forwards/Futures
 
Sales, net
 
bcf
 
—

  
—

  
0.2

  
Fuel oil
 
Forwards/Futures
 
Purchases, net
 
barrels
 
—

  
240,000

  
—

  
1 
EME's hedge products include forward and futures contracts that qualify for hedge accounting.
2 
EME's hedge transactions for capacity result from bilateral trades. Capacity sold in the PJM Interconnection, LLC Reliability Pricing Model (PJM RPM) auction is not accounted for as a derivative.
3 
These positions adjust financial and physical positions, or day-ahead and real-time positions, to reduce costs or increase gross margin. The net sales positions of these categories are primarily related to hedge transactions that are not designated as cash flow hedges.
4 
Congestion contracts include financial transmission rights, transmission congestion contracts or congestion revenue rights. These positions are similar to a swap, where the buyer is entitled to receive a stream of revenues (or charges) based on the hourly day-ahead price differences between two locations.
At December 31, 2011, EME had interest rate contracts with notional values totaling $644 million that converted floating rate LIBOR-based debt to fixed rates ranging from 0.79% to 4.29%. These contracts expire May 2013 through March 2026. In addition, EME had forward starting interest rate contracts with notional values totaling $506 million that will convert floating rate LIBOR-based debt to fixed rates of 3.5429%, 3.57% and 4.0025%. These contracts have effective dates of June 2013 and December 2021 and expire May 2023 and December 2029.

14
Table of Contents

Fair Value of Derivative Instruments
The following table summarizes the fair value of derivative instruments reflected on EME's consolidated balance sheets:
June 30, 2012
 
Derivative Assets
 
Derivative Liabilities
 
Net Assets (Liabilities)
(in millions)
Short-term
 
Long-term
 
Subtotal
 
Short-term
 
Long-term
 
Subtotal
 
Non-trading activities
 
 
 
 
 
 
 
 
 
 
 
 
 
Cash flow hedges
 
 
 
 
 
 
 
 
 
 
 
 
 
Commodity contracts
$
24

 
$
2

 
$
26

 
$
1

 
$
3

 
$
4

 
$
22

Interest rate contracts
—

 
—

 
—

 
—

 
114

 
114

 
(114
)
Economic hedges
28

 
2

 
30

 
24

 
2

 
26

 
4

Trading activities
329

 
153

 
482

 
272

 
92

 
364

 
118

 
381

 
157

 
538

 
297

 
211

 
508

 
30

Netting and collateral received1
(335
)
 
(105
)
 
(440
)
 
(297
)
 
(97
)
 
(394
)
 
(46
)
Total
$
46

 
$
52

 
$
98

 
$
—

 
$
114

 
$
114

 
$
(16
)
December 31, 2011
 
Derivative Assets
 
Derivative Liabilities
 
Net Assets (Liabilities)
(in millions)
Short-term
 
Long-term
 
Subtotal
 
Short-term
 
Long-term
 
Subtotal
 
Non-trading activities
 
 
 
 
 
 
 
 
 
 
 
 
 
Cash flow hedges
 
 
 
 
 
 
 
 
 
 
 
 
 
Commodity contracts
$
41

 
$
1

 
$
42

 
$
2

 
$
3

 
$
5

 
$
37

Interest rate contracts
—

 
—

 
—

 
—

 
90

 
90

 
(90
)
Economic hedges
31

 
1

 
32

 
26

 
1

 
27

 
5

Trading activities
276

 
142

 
418

 
232

 
79

 
311

 
107

 
348

 
144

 
492

 
260

 
173

 
433

 
59

Netting and collateral received1
(308
)
 
(85
)
 
(393
)
 
(259
)
 
(83
)
 
(342
)
 
(51
)
Total
$
40

 
$
59

 
$
99

 
$
1

 
$
90

 
$
91

 
$
8

1 
Netting of derivative receivables and derivative payables and the related cash collateral received and paid is permitted when a legally enforceable master netting agreement exists with a derivative counterparty.
Income Statement Impact of Derivative Instruments
The following table provides the cash flow hedge activity as part of accumulated other comprehensive loss:
 
Cash Flow Hedge Activity1
 
 
 
Six Months Ended June 30,
 
 
 
2012
 
2011
 
 
(in millions)
Commodity Contracts
 
Interest Rate Contracts
 
Commodity Contracts
 
Interest Rate Contracts
 
Income Statement
Location
Beginning of period derivative gains (losses)
$
35

 
$
(90
)
 
$
43

 
$
(16
)
 
 
Effective portion of changes in fair value
19

 
(24
)
 
(6
)
 
(7
)
 
 
Reclassification to earnings
(33
)
 
—

 
(29
)
 
—

 
Operating revenues
End of period derivative gains (losses)
$
21

 
$
(114
)
 
$
8

 
$
(23
)
 
 
1 
Unrealized derivative gains (losses) are before income taxes. The after-tax amounts recorded in accumulated other comprehensive loss at June 30, 2012 and 2011 for commodity and interest rate contracts were $12 million and $(69) million, and $5 million and $(14) million, respectively.

15
Table of Contents

For additional information, see Note 11—Accumulated Other Comprehensive Loss.
EME recorded no net gains or losses during the three months ended June 30, 2012 and 2011, and $1 million and $2 million during the six months ended June 30, 2012 and 2011, respectively, in operating revenues on the consolidated statements of operations representing the amount of cash flow hedge ineffectiveness.
The effect of realized and unrealized gains (losses) from derivative instruments used for economic hedging and trading purposes on the consolidated statements of operations is presented below:
 
 
Three Months Ended
June 30,
 
Six Months Ended
June 30,
(in millions)
Income Statement Location
2012
 
2011
 
2012
 
2011
Economic hedges
Operating revenues
$
6

 
$
20

 
$
17

 
$
26

 
Fuel
(6
)
 
(2
)
 
(1
)
 
4

Trading activities
Operating revenues
30

 
41

 
50

 
57

Margin and Collateral Deposits
Certain derivative instruments contain margin and collateral deposit requirements. Since EME's and its subsidiaries' credit ratings are below investment grade, EME and its subsidiaries have provided collateral in the form of cash and letters of credit for the benefit of derivative counterparties and brokers. The amount of margin and collateral deposits generally varies based on changes in fair value of the related positions. EME nets counterparty receivables and payables where balances exist under master netting arrangements. EME presents the portion of its margin and collateral deposits netted with its derivative positions on its consolidated balance sheets. Future increases in power prices could expose EME, Midwest Generation or Edison Mission Marketing & Trading, Inc. (EMMT) to additional collateral postings. The following table summarizes margin and collateral deposits provided to and received from counterparties:
(in millions)
June 30,
2012
 
December 31,
2011
Collateral provided to counterparties
 
 
 
 
 
 
 
Offset against derivative liabilities
 
$
3

 
 
 
$
2

 
Reflected in margin and collateral deposits
 
59

 
 
 
41

 
Collateral received from counterparties
 
 
 
 
 
 
 
Offset against derivative assets
 
49

 
 
 
53

 


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Note 7. Income Taxes
Effective Tax Rate
The table below provides a reconciliation of income tax benefit computed at the federal statutory income tax rate to the income tax benefit:
 
Three Months Ended
June 30,
 
Six Months Ended
June 30,
(in millions)
2012
 
2011
 
2012
 
2011
Loss from continuing operations before income taxes
$
(203
)
 
$
(88
)
 
$
(375
)
 
$
(151
)
Benefit for income taxes at federal statutory rate of 35%
$
(71
)
 
$
(30
)
 
$
(131
)
 
$
(53
)
Increase (decrease) in income tax from
 
 
 
 
 
 
 
State tax-net of federal benefit
(6
)
 
(4
)
 
(21
)
 
(9
)
Production tax credits, net
(17
)
 
(18
)
 
(36
)
 
(36
)
Taxes on income allocated to noncontrolling interests
(5
)
 
(1
)
 
(4
)
 
(1
)
Other
—

 
(4
)
 
2

 
(3
)
Total benefit for income taxes from continuing operations
$
(99
)
 
$
(57
)
 
$
(190
)
 
$
(102
)
Effective tax rate
49
%
 
65
%
 
51
%
 
68
%
Tax Dispute
The Internal Revenue Service examination phase of tax years 2003 through 2006 was completed in the fourth quarter of 2010, which included a proposed adjustment related to EME. The EME-related proposed adjustment increases the taxable gain on the 2004 sale of EME's international assets, which if sustained, would result in a federal tax payment of approximately $196 million, including interest and penalties through June 30, 2012 (the Internal Revenue Service has asserted a 40% penalty for understatement of tax liability related to this matter). Edison International disagrees with the proposed adjustment and filed a protest with the Internal Revenue Service in the first quarter of 2011. The disputed tax matter is currently being considered in appeals.
Tax Election at Homer City
On March 15, 2012, Homer City made an election to be treated as a partnership for federal and state income tax purposes. As a result of this election, Homer City is treated for tax purposes as distributing its assets and liabilities to its partners, both of which are wholly owned subsidiaries of EME, and triggering tax deductions of approximately $1 billion. Such tax deductions will be included in Edison International's 2011 consolidated tax returns and EME will be allocated the benefit for the deductions under the tax-allocation agreements.
Deferred Taxes
At June 30, 2012, EME had recognized $961 million of income tax benefits related to federal tax credit carryforwards, federal net operating loss carryforwards and state net operating loss carryforwards, including the federal and state tax deductions related to the change in tax classification at Homer City. For further information, see Note 1—Summary of Significant Accounting Policies—Liquidity and Restructuring Activities.

Note 8. Compensation and Benefit Plans
Pension Plans and Postretirement Benefits Other than Pensions
Pension Plans
During the six months ended June 30, 2012, EME made contributions of $13 million, and during the remainder of 2012, expects to make $9 million of additional contributions.

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The following were components of pension expense:
 
Three Months Ended
June 30,
 
Six Months Ended
June 30,
(in millions)
2012
 
2011
 
2012
 
2011
Service cost
$
4

 
$
5

 
$
9

 
$
9

Interest cost
4

 
3

 
7

 
7

Expected return on plan assets
(4
)
 
(3
)
 
(7
)
 
(6
)
Net amortization
2

 
1

 
3

 
2

Total expense
$
6

 
$
6

 
$
12

 
$
12

Postretirement Benefits Other Than Pensions
During the six months ended June 30, 2012, EME made contributions of $2 million, and during the remainder of 2012, expects to make $1 million of additional contributions.
The following were components of postretirement benefits expense:
 
Three Months Ended
June 30,
 
Six Months Ended
June 30,
(in millions)
2012
 
2011
 
2012
 
2011
Service cost
$
1

 
$
1

 
$
2

 
$
2

Interest cost
1

 
1

 
3

 
3

Net amortization
1

 
—

 
1

 
—

Total expense
$
3

 
$
2

 
$
6

 
$
5

Transfer of Certain Post Retirement Benefits to Edison International
In March 2012, Edison International agreed to assume the liabilities for active employees of EME and its subsidiaries under the specified plans related to deferred compensation and executive post retirement benefits. In consideration for such assumption, EME and its subsidiaries paid Edison International the after-tax amount of such liabilities as of March 1, 2012 ($25 million).

Note 9. Commitments and Contingencies
Homer City Lease and Environmental Project
Homer City made the required April 1, 2012 senior rent payment but did not make the April 1, 2012 payment of equity rent. On March 30, 2012, Homer City was granted a waiver by the owner-lessors of any rent default event with respect to the payment of the equity rent for all purposes other than restrictions on distributions from Homer City, including repayment of its intercompany loan, and the $48 million senior rent reserve letter of credit remains in place. For further discussion of the Homer City lease, refer to "Item 8. Edison Mission Energy and Subsidiaries Notes to Consolidated Financial Statements—Note 9. Commitments and Contingencies—Power Plant and Other Lease Commitments—Sale-Leaseback Transactions" on page 105 of EME's annual report on Form 10-K for the year ended December 31, 2011.
On March 29, 2012, Homer City and General Electric Capital Corporation (GECC) entered into an Implementation Agreement (the Agreement) with respect to the Homer City plant. As addressed by the Agreement, an affiliate of the GECC-controlled owner-lessors of the Homer City plant has entered into an engineering, procurement and construction agreement and has executed related agreements for the construction of environmental improvements. GECC has discretion over all decisions related to such construction agreements. Homer City agreed to conduct its business as set forth in the Agreement and to use commercially reasonable efforts to provide assistance to GECC and its affiliates in connection with the construction agreements. The estimated cost of installing sulfur dioxide (SO2) and particulate emissions control equipment for Units 1 and 2 of the Homer City plant is expected to be approximately $700 million to $750 million. On April 2, 2012, Homer City received the permit to construct such improvements from the Pennsylvania Department of Environmental Protection (PADEP).

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The Agreement also requires Homer City, at the request of GECC, to enter into one or more implementation transactions, as defined in the Agreement, for the divestiture of its leasehold interest in the Homer City plant (and, under certain circumstances, related assets and liabilities as specified) and to assist GECC in obtaining certain third-party consents or waivers. Homer City and GECC also agreed to enter into a transition services agreement in connection with any implementation transaction. There is no assurance that Homer City and GECC will actually consummate a divestiture transaction as contemplated by the Agreement.
Certain divestitures of Homer City's leasehold interest in the plant are subject to consent rights of the holders of the secured lease obligation bonds issued in connection with the original sale-leaseback transaction. GECC is currently engaged in discussions and has reached an agreement in principle on a non-binding restructuring term sheet with certain of the holders of the secured lease obligation bonds regarding amendments to the terms of the 8.137% Senior Secured Bonds due 2019 and the 8.734% Senior Secured Bonds due 2026, each issued by Homer City Funding LLC. Even though an agreement in principle has been reached with certain holders of the secured lease obligation bonds, that agreement may not be approved by the secured lease obligation bondholders as required under the operative documents to effectuate the necessary modifications to the terms of the bonds. If an agreement to modify the terms of the bonds is not approved and consummated, then it is possible that Homer City could become the subject of bankruptcy proceedings.
The Agreement also contains certain indemnities by each party in favor of the other. The Agreement may be terminated by GECC in its sole discretion at any time effective immediately upon delivery of notice to Homer City. Homer City may terminate the Agreement in connection with certain terminations of the construction agreements, subject to certain conditions.
Included in the consolidated balance sheet at June 30, 2012 are assets and liabilities of Homer City. In the event that Homer City completes a divestiture transaction with its owner-lessors or EME ceases to control Homer City, EME will record a loss on disposition and classify Homer City as a discontinued operation. At June 30, 2012, Homer City assets of $181 million were composed of cash, accounts receivable, inventory, and other assets and liabilities of $97 million were composed of accounts payable, accrued liabilities and other liabilities. In addition, EMMT had an intercompany account receivable from Homer City of $37 million at June 30, 2012. Any loss on disposition will be determined based on the assets and liabilities as of the date of disposition, the terms and conditions of the relevant transaction and an assessment as to whether any ongoing contingencies exist.
Coal Transportation Commitments
At June 30, 2012, Midwest Generation had contractual agreements for the transportation of coal. The commitments under these contracts are based on either actual coal purchases derived from committed coal volumes set forth in fuel supply contracts or minimum quantities as set forth in the transportation agreements as adjusted for provisions that mitigate the financial exposure of Midwest Generation related to a plant closure under certain circumstances as specified in the agreements. Estimated contractual obligations for coal transportation agreements are estimated to aggregate $2.4 billion, which consists of: $229 million for the remainder of 2012, $292 million for 2013, $287 million for 2014, $261 million for 2015, $261 million for 2016, and $1.1 billion thereafter. Years subsequent to 2012 reflect a reduction in minimum volumes for the shut down of the Fisk and Crawford Stations.
Guarantees and Indemnities
EME and certain of its subsidiaries have various financial and performance guarantees and indemnity agreements which are issued in the normal course of business. The contracts discussed below included performance guarantees.
Environmental Indemnities Related to the Midwest Generation Plants
In connection with the acquisition of the Midwest Generation plants, EME agreed to indemnify Commonwealth Edison Company (Commonwealth Edison) with respect to specified environmental liabilities before and after December 15, 1999, the date of sale. The indemnification obligations are reduced by any insurance proceeds and tax benefits related to such indemnified claims and are subject to a requirement that Commonwealth Edison takes all reasonable steps to mitigate losses related to any such indemnification claim. Also, in connection with the sale-leaseback transaction related to the Powerton and Joliet Stations in Illinois, EME agreed to indemnify the owner-lessors for specified environmental liabilities. These indemnities are not limited in term or amount. Due to the nature of the obligations under these indemnities, a maximum potential liability cannot be determined. Commonwealth Edison has 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 litigation discussed below under "—Contingencies—Midwest Generation New Source Review and Other Litigation," and one of the Powerton-Joliet owner-lessors has made a similar request for indemnification. Except as discussed below, EME has not recorded a liability related to these environmental indemnities.

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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 Midwest Generation's 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. 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 2013. There were approximately 218 cases for which Midwest Generation was potentially liable that had not been settled and dismissed at June 30, 2012. Midwest Generation had recorded a liability of $53 million at June 30, 2012 related to this contractual indemnity.
Indemnities Related to the Homer City Plant
In connection with the acquisition of the Homer City plant, Homer City agreed to indemnify the sellers with respect to specified environmental liabilities before and after the date of sale. EME guaranteed this obligation of Homer City. Also, in connection with the sale-leaseback transaction related to the Homer City plant, Homer City agreed to indemnify the owner-lessors for specified environmental liabilities. Due to the nature of the obligations under these indemnity provisions, they are not subject to a maximum potential liability and do not have expiration dates. EME has not recorded a liability related to this indemnity. For discussion of the New Source Review lawsuit filed against Homer City, see "—Contingencies—Homer City New Source Review and Other Litigation." Also, in connection with the Implementation Agreement discussed above, Homer City has agreed to enter into one or more implementation transactions, at the request of GECC, on the terms outlined in the Implementation Agreement, which include indemnification for specified matters.
Indemnities Provided under Asset Sale and Sale-Leaseback 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. At June 30, 2012, EME had recorded a liability of $27 million related to these matters.
In connection with the sale-leaseback transactions related to the Homer City plant 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. Under certain of these tax indemnity agreements, Homer City and Midwest Generation, as the lessees in the sale-leaseback transactions agreed to indemnify the respective owner-lessors for specified adverse tax consequences that could result from certain situations set forth in each tax indemnity agreement, including specified defaults under the respective leases. Although the Collins Station lease terminated in April 2004, Midwest Generation's indemnities in favor of its former lease equity investors are still in effect. EME provided similar indemnities in the sale-leaseback transactions related to the Powerton and Joliet Stations in Illinois. The potential indemnity obligations under these tax indemnity agreements could be significant. Due to the nature of these potential obligations, EME cannot determine a range of estimated obligations which would be triggered by a valid claim from the owner-lessors. EME has not recorded a liability for these matters.
In addition to the indemnity provided by Homer City, EME agreed to indemnify the owner-lessors in the sale-leaseback transaction related to the Homer City plant for certain negative federal income tax consequences should the rent payments be "levelized" for tax purposes and for potential foreign tax credit losses in the event that the owner-lessor's debt is characterized as recourse, rather than nonrecourse. This indemnity covers a limited range of possible tax consequences that are unrelated to performance under the lease.
Other Guarantees and Indemnities
EME guarantees Midwest Generation's payments under the Powerton and Joliet sale-leaseback agreements. A default by Midwest Generation in meeting its obligations could have an adverse impact on EME.
EME provides other indemnifications through contracts entered into in the normal course of business. These include, among other things, indemnities for specified environmental liabilities and for income taxes with respect to assets sold. EME's obligations under these agreements may or may not be limited in terms of time and/or amount, and in some instances EME may have recourse against third parties. EME cannot determine a range of estimates and has not recorded a liability related to these indemnities.

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Contingencies
In addition to the matters disclosed in these notes, EME is involved in other legal, tax and regulatory proceedings before various courts and governmental agencies regarding matters arising in the ordinary course of business. EME believes the outcome of these other proceedings, individually and in the aggregate, will not materially affect its results of operations or liquidity.
Midwest Generation New Source Review and Other Litigation
In August 2009, the United States Environmental Protection Agency (US EPA) and the State of Illinois filed a complaint in the Northern District of Illinois alleging that 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 (PSD) requirements and of the New Source Performance Standards of the Clean Air Act (CAA), including alleged requirements to obtain a construction permit and to install controls sufficient to meet best available control technology (BACT) emission rates. The US EPA also alleged that Midwest Generation and Commonwealth Edison violated certain operating permit requirements under Title V of the CAA. Finally, the US EPA alleged violations of certain opacity and particulate matter standards at the Midwest Generation plants. In addition to seeking penalties ranging from $25,000 to $37,500 per violation, per day, the complaint called for an injunction ordering Midwest Generation to install controls sufficient to meet BACT emission rates at all units subject to the complaint and other remedies. The remedies sought by the plaintiffs in the lawsuit could go well beyond the requirements of the Combined Pollutant Standard (CPS). Several Chicago-based environmental action groups intervened in the case.
Nine of the ten PSD claims raised in the complaint have been dismissed, along with claims related to alleged violations of Title V of the CAA, to the extent based on the dismissed PSD claims, and all claims asserted against Commonwealth Edison and EME. The court denied a motion to dismiss a claim by the Chicago-based environmental action groups for civil penalties in the remaining PSD claim, but noted that the plaintiffs will be required to convince the court that the statute of limitations should be equitably tolled. The court did not address other counts in the complaint that allege violations of opacity and particulate matter limitations under the Illinois State Implementation Plan and Title V of the CAA. The dismissals have been certified as "partial final judgments" capable of appeal, and an appeal is pending before the Seventh Circuit Court of Appeals. The remaining claims have been stayed pending the appeal. In February 2012, certain of the environmental action groups that had intervened in the case entered into an agreement with Midwest Generation to dismiss without prejudice all of their opacity claims as to all defendants. The agreed upon motion to dismiss was approved by the court on March 26, 2012.
In January 2012, two complaints were filed against Midwest Generation in Illinois state court by residents living near the Crawford and Fisk Stations on behalf of themselves and all others similarly situated, each asserting claims of nuisance, negligence, trespass, and strict liability. The plaintiffs seek to have their suits certified as a class action and request injunctive relief, as well as compensatory and punitive damages. The complaints are similar to two complaints previously filed in the Northern District of Illinois, which were dismissed in October 2011 for lack of federal jurisdiction. In March 2012, Midwest Generation filed motions to dismiss the cases, which are pending.
Adverse decisions in these cases could involve penalties, remedial actions and damages that could have a material impact on the financial condition and results of operations of Midwest Generation and EME. EME cannot predict the outcome of these matters or estimate the impact on the Midwest Generation plants, or its and Midwest Generation's results of operations, financial position or cash flows. EME has not recorded a liability for these matters.
Homer City New Source Review and Other Litigation
In January 2011, the US EPA filed a complaint in the Western District of Pennsylvania against Homer City, the sale-leaseback owner participants of the Homer City plant, and two prior owners of the Homer City plant. The complaint alleged violations of the PSD and Title V provisions of the CAA, as a result of projects in the 1990s performed by prior owners without PSD permits and the subsequent failure to incorporate emissions limitations that meet BACT into the station's Title V operating permit. In addition to seeking penalties ranging from $32,500 to $37,500 per violation, per day, the complaint called for an injunction ordering Homer City to install controls sufficient to meet BACT emission rates at all units subject to the complaint and for other remedies. The PADEP, the State of New York and the State of New Jersey intervened in the lawsuit. In October 2011, all of the claims in the US EPA's lawsuit were dismissed with prejudice. An appeal of the dismissal is pending before the Third Circuit Court of Appeals.
Also in January 2011, two residents filed a complaint in the Western District of Pennsylvania, on behalf of themselves and all others similarly situated, against Homer City, the sale-leaseback owner participants of the Homer City plant, two prior owners of the Homer City plant, EME, and Edison International, claiming that emissions from the Homer City plant had adversely affected their health and property values. The plaintiffs sought to have their suit certified as a class action and

21
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requested injunctive relief, the funding of a health assessment study and medical monitoring, as well as compensatory and punitive damages. In October 2011, the claims in the purported class action lawsuit that were based on the federal CAA were dismissed with prejudice, while state law statutory and common law claims were dismissed without prejudice to re-file in state court should the plaintiffs choose to do so. EME does not know whether the plaintiffs will file a complaint in state court.
In February 2012, Homer City received a 60-day Notice of Intent to Sue indicating the Sierra Club’s intent to file a citizen lawsuit alleging violations of emissions standards and limitations under the CAA and the Pennsylvania Air Pollution Control Act.
Adverse decisions in these cases could involve penalties, remedial actions and damages that could have a material impact on the financial condition and results of operations of Homer City and EME. EME cannot predict the outcome of these matters or estimate the impact on the Homer City plant, or its and Homer City's results of operations, financial position or cash flows. EME has not recorded a liability for these matters.
Environmental Remediation
Legislative and regulatory activities by federal, state and local authorities in the United States relating to energy and the environment impose numerous restrictions and requirements with respect to the operation of EME subsidiaries' existing facilities and affect the timing, cost, location, design, construction, and operation of new facilities by EME's subsidiaries, as well as the cost of mitigating the environmental impacts of past operations.
With respect to potential liabilities arising under the Comprehensive Environmental Response, Compensation and Liability Act of 1980, commonly referred to as CERCLA, or similar laws for the investigation and remediation of contaminated property, EME accrues a liability to the extent the costs are probable and can be reasonably estimated. Midwest Generation had accrued a probable amount of approximately $9 million at June 30, 2012 for estimated environmental investigation and remediation costs for four stations at the Midwest Generation 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. EME also has identified sites for which a reasonable estimate cannot be made. 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 require 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.

Note 10. Environmental Developments
Hazardous Air Pollutant Regulations
In December 2011, the US EPA announced the Mercury and Air Toxics Standards (MATS) rule, limiting emissions of hazardous air pollutants from coal- and oil-fired electrical generating units. The rule was published in the Federal Register on February 16, 2012, and became effective on April 16, 2012. A number of parties have filed notices of appeal challenging the rule.
Greenhouse Gas Regulation
In March 2012, the US EPA announced proposed carbon dioxide emissions limits for new power plants. The status of the US EPA's efforts to develop greenhouse gas emissions performance standards for existing plants is unknown.
In June 2012, the U.S. Court of Appeals for the D.C. Circuit dismissed the challenge by industry groups and some states to the Prevention of Significant Deterioration and Title V Greenhouse Gas Tailoring Rule, known as the "GHG tailoring rule."
In July 2012, the US EPA published a final rule maintaining the CO2 equivalent emissions thresholds (for purposes of PSD and Title V permitting) originally established in the GHG tailoring rule.
Greenhouse Gas Litigation
In March 2012, the federal district court in Mississippi dismissed, in its entirety, the purported class action complaint filed by private citizens in May 2011, naming a large number of defendants, including EME and three of its wholly owned subsidiaries, for damages allegedly arising from Hurricane Katrina. In April 2012, the plaintiffs filed an appeal with the Fifth Circuit Court of Appeals. Plaintiffs allege that the defendants' activities resulted in emissions of substantial quantities of greenhouse gases that have contributed to climate change and sea level rise, which in turn are alleged to have increased the destructive force of Hurricane Katrina. The lawsuit alleges causes of action for negligence, public and private nuisance, and trespass, and seeks unspecified compensatory and punitive damages. The claims in this lawsuit are nearly identical to a subset

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of the claims that were raised against many of the same defendants in a previous lawsuit that was filed in, and dismissed by, the same federal district court where the current case has been filed.

Note 11. Accumulated Other Comprehensive Loss
Accumulated other comprehensive loss consisted of the following:
(in millions)
Unrealized
Losses on Cash
Flow Hedges
 
Unrecognized
Losses and Prior Service
Adjustments, Net1
 
Accumulated
Other
Comprehensive
Loss
Balance at December 31, 2011
$
(34
)
 
$
(60
)
 
$
(94
)
Current period change
(23
)
 
2

 
(21
)
Balance at June 30, 2012
$
(57
)
 
$
(58
)
 
$
(115
)
1 
For further detail, see Note 8—Compensation and Benefit Plans.
Included in accumulated other comprehensive loss at June 30, 2012 was $12 million, net of tax, of unrealized gains on commodity-based cash flow hedges, and $69 million, net of tax, of unrealized losses related to interest rate hedges. The maximum period over which a commodity cash flow hedge is designated is through May 31, 2014.
Unrealized gains on commodity hedges consist of futures and forward electricity contracts that qualify for hedge accounting. These gains arise because current forecasts of future electricity prices in these markets are lower than the contract prices. Approximately $13 million of unrealized gains on cash flow hedges, net of tax, are expected to be reclassified into earnings during the next 12 months. Management expects that reclassification of net unrealized gains will increase energy revenues 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.

Note 12. Supplemental Cash Flows Information
 
Six Months Ended June 30,
(in millions)
2012
 
2011
Cash paid (received)
 
 
 
Interest (net of amount capitalized)1
$
154

 
$
142

Income taxes
(9
)
 
6

Cash payments under plant operating leases
124

 
189

 
 
 
 
Non-cash activities from vendor financing
$
6

 
$
19

Purchase of equipment with notes payable
$
—

 
$
56

1 
Interest paid for the six months ended June 30, 2012 and 2011 was $167 million and $158 million, respectively. Interest capitalized for the six months ended June 30, 2012 and 2011 was $13 million and $16 million, respectively.
Accrued capital expenditures at June 30, 2012 and 2011 were $25 million and $47 million, respectively. Accrued capital expenditures will be included as an investing activity in the consolidated statements of cash flows in the period paid.


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Note 13. Discontinued Operations
Summarized financial information for discontinued operations of foreign subsidiaries is as follows:
 
Three Months Ended
June 30,
 
Six Months Ended
June 30,
(in millions)
2012
 
2011
 
2012
 
2011
Income (Loss) before income taxes
$
2

 
$
—

 
$
2

 
$
(2
)
Provision for income taxes
2

 
1

 
3

 
1

Loss from operations of discontinued foreign subsidiaries
$
—

 
$
(1
)
 
$
(1
)
 
$
(3
)
The 2012 and 2011 losses were primarily due to foreign exchange rate changes and income taxes.

Note 14. Restructuring Activities
In conjunction with the decision to shut down its Fisk and Crawford Stations at the Midwest Generation plants in September 2012, EME plans to reduce approximately 200 positions from its plant operation and administrative staff in 2012. EME recorded a charge of $9 million (pre-tax) in the second quarter of 2012 related to severance and other employee benefits due to employees affected by the planned shutdowns. The charge was included in administrative and general expense on EME's consolidated statement of operations.
Midwest Generation has sold capacity forward through May 31, 2015 for both Fisk and Crawford. Midwest Generation would expect to cover its capacity obligations associated with the Fisk and Crawford units through a combination of improved fleet performance, fleet capacity not previously sold forward and, if necessary, market transactions.
In connection with the shut down of these stations, EME expects a tax deduction equal to its tax basis in the facilities, although realization of these tax benefits may not occur for several years. At June 30, 2012, the tax basis of the Fisk and Crawford Stations were $58 million and $80 million, respectively. For further information regarding the tax benefits, see Note 1—Summary of Significant Accounting Policies—Liquidity and Restructuring Activities.

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ITEM 2.
MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS
This quarterly report on Form 10-Q 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 from those currently expected, or that otherwise could impact EME or its subsidiaries, include but are not limited to:
•
EME's ability to meet its liquidity requirements during periods of operating losses and capital spending programs;
•
EME's ability to restructure its debt obligations and stabilize its capital structure;
•
EME's significant cash requirements and its limited ability to borrow funds and access the capital markets on reasonable terms;
•
supply and demand for electric capacity and energy, and the resulting prices and dispatch volumes, in the wholesale markets to which EME's generating units have access;
•
volatility of market prices for energy and capacity;
•
the difficulty of predicting wholesale prices, transmission congestion, energy demand, and other aspects of the complex and volatile markets in which EME and its subsidiaries participate;
•
EME's continued participation and the continued participation by EME's subsidiaries in tax-allocation and payment agreements with EME's respective affiliates;
•
environmental laws and regulations, at both state and federal levels, or changes in the application of those laws, that could require additional expenditures or otherwise affect EME's cost and manner of doing business, including compliance with the CPS (at Midwest Generation), CAIR or CSAPR (as applicable) and the MATS rule;
•
the completion of the transactions for the divestiture of Homer City's leasehold interest and related assets and liabilities pursuant to the terms of the Implementation Agreement between Homer City and GECC, and the timing and structure of such transactions;
•
the cost and availability of fuel, sorbents, and other commodities used for power generation and emission controls, and of related transportation services;
•
the cost and availability of emission credits or allowances;
•
transmission congestion in and to each market area and the resulting differences in prices between delivery points;
•
the availability and creditworthiness of counterparties, and the resulting effects on liquidity in the power and fuel markets in which EME and its subsidiaries operate and/or the ability of counterparties to pay amounts owed to EME in excess of collateral provided in support of their obligations;
•
governmental, statutory, regulatory or administrative changes or initiatives affecting EME or the electricity industry generally, including the market structure rules applicable to each market and price mitigation strategies adopted by ISOs and RTOs;
•
market volatility and other market conditions that could increase EME's obligations to post collateral beyond the amounts currently expected, and the potential effect of such conditions on the ability of EME and its subsidiaries to provide sufficient collateral in support of their hedging activities and purchases of fuel;
•
the potential for distributions of cash or assets and other actions, subject to contractual obligations and applicable law, that may alter the portion of Edison International's portfolio of assets held and developed by EME;
•
completion of permitting and construction of EME's capital projects;
•
weather conditions, natural disasters and other unforeseen events;

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•
the extent of additional supplies of capacity, energy and ancillary services from current competitors or new market entrants, including the development of new generation facilities, and technologies that may be able to produce electricity at a lower cost than EME's generating facilities and/or increased access by competitors to EME's markets as a result of transmission upgrades;
•
competition in all aspects of EME's business;
•
operating risks, including equipment failure, availability, heat rate, output, costs of repairs and retrofits, and availability and cost of spare parts;
•
creditworthiness of suppliers and other project participants and their ability to deliver goods and services under their contractual obligations to EME and its subsidiaries or to pay damages if they fail to fulfill those obligations;
•
effects of legal proceedings, changes in or interpretations of tax laws, rates or policies, and changes in accounting standards;
•
general political, economic and business conditions; and
•
EME's ability to attract and retain skilled people.
Additional information about risks and uncertainties, including more detail about the factors described above, is contained throughout this MD&A and in "Item 1A. Risk Factors" on page 20 of EME's annual report on Form 10-K for the year ended December 31, 2011. Readers are urged to read this entire quarterly report on Form 10-Q and the annual report on Form 10-K for the year ended December 31, 2011, including the information incorporated by reference, and to 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, 2011, and as compared to the second quarter ended June 30, 2011. 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, 2011.

MANAGEMENT'S OVERVIEW

Highlights of Operating Results
Net loss attributable to EME common shareholder is composed of the following components:
 
Three Months Ended
June 30,
 
 
 
Six Months Ended
 June 30,
 
 
(in millions)
2012
 
2011
 
Change
 
2012
 
2011
 
Change
Net loss attributable to EME common shareholder
$
(109
)
 
$
(32
)
 
$
(77
)
 
$
(193
)
 
$
(52
)
 
$
(141
)
Less: Non-core items - net of tax
 
 
 
 
 
 
 
 
 
 
 
Homer City
(29
)
 
(5
)
 
(24
)
 
(52
)
 
(15
)
 
(37
)
Loss from discontinued operations
—

 
(1
)
 
1

 
(1
)
 
(3
)
 
2

Total non-core items
(29
)
 
(6
)
 
(23
)
 
(53
)
 
(18
)
 
(35
)
Core Loss
$
(80
)
 
$
(26
)
 
$
(54
)
 
$
(140
)
 
$
(34
)
 
$
(106
)
EME's earnings (losses) are prepared in accordance with GAAP. Management uses core earnings (losses) internally for financial planning and for analysis of performance. Core earnings (losses) are also used when communicating with analysts and investors regarding EME's earnings results to facilitate comparisons of EME's performance from period to period. Core earnings (losses) are a non-GAAP financial measure and may not be comparable to those of other companies. Core earnings (losses) are defined as net income (loss) attributable to EME's shareholder excluding income (losses) from discontinued operations and income or loss from significant discrete items that management does not consider representative of ongoing earnings, such as: exit activities, sale of assets, early debt extinguishment costs, other activities that are no longer continuing, asset impairments, and certain tax, regulatory or legal proceedings. EME classified the results of Homer City, including the costs incurred in connection with the expected divestiture, as non-core for the first half of both 2012 and 2011 due to the plan described below to transition ownership of the leasehold interest to the owner-lessors.

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EME's operating loss increased significantly in the first half of 2012 compared to the first half of 2011 due to lower realized energy and capacity prices at its coal plants and lower generation at the Midwest Generation plants. The abundance of low-priced natural gas has continued to result in increased competition from natural gas-fired generating units in the markets in which Midwest Generation operates, and generation has been correspondingly affected. In addition, effective January 1, 2012, a favorable long-term rail contract that supplied Midwest Generation's fleet expired and was replaced by a higher priced contract.
EME's core loss in the second quarter 2012 increased compared to the second quarter 2011 primarily due to the following pre-tax items:
•
$45 million decrease in Midwest Generation results primarily due to lower average realized energy and capacity prices and higher fuel prices, partially offset by lower planned maintenance costs.
•
$15 million lower income from distributions received from the Doga project.
•
$11 million decrease in energy trading due to decreased revenues from trading power contracts and congestion.
•
$9 million decrease in renewable energy income primarily due to income allocated to third-party investors of Capistrano Wind Partners, partially offset by results of operations from projects that achieved commercial operations after the second quarter of 2011.
EME's core loss for the six months ended June 30, 2012 increased compared to the six months ended June 30, 2011 primarily due to the following pre-tax items:
•
$140 million decrease in Midwest Generation results primarily due to lower average realized energy and capacity prices, higher fuel prices and reduced generation, partially offset by lower planned maintenance costs.
•
$15 million lower income from distributions received from the Doga project.
•
$10 million increase in interest expense due to new energy project financings ($7 million) and lower capitalized interest ($3 million).

EME Liquidity and Restructuring Activities
At June 30, 2012, EME, and its subsidiaries without contractual dividend restrictions, had corporate cash and cash equivalents of $879 million, which includes Midwest Generation's cash and cash equivalents of $177 million. EME and Midwest Generation's previous revolving credit agreements have been terminated or expired and no longer are sources of liquidity. At June 30, 2012, EME had $3.7 billion of unsecured notes outstanding, $500 million of which mature in June 2013.
As indicated above, EME is currently experiencing operating losses due to lower realized energy and capacity prices, higher fuel costs and lower generation at the Midwest Generation plants. Forward market prices indicate that these trends are expected to continue for a number of years. As a result, EME expects that it will incur further reductions in cash flow and losses in the current year and in subsequent years. A continuation of these adverse trends coupled with pending debt maturities and the need to retrofit its Midwest Generation plants to comply with governmental regulations will exhaust EME's liquidity. Consequently, EME will need to consider all options available to it, including potential sales of assets, restructuring, reorganization of its capital structure, or conservation of cash that would be otherwise applied to the payment of obligations. EME has entered into non-disclosure and engagement agreements with advisors representing certain of its unsecured bondholders for the purpose of engaging in discussions with such advisors and Edison International regarding EME's financial condition. Absent a restructuring of its obligations, based on current projections, EME is not expected to have sufficient liquidity to repay the $500 million debt obligation due in June 2013. As a result, EME may need to file for protection under Chapter 11 of the U.S. Bankruptcy Code.
Bankruptcy proceedings could lead to a change of control of EME, which would result in the termination of EME's tax-allocation agreement. At June 30, 2012, EME had recognized $323 million of net deferred tax benefits based on continued ownership by Edison International and inclusion of EME in the consolidated income tax returns of Edison International and its subsidiaries. If it is more likely than not that EME would no longer continue to participate as part of the consolidated group of Edison International, EME would record a valuation allowance to reduce the carrying value of its net deferred tax benefit and record a material charge against earnings. The termination of the tax-allocation agreement could adversely affect EME's long-term liquidity because realization of the value of tax benefits generated by EME could be deferred until such time that EME, or a subsequent owner of EME, had the ability to utilize such benefits. There is no assurance as to when, or whether, this might occur.

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The accompanying consolidated financial statements have been prepared assuming that EME will continue as a going concern. Financial statements prepared on this basis assume the realization of assets and the satisfaction of liabilities in the normal course of business for the 12-month period following the date of these financial statements. There is no assurance that EME will be able to continue as a going concern.

Midwest Generation's Dependence on EME
Midwest Generation is largely dependent on EME to fund cash flow deficits and environmental retrofits. EME has no obligation to make capital contributions to Midwest Generation and may be unable to do so. Furthermore, Midwest Generation had $1.329 billion of notes receivable from EME at June 30, 2012 with payments used to meet its rent obligations under the Powerton and Joliet sale-leaseback agreements. If EME is unable to make payments on its notes, Midwest Generation may in turn be unable to make rent payments under the Powerton-Joliet leases. Failure to pay rent would be an event of default under the Powerton-Joliet leases that could result in termination of the leases, loss of control over the use of the Powerton and Joliet Stations and a claim for termination value under the lease agreements. Accordingly, if Midwest Generation is unable to obtain financial support from EME or other sources, Midwest Generation may need to file for protection under Chapter 11 of the U.S. Bankruptcy Code. A bankruptcy of either EME or Midwest Generation would also be an event of default under the Powerton-Joliet leases.

Midwest Generation Environmental Compliance Plans and Costs
During the second quarter of 2012, Midwest Generation continued to develop and implement a compliance program that includes the operation of ACI systems for mercury removal, upgrades to particulate removal systems and the use of dry sorbent injection, combined with the use of low sulfur PRB coal, to meet emissions limits for criteria pollutants, such as NOx and SO2 as well as for hazardous air pollutants, such as mercury, acid gas and non-mercury metals.
Apart from the Fisk and Crawford Stations, which will be shut down in September 2012, decisions whether or not to proceed with retrofitting of any particular remaining units to comply with CPS requirements for SO2 emissions, including those that have received permits, are subject to a number of factors, such as market conditions, regulatory and legislative developments, liquidity and forecasted commodity prices and capital and operating costs applicable at the time decisions are required or made. Midwest Generation may also elect to shut down units, instead of installing controls, to be in compliance with the CPS. Final decisions on whether to install controls, to install particular kinds of controls, and to actually expend capital or continue with the expenditure of capital will be made as required, subject to the requirements of the CPS and other applicable regulations. Units that are not retrofitted may continue to operate for as long as regulations and law allow.
Based on work to date, Midwest Generation estimates the remaining cost of retrofitting Powerton Units 5 and 6, Joliet Units 7 and 8 and Will County Units 3 and 4, using dry scrubbing with sodium-based sorbents and upgrading particulate removal systems, to be approximately $625 million at June 30, 2012. It is less likely that retrofits will be made to Joliet Unit 6 and the Waukegan Station. The estimated cost of retrofitting Joliet Unit 6, if made, would be approximately $75 million, while the estimated cost of retrofitting the Waukegan Station, if made, would be approximately $160 million. Final decisions to shut down units will be made in light of the timing requirements under the CPS and other applicable environmental regulations, based on the economic projections of those retrofits, on a unit-by-unit basis, at the time the decision is made. For further discussion related to the impairment policy on Midwest Generation's unit of account, refer to "Critical Accounting Estimates and Policies—Impairment of Long-Lived Assets" in Item 7 on page 56 of EME's annual report on Form 10-K for the year ended December 31, 2011.

Homer City Lease
Homer City is not expected to have sufficient cash flow to meet its obligations, including funding capital improvements and the rent payment due on October 1, 2012. Homer City made the required April 1, 2012 senior rent payment but did not make the April 1, 2012 payment of equity rent. On March 30, 2012, Homer City was granted a waiver by the owner-lessors of any rent default event with respect to the payment of the equity rent for all purposes other than restrictions on distributions from Homer City, including repayment of its intercompany loan, and the $48 million senior rent reserve letter of credit remains in place. Homer City's liquidity has continued to deteriorate during the first half of 2012. GECC, the beneficial owner of a majority of the owner-lessors, has been funding the construction activities associated with the capital improvements and providing other credit support. Homer City is not expected to have sufficient cash flow to meet its operating expenses without continued support from GECC or to fund other obligations during 2012, including the rent payment due on October 1, 2012. This may require Homer City to suspend plant operations until sufficient working capital is obtained. For further discussion of the Homer City lease, refer to "Management's Overview—Homer City Lease" in Item 7 on page 30 of EME's annual report on Form 10-K for the year ended December 31, 2011 and see "Edison Mission Energy and Subsidiaries Notes to

28
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Consolidated Financial Statements—Note 9. Commitments and Contingencies—Homer City Lease and Environmental Project."
On March 29, 2012, Homer City and GECC entered into an Implementation Agreement (the Agreement) with respect to the Homer City plant. As addressed by the Agreement, an affiliate of the GECC-controlled owner-lessors of the Homer City plant has entered into an engineering, procurement and construction agreement and has executed related agreements for the construction of environmental improvements. GECC has discretion over all decisions related to such construction agreements. Homer City agreed to conduct its business as set forth in the Agreement and to use commercially reasonable efforts to provide assistance to GECC and its affiliates in connection with the construction agreements. The estimated cost of installing SO2 and particulate emissions control equipment for Units 1 and 2 of the Homer City plant is expected to be approximately $700 million to $750 million. On April 2, 2012, Homer City received the permit to construct such improvements from PADEP.
The Agreement also requires Homer City, at the request of GECC, to enter into one or more implementation transactions, as defined in the Agreement, for the divestiture of its leasehold interest in the Homer City plant (and, under certain circumstances, related assets and liabilities as specified) and to assist GECC in obtaining certain third-party consents or waivers. Homer City and GECC also agreed to enter into a transition services agreement in connection with any implementation transaction. There is no assurance that Homer City and GECC will actually consummate a divestiture transaction as contemplated by the Agreement.
Certain divestitures of Homer City's leasehold interest in the plant are subject to consent rights of the holders of the secured lease obligation bonds issued in connection with the original sale-leaseback transaction. GECC is currently engaged in discussions and has reached an agreement in principle on a non-binding restructuring term sheet with certain of the holders of the secured lease obligation bonds regarding amendments to the terms of the 8.137% Senior Secured Bonds due 2019 and the 8.734% Senior Secured Bonds due 2026, each issued by Homer City Funding LLC. Even though an agreement in principle has been reached with certain holders of the secured lease obligation bonds, that agreement may not be approved by the secured lease obligation bondholders as required under the operative documents to effectuate the necessary modifications to the terms of the bonds. If an agreement to modify the terms of the bonds is not approved and consummated, then it is possible that Homer City could become the subject of bankruptcy proceedings.

Environmental Regulation Developments
For a discussion of environmental regulation developments, see "Edison Mission Energy and Subsidiaries Notes to Consolidated Financial Statements—Note 10. Environmental Developments."


29
Table of Contents

RESULTS OF OPERATIONS

Results of Continuing Operations

Overview
EME operates in one line of business, independent power production. The following table shows the adjusted operating income (loss) (AOI) of EME's projects:
 
Three Months Ended
June 30,
 
Six Months Ended
June 30,
(in millions)
2012
 
2011
 
2012
 
2011
Midwest Generation plants
$
(97
)
 
$
(52
)
 
$
(137
)
 
$
3

Homer City plant
(48
)
 
(10
)
 
(86
)
 
(26
)
Renewable energy projects
15

 
24

 
45

 
45

Energy trading
30

 
41

 
49

 
56

Big 4 projects
9

 
9

 
8

 
11

Sunrise
9

 
6

 
9

 
(1
)
Doga
11

 
26

 
11

 
26

Westside projects
(1
)
 
(1
)
 
(3
)
 
(1
)
Other projects
4

 
5

 
6

 
9

Other operating income
—

 
1

 
—

 
1

 
(68
)
 
49

 
(98
)
 
123

Corporate administrative and general
(34
)
 
(32
)
 
(67
)
 
(66
)
Corporate depreciation and amortization
(5
)
 
(6
)
 
(11
)
 
(12
)
AOI1
$
(107
)
 
$
11

 
$
(176
)
 
$
45

1 
AOI is equal to operating income (loss) under GAAP, plus equity in income (loss) of unconsolidated affiliates, dividend income from projects, production tax credits, other income and expenses, and net income (loss) attributable to noncontrolling interests. Production tax credits are recognized as wind energy is generated based on a per-kilowatt-hour rate prescribed in applicable federal and state statutes. AOI is a non-GAAP performance measure and may not be comparable to those of other companies. Management believes that inclusion of earnings of unconsolidated affiliates, dividend income from projects, production tax credits, other income and expenses, and net income (loss) attributable to noncontrolling interests in AOI is meaningful for investors as these components are integral to the operating results of EME.
The following table reconciles AOI to operating loss as reflected on EME's consolidated statements of operations:
 
Three Months Ended
June 30,
 
Six Months Ended
June 30,
(in millions)
2012
 
2011
 
2012
 
2011
AOI
$
(107
)
 
$
11

 
$
(176
)
 
$
45

Less:
 
 
 
 
 
 
 
Equity in income of unconsolidated affiliates
18

 
17

 
17

 
12

Dividend income from projects
11

 
27

 
11

 
28

Production tax credits
17

 
19

 
36

 
37

Other income, net
—

 
2

 
—

 
5

Net income attributable to noncontrolling interests
(5
)
 
—

 
(7
)
 
—

Operating Loss
$
(148
)
 
$
(54
)
 
$
(233
)
 
$
(37
)


30
Table of Contents

Adjusted Operating Income from Consolidated Operations

Midwest Generation Plants
The following table presents additional data for the Midwest Generation plants:
 
Three Months Ended
June 30,
 
Six Months Ended
June 30,
(in millions)
2012
 
2011
 
2012
 
2011
Operating Revenues
$
213

 
$
280

 
$
446

 
$
631

Operating Expenses

 
 
 
 
 
 
Fuel
143

 
107

 
260

 
233

Plant operations
120

 
164

 
229

 
282

Plant operating leases
18

 
18

 
37

 
37

Depreciation and amortization
22

 
29

 
43

 
58

Loss on disposal and asset impairments
2

 
9

 
4

 
9

Administrative and general
5

 
5

 
10

 
11

Total operating expenses
310

 
332

 
583

 
630

Operating Income (Loss)
(97
)
 
(52
)
 
(137
)
 
1

Other Income
—

 
—

 
—

 
2

AOI
$
(97
)
 
$
(52
)
 
$
(137
)
 
$
3

Statistics1
 
 
 
 
 
 
 
Generation (in GWh)
5,467


5,560

 
10,806

 
13,030

Aggregate plant performance
 
 
 
 
 
 
 
Equivalent availability
77.4
%

63.7
%
 
79.2
%
 
75.3
%
Capacity factor
48.5
%

49.3
%
 
47.9
%
 
58.1
%
Load factor
62.7
%

77.4
%
 
60.5
%
 
77.2
%
Forced outage rate
4.6
%

5.0
%
 
4.5
%
 
5.1
%
Average realized price/MWh
$
32.43


$
37.59

 
$
33.02

 
$
37.05

Capacity revenues only (in millions)
$
35

 
$
68

 
$
84

 
$
145

Average realized fuel costs/MWh
$
24.82


$
18.88

 
$
23.68

 
$
17.65

1 
For an explanation of how the statistical data is determined, see "—Reconciliation of Non-GAAP Disclosures—Coal Plants and Statistical Definitions."
AOI from the Midwest Generation plants decreased $45 million for the second quarter of 2012 compared to the corresponding period of 2011. The second quarter decrease in AOI was primarily attributable to lower average realized energy prices, lower capacity prices and higher fuel prices, partially offset by lower planned maintenance costs.
AOI from the Midwest Generation plants decreased $140 million for the six months ended June 30, 2012 compared to the corresponding period of 2011. The 2012 decrease in AOI was primarily attributable to lower average realized energy prices, lower capacity prices, higher fuel prices and reduced generation, partially offset by lower planned maintenance costs. Reduced generation primarily resulted from lower economic dispatch.
Included in fuel costs were unrealized losses of $7 million and $1 million during the second quarters of 2012 and 2011, respectively, and $4 million and $2 million for the six months ended June 30, 2012 and 2011, respectively, due to oil futures contracts that were accounted for as economic hedges. These contracts were entered into as hedges of the variable fuel price component of rail transportation costs.


31
Table of Contents

Homer City
The following table presents additional data for the Homer City plant, which is being classified as a non-core earnings item under "Management's Overview—Highlights of Operating Results":
 
Three Months Ended
June 30,
 
Six Months Ended
June 30,
(in millions)
2012
 
2011
 
2012
 
2011
Operating Revenues
$
82

 
$
136

 
$
182

 
$
251

Operating Expenses
 
 

 
 
 
 
Fuel
67

 
63

 
151

 
115

Plant operations
25

 
50

 
44

 
97

Plant operating leases
22

 
26

 
41

 
51

Depreciation and amortization
—

 
5

 
—

 
10

Loss on disposal and asset impairments
10

 
—

 
21

 
—

Administrative and general
6

 
2

 
11

 
4

Total operating expenses
130

 
146

 
268

 
277

Operating Loss
(48
)
 
(10
)
 
(86
)
 
(26
)
AOI
$
(48
)
 
$
(10
)
 
$
(86
)
 
$
(26
)
Statistics1
 
 
 
 
 
 
 
Generation (in GWh)
2,016


2,226

 
4,623

 
4,169

Equivalent availability
78.5
%

66.6
%
 
86.0
%
 
63.0
%
Capacity factor
49.0
%

54.1
%
 
56.2
%
 
50.9
%
Load factor
62.4
%

81.2
%
 
65.4
%
 
80.9
%
Forced outage rate
4.9
%

15.3
%
 
4.6
%
 
21.3
%
Average realized energy price/MWh
$
31.24


$
48.98

 
$
31.53

 
$
47.21

Capacity revenues only (in millions)
$
18

 
$
24

 
$
36

 
$
48

Average fuel costs/MWh
$
33.31


$
28.22

 
$
32.61

 
$
27.63

1 
For an explanation of how the statistical data is determined, see "—Reconciliation of Non-GAAP Disclosures—Coal Plants and Statistical Definitions."
AOI from the Homer City plant decreased $38 million and $60 million for the three and six months ended June 30, 2012, respectively, as compared to the corresponding periods of 2011. The decreases in AOI were primarily attributable to lower energy margins and asset impairment charges in 2012, partially offset by a decline in plant maintenance costs due to outages at Units 1 and 2 during the first quarter of 2011 and due to lower planned overhauls in the second quarter of 2012. Lower energy margins were due to lower average realized energy prices and higher coal and emission allowance costs. Asset impairment charges related to the write-off of leasehold improvements and prepaid rent incurred during the first half of 2012, which did not increase the fair value of EME's leasehold interest, for reasons as described in "Management's Overview", and therefore were fully impaired. In addition, plant operating lease expense and depreciation expense decreased in the first half of 2012 compared to the first half of 2011 as a result of the impairment of leasehold improvements and prepaid rent related to the Homer City lease in the fourth quarter of 2011. The impairment resulted in a new levelized rent schedule.


32
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Reconciliation of Non-GAAP Disclosures—Coal Plants and Statistical Definitions

Average Realized Energy Price
The average realized energy price reflects the average price at which energy is sold into the market including the effects of hedges, real-time and day-ahead sales and PJM fees and ancillary services. It is determined by dividing (i) operating revenues less unrealized gains (losses) and other non-energy related revenues by (ii) generation as shown in the table below. Revenues related to capacity sales are excluded from the calculation of average realized energy price.
Midwest Generation Plants
(in millions)
Three Months Ended
June 30,
 
Six Months Ended
June 30,
2012
 
2011
 
2012
 
2011
Operating revenues
$
213

 
$
280

 
$
446

 
$
631

Less:
 
 
 
 
 
 
 
Unrealized (gains) losses
1

 
(2
)
 
(3
)
 
(2
)
Capacity and other revenues
(36
)
 
(69
)
 
(86
)
 
(146
)
Realized revenues
$
178

 
$
209

 
$
357

 
$
483

Generation (in GWh)
5,467

 
5,560

 
10,806

 
13,030

Average realized energy price/MWh
$
32.43

 
$
37.59

 
$
33.02

 
$
37.05

Homer City Plant
(in millions)
Three Months Ended
June 30,
 
Six Months Ended
June 30,
2012
 
2011
 
2012
 
2011
Operating revenues
$
82

 
$
136

 
$
182

 
$
251

Less:
 
 

 
 
 
 
Unrealized gains
—

 
(2
)
 
—

 
(5
)
Capacity and other revenues
(18
)
 
(24
)
 
(36
)
 
(49
)
Realized revenues
$
64

 
$
110

 
$
146

 
$
197

Generation (in GWh)
2,016

 
2,226

 
4,623

 
4,169

Average realized energy price/MWh
$
31.24

 
$
48.98

 
$
31.53

 
$
47.21

The average realized energy price is presented as an aid in understanding the operating results of the coal plants. Average realized energy price is a non-GAAP performance measure since such statistical measure excludes unrealized gains or losses recorded as operating revenues. This measure may not be comparable to those of other companies. Management believes that the average realized energy price is meaningful for investors as this information reflects the impact of hedge contracts at the time of actual generation in period-over-period comparisons or as compared to real-time market prices. A reconciliation of the operating revenues of the coal plants presented in the preceding table and renewable energy projects presented in "—Renewable Energy Projects" to consolidated operating revenues is set forth below:
 
Three Months Ended
June 30,
 
Six Months Ended
June 30,
(in millions)
2012
 
2011
 
2012
 
2011
Operating revenues
 
 
 
 
 
 
 
Midwest Generation plants
$
213

 
$
280

 
$
446

 
$
631

Homer City plant
82

 
136

 
182

 
251

Renewable energy projects
63

 
59

 
135

 
111

Other revenues
48

 
61

 
86

 
93

Consolidated operating revenues as reported
$
406

 
$
536

 
$
849

 
$
1,086



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Average Realized Fuel Costs
The average realized fuel costs reflect the average cost per MWh at which fuel is consumed for generation sold into the market, including emission allowance costs and the effects of hedges. It is determined by dividing (i) fuel costs adjusted for unrealized gains (losses) by (ii) generation as shown in the table below:
Midwest Generation Plants
(in millions)
Three Months Ended
June 30,
 
Six Months Ended
June 30,
2012
 
2011
 
2012
 
2011
Fuel costs
$
143

 
$
107

 
$
260

 
$
233

Add back:
 
 
 
 
 
 
 
Unrealized losses
(7
)
 
(1
)
 
(4
)
 
(2
)
Realized fuel costs
$
136

 
$
106

 
$
256

 
$
231

Generation (in GWh)
5,467

 
5,560

 
10,806

 
13,030

Average realized fuel costs/MWh
$
24.82

 
$
18.88

 
$
23.68

 
$
17.65

The average realized fuel costs are presented as an aid in understanding the operating results of the Midwest Generation plants. Average realized fuel costs are a non-GAAP performance measure since such statistical measure excludes unrealized gains or losses recorded as fuel costs. This measure may not be comparable to those of other companies. Management believes that average realized fuel costs are meaningful for investors as this information reflects the impact of hedge contracts at the time of actual generation in period-over-period comparisons. A reconciliation of the fuel costs of the coal plants to consolidated fuel costs is set forth below:
 
Three Months Ended
June 30,
 
Six Months Ended
June 30,
(in millions)
2012
 
2011
 
2012
 
2011
Fuel costs
 
 
 
 
 
 
 
Midwest Generation plants
$
143

 
$
107

 
$
260

 
$
233

Homer City plant
67

 
63

 
151

 
115

Other
5

 
4

 
10

 
8

Consolidated fuel costs as reported
$
215

 
$
174

 
$
421

 
$
356


Statistical Definitions
•
Equivalent availability reflects the impact of the unit's inability to achieve full load, referred to as derating, as well as outages which result in a complete unit shutdown. The coal plants are not available during periods of planned and unplanned maintenance. The equivalent availability factor is defined as the number of MWh the coal plants are available to generate electricity divided by the product of the capacity of the coal plants (in MW) and the number of hours in the period.
•
The capacity factor indicates how much power a unit generated compared to the maximum amount of power that could be generated according to its rating. It is defined as the actual number of MWh generated by the coal plants divided by the product of the capacity of the coal plants (in MW) and the number of hours in the period.
•
The load factor indicates how much power a unit generated compared to the maximum amount of power that a unit was available to generate electricity. It is determined by dividing capacity factor by the equivalent availability factor.
•
The forced outage rate refers to forced outages and deratings excluding events outside of management's control as defined by NERC. Examples include floods, tornado damage and transmission outages.

Seasonality—Coal Plants
Due to fluctuations in electric demand resulting from warm weather during the summer months and cold weather during the winter months, electric revenues from the coal plants normally vary substantially on a seasonal basis. In addition, maintenance outages generally are scheduled during periods of lower projected electric demand (spring and fall), further

34
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reducing generation and increasing major maintenance costs which are recorded as an expense when incurred. Accordingly, income from the coal plants is seasonal and has significant variability from quarter to quarter. Seasonal fluctuations may also be affected by changes in market prices. For further discussion regarding market prices, see "Market Risk Exposures—Commodity Price Risk—Energy Price Risk."

Renewable Energy Projects
The following table presents additional data for EME's renewable energy projects:
 
Three Months Ended
June 30,
 
Six Months Ended
June 30,
(in millions)
2012
 
2011
 
2012
 
2011
Operating Revenues
$
63

 
$
59

 
$
135

 
$
111

Production Tax Credits
17

 
19

 
36

 
37

 
80

 
78

 
171

 
148

Operating Expenses

 
 
 
 
 
 
Plant operations
21

 
18

 
40

 
36

Depreciation and amortization
39

 
37

 
78

 
68

Administrative and general
1

 
1

 
3

 
2

Total operating expenses
61

 
56

 
121

 
106

Equity in income from unconsolidated affiliates
1

 
1

 
2

 
1

Other Income
—

 
1

 
—

 
2

Net Income Attributable to Noncontrolling Interests
(5
)
 
—

 
(7
)
 
—

AOI1
$
15

 
$
24

 
$
45

 
$
45

Statistics2
 
 
 
 
 
 
 
Generation (in GWh)3
1,551

 
1,555

 
3,297

 
2,940

Aggregate plant performance3
 
 
 
 
 
 
 
Equivalent availability
93.4
%
 
93.3
%
 
93.5
%
 
93.7
%
Capacity factor
37.4
%
 
41.0
%
 
39.7
%
 
39.5
%
1 
AOI is equal to operating income (loss) under GAAP plus equity in income (loss) of unconsolidated affiliates, dividend income from projects, production tax credits, other income and expense, and net (income) loss attributable to noncontrolling interests. Production tax credits are recognized as wind energy is generated based upon a per-kilowatt-hour rate prescribed in applicable federal and state statutes. Under GAAP, production tax credits generated by wind projects are recorded as a reduction in income taxes. Accordingly, AOI represents a non-GAAP performance measure which may not be comparable to those of other companies. Management believes that inclusion of production tax credits in AOI for wind projects is meaningful for investors as federal and state subsidies are an integral part of the economics of these projects.
2 
The statistics section summarizes key performance measures related to wind projects, which represents substantially all of the renewable energy projects.
3 
Includes renewable energy projects that are not consolidated by EME. Generation excluding unconsolidated projects was 1,343 GWh and 1,336 GWh in the second quarters of 2012 and 2011, respectively, and 2,859 GWh and 2,536 GWh in the six months ended June 30, 2012 and 2011, respectively.
AOI from renewable energy projects decreased $9 million and was unchanged for the three and six months ended June 30, 2012, respectively, as compared to the corresponding periods of 2011. The decrease in the second quarter was primarily attributable to income allocated to third-party investors in Capistrano Wind Partners, partially offset by results of operations from projects that achieved commercial operations after the second quarter of 2011. The year-to-date results benefited from the results of operations from projects that achieved commercial operation after the second quarter of 2011 offset by income allocated to third-party investors in Capistrano Wind Partners. For additional information, see "Edison Mission Energy and

35
Table of Contents

Subsidiaries Notes to Consolidated Financial Statements—Note 3. Variable Interest Entities—Projects or Entities that are Consolidated—Capistrano Wind Equity Capital."
The following table reconciles AOI from EME's renewable energy projects to its operating income as included in EME's consolidated statements of operations:
 
Three Months Ended
June 30,
 
Six Months Ended
June 30,
(in millions)
2012
 
2011
 
2012
 
2011
AOI
$
15

 
$
24

 
$
45

 
$
45

Less:
 
 
 
 
 
 
 
Equity in income of unconsolidated affiliates
1

 
1

 
2

 
1

Production tax credits
17

 
19

 
36

 
37

Other income
—

 
1

 
—

 
2

Net income attributable to noncontrolling interests
(5
)
 
—

 
(7
)
 
—

Operating Income
$
2

 
$
3

 
$
14

 
$
5


Energy Trading
AOI from energy trading activities decreased $11 million and $7 million for the three and six months ended June 30, 2012, respectively, as compared to the corresponding periods of 2011. The second quarter decrease was mainly due to lower revenues from trading power contracts and congestion. The year-to-date decrease was mainly due to the allocation to Homer City of the benefit from an arrangement that allows EMMT to deliver a portion of Homer City's power into the NYISO.

Adjusted Operating Income from Other Projects
Doga.    EME received a distribution from the Doga project of $11 million in the second quarter of 2012 compared to $26 million in the second quarter of 2011. Distributions in the second quarter of 2011 were higher due to release of funds from restricted cash once project debt obligations were repaid. AOI is recognized when cash is distributed as the Doga project is accounted for on the cost method.
Sunrise Project.    AOI from the Sunrise project increased $3 million and $10 million in the three and six months ended June 30, 2012, respectively, compared to the corresponding periods of 2011 primarily due to higher repairs and maintenance costs for a major overhaul in 2011. The power purchase agreement at the Sunrise project expired on June 30, 2012 and Sunrise will operate as a merchant project unless a new power purchase agreement is executed. The profitability of Sunrise as a merchant generator is dependent on market prices for power and natural gas and future results may differ from historical earnings. For additional information, see "Edison Mission Energy—Market Risk Exposures—Commodity Price Risk."
Seasonality.    EME's third quarter equity in income from its unconsolidated energy projects is normally higher than equity in income related to other quarters of the year due to seasonal fluctuations and higher energy contract prices during the summer months.

Interest Income (Expense)
 
Three Months Ended
June 30,
 
Six Months Ended
June 30,
(in millions)
2012
 
2011
 
2012
 
2011
Interest income
$
—

 
$
—

 
$
—

 
$
1

Interest expense, net of capitalized interest
 
 
 
 
 
 
 
EME debt
(66
)
 
(63
)
 
(133
)
 
(125
)
Nonrecourse debt
(18
)
 
(17
)
 
(37
)
 
(35
)
 
$
(84
)
 
$
(80
)
 
$
(170
)
 
$
(160
)
EME's interest expense increased $4 million and $10 million for the three and six months ended June 30, 2012, respectively, compared to the corresponding periods of 2011. The 2012 increase in interest expense was primarily due to lower capitalized

36
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interest and higher debt balances from new project financings. Capitalized interest was $7 million and $6 million for the second quarter of 2012 and 2011, respectively, and $13 million and $16 million for the six months ended June 30, 2012 and 2011, respectively. The 2012 decrease in capitalized interest was due to fewer projects under construction in 2012 compared to 2011.

Income Taxes
EME's effective tax rates were 51% and 68% for the six months ended June 30, 2012 and 2011, respectively. The effective tax rates for 2012 and 2011 were impacted by production tax credits and estimated state income tax benefits allocated from Edison International. Production tax credits of $36 million and $37 million were included in income taxes for the six months ended June 30, 2012 and 2011, respectively. Estimated state income tax benefits allocated from Edison International of $5 million and $4 million were recognized for the six months ended June 30, 2012 and 2011, respectively.

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


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LIQUIDITY AND CAPITAL RESOURCES

Available Liquidity
The following table summarizes available liquidity at June 30, 2012:
(in millions)
Cash and Cash Equivalents
EME as a holding company
 
$
549

 
EME subsidiaries without contractual dividend restrictions
 
 
 
Midwest Generation
 
177

 
Other EME subsidiaries
 
153

 
EME corporate and Midwest Generation cash and cash equivalents
 
879

 
EME subsidiaries with contractual dividend restrictions
 
 

 
Homer City
 
56

 
Other EME subsidiaries
 
74

 
Total
 
$
1,009

 
See "Management's Overview" for a discussion of EME's liquidity.
EME, as a holding company, does not directly operate any revenue-producing generation facilities. EME relies on cash distributions and tax payments from its projects and tax benefits received under a tax-allocation agreement with Edison International to meet its obligations, including debt service obligations on long-term debt. The timing and amount of distributions from EME's subsidiaries may be restricted. For further details, including the current restrictions on distributions from the Homer City facility, see "—Dividend Restrictions in Major Financings."

Capital Investment Plan
Forecasted capital expenditures through 2014 by EME's subsidiaries for existing projects and corporate activities are as follows:
(in millions)
July through December 2012
 
2013
 
2014
Midwest Generation Plants
 
 
 
 
 
Environmental1
$
28

 
$
103

 
$
311

Plant capital
6

 
47

 
16

Homer City Plant
23

 
23

 
14

Walnut Creek Project
119

 
44

 
—

Renewable Energy Projects
88

 
1

 
2

Other capital
12

 
19

 
15

Total
$
276

 
$
237

 
$
358

1 
For additional information, see "Management's Overview—Midwest Generation Environmental Compliance Plans and Costs."

Midwest Generation Capital Expenditures
Midwest Generation plants' forecasted environmental expenditures include retrofitting Powerton Units 5 and 6, Joliet Units 7 and 8 and Will County Units 3 and 4, using dry scrubbing with sodium-based sorbents and upgrading particulate removal systems to comply with CPS requirements for SO2 emissions and the US EPA's regulation on hazardous air pollutant emissions. Apart from the Fisk and Crawford Stations, which will be shut down in September 2012, decisions regarding whether or not to proceed with retrofitting any particular remaining units to comply with CPS requirements for SO2 emissions, including those that have received permits, are subject to a number of factors, such as market conditions,

38
Table of Contents

regulatory and legislative developments, liquidity and forecasted commodity prices and capital and operating costs applicable at the time decisions are required or made. Final decisions on whether to install controls, to install particular kinds of controls, and to actually expend capital or continue with the expenditure of capital will be made as required, subject to the requirements of the CPS and other applicable regulations. Furthermore, the timing of commencing capital projects may vary from the amounts set forth in the above table. For additional discussion, see "Management's Overview—Midwest Generation Environmental Compliance Plans and Costs."
Plant capital expenditures for Midwest Generation includes capital projects for boiler and turbine controls, major boiler components and electrical systems.

Homer City Capital Expenditures
The capital investment plan set forth above does not include environmental capital expenditures to retrofit the Homer City plant because Homer City does not have the funds for retrofits and will be dependent on external funding. Subject to the availability of capital, plant capital expenditures for Homer City are projected to be $23 million for the remaining six months of 2012 and $23 million and $14 million in 2013 and 2014, respectively. See "Management's Overview—Homer City Lease."

Renewable Energy Projects
At June 30, 2012, EME's development pipeline of potential wind projects was approximately 700 MW. Future development of the wind portfolio is dependent on the availability of third-party capital. To the extent that third-party capital is available, the success of development efforts will depend upon, among other things, obtaining permits and agreements necessary to support an investment.

EME's Historical Consolidated Cash Flow
This section discusses EME's consolidated cash flows from operating, financing and investing activities.

Condensed Consolidated Statement of Cash Flows
 
Six Months Ended June 30,
(in millions)
2012
 
2011
Operating cash flow from continuing operations
$
(353
)
 
$
(92
)
Operating cash flow from discontinued operations
(1
)
 
(3
)
Net cash used in operating activities
(354
)
 
(95
)
Net cash provided by financing activities
300

 
77

Net cash used in investing activities
(237
)
 
(224
)
Net decrease in cash and cash equivalents
$
(291
)
 
$
(242
)

Consolidated Cash Flows from Operating Activities
The decrease in cash provided by operating activities from continuing operations in 2012 as compared to 2011 was primarily attributable to decreased operating income due to declining energy prices, increased operating costs and higher interest payments due to new energy project financings. Operating cash flow was also impacted by timing of cash receipts and disbursements related to working capital items.


39
Table of Contents

Consolidated Cash Flows from Financing Activities
The change in financing activities is primarily due to cash contributions from noncontrolling interests and the timing of financings and repayment of debt as summarized in the following table:
 
Six Months Ended June 30,
(in millions)
2012
 
2011
Cash contributions from noncontrolling interests
$
242

 
$
—

Long-term debt financings
 
 
 
Renewable energy projects
—

 
76

Walnut Creek project
99

 
—

Short-term debt financings
 
 
 
Renewable energy projects
9

 
32

Debt repayments
 
 
 
Renewable energy projects
(20
)
 
(23
)
Other projects
(5
)
 
(5
)
Financing costs and others
(25
)
 
(3
)
Total cash provided by financing activities
$
300

 
$
77


Consolidated Cash Flows from Investing Activities
The change in investing activities is primarily due to the timing of capital expenditures and cash collateral to secure letter of credit facilities associated with the termination of EME's revolving credit facility. Changes in other investing activities are reflected in the following table:
 
Six Months Ended June 30,
(in millions)
2012
 
2011
Capital expenditures
 
 
 
Midwest Generation plants
 
 
 
Environmental
$
10

 
$
50

Plant capital
6

 
4

Homer City plant
13

 
8

Walnut Creek project
103

 
23

Renewable energy projects
31

 
128

Other capital expenditures
3

 
6

Investments in other assets
9

 
29

Collateral for letter of credit facilities
51

 
—

Other investing activities
11

 
(24
)
Total cash used in investing activities
$
237

 
$
224



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Table of Contents

Credit Ratings
Credit ratings for EME and EMMT as of June 30, 2012 were as follows:
 
Moody's Rating
S&P Rating
Fitch Rating
EME1
Caa3
CCC
C
EMMT
Not Rated
CCC
Not Rated
1 
Senior unsecured rating.
All the above ratings are on negative outlook. 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 a requirement to make equity contributions or provide additional financial support to its subsidiaries, including EMMT. However, coal contracts at Midwest Generation include provisions that provide the right to request additional collateral to support payment obligations for delivered coal and may vary based on Midwest Generation's credit ratings.

Margin, Collateral Deposits and Other Credit Support for Energy Contracts

Hedging Activities
To reduce its exposure to market risk, EME hedges a portion of its electricity price exposure through EMMT. In connection with entering into contracts, EMMT may be required to support its risk of nonperformance through parent guarantees, margining or other credit support. EME has entered into guarantees in support of EMMT's hedging and trading activities. However, EME has historically also provided collateral in the form of cash and letters of credit for the benefit of counterparties. For further details, see "Edison Mission Energy and Subsidiaries Notes to Consolidated Financial Statements—Note 6. Derivative Instruments and Hedging Activities—Margin and Collateral Deposits."
Future cash collateral requirements may be higher than the margin and collateral requirements at June 30, 2012, if wholesale energy prices change or if EMMT enters into additional transactions. EME estimates that margin and collateral requirements for energy and congestion contracts outstanding as of June 30, 2012 could increase by approximately $15 million over the remaining life of the contracts using a 95% confidence level.

Intercompany Tax-Allocation Agreement
EME is included in the consolidated federal and combined state income tax returns of Edison International and is eligible to participate in tax-allocation payments with other subsidiaries of Edison International in circumstances where domestic tax losses are incurred. The right of EME to receive and the amount of and timing of tax-allocation payments are dependent on the inclusion of EME in the consolidated income tax returns of Edison International and its subsidiaries and other factors, including the consolidated taxable income of Edison International and its subsidiaries, the amount of net operating losses and other tax items of EME, its subsidiaries, and other subsidiaries of Edison International and specific procedures regarding allocation of state taxes. EME receives tax-allocation payments for tax losses when and to the extent that the consolidated Edison International group generates sufficient taxable income in order to be able to utilize EME's consolidated tax losses in the consolidated income tax returns for Edison International and its subsidiaries. Based on the application of the factors cited above, EME is obligated during periods it generates taxable income to make payments under the tax-allocation agreements. EME expects that any tax-allocation payments it may make to Edison International during 2012 related to federal taxes will be largely offset by tax-allocation payments made to EME by Edison International and other members of the consolidated group. However, these amounts are dependent upon the course of further developments for subsidiary taxable income which is uncertain and may change materially.

Dividend Restrictions in Major Financings
For a 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 "Dividend Restrictions in Major Financings" in Item 7 on page 46 of EME's annual report on Form 10-K for the year ended December 31, 2011. Upon the expiration of the Midwest Generation credit facility on June 29, 2012, the debt-to-capitalization ratio as discussed in the Form 10-K is no longer required and Midwest Generation is also no longer

41
Table of Contents

contractually restricted in its ability to make distributions to EME. For further information, see "Liquidity and Capital Resources—Available Liquidity." Homer City is restricted from making distributions.

EME's Senior Notes and Guaranty of Powerton-Joliet Leases
EME is restricted under applicable agreements from selling or disposing of assets, which includes distributions, if the aggregate net book value of all such sales and dispositions during the most recent 12-month period would exceed 10% of consolidated net tangible assets as defined in such agreements computed as of the end of the most recent fiscal quarter preceding the sale or disposition in question. At June 30, 2012, the maximum permissible sale or disposition of EME's assets is calculated as follows:
(in millions)
 
Consolidated Net Tangible Assets
 
Total consolidated assets
$
8,254

Less:
 
Consolidated current liabilities
925

 
$
7,329

10% Threshold
$
733

This limitation does not apply if the proceeds are invested in assets in similar or related lines of business of EME. Furthermore, EME may sell or otherwise dispose of assets in excess of such 10% limitation if the proceeds from such sales or dispositions, which are not reinvested as provided above, are retained as cash or cash equivalents or are used to repay debt.
Subject to the limitations described above and applicable law, EME could, at any time and from time to time, make distributions of cash or assets, or take other actions, which could affect EME's assets held or under development.

Contractual Obligations and Contingencies

Contractual Obligations
Big Sky Turbine Financing
For a discussion of Big Sky Turbine Financing, see "Edison Mission Energy and Subsidiaries Notes to Consolidated Financial Statements—Note 5. Debt and Credit Agreements—Big Sky Turbine Financing."
Coal Transportation Agreements
For a discussion of Midwest Generation's coal transportation agreements, see "Edison Mission Energy and Subsidiaries Notes to Consolidated Financial Statements—Note 9. Commitments and Contingencies—Coal Transportation Agreements."

Contingencies
EME has contingencies related to the Midwest Generation New Source Review and other litigation, Homer City New Source Review and other litigation, and environmental remediation which are discussed in "Edison Mission Energy and Subsidiaries Notes to Consolidated Financial Statements—Note 9. Commitments and Contingencies—Contingencies."

Off-Balance Sheet Transactions
For a discussion of EME's off-balance sheet transactions, refer to "Off-Balance Sheet Transactions" in Item 7 on page 48 of EME's annual report on Form 10-K for the year ended December 31, 2011. There have been no significant developments with respect to EME's off-balance sheet transactions that affect disclosures presented in EME's annual report, except as set forth in "Management's Overview—Homer City Lease."

Environmental Matters and Regulations
For a discussion of EME's environmental matters, refer to "Environmental Matters and Regulations" in Item 1 on page 15 of EME's annual report on Form 10-K for the year ended December 31, 2011. There have been no significant developments with respect to environmental matters specifically affecting EME since the filing of EME's annual report, except as set forth in "Edison Mission Energy and Subsidiaries Notes to Consolidated Financial Statements—Note 10. Environmental Developments."

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Table of Contents

MARKET RISK EXPOSURES
For a detailed discussion of EME's market risk exposures, including commodity price risk, credit risk and interest rate risk, refer to "Market Risk Exposures" in Item 7 on page 50 of EME's annual report on Form 10-K for the year ended December 31, 2011.

Derivative Instruments

Unrealized Gains and Losses
EME classifies unrealized gains and losses from derivative instruments (other than the effective portion of derivatives that qualify for hedge accounting) as part of operating revenues or fuel costs. The following table summarizes unrealized gains (losses) from non-trading activities:
 
Three Months Ended
June 30,
 
Six Months Ended
June 30,
(in millions)
2012
 
2011
 
2012
 
2011
Midwest Generation plants
 
 
 
 
 
 
 
Non-qualifying hedges
$
(7
)
 
$
2

 
$
(1
)
 
$
1

Ineffective portion of cash flow hedges
(1
)
 
(1
)
 
—

 
(1
)
Homer City plant
 
 
 
 

 

Non-qualifying hedges
—

 
2

 
—

 
3

Ineffective portion of cash flow hedges
—

 
—

 
—

 
2

Total unrealized gains (losses)
$
(8
)
 
$
3

 
$
(1
)
 
$
5

At June 30, 2012, cumulative unrealized gains of $7 million were recognized from non-qualifying hedge contracts or the ineffective portion of cash flow hedges related to subsequent periods ($6 million for the remainder of 2012 and $1 million for 2013).

Fair Value Disclosures
In determining the fair value of EME's derivative positions, EME uses third-party market pricing where available. For further explanation of the fair value hierarchy and a discussion of EME's derivative instruments, see "Edison Mission Energy and Subsidiaries Notes to Consolidated Financial Statements—Note 4. Fair Value Measurements" and "—Note 6. Derivative Instruments and Hedging Activities," respectively.

Commodity Price Risk

Energy Price Risk
Energy and capacity from the coal plants are sold under terms, including price, duration 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. Power is sold into PJM at spot prices based upon locational marginal pricing. Energy from 428 MW of merchant renewable energy projects is sold in the energy markets, primarily at spot prices in PJM and ERCOT.

43
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The following table depicts the average historical market prices for energy per megawatt-hour at the locations indicated for the first six months of 2012 and 2011:
 
24-Hour Average
Historical Market Prices1
 
2012
 
2011
Midwest Generation plants
 
 
 
Northern Illinois Hub
$
26.70

 
$
34.29

Homer City plant
 
 
 
PJM West Hub
$
31.78

 
$
46.03

Homer City Busbar
28.47

 
41.55

1 
Energy prices were calculated at the Northern Illinois Hub and Homer City Busbar delivery points and the PJM West Hub using historical hourly day-ahead prices as published by PJM or provided on the PJM web-site.
The following table sets forth the forward market prices for energy per megawatt-hour as quoted for sales into the Northern Illinois Hub and PJM West Hub at June 30, 2012:
 
24-Hour Forward Energy Prices1
 
Northern
Illinois Hub
 
PJM West Hub
2012
 
 
 
 
 
 
 
July
 
$
33.16

 
 
 
$
38.91

 
August
 
31.99

 
 
 
36.39

 
September
 
24.05

 
 
 
30.12

 
October
 
24.09

 
 
 
30.39

 
November
 
24.41

 
 
 
31.10

 
December
 
27.89

 
 
 
35.57

 
2013 calendar "strip"2
 
$
28.79

 
 
 
$
36.24

 
1 
Energy prices were determined by obtaining broker quotes and information from other public sources relating to the Northern Illinois Hub and PJM West Hub delivery points.
2 
Market price for energy purchases for the entire calendar year.
Power prices remained low in the first six months of 2012 due to an abundance of low-priced natural gas and the sales volume from the Midwest Generation plants has been correspondingly affected. Forward market prices at the Northern Illinois Hub and 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 coal plants into these markets may vary materially from the forward market prices set forth in the preceding table.
EMMT engages in hedging activities for the coal plants to hedge the risk of future change in the price of electricity. The following table summarizes the hedge positions at June 30, 2012 for electricity expected to be generated during the remainder of 2012 and in 2013:
 
2012
 
2013
 
MWh (in
thousands)
 
Average
price/
MWh1
 
MWh (in
thousands)
 
Average
price/
MWh1
Midwest Generation plants2
3,638

 
$
38.24

 
1,020

 
$
40.42

1 
The above hedge positions include forward contracts for the sale of power and futures contracts during different periods of the year and the day. Market prices tend to be higher during on-peak periods and during summer months, although there is significant variability of power prices during different periods of time. Accordingly, the above hedge positions are not directly comparable to the 24-hour Northern Illinois Hub prices set forth above.
2 
Includes hedging transactions primarily at the Northern Illinois Hub and to a lesser extent the AEP/Dayton Hub, both in PJM, and the Indiana Hub in MISO.

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Sunrise Project
Beginning July 1, 2012, EME's 50% owned Sunrise project, which EME accounts for on the equity method, will operate as a merchant generator and sell power at spot prices from its 572 MW facility into the California ISO market, unless a power purchase agreement is obtained. Spot prices are currently expected to be between the price for the NP15 and SP15 trading locations in that market. As a gas-fired merchant generator, Sunrise purchases natural gas based on spot prices and, accordingly, the plant is dispatched in periods when the power prices exceed the cost of fuel and other variable operations and maintenance costs. Historically, Sunrise has operated more during the summer months due to higher demand driven by warm weather.

Capacity Price Risk
Under the RPM, capacity commitments are made in advance to provide a long-term pricing signal for construction and maintenance of capacity resources. The following table summarizes the status of capacity sales for Midwest Generation and Homer City at June 30, 2012:
 
 
 
 
Oversold/(Unsold)
Capacity1
MW
 
 
 
RPM Capacity
Sold in Base
Residual Auction
 
Other Capacity Sales,
Net of Purchases2
 
Aggregate
Average
Price per
MW-day
 
 
Installed
Capacity
MW
 
 
 
Capacity
Sold
MW
 
MW
 
Price per
MW-day
 
MW
 
Average
Price per
MW-day
 
 
July 1, 2012 to May 31, 2013
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Midwest Generation
5,477

 
 
(773
)
 
4,704

 
4,704

 
$
16.46

 
—

 
$
—

 
$
16.46

 
Homer City
1,884

 
 
(355
)
 
1,529

 
1,736

 
133.37

 
(207
)
 
8.16

 
150.35

 
June 1, 2013 to May 31, 2014
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Midwest Generation
4,619

3 
 
31

 
4,650

 
4,650

 
27.73

 
—

 
—

 
27.73

 
Homer City
1,884

 
 
(104
)
 
1,780

 
1,780

 
226.15

 
—

 
—

 
221.03

4 
June 1, 2014 to May 31, 2015
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Midwest Generation
4,619

 
 
6

 
4,625

 
4,625

 
125.99

 
—

 
—

 
125.99

 
Homer City
1,884

 
 
(190
)
 
1,694

 
1,694

 
136.50

 
—

 
—

 
136.50

 
June 1, 2015 to May 31, 2016
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Midwest Generation
4,619

 
 
(999
)
 
3,620

 
3,620

 
136.00

 
—

 
—

 
136.00

 
Homer City
1,884

 
 
(181
)
 
1,703

 
1,703

 
167.46

 
—

 
—

 
167.46

 
1 
Capacity not sold arises from: (i) capacity retained to meet forced outages under the RPM auction guidelines, and (ii) capacity that PJM does not purchase at the clearing price resulting from the RPM auction.
2 
Other capacity sales and purchases, net includes contracts executed in advance of the RPM base residual auction to hedge the price risk related to such auction, participation in RPM incremental auctions and other capacity transactions entered into to manage capacity risks.
3 
Reduction in installed capacity beginning June 1, 2013 is due to the shut down of Fisk and Crawford Stations in September 2012.
4 
Includes the impact of a 100 MW capacity swap transaction executed prior to the base residual auction at $135 per MW-day.
The RPM auction capacity prices for the delivery period of June 1, 2012 to May 31, 2013 and June 1, 2013 to May 31, 2014 varied between different areas of PJM. In the western portion of PJM, affecting Midwest Generation, the prices of $16.46 per MW-day and $27.73 per MW-day were substantially lower than other areas' capacity prices. The impact of lower capacity prices for these periods compared to previous years will have an adverse effect on Midwest Generation's revenues unless such lower capacity prices are offset by an unavailability of competing resources and increased energy prices.
Revenues from the sale of capacity from Midwest Generation and 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 those facilities have an opportunity to capture a higher value associated with those markets. Midwest Generation has sold capacity forward through May 31, 2015 for both Fisk and Crawford. Midwest Generation would expect to cover its capacity obligations associated with the Fisk and Crawford units through a combination of improved fleet performance, fleet capacity not previously sold forward and, if necessary, market transactions.
Effective April 16, 2012, EMMT assigned the awards it received related to Homer City capacity to Homer City effective as of June 1, 2012. As a result of the financial outlook of Homer City, as previously discussed, EME's subsidiary, EMMT, has

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ceased to enter into hedging activities related to future power sales, but continues to enter into short-term energy transactions on behalf of Homer City pursuant to an intercompany agreement. Those transactions are generally back-to-back transactions in which EMMT enters into a transaction with a third party as a principal and then enters into an equivalent transaction with Homer City.

Basis Risk
During the six months ended June 30, 2012 and 2011, day-ahead prices at the Homer City busbar were lower than those at the PJM West Hub by an average of 10%. During the six months ended June 30, 2012, day-ahead prices at the individual busbars of the Midwest Generation plants compared to the AEP/Dayton Hub, Indiana Hub (Cinergy Hub) and Northern Illinois Hub were on average lower by 7%, lower by 2% and higher by 1%, respectively. During the six months ended June 30, 2011, day-ahead prices at the individual busbars of the Midwest Generation plants were lower compared to the AEP/Dayton Hub, Indiana Hub (Cinergy Hub) and Northern Illinois Hub by an average of 13%, 4% and 1%, respectively. Differences in day-ahead pricing between the individual busbars of the Homer City and Midwest Generation plants generally arise due to transmission congestion.

Coal Price Risk
The Midwest Generation plants and Homer City plant purchase coal primarily 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. The following table summarizes the amount of coal under contract at June 30, 2012, for the remainder of 2012 and the following two years:
 
Amount of Coal Under Contract
in Millions of Equivalent Tons1
 
July through December 2012
 
2013
 
2014
Midwest Generation plants
 
9.4

 
 
10.6

 
9.8

Homer City plant
 
2.7

 
 
0.8

 
—

1 
The amount of coal under contract in equivalent tons is calculated based on contracted tons and applying an 8,800 Btu equivalent for the Midwest Generation plants and 13,000 Btu equivalents for the Homer City plant.
EME is subject to price risk for purchases of coal that are not under contract. Market prices of NAPP coal are related to the price of coal purchased for the Homer City plant. The market price of NAPP coal based on 13,000 Btu per pound heat content and less than 3.0 pounds of SO2 per MMBtu sulfur content decreased to a price of $64.90 per ton at June 29, 2012, compared to a price of $73.30 per ton at December 30, 2011, as reported by the EIA.
Market prices of PRB coal based on 8,800 Btu per pound heat content and 0.8 pounds of SO2 per MMBtu sulfur content decreased to a price of $8.50 per ton at June 29, 2012, compared to a price of $12.75 per ton at December 30, 2011, as reported by the EIA.
On July 11, 2012, Midwest Generation agreed to sell one million tons of coal scheduled to be delivered in the second half of 2012 in order to better manage coal inventories. This transaction will result in a loss of approximately $6 million, which will be recorded in the third quarter of 2012.


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Credit Risk
The credit risk exposure from counterparties of merchant energy hedging and trading activities is measured as the sum of net receivables (accounts receivable less accounts payable) and the current fair value of net derivative assets. EME's subsidiaries enter into master agreements and other arrangements in conducting such activities which typically provide for a right of setoff in the event of bankruptcy or default by the counterparty. At June 30, 2012, the balance sheet exposure as described above, by the credit ratings of EME's counterparties, was as follows:
 
June 30, 2012
(in millions)
Exposure2
 
Collateral
 
Net Exposure
Credit Rating1
 
 
 
 
 
A or higher
$
122

 
$
—

 
$
122

A-
7

 
(7
)
 
—

BBB+
13

 
—

 
13

BBB
1

 
—

 
1

BBB-
1

 
—

 
1

Below investment grade
42

 
(42
)
 
—

Total
$
186

 
$
(49
)
 
$
137

1 
EME assigns a credit rating based on the lower of a counterparty's S&P or Moody's rating. For ease of reference, the above table uses the S&P classifications to summarize risk, but reflects the lower of the two credit ratings.
2 
Exposure excludes amounts related to contracts classified as normal purchase and sales and non-derivative contractual commitments that are not recorded on the consolidated balance sheet, except for any related accounts receivable.
The credit risk exposure set forth in the above table is composed of $85 million of net accounts receivable and payables and $101 million representing the fair value of derivative contracts. The exposure is based on master netting agreements with the related counterparties. Credit ratings may not be reflective of the actual related credit risks. In addition to the amounts set forth in the above table, EME's subsidiaries have posted a $59 million cash margin in the aggregate with PJM, NYISO, MISO, clearing brokers and other counterparties to support hedging and trading activities. The margin posted to support these activities also exposes EME to credit risk of the related entities.
The coal plants sell electric power generally into the PJM market by participating in PJM's capacity and energy markets or transacting in capacity and energy on a bilateral basis. Sales into PJM accounted for approximately 66% of EME's consolidated operating revenues for the six months ended June 30, 2012. At June 30, 2012, EME's account receivable due from PJM was $70 million.
EME's wind turbine supply agreements contain significant suppliers' obligations related to the manufacturing and delivery of turbines, and payments, for delays in delivery and for failure to meet performance obligations and warranty agreements. EME's reliance on these contractual provisions is subject to credit risks. Generally, these are unsecured obligations of the turbine manufacturer. A material adverse development with respect to EME's turbine suppliers may have a material impact on EME's wind projects and development efforts.

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. For further details, see "Edison Mission Energy and Subsidiaries Notes to Consolidated Financial Statements—Note 5. Debt and Credit Agreements" and "—Note 6. Derivative Instruments and Hedging Activities."

CRITICAL ACCOUNTING ESTIMATES AND POLICIES
For a discussion of EME's critical accounting policies, refer to "Critical Accounting Estimates and Policies" in Item 7 on page 56 of EME's annual report on Form 10-K for the year ended December 31, 2011.


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ITEM 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK
For a discussion of market risk sensitive instruments, refer to "Market Risk Exposures" in Item 7 on page 50 of EME's annual report on Form 10-K for the year ended December 31, 2011. For an update to that disclosure, see "Item 2. Management's Discussion and Analysis of Financial Condition and Results of Operations—Market Risk Exposures."

ITEM 4. CONTROLS AND PROCEDURES

Disclosure Controls and Procedures
EME's management, under the supervision and with the participation of the company's President 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 second quarter of 2012. Based on that evaluation, the President and Chief Financial Officer concluded that, as of the end of the second quarter of 2012, EME's disclosure controls and procedures were 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 second quarter of 2012 that have materially affected, or are reasonably likely to materially affect, EME's internal control over financial reporting.


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PART II - OTHER INFORMATION

ITEM 1. LEGAL PROCEEDINGS
For a discussion of EME's legal proceedings, refer to "Note 9. Commitments and Contingencies—Contingencies" on page 108 of EME's annual report on Form 10-K for the year ended December 31, 2011. 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, 2011, except as follows:
Midwest Generation New Source Review and Other Litigation
In February 2012, certain of the environmental action groups that had intervened in the US EPA's New Source Review case entered into an agreement with Midwest Generation to dismiss without prejudice all of their opacity claims as to all defendants. The agreed upon motion to dismiss was approved by the court on March 26, 2012.

ITEM 1A. RISK FACTORS
In addition to the risk factors below, refer to "Item 1A. Risk Factors" on page 20 of EME's annual report on Form 10-K for the year ended December 31, 2011 for a discussion of the risks, uncertainties, and other important factors which could materially affect EME's business, financial condition, or future results. The risks described in EME's annual report on Form 10-K and in this report 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.
Liquidity Risks
Absent a restructuring of its debt obligations, EME is not expected to have sufficient liquidity to pay existing indebtedness.
At June 30, 2012, EME and its subsidiaries without contractual dividend restrictions had corporate cash and cash equivalents of $879 million, which includes Midwest Generation's cash and cash equivalents of $177 million. EME and Midwest Generation's previous revolving credit agreements have been terminated or expired and no longer are sources of liquidity. At June 30, 2012, EME had $3.7 billion of unsecured notes outstanding, $500 million of which mature in June 2013.
EME is currently experiencing operating losses due to lower realized energy and capacity prices, higher fuel costs and lower generation at the Midwest Generation plants. Forward market prices indicate that these trends are expected to continue for a number of years. As a result, EME expects that it will incur further reductions in cash flow and losses in the current year and in subsequent years. A continuation of these adverse trends coupled with pending debt maturities and the need to retrofit its Midwest Generation plants to comply with governmental regulations will exhaust EME's liquidity. Absent a restructuring of its obligations, based on current projections, EME is not expected to have sufficient liquidity to repay the $500 million debt obligation due in June 2013, and may need to file for protection under Chapter 11 of the U.S. Bankruptcy Code.
A change in control of EME could adversely affect EME’s long-term liquidity.
Bankruptcy proceedings could lead to a change of control of EME which would result in termination of EME's tax-allocation agreement. The termination of the tax-allocation agreement could adversely affect EME's long-term liquidity because realization of the value of tax benefits generated by EME could be deferred until such time that EME, or a subsequent owner of EME, had the ability to utilize such benefits. There is no assurance as to when, or whether, this might occur.


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ITEM 6. EXHIBITS
Exhibit No.
Description
31.1
Certification of the President 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.
101
Financial statements from the quarterly report on Form 10-Q of Edison Mission Energy for the quarter ended June 30, 2012, filed on July 31, 2012, formatted in XBRL: (i) the Consolidated Statements of Operations, (ii) the Consolidated Statements of Comprehensive Loss, (iii) the Consolidated Balance Sheets, (iv) the Consolidated Statements of Cash Flows, and (v) the Notes to Consolidated Financial Statements.


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

 
EDISON MISSION ENERGY
(REGISTRANT)
 
By:
/s/ Maria Rigatti
 
 
Maria Rigatti
Senior Vice President and Chief Financial Officer
(Duly Authorized Officer and
Principal Financial Officer)
 
Date:
July 31, 2012



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