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



FORM 10-Q



(Mark One)

ý

 

QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

 

 

For the quarterly period ended June 30, 2010

o

 

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 1-9936



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



California   95-4137452
(State or other jurisdiction of
incorporation or organization)
  (I.R.S. Employer
Identification No.)

2244 Walnut Grove Avenue
(P. O. Box 976)
Rosemead, California

 

91770
(Address of principal executive offices)   (Zip Code)
(626) 302-2222
(Registrant's telephone number, including area code)



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

Indicate by check mark whether the registrant 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 during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files). Yes ý No o

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, or a smaller reporting company.

Large accelerated filer ý   Accelerated filer o   Non-accelerated filer o
(Do not check if a smaller
reporting company)
  Smaller reporting company o

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

Indicate the number of shares outstanding of each of the issuer's classes of common stock, as of the latest practicable date:

Class   Outstanding at August 2, 2010
Common Stock, no par value   325,811,206


Table of Contents


TABLE OF CONTENTS

GLOSSARY   i

PART I. FINANCIAL INFORMATION

 

1

ITEM 1. FINANCIAL STATEMENTS

 

1
  Consolidated Statements of Income (Loss)   1
  Consolidated Statements of Comprehensive Income (Loss)   2
  Consolidated Balance Sheets   3
  Consolidated Statements of Cash Flows   5
 
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

 

7
 
Note 1. Summary of Significant Accounting Policies

 

7
 
Note 2. Derivative Instruments and Hedging Activities

 

10
 
Note 3. Liabilities and Lines of Credit

 

17
 
Note 4. Income Taxes

 

18
 
Note 5. Compensation and Benefit Plans

 

20
 
Note 6. Commitments and Contingencies

 

22
 
Note 7. Consolidated Statements of Changes in Equity

 

35
 
Note 8. Accumulated Other Comprehensive Income

 

36
 
Note 9. Supplemental Cash Flows Information

 

36
 
Note 10. Fair Value Measurements

 

37
 
Note 11. Regulatory Assets and Liabilities

 

43
 
Note 12. Other Income and Expenses

 

44
 
Note 13. Variable Interest Entities

 

44
 
Note 14. Business Segments

 

48

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

 

50
 
FORWARD-LOOKING STATEMENTS

 

50

EDISON INTERNATIONAL OVERVIEW
 
Introduction

 

52
 
Highlights of Operating Results

 

52
 
SCE Capital Program

 

54
 
SCE 2012 General Rate Case

 

54
 
Environmental Developments

 

55
    Midwest Generation Environmental Compliance Plans and Costs   55
    Environmental Regulation Developments   55
      Greenhouse Gas Regulation Developments   55
      Transport Rule and Coal Combustion Waste Regulation   56
      California Renewable Energy Developments   56
      Once-Through Cooling   56

Table of Contents

  EMG Renewable Program   56
    Mitsubishi Lawsuit   57
 
Parent Company Liquidity

 

57

SOUTHERN CALIFORNIA EDISON COMPANY
 
RESULTS OF OPERATIONS

 

58
 
Electric Utility Results of Operations

 

58
    Three Months Ended June 30, 2010 versus June 30, 2009   59
      Utility Earning Activities   60
      Utility Cost-Recovery Activities   60
    Six Months Ended June 30, 2010 versus June 30, 2009   61
      Utility Earning Activities   61
      Utility Cost-Recovery Activities   63
    Supplemental Operating Revenue Information   63
    Income Taxes   64
 
LIQUIDITY AND CAPITAL RESOURCES

 

64
 
Available Liquidity

 

64
    Debt Covenant   65
 
Regulatory Proceedings

 

65
    Energy Efficiency Risk/Reward Incentive Mechanism   65
    2010 FERC Rate Case   65
 
Dividend Restrictions

 

65
 
Margin and Collateral Deposits

 

65
 
Historical Consolidated Cash Flow

 

66
    Condensed Consolidated Statement of Cash Flows   66
      Cash Flows Provided by Operating Activities   66
      Cash Flows Provided (Used) by Financing Activities   66
      Cash Flows Used by Investing Activities   67
 
Contractual Obligations and Contingencies

 

67
    Contractual Obligations   67
    Contingencies   67
      Environmental Remediation   67
 
MARKET RISK EXPOSURES

 

67
 
Interest Rate Risk

 

67
 
Commodity Price Risk

 

68
    Natural Gas and Electricity Price Risk   68
 
Credit Risk

 

69

EDISON MISSION GROUP
 
RESULTS OF OPERATIONS

 

70
 
Results of Continuing Operations

 

70
    Adjusted Operating Income ("AOI") – Overview   71
    Adjusted Operating Income from Consolidated Operations   73
      Midwest Generation Plants   73
      Homer City Facilities   74
      Non-GAAP Disclosures—Fossil-Fueled Facilities   75
        Adjusted Operating Income   75

Table of Contents

      Seasonal Disclosure—Fossil-Fueled Facilities   75
      Renewable Energy Projects   76
      Energy Trading   77
    Adjusted Operating Income from Leveraged Lease Activities   77
    Adjusted Operating Income from Lease Termination and Other   77
    Adjusted Operating Income from Unconsolidated Affiliates   77
      Doga   77
      March Point   77
      Seasonal Disclosure   77
    Interest Related Income (Expense)   78
    Income Taxes   78
 
Results of Discontinued Operations

 

78
 
Derivative Instruments

 

79
    Unrealized Gains and Losses   79
    Fair Value Disclosures   79
 
LIQUIDITY AND CAPITAL RESOURCES

 

79
 
Available Liquidity

 

79
 
Capital Investment Plan

 

81
    Estimated Expenditures for Existing Projects   81
    Estimated Expenditures for Future Projects   82
 
Historical Consolidated Cash Flow

 

82
    Condensed Consolidated Statement of Cash Flows   82
      Cash Flows Used by Operating Activities   82
      Cash Flows Provided (Used) by Financing Activities   83
      Cash Flows Provided (Used) by Investing Activities   83
 
Credit Ratings

 

83
    Overview   83
    Credit Rating of EMMT   83
    Margin, Collateral Deposits and Other Credit Support for Energy Contracts   83
 
Debt Covenants and Dividend Restrictions

 

84
    Credit Facility and Financial Ratios   84
    Dividend Restrictions in Major Financings   85
    EME's Senior Notes and Guaranty of Powerton-Joliet Leases   85
 
Contractual Obligations and Contingencies

 

85
    Fuel Supply and Transportation Contracts   85
    Midwest Generation New Source Review Lawsuit   85
    Homer City New Source Review Notice of Violation   85
 
Off-Balance Sheet Transactions

 

85
 
Environmental Matters and Regulations

 

86
 
MARKET RISK EXPOSURES

 

86
 
Commodity Price Risk

 

86
    Energy Price Risk Affecting Sales from the Fossil-Fueled Facilities   86
    Capacity Price Risk   88
    Basis Risk   88
    Coal and Transportation Price Risk   89
    Emission Allowances Price Risk   89

Table of Contents

  Credit Risk   90
 
Interest Rate Risk

 

91

EDISON INTERNATIONAL PARENT AND OTHER
 
RESULTS OF OPERATIONS

 

92
 
LIQUIDITY AND CAPITAL RESOURCES

 

92
 
Historical Cash Flow

 

92
    Condensed Statement of Cash Flows   92
      Cash Flows Provided (Used) by Financing Activities   92

EDISON INTERNATIONAL (CONSOLIDATED)
 
CONTRACTUAL OBLIGATIONS

 

93
 
NEW ACCOUNTING GUIDANCE

 

93

ITEM 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

 

93

ITEM 4. CONTROLS AND PROCEDURES

 

93
 
Disclosure Controls and Procedures

 

93
 
Changes in Internal Control Over Financial Reporting

 

93

PART II. OTHER INFORMATION

 

94

ITEM 1. LEGAL PROCEEDINGS

 

94
 
Homer City New Source Review Notice of Violation

 

94
 
Midwest Generation New Source Review Lawsuit

 

94
 
Mitsubishi Lawsuit

 

94
 
Navajo Nation Litigation

 

95

ITEM 2. UNREGISTERED SALES OF EQUITY SECURITIES AND USE OF PROCEEDS

 

95

ITEM 6. EXHIBITS

 

96

SIGNATURE

 

97

Table of Contents


GLOSSARY

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

2009 Form 10-K   Edison International's Annual Report on Form 10-K for the year ended December 31, 2009
AB   Assembly Bill
AFUDC   allowance for funds used during construction
Ambit project   American Bituminous Power Partners, L.P.
AOI   Adjusted Operating Income
APS   Arizona Public Service Company
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
CAISO   California Independent System Operator
CAMR   Clean Air Mercury Rule
CARB   California Air Resources Board
Commonwealth Edison   Commonwealth Edison Company
CDWR   California Department of Water Resources
CEC   California Energy Commission
CONE   cost of new entry
CPS   Combined Pollutant Standard
CPUC   California Public Utilities Commission
CRRs   congestion revenue rights
DCR   Devers-Colorado River
DOE   U.S. Department of Energy
DOJ   U.S. Department of Justice
DRA   Division of Ratepayer Advocates
DWP   Los Angeles Department of Water & Power
EME   Edison Mission Energy
EMG   Edison Mission Group Inc.
EMMT   Edison Mission Marketing & Trading, Inc.
EPS   earnings per share
ERRA   energy resource recovery account
EWG   Exempt Wholesale Generator
Exelon Generation   Exelon Generation Company LLC
FASB   Financial Accounting Standards Board
FERC   Federal Energy Regulatory Commission
FGD   flue gas desulfurization
FGIC   Financial Guarantee Insurance Company
FTRs   firm transmission rights
Four Corners   coal fueled electric generating facility located in Farmington, New Mexico in which Edison International holds a 48% ownership interest
GAAP   generally accepted accounting principles

i


Table of Contents

Global Settlement   A settlement between Edison International and the IRS that resolved federal tax disputes related to Edison Capital's cross-border, leveraged leases through 2009, and all other outstanding federal tax disputes and affirmative claims for tax years 1986 through 2002.
GRC   General Rate Case
GWh   Gigawatt-hours
Homer City   EME Homer City Generation L.P.
Illinois EPA   Illinois Environmental Protection Agency
Illinois PCB   Illinois Pollution Control Board
Investor-Owned Utilities   SCE, SDG&E and PG&E
IRS   Internal Revenue Service
ISO   Independent System Operator
kWh(s)   kilowatt-hour(s)
LIBOR   London Interbank Offered Rate
MD&A   Management's Discussion and Analysis of Financial Condition and Results of Operations in this report
MEHC   Mission Energy Holding Company
Midwest Generation   Midwest Generation, LLC
Midwest Generation Plants   EME's power plants (fossil fuel) located in Illinois
MMBtu   million British thermal units
Mohave   two coal fueled electric generating facilities that no longer operate located in Clark County, Nevada in which SCE holds a 56% ownership interest
Moody's   Moody's Investors Service
MRTU   Market Redesign and Technology Upgrade
MW   Megawatts
MWh   megawatt-hours
NAAQS   national ambient air quality standards
NAPP   Northern Appalachian
NERC   North American Electric Reliability Corporation
Ninth Circuit   U.S. Court of Appeals for the Ninth Circuit
NOV   notice of violation
NOx   nitrogen oxide
NRC   Nuclear Regulatory Commission
NSR   New Source Review
PADEP   Pennsylvania Department of Environmental Protection
Palo Verde   large pressurized water nuclear electric generating facility located near Phoenix, Arizona in which SCE holds a 15.8% ownership interest
PBOP(s)   Postretirement benefits other than pension(s)
PBR   performance-based ratemaking
PG&E   Pacific Gas & Electric Company
PJM   PJM Interconnection, LLC
POD   Presiding Officer's Decision
PRB   Powder River Basin
PSD   Prevention of Significant Deterioration
PUHCA 2005   Public Utility Holding Company Act of 2005
PX   California Power Exchange
QF(s)   qualifying facility(ies)
RGGI   Regional Greenhouse Gas Initiative
RICO   Racketeer Influenced and Corrupt Organization
ROE   return on equity

ii


Table of Contents

RPM   reliability pricing model
RTO   Regional Transmission Organization
S&P   Standard & Poor's Ratings Services
San Onofre   large pressurized water nuclear electric generating facility located in South San Clemente, California in which SCE holds a 78.21% ownership interest
SB   Senate Bill
SCAQMD   South Coast Air Quality Management District
SCE   Southern California Edison Company
SCR   selective catalytic reduction
SNCR   selective non-catalytic reduction
SDG&E   San Diego Gas & Electric
SEC   U.S. Securities and Exchange Commission
SIP(s)   State Implementation Plan(s)
SO2   sulfur dioxide
SRP   Salt River Project Agricultural Improvement and Power District
TURN   The Utility Reform Network
US EPA   U.S. Environmental Protection Agency
VIE(s)   variable interest entity(ies)
 

iii


Table of Contents


PART I. FINANCIAL INFORMATION

ITEM 1. FINANCIAL STATEMENTS

   
Consolidated Statements of Income (Loss)
  Edison International
 
 
 
Three Months Ended
June 30,

 
Six Months Ended
June 30,

 
 
     
(in millions, except per-share amounts)
  2010
  2009
  2010
  2009
 
   
 
  (Unaudited)
 

Electric utility

  $ 2,246   $ 2,272   $ 4,405   $ 4,460  

Competitive power generation

    495     562     1,147     1,186  
       

Total operating revenue

    2,741     2,834     5,552     5,646  
       

Fuel

    254     328     549     715  

Purchased power

    612     583     1,220     1,124  

Operations and maintenance

    1,144     1,074     2,181     2,043  

Depreciation, decommissioning and amortization

    380     347     749     688  

Lease terminations and other

        866     2     888  
       

Total operating expenses

    2,390     3,198     4,701     5,458  
       

Operating income (loss)

    351     (364 )   851     188  

Interest and dividend income

    4     17     23     27  

Equity in income (loss) from partnerships and unconsolidated subsidiaries – net

    20     6     39     (2 )

Other income

    36     30     70     58  

Interest expense – net of amounts capitalized

    (175 )   (182 )   (343 )   (369 )

Other expenses

    (16 )   (17 )   (28 )   (25 )
       

Income (loss) from continuing operations before income taxes

    220     (510 )   612     (123 )

Income tax expense (benefit)

    (136 )   (524 )   14     (402 )
       

Income from continuing operations

    356     14     598     279  

Income (loss) from discontinued operations – net of tax

    1     (7 )   8     (4 )
       

Net income

    357     7     606     275  

Less: Net income attributable to noncontrolling interests

    13     23     26     41  
       

Net income (loss) attributable to Edison International common shareholders

  $ 344   $ (16 ) $ 580   $ 234  
       

Amounts attributable to Edison International common shareholders:

                         

Income (loss) from continuing operations, net of tax

  $ 343   $ (9 ) $ 572   $ 238  

Income (loss) from discontinued operations, net of tax

    1     (7 )   8     (4 )
       

Net income (loss) attributable to Edison International common shareholders

  $ 344   $ (16 ) $ 580   $ 234  
       

Basic earnings per common share attributable to Edison International common shareholders:

                         

Weighted-average shares of common stock outstanding

    326     326     326     326  

Continuing operations

  $ 1.05   $ (0.03 ) $ 1.75   $ 0.73  

Discontinued operations

        (0.02 )   0.02     (0.01 )
       

Total

  $ 1.05   $ (0.05 ) $ 1.77   $ 0.72  
       

Diluted earnings per common share attributable to Edison International common shareholders:

                         

Weighted-average shares of common stock outstanding, including effect of dilutive securities

    327     327     327     327  

Continuing operations

  $ 1.05   $ (0.03 ) $ 1.75   $ 0.73  

Discontinued operations

        (0.02 )   0.02     (0.01 )
       

Total

  $ 1.05   $ (0.05 ) $ 1.77   $ 0.72  
       

Dividends declared per common share

  $ 0.315   $ 0.31   $ 0.63   $ 0.62  
   

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

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Table of Contents

   
Consolidated Statements of Comprehensive Income (Loss)
  Edison International
 
 
 
Three Months Ended
June 30,

 
Six Months Ended
June 30,

 
 
     
(in millions)
  2010
  2009
  2010
  2009
 
   
 
  (Unaudited)
 

Net Income

  $ 357   $ 7   $ 606   $ 275  

Other comprehensive income (loss), net of tax:

                         
 

Foreign currency translation adjustments – net

        4         4  
 

Pension and postretirement benefits other than pensions:

                         
   

Net gain arising during the period

        1     12     1  
   

Amortization of net (gain) loss included in net income

    2     1     (6 )   3  
   

Prior service adjustment arising during the period

            2      
   

Amortization of prior service adjustment

            (2 )    
 

Unrealized gain (loss) on derivatives qualified as cash flow hedges:

                         
   

Unrealized holding gain (loss) arising during the period, net of income tax expense (benefit) of $(50) and $(50) for the three months and $12 and $48 for the six months ended June 30, 2010 and 2009, respectively

    (77 )   (90 )   18     61  
   

Reclassification adjustments included in net income, net of income tax expense (benefit) of $(35) and $9 for the three months and $(49) and $(23) for the six months ended June 30, 2010 and 2009, respectively

    (53 )   17     (73 )   (32 )
       

Other comprehensive income (loss)

    (128 )   (67 )   (49 )   37  
       

Comprehensive income (loss)

    229     (60 )   557     312  

Less: Comprehensive income attributable to noncontrolling interests

    13     23     26     41  
       

Comprehensive income (loss) attributable to Edison International

  $ 216   $ (83 ) $ 531   $ 271  
   

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

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Table of Contents

   
Consolidated Balance Sheets
  Edison International
 
(in millions)
 
June 30,
2010

  December 31,
2009

 
   
 
  (Unaudited)
 

ASSETS

             

Cash and equivalents

  $ 868   $ 1,673  

Short-term investments

    7     10  

Receivables, less allowances of $53 for uncollectible accounts at both dates

    880     1,017  

Accrued unbilled revenue

    542     347  

Inventory

    556     533  

Derivative assets

    224     357  

Restricted cash

    25     69  

Margin and collateral deposits

    111     125  

Regulatory assets

    338     120  

Deferred income taxes

        3  

Other current assets

    306     176  
       

Total current assets

    3,857     4,430  
       

Competitive power generation and other property – less accumulated depreciation of $1,730 and $2,231 at respective dates

    5,112     5,147  

Nuclear decommissioning trusts

    3,083     3,140  

Investments in partnerships and unconsolidated subsidiaries

    515     216  

Investments in leveraged leases

    153     160  

Other investments

    98     91  
       

Total investments and other assets

    8,961     8,754  
       

Utility plant, at original cost:

             
 

Transmission and distribution

    23,355     22,214  
 

Generation

    2,715     2,667  

Accumulated depreciation

    (6,047 )   (5,921 )

Construction work in progress

    2,682     2,701  

Nuclear fuel, at amortized cost

    339     305  
       

Total utility plant

    23,044     21,966  
       

Derivative assets

    276     268  

Restricted deposits

    44     43  

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

    1,149     1,038  

Regulatory assets

    5,058     4,139  

Other long-term assets

    666     806  
       

Total long-term assets

    7,193     6,294  
       

Total assets

 
$

43,055
 
$

41,444
 
   

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

3


Table of Contents

   
Consolidated Balance Sheets
  Edison International
 
(in millions, except share amounts)
    
June 30,
2010

  December 31,
2009

 
   
 
  (Unaudited)
 

LIABILITIES AND EQUITY

             

Short-term debt

  $ 495   $ 85  

Current portion of long-term debt

    42     377  

Accounts payable

    1,027     1,347  

Accrued taxes

    131     186  

Accrued interest

    210     196  

Customer deposits

    229     238  

Derivative liabilities

    179     107  

Regulatory liabilities

    457     367  

Deferred income taxes

    114      

Other current liabilities

    729     884  
       

Total current liabilities

    3,613     3,787  
       

Long-term debt

    11,113     10,437  
       

Deferred income taxes

    4,639     4,334  

Deferred investment tax credits

    98     102  

Customer advances

    124     119  

Derivative liabilities

    1,211     529  

Pensions and benefits

    2,119     2,061  

Asset retirement obligations

    3,323     3,241  

Regulatory liabilities

    3,391     3,328  

Other deferred credits and other long-term liabilities

    2,329     2,500  
       

Total deferred credits and other liabilities

    17,234     16,214  
       

Total liabilities

    31,960     30,438  
       

Commitments and contingencies (Note 6)

             

Common stock, no par value (800,000,000 shares authorized; 325,811,206 shares issued and outstanding at each date)

    2,315     2,304  

Accumulated other comprehensive income (loss)

    (12 )   37  

Retained earnings

    7,879     7,500  
       

Total Edison International's common shareholders' equity

    10,182     9,841  

Noncontrolling interests

    6     258  

Preferred and preference stock of utility not subject to mandatory redemption

    907     907  
       

Total equity

    11,095     11,006  
       

Total liabilities and equity

 
$

43,055
 
$

41,444
 
   

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

4


Table of Contents

   
Consolidated Statements of Cash Flows
  Edison International
 
 
 
Six Months Ended
June 30,
 
(in millions)
  2010
  2009
 
   
 
  (Unaudited)
 

Cash flows from operating activities:

             

Net income

  $ 606   $ 275  

Less: Income (loss) from discontinued operations

    8     (4 )
       

Income from continuing operations

    598     279  

Adjustments to reconcile to net cash provided by operating activities:

             
 

Depreciation, decommissioning and amortization

    749     688  
 

Regulatory impacts of net nuclear decommissioning trust earnings (reflected in accumulated depreciation)

    74     86  
 

Other amortization

    56     58  
 

Lease terminations and other

    2     888  
 

Stock-based compensation

    14     11  
 

Equity in (income) loss from partnerships and unconsolidated subsidiaries – net

    (39 )   2  
 

Distributions and dividends from unconsolidated entities

    39     5  
 

Deferred income taxes and investment tax credits

    247     (1,315 )
 

Income from leveraged leases

    (2 )   (12 )

Changes in operating assets and liabilities:

             
 

Receivables

    13     65  
 

Inventory

    (36 )   9  
 

Restricted cash

    43     (188 )
 

Margin and collateral deposits – net of collateral received

    12     (29 )
 

Other current assets

    (346 )   35  
 

Rent payments in excess of levelized rent expense

    (111 )   (113 )
 

Accounts payable

    (114 )   58  
 

Accrued taxes

    (69 )   (377 )
 

Other current liabilities

    (164 )   (94 )
 

Derivative assets and liabilities – net

    806     (628 )
 

Regulatory assets and liabilities – net

    (720 )   761  
 

Proceeds from U.S. Treasury grants

    92      
 

Other assets

    (38 )   (106 )
 

Other liabilities

    (152 )   804  

Operating cash flows from discontinued operations

    8     (4 )
       

Net cash provided by operating activities

    962     883  
       

Cash flows from financing activities:

             

Long-term debt issued

    651     939  

Long-term debt issuance costs

    (25 )   (24 )

Long-term debt repaid

    (366 )   (194 )

Bonds repurchased

        (219 )

Short-term debt financing – net

    410     (2,066 )

Settlements of stock-based compensation – net

    (2 )    

Cash contributions from noncontrolling interests

        1  

Dividends and distributions to noncontrolling interests

    (25 )   (55 )

Dividends paid

    (205 )   (202 )
       

Net cash provided (used) by financing activities

  $ 438   $ (1,820 )
   

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

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Consolidated Statements of Cash Flows
  Edison International
 
 
 
Six Months Ended
June 30,
 
(in millions)
  2010
  2009
 
   
 
  (Unaudited)
 

Cash flows from investing activities:

             

Capital expenditures

  $ (2,070 ) $ (1,540 )

Purchase of interest in acquired companies

    (4 )   (7 )

Proceeds from termination of leases

        1,420  

Proceeds from sale of nuclear decommissioning trust investments

    600     1,310  

Purchases of nuclear decommissioning trust investments and other

    (697 )   (1,415 )

Proceeds from partnerships and unconsolidated subsidiaries, net of investment

    44     12  

Maturities and sale of short-term investments

    5     3  

Purchase of short-term investments

    (1 )   (1 )

Investments in other assets

    9     (60 )

Effect of consolidation and deconsolidation of variable interest entities

    (91 )    
       

Net cash used by investing activities

    (2,205 )   (278 )
       

Net decrease in cash and equivalents

    (805 )   (1,215 )

Cash and equivalents, beginning of period

    1,673     3,916  
       

Cash and equivalents, end of period

  $ 868   $ 2,701  
   

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

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS    


Note 1. Summary of Significant Accounting Policies

Edison International's principal wholly owned subsidiaries are SCE, a rate-regulated electric utility that supplies electric energy to a 50,000 square-mile area of central, coastal and southern California; and EMG, a wholly owned competitive power generation subsidiary. EMG is a holding company whose subsidiaries and affiliates are engaged in the business of developing, acquiring, owning or leasing, operating and selling energy and capacity from independent power production facilities. EMG's subsidiaries also conduct hedging and energy trading activities in competitive power markets.


Basis of Presentation

Edison International's significant accounting policies were described in Note 1 of "Edison International Notes to Consolidated Financial Statements" included in the 2009 Form 10-K. Edison International follows the same accounting policies for interim reporting purposes, with the exception of accounting principles adopted as of January 1, 2010 as discussed below in "—New Accounting Guidance." This quarterly report should be read in conjunction with such financial statements.

In the opinion of management, all adjustments, including recurring accruals, have been made that are necessary to fairly state the consolidated financial position, results of operations and cash flows in accordance with accounting principles generally accepted in the United States of America for the periods covered by this quarterly report on Form 10-Q. The results of operations for the three- and six-month periods ended June 30, 2010 are not necessarily indicative of the operating results for the full year.

Management has performed an evaluation of subsequent events through the date the financial statements were issued.

The December 31, 2009 condensed consolidated balance sheet data was derived from audited financial statements, but does not include all disclosures required by accounting principles generally accepted in the United States of America. Except as indicated, amounts presented in the Notes to the Consolidated Financial Statements relate to continuing operations.


Cash and Equivalents

Cash equivalents included money market funds totaling $600 million and $1,457 million at June 30, 2010 and December 31, 2009, respectively. The carrying value of cash equivalents equals the fair value, as all investments have maturities of three months or less. For further discussion of money market funds, see Note 10.

Edison International temporarily invests the ending daily cash balance in its primary disbursement accounts until required for check clearing. Edison International reclassified $201 million and $224 million of checks issued against these accounts, but not yet paid by the financial institution, from cash to accounts payable at June 30, 2010 and December 31, 2009, respectively.


Earnings Per Share

Edison International computes EPS using the two-class method, which is an earnings allocation formula that determines EPS for each class of common stock and participating security. Edison International's

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participating securities are stock-based compensation awards payable in common shares, including stock options, performance shares and restricted stock units, which earn dividend equivalents on an equal basis with common shares. Stock options awarded during the period 2003 through 2006 received dividend equivalents. Stock options awarded prior to 2002 and after 2006 were granted without a dividend equivalent feature. EPS attributable to Edison International common shareholders was computed as follows:

 
  Three Months Ended
June 30,

  Six Months Ended
June 30,

 
 
     
(in millions)
  2010
  2009
  2010
  2009
 
   
 
  (Unaudited)
 

Basic earnings (loss) per share – continuing operations:

                         

Income (loss) from continuing operations attributable to common shareholders, net of tax

  $ 343   $ (9 ) $ 572   $ 238  

Participating securities dividends

    (2 )       (2 )    
       

Income (loss) from continuing operations available to common shareholders

  $ 341   $ (9 ) $ 570   $ 238  
       

Weighted average common shares outstanding

    326     326     326     326  
       

Basic earnings (loss) per share – continuing operations

  $ 1.05   $ (0.03 ) $ 1.75   $ 0.73  
       

Diluted earnings (loss) per share – continuing operations:

                         

Income (loss) from continuing operations available to common shareholders

  $ 341   $ (9 ) $ 570   $ 238  

Income impact of assumed conversions

    1         1      
       

Income (loss) from continuing operations available to common shareholders and assumed conversions

  $ 342   $ (9 ) $ 571   $ 238  
       

Weighted average common shares outstanding

    326     326     326     326  

Incremental shares from assumed conversions

    1     1     1     1  
       

Adjusted weighted average shares – diluted

    327     327     327     327  
       

Diluted earnings (loss) per share – continuing operations

  $ 1.05   $ (0.03 ) $ 1.75   $ 0.73  
   

Stock-based compensation awards to purchase 9,645,334 and 8,641,695 shares of common stock for the three months ended June 30, 2010 and 2009, respectively, and 6,080,199 and 8,641,695 shares of common stock for the six months ended June 30, 2010 and 2009, respectively, were outstanding, but were not included in the computation of diluted earnings per share because the exercise price of the awards was greater than the average market price of the common shares; and therefore, the effect would have been antidilutive.

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Inventory

Inventory is stated at the lower of cost or market, cost being determined by the weighted-average cost method for fuel, and the average cost method for materials and supplies. Inventory at June 30, 2010 and December 31, 2009 consisted of the following:

(in millions)
  June 30,
2010

  December 31,
2009

 
   
 
  (Unaudited)
 

Coal, gas, fuel oil and raw materials

  $ 186   $ 158  

Spare parts, materials and supplies

    370     375  
       

Total

  $ 556   $ 533  
   


Margin and Collateral Deposits

Margin and collateral deposits include cash deposited with counterparties and brokers and cash received from counterparties and brokers as credit support under energy contracts. The amount of margin and collateral deposits generally varies based on changes in the value of the positions. Edison International presents margin and cash collateral deposits subject to a master netting arrangement netted with its derivative positions on its consolidated balance sheets. The following table summarizes margin and collateral deposits provided to and received from counterparties:

(in millions)
  June 30,
2010

  December 31,
2009

 
   
 
  (Unaudited)
 

Collateral provided to counterparties:

             
 

Offset against derivative liabilities

  $ 34   $ 49  
 

Reflected in margin and collateral deposits

    111     125  

Collateral received from counterparties:

             
 

Offset against derivative assets

    55     124  
 

Reflected in other current liabilities

    57     59  
   


New Accounting Guidance

Accounting Guidance Adopted in 2010

Consolidation – Improvements to Financial Reporting by Enterprises Involved with Variable Interest Entities

The FASB issued an accounting standards update that changes how a company determines when an entity, that is insufficiently capitalized or is not controlled through voting (or similar rights), should be consolidated. The determination of whether a company is required to consolidate an entity is based on, among other things, an ability to direct the activities of the entity that most significantly impact the entity's economic performance and whether the entity has an obligation to absorb losses or the right to receive expected returns of the entity. This guidance requires a company to provide additional disclosures about its involvement with variable interest entities and any significant changes in risk exposure due to that involvement. Edison International adopted this guidance prospectively effective January 1, 2010. The impact of adopting this guidance resulted in the deconsolidation of assets totaling $683 million and the consolidation of assets totaling $99 million at January 1, 2010, and resulted in a cumulative effect adjustment which increased retained earnings by $15 million. For further discussion, see Note 13.

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Fair Value Measurements and Disclosures

The FASB issued an accounting standards update that provides for new disclosure requirements related to fair value measurements. The requirements, which Edison International adopted effective January 1, 2010, include separate disclosure of significant transfers in and out of Levels 1 and 2 and the reasons for the transfers. The update also clarified existing disclosure requirements for the level of disaggregation, inputs and valuation techniques. In addition, effective January 1, 2011, the Level 3 reconciliation of fair value measurements using significant unobservable inputs should include gross rather than net information about purchases, sales, issuances and settlements. The guidance impacts disclosures only. For further discussion, see Note 10.


Accounting Guidance Not Yet Adopted

In October 2009, the FASB issued amended guidance for identifying separate deliverables in a revenue-generating transaction where multiple deliverables exist, and provides guidance for allocating and recognizing revenue based on those separate deliverables. This update also requires additional disclosure related to the significant assumptions used to determine the revenue recognition of the separate deliverables. This guidance is effective beginning January 1, 2011 and is required to be applied prospectively to new or significantly modified revenue arrangements. Edison International is currently assessing the effects this guidance may have on its consolidated financial statements.


Note 2. Derivative Instruments and Hedging Activities

Electric Utility

Commodity Price Risk

SCE is exposed to commodity price risk, which represents the potential impact that can be caused by a change in the market value of a particular commodity. SCE's hedging program reduces ratepayer exposure to variability in market prices related to SCE's power and gas activities. As part of this program, SCE enters into energy options, swaps, forward arrangements, tolling arrangements and congestion revenue rights ("CRRs"). These transactions are pre-approved by the CPUC or executed in compliance with CPUC-approved procurement plans. SCE recovers its related hedging costs through the ERRA balancing account and as a result, exposure to commodity price risk is not expected to impact earnings, but may impact cash flows.

SCE's electricity price exposure arises from energy produced and sold in the MRTU market as a result of differences between SCE's load requirements versus the amount of energy delivered from its generating facilities, existing bilateral contracts and CDWR contracts allocated to SCE.

A portion of SCE's purchased power supply is subject to natural gas price volatility. SCE's natural gas price exposure arises from purchasing natural gas for generation at Mountainview and peaker plants, from bilateral contracts where pricing is based on natural gas prices (this includes contract energy prices for most renewable QFs which are based on the monthly index price of natural gas delivered at the southern California border), and power contracts in which SCE has agreed to provide the natural gas needed for generation, referred to as tolling arrangements.

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Notional Volumes of Derivative Instruments

The following table summarizes the notional volumes of derivatives used for hedging activities:

 
   
  Economic Hedges  
Commodity
  Unit of
Measure

  June 30, 2010
  December 31, 2009
 
 
   
  (Unaudited)
 
   

Electricity options, swaps and forward arrangements

  GWh     14,686     14,868  

Natural gas options, swaps and forward arrangements

  Bcf     278     266  

Congestion revenue rights

  GWh     165,097     195,367  

Tolling arrangements1

  GWh     116,398     116,398  
   
1
In compliance with a CPUC mandate, SCE held an open, competitive solicitation that produced agreements with different project developers who have agreed to construct new southern California generating resources. SCE has entered into a number of contracts which are recorded as derivative instruments. The contracts provide for fixed capacity payments as well as pricing for energy delivered based on a heat rate and contractual operation and maintenance prices. However, due to uncertainty regarding the availability of required emission credits, some of the new generating resources may not be constructed and the contracts associated with these resources could therefore terminate, at which time SCE would no longer account for these contracts as derivatives.


Fair Value of Derivative Instruments

The following table summarizes the gross and net fair values of commodity derivative instruments at June 30, 2010:

 
  Derivative Assets
  Derivative Liabilities
   
 
 
       
 
(in millions)
  Short-
Term

  Long-
Term

  Subtotal
  Short-
Term

  Long-
Term

  Subtotal
  Net
Liability

 
   
 
  (Unaudited)
 

Non-trading activities:

                                           

Economic hedges

  $ 78   $ 197   $ 275   $ 187   $ 1,188   $ 1,375   $ 1,100  

Netting and collateral

                8         8     8  
       

Total

  $ 78   $ 197   $ 275   $ 179   $ 1,188   $ 1,367   $ 1,092  
   

The following table summarizes the gross and net fair values of commodity derivative instruments at December 31, 2009:

 
  Derivative Assets
  Derivative Liabilities
   
 
 
       
 
(in millions)
  Short-
Term

  Long-
Term

  Subtotal
  Short-
Term

  Long-
Term

  Subtotal
  Net
Liability

 
   
 
  (Unaudited)
 

Non-trading activities:

                                           

Economic hedges

  $ 160   $ 187   $ 347   $ 102   $ 496   $ 598   $ 251  
   

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Income Statement Impact of Derivative Instruments

SCE recognizes realized gains and losses on derivative instruments as purchased-power expense and recovers these costs, subject to reasonableness, from ratepayers. As a result, realized gains and losses are not reflected in earnings, but may temporarily affect cash flows. Due to expected future recovery from ratepayers, unrealized gains and losses are recorded as regulatory assets or liabilities and therefore are not reflected in earnings. The results of derivative activities and related regulatory offsets are recorded in cash flows from operating activities in the consolidated statements of cash flows.

The following table summarizes the components of economic hedging activity:

 
  Three Months Ended
June 30,

  Six Months Ended
June 30,

 
 
     
(in millions)
  2010
  2009
  2010
  2009
 
   
 
  (Unaudited)
 

Realized gains/(losses)

  $ (38 ) $ (96 ) $ (62 ) $ (194 )

Unrealized gains/(losses)

    (276 )   293     (857 )   626  
   


Contingent Features/Credit-Related Exposure

Certain derivative instruments and power procurement contracts under SCE's power and natural gas hedging activities contain collateral requirements. SCE has historically provided collateral in the form of cash and/or letters of credit for the benefit of counterparties. These requirements can vary depending upon the level of unsecured credit extended by counterparties, changes in market prices relative to contractual commitments, and other factors.

Certain of these power contracts contain a provision that requires SCE to maintain an investment grade credit rating from each of the major credit rating agencies, referred to as a "credit-risk-related contingent feature." If SCE's credit rating were to fall below investment grade, SCE may be required to pay the derivative liability or post additional collateral. The aggregate fair value of all derivative liabilities with these credit-risk-related contingent features was $232 million and $91 million, as of June 30, 2010 and December 31, 2009, respectively, for which SCE has posted no collateral to its counterparties. If the credit-risk-related contingent features underlying these agreements were triggered on June 30, 2010, SCE would be required to post $20 million of additional collateral.


Competitive Power Generation

EMG uses derivative instruments to reduce exposure to market risks that arise from fluctuations in prices of electricity, capacity, fuel, emission allowances, and transmission rights. Additionally, EMG's financial results can be affected by fluctuations in interest rates. To the extent that EMG 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 EMG's consolidated balance sheets with offsetting changes recorded in the consolidated statements of income (loss). For transactions that qualify for accounting hedge treatment, the fair value is recognized, to the extent effective, on EMG's consolidated balance sheets with offsetting changes in fair value recognized in accumulated other comprehensive income until the related forecasted transaction occurs.

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Derivative instruments that are utilized for trading purposes are measured at fair value and included in the balance sheets as derivative assets or liabilities. Changes in fair value are recognized in the consolidated statements of income (loss).


Notional Volumes of Derivative Instruments

The following table summarizes the notional volumes of derivatives used for hedging and trading activities:

June 30, 2010  
 
   
   
   
  Hedging Activities    
 
Commodity
  Instrument
  Classification
  Unit of
Measure

  Cash Flow
Hedges

  Economic
Hedges

  Trading
Activities

 
   
 
   
   
   
  (Unaudited)
 
Electricity   Forwards/Futures   Sales   GWh     29,884 1   19,257 3   33,785  
Electricity   Forwards/Futures   Purchases   GWh     408 1   18,698 3   36,700  
Electricity   Capacity   Sales   MW-Day
(in thousands)
    183 2       218 2
Electricity   Capacity   Purchases   MW-Day
(in thousands)
    17 2       557 2
Electricity   Congestion   Sales   GWh         136 4   8,964 4
Electricity   Congestion   Purchases   GWh         1,362 4   195,038 4
Natural gas   Forwards/Futures   Sales   bcf         1.5     45.0  
Natural gas   Forwards/Futures   Purchases   bcf             47.9  
Fuel oil   Forwards/Futures   Sales   barrels         120,000     319,000  
Fuel oil   Forwards/Futures   Purchases   barrels         495,000     329,000  
Coal   Forwards/Futures   Sales   tons             1,095,000  
Coal   Forwards/Futures   Purchases   tons             465,000  
   

 

(in millions)
Instrument
  Purpose
  Type of Hedge
  Notional
Amount

  Expiration Date
 
 
   
   
  (Unaudited)
   
Amortizing interest rate swap   Convert floating rate (6-month LIBOR) debt to fixed rate (3.175%) debt   Cash flow   $ 145   June 2016

Amortizing forward starting interest rate swap

 

Convert floating rate (3-month LIBOR) debt to fixed rate (4.29%) debt

 

Cash flow

 

 

122

 

December 2025
 

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December 31, 2009
 
   
 
   
   
   
  Hedging Activities
   
 
 
   
   
   
       
 
Commodity
  Instrument
  Classification
  Unit of
Measure

  Cash Flow
Hedges

  Economic
Hedges

  Trading
Activities

 
   
 
   
   
   
  (Unaudited)
 
Electricity   Forwards/Futures   Sales   GWh     24,355 1   26,838 3   23,306  
Electricity   Forwards/Futures   Purchases   GWh     106 1   25,971 3   23,404  
Electricity   Capacity   Sales   MW-Day
(in thousands)
    254 2   1 2   597 2
Electricity   Capacity   Purchases   MW-Day
(in thousands)
    11 2   2 2   736 2
Electricity   Congestion   Sales   GWh         136 4   10,212 4
Electricity   Congestion   Purchases   GWh         1,576 4   181,930 4
Natural gas   Forwards/Futures   Sales   bcf         3.3     30.8  
Natural gas   Forwards/Futures   Purchases   bcf             30.6  
Fuel oil   Forwards/Futures   Sales   barrels         250,000     120,000  
Fuel oil   Forwards/Futures   Purchases   barrels         625,000     120,000  
   

 

(in millions)
Instrument
  Purpose
  Type of Hedge
  Notional
Amount

  Expiration Date
 
 
   
   
  (Unaudited)
   
Amortizing interest rate swap   Convert floating rate (6-month LIBOR) debt to fixed rate (3.175%) debt   Cash flow   $ 160   June 2016
 
1
EMG's hedge products include forward and futures contracts that qualify for hedge accounting. This category excludes power contracts for the fossil-fueled facilities which meet the normal sales and purchase exception and are accounted for on the accrual method.

2
EMG's hedge transactions for capacity result from bilateral trades. Capacity sold in the PJM RPM auction is not accounted for as a derivative.

3
EMG also entered into transactions that adjust financial and physical positions, or day-ahead and real-time positions to reduce costs or increase gross margin. These positions largely offset each other. 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.

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Fair Value of Derivative Instruments

The following table summarizes the fair value of derivative instruments reflected on EMG's consolidated balance sheets:

June 30, 2010  
 
  Derivative Assets
  Derivative Liabilities
   
 
 
       
 
 
  Net Assets
 
(in millions)
  Short-term
  Long-term
  Subtotal
  Short-term
  Long-term
  Subtotal
 
   

Non-trading activities

                                           
 

Cash flow hedges

  $ 153   $ 14   $ 167   $ 39   $ 43   $ 82   $ 85  
 

Economic hedges

    111     3     114     93     2     95     19  

Trading activities

    237     121     358     182     50     232     126  
       

    501     138     639     314     95     409     230  

Netting and collateral received1

   
(355

)
 
(59

)
 
(414

)
 
(314

)
 
(72

)
 
(386

)
 
(28

)
       

Total

  $ 146   $ 79   $ 225   $   $ 23   $ 23   $ 202  
   

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 
December 31, 2009  
 
  Derivative Assets
  Derivative Liabilities
   
 
 
       
 
 
  Net Assets
 
(in millions)
  Short-term
  Long-term
  Subtotal
  Short-term
  Long-term
  Subtotal
 
   
 
  (Unaudited)
 

Non-trading activities

                                           
 

Cash flow hedges

  $ 240   $ 17   $ 257   $ 69   $ 6   $ 75   $ 182  
 

Economic hedges

    202     8     210     180         180     30  

Trading activities

    234     111     345     182     41     223     122  
       

    676     136     812     431     47     478     334  

Netting and collateral received1

    (479 )   (55 )   (534 )   (426 )   (32 )   (458 )   (76 )
       

Total

  $ 197   $ 81   $ 278   $ 5   $ 15   $ 20   $ 258  
   
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.

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Income Statement Impact of Derivative Instruments

The following table provides the activity of accumulated other comprehensive income, containing the information about the changes in the fair value of cash flow hedges and reclassification from accumulated other comprehensive income into results of operations:

 
  Cash Flow Hedge Activity1
Six Months Ended June 30,
   
 
  Income Statement
Location

(in millions)
  2010
  2009
 
 
  (Unaudited)
   

Accumulated other comprehensive income derivative gain at January 1

  $ 175   $ 398    

Effective portion of changes in fair value

    30     109    

Reclassification from accumulated other comprehensive income to net income

    (122 )   (55 ) Competitive power generation revenue
         

Accumulated other comprehensive income derivative gain at June 30

  $ 83   $ 452    
 
1
Unrealized derivative gains are before income taxes. The after-tax amounts recorded in accumulated other comprehensive income at June 30, 2010 and 2009 were $50 million and $269 million, respectively.

The portion of a cash flow hedge that does not offset the change in the value of the transaction being hedged, which is commonly referred to as the ineffective portion, is immediately recognized in earnings.

EMG recorded a net gain (loss) of $(7) million and $5 million during the second quarters of 2010 and 2009, respectively, and $1 million and $5 million during the six months ended June 30, 2010 and 2009, respectively, representing the amount of cash flow hedge ineffectiveness and are reflected in operating revenues on the consolidated statements of income (loss).

The effect of realized and unrealized gains (losses) from derivative instruments used for economic hedging and trading purposes on the consolidated statements of income (loss) is presented below:

 
   
  Three Months Ended June 30,
  Six Months Ended June 30,
 
 
   
     
 
  Income Statement Location
 
(in millions)
  2010
  2009
  2010
  2009
 
   
 
   
  (Unaudited)
 
Economic hedges   Operating revenue   $ (3 ) $ 3   $ (7 ) $ 16  
    Fuel expense     (2 )   14     (1 )   14  
Trading activities   Operating revenue     33     17     80     27  
   


Contingent Features/Credit Related Exposure

Certain derivative instruments contain margin and collateral deposit requirements. Since EME's credit ratings are below investment grade, EME has provided collateral in the form of cash and letters of credit for the benefit of counterparties related to the net of accounts payable, accounts receivable, unrealized losses and unrealized gains in connection with derivative activities. Certain derivative contracts do not require margin, but contain provisions that require EME or Midwest Generation to

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comply with the terms and conditions of their respective credit facilities. The credit facilities each contain financial covenants. Some hedge contracts include provisions related to a change in control or material adverse effect resulting from amendments or modifications to the related credit facility. Failure by EME or Midwest Generation to comply with these provisions may result in a termination event under the hedge contracts, enabling the counterparties to terminate and liquidate all outstanding transactions and demand immediate payment of amounts owed to them. EMMT has hedge contracts that do not require margin, but provide that each party can request additional credit support in the form of adequate assurance of performance in the case of an adverse development affecting the other party. The aggregate fair value of all derivative instruments with credit-risk-related contingent features is in an asset position at June 30, 2010 and, accordingly, the contingent features described above do not currently have a liquidity exposure. Future increases in power prices could expose EME, Midwest Generation or EMMT to termination payments or additional collateral postings under the contingent features described above.


Note 3. Liabilities and Lines of Credit

Long-Term Debt

In March 2010, SCE issued $500 million of 5.5% first and refunding mortgage bonds due in 2040. In May 2010, SCE reissued $144 million of 5.0% tax-exempt pollution control bonds due in 2035. The proceeds from these bonds were used to repay commercial paper borrowings and for general corporate purposes.

EMG consolidated the Ambit project on January 1, 2010. At June 30, 2010, this project had $71 million of bonds payable, which are supported by a letter of credit. Principal payments are due annually through October 1, 2017. Interest rates are reset weekly based on current bond yields for similar securities. The average interest rate for the six months ended June 30, 2010 was 0.26%. Annual maturities of this debt at June 30, 2010 for the next five years are summarized as follows: $8 million in 2010, $8 million in 2011, $9 million in 2012, $10 million in 2013, and $10 million in 2014. In January 2010, Edison Capital repaid in full its medium-term loans. The balance of these loans was $89 million at December 31, 2009.


Credit Agreements and Short-Term Debt

In March 2010, SCE replaced its $500 million 364-day revolving credit facility with a new $500 million three-year credit facility that terminates in March 2013.

SCE's short-term debt is generally used to finance fuel inventories, balancing account under-collections and general, temporary cash requirements including power purchase payments. At June 30, 2010, the outstanding short-term debt was $215 million at a weighted-average interest rate of 0.42%. This short-term debt is supported by $2.9 billion of credit lines. At December 31, 2009, the outstanding short-term debt was zero.

In March 2010, EMG completed through its subsidiary, Cedro Hill Wind, LLC, a non-recourse financing of its interests in the Cedro Hill wind project. The financing included a $135 million construction loan that is required to be converted to a 15-year amortizing term loan by May 31, 2011, subject to meeting specified conditions. As of June 30, 2010, there was $65 million outstanding under the construction loan at a weighted average interest rate of 3.35%.

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Edison International (parent) short-term debt is generally used to finance operating expenses and dividends. At June 30, 2010, the outstanding short-term debt was $215 million at a weighted-average interest rate of 0.71%. At December 31, 2009, the outstanding short-term debt was $85 million at a weighted-average interest rate of 0.60%.


Letters of Credit

As of June 30, 2010, letters of credit issued under EME and its subsidiaries' credit facilities aggregated $129 million and are scheduled to expire as follows: $36 million in 2010 and $93 million in 2011. Letters of credit issued under SCE's credit facilities aggregated $11 million and are scheduled to expire in 2010.


Note 4. Income Taxes

The table below contains a reconciliation of income tax expense computed at the federal statutory income tax rate to the income tax provision from continuing operations attributable to common shareholders:

 
  Three Months Ended
June 30,

  Six Months Ended
June 30,

 
 
     
(in millions)
  2010
  2009
  2010
  2009
 
   
 
  (Unaudited)
 

Provision for income tax at federal statutory rate of 35%

  $ 72   $ (187 ) $ 205   $ (58 )

Increase (decrease) in income tax from:

                         

Items presented with related state income tax, net

                         
 

Global Settlement related

    (138 )   (298 )   (138 )   (298 )
 

Change in tax accounting method for asset removal costs

    (40 )       (40 )    

State tax – net of federal benefit

    16     (13 )   23     (4 )

Health care legislation

            39      

Production and housing credits

    (19 )   (16 )   (34 )   (34 )

Property-related and other

    (27 )   (10 )   (41 )   (8 )
       

Total income tax expense from continuing operations

  $ (136 ) $ (524 ) $ 14   $ (402 )
       

Pre-tax income from continuing operations

 
$

207
 
$

(533

)

$

586
 
$

(164

)
       

Effective tax rate

   
(66%

)
 
98%
   
2%
   
245%
 
   

The CPUC requires flow-through rate-making treatment for the current tax benefit arising from certain property-related and other temporary differences which reverse over time. The accounting treatment for these temporary differences results in recording regulatory assets and liabilities for amounts that would otherwise be recorded to deferred income tax expense.


Global Settlement

During the second quarter of 2010, Edison International recognized a $138 million earnings benefit resulting from acceptance by the California Franchise Tax Board of the tax positions finalized with the IRS in 2009 as part of the Global Settlement for tax years 1986 through 2002 (described in "Item 8. Edison International Notes to Consolidated Financial Statements—Note 4. Income Taxes" of the 2009 Form 10-K) and revision to interest recorded on the federal Global Settlement. Edison International is awaiting receipt of final interest calculations from the California Franchise Tax Board.

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During the six months ended June 30, 2009, Edison International recorded a consolidated after-tax earnings charge of $274 million related to the Global Settlement finalized with the IRS and termination of Edison Capital's cross-border leases ($920 million pre-tax loss).


Change in Tax Accounting Method for Asset Removal Costs

During the second quarter of 2010, the IRS approved Edison International's request to change its tax accounting method for asset removal costs primarily related to SCE's infrastructure replacement program. As a result, Edison International recognized a $40 million earnings benefit ($28 million of which relates to asset removal costs incurred prior to 2010) from deducting asset removal costs earlier in the construction cycle. These deductions are recorded on a flow-through basis.


Health Care Legislation

During the first quarter of 2010, Edison International recognized a $39 million non-cash charge to reverse previously recognized federal tax benefits eliminated by the federal health care legislation enacted in March 2010. The Patient Protection and Affordable Care Act, as modified by the Health Care and Education Reconciliation Act, includes a provision that eliminates the federal tax deduction of retiree health care costs to the extent those costs are eligible for federal Medicare Part D subsidies. Although this change does not take effect until January 1, 2013, Edison International is required to recognize the full accounting impact of the legislation in its financial statements in the period of enactment.


Accounting for Uncertainty in Income Taxes

Unrecognized Tax Benefits

The following table provides a reconciliation of unrecognized tax benefits from January 1 to June 30 for 2010 and 2009:

(in millions)
  2010
  2009
 
   
 
  (Unaudited)
 

Balance at January 1

  $ 664   $ 2,237  

Tax positions taken during the current year:

             

Increases

    35     87  

Tax positions taken during a prior year:

             

Increases

    127     148  

Decreases

    (40 )   (26 )

Decreases for settlements during the period

    (82 )   (1,807 )
       

Balance at June 30

  $ 704   $ 639  
   

As of June 30, 2010 and December 31, 2009, respectively, if recognized, $335 million and $374 million of unrecognized tax benefits would impact the effective tax rate.


Accrued Interest and Penalties

The total amount of accrued interest and penalties related to Edison International's income tax liabilities was $278 million and $380 million as of June 30, 2010 and December 31, 2009, respectively.

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The after-tax interest income recognized and included in income tax expense was $101 million and $113 million for the three months ended June 30, 2010 and 2009, respectively, and was $88 million and $109 million for the six months ended June 30, 2010 and 2009, respectively.


Note 5. Compensation and Benefit Plans

Pension Plans and Postretirement Benefits Other Than Pensions

Pension Plans

During the six months ended June 30, 2010, Edison International made 2010 plan year contributions of $57 million and expects to make $51 million of additional contributions during the remainder of 2010. SCE recovers contributions made to most of its pension plans through CPUC-approved regulatory mechanisms. Annual contributions to these plans are expected to be, at a minimum, equal to the related annual expense.

Expense components are:

 
  Three Months Ended
June 30,

  Six Months Ended
June 30,

 
 
     
(in millions)
  2010
  2009
  2010
  2009
 
   
 
  (Unaudited)
 

Service cost

  $ 34   $ 32   $ 68   $ 63  

Interest cost

    54     52     108     103  

Expected return on plan assets

    (52 )   (42 )   (104 )   (83 )

Amortization of prior service cost

    2     4     4     8  

Amortization of net loss

    7     14     14     28  
       

Expense under accounting standards

  $ 45   $ 60   $ 90   $ 119  

Regulatory adjustment – deferred

    (14 )   (37 )   (28 )   (73 )
       

Total expense recognized

  $ 31   $ 23   $ 62   $ 46  
   


Postretirement Benefits Other Than Pensions

During the six months ended June 30, 2010, Edison International made 2010 plan year contributions of $18 million and expects to make $33 million of additional 2010 plan year contributions during the remainder of 2010. SCE's annual contributions are recovered through CPUC-approved regulatory mechanisms and are expected to be, at a minimum, equal to its total annual expense.

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Expense components are:

 
  Three Months Ended
June 30,

  Six Months Ended
June 30,

 
 
     
(in millions)
  2010
  2009
  2010
  2009
 
   
 
  (Unaudited)
 

Service cost

  $ 8   $ 11   $ 16   $ 22  

Interest cost

    31     36     62     72  

Expected return on plan assets

    (25 )   (21 )   (50 )   (42 )

Amortization of prior service cost (credit)

    (9 )   (8 )   (18 )   (15 )

Amortization of net loss

    8     16     16     31  
       

Total expense

  $ 13   $ 34   $ 26   $ 68  
   


Stock-Based Compensation

During the first quarter of 2010, Edison International granted its 2010 stock-based compensation awards, which included stock options, performance shares and restricted stock units. Total stock-based compensation expense (reflected in the caption "Other operation and maintenance" on the consolidated statements of income (loss)) was $9 million and $10 million for the three months ended June 30, 2010 and 2009, respectively, and was $17 million and $16 million for the six months ended June 30, 2010 and 2009, respectively. The income tax benefit recognized in the consolidated statements of income (loss) was $4 million for the three months ended June 30, 2010 and 2009, and was $7 million and $6 million for the six months ended June 30, 2010 and 2009, respectively. Consistent with SCE's 2009 GRC, no stock-based compensation has been capitalized since December 31, 2008. Excess tax benefits included in "Settlements of stock-based compensation – net" in the financing section of the consolidated statements of cash flows were $2 million and $4 million for the six months ended June 30, 2010 and 2009, respectively.


Stock Options

The following is a summary of the status of Edison International stock options:

 
   
  Weighted-Average
   
 
 
   
       
 
 
  Stock options
  Exercise
Price

  Remaining
Contractual
Term (Years)

  Aggregate
Intrinsic Value

 
   
 
  (Unaudited)
 

Outstanding at December 31, 2009

    17,368,032   $ 32.15              

Granted

    3,714,111     33.26              

Expired

    (18,661 )   45.74              

Forfeited

    (146,821 )   31.09              

Exercised

    (377,107 )   22.59              
                   

Outstanding at June 30, 2010

    20,539,554     32.52     6.58        
             

Vested and expected to vest at June 30, 2010

    20,034,692     32.53     6.52   $ 77,846,571  
       

Exercisable at June 30, 2010

    11,854,616     32.55     5.01     55,789,066  
   

Cash outflows to purchase Edison International shares in the open market to settle stock option exercises were $6 million and $1 million for the three months ended June 30, 2010 and 2009,

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respectively, and were $13 million and $6 million for the six months ended June 30, 2010 and 2009, respectively. Cash inflows from participants to exercise stock options were $4 million and $1 million for the three months ended June 30, 2010 and 2009, respectively, and were $9 million and $4 million for the six months ended June 30, 2010 and 2009, respectively. The tax benefit realized from options exercised was $1 million and less than $1 million for the three months ended June 30, 2010 and 2009, respectively, and $2 million and $1 million for the six months ended June 30, 2010 and 2009, respectively.


Performance Shares

The following is a summary of the status of Edison International nonvested performance shares classified as equity awards:

 
  Performance
Shares

  Weighted-Average
Grant-Date
Fair Value

 
   
 
  (Unaudited)
 

Nonvested at December 31, 2009

    343,452   $    35.41  

Granted

    140,487   32.36  

Forfeited

    (68,925 ) 55.62  
           

Nonvested at June 30, 2010

    415,014   31.02  
   

The following is a summary of the status of Edison International nonvested performance shares classified as liability awards (the current portion is reflected in the caption "Other current liabilities" and the long-term portion is reflected in "Accumulated provision for pensions and benefits" on the consolidated balance sheets):

 
  Performance
Shares

  Weighted-Average
Fair Value

 
   
 
  (Unaudited)
 

Nonvested at December 31, 2009

    343,452      

Granted

    140,487      

Forfeited

    (68,925 )    
           

Nonvested at June 30, 2010

    415,014   $    18.83  
   

There were no performance shares settled in 2009 or 2010.


Note 6. Commitments and Contingencies

Commitments

SCE entered into a 20-year power purchase contract which is classified as a capital lease and is expected to be recorded on the consolidated balance sheets upon commencement of the contract in 2013. SCE's commitments upon commencement are estimated to be: $23 million in 2013, $44 million in 2014, and $805 million for the remaining period thereafter.

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Other Commitments

At June 30, 2010, SCE had power purchase contracts with additional commitments estimated to be: $67 million for the remainder of 2010, $83 million in 2011, $67 million in 2012, $39 million in 2013, $39 million in 2014, and $613 million for the remaining period thereafter.

At June 30, 2010, EMG's subsidiaries had firm commitments to spend approximately $447 million during the remainder of 2010 on capital and construction expenditures. These expenditures primarily relate to the construction of wind projects. EMG intends to fund these expenditures through project-level and turbine vendor financing, U.S. Treasury grants, cash on hand and cash generated from operations.

EMG has entered into various turbine supply agreements with vendors to support its wind development efforts. As of June 30, 2010, EME had commitments, excluding turbines subject to the legal dispute described below, to purchase 46 wind turbines (69 MW) and had 13 wind turbines (33 MW) in storage to be used for future wind projects. EMG has 59 wind turbines (102 MW) available for future projects, excluding turbines allocated to projects in construction and turbines subject to the legal dispute. EMG has payment commitments related to wind turbines of $85 million due in 2011. During the second quarter, EMG deferred the delivery and $82 million in payments for 69 MW of turbines to January 2011.

Excluded from the turbine agreements referred to above is a turbine supply agreement between Mitsubishi Power Systems Americas, Inc. and EME, which is subject to a legal dispute. EME has made deposits of $68 million for the purchase of 83 wind turbines (199 MW) under this agreement. The remaining payments under this agreement subject to dispute are $289 million, mostly related to undelivered wind turbines. Resolution of this dispute will impact whether, and to what extent, future payments may be due under this agreement.

At June 30, 2010, Midwest Generation and Homer City had fuel purchase commitments with various third-party suppliers for the purchase of coal. Based on the contract provisions, which consist of fixed prices, subject to adjustment clauses, these minimum commitments are estimated to aggregate $936 million, summarized as follows: $251 million for the remainder of 2010, $405 million in 2011, $247 million in 2012, and $33 million in 2013.

At June 30, 2010, Midwest Generation and Homer City each had contractual agreements for the transport of coal to their respective facilities. The commitments under these contracts are based on either actual coal purchases or minimum quantities. Accordingly, contractual obligations for transportation based on actual coal purchases are derived from committed coal volumes set forth in fuel supply contracts. The minimum commitments under these contracts are estimated to aggregate $314 million, summarized as follows: $143 million for the remainder of 2010, and $171 million in 2011.

In addition to the above, in July 2010, Midwest Generation entered into additional contracts for the purchase of coal. These commitments, together with the estimated transportation costs under the existing agreements, are estimated to be $101 million for 2011.

SCE and EME have letters of credit outstanding under their credit facilities. For further discussion, see Note 3.

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Guarantees and Indemnities

Edison International's subsidiaries have various financial and performance guarantees and indemnifications which are issued in the normal course of business. As discussed below, these contracts include performance guarantees, guarantees of debt and indemnifications.


Environmental Indemnities Related to the Midwest Generation Plants

In connection with the acquisition of the Midwest Generation plants, EME agreed to indemnify Commonwealth Edison with respect to specified environmental liabilities before and after December 15, 1999, the date of sale. The indemnification claims are reduced by any insurance proceeds and tax benefits related to such claims and are subject to a requirement that Commonwealth Edison takes all reasonable steps to mitigate losses related to any such indemnification claim. This indemnification for environmental liabilities is not limited in term and would be triggered by a valid claim from Commonwealth Edison. Also, in connection with the sale-leaseback transaction related to the Powerton and Joliet Stations in Illinois, EME agreed to indemnify the lessors for specified environmental liabilities. 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 Lawsuit." The sale-leaseback participants have requested similar indemnification. Except as discussed below, EME has not recorded a liability related to these environmental indemnities.

Midwest Generation entered into a supplemental agreement with Commonwealth Edison and Exelon Generation Company LLC on February 20, 2003 to resolve a dispute regarding interpretation of its reimbursement obligation for asbestos claims under the environmental indemnities set forth in the Asset Sale Agreement. Under this supplemental agreement, Midwest Generation agreed to reimburse Commonwealth Edison and Exelon Generation for 50% of specific asbestos claims pending as of February 2003 and related expenses less recovery of insurance costs, and agreed to a sharing arrangement for liabilities and expenses associated with future asbestos-related claims as specified in the agreement. As a general matter, Commonwealth Edison and Midwest Generation apportion responsibility for future asbestos-related claims based upon the number of exposure sites that are Commonwealth Edison locations or Midwest Generation locations. The obligations under this agreement are not subject to a maximum liability. The supplemental agreement had an initial five-year term with an automatic renewal provision for subsequent one-year terms (subject to the right of either party to terminate); pursuant to the automatic renewal provision, it has been extended until February 2011. There were approximately 217 cases for which Midwest Generation was potentially liable and that had not been settled and dismissed at June 30, 2010. Midwest Generation had recorded a $49 million liability at June 30, 2010 for previous, pending and future claims.

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


Environmental Indemnity Related to the Homer City Facilities

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

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obligation of Homer City. Also, in connection with the sale-leaseback transaction related to the Homer City facilities, Homer City agreed to indemnify the lessors for specified environmental liabilities. Due to the nature of the obligation under this indemnity provision, it is not subject to a maximum potential liability and does not have an expiration date. For discussion of the NOV received by Homer City and associated indemnity claims, see "—Contingencies—Homer City New Source Review Notice of Violation." EME has not recorded a liability related to this indemnity.


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. Payments would be triggered under these indemnities by valid claims from the sellers or purchasers, as the case may be. At June 30, 2010, EME had recorded a liability of $39 million related to these matters.

In connection with the sale of various domestic assets, EME has from time to time provided indemnities to the purchasers for taxes imposed with respect to operations of the asset prior to the sale. EME has also provided indemnities to purchasers for items specified in each agreement (for example, specific pre-existing litigation matters and/or environmental conditions). Due to the nature of the obligations under these indemnity agreements, a maximum potential liability cannot be determined. Not all indemnities under the asset sale agreements have specific expiration dates. Payments would be triggered under these indemnities by valid claims from the sellers or purchasers, as the case may be. No significant amounts are recorded as a liability for these matters.

In connection with the sale-leaseback transactions related to the Homer City facilities in Pennsylvania, the Powerton and Joliet Stations in Illinois and, previously, the Collins Station in Illinois, EME and several of its subsidiaries entered into tax indemnity agreements. Although the Collins Station lease terminated in April 2004, Midwest Generation's tax indemnity agreement with the former lease equity investor is still in effect. Under these tax indemnity agreements, these entities agreed to indemnify the lessors in the sale-leaseback transactions for specified adverse tax consequences that could result in certain situations set forth in each tax indemnity agreement, including specified defaults under the respective leases. The potential indemnity obligations under these tax indemnity agreements could be significant. Due to the nature of these potential obligations, EME cannot determine a maximum potential liability which would be triggered by a valid claim from the lessors. No significant amounts are recorded as a liability for these matters.


Indemnity Provided as Part of the Acquisition of Mountainview

In connection with the acquisition of Mountainview, SCE agreed to indemnify the seller with respect to specific environmental claims related to SCE's previously owned San Bernardino Generating Station, divested by SCE in 1998 and reacquired as part of the Mountainview acquisition. SCE retained certain responsibilities with respect to environmental claims as part of the original divestiture of the station. The aggregate liability for either party to the purchase agreement for damages and other amounts is a maximum of $60 million. This indemnification for environmental liabilities expires on or before March 12, 2033. SCE has not recorded a liability related to this indemnity.

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Mountainview Filter Cake Indemnity

The Mountainview power plant utilizes water from on-site groundwater wells and City of Redlands ("City") recycled water for cooling purposes. Unrelated to the operation of the plant, this water contains perchlorate. The pumping of the water removes perchlorate from the aquifer beneath the plant and concentrates it in the plant's wastewater treatment "filter cake." Use of this impacted groundwater for cooling purposes was mandated by Mountainview's California Energy Commission permit. SCE has indemnified the City for cleanup or associated actions related to groundwater contaminated by perchlorate due to the disposal of filter cake at the City's solid waste landfill. The obligations under this agreement are not limited to a specific time period or subject to a maximum liability. SCE has not recorded a liability related to this indemnity.


Other Edison International Indemnities

SCE provides other indemnifications through contracts entered into in the normal course of business. These are primarily indemnifications against adverse litigation outcomes in connection with underwriting agreements, and specified environmental indemnities and income taxes with respect to assets sold. SCE's obligations under these agreements may be limited in terms of time and/or amount, and in some instances SCE may have recourse against third parties for certain indemnities. The obligated amounts of these indemnifications often are not explicitly stated, and the overall maximum amount of the obligation under these indemnifications cannot be reasonably estimated. SCE has not recorded a liability related to these indemnities.


Contingencies

In addition to the matters disclosed in these Notes, Edison International is involved in other legal, tax and regulatory proceedings before various courts and governmental agencies regarding matters arising in the ordinary course of business. Edison International believes that the outcome of these other proceedings will not materially affect its results of operations, financial position or liquidity.


Environmental Developments

Edison International is subject to numerous environmental laws and regulations, which typically require a lengthy and complex process for obtaining licenses, permits and approvals and require it to incur substantial costs to operate existing facilities, construct and operate new facilities, and mitigate or remove the effect of past operations on the environment.

Possible developments, such as the enactment of more stringent environmental laws and regulations, proceedings that may be initiated by environmental and other regulatory authorities, cases in which new theories of liability are recognized, and settlements agreed to by other companies that establish precedent or expectations for the power industry, could affect the costs and the manner in which business is conducted, and could cause substantial additional capital expenditures or operational expenditures or the ceasing of operations at certain facilities. There is no assurance that any additional costs arising from such developments would be recovered from customers or that Edison International's financial position, results of operations and cash flows would not be materially affected by these developments.

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Midwest Generation Environmental Compliance Plans and Costs

During the second quarter of 2010, Midwest Generation continued its permitting and planning activities for NOx and SO2 controls to meet the requirements of the CPS. Midwest Generation has now received all necessary permits from the Illinois EPA allowing the installation of SNCR technology on multiple units to meet the NOx portion of the CPS.

In addition, work continued on the possible employment of FGD technology using dry scrubbing with sodium-based sorbents as a method to comply with the SO2 portion of the CPS. Testing of this technology demonstrated significant reductions in SO2 emissions when using the low-sulfur coal employed by Midwest Generation. Use of this technology in combination with low-sulfur coal is expected to require substantially less capital and installation time than the spray dryer absorber technology originally contemplated, but would likely result in higher ongoing operating costs and may consequently result in lower dispatch rates and competitiveness of Midwest Generation's plants. Also, the use of dry scrubbing with sodium-based sorbents to meet environmental regulations will likely require Midwest Generation to incur the costs of upgrading its particulate removal systems.

Based on this work, Midwest Generation estimates the cost of retrofitting all units, using dry scrubbing with sodium-based sorbents to comply with CPS requirements for SO2 emissions, at approximately $1.2 billion in 2010 dollars. If completed, these expenditures would be incurred over multiple years. Midwest Generation expects to seek permits from the Illinois EPA for select initial units later this year.

Decisions regarding whether or not to proceed with the above projects or other approaches to compliance remain subject to a number of factors, such as market conditions, regulatory and legislative developments, and forecasted commodity prices and capital and operating costs applicable at the time decisions are required or made. Midwest Generation could also elect to shut down units, instead of installing controls, to be in compliance with the CPS, and, therefore, decisions about any particular combination of retrofits and shutdowns it may ultimately employ to comply with the CPS also remain subject to conditions applicable at the time decisions are required or made. Due to existing uncertainties about these factors, Midwest Generation may defer final decisions about particular units for the maximum time available. Accordingly, final decisions on whether to install controls, to install particular kinds of controls, and to actually expend capital that is budgeted may not occur until 2012 for some of the units and potentially later for others.


Homer City Environmental Issues and Capital Resource Limitations

Homer City operates SCR equipment on all three units to reduce NOx emissions, operates FGD equipment on Unit 3 to reduce SO2 emissions, and uses coal-cleaning equipment on site to reduce the ash and sulfur content of raw coal to meet both combustion and environmental requirements. Homer City may be required to install additional environmental equipment on Unit 1 and Unit 2 to comply with environmental regulations for future operations. For further information, see "—Transport Rule" and "—Homer City New Source Review Notice of Violation." Restrictions under the agreements entered into as part of Homer City's 2001 sale-leaseback transaction could affect, and in some cases significantly limit or prohibit, Homer City's ability to incur indebtedness or make capital expenditures. Homer City will have limited ability to obtain additional outside capital for such projects without amending its lease and related agreements. EME is under no contractual obligation to provide funding to Homer City.

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Greenhouse Gas Regulation

On June 3, 2010, the US EPA finalized the PSD and Title V GHG tailoring rule. The effective date of the final rule is August 2, 2010. The emissions thresholds for CO2 equivalents in the final rule are as follows:

 
January – June 2011   75,000 tons per year for new and modified sources already subject to PSD for pollutants other than GHGs

July 2011 – June 2013

 

100,000 tons per year for new sources, and
75,000 tons per year for modified sources
 

Petitions for judicial review of the GHG tailoring rule are to be submitted by August 2, 2010. Legal challenges to the GHG tailoring rule have been filed.


Transport Rule

On July 6, 2010, the US EPA issued a Notice of Proposed Rulemaking for a proposed rule, known as the Transport Rule, which would require 31 eastern states (including Pennsylvania and Illinois) and the District of Columbia to substantially reduce power plant emissions of NOx and SO2 starting in 2012, with additional reductions in 2014. The Transport Rule would replace the Clean Air Interstate Rule, which had been remanded to the US EPA in 2008 for issuance of a revised rule.

The US EPA has proposed three possible approaches to emissions allowance trading. Under its preferred approach, a pollution limit would be set for each state, intrastate trading would be permitted among power plants, and limited interstate trading would also be permitted consistent with the requirement that each state meet its own pollution control obligations. Under the first alternative, a pollution limit would be set for each state, and only intrastate trading of allowances would be permitted. Under the second alternative, a pollution limit would be set for each state and an emissions limit would be set for each power plant, and limited emissions averaging would be permitted among affected units.

Under the Transport Rule, each covered state would initially be subject to a federal implementation plan designed to reduce pollution that significantly contributed to nonattainment of, or interferes with the maintenance of, NAAQS in other states. States would be able to choose to develop state implementation plans to replace the federal implementation plans.

Comments on the Transport Rule will be due 60 days after its publication in the Federal Register. The Transport Rule is scheduled to be finalized in 2011. The Clean Air Interstate Rule will remain in place until that time. EME believes that the US EPA's preferred approach to emissions allowance trading would provide allowance allocations which are adequate for the Midwest Generation plants based on projected emissions using the Illinois CPS allowable emission rates. The proposed rule, if adopted, may require the installation of additional environmental equipment to reduce SO2 emissions at Units 1 and 2 of the Homer City facilities to continue to operate under the rule.


National Ambient Air Quality Standard for Sulfur Dioxide

On June 2, 2010, the US EPA finalized the primary NAAQS for SO2 by establishing a new one-hour standard at a level of 75 parts per billion. The final standard is in line with EME's expectations and is

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being taken into account in EME's environmental compliance strategy. Revisions to state implementation plans to achieve compliance with the new standard are due to be submitted to the US EPA by February 2014. The US EPA anticipates that the deadline for attainment with the SO2 NAAQS will be August 2017 (five years after the US EPA intends to finalize initial determinations as to the areas of the country that are and are not in attainment with the primary SO2 NAAQS).


Hazardous Substances and Hazardous Waste Laws

On June 21, 2010, the US EPA published proposed regulations relating to coal combustion wastes. Two different proposed approaches are under consideration. The first approach, under which the US EPA would list these wastes as special wastes subject to regulation under Subtitle C of the Resource Conservation and Recovery Act (the section for hazardous wastes), could require EME to incur additional capital and operating costs. The second approach, under which the US EPA would regulate these wastes under Subtitle D of the Resource Conservation and Recovery Act (the section for nonhazardous wastes), is substantially similar to the requirements of existing regulations.


California Renewable Energy Developments

In June 2010, CARB released a proposed Renewable Electricity Standard regulation, which would require most retail sellers of electricity in California to procure 33% of their electricity from eligible renewable energy resources by 2020. The California legislature is also contemplating legislation to adopt a 33% renewables portfolio standard that may supersede the CARB regulation and impose its own program structure. Due to the possibility of legislation, the CARB has postponed voting on its proposed regulation until September 2010 at the Governor's request. SCE believes that achieving a 33% renewables portfolio standard in this timeframe will be highly ambitious, given the magnitude of the infrastructure build-out required and the slow pace of transmission permitting and approvals.


Once-Through Cooling

In May 2010, the California State Water Resources Board issued a final policy, which establishes closed-cycle wet cooling as required technology for retrofitting existing once-through cooled plants like San Onofre and many of the existing fossil-fueled power plants along the California coast. The final policy requires an independent engineering study to be conducted regarding the feasibility of compliance by California's two coastal nuclear power plants. Depending on the results of the study, the required compliance may result in significant capital expenditures at San Onofre and may affect its operations. It may also significantly impact SCE's ability to procure generating capacity from fossil-fueled plants that use ocean water in once-through cooling systems, system reliability and the cost of electricity to the extent other coastal power plants in California are forced to shut down or limit operations. The policy has the potential to adversely affect California's nineteen once-through cooled power plants, which provide over 21,000 MW of combined, in-state generation capacity, including over 9,100 MW of capacity interconnected within SCE's service territory.


Environmental Remediation

Edison International records its environmental remediation liabilities when site assessments and/or remedial actions are probable and a range of reasonably likely cleanup costs can be estimated. Edison International reviews its sites and measures the liability quarterly, by assessing a range of reasonably likely costs for each identified site using currently available information, including existing technology, presently enacted laws and regulations, experience gained at similar sites, and the probable level of involvement and financial condition of other potentially responsible parties. These estimates include

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costs for site investigations, remediation, operations and maintenance, monitoring and site closure. Unless there is a probable amount, Edison International records the lower end of this reasonably likely range of costs (reflected in "Other long-term liabilities") at undiscounted amounts.

As of June 30, 2010, Edison International's recorded estimated minimum liability to remediate its 28 identified sites at SCE (23 sites) and EME (5 sites primarily related to Midwest Generation) was $41 million, of which $38 million was related to SCE. Edison International's other subsidiaries have no identified remediation sites. The ultimate costs to clean up Edison International's identified sites may vary from its recorded liability due to numerous uncertainties inherent in the estimation process, such as: the extent and nature of contamination; the scarcity of reliable data for identified sites; the varying costs of alternative cleanup methods; developments resulting from investigatory studies; the possibility of identifying additional sites; and the time periods over which site remediation is expected to occur. Edison International believes that, due to these uncertainties, it is reasonably possible that cleanup costs at these identified sites could exceed its recorded liability by up to $223 million, all of which is related to SCE. The upper limit of this range of costs was estimated using assumptions least favorable to Edison International among a range of reasonably possible outcomes. In addition to its identified sites (sites in which the upper end of the range of costs is at least $1 million), SCE also has 34 immaterial sites for which total liability ranges from $5 million (the recorded minimum liability) to $10 million.

The CPUC allows SCE to recover 90% of its environmental remediation costs at certain sites, representing $32 million of its recorded liability, through an incentive mechanism (SCE may request to include additional sites). Under this mechanism, SCE will recover 90% of cleanup costs through customer rates; shareholders fund the remaining 10%, with the opportunity to recover these costs from insurance carriers and other third parties. SCE has successfully settled insurance claims with all responsible carriers. SCE expects to recover costs incurred at its remaining sites through customer rates. SCE has recorded a regulatory asset of $39 million for its estimated minimum environmental-cleanup costs expected to be recovered through customer rates.

Edison International's identified sites include several sites for which there is a lack of currently available information, including the nature and magnitude of contamination, and the extent, if any, that Edison International may be held responsible for contributing to any costs incurred for remediating these sites. Thus, no reasonable estimate of cleanup costs can be made for these sites.

SCE expects to clean up its identified sites over a period of up to 30 years. Remediation costs in each of the next several years are expected to range from $3 million to $18 million. Recorded costs were $3 million and $2 million for the three months ended June 30, 2010 and 2009, respectively, and were $3 million and $5 million for the six months ended June 30, 2010 and 2009, respectively.

Based on currently available information, Edison International believes it is unlikely that it will incur amounts in excess of the upper limit of the estimated range for its identified sites and, based upon the CPUC's regulatory treatment of environmental remediation costs incurred at SCE, Edison International believes that costs ultimately recorded will not materially affect its results of operations, financial position or cash flows. There can be no assurance, however, that future developments, including additional information about existing sites or the identification of new sites, will not require material revisions to such estimates.

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Federal and State Income Taxes

Edison International's federal income tax returns are currently under examination by the IRS for tax years 2003 through 2006 and are subject to examination through tax year 2009. Edison International's California state income tax returns are subject to examination for tax years 1991 through 2009.


2010 FERC Rate Case

In September 2009, the FERC issued an order allowing SCE to implement its proposed 2010 rates effective March 1, 2010, subject to refund. The proposed rates would increase SCE's FERC revenue requirement by $107 million, or 24%, over the 2009 FERC revenue requirement primarily due to an increase in transmission rate base, and would result in an approximate 1% increase to SCE's overall system average rate. SCE has terminated settlement negotiations and begun the litigation process for the proposed 2010 rates. A final decision is expected in the second half of 2011.


FERC Transmission Incentives and CWIP Proceedings

In November 2007, the FERC issued an order granting ROE incentive adders, recovery of the ROE and incentive adders in the CWIP proceedings, and 100% recovery of abandoned plant costs (if any) for three of SCE's transmission projects: 125 basis point adder for both DPV2 and Tehachapi, and a 75 basis point adder for Rancho Vista. The CPUC filed an appeal of this order, which had been stayed pending final resolution by the FERC of the 2008 CWIP proceeding. In April 2010, the FERC issued an order on SCE's 2008 CWIP proceeding. The order sets SCE's 2008 base ROE (before incentives) at 9.54% and establishes a methodology for determining the base ROE for 2009 and 2010 CWIP incentives. In June 2010, SCE filed an application for rehearing with the FERC. The order did not have a material impact on SCE's earnings or cash flows. The outcomes of the 2009 and 2010 CWIP proceedings are still pending. SCE began collecting the 2010 CWIP revenue requirements in rates on June 1, 2010. The collected 2008 through 2010 CWIP revenue requirements are subject to refund, pending a final FERC order on these matters.


Homer City New Source Review Notice of Violation

Recent Developments

In May 2010, Homer City received an NOV from the US EPA. The new NOV alleges claims similar to those in the 2008 NOV, but it adds non-attainment NSR requirements to the alleged PSD violations. It also adds two prior owners of the Homer City facilities as parties.

In July 2010, Homer City received a 60-day Notice of Intent to Sue signed by the State of New York and the PADEP, stating their intent to file a citizen suit based on the same or similar theories advanced by the US EPA in the NOV. The Notice of Intent to Sue also named the sale-leaseback owner participants of the Homer City facilities, Homer City's general partner and limited partner, and two prior owners of the Homer City facilities.


Background

In June 2008, Homer City received an NOV from the US EPA alleging that, beginning in 1988, Homer City (or former owners of the Homer City facilities) performed repair or replacement projects at Homer City Units 1 and 2 without first obtaining construction permits as required by the PSD requirements of the CAA. The US EPA also alleges that Homer City has failed to file timely and

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complete Title V permits. The NOV does not specify the penalties or other relief that the US EPA seeks for the alleged violations. On June 30, 2009 and January 2, 2010, the US EPA issued requests for information to Homer City under Section 114 of the CAA. Homer City is working on a response to the requests. Homer City has met with the US EPA and has expressed its intent to explore the possibility of a settlement. If no settlement is reached and the DOJ files suit, litigation could take many years to resolve the issues alleged in the NOV. EME cannot predict the outcome of this matter or estimate the impact on its facilities, its results of operations, financial position or cash flows.

Homer City has sought indemnification for liability and defense costs associated with the NOV from the sellers under the asset purchase agreement pursuant to which Homer City acquired the Homer City facilities. The sellers responded by denying the indemnity obligation, but accepting a portion of defense costs related to the claims.

Homer City notified the sale-leaseback owner participants of the Homer City facilities of the NOV under the operative indemnity provisions of the sale-leaseback documents. The owner participants of the Homer City facilities, in turn, sought indemnification and defense from Homer City for costs and liabilities associated with the Homer City NOV. Homer City responded by recognizing its indemnity obligation and defense of the claims on terms consistent with its contractual obligations.


Midwest Generation New Source Review Lawsuit

Recent Developments

In March 2010, the Federal District Court for the Northern District of Illinois dismissed nine of the ten counts related to PSD requirements in the complaint filed by the US EPA and the State of Illinois against Midwest Generation, holding that, as a subsequent owner, Midwest Generation could not be held liable under the PSD provisions for modifications allegedly made by Commonwealth Edison, the prior owner of the Midwest Generation plants. The Court also dismissed the tenth count to the extent it sought civil penalties under the CAA, as barred by the applicable statute of limitations. The decision did not address (i) 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 or (ii) the complaint in intervention filed by a group of Chicago-based environmental action groups, which also alleges opacity and particulate matter violations.

In April 2010, the US EPA formally issued to EME the same NOV that was issued to Midwest Generation in 2007. The transmittal letter stated that the action was based on a review of the asset purchase agreement for the Midwest Generation plants and that the NOV was being issued to EME as a successor in interest to Commonwealth Edison.

In June 2010, the US EPA, the State of Illinois, and several the environmental groups filed amended complaints in the New Source Review litigation. The amended complaints are similar to the prior complaints, but seek to add Commonwealth Edison and EME as defendants and introduce new legal theories to impose liability on Midwest Generation and EME. An August status hearing has been scheduled, at which time a schedule for responses -to the amended complaints and other procedural matters will be determined.


Background

In August 2007, Midwest Generation received an NOV from the US EPA alleging that, beginning in the early 1990s and into 2003, Midwest Generation or Commonwealth Edison performed repair or

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replacement projects at six Illinois coal-fired electric generating stations in violation of the PSD requirements and of the New Source Performance Standards of the CAA, including alleged requirements to obtain a construction permit and to install controls sufficient to meet BACT emissions 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. At approximately the same time, Commonwealth Edison received an NOV substantially similar to the Midwest Generation NOV. Midwest Generation, Commonwealth Edison, the US EPA, and the DOJ, along with several Chicago-based environmental action groups, had discussions designed to explore the possibility of a settlement but no settlement resulted.

In August 2009, the US EPA and the State of Illinois filed a complaint in the Northern District of Illinois against Midwest Generation, but not Commonwealth Edison, alleging claims substantially similar to those in the NOV. In addition to seeking penalties ranging from $25,000 to $37,500 per violation, per day, the complaint calls for an injunction ordering Midwest Generation to install controls sufficient to meet BACT emissions rates at all units subject to the complaint; to obtain new PSD or New Source Review permits for those units; to amend its applications under Title V of the CAA; to conduct audits of its operations to determine whether any additional modifications have occurred; and to offset and mitigate the harm to public health and the environment caused by the alleged CAA violations. The remedies sought by the plaintiffs in the lawsuit could go well beyond those required under the CPS. By order dated January 19, 2010, the Court allowed a group of Chicago-based environmental action groups to intervene in the case.

The owner participants of the Powerton and Joliet Stations have sought indemnification and defense from Midwest Generation and/or EME for costs and liabilities associated with these matters. EME responded by recognizing its indemnity obligation and defense of the claims on terms consistent with its contractual obligations.

An adverse decision could involve penalties and remedial actions that would have a material adverse impact on the financial condition and results of operations of EME. EME cannot predict the outcome of these matters or estimate the impact on its facilities, its results of operations, financial position or cash flows.


Navajo Nation Litigation

The Navajo Nation filed a complaint in June 1999 against SCE, among other defendants, arising out of the coal supply agreement for Mohave. Subsequently, the Hopi Tribe was added as an additional plaintiff. As amended in April 2010, the Navajo Nation's complaint asserts claims for, among other things, interference with fiduciary duties and contractual relations, fraudulent misrepresentations by nondisclosure, and various contract-related claims. The complaint claims that the defendants' actions prevented the Navajo Nation from obtaining the full value in royalty rates for the coal supplied to Mohave. The complaint seeks damages of not less than $600 million, plus interest thereon, and punitive damages of not less than $1 billion. In April 2009, in a related case filed in December 1993 against the U.S. Government, the U.S. Supreme Court found that the Navajo Nation did not have a claim for compensation. No trial date has been set for this litigation. SCE cannot predict the outcome of the Tribes' complaints against SCE.

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Nuclear Insurance

Federal law limits public liability claims from a nuclear incident to the amount of available financial protection, which is currently approximately $12.6 billion. SCE and other owners of San Onofre and Palo Verde have purchased the maximum private primary insurance available ($375 million). The balance is covered by a loss sharing program among nuclear reactor licensees. If a nuclear incident at any licensed reactor in the United States results in claims and/or costs which exceed the primary insurance at that plant site, all nuclear reactor licensees could be required to contribute their share of the liability in the form of a deferred premium.

Based on its ownership interests, SCE could be required to pay a maximum of approximately $235 million per nuclear incident. However, it would have to pay no more than approximately $35 million per incident in any one year. If the public liability limit above is insufficient, federal law contemplates that additional funds may be appropriated by Congress. This could include an additional assessment on all licensed reactor operators as a measure for raising further federal revenue.

Property damage insurance covers losses up to $500 million, including decontamination costs, at San Onofre and Palo Verde. Decontamination liability and property damage coverage exceeding the primary $500 million also has been purchased in amounts greater than federal requirements. Additional insurance covers part of replacement power expenses during an accident-related nuclear unit outage. A mutual insurance company owned by entities with nuclear facilities issues these policies. If losses at any nuclear facility covered by the arrangement were to exceed the accumulated funds for these insurance programs, SCE could be assessed retrospective premium adjustments of up to approximately $43 million per year. Insurance premiums are charged to operating expense.


Spent Nuclear Fuel

Under federal law, the DOE is responsible for the selection and construction of a facility for the permanent disposal of spent nuclear fuel and high-level radioactive waste. The DOE did not meet its contractual obligation to begin acceptance of spent nuclear fuel by January 31, 1998. Extended delays by the DOE have led to the construction of costly alternatives and associated siting and environmental issues. Currently, both San Onofre and Palo Verde have interim storage for spent nuclear fuel on site sufficient for the current license period.

In January 2004, SCE, as operating agent, filed a complaint against the DOE in the United States Court of Federal Claims seeking damages for the DOE's failure to meet its obligation to begin accepting spent nuclear fuel from San Onofre. In June 2010, the United States Court of Federal Claims issued a decision granting SCE damages of approximately $142 million to recover costs incurred through December 31, 2005. Additional legal action would be necessary to recover damages incurred after that date. The decision is subject to appeal by the DOE. Any damages recovered would be returned to SCE ratepayers or used to offset past or future fuel decommissioning or storage costs for the benefit of the ratepayer.

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Note 7. Consolidated Statements of Changes in Equity

The following table provides the changes in equity for the six months ended June 30, 2010:

 
  Equity Attributable to
Edison International

  Noncontrolling
Interests

   
 
 
       
 
(in millions)
  Common
Stock

  Accumulated
Other
Comprehensive
Income

  Retained
Earnings

  Subtotal
  Other
  Preferred
and
Preference
Stock

  Total
Equity

 
   
 
  (Unaudited)
 

Balance at December 31, 2009

  $ 2,304   $ 37   $ 7,500   $ 9,841   $ 258   $ 907   $ 11,006  

Net income

            580     580         26     606  

Other comprehensive loss

        (49 )       (49 )           (49 )

Deconsolidation of variable interest entities

                    (249 )       (249 )

Cumulative effect of a change in accounting principle, net of tax

            15     15             15  

Common stock dividends declared ($0.63 per share)

            (205 )   (205 )           (205 )

Dividends, distributions to noncontrolling interests and other

                    (3 )   (26 )   (29 )

Stock-based compensation – net

    2         (4 )   (2 )           (2 )

Noncash stock-based compensation and other

    9         (7 )   2             2  
       

Balance at June 30, 2010

  $ 2,315   $ (12 ) $ 7,879   $ 10,182   $ 6   $ 907   $ 11,095  
   

The following table provides the changes in equity for the six months ended June 30, 2009:

 
  Equity Attributable to
Edison International

  Noncontrolling
Interests

   
 
 
       
 
(in millions)
  Common
Stock

  Accumulated
Other
Comprehensive
Income

  Retained
Earnings

  Subtotal
  Other
  Preferred
and
Preference
Stock

  Total
Equity

 
   
 
  (Unaudited)
 

Balance at December 31, 2008

  $ 2,272   $ 167   $ 7,078   $ 9,517   $ 285   $ 907   $ 10,709  

Net income

            234     234     16     25     275  

Other comprehensive income

        37         37             37  

Common stock dividends declared ($0.62 per share)

            (202 )   (202 )           (202 )

Dividends, distributions to noncontrolling interests and other

                    (26 )   (25 )   (51 )

Stock-based compensation – net

    2         (2 )                

Noncash stock-based compensation and other

    11         (7 )   4             4  
       

Balance at June 30, 2009

  $ 2,285   $ 204   $ 7,101   $ 9,590   $ 275   $ 907   $ 10,772  
   

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Note 8. Accumulated Other Comprehensive Income

Edison International's accumulated other comprehensive income consists of:

(in millions)
  Cash Flow
Hedges –
Net Unrealized
Gain (Loss)

  Pension and
PBOP – Net
Gain (Loss)

  Pension and
PBOP – Prior
Service Cost

  Accumulated
Other
Comprehensive
Income (Loss)

 
   
 
  (Unaudited)
 

Balance at December 31, 2009

  $ 105   $ (70 ) $ 2   $ 37  

Current period change

    (55 )   6         (49 )
       

Balance at June 30, 2010

  $ 50   $ (64 ) $ 2   $ (12 )
   

Included in accumulated other comprehensive income at June 30, 2010 was $60 million, net of tax, in unrealized gains on EMG's commodity-based cash flow hedges; and a $10 million, net of tax, unrealized loss related to interest rate hedges. EMG's 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 $67 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 revenue recognized at market prices. Actual amounts ultimately reclassified into earnings over the next 12 months could vary materially from this estimated amount as a result of changes in market conditions. The maximum period over which a commodity cash flow hedge is designated is through December 31, 2012.


Note 9. Supplemental Cash Flows Information

Edison International's supplemental cash flows information is:

 
  Six Months Ended
June 30,
 
(in millions)
  2010
  2009
 
   
 
  (Unaudited)
 

Cash payments for interest and taxes

             
 

Interest – net of amounts capitalized

  $ 305   $ 314  
 

Tax payments

    179     198  

Noncash investing and financing activities

             
 

Details of debt exchange:

             
   

Pollution-control bonds redeemed

  $ (203 ) $  
   

Pollution-control bonds issued

    203      
 

Consolidation of variable interest entities:

             
   

Assets other than cash

  $ 94   $  
   

Liabilities and non-controlling interests

    99      
 

Deconsolidation of variable interest entities:

             
   

Assets other than cash

  $ 380   $  
   

Liabilities and non-controlling interests

    476      

Dividends declared but not paid

             
 

Common stock

  $ 103   $ 101  
 

Preferred and preference stock of utility not subject to mandatory redemption

    13     13  
   

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Note 10. 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 for a liability should reflect the entity's nonperformance risk. Fair value is determined using a hierarchy to prioritize the inputs to valuation models. 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 three levels of the fair value hierarchy are:

Level 1—Unadjusted quoted prices in active markets that are accessible at the measurement date for identical assets and liabilities;

Level 2—Pricing inputs that include quoted prices for similar assets and liabilities in active markets and inputs that are observable for the asset or liability, either directly or indirectly, for substantially the full term of the derivative instrument; and

Level 3—Prices or valuations that require inputs that are both significant to the fair value measurements and unobservable.

Edison International's assets and liabilities carried at fair value primarily consist of derivative contracts, SCE nuclear decommissioning trust investments and money market funds. Derivative contracts are primarily commodity contracts for the purchase and sale of power and gas and include contracts for forward physical sales and purchases, options and forward price swaps which settle only on a financial basis (including futures contracts). Derivative contracts can be exchange or over-the-counter traded.

The fair value of derivative contracts takes into account quoted market prices, time value of money, volatility of the underlying commodities and other factors. Derivatives that are exchange traded in active markets for identical assets or liabilities are classified as Level 1. Investments in money market funds are generally classified as Level 1, as fair value is determined by observable market prices in active markets.

EMG's derivative contracts, valued based on forward market prices in active markets (PJM West Hub, Northern Illinois Hub peak and AEP/Dayton) adjusted for nonperformance risks, are classified as Level 2. EMG obtains forward market prices from traded exchanges (Intercontinental Exchange Futures U.S. or New York Mercantile Exchange) and available broker quotes. Then, EMG selects a primary source that best represents traded activity for each market to develop observable forward market prices in determining the fair value of these positions. Broker quotes or prices from exchanges are used to validate and corroborate the primary source. These price quotations reflect mid-market prices (average of bid and ask) and are obtained from sources that EMG believes to provide the most liquid market for the commodity. EMG considers broker quotes to be observable when corroborated with other information which may include a combination of prices from exchanges, other brokers and comparison to executed trades.

SCE's Level 2 derivatives primarily consist of natural gas financial swaps and natural gas physical trades for which SCE obtains the applicable Henry Hub, basis, index, or forward market prices from the New York Mercantile Exchange and Intercontinental Exchange.

Level 3 includes the majority of SCE's derivatives, including over-the-counter options, bilateral contracts, capacity contracts, and QF contracts. The fair value of these derivatives is determined using

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uncorroborated non-binding broker quotes (from one or more brokers) and models which may require SCE to extrapolate short-term observable inputs in order to calculate fair value. Broker quotes are obtained from several brokers and compared against each other for reasonableness.

Level 3 also includes derivatives that trade infrequently (such as firm transmission rights and CRRs in the California market, financial transmission rights traded in markets outside California and over-the-counter derivatives at illiquid locations) and long-term power agreements. For illiquid financial transmission rights and CRRs, objective criteria are reviewed, including system congestion and other underlying drivers, and fair value is adjusted when it is concluded that a change in objective criteria would result in a new valuation that better reflects fair value.

Changes in fair values are based on the hypothetical sale of illiquid positions. For illiquid long-term power agreements, fair value is based upon a discounting of future electricity and natural gas prices derived from a proprietary model using the risk free discount rate for a similar duration contract, adjusted for credit risk and market liquidity. Changes in fair value are based on changes to forward market prices, including forecasted prices for illiquid forward periods. In circumstances where Edison International cannot verify fair value with observable market transactions, it is possible that a different valuation model could produce a materially different estimate of fair value. As markets continue to develop and more pricing information becomes available, Edison International continues to assess valuation methodologies used to determine fair value. Derivative contracts with counterparties that have significant nonperformance risks are classified as Level 3.

In assessing nonperformance risks, Edison International reviews credit ratings of counterparties (and related default rates based on such credit ratings) and prices of credit default swaps. The market price (or premium) for credit default swaps represents the price that a counterparty would pay to transfer the risk of default, typically bankruptcy, to another party. A credit default swap is not directly comparable to the credit risks of derivative contracts, but provides market information of the related risk of nonperformance. The fair value of derivative assets and derivative liabilities nonperformance risk was $4 million and $9 million, respectively, at June 30, 2010 and was $4 million and $7 million, respectively, at December 31, 2009.

The SCE nuclear decommissioning trust investments include equity securities, U.S. treasury securities and other fixed-income securities. Equity and treasury securities are classified as Level 1 as fair value is determined by observable market prices in active or highly liquid and transparent markets. The remaining fixed-income securities are classified as Level 2. The fair value of these financial instruments is based on evaluated prices that reflect significant observable market information such as reported trades, actual trade information of similar securities, benchmark yields, broker/dealer quotes, issuer spreads, bids, offers and relevant credit information.

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The following tables set forth assets and liabilities that were accounted for at fair value by level within the fair value hierarchy:

 
  As of June 30, 2010  
(in millions)
  Level 1
  Level 2
  Level 3
  Netting and
collateral1

  Total
 
   
 
  (Unaudited)
 

Assets at Fair Value

                               
 

Money market funds2

  $ 625   $   $   $   $ 625  
       
 

Derivative contracts

                               
   

Electricity

        142     362     (88 )   416  
   

Natural gas

    2     1     83     (2 )   84  
   

Fuel oil

    8             (8 )    
       
   

Subtotal of commodity contracts

    10     143     445     (98 )   500  
       
 

Long-term disability plan

    9                 9  
       
 

Nuclear decommissioning trusts

                               
   

Stocks3

    1,635                 1,635  
   

Municipal bonds

        703             703  
   

Corporate bonds4

        395             395  
   

U.S. government and agency securities

    262     54             316  
   

Short-term investments, primarily cash equivalents5

        12             12  
       
   

Subtotal of nuclear decommissioning trusts

    1,897     1,164             3,061  
       

Total assets6

  $ 2,541   $ 1,307   $ 445   $ (98 ) $ 4,195  
   

Liabilities at Fair Value

                               
 

Derivative contracts:

                               
   

Electricity

  $   $ (68 ) $ (1,100 ) $ 70   $ (1,098 )
   

Natural gas

    (1 )   (234 )   (48 )   8     (275 )
       
   

Subtotal of commodity contracts

    (1 )   (302 )   (1,148 )   78     (1,373 )
       
   

Interest rate contracts

        (17 )           (17 )
       

Net assets (liabilities)

  $ 2,540   $ 988   $ (703 ) $ (20 ) $ 2,805  
   

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  As of December 31, 2009  
(in millions)
  Level 1
  Level 2
  Level 3
  Netting and
Collateral1

  Total
 
   
 
  (Unaudited)
 

Assets at Fair Value

                               
 

Money market funds2

  $ 1,526   $   $   $   $ 1,526  
       
 

Derivative contracts

                               
   

Electricity

        235     440     (136 )   539  
   

Natural gas

    2     10     76     (2 )   86  
   

Fuel oil

    15             (15 )    
       
   

Subtotal of commodity contracts

    17     245     516     (153 )   625  
       
 

Long-term disability plan

    8                 8  
       
 

Nuclear decommissioning trusts

                               
   

Stocks3

    1,772                 1,772  
   

Municipal bonds

        634             634  
   

Corporate bonds4

        393             393  
   

U.S. government and agency securities

    240     68             308  
   

Short-term investments, primarily cash equivalents5

    1     14             15  
       
   

Subtotal of nuclear decommissioning trusts

    2,013     1,109             3,122  
       

Total assets6

  $ 3,564   $ 1,354   $ 516   $ (153 ) $ 5,281  
   

Liabilities at Fair Value

                               
 

Derivative contracts:

                               
   

Electricity

  $   $ (85 ) $ (433 ) $ 73   $ (445 )
   

Natural gas

    (3 )   (150 )   (21 )   4     (170 )
       
   

Subtotal of commodity contracts

    (3 )   (235 )   (454 )   77     (615 )
       
   

Foreign currency and interest rate contracts

        (21 )           (21 )
       

Net assets (liabilities)

  $ 3,561   $ 1,098   $ 62   $ (76 ) $ 4,645  
   
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
At June 30, 2010 and December 31, 2009, included in cash and cash equivalents and restricted cash and at December 31, 2009, also included in prepaid expenses and other on Edison International's consolidated balance sheets.

3
At June 30, 2010 and December 31, 2009, approximately 68% and 67% of the equity investments were located in the United States, respectively.

4
Corporate bonds are diversified. At June 30, 2010 and December 31, 2009, this category included $37 million and $50 million, respectively, for collateralized mortgage obligations and other asset backed securities.

5
Excludes net assets of $22 million and $18 million of interest and dividend receivables and receivables related to pending securities sales and payables related to pending securities purchases at June 30, 2010 and December 31, 2009, respectively.

6
Excludes $32 million of cash surrender value of life insurance investments for deferred compensation at June 30, 2010 and December 31, 2009.

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The following table sets forth a summary of changes in the fair value of Level 3 assets and liabilities:

 
  Three Months Ended
June 30,

  Six Months Ended
June 30,

 
 
     
(in millions)
  2010
  2009
  2010
  2009
 
   
 
  (Unaudited)
 

Fair value, net asset (liability) at
beginning of period

  $ (397 ) $ 143   $ 62   $ (302 )

Total realized/unrealized gains (losses):

                   
 

Included in earnings1

    (18 )   (49 )   27     97  
 

Included in regulatory assets and
liabilities2

    (294 )   204     (781 )   591  
 

Included in accumulated other
comprehensive income

    (2 )       4      

Purchases and settlements, net

    2     67     (20 )   (17 )

Transfers into or out of Level 3

    6     (8 )   5     (12 )
       

Fair value, net asset (liability) at end
of period

  $ (703 ) $ 357   $ (703 ) $ 357  
   

Change during the period in unrealized
gains (losses) related to assets and
liabilities held at the end of the period3

  $ (287 ) $ 225   $ (717 ) $ 675  
   
1
Reported in "Competitive power generation" revenue on Edison International's consolidated statements of income (loss).

2
Due to regulatory mechanisms, SCE's realized and unrealized gains and losses are recorded as regulatory assets and liabilities.

3
Amounts reported in "Competitive power generation" revenue on Edison International's consolidated statements of income were $(2) million and $13 million for the three months ended June 30, 2010 and 2009, respectively, and were $32 million and $71 million for the six months ended June 30, 2010 and 2009, respectively. The remainder of the unrealized gains and losses relate to SCE. See (2) above.

There were no significant transfers between levels during the first six months of 2010. Edison International determines the fair value for transfers in and transfers out of each level as of the end of each reporting period.


Nuclear Decommissioning Trusts

SCE is collecting in rates amounts for the future costs of removal of its nuclear assets, and has placed those amounts in independent decommissioning trusts. Contributions are approximately $46 million per year. Funds collected, together with accumulated earnings, will be utilized solely for decommissioning. The CPUC has set certain restrictions related to the investments of these trusts.

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The following table sets forth amortized cost and fair value of the trust investments:

 
   
  Amortized Cost
  Fair Value
 
 
   
     
(in millions)
  Maturity
Dates1

  June 30,
2010

  December 31,
2009

  June 30,
2010

  December 31,
2009

 
   
 
   
  (Unaudited)
 

Stocks

      $ 843   $ 822   $ 1,635   $ 1,772  

Municipal bonds

    2010 – 2047     602     545     703     634  

Corporate bonds

    2010 – 2044     317     309     395     393  

U.S. government and
agency securities

    2010 – 2039     285     287     316     308  

Short-term investments
and receivables/payables

    2010     33     33     34     33  
             

Total

        $ 2,080   $ 1,996   $ 3,083   $ 3,140  
   
1
Maturity dates as of June 30, 2010.

Trust fund earnings (based on specific identification) increase the trust fund balance and the ARO regulatory liability. Proceeds from sales of securities (which are reinvested) were $315 million and $652 million for the three months ended June 30, 2010 and 2009, respectively, and $600 million and $1.3 billion for the six months ended June 30, 2010 and 2009, respectively. Unrealized holding gains, net of losses, were $1.0 billion and $1.1 billion at June 30, 2010 and December 31, 2009, respectively. Approximately 92% of the cumulative trust fund contributions were tax-deductible.

The following table sets forth a summary of changes in the fair value of the trust:

 
  Three Months Ended
June 30,

  Six Months Ended
June 30,

 
 
     
(in millions)
  2010
  2009
  2010
  2009
 
   
 
  (Unaudited)
 

Balance at beginning of period

  $ 3,248   $ 2,399   $ 3,140   $ 2,524  

Realized gains

    18     115     38     189  

Realized losses

    (5 )   (77 )   (4 )   (140 )

Unrealized gains (losses) – net

    (205 )   220     (143 )   148  

Other-than-temporary impairment

    (7 )   (9 )   (11 )   (103 )

Interest, dividends, contributions and other

    34     25     63     55  
       

Balance at end of period

  $ 3,083   $ 2,673   $ 3,083   $ 2,673  
   

Due to regulatory mechanisms, earnings and realized gains and losses (including other-than-temporary impairments) have no impact on operating revenue or earnings.

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Long-term Debt

The carrying amounts and fair values of long-term debt are:

 
  June 30, 2010
  December 31, 2009
 
 
     
(in millions)
  Carrying
Amount

  Fair Value
  Carrying
Amount

  Fair Value
 
   
 
  (Unaudited)
 

Long-term debt, including current portion

  $ 11,155   $ 10,793   $ 10,814   $ 10,452  
   

Fair values of long-term debt are based on evaluated prices that reflect significant observable market information such as reported trades, actual trade information of similar securities, benchmark yields, broker/dealer quotes of new issue prices and relevant credit information.

The carrying value of trade receivables, payables and short-term debt approximate fair value and therefore are not included in the table above.


Note 11. Regulatory Assets and Liabilities

Regulatory assets included on the consolidated balance sheets are:

(in millions)
  June 30,
2010

  December 31,
2009

 
   
 
  (Unaudited)
 

Current:

             

Regulatory balancing accounts

  $ 194   $ 94  

Energy derivatives

    143     25  

Other

    1     1  
       

    338     120  
       

Long-term:

             

Regulatory balancing accounts

    43     43  

Deferred income taxes – net

    1,775     1,561  

Unamortized nuclear investment – net

    310     340  

Nuclear-related ARO investment – net

    248     258  

Unamortized coal plant investment – net

    71     73  

Unamortized loss on reacquired debt

    277     287  

Pensions and other postretirement benefits

    1,004     1,014  

Energy derivatives

    1,092     357  

Environmental remediation

    39     36  

Other

    199     170  
       

    5,058     4,139  
       

Total regulatory assets

  $ 5,396   $ 4,259  
   

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Regulatory liabilities included on the consolidated balance sheets are:

(in millions)
  June 30,
2010

  December 31,
2009

 
   
 
  (Unaudited)
 

Current:

             

Regulatory balancing accounts

  $ 455   $ 363  

Other

    2     4  
       

    457     367  
       

Long-term:

             

Regulatory balancing accounts

    808     642  

ARO

    12     171  

Costs of removal

    2,571     2,515  
       

    3,391     3,328  
       

Total regulatory liabilities

  $ 3,848   $ 3,695  
   


Note 12. Other Income and Expenses

Other income and expenses are as follows:

 
  Three Months Ended
June 30,

  Six Months Ended
June 30,

 
 
     
(in millions)
  2010
  2009
  2010
  2009
 
   
 
  (Unaudited)
 

Other Income:

                         

Equity AFUDC

  $ 25   $ 18   $ 54   $ 35  

Increase in cash surrender value of life insurance policies

    6     6     12     13  

Other

    4     5     4     8  
       

Total utility other income

    35     29     70     56  
       

Competitive power generation and parent

    1     1         2  
       

Total other income

  $ 36   $ 30   $ 70   $ 58  
       

Other Expenses:

                         

Civic, political and related activities and donations

  $ 9   $ 6   $ 15   $ 8  

Marketing services

    2     6     3     6  

Other

    4         8     6  
       

Total utility other expenses

    15     12     26     20  
       

Competitive power generation and parent

    1     5     2     5  
       

Total other expenses

  $ 16   $ 17   $ 28   $ 25  
   


Note 13. Variable Interest Entities

Effective January 1, 2010, Edison International adopted the FASB's new guidance regarding variable interest entities ("VIEs"). A VIE is defined as a legal entity whose equity owners do not have sufficient equity at risk, or, as a group, the holders of the equity investment at risk lack any of the following three characteristics: decision-making rights, the obligation to absorb losses, or the right to receive the expected residual returns of the entity. The new guidance replaces the predominantly quantitative

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model for determining which reporting entity, if any, has a controlling financial interest in a VIE with a qualitative approach. Under this new qualitative model, the primary beneficiary is identified as the variable interest holder that has both the power to direct the activities of the VIE that most significantly impact the entity's economic performance and the obligation to absorb losses or the right to receive benefits from the entity that could potentially be significant to the VIE. The primary beneficiary is required to consolidate the VIE unless specific exceptions or exclusions are met. Commercial and operating activities are generally the factors that most significantly impact the economic performance of VIEs in which Edison International has a variable interest. Commercial and operating activities include construction, operation and maintenance, fuel procurement, dispatch and compliance with regulatory and contractual requirements.


Projects or Entities that are Consolidated

At June 30, 2010 and December 31, 2009, EMG had majority interests in 15 wind projects with a total generating capacity of 701 MW that have minority interests held by others. The projects are located in Iowa, Minnesota, New Mexico, Nebraska and Texas. As of December 31, 2009, all of these projects were consolidated by EMG. Upon the application of the new guidance effective January 1, 2010, EMG deconsolidated two of these projects. See further discussion in "—Variable Interests in VIEs that are not Consolidated—Equity Interests." In determining that EMG was the primary beneficiary of the 13 projects consolidated at June 30, 2010, the key factors considered were EMG's ability to direct commercial and operating activities and EMG's obligation to absorb losses and right to receive benefits that could potentially be significant to the variable interest entities.

The following table presents summarized financial information of the wind projects that had minority interests held by others and were consolidated by Edison International:

(in millions)
  June 30,
2010

  December 31,
2009

 
   
 
  (Unaudited)
 

Current assets

  $ 26   $ 73  

Net property, plant and equipment1

    682     944  

Other long-term assets

    2     2  
       
 

Total assets1

  $ 710   $ 1,019  
       

Current liabilities

  $ 16   $ 17  

Long-term obligations net of current maturities

    18     20  

Deferred revenues

    57     58  

Other long-term liabilities

    19     21  
       
 

Total liabilities

  $ 110   $ 116  
       

Noncontrolling interests

  $ 5   $ 76  
   
1
Amounts included assets of $253 million ($247 million of net property, plant and equipment) that were deconsolidated on January 1, 2010.

Assets serving as collateral for the debt obligations had a carrying value of $79 million and $81 million at June 30, 2010 and December 31, 2009, respectively, and primarily consist of property, plant and equipment.

EMG has a 50% partnership interest in the Ambit project. EMG has the power to direct the commercial and operating activities of the project pursuant to the existing contracts and has the obligation to absorb losses and right to receive benefits from the project. Therefore, under the new

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guidance, EMG is the primary beneficiary which resulted in the consolidation of the Ambit project by Edison International. Total assets consolidated at January 1, 2010 and June 30, 2010 were $99 million and $100 million, respectively. Substantially all of the assets of the Ambit project are pledged as collateral for the partnership's debt obligations.


Variable Interests in VIEs that are not Consolidated

Power Purchase Contracts

SCE has power purchase agreements ("PPAs") in which it has a variable interest in 17 VIEs, including 6 tolling agreements where SCE provides the natural gas to operate the plants and 11 contracts with QFs (including the Big 4 projects) that contain variable pricing provisions based on the price of natural gas. SCE has concluded that it is not the primary beneficiary of these VIEs since it does not control the commercial and operating activities of these entities. In general, because payments for capacity are the primary source of income, the most significant economic activity for SCE's VIEs is the operation and maintenance of the power plants. SCE does not have control over the operation and maintenance of the facilities considered VIEs and it does not bear operational risk of the facilities. See further discussion of the Big 4 projects below.

As of the balance sheet date, the carrying amount of assets and liabilities in SCE's consolidated balance sheet that relate to its involvement with VIEs result from amounts due under the PPAs or the fair value of those derivative contracts, which are accounted for at fair value. See Note 10 for a discussion on nonperformance risk. Further, SCE has no residual interest in the entities and has not provided or guaranteed any debt or equity support, liquidity arrangements, performance guarantees or other commitments associated with these contracts other than the purchase commitments described in Note 6. The aggregate capacity dedicated to SCE for these VIE projects was 1,749 MW at June 30, 2010 and the amounts that SCE paid to these projects were $117 million and $115 million for the three months ended June 30, 2010 and 2009, respectively, and $242 million and $231 million for the six months ended June 30, 2010 and 2009, respectively. These amounts are recoverable in customer rates.

The following table summarizes as of June 30, 2010, SCE's assets and liabilities and exposure to loss associated with SCE's variable interests in the VIEs described above:

 
  Assets
  Liabilities
   
 
 
       
 
(in millions)
  Short-
Term

  Long-
Term

  Short-
Term

  Long-
Term

  Maximum
Exposure

 
   
 
  (Unaudited)
 

Derivatives

  $   $   $ 42   $ 964   $  

Accounts payable

            59          
       

Total

  $   $   $ 101   $ 964   $  
   

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The following table summarizes as of December 31, 2009, SCE's assets and liabilities and exposure to loss associated with SCE's variable interests in the VIEs described above:

 
  Assets
  Liabilities
   
 
 
       
 
(in millions)
  Short-
Term

  Long-
Term

  Short-
Term

  Long-
Term

  Maximum
Exposure

 
   
 
  (Unaudited)
 

Derivatives

  $   $ 43   $ 17   $ 385   $ 43  

Accounts payable

            39          
       

Total

  $   $ 43   $ 56   $ 385   $ 43  
   

Realized and unrealized losses are recovered or expected to be recovered from ratepayers in rates, subject to reasonableness, and therefore are not reflected in earnings.


Equity Interests

EMG accounts for domestic energy projects where EMG has a 50% or less ownership interest and cannot exercise unilateral control under the equity method. As of June 30, 2010 and December 31, 2009, EMG had significant variable interests in projects that are not consolidated consisting of the Big 4 projects and the Sunrise project. A subsidiary of EMG operates the Big 4 projects and EMG's partner provides the fuel management services. In addition, the executive director of these projects is provided by EMG's partner. Commercial and operating activities are jointly controlled by a management committee of each VIE. Accordingly, EMG continues to account for its variable interests under the equity method.

As noted previously in "Projects or Entities that are Consolidated," EMG deconsolidated two renewable wind energy generating facilities, the Elkhorn Ridge wind project and San Juan Mesa wind project, on January 1, 2010. The commercial and operating activities of these entities are directed by a management committee comprised of representatives of each partner. Thus, EMG is not the primary beneficiary of these projects. Accordingly, effective January 1, 2010, EMG accounts for its interests in these projects under the equity method.

The following table presents the carrying amount of EMG's investments in unconsolidated variable interest entities and the maximum exposure to loss for each investment as of June 30, 2010:

 
  June 30, 2010  
(in millions)
  Investment
  Maximum
Exposure

 
   
 
  (Unaudited)
 

Natural gas-fired projects

  $ 325   $ 325  

Wind projects

    174     174  
   

EMG's maximum exposure to loss in its variable interest entities accounted for under the equity method is generally limited to its investment in these entities. Two of EMG's domestic energy projects have long-term debt that is secured by a pledge of assets of the project entity, but does not provide for any recourse to EME. Accordingly, a default on a long-term financing of a project could result in foreclosure on the assets of the project entity resulting in a loss of some or all of EMG's investment, but would not require EMG to contribute additional capital. At June 30, 2010, entities which EMG has accounted for under the equity method had indebtedness of $143 million, of which $54 million is proportionate to EMG's ownership interest in these projects.

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Big 4 Projects Consolidated Prior to 2010

Edison International has variable interests in the Big 4 Projects through equity interests held by EMG and power contracts between SCE and the Big 4 Projects that contain variable contract pricing provisions based on the price of natural gas. Prior to 2010, Edison International had determined that SCE was the primary beneficiary of these four VIEs and, therefore, consolidated these projects. Edison International deconsolidated the Big 4 Projects at January 1, 2010 since it did not control the commercial and operating activities of these projects through EMG and SCE. Commercial and operating activities are jointly controlled by a management committee of each VIE. Therefore, neither EMG, SCE nor Edison International on a consolidated basis has control of the entities. In addition, EMG's partner provides the executive director and fuel management services and the steam supply is based on the needs of EMG's partner. The deconsolidation did not result in a gain or loss.

The following table presents the carrying amounts of VIEs consolidated by Edison International at December 31, 2009 (these balances were deconsolidated at January 1, 2010):

(in millions)
  December 31,
2009

 
   
 
  (Unaudited)
 

Cash

  $ 92  

Other current assets

    81  

Competitive power generation and other property, plant and equipment—net

    253  

Other long-term assets

    4  
       
 

Total assets

  $ 430  
       

Current liabilities

  $ 64  

Asset retirement obligations

    17  

Noncontrolling interest

    349  
       
 

Total liabilities and equity

  $ 430  
   


Note 14. Business Segments

Edison International's reportable business segments include its electric utility operation segment (SCE) and a competitive power generation segment (EMG). Prior to January 1, 2010, Edison International reported three business segments: electric utility operations segment, competitive power generation segment and financial services segment. As a result of termination of the cross-border leases during 2009 and the continued decline of the remaining portfolio of the financial services segment, the remaining business activity is no longer significant enough to report separately. Accordingly, the financial services segment has been combined into the competitive power generation segment for all periods presented. The combination of these business activities is consistent with the management structure of EMG and evaluation of performance by Edison International. The significant accounting policies of the segments are the same as those described in Note 1.

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Segment income statement information was:

 
  Three Months Ended
June 30,

  Six Months Ended
June 30,

 
 
     
(in millions)
  2010
  2009
  2010
  2009
 
   
 
  (Unaudited)
 

Operating Revenue (Loss):

                         

Electric utility

  $ 2,247   $ 2,273   $ 4,406   $ 4,462  

Competitive power generation

    495     562     1,147     1,186  

Parent and other2

    (1 )   (1 )   (1 )   (2 )
       

Consolidated Edison International

  $ 2,741   $ 2,834   $ 5,552   $ 5,646  
       

Net Income (Loss) attributable to Edison International:

                         

Electric utility3

  $ 301   $ 499   $ 465   $ 707  

Competitive power generation1,4

    27     (558 )   104     (510 )

Parent and other2,5

    16     43     11     37  
       

Consolidated Edison International

  $ 344   $ (16 ) $ 580   $ 234  
   

Segment balance sheet information was:

(in millions)
  June 30,
2010

  December 31,
2009

 
   
 
  (Unaudited)
 

Total Assets:

             

Electric utility

  $ 34,213   $ 32,474  

Competitive power generation

    9,212     9,543  

Parent and other2

    (370 )   (573 )
       

Consolidated Edison International

  $ 43,055   $ 41,444  
   
1
Includes earnings (losses) from discontinued operations of $1 million and $(7) million for the three months ended June 30, 2010 and 2009, respectively, and $8 million and $(4) million for the six months ended June 30, 2010 and 2009, respectively.

2
Includes amounts from Edison International (parent) and other Edison International subsidiaries that are not significant as a reportable segment, as well as intercompany eliminations.

3
Includes earnings of $53 million and $300 million for both the three- and six-month periods ended June 30, 2010 and 2009, respectively, related to the federal and state impacts of the Global Settlement. See Note 4.

4
Includes earnings of $58 million for both the three- and six-month periods ended June 30, 2010 and losses of $612 million and $624 million for the three- and six-month periods ended June 30, 2009, respectively, related to termination of Edison Capital's cross-border leases and the federal and state impacts of Global Settlement on EMG. See Note 4.

5
Includes earnings of $27 million and $50 million for both the three- and six-month periods ended June 30, 2010 and 2009, respectively, related to the federal and state impacts of the Global Settlement. See Note 4.

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

FORWARD-LOOKING STATEMENTS

This MD&A contains "forward-looking statements" within the meaning of the Private Securities Litigation Reform Act of 1995. Forward-looking statements reflect Edison International's current expectations and projections about future events based on Edison International'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 Edison International that is incorporated in this report, or that refers to or incorporates this report, may also contain forward-looking statements. In this report and elsewhere, the words "expects," "believes," "anticipates," "estimates," "projects," "intends," "plans," "probable," "may," "will," "could," "would," "should," and variations of such words and similar expressions, or discussions of strategy or of 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 Edison International, include, but are not limited to:

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 the cost and manner of doing business;

cost of capital and the ability to borrow funds and access the capital markets on reasonable terms;

cost and availability of electricity, including the ability to procure sufficient resources to meet expected customer needs in the event of significant counterparty defaults under power-purchase agreements;

changes in the fair value of investments and other assets;

ability of SCE to recover its costs in a timely manner from its customers through regulated rates;

decisions and other actions by the CPUC, the FERC and other regulatory authorities and delays in regulatory actions;

changes in interest rates and rates of inflation, including those rates which may be adjusted by public utility regulators;

governmental, statutory, regulatory or administrative changes or initiatives affecting the electricity industry, including the market structure rules applicable to each market and price mitigation strategies adopted by Independent System Operators and Regional Transmission Organizations;

risks associated with operating nuclear and other power generating facilities, including operating risks; nuclear fuel storage issues; failure, availability, efficiency, output, cost of repairs and retrofits of equipment; and availability and cost of spare parts;

availability and creditworthiness of counterparties and the resulting effects on liquidity in the power and fuel markets and/or the ability of counterparties to pay amounts owed in excess of collateral provided in support of their obligations;

cost and availability of labor, equipment and materials;

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ability to obtain sufficient insurance, including insurance relating to SCE's nuclear facilities and wildfire-related liability, and to recover the costs of such insurance;

ability to recover uninsured losses in connection with wildfire-related liability;

effects of legal proceedings, changes in or interpretations of tax laws, rates or policies, and changes in accounting standards;

potential for penalties or disallowances caused by non-compliance with applicable laws and regulations;

outcome of disputes with state tax authorities regarding tax positions taken by Edison International;

cost and availability of coal, natural gas, fuel oil, and nuclear fuel, and related transportation to the extent not recovered through regulated rate cost escalation provisions or balancing accounts;

cost and availability of emission credits or allowances for emission credits;

transmission congestion in and to each market area and the resulting differences in prices between delivery points;

ability to provide sufficient collateral in support of hedging activities and power and fuel purchased;

weather conditions, natural disasters and other unforeseen events;

risks inherent in the development of generation projects and transmission and distribution infrastructure replacement and expansion projects, including those related to project site identification, construction, permitting, and governmental approvals; and

risks that competing transmission systems will be built by merchant transmission providers in SCE's territory.

Additional information about risks and uncertainties, including more detail about the factors described above, are discussed throughout this MD&A and in the "Risk Factors" section included in Part I, Item 1A of the 2009 Form 10-K. Readers are urged to read this entire report, including the information incorporated by reference, and carefully consider the risks, uncertainties and other factors that affect Edison International's business. Forward-looking statements speak only as of the date they are made and Edison International is not obligated to publicly update or revise forward-looking statements. Readers should review future reports filed by Edison International with the Securities and Exchange Commission.

This MD&A for the three- and six-month periods ended June 30, 2010 discusses material changes in the consolidated financial condition, results of operations and other developments of Edison International since December 31, 2009, and as compared to the three-and six-month periods ended June 30, 2009. This discussion presumes that the reader has read or has access to Edison International's MD&A for the calendar year 2009 (the "year-ended 2009 MD&A"), which was included in the 2009 Form 10-K.

Except when otherwise stated, references to each of Edison International, SCE and EMG mean each such company with its subsidiaries on a consolidated basis. References to "Edison International (parent)" or "parent company" mean Edison International on a stand-alone basis, not consolidated with its subsidiaries.

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EDISON INTERNATIONAL OVERVIEW

Introduction

This overview is presented in six sections:

Highlights of operating results,

SCE capital program,

SCE 2012 General Rate Case,

Environmental developments,

EMG's renewables programs, and

Parent company liquidity.

The overview is presented as an update to the overview presented in the 2009 Form 10-K. See pages 62 to 69 of the 2009 Form 10-K for additional information on these topics.


Highlights of Operating Results

 
  Three Months Ended
June 30,
   
  Six Months Ended
June 30,
   
 
 
  2010
  2009
  Change
  2010
  2009
  Change
 
   

Net Income attributable to Edison International

                                     
 

SCE

  $ 301   $ 499   $ (198 ) $ 465   $ 707   $ (242 )
 

EMG

    27     (558 )   585     104     (510 )   614  
 

Edison International Parent and Other

    16     43     (27 )   11     37     (26 )
       
 

Edison International Consolidated

    344     (16 )   360     580     234     346  
       

Non-Core Earnings (Loss)

                                     
 

Global Settlement1:

                                     
   

SCE

    53     300     (247 )   53     300     (247 )
   

EMG2

    58     (612 )   670     58     (624 )   682  
   

Edison International Parent and Other

    27     50     (23 )   27     50     (23 )
 

SCE – tax impact of health care legislation

                (39 )       (39 )
 

EMG discontinued operations

    1     (7 )   8     8     (4 )   12  
       
 

Edison International Consolidated

    139     (269 )   408     107     (278 )   385  
       

Core Earnings (Loss)

                                     
 

SCE

    248     199     49     451     407     44  
 

EMG

    (32 )   61     (93 )   38     118     (80 )
 

Edison International Parent and Other

    (11 )   (7 )   (4 )   (16 )   (13 )   (3 )
       
 

Edison International Consolidated

  $ 205   $ 253   $ (48 ) $ 473   $ 512   $ (39 )
   
1
Includes the impact of state taxes related to issues resolved as part of the Global Settlement.

2
Includes the impact of termination of two of Edison Capital's cross-border leases.

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Edison International's earnings are prepared in accordance with generally accepted accounting principles used in the United States. Management uses core earnings by principal operating subsidiary internally for financial planning and for analysis of performance. Core earnings by principal operating subsidiary are also used when communicating with analysts and investors regarding our earnings results to facilitate comparisons of the Company's performance from period to period. Core earnings are a non-GAAP financial measure and may not be comparable to those of other companies. Core earnings are defined as earnings attributable to Edison International shareholders excluding income or loss from discontinued operations and income or loss from significant discrete items that management does not consider representative of ongoing earnings, such as: settlement of prior year tax liabilities and change in tax law; exit activities, including lease terminations, asset impairments, sale of certain assets, early debt extinguishment costs and other activities that are no longer continuing; and non-recurring regulatory or legal proceedings.

SCE's 2010 core earnings increased $49 million and $44 million for the quarter and year-to-date, respectively. The quarter increase was due to lower income tax expense and higher authorized revenue to support rate base growth. These quarter increases were partially offset by higher operating expenses, including the impact of curtailed spending last year due to the timing of the 2009 CPUC GRC decision. The year-to-date increase was due to higher authorized revenue to support rate base growth, lower income tax expense and higher capitalized financing costs (AFUDC). These year-to-date increases were partially offset by higher operating expenses, including the impact of curtailed spending last year due to the timing of the 2009 CPUC GRC decision. The lower tax expense for the quarter and year-to-date includes a change in method of tax accounting for asset removal costs primarily related to SCE's infrastructure replacement program.

EMG's 2010 core earnings decreased $93 million and $80 million for the quarter and year-to-date, respectively. The decline in core earnings during the second quarter reflects increased coal fleet maintenance activities for scheduled plant outages, impact of unrealized gains and losses and lower generation. In addition, second quarter of 2009 results included $20 million after tax related to the sale of an interest in the Midlands Cogeneration Ventures leverage lease. In addition to the decrease in earnings attributable to the leverage lease transaction, the decrease in the six month results includes the higher scheduled outages during the second quarter, impact of unrealized gains and losses, and lower average realized energy prices. Partially offsetting these decreases in the six month results were higher trading revenues and distributions from two projects recorded in the first quarter.

Consolidated non-core items for Edison International included:

An earnings benefit of $138 million recorded in the second quarter of 2010 resulting from acceptance by the California Franchise Tax Board of the tax positions finalized with the IRS in 2009 as part of the Global Settlement for tax years 1986 through 2002 (described in "Item 8. Edison International Notes to Consolidated Financial Statements—Note 4. Income Taxes" of the 2009 Form 10-K) and revision to interest recorded on the federal Global Settlement. Edison International is awaiting receipt of final interest calculations from the California Franchise Tax Board.

A non-cash charge of $39 million in the first quarter of 2010 to reverse previously recognized federal tax benefits eliminated by the federal health care legislation. The Patient Protection and Affordable Care Act, as modified by the Health Care and Education Reconciliation Act, was enacted in March 2010. The new health care legislation includes a provision that eliminates the federal tax deduction of retiree health care costs to the extent those costs are eligible for federal Medicare Part D subsidies. Although this change does not take effect until January 1, 2013, Edison International is required to recognize the full accounting impact of the legislation in its financial statements in the period of enactment.

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An after-tax earnings charge of $262 million and $274 million for the three- and six-month periods ended June 30, 2009, respectively, related to the Global Settlement with the IRS and termination of Edison Capital's cross-border leases ($920 million pre-tax loss).


SCE Capital Program

SCE's capital program continues to be focused primarily in five areas:

Upgrading and constructing new transmission lines to strengthen system reliability and increase access to renewable energy, including the Tehachapi, Devers-Colorado River and Eldorado-Ivanpah projects.

Maintaining reliability and expanding capability of SCE's transmission and distribution system.

Developing and installing up to 250 MW of utility-owned solar photovoltaic generating facilities (generally ranging in size from 1 to 2 MW each) on commercial and industrial rooftops and other space in SCE's service territory.

Replacing steam generators at San Onofre intended to enable operations until at least the end of its initial license period in 2022. During the first quarter of 2010, SCE completed the replacement of the steam generators at San Onofre Unit 2, which was returned to service on April 11, 2010. See "SCE: Results of Operations—Electric Utility Results of Operations—Utility Earning Activities" for discussion of the extended outage at San Onofre Unit 2.

Installing "smart" meters in approximately 5.3 million households and small businesses referred to as EdisonSmartConnect™. During the first six months of 2010, SCE installed approximately 860,000 smart meters, with cumulative installations totaling over 1 million.

SCE continues to plan to utilize cash generated from its operations and issuance of additional debt and preferred equity for its capital program. During the six months ended June 30, 2010, SCE issued long-term debt (see "SCE: Liquidity and Capital Resources—Historical Consolidated Cash Flow—Condensed Consolidated Statement of Cash Flows—Cash Flows Provided (Used) by Financing Activities" for further information).

SCE's capital investments (including accruals) during the six months ended June 30, 2010 totaled $1.5 billion. SCE projects that capital investments will be in the range of $3.3 billion to $4.0 billion in 2010 and the 2010 – 2014 total capital investment spending will be in the range of $18 billion to $21.5 billion. The rate of actual capital spending will be affected by permitting, regulatory, market and other factors as discussed further under "SCE: Liquidity and Capital Resources—Capital Investment Plans" in the 2009 Form 10-K.


SCE 2012 General Rate Case

On July 19, 2010, SCE submitted to the CPUC's Division of Ratepayer Advocates its notice of intent (NOI) to file a 2012 GRC. The NOI indicates that SCE's GRC application, expected to be filed by year-end 2010, will request a 2012 base rate revenue requirement of $6.3 billion. After considering the effects of sales growth, SCE's request would be a $903 million increase over projected 2011 base rate revenue. If the CPUC approves the requested rate increase and allocates the increase to ratepayer groups on a system average percentage change basis, the percentage increases over current base rates and total rates are estimated to be 16.9% and 7.9%, respectively. The requested revenue requirement increase is driven by the need to maintain system reliability, accommodate customer load growth, and

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increase operation and maintenance expenses primarily for capital-related projects, information technology, insurance and pension contributions. The NOI also indicates that SCE's application will propose a post-test year ratemaking mechanism which would result in 2013 and 2014 incremental base revenue requirement increases, net of sales growth, of $305 million and $542 million, respectively, for the same reasons. The current schedule anticipates a final decision on SCE's 2012 GRC by the end of 2011. SCE cannot predict the revenue requirement the CPUC will ultimately authorize or precisely when a final decision will be adopted.


Environmental Developments

Midwest Generation Environmental Compliance Plans and Costs

During the second quarter of 2010, Midwest Generation continued its permitting and planning activities for NOx and SO2 controls to meet the requirements of the CPS. Midwest Generation has now received all necessary permits from the Illinois EPA allowing the installation of SNCR technology on multiple units to meet the NOx portion of the CPS.

In addition, work continued on the possible employment of FGD technology using dry scrubbing with sodium-based sorbents as a method to comply with the SO2 portion of the CPS. Testing of this technology demonstrated significant reductions in SO2 emissions when using the low-sulfur coal employed by Midwest Generation. Use of this technology in combination with low-sulfur coal is expected to require substantially less capital and installation time than the spray dryer absorber technology originally contemplated, but would likely result in higher ongoing operating costs and may consequently result in lower dispatch rates and competitiveness of Midwest Generation's plants. Also, the use of dry scrubbing with sodium-based sorbents to meet environmental regulations will likely require Midwest Generation to incur the costs of upgrading its particulate removal systems.

Based on this work, Midwest Generation estimates the cost of retrofitting all units, using dry scrubbing with sodium-based sorbents to comply with CPS requirements for SO2 emissions, at approximately $1.2 billion in 2010 dollars. If completed, these expenditures would be incurred over multiple years. Midwest Generation expects to seek permits from the Illinois EPA for select units later this year.

Decisions regarding whether or not to proceed with the above projects or other approaches to compliance remain subject to a number of factors, such as market conditions, regulatory and legislative developments, and forecasted commodity prices and capital and operating costs applicable at the time decisions are required or made. Midwest Generation could also elect to shut down units, instead of installing controls, to be in compliance with the CPS, and, therefore, decisions about any particular combination of retrofits and shutdowns it may ultimately employ to comply with the CPS also remain subject to conditions applicable at the time decisions are required or made. Due to existing uncertainties about these factors, Midwest Generation may defer final decisions about particular units for the maximum time available. Accordingly, final decisions on whether to install controls, to install particular kinds of controls, and to actually expend capital that is budgeted may not occur until 2012 for some of the units and potentially later for others.


Environmental Regulation Developments

Greenhouse Gas Regulation Developments

In June 2010, the US EPA published its final greenhouse gas tailoring rule, with less stringent statutory emissions thresholds for greenhouse gases than those originally proposed in late 2009. Since the rule

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affects only new or modified sources, it is not expected to have any immediate effect on the fossil-fuel generating stations of SCE or EMG.


Transport Rule and Coal Combustion Waste Regulation

In June and July of 2010, two proposed rules were published. The first proposed rule, known as the Transport Rule (a replacement for the CAIR), would substantially reduce power plant emissions of NOx and SO2 starting in 2012, with additional reductions in 2014, and would impose new limitations on emissions allowance trading. The second proposal relates to the handling of coal combustion wastes.


California Renewable Energy Developments

In June 2010, CARB released a proposed Renewable Electricity Standard regulation, which would require most retail sellers of electricity in California to procure 33% of their electricity from eligible renewable energy resources by 2020. The California legislature is also contemplating legislation to adopt a 33% renewables portfolio standard that may supersede the CARB regulation and impose its own program structure. SCE believes that achieving a 33% renewables portfolio standard in this timeframe will be highly ambitious, given the magnitude of the infrastructure build-out required and the slow pace of transmission permitting and approvals.

Once-Through Cooling

On May 4, 2010, the California State Water Resources Board issued a final policy, which establishes closed-cycle wet cooling as required technology for retrofitting existing once-through cooled plants like San Onofre and many of the existing fossil-fueled power plants along the California coast. The final policy requires an independent engineering study to be conducted regarding the feasibility of compliance by California's two coastal nuclear power plants. Depending on the results of the study, the required compliance may result in significant capital expenditures at San Onofre and may affect its operations. It may also significantly impact SCE's ability to procure generating capacity from fossil-fueled plants that use ocean water in once-through cooling systems, system reliability and the cost of electricity to the extent other coastal power plants in California are forced to shut down or limit operations.

For further description discussion, see "Edison International Notes to Consolidated Financial Statements—Note 6. Commitments and Contingencies—Contingencies—Environmental Developments."


EMG Renewable Program

EMG has four projects totaling 600 MW under construction. Included among the projects under construction is the 130 MW Taloga project, which is slated to utilize wind turbines that are subject to a legal dispute. EMG also had a development pipeline of potential wind projects with projected installed capacity of approximately 3,400 MW at June 30, 2010. EMG had a purchase contract for 69 MW of wind turbines, and 33 MW of wind turbines in storage, that are to be used for projects not yet under construction as of June 30, 2010, excluding turbine purchase contracts for 199 MW of wind turbines that are subject to a legal dispute. EMG has deferred delivery and payment for the 69 MW of turbines under the purchase contract to January 2011. If EMG is unable to develop such projects on acceptable terms and conditions, certain turbine orders may be terminated, which would result in a material charge. The pace of additional growth in EMG's renewables program will be subject to the availability of projects that meet EMG's requirements and the capital needed for development, which will be affected by the extent of internally generated cash flow and future decisions about capital expenditures for environmental compliance by its coal fleet. Consequently, pending substantial progress on or

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financing of the environmental retrofits, growth of the renewables program may depend upon the availability of third-party financing.


Mitsubishi Lawsuit

EME filed a complaint in the Superior Court of the State of California against Mitsubishi Power Systems Americas, Inc. and Mitsubishi Heavy Industries, Ltd. with respect to a wind turbine generator supply agreement. Matters under dispute include, among other things, the requirement to purchase and pay the remaining purchase price for 199 MW of wind turbines, including related services and warranties, among other items, in the approximate amount of $289 million. The complaint asks the Court for, among other things, an order finding the supply agreement void and unenforceable and for an award of monetary damages, including return to EME of deposits of $68 million previously made for the units subject to dispute. See "Legal Proceedings" in Part II of this quarterly report.


Parent Company Liquidity

The parent company's liquidity and its ability to pay operating expenses and dividends to common shareholders have historically been dependent on dividends from SCE, tax-allocation payments under its tax-allocation agreements with its subsidiaries, and access to bank and capital markets. Given its subsidiaries' plans to use their cash flows for their respective capital needs, Edison International (parent) expects to incur additional borrowings to fund its dividends to common shareholders and operating expenses.

At June 30, 2010, Edison International (parent) had approximately $27 million of cash and equivalents. The following table summarizes the status of the Edison International (parent) credit facility at June 30, 2010:

(in millions)
  Edison
International
(parent)

 
   

Commitment

  $ 1,426  

Outstanding borrowings

    (215 )

Outstanding letters of credit

     
       

Amount available

  $ 1,211  
   

Edison International has a debt covenant in its credit facility that requires a consolidated debt to total capitalization ratio of less than or equal to 0.65 to 1. At June 30, 2010, Edison International's consolidated debt to total capitalization ratio was 0.53 to 1.

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SOUTHERN CALIFORNIA EDISON COMPANY

RESULTS OF OPERATIONS

SCE's results of operations are derived mainly through two sources:

Utility earning activities, which mainly represent CPUC- and FERC-authorized base rates, which allow a reasonable return, and CPUC-authorized incentive mechanisms; and

Utility cost-recovery activities, which mainly represent CPUC-authorized balancing accounts, which allow recovery of costs (including carrying costs) incurred or provide mechanisms to track and recover or refund differences in forecasted and actual amounts. Balancing accounts (except for certain capital-related projects) do not allow for a return.

Utility earning activities include base rates that are designed to recover forecasted operation and maintenance costs, certain capital-related carrying costs, interest, taxes and a return, including the return and taxes on capital projects recovered through balancing account mechanisms. Differences between authorized and actual results impact earnings. Also included in utility earning activities are revenues or penalties related to incentive mechanisms, other operating revenue, and regulatory charges or disallowances, if any.

Utility cost-recovery activities include rates which provide for recovery, subject to reasonableness review, of fuel costs, purchased power costs, certain operation and maintenance expenses (including public purpose related program costs), and depreciation expense related to certain projects. There is no return earned on cost-recovery expenses.


Electric Utility Results of Operations

The following table is a summary of SCE's results of operations for the periods indicated. The presentation below separately identifies utility earning activities and utility cost-recovery activities.

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Three Months Ended June 30, 2010 versus June 30, 2009

 
  Three Months Ended
June 30, 2010

  Three Months Ended
June 30, 2009

 
 
     
(in millions)
  Utility
Earning
Activities

  Utility
Cost-
Recovery
Activities1,2

  Total
Consolidated

  Utility
Earning
Activities

  Utility
Cost-
Recovery
Activities1,2

  Total
Consolidated

 
   

Operating revenue

  $ 1,308   $ 939   $ 2,247   $ 1, 253   $ 1,020   $ 2,273  
       

Fuel and purchased power

        706     706         739     739  

Operation and maintenance

    537     218     755     516     246     762  

Depreciation, decommissioning and amortization

    306     14     320     275     14     289  

Property and other taxes

    61     1     62     61         61  

Gain on sale of assets

                    (1 )   (1 )
         

Total operating expenses

    904     939     1,843     852     998     1,850  
       

Operating income

    404         404     401     22     423  

Net interest expense and other

    (85 )       (85 )   (87 )       (87 )
       

Income before income taxes

    319         319     314     22     336  

Income tax expense (benefit)

    5         5     (198 )       (198 )
       

Net income

    314         314     512     22     534  

Net income attributable to noncontrolling interests

                    22     22  

Dividends on preferred and preference stock not subject to mandatory redemption

    13         13     13         13  
       

Net income available for common stock

  $ 301   $   $ 301   $ 499   $   $ 499  
       

Core Earnings3

              $ 248               $ 199  

Non-Core Earnings:

                                     
 

Global Settlement

                53                 300  
 

Tax impact of health care legislation

                                 
       

Total SCE GAAP Earnings

              $ 301               $ 499  
   
1
Effective January 1, 2010, SCE deconsolidated the Big 4 projects which affects comparability of cost-recovery activities (see "Edison International Notes to Consolidated Financial Statements Note 13. Variable Interest Entities" for further discussion). Included in the three- and six-month periods ended June 30, 2009, respectively, were the following balances related to the Big 4 projects:

(in millions)
  Three Months Ended June 30, 2009
  Six Months Ended June 30, 2009
 
   

Operating revenue

  $ 131   $ 274  
       

Fuel

    76     177  

Operation and maintenance

    25     46  

Depreciation

    8     17  
       

Total operating expenses

    109     240  
       

Net income

  $ 22   $ 34  
   
2
Effective July 1, 2009, SCE transferred Mountainview Power Company, LLC, to SCE (see "Note 8. Property and Plant" in the 2009 Form 10-K for further discussion). As a result of the transfer and for comparability purposes, Mountainview's 2009 activities ($27 million for both operating revenue and total expenses for the three months ended June 30, 2009 and $49 million for both operating revenue and total expenses for the six months ended June 30, 2009) were reclassified from cost-recovery activities to utility earnings activities consistent with the 2010 regulatory recovery mechanism.

3
See use of Non-GAAP financial measure in "Edison International Overview—Highlights of Operating Results."

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Utility Earning Activities

Utility earning activities were primarily affected by the following:

Higher operating revenue of $55 million primarily due to the following:

$40 million increase related to implementation of the 2009 GRC (effective January 1, 2009) which authorized a 4.25% increase in 2010 authorized revenue.

$15 million increase related to revenue requirements for capital projects recovered through CPUC-authorized balancing accounts primarily related to the steam generator replacement project and the EdisonSmartConnectTM project.

$5 million increase related to the 2009 and 2010 FERC rate cases effective March 1, 2009 and March 1, 2010, respectively (see "SCE: Liquidity and Capital Resources—Regulatory Proceedings—2010 FERC Rate Case" for further discussion).

Higher operation and maintenance expense of $21 million including the impact of curtailed spending last year due to the timing of the 2009 GRC decision. The increase in operation and maintenance expense was primarily in the following areas:

$15 million of higher transmission and distribution expenses. In addition to the impact of curtailed spending, the 2010 increase reflects higher costs to support system reliability and infrastructure replacement, increases in preventive maintenance work and training costs.

$10 million of higher expenses related to higher general liability insurance, a nuclear insurance refund received in 2009, and higher injury and damage claims.

    Partially offset by:

Higher depreciation expense of $31 million primarily resulting from increased capital investments including capitalized software costs.

See "—Income Taxes" below for discussion of lower income taxes during the three months ended June 30, 2010 compared to the same period in 2009.


Utility Cost-Recovery Activities

Excluding the impact of deconsolidation of the Big 4 projects (see "Edison International Notes to Consolidated Financial Statements Note 13. Variable Interest Entities"), utility cost-recovery activities were primarily affected by:

Higher purchased power expense of $29 million primarily due to: higher QF purchased power expense of $120 million primarily due to higher natural gas prices and higher kWh purchases. This was partially offset by lower bilateral energy purchase expense of $30 million primarily due to decreased kWh purchases. Realized losses on economic hedging activities were $38 million in 2010

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Higher fuel expense of $14 million primarily due to higher costs at Mountainview of $15 million resulting from higher natural gas prices.


Six Months Ended June 30, 2010 versus June 30, 2009

 
  Six Months Ended
June 30, 2010

  Six Months Ended
June 30, 2009

 
 
     
(in millions)
  Utility
Earning
Activities

  Utility
Cost-
Recovery
Activities1,2

  Total
Consolidated

  Utility
Earning
Activities

  Utility
Cost-
Recovery
Activities1,2

  Total
Consolidated

 
   

Operating revenue

  $ 2,573   $ 1,833   $ 4,406   $ 2,457   $ 2,005   $ 4,462  
       

Fuel and purchased power

        1,395     1,395         1,480     1,480  

Operation and maintenance

    1,057     411     1,468     958     462     1,420  

Depreciation, decommissioning and amortization

    605     24     629     548     26     574  

Property and other taxes

    129     1     130     127         127  

Gain on sale of assets

                    (1 )   (1 )
       

Total operating expenses

    1,791     1,831     3,622     1,633     1,967     3,600  
       

Operating income

    782     2     784     824     38     862  

Net interest expense and other

    (157 )   (2 )   (159 )   (169 )   (4 )   (173 )
       

Income before income taxes

    625         625     655     34     689  

Income tax expense (benefit)

    134         134     (77 )       (77 )
       

Net income

    491         491     732     34     766  

Net income attributable to noncontrolling interests

                    34     34  

Dividends on preferred and preference stock not subject to mandatory redemption

    26         26     25         25  
       

Net income available for common stock

  $ 465   $   $ 465   $ 707   $   $ 707  
       

Core Earnings3

              $ 451               $ 407  

Non-Core Earnings:

                                     
 

Global Settlement

                53                 300  
 

Tax impact of health care legislation

                (39 )                
       

Total SCE GAAP Earnings

              $ 465               $ 707  
   
1
See footnote 1 under "—Three Months Ended June 30, 2010 versus June 30, 2009" table above.

2
See footnote 2 under "—Three Months Ended June 30, 2010 versus June 30, 2009" table above.

3
See use of Non-GAAP financial measure in "Edison International Overview—Highlights of Operating Results."


Utility Earning Activities

Utility earning activities were primarily affected by the following:

Higher operating revenue of $116 million primarily due to the following:

$80 million increase related to implementation of the 2009 GRC (effective January 1, 2009) which authorized a 4.25% increase in 2010 authorized revenue.

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Higher operation and maintenance expense of $99 million including the impact of curtailed spending last year due to the timing of the 2009 GRC decision. The increase in operation and maintenance expense was primarily in the following areas:

$45 million of higher transmission and distribution expenses. In addition to the impact of curtailed spending, the 2010 increase reflects higher costs to support system reliability and infrastructure replacement, increases in preventive maintenance work, line clearing costs and training costs.

$30 million of higher expenses related to higher general liability insurance, a nuclear insurance refund received in 2009, and higher injury and damage claims.

$5 million of higher 2010 generation expenses reflecting $10 million primarily due to additional work identified during the San Onofre Unit 2 scheduled outage and $10 million primarily due to overhaul and outage costs at Four Corners. These increases were partially offset by a $15 million hydrogen energy project payment made in the second quarter of 2009, which was subsequently approved for balancing account treatment in December 2009. During the San Onofre Unit 2 scheduled outage, SCE identified and completed additional work unrelated to the steam generator replacement that resulted in increased operation and maintenance expense and extended the outage beyond SCE's initial estimated timeframe. San Onofre Unit 2 was returned to service on April 11, 2010.

The first two of the four replacement steam generators were installed in San Onofre Unit 2 in the first quarter of 2010 and the installation of the final two steam generators at San Onofre Unit 3 is expected to begin in late 2010. The CPUC has previously adopted a mechanism establishing thresholds for recovery of SCE's incurred costs for the steam generator replacements. Costs above an established threshold will require a reasonableness review. No cost recovery will be allowed for costs incurred that exceed an authorized cap. The determination of whether a reasonableness review of costs is necessary will be made after the steam generator replacement project is completed.

As discussed in the 2009 Form 10-K, SCE is subject to the jurisdiction of the NRC with respect to its San Onofre and Palo Verde Nuclear Generating Stations. San Onofre is currently addressing a number of regulatory and performance issues, and the NRC has required SCE to take actions to provide greater assurance of compliance by San Onofre personnel with applicable NRC requirements and procedures. SCE continues to implement plans to address the identified issues. The NRC has continued to affirm that San Onofre has been operated and is being operated safely; however, a number of these issues remain outstanding, and additional issues have been identified. The cumulative impact of these regulatory and performance issues has been an increase in management focus and other resources applied at San Onofre. To the extent that these issues persist, the likelihood of further required action, and associated potential for effects on costs and operations, will increase.

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Higher depreciation expense of $57 million primarily related to increased capital investments including capitalized software costs.

Lower net interest expense and other of $12 million primarily related to higher capitalized cost of equity and debt (AFUDC) resulting from a higher capitalization rate and level of construction in progress. See "Edison International Notes to Consolidated Financial Statements Note 12. Other Income and Expenses" for further detail of other income and expenses.

See "—Income Taxes" below for discussion of lower income taxes during the six months ended June 30, 2010 compared to the same period in 2009.


Utility Cost-Recovery Activities

Excluding the impact of deconsolidation of the Big 4 projects (see "Edison International Notes to Consolidated Financial Statements Note 13. Variable Interest Entities"), utility cost-recovery activities were primarily affected by:

Higher purchased power expense of $96 million primarily related to: higher QF purchased power expense of $250 million primarily due to higher natural gas prices and higher kWh purchases; and higher ISO-related energy costs of $75 million, including replacement power costs related to the San Onofre Unit 2 scheduled outage. This was partially offset by lower bilateral energy purchase expense of $90 million primarily due to decreased kWh purchases. Realized losses on economic hedging activities were $62 million in 2010 and $194 million in 2009. Changes in realized losses on economic hedging activities were primarily due to settled natural gas prices being lower than contract prices.

Lower fuel expense of $4 million primarily related to lower costs at Four Corners (coal) of $10 million and lower costs at San Onofre Unit 2 of $5 million both resulting from the outages described above. These decreases were offset by higher costs at Mountainview of $15 million resulting from higher natural gas prices.


Supplemental Operating Revenue Information

SCE's total consolidated operating revenue was $2.2 billion and $2.3 billion for the three months ended June 30, 2010 and 2009, respectively, of which $2.4 billion and $2.3 billion was related to retail billed and unbilled revenue (excluding wholesale sales and balancing account (over)/undercollections) for the same respective periods. SCE's total consolidated operating revenue was $4.4 billion and $4.5 billion for the six months ended June 30, 2010 and 2009, respectively, of which $4.4 billion and $4.2 billion was related to retail billed and unbilled revenue (excluding wholesale sales and balancing account (over)/undercollections) for the same respective periods. Retail billed and unbilled revenue increased $57 million and $201 million for the three- and six-month periods ended June 30, 2010, respectively, compared to the same periods in 2009. The quarter and year-to-date increases reflect a rate increase of $126 million and $305 million, respectively, and a sales volume decrease of $69 million and $104 million, respectively. The rate increase was due to higher system average rates for 2010 compared to the same periods in 2009 mainly due to the implementation of the 2009 CPUC GRC decision and approved FERC transmission rate changes. The sales volume decrease was due to slightly milder weather experienced during the second quarter of 2010 compared to the same period in 2009 and economic conditions. As a result of the CPUC-authorized decoupling mechanism, SCE does not bear the volumetric risk related to electricity sales (see "Overview of Ratemaking Mechanisms" in the 2009 Form 10-K).

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Due to warmer weather during the summer months and SCE's rate design, operating revenue during the third quarter of each year is generally higher than other quarters.

Amounts SCE bills and collects from its customers for electric power purchased and sold by the CDWR to SCE's customers, CDWR bond-related costs and a portion of direct access exit fees are remitted to the CDWR and are not recognized as revenue by SCE. The amounts collected and remitted to CDWR were $286 million and $582 million for the three- and six-month periods ended June 30, 2010, respectively, and $391 million and $896 million for the three- and six-month periods ended June 30, 2009, respectively. Effective January 1, 2010, the CDWR-related rates were decreased primarily to refund CDWR overcollections to customers.


Income Taxes

SCE's income tax expense from continuing operations increased $203 million and $211 million during the three- and six-month periods ended June 30, 2010, respectively. The 2010 income tax expense reflects: a $39 million non-cash charge recorded in the first quarter related to the federal health care legislation enacted in March 2010; a $40 million earnings benefit due to a change in method of tax accounting for asset removal costs primarily related to SCE's infrastructure replacement program; and a $53 million earnings benefit recorded in the second quarter resulting from acceptance by the California Franchise Tax Board of the tax positions finalized with the IRS in 2009 as part of the Global Settlement for tax years 1986 through 2002. During the second quarter of 2009, SCE recognized a $300 million earnings benefit related to the federal Global Settlement finalized with the IRS. See "Edison International Notes to Consolidated Financial Statements—Note 4. Income Taxes" for further discussion.


LIQUIDITY AND CAPITAL RESOURCES

SCE expects to fund its continuing obligations and projected capital investments for 2010 through cash and equivalents on hand, operating cash flows and incremental capital market financings of debt and preferred equity. SCE also has availability under its credit facilities if additional funding and liquidity are necessary to meet operating and capital requirements.


Available Liquidity

As of June 30, 2010, SCE had approximately $91 million of cash and equivalents and short-term investments. As of June 30, 2010, SCE's long-term debt, including current maturities of long-term debt, was $7.1 billion.

The following table summarizes the status of SCE's credit facilities at June 30, 2010:

(in millions)
  Credit
Facilities1

 
   

Commitment

  $ 2,894  

Outstanding borrowings

    (215 )

Outstanding letters of credit

    (11 )
       

Amount available

  $ 2,668  
   
1
SCE has two revolving credit facilities with various banks; a $2.4 billion five-year credit facility that terminates in February 2013, with four one-year options to extend by mutual consent, and a $500 million three-year credit facility that terminates in March 2013.

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Debt Covenant

SCE has a debt covenant in its credit facilities that limits its debt to total capitalization ratio to less than or equal to 0.65 to 1. At June 30, 2010, SCE's debt to total capitalization ratio was 0.46 to 1.


Regulatory Proceedings

Energy Efficiency Risk/Reward Incentive Mechanism

As discussed in the year-ended 2009 MD&A, the CPUC adopted an Energy Efficiency Risk/Reward Incentive Mechanism applicable to the 2006 – 2008 performance period under which SCE expected to receive a $27 million final payment in late 2010. SCE expects a CPUC decision on the final payment, if any, in the second half of 2010. There is no assurance that SCE will receive a final payment.


2010 FERC Rate Case

In September 2009, the FERC issued an order allowing SCE to implement its proposed 2010 rates effective March 1, 2010, subject to refund. The proposed rates would increase SCE's FERC revenue requirement by $107 million, or 24%, over the 2009 FERC revenue requirement primarily due to an increase in transmission rate base, and would result in an approximate 1% increase to SCE's overall system average rate. SCE has terminated settlement negotiations and begun the litigation process for the proposed 2010 rates. A final decision is expected in the second half of 2011.


Dividend Restrictions

The CPUC regulates SCE's capital structure and limits the dividends it may pay Edison International. In SCE's most recent cost of capital proceeding, the CPUC set an authorized capital structure for SCE which included a common equity component of 48%. SCE may make distributions to Edison International as long as the common equity component of SCE's capital structure remains at or above the 48% authorized level on a 13-month weighted-average basis. At June 30, 2010, SCE's 13-month weighted-average common equity component of total capitalization was 51% resulting in the capacity to pay $461 million in additional dividends.

SCE paid dividends of $100 million to its parent, Edison International, in January 2010. Future dividend amounts and timing of distributions are dependent upon several factors, including the actual level of capital investments, operating cash flows and earnings.


Margin and Collateral Deposits

Certain derivative instruments and power procurement contracts under SCE's power and natural gas hedging activities contain collateral requirements. The table below illustrates the amount of collateral posted by SCE to its counterparties, as well as the potential collateral that would be required if SCE's credit rating fell below investment grade.

(in millions)
  June 30, 2010
 
   

Collateral posted as of June 30, 20101

  $ 22  

Incremental collateral requirements resulting from a potential downgrade of SCE's credit rating to below investment grade

    180  
       

Total posted and potential collateral requirements2

  $ 202  
   
1
Collateral posted consisted of $8 million which was offset against net derivative liabilities and $14 million provided to counterparties and other brokers (consisting of $4 million in cash reflected in "Margin and collateral deposits" on the consolidated balance sheets and $10 million in letters of credit).

2
Total posted and potential collateral requirements may increase by an additional $13 million, based on SCE's forward position as of June 30, 2010, due to adverse market price movements over the remaining life of the existing contracts using a 95% confidence level.

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Historical Consolidated Cash Flow

This section discusses consolidated cash flows from operating, financing and investing activities.


Condensed Consolidated Statement of Cash Flows

 
  Six Months Ended
June 30,
 
(in millions)
  2010
  2009
 
   

Cash flows provided by operating activities

  $ 1,095   $ 2,054  

Cash flows provided (used) by financing activities

    465     (1,694 )

Cash flows used by investing activities

    (1,937 )   (1,517 )
       

Net decrease in cash and equivalents

  $ (377 ) $ (1,157 )
   


Cash Flows Provided by Operating Activities

Cash provided by operating activities decreased $959 million in the second quarter of 2010, compared to the second quarter of 2009 primarily due to the impacts of the Global Settlement, which resulted in a net tax allocation payment received in 2009 from Edison International of $875 million and an increase in deferred tax liabilities related to the settlement of affirmative claims. The 2010 change was also due to the timing of cash receipts and disbursements related to working capital items and a decrease in pre-tax income.


Cash Flows Provided (Used) by Financing Activities

Financing activities for the first six months of 2010 were as follows:

Reissued $144 million of tax-exempt pollution control bonds due in 2035. The proceeds from these bonds were used to repay commercial paper borrowings and for general corporate purposes.

Issued $500 million of first refunding mortgage bonds due in 2040. The bond proceeds were used to repay commercial paper borrowings and for general corporate purposes.

Issued $215 million of short-term debt to fund interim working capital requirements.

Repaid $250 million of senior unsecured notes.

Paid $100 million in dividends to Edison International.

Financing activities for the first six months of 2009 were as follows:

Issued $500 million of first refunding mortgage bonds due in 2039 and $250 million of first and refunding mortgage bonds due in 2014. The bond proceeds were used for general corporate purposes and to finance fuel inventories.

Repaid a net $1.9 billion of short-term debt.

Repaid $150 million of first and refunding mortgage bonds.

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Purchased $219 million of two issues of tax-exempt pollution control bonds and converted the issues to a variable rate structure. As discussed above, SCE reissued $144 million of these bonds during the first six months of 2010. SCE continues to hold the remaining $75 million of these bonds which are outstanding and have not been retired or cancelled.

Paid $100 million in dividends to Edison International.


Cash Flows Used by Investing Activities

Cash flows from investing activities are driven primarily by capital expenditures and funding of nuclear decommissioning trusts. Cash paid for capital expenditures was $1.8 billion and $1.4 billion for the six months ended June 30, 2010 and 2009, respectively, primarily related to transmission and distribution investments. Net purchases of nuclear decommissioning trust investments and other were $97 million and $105 million for the six months ended June 30, 2010 and 2009, respectively.


Contractual Obligations and Contingencies

Contractual Obligations

For a discussion of issuances of long-term debt, see "Edison International Notes to Consolidated Financial Statements Note 3. Liabilities and Lines of Credit—Long-Term Debt."

For a discussion of purchase obligations and capital lease obligations, see "Edison International Notes to Consolidated Financial Statements Note 6. Commitments and Contingencies—Commitments and —Other Commitments."


Contingencies

Developments related to SCE's FERC Transmission Incentives and CWIP Proceedings, Navajo Nation Litigation and Spent Nuclear Fuel are discussed in "Edison International Notes to Consolidated Financial Statements Note 6. Commitments and Contingencies—Contingencies."


Environmental Remediation

As of June 30, 2010, SCE identified 23 sites for remediation and recorded an estimated minimum liability of $38 million. SCE expects to recover 90% of its remediation costs at certain sites. SCE expects to clean up its identified sites over a period of up to 30 years. Remediation costs in each of the next several years are expected to range from $3 million to $18 million. See "Edison International Notes to Consolidated Financial Statements Note 6. Commitments and Contingencies—Contingencies" for further discussion.


MARKET RISK EXPOSURES

For a detailed discussion of SCE's market risk exposures, including commodity price risk, credit risk and interest rate risk, see "SCE: Market Risk Exposures—Commodity Price Risk" in the year-ended 2009 MD&A.


Interest Rate Risk

At June 30, 2010, the fair market value of SCE's long-term debt (including current portion of long-term debt) was $8.1 billion, compared to a carrying value of $7.1 billion. At June 30, 2010, SCE

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did not believe that its short-term debt was subject to interest rate risk due to the fair value being approximately equal to the carrying value.


Commodity Price Risk

Natural Gas and Electricity Price Risk

The following table summarizes the fair values of outstanding derivative instruments used at SCE to mitigate its exposure to spot market prices. For further discussion on fair value measurements, see "Edison International Notes to Consolidated Financial Statements Note 10. Fair Value Measurements."

 
  June 30, 2010
  December 31, 2009
 
 
     
(in millions)
  Assets
  Liabilities
  Assets
  Liabilities
 
   

Electricity options, swaps and forward arrangements

  $ 1   $ 89   $ 1   $ 25  

Natural gas options, swaps and forward arrangements

    84     280     86     171  

Congestion revenue rights

    190         217      

Tolling arrangements1

        1,006     43     402  

Netting and collateral

        (8 )        
       

Total

  $ 275   $ 1,367   $ 347   $ 598  
   
1
In compliance with a CPUC mandate, SCE held an open, competitive solicitation that produced agreements with different project developers who have agreed to construct new southern California generating resources. The contracts provide for fixed capacity payments as well as pricing for energy delivered based on a heat rate and contractual operation and maintenance prices. However, due to uncertainty regarding the availability of required emission credits, some of the generating resources may not be constructed and the contracts associated with these resources could therefore terminate, at which time SCE would no longer account for these contracts as derivatives.

The change in the fair value of derivative contracts for the six months ended June 30, 2010 was as follows:

(in millions)
   
 
   

Fair value of derivative contracts, net liability at January 1, 2010

  $ (251 )

Total realized/unrealized net losses:

       
 

Included in regulatory assets and liabilities1

    (919 )

Purchases and settlements, net

    70  

Netting and collateral

    8  
       

Fair value of derivative contracts, net liability at June 30, 2010

  $ (1,092 )
   
1
Due to regulatory mechanisms, SCE's realized and unrealized gains and losses are recorded as regulatory assets and liabilities.

SCE recognizes realized gains and losses on derivative instruments as purchased power expense and recovers these costs, subject to reasonableness, from ratepayers. As a result, realized gains and losses are not reflected in earnings, but may temporarily affect cash flows. Due to expected future recovery from ratepayers, unrealized gains and losses are recorded as regulatory assets or liabilities and therefore are not reflected in earnings. Realized losses on economic hedging activities were primarily due to settled natural gas prices being lower than contract prices. Unrealized losses on economic hedging activities were primarily due to lower forward heat rates (spread between electricity prices and natural gas prices) related to SCE's long-term contracts from new natural gas-fired generation facilities.

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Credit Risk

Credit risk exposure from counterparties for power and gas trading activities is measured as the sum of net accounts receivable (accounts receivable less accounts payable) and the current fair value of net derivative assets (derivative assets less derivative liabilities) reflected on the consolidated balance sheets. SCE enters into master agreements which typically provide for a right of setoff. Accordingly, SCE's credit risk exposure from counterparties is based on a net exposure under these arrangements. As of June 30, 2010, the amount of balance sheet exposure as described above broken down by the credit ratings of SCE's counterparties, was as follows:

 
  June 30, 2010  
(in millions)
  Exposure2
  Collateral
  Net Exposure
 
   

S&P Credit Rating1

                   

A or higher

  $ 217   $   $ 217  

A-

             

BBB+

    1         1  

BBB

             

BBB-

             

Below investment grade and not rated

             
       

Total

  $ 218   $   $ 218  
   
1
SCE 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 sheets, except for any related net accounts receivable.

The credit risk exposure set forth in the above table is comprised of less than $1 million of net account receivables and $218 million representing the fair value, adjusted for counterparty credit reserves, of derivative contracts.

The CAISO comprises 87% of the total net exposure above and is mainly related to the CRRs' fair value (see "—Commodity Price Risk" for further information).

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EDISON MISSION GROUP

RESULTS OF OPERATIONS

The following table is a summary of EMG's results of operations. Effective January 1, 2010, Edison International combined the competitive power generation and financial services segments into one business segment. The change resulted from termination of cross-border leases during 2009 and the continued decline of the remaining portfolio of the financial services segment. Accordingly, the financial services segment has been combined retroactively for all periods presented into one business segment. The combination of these business activities is consistent with the management structure of EMG and evaluation of performance by Edison International.


Results of Continuing Operations

This section discusses operating results for the three- and six-month periods ended June 30, 2010 and 2009. EMG's continuing operations include the fossil-fueled facilities, renewable energy and gas-fired projects, energy trading, and gas-fired projects under contract, corporate interest expense and general and administrative expenses. EMG's discontinued operations include all international operations, except the Doga project.

The following table is a summary of competitive power generation results of operations for the periods indicated.

 
  Three Months Ended
June 30,

  Six Months Ended
June 30,

 
 
     
(in millions)
  2010
  2009
  2010
  2009
 
   

Competitive power generation operating revenue

  $ 495   $ 562   $ 1,147   $ 1,186  
       

Fuel

    160     172     374     359  

Other operation and maintenance

    319     244     570     483  

Depreciation, decommissioning and amortization

    60     58     120     114  

Lease terminations and other

        867     3     889  
       

Total operating expenses

    539     1,341     1,067     1,845  

Operating income (loss)

    (44 )   (779 )   80     (659 )
       

Interest and dividend income

    4     14     24     21  

Equity in income from partnerships and unconsolidated subsidiaries – net

    20     17     39     15  

Other income

    1     1         2  

Interest expense – net of amounts capitalized

    (66 )   (75 )   (133 )   (152 )

Other expenses

        (5 )       (4 )
       

Income (loss) from continuing operations before income taxes

    (85 )   (827 )   10     (777 )
       

Income tax expense (benefit)

    (111 )   (275 )   (86 )   (270 )

Income (loss) from continuing operations

    26     (552 )   96     (507 )

Income (loss) from discontinued operations – net of tax

    1     (7 )   8     (4 )
       

Net income (loss)

    27     (559 )   104     (511 )

Less: Net income (loss) attributable to noncontrolling interests

        (1 )       (1 )
       

Net income (loss) available for common stock

  $ 27   $ (558 ) $ 104   $ (510 )
   

Core Earnings (Loss)1

  $ (32 ) $ 61   $ 38   $ 118  

Non-Core Earnings (Loss):

                         
 

Global Settlement2

    58     (612 )   58     (624 )
 

Discontinued Operations

    1     (7 )   8     (4 )
   

Total EMG GAAP Earnings (Loss)

  $ 27   $ (558 ) $ 104   $ (510 )
   
1
See use of Non-GAAP financial measure in "Edison International Overview—Highlights of Operating Results."

2
Includes the impact of termination of two of Edison Capital's cross-border leases and impact of state taxes related to issues resolved as part of the Global Settlement.

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EMG's second quarter 2010 core earnings were lower than second quarter 2009 core earnings primarily due to the following:

$160 million decreased income from Midwest Generation and Homer City due to lower realized energy revenue and higher plant maintenance costs primarily attributed to scheduled plant outages during 2010. Plant maintenance and overhaul related expenses were higher in 2010 due to the deferral of plant outages in 2009. Scheduled plant maintenance for 2010 was substantially completed in the second quarter. Lower availability in 2010 compared to the same period in 2009 was also the result of deratings caused by opacity at the Homer City facilities and transmission line tornado damage impacting the Powerton Station. In addition, EMG's results were impacted by $17 million of unrealized losses during the second quarter of 2010 compared to unrealized gains of $24 million during the same period last year.

$33 million gain in the second quarter of 2009 from the sale of an interest in a leverage lease (Midlands Cogeneration Ventures) and lower lease income from termination of cross-border leverage leases in 2009.

These decreases were partially offset by the following:

$14 million increased energy trading revenue during the second quarter of 2010 due to congestion and basis trading.

$9 million decrease in corporate expenses due primarily to lower renewable energy development expenses.

EMG's core earnings for the six months ended June 30, 2010 were lower than core earnings for the six months ended June 30, 2009 primarily due to the following:

$186 million decreased income from Midwest Generation and Homer City due to lower realized energy revenue and higher plant maintenance costs primarily attributed to scheduled plant outages during 2010. Plant maintenance and overhaul related expenses were higher in 2010 due to the deferral of plant outages in 2009. Scheduled plant maintenance for 2010 was substantially completed in the first half of the year. Lower availability in 2010 compared to the same period in 2009 was also the result of deratings caused by opacity at the Homer City facilities and transmission line tornado damage impacting the Powerton Station. In addition, EMG's results were impacted by $17 million of unrealized losses during the six months ended June 30, 2010 compared to unrealized gains of $39 million during the same period last year.

$33 million gain in the second quarter of 2009 from the sale of an interest in a leverage lease (Midlands Cogeneration Ventures) and lower lease income from termination of cross-border leverage leases in 2009.

These decreases were partially offset by the following:

$51 million increased energy trading revenue due to congestion and basis trading.

$9 million decrease in corporate expenses due primarily to lower renewable energy development expenses.

Consolidated non-core items for EMG included:

An earnings benefit of approximately $58 million recorded in the second quarter of 2010 resulting from acceptance by the California Franchise Tax Board of the tax positions finalized with the IRS in 2009 as part of the Global Settlement for tax years 1986 through 2002 and revision to interest recorded on the federal Global Settlement.

Adjusted Operating Income ("AOI") – Overview

The following section and table provide a summary of results of EMG's operating projects and corporate expenses for the second quarters of 2010 and 2009 and six months ended June 30, 2010 and 2009, together with discussions of the contributions by specific projects and of other significant factors affecting these results.

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The following table shows the adjusted operating income (AOI) of EMG's projects:

 
  Three Months Ended
June 30,

  Six Months Ended
June 30,

 
 
     
(in millions)
  2010
  2009
  2010
  2009
 
   

Midwest Generation plants

  $ (39 ) $ 74   $ 48   $ 188  

Homer City facilities

        47     37     83  

Renewable energy projects

    19     11     29     37  

Energy trading

    31     17     78     27  

Big 4 projects

    12     11     16     17  

Sunrise

    7     6     3     1  

Doga

        8     15     8  

March Point

        1     17     3  

Westside projects

            1     3  

Leveraged lease income

    1     1     2     12  

Lease termination and other

        (867 )   (3 )   (889 )

Other projects

    3     3     6     5  

Other operating income (expense)

    2     (4 )   4     (10 )
       

    36     (692 )   253     (515 )

Corporate administrative and general

    (36 )   (47 )   (74 )   (84 )

Corporate depreciation and amortization

    (4 )   (4 )   (8 )   (7 )
       

AOI1

  $ (4 ) $ (743 ) $ 171   $ (606 )
   
1
AOI is equal to operating income under GAAP, plus equity in earnings 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 EMG.

The following table reconciles AOI to operating income (loss) as reflected on EMG's consolidated statements of income (loss):

 
  Three Months Ended
June 30,

  Six Months Ended
June 30,

 
 
     
(in millions)
  2010
  2009
  2010
  2009
 
   
AOI   $ (4 ) $ (743 ) $ 171   $ (606 )
Less:                          
  Equity in earnings (losses) of unconsolidated affiliates     20     17     39     15  
  Dividend income from projects     2     8     18     10  
  Production tax credits     19     14     33     30  
  Other income, net     (1 )   (3 )   1     (2 )
       
Operating Income (Loss)   $ (44 ) $ (779 ) $ 80   $ (659 )
   

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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)
  2010
  2009
  2010
  2009
 
   

Operating Revenues

  $ 281   $ 340   $ 660   $ 724  

Operating Expenses

                         
 

Fuel1

    98     110     239     233  
 

Plant operations

    169     106     268     202  
 

Plant operating leases

    18     19     37     38  
 

Depreciation and amortization

    28     27     56     54  
 

Administrative and general

    7     5     12     10  
       
 

Total operating expenses

    320     267     612     537  
       

Operating Income (Loss)

    (39 )   73     48     187  
       

Other Income

        1         1  
       

AOI

  $ (39 ) $ 74   $ 48   $ 188  
   

Statistics

                         
 

Generation (in GWh):

                         
   

Energy only contracts

    5,430     6,361     13,642     12,117  
   

Load requirements services contract

        447         1,333  
       
 

Total

    5,430     6,808     13,642     13,450  
   
1
Included in fuel costs were $1 million and $14 million during the second quarters of 2010 and 2009, respectively, and $5 million and $33 million during the six months ended June 30, 2010 and 2009, respectively, related to the net cost of emission allowances. Transfers of emission allowances between Midwest Generation and Homer City are made at fair market value. Transfers of NOX emission allowances to Midwest Generation were $0.4 million and $1 million during the six months ended June 30, 2010 and 2009, respectively. Transfers of SO2 emission allowances from Midwest Generation were $5 million during the first six months of 2010. For more information regarding the price of emission allowances, see "EMG: Market Risk Exposures—Commodity Price Risk—Emission Allowances Price Risk."

AOI from the Midwest Generation plants decreased $113 million and $140 million for the second quarter and six months ended June 30, 2010, respectively, compared to the corresponding periods of 2009. The 2010 decreases in AOI were primarily attributable to an increase in plant operations costs related to scheduled plant outages, unrealized losses related to hedge contracts and a decline in realized gross margin. Plant maintenance and overhaul related expenses were higher in 2010 due to the deferral of plant outages in 2009. Scheduled plant maintenance for 2010 was substantially completed in the second quarter. The decline in realized gross margin during the second quarter was driven by lower generation, partially offset by higher capacity revenues. The year-to-date decline in realized gross margin was driven by lower average realized energy prices, partially offset by higher capacity revenues.

Included in operating revenues were unrealized gains (losses) of $(3) million and $5 million for the second quarters of 2010 and 2009, respectively, and $4 million and $20 million for the six months ended June 30, 2010 and 2009, respectively. Unrealized gains (losses) in 2010 were due to both the

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ineffective portion of forward and futures contracts which are derivatives that qualify as cash flow hedges, and hedge contracts which are not accounted for as cash flow hedges (referred to as economic hedges). Unrealized gains in 2009 were primarily due to economic hedge contracts that are accounted for on a mark-to-market basis.

Included in fuel expenses were unrealized gains (losses) of $(2) million and $14 million for the second quarters of 2010 and 2009, respectively, and $(7) million and $14 million for the six months ended June 30, 2010 and 2009, respectively. Unrealized gains (losses) were due to oil futures contracts, which were accounted for as economic hedges. The contracts hedge a portion of a fuel adjustment mechanism of a rail transportation contract.

For more information regarding forward market prices and unrealized gains (losses), see "EMG: Market Risk Exposures—Commodity Price Risk" and "EMG: Results of Operations—Derivative Instruments," respectively.


Homer City Facilities

The following table presents additional data for the Homer City facilities:

 
  Three Months Ended
June 30,

  Six Months Ended
June 30,

 
 
     
(in millions)
  2010
  2009
  2010
  2009
 
   

Operating Revenues

  $ 129   $ 161   $ 304   $ 326  

Operating Expenses

                         
 

Fuel1

    57     63     127     127  
 

Plant operations

    39     22     76     56  
 

Plant operating leases

    27     25     52     50  
 

Depreciation and amortization

    4     3     9     8  
 

Administrative and general

    2     1     3     2  
       
 

Total operating expenses

    129     114     267     243  
       

Operating Income

        47     37     83  
       

AOI

  $   $ 47   $ 37   $ 83  
   

Statistics

                         
 

Generation (in GWh)

    2,289     3,025     5,243     5,683  
   
1
Included in fuel costs were $1 million during each of the second quarters of 2010 and 2009, and $5 million and $8 million during the six months ended June 30, 2010 and 2009, respectively, related to the net cost of emission allowances. Transfers of emission allowances between Midwest Generation and Homer City are made at fair market value. Transfers of SO2 emission allowances to Homer City were $5 million during the six months ended June 30, 2010. Transfers of NOx emission allowances from Homer City were $0.4 million and $1 million during the six months ended June 30, 2010 and 2009, respectively. For more information regarding the price of emission allowances, see "EMG: Market Risk Exposures—Commodity Price Risk—Emission Allowances Price Risk."

AOI from the Homer City facilities decreased $47 million and $46 million for the second quarter and six months ended June 30, 2010, respectively, compared to the corresponding periods of 2009. The 2010 decreases in AOI were primarily attributable to an increase in plant operations costs related to scheduled plant outages, higher unrealized losses related to hedge contracts and a decline in realized gross margin. Plant maintenance and overhaul related expenses were higher in 2010 due to the deferral of plant outages in 2009. Scheduled plant maintenance for 2010 was substantially completed in the

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second quarter. The decline in realized gross margin was driven by lower generation and higher coal costs, partially offset by higher capacity revenues.

Included in operating revenues were unrealized gains (losses) from hedge activities of $(12) million and $5 million for the second quarters of 2010 and 2009, respectively, and $(14) million and $5 million for the six months ended June 30, 2010 and 2009, respectively. Unrealized gains (losses) in 2010 and 2009 were primarily attributable to the ineffective portion of forward and futures contracts which are derivatives that qualify as cash flow hedges. The ineffective portion of hedge contracts at Homer City was attributable to changes in the difference between energy prices at the PJM West Hub (the settlement point under forward contracts) and the energy prices at the Homer City busbar (the delivery point where power generated by the Homer City facilities is delivered into the transmission system). For more information regarding forward market prices and unrealized gains (losses), see "EMG: Market Risk Exposures—Commodity Price Risk" and "EMG: Results of Operations—Derivative Instruments."


Non-GAAP Disclosures—Fossil-Fueled Facilities

Adjusted Operating Income

AOI is equal to operating income (loss) plus other income (expense) for the fossil-fueled facilities. AOI is a non-GAAP performance measure and may not be comparable to those of other companies. Management believes that inclusion of other income (expense) is meaningful for investors as the components of other income (expense) are integral to the operating results of the fossil-fueled facilities.


Seasonal Disclosure—Fossil-Fueled Facilities

Due to fluctuations in electric demand resulting from warmer weather during the summer months and cold weather during the winter months, electric revenues from the fossil-fueled facilities 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 reducing generation and increasing major maintenance costs which are recorded as an expense when incurred. Accordingly, AOI from the fossil-fueled facilities 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 "EMG: Market Risk Exposures—Commodity Price Risk—Energy Price Risk Affecting Sales from the Fossil-Fueled Facilities."

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Renewable Energy Projects

The following table presents additional data for EMG's renewable energy projects:

 
  Three Months Ended
June 30,

  Six Months Ended
June 30,

 
 
     
(in millions)
  2010
  2009
  2010
  2009
 
   

Operating Revenues

  $ 34   $ 31   $ 64   $ 75  

Production Tax Credits

    19     14     33     30  
       

    53     45     97     105  
       

Operating Expenses

                         
 

Plant operations

    12     12     24     25  
 

Depreciation and amortization

    22     21     43     41  
 

Administrative and general

        1     1     2  
       
 

Total operating expenses

    34     34     68     68  
       

AOI1

  $ 19   $ 11   $ 29   $ 37  
   

Statistics

                         
 

Generation (in GWh)2

    992     718     1,835     1,538  
   
1
AOI is equal to operating income (loss) plus equity in earnings (losses) of unconsolidated affiliates, 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. The following table reconciles AOI as shown above to operating income (loss) under GAAP:

 
  Three Months Ended
June 30,

  Six Months Ended
June 30,

 
 
     
(in millions)
  2010
  2009
  2010
  2009
 
   

AOI

  $ 19   $ 11   $ 29   $ 37  

Less:

                         
 

Production tax credits

    19     14     33     30  
       

Operating Income (Loss)

  $   $ (3 ) $ (4 ) $ 7  
   
2
Includes renewable energy projects that are unconsolidated at EMG. Generation excluding unconsolidated projects was 821 GWh and 1,512 GWh for the three months and six months ended June 30, 2010, respectively.

AOI from renewable energy projects increased $8 million and decreased $8 million for the second quarter and six months ended June 30, 2010, respectively, compared to the corresponding periods of 2009. The second quarter increase in AOI was primarily attributable to higher generation resulting from an increase in projects in operations. The year-to-date decrease in AOI results from higher depreciation and operations costs related to additional projects in operations, offset by the impact of the deconsolidation of two renewable projects in 2010. AOI in the second quarter and six months ended June 30, 2009 included $5 million and $16 million, respectively, of liquidated damages from availability guarantees provided by a wind turbine supplier, which compensated EMG for lower generation (none recorded in 2010). The second quarter ended June 30, 2010 did not include liquidated damages for equipment warranty related items given completion of the blade remediation

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program. During the second quarter of 2010, EMG received $92 million in U.S. Treasury grants, which was recorded as deferred revenue and is recognized as revenue over the life of the project.


Energy Trading

EMG seeks to generate profit by utilizing its subsidiary, EMMT, to engage in trading activities in those markets in which it is active as a result of its management of the merchant power plants of Midwest Generation and Homer City. EMMT trades power, fuel, coal, and transmission congestion primarily in the eastern U.S. power grid using products available over the counter, through exchanges, and from ISOs.

AOI from energy trading activities increased $14 million and $51 million for the second quarter and six months ended June 30, 2010, respectively, compared to the corresponding periods of 2009. The 2010 increases in AOI from energy trading activities were attributable to increased revenue in congestion and basis trading.


Adjusted Operating Income from Leveraged Lease Activities

AOI from leveraged lease income decreased by $10 million for the six months ended June 30, 2010, compared to the corresponding period of 2009 due to the termination of the cross-border leases and the sale of a lease investment during the first half of 2009.


Adjusted Operating Income from Lease Termination and Other

AOI from lease termination and other included losses of $889 million for the six months ended June 30, 2009 due to the termination of the cross-border leases. (See "Edison International Notes to Consolidated Financial Statements—Note 4. Income Taxes" of the 2009 Form 10-K, for further information.


Adjusted Operating Income from Unconsolidated Affiliates

Doga

AOI from the Doga project decreased $8 million and increased $7 million for the second quarter and six months ended June 30, 2010, respectively, compared to the corresponding periods of 2009 due to the timing of distributions. AOI is recognized when cash is distributed from the project since the Doga project is accounted for on the cost method.


March Point

AOI from the March Point project increased $14 million for the six months ended June 30, 2010, compared to the corresponding period of 2009. The 2010 increase was primarily due to an $18 million equity distribution received from the project in February 2010. EMG subsequently sold its ownership interest in the March Point project to its partner at book value.


Seasonal Disclosure

EMG'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.

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Interest Related Income (Expense)

 
  Three Months Ended
June 30,

  Six Months Ended
June 30,

 
 
     
(in millions)
  2010
  2009
  2010
  2009
 
   

Interest income

  $ 3   $ 5   $ 6   $ 11  
   

Interest expense:

                         
 

EME debt

  $ (58 ) $ (68 ) $ (118 ) $ (136 )
 

Non-recourse debt:

                         
   

Midwest Generation

        (2 )   (1 )   (5 )
   

EME Funding

        (2 )       (4 )
   

EME CP Holding Co.

    (1 )   (1 )   (2 )   (2 )
   

Viento Funding II, Inc.

    (4 )       (8 )    
   

Other projects

    (3 )   (2 )   (4 )   (5 )
       

  $ (66 ) $ (75 ) $ (133 ) $ (152 )
   

The 2010 decrease in interest expense was primarily due to higher capitalized interest and lower debt balances under EME's and Midwest Generation's credit facilities. Capitalized interest for projects under construction increased $8 million and $13 million for the second quarter and six months ended June 30, 2010, respectively, compared to the corresponding periods of 2009. The year-to-date variance was also due to the repayment of debt at EME Funding related to the Big 4 projects.


Income Taxes

EMG's income taxes from continuing operations during the second quarter of 2010 included a $58 million income tax benefit resulting from acceptance by the California Franchise Tax of the tax positions finalized with the IRS as part of the Global Settlement for tax years 1986 through 2002. In addition, the income taxes for the six months ended June 30, 2010 and 2009, included tax benefits of production and housing tax credits of $34 million during each period. During the second quarter of 2009, an income tax benefit was recorded on a pre-tax loss on termination of leverage leases at Edison Capital and impact of the federal Global Settlement finalized with the IRS.


Results of Discontinued Operations

Income from discontinued operations, net of tax, increased $8 million and $12 million for the second quarter and six months ended June 30, 2010, respectively, compared to the corresponding periods of 2009. The 2010 increase was due to lower foreign exchange rates. The year-to-date increase was due to a reduction in EMG's estimated liability due primarily to expiration of a contract indemnity during the first quarter of 2010. EMG increased its estimated liability for a tax indemnity by $6 million in the second quarter and six months ended June 30, 2009.

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Derivative Instruments

Unrealized Gains and Losses

EMG 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 expenses. The results of derivative activities are recorded as part of cash flows from operating activities on the consolidated statements of cash flows. The following table summarizes unrealized gains (losses) from non-trading activities:

 
  Three Months Ended
June 30,
  Six Months Ended
June 30,
 
(in millions)
  2010
  2009
  2010
  2009
 
   

Midwest Generation plants

                         
 

Non-qualifying hedges

  $ (4 ) $ 18   $ (6 ) $ 34  
 

Ineffective portion of cash flow hedges

    (1 )   1     3      

Homer City facilities

                         
 

Non-qualifying hedges

        1          
 

Ineffective portion of cash flow hedges

    (12 )   4     (14 )   5  
       

Total unrealized gains (losses)

  $ (17 ) $ 24   $ (17 ) $ 39  
   

At June 30, 2010, cumulative unrealized gains of $25 million were recognized from non-qualifying hedge contracts or the ineffective portion of cash flow hedges related to subsequent periods ($16 million for the remainder of 2010, $8 million for 2011, and $1 million for 2012).


Fair Value Disclosures

In determining the fair value of EMG's derivative positions, EMG uses third-party market pricing where available. For further explanation of the fair value hierarchy and a discussion of EMG's derivative instruments, see "Edison International Notes to Consolidated Financial Statements—Note 10. Fair Value Measurements" and "—Note 2. Derivative Instruments and Hedging Activities," respectively, and refer to "EMG: Results of Operations—Fair Value of Derivative Instruments" in the year-ended 2009 MD&A.


LIQUIDITY AND CAPITAL RESOURCES

Available Liquidity

At June 30, 2010, EMG and its subsidiaries had consolidated cash and cash equivalents of $746 million and a total of $961 million of capacity under its credit facilities. EMG's consolidated debt at June 30, 2010 was $4.1 billion, of which $107 million was current. In addition, EMG's subsidiaries had $3.0 billion of long-term lease obligations related to their sale-leaseback transactions that are due over periods ranging up to 25 years.

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The following table summarizes the status of the EME and Midwest Generation credit facilities at June 30, 2010:

(in millions)
  EME
  Midwest
Generation

 
   

Commitment

  $ 600   $ 500  

Less: Commitment from Lehman Brothers subsidiary

    (36 )    
       

    564     500  

Outstanding borrowings

         

Outstanding letters of credit

    (100 )   (3 )
       

Amount available

  $ 464   $ 497  
   

As a result of credit ratings actions in 2010, described under "—Credit Ratings," the margins applicable to Midwest Generation's $500 million working capital facility increased 27.5 basis points. Borrowings made under this credit facility currently bear interest at LIBOR plus 1.15%, unless average utilized commitments during a period exceed $250 million, in which case the margin increases to 1.275%.

For the remainder of 2010, EMG anticipates capital expenditures of $635 million (excluding a $289 million disputed amount under a turbine supply agreement) to be funded with a combination of project-level financing, U.S. Treasury grants, cash on hand, and cash flow from operations. EMG secured a $206 million vendor financing, of which $200 million was available at June 30, 2010, and a $160 million project financing, of which $70 million was available at June 30, 2010. EMG intends to file for U.S. Treasury grants for its renewable energy projects in construction.

EMG may from time to time seek to retire or purchase its outstanding debt through cash purchases and/or exchange offers, in open market purchases, privately negotiated transactions or otherwise. Such repurchases or exchanges, if any, will depend on prevailing market conditions, EMG's liquidity requirements, contractual restrictions and other factors. The amounts involved may be material.

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Capital Investment Plan

At June 30, 2010, forecasted capital expenditures through 2012 by EMG's subsidiaries for existing projects, corporate activities and turbine commitments were as follows:

(in millions)
  July through December 2010
  2011
  2012
 
   

Midwest Generation Plants

                   
 

Plant capital expenditures

  $ 26   $ 79   $ 10  
 

Environmental expenditures1

    93     145     78  

Homer City Facilities

                   
 

Plant capital expenditures

    8     52     24  
 

Environmental expenditures2

    1     3     22  

Renewable Projects

                   
 

Capital and construction expenditures3

    495          
 

Turbine commitments4

        85      

Other capital expenditures

    12     17     9  
       

Total

  $ 635   $ 381   $ 143  
   
1
Environmental expenditures include primarily expenditures related to SNCR equipment and $156 million for expenditures during the remainder of 2010 to 2012 to retrofit initial units using dry scrubbing with sodium-based sorbents to comply with CPS requirements for SO2 emissions. Midwest Generation could elect to shut down units instead of installing controls to be in compliance with the CPS, and, therefore, decisions about any particular combination of retrofits and shutdowns it may ultimately employ to comply remain subject to conditions applicable at the time decisions are required or made. For additional discussion, see "Edison International Overview—Environmental Developments" and refer to "Environmental Regulation of Edison International and Subsidiaries" in the 2009 Form 10-K.

2
Excludes amounts that may become required under environmental regulations for future operations. For further information, see "Edison International Notes to Consolidated Financial Statements—Note 6. Commitments and Contingencies—Contingencies—Environmental Developments—Transport Rule" and "—Contingencies—Homer City New Source Review Notice of Violation.

3
Includes projects under construction where project financing has been secured. The available balance under secured financing arrangements was $270 million as of June 30, 2010. For further discussion, see "Edison International Notes to Consolidated Financial Statements—Note 3. Liabilities and Lines of Credit," and refer to "EMG: Liquidity and Capital Resources Project-Level Financing" in the year-ended 2009 MD&A.

4
Turbine commitment figures exclude $289 million which is subject to dispute under provisions in one of the turbine supply agreements. In March 2010, EME filed a breach of contract complaint against this turbine supplier. For additional discussion, see "Legal Proceedings" in Part II of this quarterly report.


Estimated Expenditures for Existing Projects

Plant capital expenditures relate to non-environmental projects such as upgrades to boiler and turbine controls, replacement of major boiler components, mill steam inerting projects, generator stator rewinds, 4Kv switchgear and main power transformer replacement.

Environmental expenditures at Homer City relate to emission monitoring and control projects. Midwest Generation is subject to various commitments with respect to environmental compliance. Expenditures, in addition to those included on the preceding table, are anticipated and could be material; however,

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the amounts and timing have not been determined. For more information on the current status of environmental improvements in Illinois, see "Edison International Overview—Environmental Developments." For further discussion of environmental regulations, refer to "Environmental Regulation of Edison International and Subsidiaries" in the 2009 Form 10-K.


Estimated Expenditures for Future Projects

EMG has wind turbines in storage and on order for wind projects under construction and to be used for future wind projects (turbine commitments are reflected separately in the preceding capital expenditure table). Amounts exclude balance of project costs for 102 MW available for new projects, which EMG estimates to be an additional $75 million to $120 million based on typical project costs. The pace of additional growth in EMG's renewables program will be subject to the availability of projects that meet EMG's requirements and the capital needed for development, which will be affected by the extent of internally generated cash flow and future decisions about capital expenditures for environmental compliance by its coal fleet. Consequently, pending substantial progress on or financing of the environmental retrofits, growth of the renewables programs may depend upon the availability of outside project-level debt and equity financing. Successful completion of the development of a wind project depends upon obtaining permits and agreements necessary to support an investment and may take a number of years due to factors that include local permit requirements, willingness of local utilities to purchase renewable power at sufficient prices to earn an appropriate rate of return, and availability and prices of equipment.


Historical Consolidated Cash Flow

This section discusses EMG's consolidated cash flows from operating, financing and investing activities.


Condensed Consolidated Statement of Cash Flows

 
  Six Months Ended June 30,  
(in millions)
  2010
  2009
 
   

Operating cash flows used by continuing operations

  $ (120 ) $ (1,139 )

Operating cash flow from discontinued operations

    8     (4 )
       

Net cash used by operating activities

    (112 )   (1,143 )

Net cash provided (used) by financing activities

    (52 )   147  

Net cash provided (used) by investing activities

    (274 )   1,233  
       

Net increase (decrease) in cash and cash equivalents

  $ (438 ) $ 237  
   


Cash Flows Used by Operating Activities

Cash used by operating activities from continuing operations decreased $1 billion in the first six months of 2010, compared to the first six months of 2009. The 2009 change was primarily due to the impacts of the Global Settlement which resulted in remittances of net tax allocation payments to Edison International of $1.1 billion by Edison Capital related to the termination of Edison Capital's interests in cross-border leases (see "Item 8. Edison International Notes to Consolidated Financial Statements—Note 4. Income Taxes" of the 2009 Form 10-K for further discussion). In April 2010, Edison Capital funded a $253 million deposit to the IRS related to the Global Settlement. The 2010 change was also due to a decrease in cash collateral deposits for risk management and energy trading compared to 2009, $92 million received related to U.S. Treasury grants, and changes in the timing of cash receipts and disbursements related to working capital items.

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Cash Flows Provided (Used) by Financing Activities

Cash provided (used) by financing activities from continuing operations decreased $199 million in the first six months of 2010, compared to the first six months of 2009. The 2010 decrease was primarily attributable to lower levels of renewable energy project financing. For further project financing details, see "Edison International Notes to Consolidated Financial Statements—Note 3. Liabilities and Lines of Credit." In addition, in January 2010, Edison Capital redeemed in full its medium-term loans.


Cash Flows Provided (Used) by Investing Activities

Cash provided (used) by investing activities from continuing operations decreased $1.5 billion in the first six months of 2010, compared to the first six months of 2009. The 2010 decrease was primarily due to $1.385 billion of net proceeds from termination of the cross-border leases at Edison Capital in 2009. The change was also due to higher expenditures for construction of renewable energy projects compared to 2009.


Credit Ratings

Overview

On June 29, 2010, Moody's lowered the credit ratings of EME to B3 from B2 and Midwest Generation to Ba2 from Ba1. 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.

EMG does not have any "rating triggers" contained in subsidiary financings that would result in it being required to make equity contributions or provide additional financial support to its subsidiaries, 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. Furthermore, EMMT also has hedge contracts that do not require margin, but contain the right of each party to request additional credit support in the form of adequate assurance of performance in the case of an adverse development affecting the other party. For discussions of contingent features related to energy contracts, see "—Margin, Collateral Deposits and Other Credit Support for Energy Contracts."


Credit Rating of EMMT

For a discussion of the effect of EMMT's credit rating on EMG's ability to sell forward the output of the Homer City facilities through EMMT, refer to "EMG: Liquidity and Capital Resources—Credit Ratings—Credit Rating of EMMT" in the year-ended 2009 MD&A.


Margin, Collateral Deposits and Other Credit Support for Energy Contracts

Future cash collateral requirements may be higher than the margin and collateral requirements were at June 30, 2010, if wholesale energy prices change or if EMMT enters into additional transactions. EMG estimates that margin and collateral requirements for energy and congestion contracts outstanding as of June 30, 2010 could increase by approximately $184 million over the remaining life of the contracts using a 95% confidence level. This increase may not be offset by similar changes in the cash flows of the underlying hedged items in the same periods. Certain EMMT hedge contracts do not require margin, but contain provisions that require EMG or Midwest Generation to comply with the terms and

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conditions of their credit facilities. The credit facilities contain financial covenants which are described further in "—Debt Covenants and Dividend Restrictions."

Hedge contracts include provisions relating to a change in control or material adverse effect resulting from amendments or modifications to the related credit facility. EMMT has hedge contracts that do not require margin, but contain the right of each party to request additional credit support in the form of adequate assurance of performance in the case of an adverse development affecting the other party. The aggregate fair value of all derivative instruments with credit-risk-related contingent features is in an asset position at June 30, 2010 and, accordingly, the contingent features described above do not currently have a liquidity exposure. Future increases in power prices could expose EME or Midwest Generation to termination payments or additional collateral postings under the contingent features described above.

Midwest Generation has cash on hand and a credit facility to support margin requirements specifically related to contracts entered into by EMMT related to the Midwest Generation plants. In addition, EMG has cash on hand and a credit facility to provide credit support to subsidiaries. For discussion on available borrowing capacity under Midwest Generation and EME credit facilities, see "—Available Liquidity."


Debt Covenants and Dividend Restrictions

Credit Facility and Financial Ratios

EME's credit facility contains financial covenants which require EME to maintain a minimum interest coverage ratio and a maximum corporate-debt-to-capital ratio as such terms are defined in the credit facility.

The following table sets forth the interest coverage ratio:

 
  12 Months Ended  
(in millions)
  June 30,
2010

  December 31,
2009

 
   

Ratio

    1.72     1.72  

Covenant threshold (not less than)

    1.20     1.20  
   

The following table sets forth the corporate-debt-to-capital ratio:

(in millions)
  June 30,
2010

  December 31,
2009

 
   

Corporate-debt-to-capital ratio

    0.53     0.54  

Covenant threshold (not more than)

    0.75     0.75  
   

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Dividend Restrictions in Major Financings

Set forth below are key ratios of EME's principal subsidiaries required by financing arrangements at June 30, 2010 or for the 12 months ended June 30, 2010:

Subsidiary
  Financial Ratio
  Covenant
  Actual
 

Midwest Generation (Midwest Generation plants)

 

Debt to Capitalization Ratio

 

Less than or equal to
0.60 to 1

  0.16 to 1

Homer City (Homer City facilities)

 

Senior Rent Service Coverage Ratio

 

Greater than
1.7 to 1

  2.53 to 1
 

For a more detailed description of the covenants binding EME's principal subsidiaries that may restrict the ability of those entities to make distributions to EME directly or indirectly through the other holding companies owned by EME, refer to "EMG: Liquidity and Capital Resources—Debt Covenants and Dividend Restrictions—Dividend Restrictions in Major Financings" in the year-ended 2009 MD&A.


EME's Senior Notes and Guaranty of Powerton-Joliet Leases

EME is restricted under applicable agreements from the sale or disposition 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, 2010, the maximum permissible sale or disposition of EME assets was $805 million.


Contractual Obligations and Contingencies

Fuel Supply and Transportation Contracts

For a discussion of fuel supply contracts and coal transportation agreements, see "Edison International Notes to Consolidated Financial Statements—Note 6. Commitments and Contingencies—Other Commitments."


Midwest Generation New Source Review Lawsuit

For a discussion of the Midwest Generation New Source Review Lawsuit, see "Edison International Notes to Consolidated Financial Statements—Note 6. Commitments and Contingencies—Contingencies—Midwest Generation New Source Review Lawsuit."


Homer City New Source Review Notice of Violation

For a discussion of the Homer City New Source Review Notice of Violation, see "Edison International Notes to Consolidated Financial Statements—Note 6. Commitments and Contingencies—Contingencies—Homer City New Source Review Notice of Violation."


Off-Balance Sheet Transactions

For a discussion of Edison International's off-balance sheet transactions, refer to "EMG: Liquidity and Capital Resources—Off-Balance Sheet Transactions" in the year-ended 2009 MD&A. There have been

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no significant developments with respect to Edison International's off-balance sheet transactions that affect disclosures presented in the 2009 Form 10-K.


Environmental Matters and Regulations

For a discussion of EMG's environmental matters, refer to "Environmental Regulation of Edison International and Subsidiaries" in the 2009 Form 10-K. There have been no significant developments with respect to environmental matters specifically affecting EMG since the filing of the 2009 Form 10-K, except as set forth in "Edison International Notes to Consolidated Financial Statements—Note 6. Commitments and Contingencies—Contingencies—Environmental Developments."


MARKET RISK EXPOSURES

For a detailed discussion of EMG's market risk exposures, including commodity price risk, credit risk and interest rate risk, refer to "EMG: Market Risk Exposures" in the year-ended 2009 MD&A.


Commodity Price Risk

Energy Price Risk Affecting Sales from the Fossil-Fueled Facilities

Energy and capacity from the fossil-fueled facilities 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. Hedging transactions related to generation are generally entered into at the Northern Illinois Hub or the AEP/Dayton Hub, both in PJM, for the Midwest Generation plants and generally at the PJM West Hub for the Homer City facilities. These trading hubs have been the most liquid locations for hedging purposes.

The following table depicts the average historical market prices for energy per megawatt-hour at the locations indicated for the first six months of 2010 and 2009:

 
  24-Hour Average Historical Market Prices1  
 
  2010
  2009
 
   

Midwest Generation plants

             
 

Northern Illinois Hub

  $ 33.44   $ 30.08  

Homer City facilities

             
 

PJM West Hub

  $ 43.88   $ 41.40  
 

Homer City Busbar

    38.28     38.01  
   
1
Energy prices were calculated at the respective delivery points using historical hourly real-time prices as published by PJM or provided on the PJM web site.

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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, 2010:

 
  24-Hour Forward Energy Prices1  
 
  Northern
Illinois Hub

  PJM West Hub
 
   

2010

             
 

July

  $ 40.32   $ 53.39  
 

August

    39.34     52.04  
 

September

    31.05     42.66  
 

October

    26.59     40.15  
 

November

    30.05     41.16  
 

December

    32.43     44.25  

2011 calendar "strip"2

 
$

32.75
 
$

45.54
 
   
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.

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 fossil-fueled facilities into these markets may vary materially from the forward market prices set forth in the preceding table.

EMMT engages in hedging activities for the fossil-fueled facilities to hedge the risk of future change in the price of electricity. The following table summarizes the hedge positions (including load-serving transactions and forward contracts accounted for on the accrual basis) as of June 30, 2010 for electricity expected to be generated during the remainder of 2010 and in 2011 and 2012:

 
  2010
  2011
  2012
 
 
     
 
  MWh (in
thousands)

  Average
price/
MWh1

  MWh (in
thousands)

  Average
price/
MWh1

  MWh (in
thousands)

  Average
price/
MWh1

 
   

Midwest Generation plants

                                     
 

Northern Illinois and AEP/Dayton Hubs

    9,835   $ 42.87     14,152   $ 37.93     2,040   $ 41.37  

Homer City facilities2

                                     
 

PJM West Hub

    2,540     71.19     2,428     52.15     1,182     51.78  
       

Total

    12,375           16,580           3,222        
   
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 or PJM West Hub prices set forth above.

2
Includes hedging transactions primarily at the PJM West Hub and to a lesser extent at other trading locations. Years 2010, 2011 and 2012 include hedging activities entered into by EMMT for the Homer City facilities that are not designated under the intercompany agreements with Homer City due to limitations under the sale leaseback transaction documents.

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In addition, as of June 30, 2010, EMMT had entered into 1.5 bcf of natural gas futures contracts (equivalent to approximately 255 GWh of energy only contracts using a ratio of 6 MMBtu to 1 MWh) for the Midwest Generation plants to economically hedge energy price risks during 2010 at an equivalent average energy price of approximately $38.40/MWh.


Capacity Price Risk

The following table summarizes the status of capacity sales for Midwest Generation and Homer City at June 30, 2010:

 
   
   
   
  RPM Capacity
Sold in Base
Residual Auction

  Other Capacity Sales,
Net of Purchases2

   
 
 
   
   
   
       
 
 
  Installed
Capacity
MW

  Unsold
Capacity1
MW

  Capacity
Sold
MW

  MW
  Price per
MW-day

  MW
  Average
Price per
MW-day

  Aggregate
Average
Price per
MW-day

 
   

July 1, 2010 to May 31, 2011

                                                 
 

Midwest Generation

    5,477     (548 )   4,929     4,929   $ 174.29       $   $ 174.29  
 

Homer City

    1,884     (211 )   1,673     1,813     174.29     (140 )   55.36     184.24  

June 1, 2011 to May 31, 2012

                                                 
 

Midwest Generation

    5,477     (495 )   4,982     4,582     110.00     400     85.00     107.99  
 

Homer City

    1,884     (113 )   1,771     1,771     110.00             110.00  

June 1, 2012 to May 31, 2013

                                                 
 

Midwest Generation

    5,477     (773 )   4,704     4,704     16.46             16.46  
 

Homer City

    1,884     (148 )   1,736     1,736     133.37             133.37  

June 1, 2013 to May 31, 2014

                                                 
 

Midwest Generation

    5,477     (827 )   4,650     4,650     27.73             27.73  
 

Homer City

    1,884     (104 )   1,780     1,780     226.15             221.03 3
   
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
Includes the impact of a 100 MW capacity swap transactions executed prior to the base residual auction at $135 MW-day.

The RPM auction capacity prices for the delivery period of June 1, 2013 to May 31, 2014 varied between different areas of PJM. In the western portion of PJM, affecting Midwest Generation, the price of $27.73 per MW-day was substantially lower than other areas' capacity prices. The impact of lower capacity prices for this period 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, which is uncertain.


Basis Risk

During the six months ended June 30, 2010, transmission congestion in PJM has resulted in prices at the individual busbars of the Midwest Generation plants being lower than those at the AEP/Dayton Hub and Northern Illinois Hub by an average of 11% and 1%, respectively, compared to 17% and less

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than 1%, respectively, during the six months ended June 30, 2009. During the six months ended June 30, 2010 and 2009, transmission congestion in PJM has resulted in prices at the Homer City busbar being lower than those at the PJM West Hub by an average of 13% and 8%, respectively.


Coal and Transportation Price Risk

The Midwest Generation plants and Homer City facilities 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, 2010 for the remainder of 2010 and the following three years:

 
  Amount of Coal Under Contract
in Millions of Equivalent Tons1
 
 
  July through
December 2010

  2011
  2012
  2013
 
   

Midwest Generation plants2

    10.2     11.7     9.8      

Homer City facilities

    2.5     4.2     1.7     0.5  
   
1
The amount of coal under contract in tons is calculated based on contracted tons and applying an 8,800 Btu equivalent for the Midwest Generation plants and 13,000 Btu equivalent for the Homer City facilities.

2
In July 2010, Midwest Generation entered into additional contracts for the purchase of 3.9 million tons of coal for 2011.

EMG is subject to price risk for purchases of coal that are not under contract. Prices of Northern Appalachian (NAPP) coal, which are related to the price of coal purchased for the Homer City facilities, increased during 2010 from 2009 year-end prices. The market price of NAPP coal (with 13,000 Btu per pound heat content and <3.0 pounds of SO2 per MMBtu sulfur content) increased to a price of $62.75 per ton at July 2, 2010, compared to a price of $52.50 per ton at December 31, 2009, as reported by the Energy Information Administration.

Prices of PRB coal (with 8,800 Btu per pound heat content and 0.8 pounds of SO2 per MMBtu sulfur content) purchased for the Midwest Generation plants increased during 2010 from 2009 year-end prices. The market price of PRB coal increased to a price of $13.05 per ton at July 2, 2010, compared to a price of $9.25 per ton at December 31, 2009, as reported by the Energy Information Administration.

EMG has contracts for the transport of coal to its facilities. The primary contract is with Union Pacific Railroad (and various short-haul carriers), which extends through 2011. EMG is exposed to price risk related to transportation rates after the expiration of its existing transportation contracts. Current market transportation rates for PRB coal are higher than the existing rates under contract. Transportation costs are approximately half of the delivered cost of PRB coal to the Midwest Generation plants.


Emission Allowances Price Risk

EMG purchases (or sells) emission allowances for the fossil-fueled facilities based on the amounts required for actual generation in excess of (or less than) the amounts allocated to these facilities under applicable programs. In the event that actual emission allowances required are greater than allowances held, EMG is subject to price risk for purchases of emission allowances. The market price for emission allowances may vary significantly. The average purchase price of SO2 allowances decreased to $50 per

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ton during the six months ended June 30, 2010 from $65 per ton in 2009. The average purchase price of annual NOx allowances decreased to $974 per ton during the six months ended June 30, 2010 from $1,431 per ton in 2009. Based on broker's quotes and information from public sources, the spot price for SO2 allowances and annual NOx allowances was $15 per ton and $465 per ton, respectively, at June 30, 2010.

For a discussion of environmental regulations related to emissions, refer to "Environmental Regulation of Edison International and Subsidiaries" in the 2009 Form 10-K.

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. EMG'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, 2010, the balance sheet exposure as described above, broken down by the credit ratings of EMG's counterparties, was as follows:

 
  June 30, 2010  
(in millions)
  Exposure2
  Collateral
  Net Exposure
 
   

Credit Rating1

                   
 

A or higher

  $ 133   $ (28 ) $ 105  
 

A-

    120     (6 )   114  
 

BBB+

    27         27  
 

BBB

    23         23  
 

BBB-

    23         23  
 

Below investment grade

    20     (18 )   2  
       

Total

  $ 346   $ (52 ) $ 294  
   
1
EMG 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 sheets, except for any related accounts receivable.

The credit risk exposure set forth in the above table is comprised of $139 million of net accounts receivable and payables and $207 million representing the fair value of derivative contracts. The exposure is based on master netting agreements with the related counterparties. Due to developments in the financial markets, credit ratings may not be reflective of the actual related credit risks. In addition to the amounts set forth in the above table, EMG's subsidiaries have posted a $108 million cash margin in the aggregate with PJM, New York Independent System Operator (NYISO), Midwest Independent Transmission System Operator (MISO), clearing brokers and other counterparties to support hedging and trading activities. The margin posted to support these activities also exposes EMG to credit risk of the related entities.

The fossil-fueled facilities sell electric power generally into the PJM market by participating in PJM's capacity and energy markets or transact in capacity and energy on a bilateral basis. Sales into PJM accounted for approximately 67% of EMG's consolidated operating revenues for the six months ended June 30, 2010. PJM, a regional transmission organization (RTO) with over 300 member companies, maintains its own credit risk policies and does not extend unsecured credit to non-investment grade

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companies. Losses resulting from a PJM member default are shared by all other members using a predetermined formula. At June 30, 2010, EMG's account receivable due from PJM was $66 million.

The terms of EMG's wind turbine supply agreements contain significant obligations of the suppliers in the form of manufacturing and delivery of turbines, and payments for delays in delivery and for failure to meet performance obligations and warranty agreements. EMG'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 EMG's turbine suppliers may have a material impact on EMG'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. EMG 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 details, see "Edison International Notes to Consolidated Financial Statements—Note 3. Liabilities and Lines of Credit." The fair market value of fixed interest rate obligations are subject to interest rate risk. The fair market value of EMG's consolidated short-term debt and long-term obligations (including current portion) was $2.8 billion at June 30, 2010, compared to the carrying value of $4.1 billion.

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EDISON INTERNATIONAL PARENT AND OTHER

RESULTS OF OPERATIONS

Results of operations for Edison International parent and other includes amounts from other Edison International subsidiaries that are not significant as a reportable segment, as well as intercompany eliminations.

Edison International parent and other income from continuing operations were $16 million and $43 million for the three months ended June 30, 2010 and 2009, respectively, and $11 million and $37 million for the six months ended June 30, 2010 and 2009, respectively.


LIQUIDITY AND CAPITAL RESOURCES

Historical Cash Flow

This section discusses Edison International (parent) and other cash flows from operating, financing and investing activities.


Condensed Statement of Cash Flows

 
  Six Months Ended
June 30,
 
(in millions)
  2010
  2009
 
   

Cash flows used by operating activities

  $ (21 ) $ (27 )

Cash flows provided (used) by financing activities

    25     (274 )

Cash flows provided by investing activities

    7     6  
       

Net increase (decrease) in cash and equivalents

  $ 11   $ (295 )
   


Cash Flows Provided (Used) by Financing Activities

Financing activities for the first six months of 2010 were as follows:

Paid $205 million of (or $0.315 per share) dividends to Edison International common shareholders. These quarterly dividends represent an increase of $0.005 per share over quarterly dividends paid in 2009. In April 2010, the Board of Directors of Edison International declared a $0.315 per share quarterly dividend which was paid in July 2010.

Received $100 million of dividend payments from SCE.

Borrowed $130 million under Edison International's line of credit to fund interim working capital requirements.

Financing activities for the first six months of 2009 were as follows:

Paid $202 million of (or $0.31 per share) dividends to Edison International common shareholders. These quarterly dividends represent an increase of $0.005 per share over quarterly dividends paid in 2008.

Repaid a net $173 million of short-term debt.

Received $100 million of dividend payments from SCE.

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EDISON INTERNATIONAL (CONSOLIDATED)

CONTRACTUAL OBLIGATIONS

For a discussion of Edison International (Consolidated) contractual obligations, refer to "Edison International (Consolidated)—Contractual Obligations" in the year-ended 2009 MD&A. There have been no significant changes with respect to Edison International (Consolidated) contractual obligations since the filing of the 2009 Form 10-K, except as discussed in "EMG: Liquidity and Capital Resources—Contractual Obligations and Contingencies" and "SCE: Liquidity and Capital Resources—Contractual Obligations and Contingencies."


NEW ACCOUNTING GUIDANCE

New accounting guidance is discussed in "Edison International Notes to Consolidated Financial Statements Note 1. Summary of Significant Accounting Policies—New Accounting Guidance."

ITEM 3.    QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

Information responding to this item is included in the MD&A under the headings "SCE: Market Risk Exposures" and "EMG: Market Risk Exposures" and is incorporated herein by reference.

ITEM 4.    CONTROLS AND PROCEDURES

Disclosure Controls and Procedures

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


Changes in Internal Control Over Financial Reporting

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

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PART II. OTHER INFORMATION

ITEM 1.    LEGAL PROCEEDINGS

Homer City New Source Review Notice of Violation

Developments related to the Homer City New Source Review Notice of Violation are discussed in "Edison International Notes to Consolidated Financial Statements Note 6. Commitments and Contingencies—Contingencies—Homer City New Source Review Notice of Violation—Recent Developments."


Midwest Generation New Source Review Lawsuit

Developments related to the Midwest Generation New Source Review Lawsuit are discussed in "Edison International Notes to Consolidated Financial Statements Note 6. Commitments and Contingencies—Contingencies—Midwest Generation New Source Review Lawsuit—Recent Developments."


Mitsubishi Lawsuit

EME and Mitsubishi Power Systems Americas, Inc. are parties to a wind turbine generator supply agreement executed in March 2007 with respect to the purchase of 166 wind turbines and related services and warranties. Mitsubishi has delivered 83 wind turbines under the agreement. The remaining wind turbines, among other items, are under dispute.

EME filed a complaint on March 19, 2010, and an amended complaint on April 1, 2010, in the Superior Court of the State of California against Mitsubishi Power Systems Americas, Inc. and Mitsubishi Heavy Industries, Ltd with respect to a wind turbine generator supply agreement for the purchase of wind turbines and related services and warranties. EME's complaint alleges, among other things: (a) that the Mitsubishi entities fraudulently induced EME to enter into the supply agreement by misrepresenting the facts and circumstances surrounding Mitsubishi's rights to certain technology incorporated into the turbines; (b) that the Mitsubishi entities breached the implied covenant of good faith and fair dealing; (c) that the Mitsubishi entities breached their warranty obligations; (d) that the Mitsubishi entities repudiated the supply agreement when they failed to provide EME with adequate assurances of performance; and (e) that certain price escalation provisions in the supply agreement do not reflect the intent of the contracting parties.

The complaint asks the Court for an order finding the supply agreement void and unenforceable or, in the alternative, for an order reforming its price escalation provisions to conform to the contracting parties' intent. The complaint also requests an order of specific performance requiring the Mitsubishi entities to honor their warranties with respect to equipment already purchased, an award of monetary damages (including exemplary and punitive damages), and an accounting of all amounts due under the supply agreement, including reimbursement to EME of amounts previously paid for units it can no longer use and is excused from accepting, together with prejudgment interest, and such other relief as the Court may deem just and proper. In June 2010, EME filed a motion to amend its complaint to include, among other things, additional support for its claims.

The failure of the Mitsubishi entities to perform certain previously contracted services pertaining to the Taloga project, including delivery and commissioning of turbines still in storage, could delay the development of the Taloga project. If the Taloga project does not achieve commercial operation by March 31, 2011, subject to extension under certain circumstances, Taloga's offtaker could seek to terminate or renegotiate its power purchase agreement.

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Navajo Nation Litigation

Developments related to the Navajo Nation Litigation are discussed in "Edison International Notes to Consolidated Financial Statements Note 6. Commitments and Contingencies—Contingencies—Navajo Nation Litigation."

ITEM 2.    UNREGISTERED SALES OF EQUITY SECURITIES AND USE OF PROCEEDS

(c)
Purchases of Equity Securities by the Issuer and Affiliated Purchasers

Period
  (a) Total
Number of
Shares
(or Units)
Purchased1

  (b) Average
Price Paid per
Share (or Unit)1

  (c) Total
Number of
Shares
(or Units)
Purchased
as Part of
Publicly
Announced
Plans or
Programs

  (d) Maximum
Number (or
Approximate
Dollar Value)
of Shares
(or Units) that May
Yet Be Purchased
Under the Plans or
Programs

 
   

April 1, 2010 to April 30, 2010

    247,095   $ 33.78          

May 1, 2010 to May 31, 2010

    1,046,903   $ 32.80          

June 1, 2010 to June 30, 2010

    603,223   $ 32.68          
       

Total

    1,897,221   $ 32.89          
   
1
The shares were purchased by agents acting on Edison International's behalf for delivery to plan participants to fulfill requirements in connection with Edison International's (i) 401(k) Savings Plan, (ii) Dividend Reinvestment and Direct Stock Purchase Plan, and (iii) long-term incentive compensation plans. The shares were purchased in open-market transactions pursuant to plan terms or participant elections. The shares were never registered in Edison International's name and none of the shares purchased were retired as a result of the transactions.

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ITEM 6.    EXHIBITS

10.1   Edison International Director Matching Gifts Program, as adopted June 24, 2010

31.1

 

Certification of the Chief Executive Officer pursuant to Section 302 of the Sarbanes-Oxley Act

31.2

 

Certification of the Chief Financial Officer pursuant to Section 302 of the Sarbanes-Oxley Act

32

 

Statement Pursuant to 18 U.S.C. Section 1350

101

 

Financial statements from the quarterly report on Form 10-Q of Edison International for the quarter ended June 30, 2010, filed on August 5, 2010, formatted in XBRL: (i) the Consolidated Statements of Income (Loss); (ii) the Consolidated Statements of Comprehensive Income (Loss); (iii) the Consolidated Balance Sheets; (iv) the Consolidated Statements of Cash Flows; and (v) the Notes to the Consolidated Financial Statements

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SIGNATURE

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


 

 

EDISON INTERNATIONAL
                    (Registrant)

 

 

By:

 

/s/ MARK C. CLARKE

Mark C. Clarke
Vice President and Controller
(Duly Authorized Officer and
Principal Accounting Officer)

Date: August 5, 2010

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