Form 10-Q

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

 


FORM 10-Q

 


(Mark One)

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

 

     For the quarterly period ended June 30, 2007

 

¨ 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  x    No  ¨

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, or a non-accelerated filer. See definition of “accelerated filer” in Rule 12b-2 of the Exchange Act.

 

Large accelerated filer  x       Accelerated filer  ¨       Non-accelerated filer  ¨    

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

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 3, 2007

Common Stock, no par value   325,811,206

 



EDISON INTERNATIONAL

INDEX

 

    

Page

No.

Part I. Financial Information

  

Item 1.

   Financial Statements:    1
  

Consolidated Statements of Income – Three and Six Months Ended June 30, 2007 and 2006

   1
  

Consolidated Statements of Comprehensive Income – Three and Six Months Ended June 30, 2007 and 2006

   2
  

Consolidated Balance Sheets – June 30, 2007 and December 31, 2006

   3
  

Consolidated Statements of Cash Flows – Six Months Ended June 30, 2007 and 2006

   5
  

Notes to Consolidated Financial Statements

   7

Item 2.

  

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

   36

Item 3.

  

Quantitative and Qualitative Disclosures About Market Risk

   87

Item 4.

  

Controls and Procedures

   88
Part II. Other Information   

Item 1.

  

Legal Proceedings

   89

Item 2.

  

Unregistered Sales of Equity Securities and Use of Proceeds

   89

Item 4.

  

Submission of Matters to a Vote of Security Holders

   89

Item 6.

  

Exhibits

   91

Signature

   92

 

i


GLOSSARY

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

 

Btu

   British Thermal units

Commonwealth Edison

   Commonwealth Edison Company

CDWR

   California Department of Water Resources

CPSD

   Consumer Protection and Safety Division

CPUC

   California Public Utilities Commission

District Court

   U.S. District Court for the District of Columbia

DOE

   United States Department of Energy

DRA

   CPUC Division of Ratepayer Advocates

DWP

   Los Angeles Department of Water & Power

EME

   Edison Mission Energy

EME Homer City

   EME Homer City Generation L.P.

EMG

   Edison Mission Group Inc.

EMMT

   Edison Mission Marketing & Trading, Inc.

EPS

   earnings per share

ERRA

   energy resource recovery account

Exelon Generation

   Exelon Generation Company LLC

FASB

   Financial Accounting Standards Board

FERC

   Federal Energy Regulatory Commission

FIN 39-1

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

FIN 48

   Financial Accounting Standards Interpretation No. 48, Accounting for Uncertainty in Income Taxes—an interpretation of FAS 109

FTR

   firm transmission rights

GRC

   General Rate Case

IRS

   Internal Revenue Service

ISO

   California Independent System Operator

kWh(s)

   kilowatt-hour(s)

MD&A

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

MEHC

   Mission Energy Holding Company

Midland Cogen

   Midland Cogeneration Venture

Midway-Sunset

   Midway-Sunset Cogeneration Company

Midwest Generation

   Midwest Generation, LLC

Moody’s

   Moody’s Investors Service

MW

   Megawatts


GLOSSARY (Continued)

 

MWh

   megawatt-hours

NAPP

   Northern Appalachian

Ninth Circuit

   United States Court of Appeals for the Ninth Circuit

NOX

   nitrogen oxide

NRC

   Nuclear Regulatory Commission

NOI

   Notice of Intent

NOV

   Notice of Violation

Palo Verde

   Palo Verde Nuclear Generating Station

PBR

   performance-based ratemaking

PG&E

   Pacific Gas & Electric Company

PJM

   PJM Interconnection, LLC

PRB

   Powder River Basin

PX

   California Power Exchange

QF(s)

   qualifying facility(ies)

RICO

   Racketeer Influenced and Corrupt Organization

RPM

   Reliability Pricing Model

S&P

   Standard & Poor’s

San Onofre

   San Onofre Nuclear Generating Station

SCE

   Southern California Edison Company

SDG&E

   San Diego Gas & Electric

SFAS

   Statement of Financial Accounting Standards issued by the FASB

SFAS No. 123(R)

   Statement of Financial Accounting Standards No. 123(R), “Share-Based Payment (revised 2004)”

SFAS No. 133

   Statement of Financial Accounting Standards No. 133, “Accounting for Derivative Instruments and Hedging Activities”

SFAS No. 144

   Statement of Financial Accounting Standards No. 144, “Accounting for the Impairment or Disposal of Long-Lived Assets”

SFAS No. 157

   Statement of Financial Accounting Standards No. 157, “Fair Value Measurements”

SFAS No. 158

   Statement of Financial Accounting Standards No. 158, “Employers’ Accounting for Defined Benefit Pension and Other Postretirement Plans”

SFAS No. 159

   Statement of Financial Accounting Standards No. 159, “The Fair Value Option for Financial Assets and Liabilities, Including an Amendment of FASB Statement No. 115”

SIP(s)

   State Implementation Plan(s)

SO2

   sulfur dioxide

US EPA

   United States Environmental Protection Agency

VIE(s)

   variable interest entity(ies)


E D ISON INTERNATIONAL

PART I FINANCIAL INFORMATION

Item 1. Financial Statements

CONSOLIDATED STATEMENTS OF INCOME

 

    

Three Months Ended

June 30,

   

Six Months Ended

June 30,

 
In millions, except per-share amounts       2007             2006             2007             2006      
    (Unaudited)  

Electric utility

  $   2,459     $   2,521     $   4,681     $   4,739  

Nonutility power generation

    569       460       1,241       970  

Financial services and other

    19       20       37       44  

Total operating revenue

    3,047       3,001       5,959       5,753  

Fuel

    438       380       924       840  

Purchased power

    829       769       1,146       1,783  

Provisions for regulatory adjustment clauses – net

    (33 )     (10 )     255       (371 )

Other operation and maintenance

    999       933       1,879       1,818  

Depreciation, decommissioning and amortization

    313       339       627       631  

Net gain on sale of utility property and plant

          (1 )     (1 )     (1 )

Total operating expenses

    2,546       2,410       4,830       4,700  

Operating income

    501       591       1,129       1,053  

Interest and dividend income

    45       43       85       80  

Equity in income from partnerships and unconsolidated subsidiaries – net

    20       10       37       14  

Other nonoperating income

    22       33       39       74  

Interest expense – net of amounts capitalized

    (188 )     (209 )     (386 )     (409 )

Loss on early extinguishment of debt

    (241 )     (143 )     (241 )     (143 )

Other nonoperating deductions

    (9 )     (10 )     (22 )     (22 )

Income from continuing operations before tax and minority interest

    150       315       641       647  

Income tax expense

          95       129       206  

Dividends on preferred and preference stock of utility not subject to mandatory redemption

    13       13       26       25  

Minority interest

    46       34       65       59  

Income from continuing operations

    91       173       421       357  

Income from discontinued operations – net of tax

    2       4       5       77  

Income before accounting change

    93       177       426       434  

Cumulative effect of accounting change – net of tax

                      1  

Net income

  $ 93     $ 177     $ 426     $ 435  

Weighted-average shares of common stock outstanding

    326       326       326       326  

Basic earnings per common share:

       

Continuing operations

  $ 0.28     $ 0.53     $ 1.28     $ 1.08  

Discontinued operations

    0.01       0.01       0.01       0.24  

Total

  $ 0.29     $ 0.54     $ 1.29     $ 1.32  

Weighted-average shares, including effect of dilutive securities

    330       330       331       331  

Diluted earnings per common share:

       

Continuing operations

  $ 0.28     $ 0.53     $ 1.28     $ 1.09  

Discontinued operations

          0.01       0.01       0.23  

Total

  $ 0.28     $ 0.54     $ 1.29     $ 1.32  

Dividends declared per common share

  $ 0.29     $ 0.27     $ 0.58     $ 0.54  

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

 

1


EDISON INTERNATIONAL

CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME

 

     

Three Months Ended

June 30,

   

Six Months Ended

June 30,

 
In millions        2007            2006             2007             2006      
     (Unaudited)  

Net income

   $ 93    $ 177     $ 426     $ 435  

Other comprehensive income (loss), net of tax:

         

Foreign currency translation adjustments:

         

Other foreign currency translation adjustments-net

          2       (2 )     2  

Pension and postretirement benefits other than pensions:

         

Minimum pension liability adjustment

          (2 )           (2 )

Amortization of loss and prior service cost-net

                1        

Unrealized gain (loss) on cash flow hedges:

         

Other unrealized gain (loss) on cash flow hedges – net

     48      72       (121 )     259  

Reclassification adjustment for gain (loss) included in net income

     10      17       26       (13 )

Other comprehensive income (loss)

     58      89       (96 )     246  

Comprehensive income

   $   151    $   266     $   330     $   681  

 

 

 

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

 

2


EDISON INTERNATIONAL

CONSOLIDATED BALANCE SHEETS

 

In millions   

June 30,

2007

   

December 31,

2006

 
     (Unaudited)        

ASSETS

    

Cash and equivalents

   $ 1,219     $ 1,795  

Restricted cash

     52       59  

Margin and collateral deposits

     232       124  

Receivables, less allowances of $26 and $29 for uncollectible accounts at respective dates

     1,050       1,014  

Accrued unbilled revenue

     480       303  

Fuel inventory

     133       122  

Materials and supplies

     282       270  

Accumulated deferred income taxes – net

     349       203  

Derivative assets

     277       328  

Regulatory assets

     385       554  

Short-term investments

     317       558  

Other current assets

     215       152  

Total current assets

     4,991       5,482  

Nonutility property – less accumulated provision for depreciation of $1,688 and $1,627 at respective dates

     4,534       4,356  

Nuclear decommissioning trusts

     3,304       3,184  

Investments in partnerships and unconsolidated subsidiaries

     271       308  

Investments in leveraged leases

     2,507       2,495  

Other investments

     108       91  

Total investments and other assets

     10,724       10,434  

Utility plant, at original cost:

    

Transmission and distribution

     18,138       17,606  

Generation

     1,481       1,465  

Accumulated provision for depreciation

     (4,927 )     (4,821 )

Construction work in progress

     1,684       1,486  

Nuclear fuel, at amortized cost

     168       177  

Total utility plant

     16,544       15,913  

Regulatory assets

     2,821       2,818  

Restricted cash

     62       91  

Margin and collateral deposits

     14       4  

Derivative assets

     107       131  

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

     668       556  

Other long-term assets

     1,052       832  

Total long-term assets

     4,724       4,432  

Total assets

   $   36,983     $   36,261  

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

 

3


EDISON INTERNATIONAL

CONSOLIDATED BALANCE SHEETS

 

In millions, except share amounts   

June 30,

2007

   

December 31,

2006

     (Unaudited)      

LIABILITIES AND SHAREHOLDERS’ EQUITY

    

Short-term debt

   $ 175     $

Long-term debt due within one year

     330       488

Accounts payable

     853       926

Accrued taxes

     163       155

Accrued interest

     182       196

Counterparty collateral

     40       36

Customer deposits

     212       198

Book overdrafts

     222       140

Derivative liabilities

     123       181

Regulatory liabilities

     1,120       1,000

Other current liabilities

     859       983

Total current liabilities

     4,279       4,303

Long-term debt

     9,091       9,101

Accumulated deferred income taxes – net

     5,309       5,297

Accumulated deferred investment tax credits

     119       122

Customer advances

     161       160

Derivative liabilities

     65       86

Power-purchase contracts

     27       32

Accumulated provision for pensions and benefits

     1,152       1,099

Asset retirement obligations

     2,810       2,759

Regulatory liabilities

     3,234       3,140

Other deferred credits and other long-term liabilities

     1,494       1,267

Total deferred credits and other liabilities

     14,371       13,962

Total liabilities

     27,741       27,366

Commitments and contingencies (Note 6)

    

Minority interest

     292       271

Preferred and preference stock of utility not subject to mandatory redemption

     915       915

Common stock, no par value (325,811,206 shares outstanding at each date)

     2,106       2,080

Accumulated other comprehensive income (loss)

     (18 )     78

Retained earnings

     5,947       5,551

Total common shareholders’ equity

     8,035       7,709

Total liabilities and shareholders’ equity

   $   36,983     $   36,261

 

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

 

4


EDISON INTERNATIONAL

CONSOLIDATED STATEMENTS OF CASH FLOWS

 

     

Six Months Ended

June 30,

 
In millions        2007             2006      
     (Unaudited)  

Cash flows from operating activities:

    

Net income

   $ 426     $ 435  

Less: income from discontinued operations – net of tax

     5       77  

Income from continuing operations

     421       358  

Adjustments to reconcile to net cash provided by operating activities:

    

Cumulative effect of accounting change – net of tax

           (1 )

Depreciation, decommissioning and amortization

     627       631  

Realized loss on nuclear decommissioning trusts

     23        

Other amortization

     64       43  

Minority interest

     65       59  

Deferred income taxes and investment tax credits

     (193 )     160  

Equity in income from partnerships and unconsolidated subsidiaries

     (37 )     (14 )

Income from leveraged leases

     (31 )     (36 )

Levelized rent expense

     (112 )     (112 )

Loss on early extinguishment of debt

     241       143  

Regulatory assets – long-term

     76       112  

Regulatory liabilities – long-term

     (1 )     (174 )

Derivative assets – long-term

     (4 )     14  

Derivative liabilities – long-term

     (57 )     38  

Other assets

     (22 )     (96 )

Other liabilities

     251       (14 )

Margin and collateral deposits – net of collateral received

     (113 )     263  

Receivables and accrued unbilled revenue

     (189 )     (78 )

Derivative assets – short-term

     (40 )     171  

Derivative liabilities – short-term

     (63 )     42  

Inventory and other current assets

     (42 )     (47 )

Regulatory assets – short-term

     169       (204 )

Regulatory liabilities – short-term

     121       29  

Accrued interest and taxes

     205       (4 )

Accounts payable and other current liabilities

     (151 )     (333 )

Distributions and dividends from unconsolidated entities

  

 

21

 

    26  

Operating cash flows from discontinued operations

  

 

5

 

    82  

Net cash provided by operating activities

     1,234       1,058  

Cash flows from financing activities:

    

Long-term debt issued

     2,905       1,815  

Premium paid on extinguishment of debt and issuance costs

     (240 )     (26 )

Long-term debt repaid

       (2,965 )       (1,818 )

Issuance of preference stock

           196  

Rate reduction notes repaid

     (116 )     (116 )

Short-term debt financing – net

     175       518  

Change in book overdrafts

     82       (64 )

Shares purchased for stock-based compensation

     (180 )     (101 )

Proceeds from stock option exercises

     72       33  

Excess tax benefits related to stock option exercises

     35       14  

Dividends to minority shareholders

     (32 )     (63 )

Dividends paid

     (189 )     (176 )

Net cash provided (used) by financing activities

   $ (453 )   $ 212  

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

 

5


EDISON INTERNATIONAL

CONSOLIDATED STATEMENTS OF CASH FLOWS

 

     

Six Months Ended

June 30,

 
In millions        2007             2006      
     (Unaudited)  

Cash flows from investing activities:

    

Capital expenditures

   $ (1,335 )   $ (1,207 )

Purchase of interest of acquired companies

     (23 )     (18 )

Proceeds from sale of property and interests in projects

           44  

Proceeds from nuclear decommissioning trust sales

     2,017       1,461  

Purchases of nuclear decommissioning trust investments

     (2,084 )     (1,544 )

Proceeds from partnerships and unconsolidated subsidiaries, net of investment

     31       13  

Maturities and sales of short-term investments

     270       97  

Purchase of short-term investments

     (30 )     (173 )

Restricted cash

     30       (15 )

Turbine deposits

     (241 )     (17 )

Customer advances for construction and other investments

     8       54  

Net cash used by investing activities

     (1,357 )     (1,305 )

Net decrease in cash and equivalents

     (576 )     (35 )

Cash and equivalents, beginning of period

     1,795       1,893  

Cash and equivalents, end of period

   $   1,219     $   1,858  

 

 

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

 

6


EDISON INTERNATIONAL

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Management’s Statement

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, 2007 are not necessarily indicative of the operating results for the full year.

This quarterly report should be read in conjunction with Edison International’s Annual Report to Shareholders incorporated by reference into Edison International’s Annual Report on Form 10-K for the year ended December 31, 2006 filed with the Securities and Exchange Commission.

Note 1. Summary of Significant Accounting Policies

Basis of Presentation

Edison International’s significant accounting policies were described in Note 1 of “Notes to Consolidated Financial Statements” included in its 2006 Annual Report on Form 10-K. Edison International follows the same accounting policies for interim reporting purposes, with the exception of the change in accounting for uncertain tax positions (discussed below in “New Accounting Pronouncements”).

On April 1, 2006, EME received, as a capital contribution from its affiliate, Edison Capital, ownership interests in a portfolio of wind projects located in Iowa and Minnesota and a small biomass project. EME accounted for this acquisition at Edison Capital’s historical cost as a transaction between entities under common control. As a result of this capital contribution, Edison International’s nonutility power generation segment now includes the wind assets and biomass power project previously owned by Edison Capital and included in the financial services segment.

Certain prior-period amounts were reclassified to conform to the June 30, 2007 financial statement presentation. Except as indicated, amounts presented in the Notes to the Consolidated Financial Statements relate to continuing operations.

Earnings Per Common Share (EPS)

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 participating securities are stock based compensation awards payable in common shares, including stock options, performance shares and restricted stock units, that 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. As a result of meeting a performance trigger, the options granted in 1998 and 1999 began earning dividend equivalents in 2006.

Basic EPS is computed by dividing net income allocated for common stock by the weighted-average number of common shares outstanding. Net income allocated for common stock was $93 million and $175 million for the three months ended June 30, 2007 and 2006, respectively, and was $421 million and $431 million for the six months ended June 30, 2007, and 2006, respectively. In determining net income allocated for common stock, dividends on preferred and preference stock of utility have been deducted.

For the diluted EPS calculation, dilutive securities (stock-based compensation awards) are added to the weighted-average shares and net income is adjusted for dividend equivalents on dilutive securities. Stock options with exercise prices greater than or equal to the market price are not included in the dilutive securities calculation. Dilutive securities are excluded from the diluted EPS calculation for items with a net loss due to their antidilutive effect.

 

7


EDISON INTERNATIONAL

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

 

Income Taxes

Edison International’s eligible subsidiaries are included in Edison International’s consolidated federal income tax and combined state tax returns. Edison International has tax-allocation and payment agreements with certain of its subsidiaries. For subsidiaries other than SCE, the right of a participating subsidiary to receive or make a payment and the amount and timing of tax-allocation payments are dependent on the inclusion of the subsidiary in the consolidated income tax returns of Edison International and other factors including the consolidated taxable income of Edison International and its includible subsidiaries, the amount of taxable income or net operating losses and other tax items of the participating subsidiary, as well as the other subsidiaries of Edison International. There are specific procedures regarding allocations of state taxes. Each subsidiary is eligible to receive tax-allocation payments for its tax losses or credits only at such time as Edison International and its subsidiaries generate sufficient taxable income to be able to utilize the participating subsidiary’s losses in the consolidated tax return of Edison International. Under an income tax-allocation agreement approved by the CPUC, SCE’s tax liability is computed as if it filed a separate return.

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

Income tax expense includes the current tax liability from operations and the change in deferred income taxes during the year. Investment tax credits are deferred and amortized over the lives of the related properties. Interest expense and penalties associated with income taxes are reflected in the caption “Income tax expense” on the consolidated statements of income.

For a further discussion of income taxes, see Note 4.

New Accounting Pronouncements

Accounting Pronouncement Adopted

In July 2006, the FASB issued FIN 48 which clarifies the accounting for uncertain tax positions. FIN 48 requires an enterprise to recognize, in its financial statements, the best estimate of the impact of a tax position by determining if the weight of the available evidence indicates it is more likely than not, based solely on the technical merits, that the position will be sustained on audit. Edison International adopted FIN 48 effective January 1, 2007. Implementation of FIN 48 resulted in a cumulative-effect adjustment that increased retained earnings by $250 million upon adoption. Edison International will continue to monitor and assess new income tax developments including the IRS’ challenge of the sale/leaseback and lease/leaseback transactions discussed in “Other Developments—Federal and State Income Taxes.”

In July 2006, the FASB issued an FSP on accounting for a change in timing of cash flows related to income taxes generated by a leverage lease transaction (FSP FAS 13-2). Edison International adopted FSP FAS 13-2 effective January 1, 2007. The adoption did not have a material impact on Edison International’s consolidated financial statements.

Accounting Pronouncements Not Yet Adopted

In April 2007, the FASB issued FIN 39-1. FIN 39-1 amends paragraph 3 of FIN No. 39 to replace the terms conditional contracts and exchange contracts with the term derivative instruments as defined in SFAS No. 133.

 

8


EDISON INTERNATIONAL

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

 

FIN 39-1 also states that under master netting arrangements if collateral is based on fair value, then it must be netted with the fair value of derivative assets/liabilities if an entity qualified and elected the option to net those amounts. Edison International will adopt FIN 39-1 on January 1, 2008. Adoption of this position will result in netting a portion of margin and cash collateral deposits with derivative liabilities on Edison International’s consolidated balance sheets, but will have no impact on Edison International’s consolidated statements of income.

In February 2007, the FASB issued SFAS No. 159, which provides an option to report eligible financial assets and liabilities at fair value, with changes in fair value recognized in earnings. Upon adoption, the first remeasurement to fair value would be reported as a cumulative-effect adjustment to the opening balance of retained earnings. Edison International will adopt SFAS No. 159 on January 1, 2008. Edison International is currently evaluating whether it will opt to report any financial assets and liabilities at fair value and the impact, if adopted, on its consolidated financial statements.

In September 2006, the FASB issued SFAS No. 157, which clarifies the definition of fair value, establishes a framework for measuring fair value and expands the disclosures on fair value measurements. Edison International will adopt SFAS No. 157 on January 1, 2008. Edison International is currently evaluating the impact of adopting SFAS No. 157 on its financial statements.

Sales and Use Taxes

SCE bills certain sales and use taxes levied by state or local governments to its customers. Included in these sales and use taxes are franchise fees, which SCE pays to various municipalities (based on contracts with these municipalities) in order to operate within the limits of the municipality. SCE bills these franchise fees to its customers based on a CPUC-authorized rate. These franchise fees, which are required to be paid regardless of SCE’s ability to collect from the customer, are accounted for on a gross basis and reflected in electric utility revenue and other operation and maintenance expense. SCE’s franchise fees billed to customers and recorded as electric utility revenue were $24 million and $27 million for the three months ended June 30, 2007 and 2006, respectively, and $47 million for both periods ended June 30, 2007 and 2006. When SCE acts as an agent, and the tax is not required to be remitted if it is not collected from the customer, the taxes are accounted for on a net basis. Amounts billed to and collected from customers for these taxes are being remitted to the taxing authorities and are not recognized as revenue.

Short-term Investments

Edison International’s short-term investments are held by EME. At June 30, 2007 and December 31, 2006, EME had classified all marketable debt securities as held-to-maturity and carried at amortized cost plus accrued interest which approximated their fair value. Gross unrealized holding gains and losses were not material.

EME’s held-to-maturity securities, which all mature within one year, consisted of the following:

 

In millions   

June 30,

2007

  

December 31,

2006

     (Unaudited)     

Commercial paper

   $   269    $   417

Certificates of deposit

     47      141

Corporate bonds

     1     

Total

   $ 317    $ 558

 

9


EDISON INTERNATIONAL

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

 

Stock-Based Compensation

Stock options, performance shares, deferred stock units and, beginning in 2007, restricted stock units have been granted under Edison International’s long-term incentive compensation programs. Edison International usually does not issue new common stock for equity awards settled. Rather, a third party is used to facilitate the exercise of stock options and the purchase and delivery of outstanding common stock for settlement of option exercises, performance shares, and restricted stock units. Performance shares earned are settled half in cash and half in common stock; however, Edison International has discretion under certain of the awards to pay the half subject to cash settlement in common stock. Deferred stock units granted to management are settled in cash, not stock and represent a liability.

On April 26, 2007, Edison International’s shareholders approved a new incentive plan (the 2007 Performance Incentive Plan) that includes stock-based compensation. No additional awards will be granted under Edison International’s prior stock-based compensation plans on or after April 26, 2007, and all future issuances will be made under the new plan. The maximum number of shares of Edison International’s common stock that may be issued or transferred pursuant to awards under the new incentive plan is 8.5 million shares, plus the number of any shares subject to awards issued under Edison International’s prior plans and outstanding as of April 26, 2007, which expire, cancel or terminate without being exercised or shares being issued. As of June 30, 2007, Edison International has approximately 8.4 million shares remaining for future issuance under its stock-based compensation plan. For further discussion see “Stock-Based Compensation” in Note 5.

Note 2. Derivative Instruments and Hedging Activities

SCE is exposed to commodity price risk associated with its purchases for additional capacity and ancillary services to meet its peak energy requirements as well as exposure to natural gas prices associated with power purchased from QFs, fuel tolling arrangements, and its own gas-fired generation, including the Mountainview plant. SCE’s realized and unrealized gains and losses arising from derivative instruments are reflected in purchased-power expense and offset through the provision for regulatory adjustment clauses – net on the consolidated statements of income and thus do not affect earnings, but may temporarily affect cash flows. The following is a summary of purchased-power expense:

 

      Three Months Ended
June 30,
    Six Months Ended
June 30,
 
In millions        2007             2006             2007             2006      

Purchased-power from bilateral contracts, QFs, ISO, and exchange energy

   $   787     $   706     $   1,237     $   1,321  

Unrealized (gains)/losses on economic hedging activities

     45       9       (89 )     342  

Realized (gains)/losses on economic hedging activities

     23       91       52       166  

Energy settlements and refunds

     (26 )     (37 )     (54 )     (46 )

Total purchased-power expense

   $ 829     $ 769     $ 1,146     $ 1,783  

The increase for the three months ended June 30, 2007 in net unrealized losses on economic hedging activities was primarily due to lower forward natural gas prices in the second quarter of 2007, compared to the same period in 2006. The increase for the six months ended June 30, 2007 in net unrealized gains on economic hedging activities was primarily a result of changes in SCE’s gas hedge portfolio mix.

 

10


EDISON INTERNATIONAL

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

 

Note 3. Liabilities and Lines of Credit

Long-term Debt

As of June 30, 2007, Edison International’s long-term debt maturities and sinking fund requirements for the next five years are: 2007 – $306 million; 2008 – $33 million; 2009 – $175 million; 2010 – $314 million;

2011 – $13 million. As discussed below, these amounts have been updated primarily to reflect EME’s financing activities completed during the second quarter of 2007.

Senior Notes Offering

On May 7, 2007, EME completed a private offering of $1.2 billion of its 7.00% senior notes due 2017, $800 million of its 7.20% senior notes due 2019 and $700 million of its 7.625% senior notes due 2027. EME will pay interest on the senior notes on May 15 and November 15 of each year, beginning on November 15, 2007.

The senior notes are EME’s senior unsecured obligations, ranking equal in right of payment to all EME’s existing and future senior unsecured indebtedness, and will be senior to all EME’s future subordinated indebtedness. EME’s secured debt and its other secured obligations are effectively senior to the senior notes to the extent of the value of the assets securing such debt or other obligations. None of EME’s subsidiaries have guaranteed the senior notes and, as a result, all of the existing and future liabilities of EME’s subsidiaries are effectively senior to the senior notes.

EME used the net proceeds of the offering of the senior notes, together with cash on hand, to purchase approximately $587 million of EME’s outstanding 7.73% senior notes due 2009, to purchase approximately $1 billion of Midwest Generation’s 8.75% second priority senior secured notes due 2034, to repay the outstanding amount (approximately $328 million) of Midwest Generation’s senior secured term loan facility, and to make a dividend payment of $899 million to MEHC which enabled MEHC to purchase approximately $796 million of its 13.5% senior secured notes due 2008. The net proceeds of the offering of the senior notes, together with cash on hand, were also used to pay related tender premiums, consent fees, and accrued interest. Edison International recorded a total pre-tax loss of $241 million ($148 million after tax) on early extinguishment of debt during the second quarter of 2007.

Redemption of MEHC Senior Secured Notes

On June 25, 2007, MEHC redeemed in full its senior secured notes. As a result of the redemption, EME is no longer subject to financial and investment restrictions that were contained in the indenture pursuant to which the senior secured notes were issued. Following the redemption, MEHC no longer files reports with the U.S. Securities and Exchange Commission.

Credit Agreement Amendments

On May 7, 2007, EME amended its existing $500 million secured credit facility, increasing the total borrowings available thereunder to $600 million.

On June 29, 2007, Midwest Generation completed a refinancing of indebtedness by amending and restating its existing credit facility. The refinancing provided, among other things, for: (a) the option to extend the maturity of the working capital facility by up to two years, subject to the satisfaction of enumerated conditions, (b) the option to grant first or second priority liens to eligible hedge counterparties, (c) the release of collateral in the event that the unsecured debt of Midwest Generation is rated investment grade, (d) a reduction in the interest rate applicable to the working capital facility, and (e) a modification of covenants, including the incurrence of indebtedness covenant and the financial covenants. The refinancing also eliminates the term loan facility.

 

11


EDISON INTERNATIONAL

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

 

After giving effect to the refinancing, the working capital facility interest rate was lowered to LIBOR + 0.55% from LIBOR + 1.50%. The working capital facility matures in 2012, with an option to extend for up to two years. Also, as part of the refinancing, Midwest Generation’s financial covenants were modified, with its debt to capitalization ratio to be no greater than 0.60 to 1.

Midwest Generation intends to use its secured working capital facility to provide credit support for its hedging activities and for general working capital purposes. Midwest Generation may also support its hedging activities by granting first or second priority liens to eligible hedge counterparties. As of June 30, 2007, approximately $33 million had been utilized under the working capital facility.

Short-term Debt

All short-term debt is held by SCE. SCE’s short-term debt is generally used to finance fuel inventories, balancing account undercollections and general, temporary cash requirements. At June 30, 2007, the outstanding short-term debt and weighted-average interest rate was $175 million at 5.56%. SCE’s short-term debt is supported by a $2.5 billion credit line of which $2.1 billion was available as of June 30, 2007.

Note 4. Income Taxes

Edison International’s composite federal and state statutory income tax rate was approximately 40% (net of the federal benefit for state income taxes) for all periods presented. Edison International’s effective tax rate from continuing operations was 0% and 23% for the three- and six-month periods ended June 30, 2007, respectively, as compared to 35% and 37% for the respective periods in 2006. The decreased effective tax rate was primarily caused by reductions made to the income tax reserve at SCE during the first quarter of 2007 to reflect progress in an administrative appeal process with the IRS related to the income tax treatment of costs associated with environmental remediation and also due to a $15 million reduction made to the income tax reserves during the second quarter of 2007 to reflect settlement of a state tax issue related to the April 2007 State Notice of Proposed Adjustment discussed below. Additional decreases to the 2007 effective tax rate resulted from accruing lower tax reserve interest expense at SCE in 2007, as compared to 2006, as a result of implementing FIN 48 and from year over year changes in property related flow-through items at SCE. In addition, the decreased effective tax rate in the second quarter of 2007 resulted from a reduction in pre-tax income.

The net liability recorded for uncertain tax positions was $231 million and $223 million as of June 30, 2007 and the date of adoption (January 1, 2007) of FIN 48, respectively. The net liability as of June 30, 2007 and the date of adoption consists of $482 million and $490 million, respectively, of unrecognized tax benefits, partially offset by $251 million and $267 million, respectively, of recognized tax benefits representing the expected settlement outcome of affirmative claims made or expected to be made that meet the recognition requirement pursuant to FIN 48. The change in the unrecognized tax benefits from the date of adoption reflects decreases of $14 million from positions taken in taken in 2007 partially offset by increases of $3 million related to settling an affirmative claim with a taxing authority and $3 million from positions taken in prior periods. The total amount of unrecognized tax benefits as of June 30, 2007 and the date of adoption that, if recognized, would affect the effective tax rate was $206 million and $172 million, respectively.

The unrecognized tax benefits, as of June 30, 2007 and the date of adoption, do not reflect affirmative claims of $1.6 billion and $1.7 billion, respectively. These claims consist of $64 million and $71 million representing the difference between the amount filed on amended tax returns and the amount recognized pursuant to FIN 48 and $1.5 billion and $1.6 billion of claims which have been filed on amended tax returns but have not met the recognition requirement pursuant to FIN 48, the majority of which have been denied as part of an IRS

 

12


EDISON INTERNATIONAL

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

 

examination. These affirmative claims remain unpaid by the IRS and no receivable has been accrued. Edison International is vigorously defending these affirmative positions in IRS administrative appeals.

The total amount of accrued interest and penalties was $145 million and $119 million as of June 30, 2007 and the date of adoption, respectively. The total amount of interest expense and penalties recognized in income tax expense for the three-months ended June 30, 2007 was $5 million. The total benefit recognized in income tax expense for the six months ended June 30, 2007 was $29 million.

Edison International remains subject to examination and administrative appeals by the IRS from 1994 – present. In addition, the statute of limitations remains open from 1986 – 1993 for certain affirmative claims. In July 2007, Edison International received a Notice of Proposed Adjustment from the IRS accepting an affirmative claim position involving the taxability of balancing account over-collections. This issue was addressed as part of the ongoing IRS examinations and administrative appeals process. The tax years affected by this Notice of Proposed Adjustment remain subject to examination and administrative appeals. The cash and earnings impacts of this position are dependent on the ultimate settlement of all issues in these tax years. Edison International expects earnings and cash flows to increase within the range of $65 million to $75 million and $275 million to $300 million, respectively.

In April 2007, Edison International received a Notice of Proposed Adjustment from the California Franchise Tax Board for tax years 2001 and 2002. In June 2007, Edison International filed its protest to deficiencies asserted in the April 2007 Notice of Proposed Adjustment. Edison International remains subject to examination by the California Franchise Tax Board for tax years from 2003 – present. Edison International is also subject to examination by select state tax authorities, with varying statute of limitations. Some state jurisdictions follow the federal statute for comparable issues.

Edison International continues its efforts to resolve open tax issues with the IRS and State authorities. The timing for resolving these open tax positions is subject to uncertainty, but it is reasonably possible that some portion of these open tax positions could be resolved in the next 12 months.

As a matter of course, Edison International is regularly audited by federal, state and foreign taxing authorities. For further discussion of this matter, see “Federal and State Income Taxes” in Note 6.

Note 5. Compensation and Benefits Plans

Pension Plans

Edison International previously disclosed in Note 5 of “Notes to Consolidated Financial Statements” included in its 2006 Annual Report on Form 10-K that it expects to contribute approximately $66 million to its pension plans in 2007. As of June 30, 2007, Edison International had made $50 million in contributions related to 2006 and $16 million related to 2007 and estimates to make $37 million of additional contributions in the last six months of 2007. Expected contribution funding in 2007 could vary from anticipated amounts, depending on the funded status at year-end and tax-deductible funding limitations.

Net pension cost recognized is calculated under the actuarial method used for ratemaking. The difference between pension costs calculated for accounting and ratemaking is deferred.

 

13


EDISON INTERNATIONAL

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

 

Expense components are:

 

      Three Months Ended
June 30,
   

Six Months Ended

June 30,

 
In millions        2007             2006             2007             2006      
     (Unaudited)  

Service cost

   $ 31     $ 30     $ 62     $ 60  

Interest cost

     47       45       94       91  

Expected return on plan assets

       (63 )       (59 )       (126 )       (117 )

Special termination benefits

           4             4  

Amortization of prior service cost

     4       4       8       8  

Amortization of net loss

     1       2       2       3  

Subtotal

     20       26       40       49  

Regulatory adjustment—deferred

     1       (1 )     2       (3 )

Total expense recognized

   $ 21     $ 25     $ 42     $ 46  

Postretirement Benefits Other Than Pensions

Edison International previously disclosed in Note 5 of “Notes to Consolidated Financial Statements” included in its 2006 Annual Report on Form 10-K that it expects to contribute approximately $42 million to its postretirement benefits other than pension plans in 2007. As of June 30, 2007, Edison International had made no contributions related to 2006 and $11 million related to 2007 and estimates to make $31 million of additional contributions in the last six months of 2007. Expected contribution funding in 2007 could vary from anticipated amounts, depending on the funded status at year-end and tax-deductible funding limitations.

Expense components are:

 

      Three Months Ended
June 30,
    Six Months Ended
June 30,
 
In millions        2007             2006             2007             2006      
     (Unaudited)  

Service cost

   $ 11     $ 13     $ 23     $ 25  

Interest cost

     32       32       64       64  

Expected return on plan assets

       (30 )       (27 )       (60 )       (54 )

Special termination benefits

           3             3  

Amortization of prior service credit

     (8 )     (8 )     (16 )     (16 )

Amortization of net loss

     7       12       13       24  

Total expense recognized

   $ 12     $ 25     $ 24     $ 46  

Stock-Based Compensation

Total stock-based compensation expense (reflected in the caption “Other operation and maintenance” on the consolidated statements of income) was $22 million and $13 million for the three months ended June 30, 2007 and 2006, respectively, and was $29 million and $23 million for the six months ended June 30, 2007 and 2006, respectively. The income tax benefit recognized in the consolidated statements of income was $9 million and $5 million for the three months ended June 30, 2007 and 2006, respectively, and was $12 million and $9 million for the six months ended June 30, 2007 and 2006, respectively. Total stock-based compensation cost capitalized was $2 million and $1 million for the three months ended June 30, 2007 and 2006, respectively, and was $3 million and $2 million for the six months ended June 20, 2007 and 2006, respectively.

 

14


EDISON INTERNATIONAL

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

 

Stock Options

A summary of the status of Edison International stock options is as follows:

 

           Weighted-Average     
      Stock
Options
    Exercise
Price
   Remaining
Contractual
Term (Years)
   Aggregate
Intrinsic
Value

Outstanding at December 31, 2006

   14,111,697     $   26.33      

Granted

   1,780,126     $   47.64      

Forfeited

   (46,840 )   $   40.46      

Exercised

   (3,196,963 )   $   22.61      

Outstanding at June 30, 2007

   12,648,020     $   30.21    6.81   

Vested and expected to vest at June 30, 2007

   12,144,037     $   29.85    6.75    $   292,883,812

Exercisable at June 30, 2007

   6,892,004     $   23.64    5.66    $   209,017,251

Stock options granted in 2007 do not accrue dividend equivalents except for options granted to Edison International’s Board of Directors.

The amount of cash used to settle stock options exercised was $77 million and $24 million for the three months ended June 30, 2007 and 2006, respectively, and was $163 million and $68 million for the six months ended June 30, 2007 and 2006, respectively. Cash received from options exercised was $33 million and $13 million for the three months ended June 30, 2007 and 2006, respectively, and was $72 million and $33 million for the six months ended June 30, 2007 and 2006, respectively. The estimated tax benefit from options exercised was $18 million and $4 million for the three months ended June 30, 2007 and 2006, respectively, and was $36 million and $14 million for the six months ended June 30, 2007 and 2006, respectively.

Note 6. Commitments and Contingencies

The following is an update to Edison International’s commitments. See Note 6 of “Notes to Consolidated Financial Statements” included in Edison International’s 2006 Annual Report for a detailed discussion.

Lease Commitments

SCE entered into a new operating lease for a power contract during the first six months of 2007. SCE’s additional operating lease commitments for this new power contract are estimated to be $68 million for 2008 and $114 million for each of the years 2009, 2010, and 2011.

SCE executed a power purchase contract in June 2007 which met the requirements for capital leases. As of June 30, 2007, the capital lease requires future minimum lease payments of $28 million (approximately $1 million per year) through May 2027. As of June 30, 2007, the executory costs and imputed interest for this capital lease are $11 million and $7 million, respectively.

Other Commitments

Midwest Generation and EME Homer City have entered into additional fuel purchase commitments during the first six months of 2007. These additional commitments are currently estimated to be $6 million for the remainder of 2007, $208 million in 2008, $153 million in 2009, and $77 million in 2010.

 

15


EDISON INTERNATIONAL

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

 

SCE entered into service contracts associated with uranium enrichment and fuel fabrication during the first three months of 2007. SCE’s fuel supply commitments for the remainder of 2007 are estimated to be $143 million.

Midwest Generation has contractual agreements for the transport of coal to its facilities. The primary contract is with Union Pacific Railroad (and various delivering carriers) which extends through 2011. Midwest Generation’s commitments under this contract are based on actual coal purchases from the PRB. Accordingly, contractual obligations for transportation are based on coal volumes set forth in fuel supply contracts. The increase in transportation commitments entered into during the first six months of 2007 relates to additional volumes of fuel purchases using the terms of existing transportation agreements. These commitments are currently estimated to be $8 million for the remainder of 2007, $110 million for 2008, $75 million for 2009, and $77 million for 2010.

At June 30, 2007, EME’s subsidiaries had firm commitments to spend approximately $229 million during the remainder of 2007 and $24 million in 2008 on capital and construction expenditures. The majority of these expenditures relate to the construction of wind projects. Also included are expenditures for dust collection and mitigation system and environmental improvements. These expenditures are planned to be financed by cash on hand, cash generated from operations or existing subsidiary credit agreements.

At June 30, 2007, EME had entered into agreements with vendors securing 669 wind turbines (1,414 MW) with remaining commitments of $382 million in 2007, $534 million in 2008, and $426 million in 2009. At June 30, 2007, EME had recorded wind turbine deposits of $262 million included in other long-term assets in Edison International’s consolidated balance sheet. In addition, EME had entered into an agreement to purchase five gas turbines and related equipment for an aggregate purchase price of approximately $145 million. In June 2007, EME entered into a change order agreement with the seller of the turbines reducing the number of gas turbines to four with a remaining commitment of $26 million at June 30, 2007. In addition, EME recorded $21 million, included in other current assets in Edison International’s consolidated balance sheet, with respect to a refund of the turbine payments. Subsequent to June 30, 2007, EME entered into additional change order agreements reducing the number of gas turbines to one. EME expects to receive refunds totaling $92 million during the third quarter of 2007 with respect to the four turbines.

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 included performance guarantees, guarantees of debt and indemnifications.

Tax Indemnity Agreements

In connection with the sale-leaseback transactions that EME has entered into related to the Powerton and Joliet Stations in Illinois, the Collins Station in Illinois, and the Homer City facilities in Pennsylvania, EME and several of its subsidiaries entered into tax indemnity agreements. Under these tax indemnity agreements, these entities agreed to indemnify the lessors in the sale-leaseback transactions for specified adverse tax consequences that could result in certain situations set forth in each tax indemnity agreement, including specified defaults under the respective leases. The potential indemnity obligations under these tax indemnity agreements could be significant. Due to the nature of these potential obligations, EME cannot determine a maximum potential liability which would be triggered by a valid claim from the lessors. EME has not recorded a liability related to these indemnities. In connection with the termination of the Collins Station lease in April 2004, Midwest Generation will continue to have obligations under the tax indemnity agreement with the former lease equity investor.

 

16


EDISON INTERNATIONAL

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

 

Indemnities Provided as Part of the Acquisition of the Illinois Plants

In connection with the acquisition of the Illinois Plants, EME agreed to indemnify Commonwealth Edison with respect to specified environmental liabilities before and after December 15, 1999, the date of sale. The indemnification claims are reduced by any insurance proceeds and tax benefits related to such claims and are subject to a requirement that Commonwealth Edison takes all reasonable steps to mitigate losses related to any such indemnification claim. Due to the nature of the obligation under this indemnity, a maximum potential liability cannot be determined. This indemnification for environmental liabilities is not limited in term and would be triggered by a valid claim from Commonwealth Edison. Except as discussed below, EME has not recorded a liability related to this indemnity.

Midwest Generation entered into a supplemental agreement with Commonwealth Edison and Exelon Generation on February 20, 2003 to resolve a dispute regarding interpretation of its reimbursement obligation for asbestos claims under the environmental indemnities set forth in the Asset Sale Agreement. Under this supplemental agreement, Midwest Generation agreed to reimburse Commonwealth Edison and Exelon Generation for 50% of specific 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 has a five-year term with an automatic renewal provision (subject to the right of either party to terminate). Payments are made under this indemnity upon tender by Commonwealth Edison of appropriate proof of liability for an asbestos-related settlement, judgment, verdict, or expense. There were approximately 179 cases for which Midwest Generation was potentially liable and that had not been settled and dismissed at June 30, 2007. Midwest Generation had recorded a $64 million liability at June 30, 2007 related to this matter.

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

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

In connection with the acquisition of the Homer City facilities, EME Homer City agreed to indemnify the sellers with respect to specific environmental liabilities before and after the date of sale. Payments would be triggered under this indemnity by a claim from the sellers. EME guaranteed the obligations of EME Homer City. Due to the nature of the obligation under this indemnity provision, it is not subject to a maximum potential liability and does not have an expiration date. EME has not recorded a liability related to this indemnity.

Indemnities Provided under Asset Sale Agreements

The asset sale agreements for the sale of EME’s international assets contain indemnities from EME to the purchasers, including indemnification for taxes imposed with respect to operations of the assets prior to the sale and for pre-closing environmental liabilities. Not all indemnities under the asset sale agreements have specific expiration dates. Payments would be triggered under these indemnities by valid claims from the sellers or purchasers, as the case may be. At June 30, 2007, EME had recorded a liability of $94 million related to these matters.

 

17


EDISON INTERNATIONAL

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

 

In connection with the sale of various domestic assets, EME has from time to time provided indemnities to the purchasers for taxes imposed with respect to operations of the asset prior to the sale. EME has also provided indemnities to purchasers for items specified in each agreement (for example, specific pre-existing litigation matters and/or environmental conditions). Due to the nature of the obligations under these indemnity agreements, a maximum potential liability cannot be determined. Not all indemnities under the asset sale agreements have specific expiration dates. Payments would be triggered under these indemnities by valid claims from the sellers or purchasers, as the case may be. EME has not recorded a liability related to these indemnities.

Capacity Indemnification Agreements

EME has guaranteed, jointly and severally with Texaco Inc., the obligations of March Point Cogeneration Company under its project power sales agreements to repay capacity payments to the project’s power purchaser in the event that the power sales agreements terminate, March Point Cogeneration Company abandons the project, or the project fails to return to normal operations within a reasonable time after a complete or partial shutdown, during the term of the power sales agreements. In addition, a subsidiary of EME has guaranteed the obligations of Sycamore Cogeneration Company under its project power sales agreement to repay capacity payments to the project’s power purchaser in the event that the project unilaterally terminates its performance or reduces its electric power producing capability during the term of the power sales agreement. The obligations under the indemnification agreements as of June 30, 2007, if payment were required, would be $89 million. EME has not recorded a liability related to these indemnities.

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.

Other Edison International Indemnities

Edison International 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.

Edison International’s obligations under these agreements may be limited in terms of time and/or amount, and in some instances Edison International 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. Edison International 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 the outcome of these other proceedings will not materially affect its results of operations or liquidity.

 

18


EDISON INTERNATIONAL

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

 

Challenges of Illinois Power Procurement Auction Results

EMMT participated successfully in the first Illinois power procurement auction, held in September 2006 according to rules approved by the Illinois Commerce Commission, and entered into two load requirements services contracts through which it is delivering electricity, capacity and specified ancillary, transmission and load following services necessary to serve a portion of Commonwealth Edison’s residential and small commercial customer load, using contracted supply from Midwest Generation.

EME believes that EMMT’s actions in regard to the Illinois auction were appropriate and lawful and intends to defend vigorously all of the matters described below. However, at this time EME cannot predict the outcome of these matters.

FERC Complaint

On March 16, 2007, the Office of the Attorney General for the State of Illinois filed a complaint at the FERC alleging that the prices resulting from the Illinois auction resulted in unjust and unreasonable rates under the Federal Power Act and that participating wholesale sellers in the Illinois auction had colluded and manipulated the results of the auction. All successful participants in the Illinois auction, including EMMT, were named as respondents. The Office of the Attorney General asked the FERC to order refunds and to revoke the respondents’ market-based rate pricing authority. On July 24, 2007, Midwest Generation and EMMT, along with other power generation companies and utilities, entered into a settlement with the Illinois Attorney General. The settlement is subject to enacting legislation. See Note 12 for further discussion.

Class Action Lawsuits

On April 4, 2007, EMMT was served with a complaint filed in the Circuit Court of Cook County, Illinois, by Saul R. Wexler, individually and on behalf of an alleged class of similarly situated electric ratepayers in Illinois, against Commonwealth Edison, Ameren, and all of the successful participants in the Illinois auction, including EMMT. The lawsuit alleges that the defendants, including EMMT, colluded and conspired to manipulate the auction results by price-fixing. The lawsuit seeks unspecified damages. On April 26, 2007, the defendants transferred the complaint to the U.S. District Court for the Northern District of Illinois, Eastern Division. On June 4, 2007, the defendants filed a motion to dismiss the case which remains pending.

On March 30, 2007, David Schafer, Tim Perry, Pat Martin and Michael Murray, individually and on behalf of an alleged class of similarly situated electric ratepayers in Illinois, filed a complaint in the Circuit Court of Cook County, Illinois, against Commonwealth Edison, Ameren, and all of the successful participants in the Illinois auction, including EMMT. EMMT has not been formally served in the case. The lawsuit alleges that the defendants, including EMMT, colluded and conspired to manipulate the auction results by price-fixing. The lawsuit seeks unspecified damages. On April 26, 2007, the defendants transferred the complaint to the U.S. District Court for the Northern District of Illinois, Eastern Division. On June 4, 2007, the defendants filed a motion to dismiss the case which remains pending.

Environmental Remediation

Edison International is subject to numerous environmental laws and regulations, which 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.

Edison International believes that it is in substantial compliance with environmental regulatory requirements; however, possible future developments, such as the enactment of more stringent environmental laws and

 

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regulations, could affect the costs and the manner in which business is conducted and could cause substantial additional capital expenditures. There is no assurance that additional costs would be recovered from customers or that Edison International’s financial position and results of operations would not be materially affected.

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 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 (classified as other long-term liabilities) at undiscounted amounts.

As of June 30, 2007, Edison International’s recorded estimated minimum liability to remediate its 37 identified sites at SCE (23 sites) and EME (14 sites related to Midwest Generation) was $77 million, $74 million of which 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 could exceed its recorded liability by up to $127 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 32 immaterial sites whose total liability ranges from $2 million (the recorded minimum liability) to $8 million.

The CPUC allows SCE to recover environmental remediation costs at certain sites, representing $29 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 $72 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.

Edison International 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 $11 million to $31 million. Recorded costs for the 12 months ended June 30, 2007 were $18 million.

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 or financial position. There can be no assurance,

 

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however, that future developments, including additional information about existing sites or the identification of new sites, will not require material revisions to such estimates.

Federal and State Income Taxes

Edison International received Revenue Agent Reports from the IRS in August 2002 and in January 2005 asserting deficiencies in federal corporate income taxes with respect to audits of its 1994 – 1996 and 1997 – 1999 tax years, respectively. Edison International expects to conclude the administrative phase of the audit of the 1994 – 1996 tax years by the end of 2007. Many of the asserted tax deficiencies are timing differences and, therefore, amounts ultimately paid (exclusive of penalties), if any, would be deductible on future tax returns of Edison International. Edison International has also submitted affirmative claims to the IRS and state tax agencies which are being addressed in administrative proceedings. Any benefits would be recorded at the earlier of when Edison International believes that the affirmative claim position has a more likely than not probability of being sustained or when a settlement is consummated. Certain affirmative claims have been recorded as part of the implementation of FIN 48.

As part of a nationwide challenge of certain types of lease transactions, the IRS has raised issues about the deferral of income taxes associated with Edison Capital’s cross-border, leveraged leases.

The IRS is challenging Edison Capital’s foreign power plant and electric locomotive sale/leaseback transactions entered into in 1993 and 1994 (Replacement Leases, which the IRS refers to as a sale-in/lease-out or SILO). The IRS is also challenging Edison Capital’s foreign power plant and electric transmission system lease/leaseback transactions entered into in 1997 and 1998 (Lease/Leaseback, which the IRS refers to as a lease-in/lease-out or LILO).

Edison Capital also entered into a lease/service contract transaction in 1999 involving a foreign telecommunication system (Service Contract, which the IRS also refers to as a SILO). The IRS has not yet asserted any adjustment for the Service Contract but Edison International has been responding to data requests from the IRS about the transaction as part of an IRS examination of tax years 2000 – 2002. The following table summarizes estimated federal and state income taxes deferred from these leases as of December 31, 2006. Repayment of these deferred taxes would be accelerated if the IRS prevails:

 

In millions   

Tax Years
Under Appeal

1994 – 1999

  

Tax Years

Under Audit

2000 – 2002

  

Unaudited
Tax Years

2003 – 2006

   Total

Replacement Leases (SILO)

   $ 44    $ 19    $ 23    $ 86

Lease/Leaseback (LILO)

     558      562      6      1,126

Service Contract (SILO)

          126      199      325
     $   602    $   707    $   228    $   1,537

As of June 30, 2007, the interest (after tax) on the proposed tax adjustments is estimated to be approximately $451 million. The IRS also seeks a 20% penalty on any sustained tax adjustment.

Edison International believes it properly reported these transactions based on applicable statutes, regulations and case law in effect at the time the transactions were entered into, and it is vigorously defending its tax treatment of these leases. Written protests were filed to appeal the audit adjustments for the tax years under appeal asserting that the IRS’s position misstates material facts, misapplies the law and is incorrect. This matter is now being considered by the Administrative Appeals branch of the IRS.

In addition, the payment of taxes, interest and penalties could have a significant impact on earnings and cash flow. In order to commence litigation in certain forums, Edison International must make payments of disputed

 

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taxes, along with interest and any penalties asserted by the IRS, and thereafter pursue refunds. On May 26, 2006, Edison International paid $111 million of the taxes, interest and penalties for tax year 1999 followed by a refund claim for the same amount. The cash payment was funded by Edison Capital and accounted for as a deposit which will be refunded with interest to the extent Edison International prevails. Since the IRS did not act on this refund claim within six months from the date the claim was filed, it is deemed denied. Edison International is prepared to take legal action to assert its refund claim if an acceptable settlement cannot be reached with the IRS.

A number of other cases involving these kinds of lease transactions are pending before various courts. The first case involving a LILO was recently decided against the taxpayer on summary judgment in the Federal District Court in North Carolina. That taxpayer has announced its intention to appeal that decision to the Fourth Circuit Court of Appeals.

Edison International expects to file a refund claim for any taxes, interest and penalties paid pursuant to the administrative appeals settlement of the 1994 – 1996 tax years related to assessed tax deficiencies and penalties assessed on the Replacement Leases. These payments would be treated as a deposit. Edison International may make additional payments related to other tax years to preserve its litigation rights, although, at this time, the amount and timing of these additional payments is uncertain. At this time, Edison International is unable to predict the impact of the ultimate resolution of these matters.

The IRS Revenue Agent Report for the 1997 – 1999 audit also asserted deficiencies with respect to a transaction entered into by an SCE subsidiary which may be considered substantially similar to a listed transaction described by the IRS as a contingent liability company. This matter is currently being considered by the Administrative Appeals branch of the IRS where Edison International is defending its tax return position with respect to this transaction.

In April 2004, Edison International filed California Franchise Tax amended returns for tax years 1997 – 2002 to mitigate the possible imposition of new California penalty provisions on transactions that may be considered as listed or substantially similar to listed transactions described in an IRS notice that was published in 2001. These transactions include certain Edison Capital leveraged lease transactions and the SCE subsidiary contingent liability company transaction described above. Edison International filed these amended returns under protest retaining its appeal rights.

In December 2006, Edison International reached a settlement with the California Franchise Tax Board regarding the sourcing of gross receipts from the sale of electric services for California state tax apportionment purposes for tax years 1981 to 2004. In the fourth quarter of 2006, Edison International recorded a $49 million benefit related to a tax reserve adjustment as a result of this settlement. In addition to this tax reserve adjustment, Edison International received a net cash refund of $52 million in April 2007 as a result of this same settlement.

FERC Notice Regarding Investigatory Proceeding against EMMT

At the end of October 2006, EMMT was advised by the enforcement staff at the FERC that it is prepared to recommend that the FERC initiate a formal investigatory proceeding and seek monetary sanctions against EMMT for alleged violation of the Energy Policy Act of 2005 and the FERC’s rules regarding market behavior, all with respect to certain bidding practices previously employed by EMMT. EMMT is engaged in discussions with the staff to explore the possibility of resolution of this matter. Should a formal proceeding be commenced, EMMT will be entitled to contest any alleged violations before the FERC and an appropriate court. EME believes that EMMT has complied with all applicable laws and regulations and intends to contest vigorously any allegation of violation. EME cannot predict at this time the outcome of this matter or estimate the possible liability should the outcome be adverse.

 

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FERC Refund Proceedings

SCE is participating in several related proceedings seeking recovery of refunds from sellers of electricity and natural gas who manipulated the electric and natural gas markets during the energy crisis in California in 2000 – 2001 or who benefited from the manipulation by receiving inflated market prices. SCE is required to refund to customers 90% of any refunds actually realized by SCE, net of litigation costs, and 10% will be retained by SCE as a shareholder incentive.

During the course of the refund proceedings, the FERC ruled that governmental power sellers, like private generators and marketers that sold into the California market, should refund the excessive prices they received during the crisis period. However, on September 21, 2005, the Ninth Circuit ruled in Bonneville v. FERC that the FERC does not have authority directly to enforce its refund orders against governmental power sellers. The Court, however, clarified that its decision does not preclude SCE or other parties from pursuing civil claims against the governmental power sellers. On March 16, 2006, SCE, PG&E and the California Electricity Oversight Board jointly filed suit in federal court against several governmental power sellers, seeking damages based on the reduced prices set by the FERC for transactions during the crisis period. In March 2007, the federal court dismissed this suit concluding that the claims should have been filed in state court. SCE, along with PG&E, the Oversight Board and SDG&E, refiled on April 29, 2007 in the Los Angeles Superior Court. In addition, on March 12, 2007, SCE, PG&E and the Oversight Board filed a similar group of claims in the U.S. Court of Federal Claims against two federal agencies that sold power into California during the energy crisis. SCE cannot predict whether it may be able to recover any additional refunds from governmental power sellers as a result of these suits.

On April 2, 2007, SCE, PG&E, SDG&E, the Oversight Board, the CPUC, and the California Attorney General (the California Parties), in anticipation of the Ninth Circuit remand of its rulings in Bonneville to the FERC for further action, filed pleadings at the FERC requesting that it order the California ISO and the PX to complete their calculations of refunds owed to purchasers by all sellers, including governmental sellers. On April 5, 2007, the Ninth Circuit issued the remand of Bonneville to the FERC. On April 17 and 18, 2007, several governmental power sellers filed pleadings at the FERC opposing the California Parties’ request and contending that Bonneville required FERC to order the California ISO and PX to immediately return collateral previously deposited by governmental sellers and pay receivables that governmental sellers claim are owed to them. This matter remains pending at the FERC.

In November 2005, SCE and other parties entered into a settlement agreement with Enron Corporation and a number of its affiliates, most of which are debtors in Chapter 11 bankruptcy proceedings pending in New York. In 2006, SCE received distributions of approximately $55 million on its allowed bankruptcy claim. In April 2007, SCE received and recorded an additional distribution on its allowed bankruptcy claim of approximately $12 million and 55,465 shares of Portland General Electric Company stock, with an aggregate value of less than $2 million. Additional distributions are expected but SCE cannot currently predict the amount or timing of such distributions.

On August 2, 2006, the Ninth Circuit issued an opinion regarding the scope of refunds issued by the FERC. The Ninth Circuit broadened the time period during which refunds could be ordered to include the summer of 2000 based on evidence of pervasive tariff violations and broadened the categories of transactions that could be subject to refund. As a result of this decision, SCE may be able to recover additional refunds from sellers of electricity during the crisis with whom settlements have not been reached.

 

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

 

Investigations Regarding Performance Incentives Rewards

SCE was eligible under its CPUC-approved PBR mechanism to earn rewards or penalties based on its performance in comparison to CPUC-approved standards of customer satisfaction, employee injury and illness reporting, and system reliability.

SCE conducted investigations into its performance under these PBR mechanisms and has reported to the CPUC certain findings of misconduct and misreporting as further discussed below.

Customer Satisfaction

SCE received two letters in 2003 from one or more anonymous employees alleging that personnel in the service planning group of SCE’s transmission and distribution business unit altered or omitted data in attempts to influence the outcome of customer satisfaction surveys conducted by an independent survey organization. The results of these surveys are used, along with other factors, to determine the amounts of any incentive rewards or penalties for customer satisfaction. SCE recorded aggregate customer satisfaction rewards of $28 million over the period 1997 – 2000. Potential customer satisfaction rewards aggregating $10 million for the years 2001 and 2002 are pending before the CPUC and have not been recognized in income by SCE. SCE also anticipated that it could be eligible for customer satisfaction rewards of approximately $10 million for 2003.

Following its internal investigation, SCE proposed to refund to ratepayers $7 million of the PBR rewards previously received and forgo an additional $5 million of the PBR rewards pending that are both attributable to the design organization’s portion of the customer satisfaction rewards for the entire PBR period (1997 – 2003). In addition, SCE also proposed to refund all of the approximately $2 million of customer satisfaction rewards associated with meter reading.

SCE has taken remedial action as to the customer satisfaction survey misconduct by disciplining and/or terminating certain employees, including several supervisory personnel, updating system process and related documentation for survey reporting, and implementing additional supervisory controls over data collection and processing. Performance incentive rewards for customer satisfaction expired in 2003 pursuant to the 2003 GRC.

Employee Injury and Illness Reporting

In light of the problems uncovered with the customer satisfaction surveys, SCE conducted an investigation into the accuracy of SCE’s employee injury and illness reporting. The yearly results of employee injury and illness reporting to the CPUC are used to determine the amount of the incentive reward or penalty to SCE under the PBR mechanism. Since the inception of PBR in 1997, SCE has recognized $20 million in employee safety incentives for 1997 through 2000 and, based on SCE’s records, may be entitled to an additional $15 million for 2001 through 2003.

On October 21, 2004, SCE reported to the CPUC and other appropriate regulatory agencies certain findings concerning SCE’s performance under the PBR incentive mechanism for injury and illness reporting. SCE disclosed in the investigative findings to the CPUC that SCE failed to implement an effective recordkeeping system sufficient to capture all required data for first aid incidents.

As a result of these findings, SCE proposed to the CPUC that it not collect any reward under the mechanism and return to ratepayers the $20 million it had already received. SCE has also proposed to withdraw the pending rewards for the 2001 – 2003 time frames.

SCE has taken remedial action to address the issues identified, including revising its organizational structure and overall program for environmental, health and safety compliance, disciplining employees who committed wrongdoing and terminating one employee. SCE submitted a report on the results of its investigation to the CPUC on December 3, 2004.

 

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System Reliability

In light of the problems uncovered with the PBR mechanisms discussed above, SCE conducted an investigation into the third PBR metric, system reliability. On February 28, 2005, SCE provided its final investigatory report to the CPUC concluding that the reliability reporting system is working as intended.

CPUC Investigation

On June 15, 2006, the CPUC instituted a formal investigation to determine whether and in what amounts to order refunds or disallowances of past and potential PBR rewards for customer satisfaction, employee safety and system reliability portions of PBR. The CPUC also may consider whether to impose additional penalties on SCE.

In June 2006, the CPSD of the CPUC issued its report regarding SCE’s PBR program, recommending that the CPUC impose various refunds and penalties on SCE. Subsequently, in September 2006, the CPSD and other intervenors, such as the CPUC’s Division of Ratepayer Advocates and The Utility Reform Network, filed testimony on these matters recommending various refunds and penalties to be imposed upon SCE. On October 16, 2006, SCE filed testimony opposing the various refund and penalty recommendations of the CPSD and other intervenors. Based on SCE’s proposal for refunds and the combined recommendations of the CPSD and other intervenors, the potential refunds and penalties could range from $52 million up to $388 million. SCE has recorded an accrual at the lower end of this range of potential loss and is accruing interest on collected amounts that SCE has proposed to refund to customers. Evidentiary hearings which addressed the planning and meter reading components of customer satisfaction, safety, issues related to SCE’s administration of the survey, and statutory fines associated with those matters took place in the fourth quarter of 2006. System reliability issues and the remaining customer satisfaction components of the investigation will be addressed in a second phase of the proceeding, which will commence with the filing of SCE’s opening testimony in September 2007. A Presiding Officer’s Decision has not yet been received on the issues addressed during phase one and SCE cannot predict when such decision will be issued. At this time, SCE cannot predict the outcome of these matters or reasonably estimate the potential amount of any additional refunds, disallowances, or penalties that may be required above the lower end of the range.

ISO Disputed Charges

On April 20, 2004, the FERC issued an order concerning a dispute between the ISO and the Cities of Anaheim, Azusa, Banning, Colton and Riverside, California over the proper allocation and characterization of certain transmission service related charges. On March 29, 2007, the FERC issued an order agreeing with SCE’s position that the charges incurred by the ISO were related to voltage support and should be allocated to the scheduling coordinators, rather than to SCE as a transmission owner. The Cities filed a request for rehearing of the FERC’s order on April 27, 2007. On May 25, 2007, the FERC issued a procedural order granting the rehearing application for the purpose of allowing the FERC to give it further consideration. In a future order, FERC may deny the rehearing request or grant the requested relief in whole or in part. SCE believes that the most recent substantive FERC order correctly allocates responsibility for these ISO charges. However, SCE cannot provide assurance as to the final outcome of the rehearing. If a subsequent regulatory decision changes the allocation of responsibility for these charges, and SCE is required to pay these charges as a transmission owner, SCE may seek recovery in its reliability service rates. SCE cannot provide any assurance that recovery of these charges in its reliability service rates would be permitted.

Leveraged Lease Investments

Edison Capital has a net leveraged lease investment of $55 million, before deferred taxes, in three aircraft leased to American Airlines. Although American Airlines reported a profit in 2006, it reported net losses for a number

 

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

 

of years prior to 2006. A default in the leveraged lease by American Airlines could result in a loss of some or all of Edison Capital’s lease investment. At June 30, 2007, American Airlines was current in its lease payments to Edison Capital.

Edison Capital also has a net leveraged lease investment of $46 million, before deferred taxes, in a 1,500-MW natural gas-fired cogeneration plant leased to Midland Cogen. During 2005, Midland Cogen wrote down the book value of its power plant as a result of substantial increases in long-term natural gas prices. A default of the lease could result in a loss of some or all of Edison Capital’s lease investment. At June 30, 2007, Midland Cogen was current in its payments under the lease.

Midway-Sunset Cogeneration Company

San Joaquin Energy Company, a wholly owned subsidiary of EME, owns a 50% general partnership interest in Midway-Sunset, which owns a 225 MW cogeneration facility near Fellows, California. Midway-Sunset is a party to several proceedings pending at the FERC because Midway-Sunset was a seller in the PX and ISO markets during 2000 and 2001, both for its own account and on behalf of SCE and PG&E, the utilities to which the majority of Midway-Sunset’s power was contracted for sale. As a seller into the PX and ISO markets, Midway-Sunset is potentially liable for refunds to purchasers in these markets. See discussion above in “FERC Refund Proceedings.”

The claims asserted against Midway-Sunset for refunds related to power sold into the PX and ISO markets, including power sold on behalf of SCE and PG&E, are estimated to be less than $70 million for all periods under consideration. Midway- Sunset did not retain any proceeds from power sold into the PX and ISO markets on behalf of SCE and PG&E in excess of the amounts to which it was entitled under the pre-existing power sales contracts, but instead passed through those proceeds to the utilities. Since the proceeds were passed through to the utilities, EME believes that PG&E and SCE are obligated to reimburse Midway-Sunset for any refund liability that it incurs as a result of sales made into the PX and ISO markets on their behalves.

During this period, amounts SCE received from Midway-Sunset were credited to SCE’s customers against power purchase expenses through the ratemaking mechanism in place at that time. SCE believes that any net amounts reimbursed to Midway-Sunset would be recoverable from its customers through current regulatory mechanisms. Edison International does not expect any refund payment made by Midway-Sunset, or any SCE reimbursement to Midway-Sunset, to have a material impact on earnings.

Midwest Generation Potential Environmental Proceeding

On July 31, 2007, the US EPA issued a NOV to Midwest Generation and Commonwealth Edison. In the NOV, the US EPA alleges that, beginning in the early 1990’s and into 2003, Midwest Generation or Commonwealth Edison performed construction projects at six Illinois coal-fired electric generating stations in violation of the Prevention of Significant Deterioration requirements and of the New Source Performance Standards of the Clean Air Act, including alleged requirements to obtain a construction permit and to install Best Available Control Technology at the time of the projects. The US EPA also alleges that Midwest Generation and Commonwealth Edison violated certain operating permit requirements under Title V of the Clean Air Act. Finally, the US EPA alleges violations of certain opacity and particulate matter standards at the Illinois Plants. The US EPA has invited Midwest Generation and Commonwealth Edison to meet with the US EPA by August 30, 2007 to discuss the alleged violations. Midwest Generation is investigating the claims made by the US EPA in the NOV and potential responses and cannot predict at this time what effect this matter may have on its facilities, its results of operations or financial position.

 

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EDISON INTERNATIONAL

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Navajo Nation Litigation

The Navajo Nation filed a complaint in June 1999 in the District Court against SCE, among other defendants, arising out of the coal supply agreement for Mohave. The complaint asserts claims for, among other things, violations of the federal RICO statute, 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, trebling of that amount, and punitive damages of not less than $1 billion.

In April 2004, the District Court dismissed SCE’s motion for summary judgment and concluded that a 2003 U.S. Supreme Court decision in an ongoing related lawsuit by the Navajo Nation against the U.S. Government did not preclude the Navajo Nation from pursuing its RICO and intentional tort claims.

Pursuant to a joint request of the parties, the District Court granted a stay of the action on October 5, 2004 to allow the parties to attempt to negotiate a resolution of the issues associated with Mohave with the assistance of a facilitator. An initial organizational session was held with the facilitator on October 14, 2004 and negotiations are ongoing. On July 28, 2005, the District Court issued an order removing the case from its active calendar, subject to reinstatement at the request of any party. On April 30, 2007, the District Court, in light of the duration of the stay, issued a minute order directing that the parties file a joint status report and recommendation for future proceedings no later than June 1, 2007. In their June 1, 2007 joint status report, the parties advised the District Court of the history and status of their settlement efforts, including the potential for further discussions. Following its receipt of the status report, the District Court continued the stay and directed the parties to file a further joint status report by October 5, 2007.

SCE cannot predict the outcome of the 1999 Navajo Nation’s complaint against SCE, the ultimate impact on the complaint of the Supreme Court’s 2003 decision and the on-going litigation by the Navajo Nation against the Government in the related case, or the impact on the facilitated negotiations of the Mohave co-owners’ announced decisions to discontinue efforts to return Mohave to service.

Nuclear Insurance

Federal law limits public liability claims from a nuclear incident to $10.8 billion. SCE and other owners of San Onofre and Palo Verde have purchased the maximum private primary insurance available ($300 million). The balance is covered by the industry’s retrospective rating plan that uses deferred premium charges to every reactor licensee 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. Federal regulations require this secondary level of financial protection. The NRC exempted San Onofre Unit 1 from this secondary level, effective June 1994. The current maximum deferred premium for each nuclear incident is $101 million per reactor, but not more than $15 million per reactor may be charged in any one year for each incident. The maximum deferred premium per reactor and the yearly assessment per reactor for each nuclear incident will be adjusted for inflation on a 5-year schedule. The next inflation adjustment will occur no later than August 20, 2008. Based on its ownership interests, SCE could be required to pay a maximum of $201 million per nuclear incident. However, it would have to pay no more than $30 million per incident in any one year. Such amounts include a 5% surcharge if additional funds are needed to satisfy public liability claims and are subject to adjustment for inflation. If the public liability limit above is insufficient, federal regulations may impose further revenue-raising measures to pay claims, including a possible additional assessment on all licensed reactor operators.

 

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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 utilities 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 $44 million per year. Insurance premiums are charged to operating expense.

Palo Verde Nuclear Generating Station Outage and Inspection

Between December 2005 when Palo Verde Unit 1 returned to service from its refueling and steam generator replacement outage and March 2006, Palo Verde Unit 1 operated at between 25% and 32% power level. The need to operate at a reduced power level was due to the vibration level in one of the unit’s shutdown cooling lines. On March 18, 2006, Arizona Public Service, the operating agent for Palo Verde Unit 1, removed the unit from service in order to resolve the problem. The vibration problem was resolved and Palo Verde Unit 1 was returned to service on July 7, 2006. Incremental replacement power costs incurred during the outage and periods of reduced power operation of approximately $32 million are expected to be recovered through the ERRA rate-making mechanism.

The NRC held three special inspections of Palo Verde, between March 2005 and February 2007. A follow-up to the first inspection resulted in a finding that Palo Verde had not established adequate measures to ensure that certain corrective actions were effective to address the root cause of the event. The second recent inspection identified five violations, but none of those resulted in increased NRC scrutiny. The most recent inspection, concerning the failure of an emergency backup generator at Palo Verde Unit 3 identified a violation that, combined with the first inspection finding, will cause the NRC to undertake additional oversight inspections of Palo Verde. In addition, Palo Verde will be required to take additional corrective actions, including surveys of its plant personnel and self-assessments of its programs and procedures, which will increase costs to both Palo Verde and its co-owners, including SCE. Because the surveys and self-assessments have not yet occurred and are critical to determining what other actions Palo Verde will need to take to address the NRC’s concerns, SCE cannot calculate the total increase in costs, but presently estimates that operation and maintenance costs at Palo Verde will increase by a minimum of $22 million per year through 2009. SCE also is unable to estimate how long SCE will continue to incur these costs.

Procurement of Renewable Resources

California law requires SCE to increase its procurement of renewable resources by at least 1% of its annual retail electricity sales per year so that 20% of its annual electricity sales are procured from renewable resources by no later than December 31, 2010.

On October 19, 2006, the CPUC issued a decision that, among other things, implemented a “cumulative deficit banking” feature which would carry forward and accumulate annual deficits until the deficit has been satisfied at a later time through actual deliveries of eligible renewable energy and made an accounting determination that defines the annual targets for each year of the renewable portfolio standards program. Based on terms of the controlling California statute, in March 2007, SCE successfully challenged the CPUC’s accounting determination of SCE’s annual targets. This change is expected to enable SCE to meet its target for 2007.

On April 3, 2007, SCE filed its renewable portfolio standard compliance report for 2004 through 2006. The compliance report confirms that SCE met its renewable goals for each of these years. In light of the annual target

 

28


EDISON INTERNATIONAL

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

 

revisions that resulted from the March 2007 successful challenge to the CPUC’s accounting determination, the report also projects that SCE will meet its renewable goals for 2007 and 2008 but could have a potential deficit in 2009. The potential deficit in 2009, however, does not take into account future procurement opportunities or the full utilization by SCE of the CPUC’s rules for flexible compliance with annual targets. SCE continues to engage in several initiatives to procure additional renewable resources, including formal solicitations approved by the CPUC, bilateral negotiations with individual projects and other initiatives.

Under current CPUC decisions, potential penalties for SCE’s failure to achieve its renewable procurement objectives for any year would be considered by the CPUC in the context of the CPUC’s review of SCE’s annual compliance filing. Under the CPUC’s current rules, the maximum penalty for failing to achieve renewable procurement targets is $25 million per year.

Scheduling Coordinator Tariff Dispute

Pursuant to the Amended and Restated Exchange Agreement, SCE serves as a scheduling coordinator for the DWP over the ISO-controlled grid. In late 2003, SCE began charging the DWP under a tariff subject to refund for FERC-authorized scheduling coordinator charges incurred by SCE on the DWP’s behalf. The scheduling coordinator charges are billed to the DWP under a FERC tariff that remains subject to dispute. The DWP has paid the amounts billed under protest but requested that the FERC declare that SCE was obligated to serve as the DWP’s scheduling coordinator without charge. The FERC accepted SCE’s tariff for filing, but held that the rates charged to the DWP have not been shown to be just and reasonable and thus made them subject to refund and further review by the FERC. In September 2006, SCE and DWP agreed to a term sheet that would settle this dispute, among others surrounding the Exchange Agreement. The settlement was approved by the FERC on July 27, 2007 and is expected to be approved by the City of Los Angeles in the second half of 2007. As of June 30, 2007, SCE has an accrued liability of $47 million (including $6 million of interest) for the potential refunds representing charges collected. Under the settlement terms, SCE would refund to the DWP the scheduling coordinator charges collected, with an offset for contract losses, and will be able to recover the scheduling coordinator charges from all transmission grid customers.

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 obligation to begin acceptance of spent nuclear fuel by January 31, 1998. It is not certain when the DOE will begin accepting spent nuclear fuel from San Onofre or other nuclear power plants. Extended delays by the DOE have led to the construction of costly alternatives and associated siting and environmental issues. SCE has paid the DOE the required one-time fee applicable to nuclear generation at San Onofre through April 6, 1983 (approximately $24 million, plus interest). SCE is also paying the required quarterly fee equal to 0.1¢-per-kWh of nuclear-generated electricity sold after April 6, 1983. On January 29, 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. The case was stayed through April 7, 2006. On June 5, 2006, the Court of Federal Claims lifted the stay on SCE’s case and established a discovery schedule. A Joint Status Report is due on February 22, 2008, regarding further proceedings in this case, presumably including the setting of a trial date.

SCE has primary responsibility for the interim storage of spent nuclear fuel generated at San Onofre. Spent nuclear fuel is stored in the San Onofre Units 2 and 3 spent fuel pools and the San Onofre independent spent fuel storage

 

29


EDISON INTERNATIONAL

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

 

installation where all of Unit 1’s spent fuel located at San Onofre is stored. There are now sufficient dry casks and modules available at the independent spent fuel storage installation to meet plant requirements through 2008. SCE, as operating agent, plans to continually load casks on a schedule to maintain full core off-load capability for both units in order to meet the plant requirements until 2022 (the end of the current NRC operating license).

In order to increase on-site storage capacity and maintain core off-load capability, Palo Verde has constructed an independent spent fuel storage facility. Arizona Public Service, as operating agent, plans to continually load dry casks on a schedule to maintain full core off-load capability for all three units.

Note 7. Accumulated Other Comprehensive Income (Loss) Information

Edison International’s accumulated other comprehensive income (loss) consists of:

 

In millions   

June 30,

2007

   

December 31,

2006

 
     (Unaudited)        

Foreign currency translation adjustments – net of tax

   $ (1 )   $ 1  

SFAS No. 158 – pension and other postretirement benefits – net of tax

     (32 )     (33 )

Unrealized gain on cash flow hedges – net of tax

        15         110  

Accumulated other comprehensive income (loss)

   $ (18 )   $ 78  

SFAS No. 158 – pension and other postretirement benefits – net of tax relates to “Pension Plans” and “Postretirement Benefits Other Than Pensions” discussed in Note 5.

Unrealized gains on cash flow hedges, net of tax, at June 30, 2007, included unrealized gains on commodity hedges related to Midwest Generation and EME Homer City 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. The decrease in unrealized gains during the six months ended June 30, 2007 resulted from an increase in market prices for power.

As EME’s hedged positions for continuing operations are realized, approximately $37 million, after tax, of the net unrealized gains on cash flow hedges at June 30, 2007 are expected to be reclassified into earnings during the next 12 months. Management expects that reclassification of net unrealized gains will offset energy revenue recognized at market prices. Actual amounts ultimately reclassified into earnings over the next 12 months could vary materially from this estimated amount as a result of changes in market conditions. The maximum period over which a cash flow hedge is designated is through December 31, 2009.

Under SFAS No. 133, the portion of a cash flow hedge that does not offset the change in value of the transaction being hedged, which is commonly referred to as the ineffective portion, is immediately recognized in earnings. EME recorded net losses of approximately $9 million and $6 million during the second quarters of 2007 and 2006, respectively, and $10 million and $17 million during the six months ended June 30, 2007 and 2006, respectively, representing the amount of cash flow hedges’ ineffectiveness for continuing operations, reflected in operating revenues in EME’s consolidated income statements.

 

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EDISON INTERNATIONAL

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

 

Note 8. Supplemental Cash Flows Information

Edison International’s supplemental cash flows information is:

 

      Six Months Ended
June 30,
 
In millions        2007             2006      
     (Unaudited)  

Cash payments (receipts) for interest and taxes:

    

Interest – net of amounts capitalized

   $   269     $    361  

Tax payments (receipts)

     (19 )     81  

Noncash investing and financing activities:

    

Details of debt exchange:

    

Pollution-control bonds redeemed

   $     $ (331 )

Pollution-control bonds issued

           331  

Details of obligation under capital lease:

    

Capital lease asset purchased

   $ (10 )   $  

Capital lease obligation issued

     10        

Dividends declared but not paid:

    

Common Stock

   $ 94     $ 88  

Preferred and preference stock of utility not subject to mandatory redemption

     13       13  

Details of assets acquired:

    

Fair value of assets acquired

   $ 29     $ 29  

Liabilities assumed

            

Net assets acquired

   $ 29     $ 29  

During the first six months of 2007, EME accrued $19 million in connection with the purchase price of wind projects acquired in March 2007 due upon completion of construction. During the first six months of 2006, EME accrued $11 million in connection with the purchase price of the Wildorado wind project paid upon completion of the project in April 2007. Also in 2006, EME received a capital contribution of $76 million in the form of ownership interests in a portfolio of wind projects and a small biomass project.

 

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EDISON INTERNATIONAL

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

 

Note 9. Regulatory Assets and Liabilities

Regulatory assets included in the consolidated balance sheets are:

 

 

In millions   

June 30,

2007

  

December 31,

2006

     (Unaudited)     

Current:

     

Regulatory balancing accounts

   $ 104    $ 128

Rate reduction notes – transition cost deferral

     111      219

Direct access procurement charges

     20      63

Energy derivatives

     58      88

Purchased-power settlements

     18      31

Deferred FTR proceeds

     47      14

Other

     27      11
       385      554

Long-term:

     

Flow-through taxes – net

     1,140      1,023

Unamortized nuclear investment – net

     421      435

Nuclear-related asset retirement obligation investment –net

     307      317

Unamortized coal plant investment – net

     98      102

Unamortized loss on reacquired debt

     308      318

SFAS No. 158 pensions and postretirement benefits

     305      303

Energy derivatives

     72      145

Environmental remediation

     72      77

Other

     98      98
       2,821      2,818
Total regulatory assets    $   3,206    $   3,372

Deferred FTR proceeds represent the deferral of congestion revenue SCE received as a transmission owner from the annual ISO FTR auction. The deferred FTR proceeds will be recognized over the period April 2007 through January 2008.

 

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EDISON INTERNATIONAL

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

 

Regulatory liabilities included in the consolidated balance sheets are:

 

In millions    June 30,
2007
  

December 31,

2006

     (Unaudited)     

Current:

     

Regulatory balancing accounts

   $ 1,000    $ 912

Direct access procurement charges

     20      63

Energy derivatives

     12      7

Deferred FTR costs

     84      11

Other

     4      7
       1,120      1,000

Long-term:

     

Asset retirement obligations

     799      732

Costs of removal

     2,190      2,158

SFAS No. 158 pensions and other postretirement benefits

     153      145

Energy derivatives

     14      27

Employee benefit plans

     78      78
       3,234      3,140

Total regulatory liabilities

   $   4,354    $   4,140

Deferred FTR costs represent the deferral of the costs associated with FTRs that SCE purchased during the annual ISO auction process. The FTRs provide SCE with scheduling priority in certain transmission grid congestion areas in the day-ahead market. The FTRs meet the definition of a derivative instrument and are recorded at fair value and marked to market each reporting period. Any fair value change for FTRs is reflected in the deferred FTR costs regulatory liability. The deferred FTR costs are recognized as FTRs are used or expire during the period April 2007 through March 2008.

Note 10. Business Segments

Edison International’s reportable business segments include its electric utility operation segment (SCE), a nonutility power generation segment (MEHC-parent only and EME), and a financial services provider segment (Edison Capital). Edison International evaluates performance based on net income.

On April 1, 2006, EME received as a capital contribution, ownership interests in a portfolio of wind projects located in Iowa and Minnesota and a small biomass project. As a result of this capital contribution, Edison International’s nonutility power generation segment now includes the wind assets and biomass power project previously owned by Edison Capital. The resulting change in the structure of Edison International’s internal organization and in accordance with SFAS No. 131, “Disclosures about Segments of an Enterprise and Related Information,” prior periods have been restated to conform to Edison International’s new business segment definition.

 

33


EDISON INTERNATIONAL

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

 

Segment information for the three and six months ended June 30, 2007 and 2006 was:

 

      Three Months Ended
June 30,
     Six Months Ended
June 30,
 
In millions    2007     2006      2007     2006  
     (Unaudited)  

Operating Revenue:

         

Electric utility

   $   2,459     $   2,521      $   4,681     $   4,739  

Nonutility power generation

     569       460        1,241       975  

Financial services

     18       19        35       38  

All others(1)

     1       1        2       1  

Consolidated Edison International

   $ 3,047     $ 3,001      $ 5,959     $ 5,753  

Net Income (Loss):

         

Electric utility(2)

   $ 144     $ 234      $ 325     $ 355  

Nonutility power generation(3)

     (73 )     (56 )      65       75  

Financial services

     26       5        45       20  

All others(1)

     (4 )     (6 )      (9 )     (15 )

Consolidated Edison International

   $ 93     $ 177      $ 426     $ 435  

 

(1) Includes amounts from nonutility subsidiaries, as well as Edison International (parent) that are not significant as a reportable segment.

 

(2) Net income available for common stock.

 

(3) Includes earnings from discontinued operations of $2 million and $4 million for the three months ended June 30, 2007 and 2006, respectively and $5 million and $77 million for the six months ended June 30, 2007 and 2006, respectively.

Note 11. Discontinued Operations

EME previously owned a 220 MW power plant located in the United Kingdom, referred to as the Lakeland project. An administrative receiver was appointed in 2002 as a result of a default by the project’s counterparty, a subsidiary of TXU Europe Group plc. Following a claim for termination of the power sales agreement, the Lakeland project received a settlement of £116 million (approximately $217 million). EME is entitled to receive the remaining amount of the settlement after payment of creditor claims. As creditor claims have been settled, EME received payments of £61 million (approximately $106 million) in the first quarter of 2006, £9 million (approximately $16 million) in April 2006 and £4 million (approximately $8 million) in January 2007. The after-tax income attributable to the Lakeland project was none and $10 million for the second quarters of 2007 and 2006, respectively, and $5 million and $83 million for the six months ended June 30, 2007 and 2006, respectively. Beginning in 2002, EME reported the Lakeland project as discontinued operations and accounts for its ownership of Lakeland Power on the cost method (earnings are recognized as cash is distributed from the project).

For both periods presented, the results of EME’s project discussed above have been accounted for as discontinued operations in the consolidated financial statements in accordance with SFAS No. 144.

For the three months ended June 30, 2007, and 2006, there was no revenue from discontinued operations and pre-tax income was $5 million and $7 million, respectively. For the six months ended June 30, 2007, and 2006, there was no revenue from discontinued operations and pre-tax income was $11 million and $119 million, respectively.

 

34


EDISON INTERNATIONAL

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

 

Note 12. Subsequent Event

On July 24, 2007, Midwest Generation and its affiliate EMMT, along with other power generation companies and utilities, entered into a settlement agreement with the Illinois Attorney General. The settlement is subject to the passage of legislation which if enacted and signed by the Governor of Illinois will, among other things, establish a new Illinois Power Agency to manage future power procurement for Commonwealth Edison and Ameren (beginning with the planning year June 1, 2009 through May 31, 2010). The settlement legislation was passed by the Illinois legislature on July 26, 2007 but has not yet been signed by the Governor of Illinois. No assurance can be given that the terms of the settlement agreement will be implemented as contemplated or that the legislation necessary for the settlement to become effective will be signed by the Governor of Illinois.

As part of the settlement, Midwest Generation has agreed to pay $25 million over three years toward approximately $1 billion in utility customer rate relief and startup costs of the new Illinois Power Agency. The remainder is to be funded by subsidiaries of Exelon Corporation, subsidiaries of Ameren, Dynegy Holdings Inc., and Mid-American Energy Company. Also as part of the settlement, the Illinois Attorney General has agreed to file motions to dismiss auction-related complaints filed at the FERC, the Illinois Commerce Commission and in the Illinois courts.

Subject to the foregoing, Midwest Generation plans to make a payment of $7.5 million within ten business days after the settlement becomes effective (or on such later date as the Illinois Attorney General may specify in writing), followed by monthly payments of $750,000 beginning in January 2008 and continuing until the total commitment has been funded. These payments are non-refundable; however, Midwest Generation’s obligations to make the monthly payments will cease if, at any time prior to December 2009, as further described in the rate relief package and related agreements, Illinois imposes an electric rate freeze or an additional tax on generators.

 

35


Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations

INTRODUCTION

This Management’s Discussion and Analysis of Financial Condition and Results of Operation for the three- and six-month periods ended June 30, 2007 discusses material changes in the financial condition, results of operations and other developments of Edison International since December 31, 2006, and as compared to the three- and six-month periods ended June 30, 2006. This discussion presumes that the reader has read or has access to Edison International’s MD&A for the calendar year 2006 (the year-ended 2006 MD&A), which was included in Edison International’s 2006 annual report to shareholders and incorporated by reference into Edison International’s Annual Report on Form 10-K for the year ended December 31, 2006, filed with the Securities and Exchange Commission.

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, or that otherwise could impact Edison International or its subsidiaries, include, but are not limited to:

 

 

the ability of Edison International to meet its financial obligations and to pay dividends on its common stock if its subsidiaries are unable to pay dividends;

 

 

the 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;

 

 

market risks affecting SCE’s energy procurement activities;

 

 

access to capital markets and the cost of capital;

 

 

changes in interest rates, rates of inflation and foreign exchange rates;

 

 

governmental, statutory, regulatory or administrative changes or initiatives affecting the electricity industry, including the market structure rules applicable to each market;

 

 

environmental regulations that could require additional expenditures or otherwise affect the cost and manner of doing business;

 

 

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

 

 

the availability of labor, equipment and materials;

 

 

the ability to obtain sufficient insurance, including insurance relating to SCE’s nuclear facilities;

 

 

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

 

36


 

the outcome of disputes with the IRS and other tax authorities regarding tax positions taken by Edison International;

 

 

supply and demand for electric capacity and energy, and the resulting prices and dispatch volumes, in the wholesale markets to which EMG’s generating units have access;

 

 

the cost and availability of coal, natural gas, fuel oil, nuclear fuel, and associated transportation;

 

 

the 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;

 

 

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

 

 

the risk of counterparty default in hedging transactions or power-purchase and fuel contracts;

 

 

the extent of additional supplies of capacity, energy and ancillary services from current competitors or new market entrants, including the development of new generation facilities and technologies;

 

 

the difficulty of predicting wholesale prices, transmission congestion, energy demand and other aspects of the complex and volatile markets in which EMG and its subsidiaries participate;

 

 

general political, economic and business conditions;

 

 

weather conditions, natural disasters and other unforeseen events;

 

 

changes in the fair value of investments and other assets; and

 

 

the risks inherent in the development of generation projects as well as transmission and distribution infrastructure replacement and expansion including those related to siting, financing, construction, permitting, and governmental approvals.

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 Edison International’s 2006 Annual Report on 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 & Exchange Commission.

Edison International is engaged in the business of holding, for investment, the common stock of its subsidiaries. Edison International’s principal operating subsidiaries are SCE, a rate-regulated electric utility, and EMG. EMG is the holding company for its principal wholly owned subsidiaries, EME, which is engaged in the business of developing, acquiring, owning, or leasing, operating and selling energy and capacity from independent power production facilities, and Edison Capital, a provider of capital and financial services.

In this MD&A, except when stated to the contrary, references to each of Edison International, SCE, EMG, EME or Edison Capital mean each such company with its subsidiaries on a consolidated basis. References to Edison International (parent) or parent company mean Edison International or on a stand-alone basis, not consolidated with its subsidiaries.

 

37


This MD&A is presented in 8 major sections. The company-by-company discussion of SCE, EMG, and Edison International (parent) includes discussions of liquidity, market risk exposures, and other matters (as relevant to each principal business segment). The remaining sections discuss Edison International on a consolidated basis. The consolidated sections should be read in conjunction with the discussion of each company’s section.

 

      Page

Current Developments

  

39

Southern California Edison Company

  

43

Edison Mission Group Inc.

  

52

Edison International (Parent)

  

70

Results of Operations and Historical Cash Flow Analysis

  

71

New Accounting Pronouncements

  

81

Commitments, Guarantees and Indemnities

  

81

Other Developments

  

82

 

38


CURRENT DEVELOPMENTS

The following section provides a summary of current developments related to Edison International’s principal business segments. This section is intended to be a summary of those current developments that management believes are of most importance since year-end December 31, 2006. This section is not intended to be an all-inclusive list of all current developments related to each principal business segment and should be read together with all sections of this MD&A.

SCE: CURRENT DEVELOPMENTS

2008 Cost of Capital Proceeding

On May 8, 2007, SCE filed its 2008 cost of capital application requesting a rate-making capital structure of 43% long-term debt, 9% preferred equity and 48% common equity. In addition, SCE is seeking a cost of long-term debt of 6.20%, cost of preferred equity of 5.98% and a return on common equity of 11.80%. SCE expects a decision on the 2008 cost of capital application by the end of 2007.

2009 General Rate Case

On July 23, 2007, SCE tendered to the CPUC’s DRA its NOI to file a 2009 GRC. The NOI indicates that SCE’s GRC application will request a 2009 base rate revenue requirement of $5.19 billion, an increase of approximately $856 million over the projected 2008 authorized base rate revenue requirement. After considering the effects of sales growth and other offsets, SCE’s request would be a $724 million increase over current authorized base rate revenue. If the CPUC approves these requested increases and allocates them to ratepayer groups on a system average percentage change basis, the percentage increases over current base rates and total rates are estimated to be 16.2% and 6.2%, respectively. The requested revenue requirement increase is necessary for SCE to build facilities to serve new customers, reinforce its system to accommodate customer load growth, replace aging infrastructure, meet regulatory requirements in generation and electricity procurement, fund increased operations and maintenance costs, and provide for increased costs to recruit, train, and retain employees in light of anticipated retirements. The NOI also identifies that SCE’s application will propose a post-test year ratemaking mechanism which would result in 2010 and 2011 base rate revenue requirement increases, net of sales growth, of $250.5 million and $285.3 million, respectively, for the same reasons. SCE will also be requesting in its application that Mountainview be included in utility rate base and its operating costs be recovered through the 2009 GRC rather than the current structure under which SCE recovers Mountainview generating costs through a power purchase agreement.

The NOI includes a draft of the upcoming GRC application and testimony. The CPUC’s Rate Case Plan decision initially assigns to DRA the role of ensuring that a utility’s NOI substantially complies with the documentation requirements of that decision. The DRA is required to notify SCE of any deficiencies in the NOI by August 17, 2007. SCE can file its 2009 GRC application no sooner than 60 days after curing any such deficiencies. A final decision on SCE’s 2009 GRC is expected by December 2008.

SCE cannot predict the revenue requirement the CPUC will ultimately authorize or precisely when a final decision will be adopted.

EdisonSmartConnecttm

SCE’s EdisonSmartConnecttm project involves installing state-of-the-art “smart” meters in approximately 5.3 million households and small businesses through its service territory. The development of this advanced metering infrastructure is to be accomplished in three phases: the initial design phase to develop the new generation of advanced metering systems (Phase I), which was completed in 2006; the pre-deployment phase (Phase II) to field test and select EdisonSmartConnecttm technologies, select the deployment vendor and finalize the EdisonSmartConnecttm business case for full deployment, which will be conducted during 2007; and the final

 

39


deployment phase (Phase III), which is expected to begin in 2008 and be completed in 2012. The total cost for this project is estimated to be $1.7 billion of which $1.3 billion is estimated to be capitalized and included in utility rate base.

On July 26, 2007, the CPUC unanimously approved $45 million for Phase II of this project. SCE filed its Phase III application on July 31, 2007, requesting CPUC authorization to deploy EdisonSmartConnecttm meters to all residential and small business customers under 200 kW over a five-year period beginning in 2008. SCE expects a decision on the Phase III application by mid-2008.

Peaker Plant Generation Projects

On August 15, 2006, the CPUC issued a ruling addressing electric reliability needs in Southern California for the summer of 2007 and directing, among other things, that SCE pursue new utility-owned peaker generation (which would be available on notice during peak demand periods) that would be online by August 2007. SCE completed the construction of and placed online four combustion turbine peaker plants, in August 2007, each with a capacity of approximately 45 MW. SCE continues to pursue permitting for the construction of a fifth project. See “SCE: Regulatory Matters—Peaker Plant Generation Project” for further discussion.

EMG: CURRENT DEVELOPMENTS

Business Development

EME has undertaken a number of activities in 2007 with respect to wind projects, including the following:

 

 

In March 2007, EME acquired three wind projects in development in Utah and Wyoming totaling 212 MW. One of the projects, the 61 MW Mountain Wind I project, commenced construction during the second quarter of 2007 with completion scheduled during the first quarter of 2008. The estimated capital cost of this project, excluding capitalized interest, is $104 million. The project plans to sell electricity to PacifiCorp under a 20-year power purchase agreement. The other two projects are in preliminary stages of development.

 

 

In March 2007, EME acquired the remaining membership interests in two wind projects, totaling 67 MW, under development in Pennsylvania. Construction of these projects commenced during the second quarter of 2007 with completion scheduled during the first quarter of 2008. The estimated capital cost, excluding capitalized interest, is $121 million. The 29 MW Forward project plans to sell electricity to Constellation New Energy under a 10-year power purchase agreement. The 38 MW Lookout project plans to sell electricity into PJM as a merchant wind generator.

 

 

In March 2007, EME purchased from Mitsubishi Power Systems Americas, Inc. wind turbines and related services and warranties for an aggregate purchase price of approximately $256 million with deliveries scheduled for 2008 and 2009. EME also made a reservation fee payment of $8 million for additional turbines for 2009 delivery. In June 2007, EME exercised its option to acquire 83 turbines (totaling 199 MW) for 2008 and 2009 delivery. The aggregate purchase price for these turbines and related services and warranties was approximately $248 million (a portion of which is denominated in Japanese yen and subject to exchange rate fluctuations).

 

 

In April 2007, EME acquired six projects in development in Texas and Oklahoma totaling 700 MW. These projects are in various stages of development with target completion dates of 2008 through 2010. The purchase price for these projects is comprised of an initial payment and subsequent payments tied to milestones and adjustments based on EME’s projected internal rate of return in individual projects. Completion of development of these projects is dependent on a number of items, including, among other things, obtaining power sales agreements, and in certain cases, permits and interconnection agreements.

 

 

In June 2007, EME acquired a 99.9% interest in a 20 MW wind project under development in Minnesota. Construction of this project commenced in May 2007 with completion scheduled during the first quarter of

 

40


 

2008. The estimated capital cost, excluding capitalized interest, is $33 million. The project plans to sell electricity to Missouri River Energy Services under a 20-year power purchase agreement.

 

 

In June 2007, EME contracted with Suzlon Wind Energy Corporation for the purchase of 300 wind turbines (totaling 630 MW) together with related services and warranties, for an aggregate purchase price of approximately $698 million with deliveries scheduled for 2008 and 2009.

As of June 30, 2007, EME had a development pipeline of potential wind projects with an installed capacity of approximately 3,100 MW (the development pipeline represents potential projects with respect to which EME either owns the project rights or has exclusive negotiation rights).

PJM Reliability Pricing Model

In April 2007, PJM completed the first capacity auction under the PJM Reliability Pricing Model. EME participated in the auction for the period June 1, 2007 through May 31, 2008. After accounting for previous forward sales of capacity, EMMT sold net 2,628 MW of capacity from the Illinois plants and net 786 MW of capacity from the Homer City facilities. The Illinois plants and the Homer City facilities are located in the “Rest of Market” area which had a clearing price of $40.80 per MW-day.

In July 2007, EME participated in the auction for the period June 1, 2008 through May 31, 2009. After accounting for previous forward sales of capacity, EMMT sold net 3,283 MW of capacity from the Illinois plants and net 820 MW of capacity from the Homer City facilities. The Illinois plants and the Homer City facilities are located in the “Rest of Market” area which had a clearing price of $111.92 per MW-day. For further discussion regarding the PJM and recent auctions, see “EMG: Market Risk Exposures—Commodity Price Risk—Capacity Price Risk.”

Illinois Settlement

On July 24, 2007, Midwest Generation and its affiliate EMMT, along with other power generation companies and utilities, entered into a settlement agreement with the Illinois Attorney General. The settlement is subject to the passage of legislation which if enacted and signed by the Governor of Illinois will, among other things, establish a new Illinois Power Agency to manage future power procurement for Commonwealth Edison and Ameren (beginning with the planning year June 1, 2009 through May 31, 2010). The settlement legislation was passed by the Illinois legislature on July 26, 2007, but has not yet been signed by the Governor of Illinois. No assurance can be given that the terms of the settlement agreement will be implemented as contemplated or that the legislation necessary for the settlement to become effective will be signed by the Governor of Illinois.

As part of the settlement, Midwest Generation has agreed to pay $25 million over three years toward approximately $1 billion in utility customer rate relief and startup costs of the new Illinois Power Agency. The remainder is to be funded by subsidiaries of Exelon Corporation, subsidiaries of Ameren, Dynegy Holdings Inc., and Mid-American Energy Company. Also as part of the settlement, the Illinois Attorney General has agreed to file motions to dismiss auction-related complaints filed at the FERC, the Illinois Commerce Commission and in the Illinois courts.

Subject to the foregoing, Midwest Generation plans to make a payment of $7.5 million within ten business days after the settlement becomes effective (or on such later date as the Illinois Attorney General may specify in writing), followed by monthly payments of $750,000 beginning in January 2008 and continuing until the total commitment has been funded. These payments are non-refundable; however, Midwest Generation’s obligations to make the monthly payments will cease if, at any time prior to December 2009, as further described in the rate relief package and related agreements, Illinois imposes an electric rate freeze or an additional tax on generators.

 

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Refinancing

Senior Notes Offering

On May 7, 2007, EME completed a private offering of $1.2 billion of its 7.00% senior notes due 2017, $800 million of its 7.20% senior notes due 2019 and $700 million of its 7.625% senior notes due 2027. EME will pay interest on the senior notes on May 15 and November 15 of each year, beginning on November 15, 2007. The net proceeds were used, together with cash on hand, to:

 

 

purchase substantially all of EME’s outstanding 7.73% senior notes due 2009,

 

 

purchase substantially all of Midwest Generation’s 8.75% second priority senior secured notes due 2034,

 

 

repay the outstanding balance of Midwest Generation’s senior secured term loan facility ($327.8 million), and

 

 

make a dividend payment of $899 million to MEHC which enabled MEHC to purchase substantially all of its 13.5% senior secured notes due 2008.

Redemption of MEHC Senior Secured Notes

On June 25, 2007, MEHC redeemed in full its senior secured notes. As a result of the redemption, EME is no longer subject to financial and investment restrictions that were contained in the indenture pursuant to which the senior secured notes were issued. Following the redemption, MEHC no longer files reports with the U.S. Securities and Exchange Commission.

The refinancing activities improved EMG’s overall liquidity, operating flexibility and ability to capitalize on growth opportunities. EMG recorded a total pre-tax loss of approximately $241 million (approximately $148 million after tax) on early extinguishment of debt during the second quarter of 2007.

Credit Agreement Amendments

During the second quarter of 2007, EME amended its existing $500 million secured credit facility, increasing the total borrowings available thereunder to $600 million, and Midwest Generation amended and restated its existing $500 million senior secured working capital facility. The changes to the senior secured working capital facility included a reduction in the interest rate, a longer maturity date, and fewer restrictive covenants. Midwest Generation intends to use its secured working capital facility to provide credit support for its hedging activities and for general working capital purposes. Midwest Generation may also support its hedging activities by granting first or second priority liens to eligible hedge counterparties.

 

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SOUTHERN CALIFORNIA EDISON COMPANY

SCE: LIQUIDITY

Overview

As of June 30, 2007, SCE had cash and equivalents of $91 million ($86 million of which was held by SCE’s consolidated VIEs). As of June 30, 2007, long-term debt, including current maturities of long-term debt, was $5.4 billion. On February 23, 2007, SCE amended its credit facility, increasing the amount of borrowing capacity to $2.5 billion, extending the maturity to February 2012 and removing the first mortgage bond security pledge. As a result of removing the first mortgage bond security, the credit facility’s pricing changed to an unsecured basis per the terms of the credit facility agreement. At June 30, 2007, the credit facility supported $179 million in letters of credit and $175 million in commercial paper leaving $2.1 billion available for liquidity purposes.

SCE’s estimated cash outflows during the 12-month period following June 30, 2007 primarily consist of:

 

 

Debt maturities of approximately $311 million, including $130 million of rate reduction notes that have a separate nonbypassable recovery mechanism approved by state legislation and CPUC decisions. The rate reduction notes are scheduled to be paid off in December 2007 and the nonbypassable rates being charged to customers are expected to cease as of January 1, 2008;

 

 

Projected capital expenditures of $1.4 billion remaining for 2007 primarily to replace and expand distribution and transmission infrastructure and construct and replace major components of generation assets (see “—Capital Expenditures” below);

 

 

Dividend payments to SCE’s parent company. On February 22, 2007, the Board of Directors of SCE declared a $25 million dividend to Edison International which was paid in April 2007. On April 26, 2007 the Board of Directors of SCE declared a $25 million dividend which was paid to Edison International in July 2007;

 

 

Fuel and procurement-related costs (see “SCE: Regulatory Matters—Current Regulatory Developments—Energy Resource Recovery Account Proceedings”); and

 

 

General operating expenses.

SCE expects to meet its continuing obligations, including cash outflows for operating expenses, including power-procurement, through cash and equivalents on hand, operating cash flows and short-term borrowings, when necessary. Projected capital expenditures are expected to be financed through operating cash flows and the issuance of short-term and long-term debt and preferred equity.

SCE’s liquidity may be affected by, among other things, matters described in “SCE: Regulatory Matters” and “Commitments, Guarantees and Indemnities.”

Capital Expenditures

As discussed under the heading “SCE: Liquidity—Capital Expenditures” in the year-ended 2006 MD&A, SCE is experiencing significant growth in actual and planned capital expenditures to replace and expand its distribution and transmission infrastructure, and to construct and replace major components of generation assets. On February 22, 2007, the Finance Committee of the Board of Directors approved SCE’s 2007 through 2011 capital investment plan which includes total capital spending of up to $17.3 billion. During the three- and six-month periods ended June 30, 2007, SCE spent $550 million and $1 billion, respectively, in capital expenditures related to its 2007 capital plan.

 

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Credit Ratings

At June 30, 2007, SCE’s credit ratings were as follows:

 

      Moody’s Rating    S&P Rating    Fitch Rating

Long-term senior secured debt

   A2    BBB+    A+

Short-term (commercial paper)

   P-2    A-2    F-1

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

Dividend Restrictions and Debt Covenants

The CPUC regulates SCE’s capital structure and limits the dividends it may pay Edison International (see “Edison International (Parent): Liquidity” for further discussion). 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 determines compliance with this capital structure based on a 13-month weighted-average calculation. At June 30, 2007, SCE’s 13-month weighted-average common equity component of total capitalization was 49.85%. At June 30, 2007, SCE had the capacity to pay $216 million in additional dividends based on the 13-month weighted-average method. However, based on recorded June 30, 2007 balances, SCE’s common equity to total capitalization ratio (as adjusted for rate-making purposes) was 50.60%. SCE had the capacity to pay $303 million of additional dividends to Edison International based on June 30, 2007 recorded balances.

SCE has a debt covenant in its credit facility that requires a debt to total capitalization ratio of less than or equal to 0.65 to 1 to be met. At June 30, 2007, SCE’s debt to total capitalization ratio was 0.44 to 1.

Margin and Collateral Deposits

SCE has entered into certain margining agreements for power and gas trading activities in support of its procurement plan as approved by the CPUC. SCE’s margin deposit requirements under these agreements can vary depending upon the level of unsecured credit extended by counterparties and brokers, changes in market prices relative to contractual commitments, and other factors. At June 30, 2007, SCE had a net deposit of $175 million (consisting of $36 million in cash and reflected in “Margin and collateral deposits” on the consolidated balance sheet and $139 million in letters of credit) with counterparties. In addition, SCE has deposited $59 million (consisting of $18 million in cash and reflected in “Margin and collateral deposits” on the consolidated balance sheet and $40 million in letters of credit) with other brokers. Cash deposits with brokers and counterparties earn interest at various rates.

SCE: REGULATORY MATTERS

Current Regulatory Developments

This section of the MD&A describes significant regulatory issues that may impact SCE’s financial condition or results of operations.

Impact of Regulatory Matters on Customer Rates

SCE is concerned about high customer rates, which were a contributing factor that led to the deregulation of the electric services industry during the mid-1990s. On January 1, 2007 SCE’s bundled service system average rate was 14.5¢ per-kWh (including 3.1¢ per-kWh related to CDWR which is not recognized as revenue by SCE). On February 14, 2007, SCE’s system average rate decreased to 13.9¢-per-kWh (including 3.0¢ per-kWh related to

 

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CDWR) mainly as the result of estimated lower natural gas prices in 2007, as well as the refund of overcollections in the ERRA balancing account that occurred in 2006 from lower than expected natural gas prices and higher than expected summer 2006 kWh sales (see “—Energy Resource Recovery Account Proceedings” below). In addition, the rate change incorporates the collection of the residential rate increase deferral discussed in the year-ended 2006 MD&A under the heading “Regulatory Matters—Current Regulatory Developments—Impact of Regulatory Matters on Customer Rates.”

On August 1, 2007, SCE filed its 2008 ERRA forecast requesting a revenue requirement increase of $515 million (see “—Energy Resource Recovery Account Proceedings”). In addition, SCE requested to consolidate other rate changes authorized by the CPUC with this ERRA revenue requirement increase effective on or soon after January 1, 2008. SCE is estimating an increase of $528 million in its total system 2008 consolidated revenue requirement when combining the ERRA revenue requirement increase with all other estimated CPUC-authorized revenue requirement changes. After taking estimated 2008 sales growth into account, SCE estimates a total system revenue increase of $447 million. Implementation of the increased consolidated revenue requirement, as requested, would increase the bundled service system average rate from 13.9¢-per-kWh (including 3.0¢ per-kWh related to CDWR) to 14.4 ¢-per-kWh (including 3.1¢ per-kWh related to CDWR), an increase of 3.6%.

FERC Petition for Transmission Incentives

On May 18, 2007, SCE filed a petition seeking transmission incentives for three of its largest proposed transmission projects; Devers-Palo Verde II (“DPV2”) (a high voltage (500 kV) transmission line from Devers substation near Palm Springs, California to a new substation near Palo Verde, west of Phoenix), the Tehachapi Transmission Project (“Tehachapi”) (an eleven transmission line segments and associated substations project to interconnect renewable generation projects near the Tehachapi and Big Creek area), and the Rancho Vista Substation project (“Rancho Vista”) (a proposed new 500kV substation in the City of Rancho Cucamonga). In its Petition, SCE requested a higher return on equity on SCE’s entire transmission rate base in SCE’s next FERC transmission rate case and an additional increase for these three projects upon approval of SCE’s incentive filing. In addition, the petition requests to include in rate base 100% of prudently-incurred capital expenditures during the construction of all three projects and 100% recovery of prudently-incurred abandoned plant costs for DPV2 and Tehachapi, if either or both of these projects are cancelled due to factors beyond SCE’s control. On July 17, 2007, the FERC requested further information relating to SCE’s incentives request. SCE must provide this information by August 16, 2007. A FERC ruling on the petition is not likely to be issued before September, 2007.

The Tehachapi and Rancho Vista projects are proceeding as anticipated. However, despite SCE having obtained approvals for the DPV2 project from the CPUC and other Arizona governmental agencies, by decision dated June 6, 2007, the Arizona Corporation Commission (ACC) denied approval of the DPV2 project. SCE’s application for rehearing and reconsideration was subsequently denied due to inaction by the ACC. SCE intends to file an appeal of the ACC’s decision by August 14, 2007 and is evaluating its options, which include filing a new application with the ACC and building the project in various phases. As of June 30, 2007, SCE has spent approximately $28 million on this project.

Energy Resource Recovery Account Proceedings

As discussed under the heading “Regulatory Matters—Current Regulatory Developments—Energy Resource Recovery Account Proceedings” in the year-ended 2006 MD&A, the ERRA is the balancing account mechanism to track and ensure recovery of SCE’s fuel and procurement-related costs. At December 31, 2006, the ERRA was overcollected by $526 million, which was 13.2% of SCE’s prior year’s generation revenue. On January 25, 2007, the CPUC approved SCE’s request to reduce the 2007 ERRA revenue requirement by $630 million. The CPUC also authorized SCE to consolidate the decreased ERRA revenue requirement with the authorized revenue requirement changes in other SCE proceedings resulting in lower rate levels implemented in February 2007. See “—Impact of Regulatory Matters on Customer Rates” above for further discussion. At June 30, 2007 the ERRA was overcollected by $507 million. SCE anticipates this overcollection to continue to decrease during the remainder of 2007, based on the reduced ERRA revenue requirement approved by the CPUC on January 25, 2007.

 

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2008 ERRA Forecast

On August 1, 2007, SCE filed its 2008 ERRA forecast application in which it forecasts an ERRA revenue requirement of $4.3 billion, an increase of $515 million over SCE’s adopted 2007 ERRA revenue requirement. The increase is mainly attributable to a reduction in ERRA overcollections resulting from the $630 million revenue requirement reduction in 2007, as discussed above. See “—Impact of Regulatory Matters on Customer Rates” above for further discussion.

ISO Disputed Charges

As discussed under the heading “Regulatory Matters—Current Regulatory Developments—ISO Disputed Charges” in the year-ended 2006 MD&A, on April 20, 2004, the FERC issued an order concerning a dispute between the ISO and the Cities of Anaheim, Azusa, Banning, Colton and Riverside, California over the proper allocation and characterization of certain transmission service related charges. On March 29, 2007, the FERC issued an order agreeing with SCE’s position that the charges incurred by the ISO were related to voltage support and should be allocated to the scheduling coordinators, rather than to SCE as a transmission owner. The Cities filed a request for rehearing of the FERC’s order on April 27, 2007. On May 25, 2007, the FERC issued a procedural order granting the rehearing application for the purpose of allowing the FERC to give it further consideration. In a future order, FERC may deny the rehearing request or grant the requested relief in whole or in part. SCE believes that the most recent substantive FERC order correctly allocates responsibility for these ISO charges. However, SCE cannot provide assurance as to the final outcome of the rehearing. If a subsequent regulatory decision changes the allocation of responsibility for these charges, and SCE is required to pay these charges as a transmission owner, SCE may seek recovery in its reliability service rates. SCE cannot provide any assurance that recovery of these charges in its reliability service rates would be permitted.

Peaker Plant Generation Projects

As discussed under the heading “Regulatory Matters—Current Regulatory Developments—Peaker Plant Generation Projects” in the year-ended 2006 MD&A, SCE pursued construction of five combustion turbine peaker plants. In August 2007, four of these peaker plants were placed online. SCE continues the construction of the fifth project, however, the required construction permit has been denied by the City of Oxnard. SCE believes the permit denial to be without merit and is appealing this denial to the Coastal Commission and expects a decision in the fourth quarter of 2007. However, SCE cannot predict the outcome of the proceeding nor estimate the impact of a delayed permit issuance on the project’s construction schedule. SCE believes that the peaker plants will help meet electric reliability needs, notwithstanding the delay encountered by the fifth Oxnard project. SCE has revised its initial budget for all five projects from $250 million to approximately $275 million. SCE expects to fully recover its costs from these projects, but cannot predict the outcome of regulatory proceedings. As of June 30, 2007 SCE had spent or firmly committed approximately $179 million.

Procurement of Renewable Resources

California law requires SCE to increase its procurement of renewable resources by at least 1% of its annual retail electricity sales per year so that 20% of its annual electricity sales are procured from renewable resources by no later than December 31, 2010.

On October 19, 2006, the CPUC issued a decision that, among other things, implemented a “cumulative deficit banking” feature which would carry forward and accumulate annual deficits until the deficit has been satisfied at a later time through actual deliveries of eligible renewable energy and made an accounting determination that defines the annual targets for each year of the renewable portfolio standards program. Based on terms of the controlling California statute, in March 2007, SCE successfully challenged the CPUC’s accounting determination of SCE’s annual targets. This change is expected to enable SCE to meet its target for 2007.

 

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On April 3, 2007, SCE filed its renewable portfolio standard compliance report for 2004 through 2006. The compliance report confirms that SCE met its renewable goals for each of these years. In light of the annual target revisions that resulted from the March 2007 successful challenge to the CPUC’s accounting determination, the report also projects that SCE will meet its renewable goals for 2007 and 2008 but could have a potential deficit in 2009. The potential deficit in 2009, however, does not take into account future procurement opportunities or the full utilization by SCE of the CPUC’s rules for flexible compliance with annual targets. SCE continues to engage in several initiatives to procure additional renewable resources, including formal solicitations approved by the CPUC, bilateral negotiations with individual projects and other initiatives.

Under current CPUC decisions, potential penalties for SCE’s failure to achieve its renewable procurement objectives for any year would be considered by the CPUC in the context of the CPUC’s review of SCE’s annual compliance filing. Under the CPUC’s current rules, the maximum penalty for failing to achieve renewable procurement targets is $25 million per year.

Scheduling Coordinator Tariff Dispute

Pursuant to the Amended and Restated Exchange Agreement, SCE serves as a scheduling coordinator for the DWP over the ISO-controlled grid. In late 2003, SCE began charging the DWP under a tariff subject to refund for FERC-authorized scheduling coordinator charges incurred by SCE on the DWP’s behalf. The scheduling coordinator charges are billed to the DWP under a FERC tariff that remains subject to dispute. The DWP has paid the amounts billed under protest but requested that the FERC declare that SCE was obligated to serve as the DWP’s scheduling coordinator without charge. The FERC accepted SCE’s tariff for filing, but held that the rates charged to the DWP have not been shown to be just and reasonable and thus made them subject to refund and further review by the FERC. In September 2006, SCE and the DWP agreed to a term sheet that would settle this dispute, among others surrounding the Exchange Agreement. The settlement was approved by the FERC on July 27, 2007 and is expected to be approved by the City of Los Angeles in the second half of 2007. As of June 30, 2007, SCE has an accrued liability of $47 million (including $6 million of interest) for the potential refunds representing charges collected. Under the settlement terms, SCE would refund to the DWP the scheduling coordinator charges collected, with an offset for contract losses, and will be able to recover the scheduling coordinator charges from all transmission grid customers.

FERC Refund Proceedings

SCE is participating in several related proceedings seeking recovery of refunds from sellers of electricity and natural gas who manipulated the electric and natural gas markets during the energy crisis in California in 2000 – 2001 or who benefited from the manipulation by receiving inflated market prices. SCE is required to refund to customers 90% of any refunds actually realized by SCE, net of litigation costs, and 10% will be retained by SCE as a shareholder incentive.

During the course of the refund proceedings, the FERC ruled that governmental power sellers, like private generators and marketers that sold into the California market, should refund the excessive prices they received during the crisis period. However, on September 21, 2005, the Ninth Circuit ruled in Bonneville v. FERC that the FERC does not have authority directly to enforce its refund orders against governmental power sellers. The Court, however, clarified that its decision does not preclude SCE or other parties from pursuing civil claims against the governmental power sellers. On March 16, 2006, SCE, PG&E and the California Electricity Oversight Board jointly filed suit in federal court against several governmental power sellers, seeking damages based on the reduced prices set by the FERC for transactions during the crisis period. In March 2007, the federal court dismissed this suit concluding that the claims should have been filed in state court. SCE, along with PG&E, the Oversight Board and SDG&E, refiled on April 29, 2007 in the Los Angeles Superior Court. In addition, on March 12, 2007, SCE, PG&E and the Oversight Board filed a similar group of claims in the U.S. Court of Federal Claims against two federal agencies that sold power into California during the energy crisis. SCE cannot predict whether it may be able to recover any additional refunds from governmental power sellers as a result of these suits.

 

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On April 2, 2007, SCE, PG&E, SDG&E, the Oversight Board, the CPUC, and the California Attorney General (the California Parties), in anticipation of the Ninth Circuit remand of its rulings in Bonneville to the FERC for further action, filed pleadings at the FERC requesting that it order the California ISO and the PX to complete their calculations of refunds owed to purchasers by all sellers, including governmental sellers. On April 5, 2007, the Ninth Circuit issued the remand of Bonneville to the FERC. On April 17 and 18, 2007, several governmental power sellers filed pleadings at the FERC opposing the California Parties’ request and contending that Bonneville required FERC to order the California ISO and PX to immediately return collateral previously deposited by governmental sellers and pay receivables that governmental sellers claim are owed to them. This matter remains pending at the FERC.

In November 2005, SCE and other parties entered into a settlement agreement with Enron Corporation and a number of its affiliates, most of which are debtors in Chapter 11 bankruptcy proceedings pending in New York. In 2006, SCE received distributions of approximately $55 million on its allowed bankruptcy claim. In April 2007, SCE received and recorded an additional distribution on its allowed bankruptcy claim of approximately $12 million and 55,465 shares of Portland General Electric Company stock, with an aggregate value of less than $2 million. Additional distributions are expected but SCE cannot currently predict the amount or timing of such distributions.

On August 2, 2006, the Ninth Circuit issued an opinion regarding the scope of refunds issued by the FERC. The Ninth Circuit broadened the time period during which refunds could be ordered to include the summer of 2000 based on evidence of pervasive tariff violations and broadened the categories of transactions that could be subject to refund. As a result of this decision, SCE may be able to recover additional refunds from sellers of electricity during the crisis with whom settlements have not been reached.

Investigations Regarding Performance Incentives Rewards

SCE was eligible under its CPUC-approved PBR mechanism to earn rewards or penalties based on its performance in comparison to CPUC-approved standards of customer satisfaction, employee injury and illness reporting, and system reliability.

SCE conducted investigations into its performance under these PBR mechanisms and has reported to the CPUC certain findings of misconduct and misreporting as further discussed below.

Customer Satisfaction

SCE received two letters in 2003 from one or more anonymous employees alleging that personnel in the service planning group of SCE’s transmission and distribution business unit altered or omitted data in attempts to influence the outcome of customer satisfaction surveys conducted by an independent survey organization. The results of these surveys are used, along with other factors, to determine the amounts of any incentive rewards or penalties for customer satisfaction. SCE recorded aggregate customer satisfaction rewards of $28 million over the period 1997 – 2000. Potential customer satisfaction rewards aggregating $10 million for the years 2001 and 2002 are pending before the CPUC and have not been recognized in income by SCE. SCE also anticipated that it could be eligible for customer satisfaction rewards of approximately $10 million for 2003.

Following its internal investigation, SCE proposed to refund to ratepayers $7 million of the PBR rewards previously received and forgo an additional $5 million of the PBR rewards pending that are both attributable to the design organization’s portion of the customer satisfaction rewards for the entire PBR period (1997 – 2003). In addition, SCE also proposed to refund all of the approximately $2 million of customer satisfaction rewards associated with meter reading.

SCE has taken remedial action as to the customer satisfaction survey misconduct by disciplining and/or terminating certain employees, including several supervisory personnel, updating system process and related documentation for survey reporting, and implementing additional supervisory controls over data collection and processing. Performance incentive rewards for customer satisfaction expired in 2003 pursuant to the 2003 GRC.

 

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Employee Injury and Illness Reporting

In light of the problems uncovered with the customer satisfaction surveys, SCE conducted an investigation into the accuracy of SCE’s employee injury and illness reporting. The yearly results of employee injury and illness reporting to the CPUC are used to determine the amount of the incentive reward or penalty to SCE under the PBR mechanism. Since the inception of PBR in 1997, SCE has recognized $20 million in employee safety incentives for 1997 through 2000 and, based on SCE’s records, may be entitled to an additional $15 million for 2001 through 2003.

On October 21, 2004, SCE reported to the CPUC and other appropriate regulatory agencies certain findings concerning SCE’s performance under the PBR incentive mechanism for injury and illness reporting. SCE disclosed in the investigative findings to the CPUC that SCE failed to implement an effective recordkeeping system sufficient to capture all required data for first aid incidents.

As a result of these findings, SCE proposed to the CPUC that it not collect any reward under the mechanism and return to ratepayers the $20 million it had already received. SCE has also proposed to withdraw the pending rewards for the 2001 – 2003 time frames.

SCE has taken remedial action to address the issues identified, including revising its organizational structure and overall program for environmental, health and safety compliance, disciplining employees who committed wrongdoing and terminating one employee. SCE submitted a report on the results of its investigation to the CPUC on December 3, 2004.

System Reliability

In light of the problems uncovered with the PBR mechanisms discussed above, SCE conducted an investigation into the third PBR metric, system reliability. On February 28, 2005, SCE provided its final investigatory report to the CPUC concluding that the reliability reporting system is working as intended.

CPUC Investigation

On June 15, 2006, the CPUC instituted a formal investigation to determine whether and in what amounts to order refunds or disallowances of past and potential PBR rewards for customer satisfaction, employee safety and system reliability portions of PBR. The CPUC also may consider whether to impose additional penalties on SCE.

In June 2006, the CPSD of the CPUC issued its report regarding SCE’s PBR program, recommending that the CPUC impose various refunds and penalties on SCE. Subsequently, in September 2006, the CPSD and other intervenors, such as the CPUC’s Division of Ratepayer Advocates and The Utility Reform Network, filed testimony on these matters recommending various refunds and penalties to be imposed upon SCE. On October 16, 2006, SCE filed testimony opposing the various refund and penalty recommendations of the CPSD and other intervenors. Based on SCE’s proposal for refunds and the combined recommendations of the CPSD and other intervenors, the potential refunds and penalties could range from $52 million up to $388 million. SCE has recorded an accrual at the lower end of this range of potential loss and is accruing interest on collected amounts that SCE has proposed to refund to customers. Evidentiary hearings which addressed the planning and meter reading components of customer satisfaction, safety, issues related to SCE’s administration of the survey, and statutory fines associated with those matters took place in the fourth quarter of 2006. System reliability issues and the remaining customer satisfaction components of the investigation will be addressed in a second phase of the proceeding, which will commence with the filing of SCE’s opening testimony in September 2007. A Presiding Officer’s Decision has not yet been received on the issues addressed during phase one and SCE cannot predict when such decision will be issued. At this time, SCE cannot predict the outcome of these matters or reasonably estimate the potential amount of any additional refunds, disallowances, or penalties that may be required above the lower end of the range.

 

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Palo Verde Nuclear Generating Station Outage and Inspection

Between December 2005 when Palo Verde Unit 1 returned to service from its refueling and steam generator replacement outage and March 2006, Palo Verde Unit 1 operated at between 25% and 32% power level. The need to operate at a reduced power level was due to the vibration level in one of the unit’s shutdown cooling lines. On March 18, 2006, Arizona Public Service, the operating agent for Palo Verde Unit 1, removed the unit from service in order to resolve the problem. The vibration problem was resolved and Palo Verde Unit 1 was returned to service on July 7, 2006. Incremental replacement power costs incurred during the outage and periods of reduced power operation of approximately $32 million are expected to be recovered through the ERRA rate-making mechanism.

The NRC held three special inspections of Palo Verde, between March 2005 and February 2007. A follow-up to the first inspection resulted in a finding that Palo Verde had not established adequate measures to ensure that certain corrective actions were effective to address the root cause of the event. The second recent inspection identified five violations, but none of those resulted in increased NRC scrutiny. The most recent inspection, concerning the failure of an emergency backup generator at Palo Verde Unit 3 identified a violation that, combined with the first inspection finding, will cause the NRC to undertake additional oversight inspections of Palo Verde. In addition, Palo Verde will be required to take additional corrective actions, including surveys of its plant personnel and self-assessments of its programs and procedures, which will increase costs to both Palo Verde and its co-owners, including SCE. Because the surveys and self-assessments have not yet occurred and are critical to determining what other actions Palo Verde will need to take to address the NRC’s concerns, SCE cannot calculate the total increase in costs, but presently estimates that operation and maintenance costs at Palo Verde will increase by a minimum of $22 million per year through 2009. SCE also is unable to estimate how long SCE will continue to incur these costs.

SCE: MARKET RISK EXPOSURES

SCE’s primary market risks include fluctuations in interest rates, commodity prices and volumes, and counterparty credit. Fluctuations in interest rates can affect earnings and cash flows. Fluctuations in commodity prices and volumes and counterparty credit losses may temporarily affect cash flows, but are not expected to affect earnings due to expected recovery through regulatory mechanisms. SCE uses derivative financial instruments, as appropriate, to manage its market risks.

Commodity Price Risk

As discussed in the year-ended 2006 MD&A, SCE is exposed to commodity price risk associated with its purchases for additional capacity and ancillary services to meet its peak energy requirements as well as exposure to natural gas prices associated with power purchased from QFs, fuel tolling arrangements, and its own gas-fired generation, including the Mountainview plant.

SCE has an active hedging program in place to minimize ratepayer exposure to spot-market price spikes; however, to the extent that SCE does not mitigate the exposure to commodity price risk, the unhedged portion is subject to the risks and benefits of spot-market price movements, which are ultimately passed-through to ratepayers.

To mitigate SCE’s exposure to spot-market prices, SCE enters into energy options, tolling arrangements, and forward physical contracts. In the first quarter of 2007 SCE secured FTRs through the annual ISO auction. These FTRs provide SCE with scheduling priority in certain transmission grid congestion areas in the day-ahead market and qualify as derivative instruments. SCE also enters into contracts for power and gas options, as well as swaps and futures, in order to mitigate its exposure to increases in natural gas and electricity pricing. These transactions are pre-approved by the CPUC or executed in compliance with CPUC-approved procurement plans.

 

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SCE records its derivative instruments on its consolidated balance sheets at fair value unless they meet the definition of a normal purchase or sale. Certain derivative instruments do not meet the normal purchases and sales exception because demand variations and CPUC mandated resource adequacy requirements may result in physical delivery of excess energy that may not be in quantities that are expected to be used over a reasonable period in the normal course of business and may then be resold into the market. In addition, certain contracts do not meet the definition of clearly and closely related under SFAS No. 133 since pricing for certain renewable contracts is based on an unrelated commodity. The derivative instrument fair values are marked to market at each reporting period. Any fair value changes for recorded derivatives are recorded in purchased-power expense and offset through the provision for regulatory adjustment clauses – net; therefore, fair value changes do not affect earnings. Hedge accounting is not used for these transactions due to this regulatory accounting treatment. The following table summarizes the fair values of outstanding derivative financial instruments used at SCE to mitigate its exposure to spot market prices:

 

     June 30, 2007    December 31, 2006
In millions    Assets    Liabilities    Assets    Liabilities

Energy options

   $    $ 24    $    $ 10

FTRs

     89               

Forward physicals (power) and tolling arrangements

     15                1

Gas options, swaps and forward arrangements

  

 

     20           101

Total

   $   104    $   44    $   —    $   112

Quoted market prices, if available, are used for determining the fair value of contracts, as discussed above. If quoted market prices are not available, internally maintained standardized or industry accepted models are used to determine the fair value. The models are updated with spot prices, forward prices, volatilities and interest rates from regularly published and widely distributed independent sources.

The increase for the six months ended June 30, 2007 in net unrealized gains on economic hedging activities was primarily a result of changes in SCE's gas hedge portfolio mix. Due to expected recovery through regulatory mechanisms unrealized gains and losses may temporarily affect cash flows, but are not expected to affect earnings.

 

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EDISON MISSION GROUP INC.

EMG: LIQUIDITY

Liquidity

At June 30, 2007, EMG and its subsidiaries had cash and cash equivalents and short-term investments of $1.32 billion, EMG had a total of $989 million of available borrowing capacity under its credit facilities. EMG’s consolidated debt at June 30, 2007 was $4.09 billion. In addition, EME’s subsidiaries had $4.0 billion of long-term lease obligations related to the sale-leaseback transactions that are due over periods ranging up to 28 years.

Capital Expenditures

At June 30, 2007, the three-year estimated capital expenditures by EME’s subsidiaries related to existing projects, corporate activities and turbine commitments were as follows:

 

In millions    July
through
December
2007
   2008      2009

Illinois Plants

          

Plant capital expenditures

   $ 11    $ 45      $ 26

Environmental expenditures

     25      39        66

Homer City Facilities

          

Plant capital expenditures

     11      26        20

Environmental expenditures

     6      9        15

Wind and Thermal Projects

          

Projects under construction

     194            

Turbine commitments

     408      534        426

Corporate capital expenditures

     8      7        7

Total

   $   663    $   660      $   560

Expenditures for Existing Projects

Plant capital expenditures relate to non-environmental projects such as upgrades to boiler and turbine controls and dust collection/mitigation systems, a spare main power transformer, railroad interconnection and an expansion of a coal cleaning plant refuse site. Environmental expenditures relate to environmental projects such as mercury emission monitoring and control and SCR performance improvements at the Homer City facilities and various projects at the Illinois plants to achieve specified emissions reductions such as installation of mercury controls. EME plans to finance these expenditures with financings, cash on hand or cash generated from operations. See further discussion regarding these and possible additional capital expenditures, including environmental control equipment at the Homer City facilities, under “Edison International: Management’s Overview” and “Other Developments—Environmental Matters—Air Quality Standards,” and “—Clean Air Act—Illinois,” and “—Mercury Regulation” in the year-ended 2006 MD&A.

Expenditures for New Projects

EME expects to make substantial investments in new projects during the next three years. As of June 30, 2007, EME had a development pipeline of potential wind projects with an installed capacity of approximately 3,100 MW (the development pipeline represents potential projects which EME either owns the project rights or has exclusive negotiation rights). Completion of these projects is dependent upon a number of items which may include, depending on the project’s status, completion of a power sales agreement, permits, an interconnection agreement or other agreements necessary to start construction. Additional projects may from time to time be

 

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added to the development pipeline, and there is no assurance that the projects included in the development pipeline currently or added in the future will lead to the successful completion of a wind project.

Credit Ratings

Overview

Credit ratings for EMG’s direct and indirect subsidiaries at June 30, 2007, were as follows:

 

      Moody’s Rating    S&P Rating    Fitch Rating

EME

   B1    BB-    BB-

Midwest Generation

   Baa3    BB+    BBB-

EMMT

   Not Rated    BB-    Not Rated

Edison Capital

   Ba1    BB+    Not Rated

EMG 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. EMG 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.

Credit Rating of EMMT

The Homer City sale-leaseback documents restrict EME Homer City’s ability to enter into trading activities, as defined in the documents, with EMMT to sell forward the output of the Homer City facilities if EMMT does not have an investment grade credit rating from S&P or Moody’s or, in the absence of those ratings, if it is not rated as investment grade pursuant to EME’s internal credit scoring procedures. These documents include a requirement that the counterparty to such transactions, and EME Homer City, if acting as seller to an unaffiliated third party, be investment grade. EME currently sells all the output from the Homer City facilities through EMMT, which has a below investment grade credit rating, and EME Homer City is not rated. Therefore, in order for EME to continue to sell forward the output of the Homer City facilities, either: (1) EME must obtain consent from the sale-leaseback owner participant to permit EME Homer City to sell directly into the market or through EMMT; or (2) EMMT must provide assurances of performance consistent with the requirements of the sale-leaseback documents. EME has obtained a consent from the sale-leaseback owner participant that will allow EME Homer City to enter into such sales, under specified conditions, through December 31, 2008. EME Homer City continues to be in compliance with the terms of the consent. EME is permitted to sell the output of the Homer City facilities into the spot market at any time. See “EMG: Market Risk Exposures—Commodity Price Risk—Energy Price Risk Affecting Sales from the Homer City Facilities.”

Margin, Collateral Deposits and Other Credit Support for Energy Contracts

In connection with entering into contracts in support of EME’s hedging and energy trading activities (including forward contracts, transmission contracts and futures contracts), EME’s subsidiary, EMMT, has entered into agreements to mitigate the risk of nonperformance. EME has entered into guarantees in support of EMMT’s hedging and trading activities; however, because the credit ratings of EMMT and EME are below investment grade, EME has historically also provided collateral in the form of cash and letters of credit for the benefit of counterparties related to accounts payable and unrealized losses in connection with these hedging and trading activities. At June 30, 2007, EMMT had deposited $93 million in cash with brokers in margin accounts in

 

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support of futures contracts and had deposited $99 million with counterparties in support of forward energy and transmission contracts. In addition, EME had issued letters of credit of $32 million in support of commodity contracts at June 30, 2007.

Future cash collateral requirements may be higher than the margin and collateral requirements at June 30, 2007, if wholesale energy prices increase or the amount hedged increases. EME estimates that margin and collateral requirements for energy contracts outstanding as of June 30, 2007 could increase by approximately $260 million over the remaining life of the contracts using a 95% confidence level.

Midwest Generation has cash on hand and a $500 million working capital facility to support margin requirements specifically related to contracts entered into by EMMT related to the Illinois plants. At June 30, 2007, Midwest Generation had available $467 million of borrowing capacity under this credit facility. As of June 30, 2007, Midwest Generation had $68 million in loans receivable from EMMT for margin advances. In addition, EME has cash on hand and $522 million of borrowing capacity available under a $600 million working capital facility to provide credit support to subsidiaries. See “—EME’s Liquidity as a Holding Company” for further discussion.

Intercompany Tax-Allocation Agreement

EME and Edison Capital are included in the consolidated federal and combined state income tax returns of Edison International and are eligible to participate in tax-allocation payments with other subsidiaries of Edison International in circumstances where domestic tax losses are incurred. The right of EME and Edison Capital to receive and the amount of and timing of tax-allocation payments are dependent on the inclusion of EME and Edison Capital in the consolidated income tax returns of Edison International and its subsidiaries and other factors, including the consolidated taxable income of Edison International and its subsidiaries, the amount of net operating losses and other tax items of EMG’s subsidiaries, and other subsidiaries of Edison International and specific procedures regarding allocation of state taxes. EME and Edison Capital receive tax-allocation payments for tax losses when and to the extent that the consolidated Edison International group generates sufficient taxable income in order to be able to utilize EME’s or Edison Capital’s consolidated tax losses in the consolidated income tax returns for Edison International and its subsidiaries. Based on the application of the factors cited above, each of EME and Edison Capital is obligated during periods it generates taxable income, to make payments under the tax-allocation agreements. EME made tax-allocation payments to Edison International of $156 million and $162 million during the first six months of 2007 and 2006, respectively. Edison Capital received net tax-allocation payments from Edison International of $80 million and $64 million during the first six months of 2007 and 2006, respectively.

Dividend Restrictions in Major Financings

General

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

 

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Key Ratios of EMG’s Principal Subsidiaries Affecting Dividends

Set forth below are key ratios of EMG’s principal subsidiaries required by financing arrangements at June 30, 2007 or for the twelve months ended June 30, 2007:

 

Subsidiary   Financial Ratio   Covenant    Actual

Midwest Generation
(Illinois plants)

 

Debt to Capitalization Ratio

 

Less than or equal to
0.60 to 1

   0.24 to 1

EME Homer City
(Homer City facilities)

 

Senior Rent Service Coverage Ratio

 

Greater than 1.7 to 1

   2.64 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—MEHC’s Dividend Restrictions in Major Financings” in the year ended December 31, 2006.

Edison Capital’s ability to make dividend payments is currently restricted by covenants in its financial instruments, which require Edison Capital, through a wholly owned subsidiary, to maintain a specified minimum net worth of $200 million. Edison Capital satisfied this minimum net worth requirement as of June 30, 2007.

EMG: OTHER DEVELOPMENTS

Challenges of Illinois Power Procurement Auction Results

EMMT participated successfully in the first Illinois power procurement auction, held in September 2006 according to rules approved by the Illinois Commerce Commission, and entered into two load requirements services contracts through which it is delivering electricity, capacity and specified ancillary, transmission and load following services necessary to serve a portion of Commonwealth Edison’s residential and small commercial customer load, using contracted supply from Midwest Generation.

EMG believes that EMMT’s actions in regard to the Illinois auction were appropriate and lawful and intends to defend vigorously all of the matters described below. However, at this time EMG cannot predict the outcome of these matters.

FERC Complaint

On March 16, 2007, the Office of the Attorney General for the State of Illinois filed a complaint at the FERC alleging that the prices resulting from the Illinois auction resulted in unjust and unreasonable rates under the Federal Power Act and that participating wholesale sellers in the Illinois auction had colluded and manipulated the results of the auction. All successful participants in the Illinois auction, including EMMT, were named as respondents. The Office of the Attorney General asked the FERC to order refunds and to revoke the respondents’ market-based rate pricing authority. On July 24, 2007, Midwest Generation and EMMT, along with other power generation companies and utilities, entered into a settlement agreement with the Illinois Attorney General. The settlement is subject to enacting legislation. See “EMG: Current Developments—Illinois Settlement” for further discussion.

Class Action Lawsuits

On April 4, 2007, EMMT was served with a complaint filed in the Circuit Court of Cook County, Illinois, by Saul R. Wexler, individually and on behalf of an alleged class of similarly situated electric ratepayers in Illinois, against Commonwealth Edison, Ameren, and all of the successful participants in the Illinois auction, including EMMT. The lawsuit alleges that the defendants, including EMMT, colluded and conspired to manipulate the auction results by price-fixing. The lawsuit seeks unspecified damages. On April 26, 2007, the defendants

 

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transferred the complaint to the U.S. District Court for the Northern District of Illinois, Eastern Division. On June 4, 2007, the defendants filed a motion to dismiss the case, which remains pending.

On March 30, 2007, David Schafer, Tim Perry, Pat Martin and Michael Murray, individually and on behalf of an alleged class of similarly situated electric ratepayers in Illinois, filed a complaint in the Circuit Court of Cook County, Illinois, against Commonwealth Edison, Ameren, and all of the successful participants in the Illinois auction, including EMMT. EMMT has not been formally served in the case. The lawsuit alleges that the defendants, including EMMT, colluded and conspired to manipulate the auction results by price-fixing. The lawsuit seeks unspecified damages. On April 26, 2007, the defendants transferred the complaint to the U.S. District Court for the Northern District of Illinois, Eastern Division. On June 4, 2007, the defendants filed a motion to dismiss the case, which remains pending.

PJM Matters

As previously reported, on December 22, 2006, the FERC issued an order conditionally approving the RPM settlement subject to PJM making certain compliance filings. The compliance filings were made by PJM on January 22, 2007 and February 20, 2007, and accepted by the FERC on June 25, 2007 and July 11, 2007, respectively. On June 1, 2007, PJM implemented marginal losses for transmission for its competitive wholesale electric market. For further discussion regarding the RPM and recent auctions, see “EMG: Market Risk Exposures—Capacity Price Risk.” EME is still evaluating the impact that marginal loss pricing in PJM will have on its results of operations, but continues to believe that it may reduce locational marginal prices for some of its units relative to the locational marginal prices for the benchmark locations of Western Hub and Northern Illinois Hub.

PJM Competitive Wholesale Electric Market

On June 1, 2007, PJM implemented marginal losses for transmission for its competitive wholesale electric market. EME is still evaluating the impact that marginal loss pricing in PJM will have on its results of operations, but continues to believe that it may reduce locational marginal prices for some of its units relative to the locational marginal prices for the benchmark locations of Western Hub and Northern Illinois Hub.

Midwest Generation Potential Environmental Proceeding

On July 31, 2007, the US EPA issued a NOV to Midwest Generation and Commonwealth Edison. In the NOV, the US EPA alleges that, beginning in the early 1990’s and into 2003, Midwest Generation or Commonwealth Edison performed construction projects at six Illinois coal-fired electric generating stations in violation of the Prevention of Significant Deterioration requirements and of the New Source Performance Standards of the Clean Air Act, including alleged requirements to obtain a construction permit and to install Best Available Control Technology at the time of the projects. The US EPA also alleges that Midwest Generation and Commonwealth Edison violated certain operating permit requirements under Title V of the Clean Air Act. Finally, the US EPA alleges violations of certain opacity and particulate matter standards at the Illinois Plants. The US EPA has invited Midwest Generation and Commonwealth Edison to meet with the US EPA by August 30, 2007 to discuss the alleged violations. Midwest Generation is investigating the claims made by the US EPA in the NOV and potential responses and cannot predict at this time what effect this matter may have on its facilities, its results of operations or financial position.

Federal Income Taxes

Edison International received Revenue Agent Reports from the IRS in August 2002 and in January 2005 asserting deficiencies in federal corporate income taxes with respect to audits of its 1994 to 1996 and 1997 to 1999 tax years, respectively. Among the issues raised were items related to Edison Capital. See “Other Developments—Federal and State Income Taxes” for further discussion of these matters.

 

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EMG: MARKET RISK EXPOSURES

Introduction

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

Commodity Price Risk

Overview

EME’s revenues and results of operations of its merchant power plants will depend upon prevailing market prices for capacity, energy, ancillary services, emission allowances or credits, coal, natural gas and fuel oil, and associated transportation costs in the market areas where EME’s merchant plants are located. Among the factors that influence the price of energy, capacity and ancillary services in these markets are:

 

 

prevailing market prices for coal, natural gas and fuel oil, and associated transportation;

 

 

the extent of additional supplies of capacity, energy and ancillary services from current competitors or new market entrants, including the development of new generation facilities and/or technologies that may be able to produce electricity at a lower cost than EME’s generating facilities and/or increased access by competitors to EME’s markets as a result of transmission upgrades;

 

 

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

 

 

the market structure rules established for each market area and regulatory developments affecting the market areas, including any price limitations and other mechanisms adopted to address volatility or illiquidity in these markets or the physical stability of the system;

 

 

the cost and availability of emission credits or allowances;

 

 

the availability, reliability and operation of competing power generation facilities, including nuclear generating plants, where applicable, and the extended operation of such facilities beyond their presently expected dates of decommissioning;

 

 

weather conditions prevailing in surrounding areas from time to time; and

 

 

changes in the demand for electricity or in patterns of electricity usage as a result of factors such as regional economic conditions and the implementation of conservation programs.

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

Introduction

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

In addition to prevailing market prices, EME’s ability to derive profits from the sale of electricity will be affected by the cost of production, including costs incurred to comply with environmental regulations. The costs of

 

57


production of the units vary and, accordingly, depending on market conditions, the amount of generation that will be sold from the units is expected to vary.

EME uses “value at risk” to identify, measure, monitor and control its overall market risk exposure in respect of its Illinois plants, its Homer City facilities, and its trading positions. The use of value at risk allows management to aggregate overall commodity risk, compare risk on a consistent basis and identify the risk factors. Value at risk measures the possible loss over a given time interval, under normal market conditions, at a given confidence level. Given the inherent limitations of value at risk and relying on a single risk measurement tool, EME supplements this approach with the use of stress testing and worst-case scenario analysis for key risk factors, as well as stop-loss limits and counterparty credit exposure limits.

Hedging Strategy

To reduce its exposure to market risk, EME hedges a portion of its merchant portfolio risk through EMMT, an EME subsidiary engaged in the power marketing and trading business. To the extent that EME does not hedge its merchant portfolio, the unhedged portion will be subject to the risks and benefits of spot market price movements. Hedge transactions are primarily implemented through:

 

 

the use of contracts cleared on the Intercontinental Trading Exchange and the New York Mercantile Exchange,

 

 

forward sales transactions entered into on a bilateral basis with third parties, including electric utilities and power marketing companies,

 

 

full requirements services contracts or load requirements services contracts for the procurement of power for electric utilities’ customers, with such services including the delivery of a bundled product including, but not limited to, energy, transmission, capacity, and ancillary services, generally for a fixed unit price, and

 

 

participation in capacity auctions.

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

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

Energy Price Risk Affecting Sales from the Illinois Plants

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

Midwest Generation sells its power into PJM at spot prices based upon locational marginal pricing. Hedging transactions related to the generation of the Illinois plants are generally entered into at the Northern Illinois Hub

 

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in PJM, and may also be entered into at other trading hubs, including the AEP/Dayton Hub in PJM and the Cinergy Hub in the MISO. These trading hubs have been the most liquid locations for hedging purposes. However, hedging transactions which settle at points other than the Northern Illinois Hub are subject to the possibility of basis risk. See “—Basis Risk” below for further discussion.

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

The following table depicts the average historical market prices for energy per megawatt-hour during the first six months of 2007 and 2006.

 

     24-Hour
Northern Illinois Hub
Historical Energy Prices(1)
      2007    2006

January

   $ 35.75    $ 42.27

February

     56.64      42.66

March

     42.04      42.50

April

     48.91      43.16

May

     44.49      39.96

June

     39.76      34.80

Six-Month Average

   $   44.60    $   40.89

 

  (1) Energy prices were calculated at the Northern Illinois Hub delivery point using hourly real-time prices as published by PJM.  

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

The following table sets forth the forward market prices for energy per megawatt-hour as quoted for sales into the Northern Illinois Hub at June 30, 2007:

 

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

2007

  

July

   $ 45.87

August

     50.61

September

     37.31

October

     36.18

November

     38.48

December

     44.63

2008 Calendar “strip”(2)

   $   46.09

 

  (1) Energy prices were determined by obtaining broker quotes and information from other public sources relating to the Northern Illinois Hub delivery point.  

 

  (2) Market price for energy purchases for the entire calendar year, as quoted for sales into the Northern Illinois Hub.  

 

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The following table summarizes Midwest Generation’s hedge position (primarily based on prices at the Northern Illinois Hub) at June 30, 2007:

      2007    2008    2009

Energy Only Contracts(1)

        

MWh

   8,250,150    10,837,600    2,048,000

Average price/MWh(2)

   $   48.07    $  61.38    $  60.00

Load Requirements Services Contracts

        

Estimated MWh(3)

   4,071,803    5,613,433    1,631,859

Average price/MWh(4)

   $  64.35    $  64.01    $  63.65

Total estimated MWh

     12,321,953      16,451,033      3,679,859

 

  (1) Primarily at Northern Illinois Hub.  

 

  (2) The energy only contracts 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 position at June 30, 2007 is not directly comparable to the 24-hour Northern Illinois Hub prices set forth above.  

 

  (3) Under a load requirements services contract, the amount of power sold is a portion of the retail load of the purchasing utility and thus can vary significantly with variations in that retail load. Retail load depends upon a number of factors, including the time of day, the time of the year and the utility’s number of new and continuing customers. Estimated MWh have been forecast based on historical patterns and on assumptions regarding the factors that may affect retail loads in the future. The actual load will vary from that used for the above estimate, and the amount of variation may be material.  

 

  (4) The average price per MWh under a load requirements services contract (which is subject to a seasonal price adjustment) represents the sale of a bundled product that includes, but is not limited to, energy, capacity and ancillary services. Furthermore, as a supplier of a portion of a utility’s load, Midwest Generation will incur charges from PJM as a load-serving entity. For these reasons, the average price per MWh under a load requirements services contract is not comparable to the sale of power under an energy only contract. The average price per MWh under a load requirements services contract represents the sale of the bundled product based on an estimated customer load profile.  

Energy Price Risk Affecting Sales from the Homer City Facilities

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

 

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The following table depicts the average historical market prices for energy per megawatt-hour at the Homer City busbar and in PJM West Hub (EME Homer City’s primary trading hub) during the first six months of 2007 and 2006:

 

      Historical Energy Prices(1) 24-Hour PJM
      Homer City          West Hub
      2007    2006          2007    2006

January

   $ 40.30    $ 48.67       $ 44.63    $ 54.57

February

     64.27      49.54         73.93      56.39

March

     55.00      53.26         61.02      58.30

April

     52.42      48.50         58.74      49.92

May

     48.12      44.71         53.89      48.55

June

     45.88      38.78         60.19      45.78

Six-Month Average

   $   51.00    $   47.24       $   58.73    $   52.25

 

  (1) Energy prices were calculated at the Homer City busbar (delivery point) and PJM West Hub using historical hourly real-time prices provided on the PJM-ISO web-site.  

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

The following table sets forth the forward market prices for energy per megawatt-hour as quoted for sales into the PJM West Hub at June 30, 2007:

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

2007

  

July

   $ 64.02

August

     69.02

September

     49.57

October

     48.52

November

     50.71

December

     57.24

2008 Calendar “strip”(2)

   $   62.36

 

  (1) Energy prices were determined by obtaining broker quotes and information from other public sources relating to the PJM West Hub delivery point. Forward prices at PJM West Hub are generally higher than the prices at the Homer City busbar.  

 

  (2) Market price for energy purchases for the entire calendar year, as quoted for sales into the PJM West Hub.  

 

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The following table summarizes Homer City’s hedge position at June 30, 2007:

      2007    2008    2009

MWh

   3,820,375    7,232,000    2,048,000

Average price/MW(1)

   $  64.24    $  60.86    $  71.05

 

  (1) The above hedge positions include forward contracts for the sale of power 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 position at June 30, 2007 is not directly comparable to the 24-hour PJM West Hub prices set forth above.  

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

Capacity Price Risk

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

The first auction took place in April 2007 and resulted in a fixed price for Midwest Generation and EME Homer City’s capacity sold into the auction (included in PJM as “rest of market” location) of $40.80/MW per day for the period from June 1, 2007 through May 31, 2008. The second auction took place in July 2007 and resulted in a fixed price for Midwest Generation and EME Homer City’s capacity sold into the auction of $111.92/MW per day for the period from June 1, 2008 through May 31, 2009. Subsequent auctions will be conducted in October 2007 and January 2008 to auction capacity for periods through May 2011.

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

Prior to the RPM auctions for the revelant delivery periods, EME Homer City sold a portion of its capacity to an unrelated third party for the delivery periods from June 1, 2007 through May 31, 2008 and June 1, 2008 through May 31, 2009. EME Homer City will not receive the RPM auction clearing price for this previously sold capacity. The price EME Homer City will receive for these capacity sales is a function of NYISO capacity clearing prices resulting from separate NYISO capacity auctions.

 

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The following table summarizes the status of capacity sales for Midwest Generation and EME Homer City at July 27, 2007:

 

     July 1, 2007 to May 31, 2008        June 1, 2008 to May 31, 2009
      Midwest
Generation
   EME Homer
City
        Midwest
Generation
   EME Homer
City

Fixed Price Capacity Sales

             

Through RPM Auction, Net

             

MW

  

 

2,625

     786     

 

3,283

     820

Price per MW-day

   $   40.80    $   40.80      $   111.92    $   111.92

Non-unit Specific Capacity Sales

             

MW

     500             880     

Price per MW-day

   $ 21.29          

$

64.35

    

Variable Capacity Sales

             

MW

          870             881

Price per MW-day(1)

        $ 69.39             $ 72.56

 

(1) Actual contract price is a function of NYISO capacity auction clearing prices. Capacity price per MW-day is based on forward over-the-counter NYISO prices on July 27, 2007.

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

Basis Risk

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

 

 

sales of actual generation in the amounts covered by the forward contracts with reference to PJM spot prices at the busbar of the plant involved, plus,

 

 

sales to third parties at the price under such hedging contracts at designated settlement points (generally the PJM West Hub for the Homer City facilities and the Northern Illinois Hub for the Illinois plants) less the cost of power at spot prices at the same designated settlement points.

Under PJM’s market design, locational marginal pricing, which establishes market prices at specific locations throughout PJM by considering factors including generator bids, load requirements, transmission congestion and losses, can cause the price of a specific delivery point to be higher or lower relative to other locations depending on how the point is affected by transmission constraints. To the extent that, on the settlement date of a hedge

 

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contract, spot prices at the relevant busbar are lower than spot prices at the settlement point, the proceeds actually realized from the related hedge contract are effectively reduced by the difference. This is referred to as “basis risk.” During the six months ended June 30, 2007, 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%, compared to 10% during the six months ended June 30, 2006. The monthly average difference during the 12 months ended June 30, 2007 ranged from 3% to 24%. In contrast to the Homer City facilities, during the past 12 months, the prices at the Northern Illinois Hub were substantially the same as those at the individual busbars of the Illinois plants.

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

Coal Price Risk

The Illinois plants and the Homer City facilities purchase coal primarily obtained from the Southern PRB of Wyoming and from mines located near the facilities in Pennsylvania, respectively. Coal purchases are made under a variety of supply agreements extending through 2010. The following table summarizes the amount of coal under contract at June 30, 2007 for the remainder of 2007 and the following three years.

 

      Amount of Coal Under Contract
in Millions of Tons(1)
      July
through
December
2007
   2008    2009    2010

Illinois plants

   9.2    14.6    11.7    11.7

Homer City facilities

   2.7    4.3    3.5    0.2

 

  (1) The amount of coal under contract in tons is calculated based on contracted tons and applying an 8,800 Btu equivalent for the Illinois plants and 13,000 Btu equivalent for the Homer City facilities.  

EME is subject to price risk for purchases of coal that are not under contract. Prices of NAPP coal, which are related to the price of coal purchased for the Homer City facilities, increased during the first six months of 2007 from 2006 year-end prices. The price of NAPP coal (with 13,000 Btu per pound heat content and <3.0 pounds of SO2 per MMBtu sulfur content) increased to $45.15 per ton at June 29, 2007 from $43.00 per ton at December 15, 2006, as reported by the Energy Information Administration. The 2007 increase in the NAPP coal price was in line with normal market price volatility. Prices of PRB coal (with 8,800 Btu per pound heat content and 0.8 pounds of SO2 per MMBtu sulfur content), which is purchased for the Illinois plants decreased during the first six months of 2007 from 2006 year-end prices due to continuing high stockpiles and oversupply of market. The price of PRB coal decreased from $9.90 per ton at December 15, 2006 to $9.15 per ton at June 29, 2007, as reported by the Energy Information Administration.

Emission Allowances Price Risk

The federal Acid Rain Program requires electric generating stations to hold SO2 allowances, and Illinois and Pennsylvania regulations implemented the federal NOX SIP Call requirement. As part of the acquisition of the Illinois plants and the Homer City facilities, EME obtained the rights to the emission allowances that have been or are allocated to these plants. EME purchases (or sells) emission allowances based on the amounts required for

 

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actual generation in excess of (or less than) the amounts allocated under these programs. The average price of purchased SO2 allowances decreased to $517 per ton during the first six months of 2007 from $664 per ton during 2006. The price of SO2 allowances, determined by obtaining broker quotes and information from other public sources, was $544 per ton as of July 31, 2007.

For a discussion of environmental regulations related to emissions, refer to “Other Developments” in the year-ended 2006 MD&A.

Accounting for Energy Contracts

EME uses a number of energy contracts to manage exposure from changes in the price of electricity, including forward sales and purchases of physical power and forward price swaps which settle only on a financial basis (including futures contracts). EME follows SFAS No. 133, and under this Standard these energy contracts are generally defined as derivative financial instruments. Importantly, SFAS No. 133 requires changes in the fair value of each derivative financial instrument to be recognized in earnings at the end of each accounting period unless the instrument qualifies for hedge accounting under the terms of SFAS No. 133. For derivatives that do qualify for cash flow hedge accounting, changes in their fair value are recognized in other comprehensive income until the hedged item settles and is recognized in earnings. However, the ineffective portion of a derivative that qualifies for cash flow hedge accounting is recognized currently in earnings. For further discussion of derivative financial instruments, see “Critical Accounting Estimates—Derivative Financial Instruments and Hedging Activities” in the year ended December 31, 2006.

SFAS No. 133 affects the timing of income recognition, but has no effect on cash flow. To the extent that income varies under SFAS No. 133 from accrual accounting (i.e., revenue recognition based on settlement of transactions), EME records unrealized gains or losses. EME classifies unrealized gains and losses from energy contracts as part of operating revenues. The results of derivative activities are recorded as part of cash flows from operating activities in the consolidated statements of cash flows. The following table summarizes unrealized gains (losses) from non-trading activities for the second quarters of 2007 and 2006 and six months ended June 30, 2007 and 2006:

 

      Three Months Ended
June 30,
    Six Months Ended
June 30,
In millions    2007     2006     2007     2006

Non-qualifying hedges

        

Illinois plants

   $ 4     $ 2     $ (18 )   $ 10

Homer City

     2       4       1       2

Ineffective portion of cash flow hedges

        

Illinois Plants

           (1 )           1

Homer City

       (5 )     5       (3 )     2

Total unrealized gains (losses)

   $ 1     $   10     $   (20 )   $   15

Fair Value of Financial Instruments

Non-Trading Derivative Financial Instruments

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

 

In millions    June 30,
2007
   December 31,
2006

Commodity price:

     

Electricity

   $   1    $   184

 

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In assessing the fair value of EME’s non-trading derivative financial instruments, EME uses a variety of methods and assumptions based on the market conditions and associated risks existing at each balance sheet date. The fair value of commodity price contracts takes into account quoted market prices, time value of money, volatility of the underlying commodities and other factors. The decrease in fair value of electricity contracts at June 30, 2007 as compared to December 31, 2006 is attributable to an increase in the average market prices for power as compared to contracted prices at June 30, 2007, which is the valuation date. The following table summarizes the maturities and the related fair value, based on actively traded prices, of EME’s commodity derivative assets and liabilities as of June 30, 2007:

 

In millions    Total
Fair
Value
   Maturity
<1 year
   Maturity
1 to 3
years
    Maturity
4 to 5
years
   Maturity
>5 years

Prices actively quoted

   $   1    $   43    $    (42)   $   —    $   —

Energy Trading Derivative Financial Instruments

The fair value of the commodity financial instruments related to energy trading activities as of June 30, 2007 and December 31, 2006, are set forth below:

 

     June 30, 2007    December 31, 2006
In millions    Assets    Liabilities    Assets    Liabilities

Electricity

   $   142    $   18    $   313    $   207

Other

               5     
Total    $ 142    $ 18    $ 318    $ 207

The change in the fair value of trading contracts for the six months ended June 30, 2007, was as follows:

 

In millions        

Fair value of trading contracts at January 1, 2007

   $   111  

Net gains from energy trading activities

     65  

Amount realized from energy trading activities

     (58 )

Other changes in fair value

     6  
Fair value of trading contracts at June 30, 2007    $ 124  

Quoted market prices are used to determine the fair value of the financial instruments related to energy trading activities, except for the power sales agreement with an unaffiliated electric utility that EME’s subsidiary purchased and restructured and a long-term power supply agreement with another unaffiliated party. EME’s subsidiary recorded these agreements at fair value based upon a discounting of future electricity prices derived from a proprietary model using a discount rate equal to the cost of borrowing the non-recourse debt incurred to finance the purchase of the power supply agreement. The following table summarizes the maturities, the valuation method and the related fair value of energy trading assets and liabilities (as of June 30, 2007):

 

In millions    Total
Fair
Value
   Maturity
<1 year
   Maturity
1 to 3
years
   Maturity
4 to 5
years
   Maturity
>5 years

Prices actively quoted

   $ 41    $   37    $ 4    $   —    $   —

Prices based on models and other valuation methods

     83      3      14      20      46
Total    $   124    $ 40    $   18    $ 20    $ 46

 

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Credit Risk

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

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

The credit risk exposure from counterparties of merchant energy activities (excluding load requirements services contracts) are measured as either: (i) the sum of 60 days of accounts receivable, current fair value of open positions, and a credit value at risk, or (ii) the sum of delivered and unpaid accounts receivable and the current fair value of open positions. EME’s subsidiaries enter into master agreements and other arrangements in conducting hedging and trading activities which typically provide for a right of setoff in the event of bankruptcy or default by the counterparty. Accordingly, EME’s credit risk exposure from counterparties is based on net exposure under these agreements. At June 30, 2007, the amount of exposure as described above, broken down by the credit ratings of EME’s counterparties, was as follows:

 

In millions    June 30, 2007

S&P Credit Rating

  

A or higher

   $ 19

A-

     18

BBB+

     80

BBB

     31

BBB-

     2

Below investment grade

    
Total    $   150

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

In addition, coal for the Illinois plants and the Homer City facilities is purchased from suppliers under contracts which may be for multiple years. A number of the coal suppliers to the Illinois plants and the Homer City facilities do not currently have an investment grade credit rating and, accordingly, EME may have limited recourse to collect damages in the event of default by a supplier. EME seeks to mitigate this risk through

 

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diversification of its coal suppliers and through guarantees and other collateral arrangements when available. Despite this, there can be no assurance that these efforts will be successful in mitigating credit risk from coal suppliers.

EME’s merchant plants sell electric power generally into the PJM market by participating in PJM’s capacity and energy markets or transact capacity and energy on a bilateral basis. Sales into PJM accounted for approximately 49% of EME’s consolidated operating revenues for the six months ended June 30, 2007. Moody’s rates PJM’s senior unsecured debt Aa3. PJM, an ISO with over 300 member companies, maintains its own credit risk policies and does not extend unsecured credit to non-investment grade companies. Any losses due to a PJM member default are shared by all other members based upon a predetermined formula. At June 30, 2007, EME’s account receivable due from PJM was $86 million.

Beginning in January 2007, EME also derived a significant source of its revenues from the sale of energy, capacity and ancillary services generated at the Illinois plants to Commonwealth Edison under load requirements services contracts. Sales under these contracts accounted for 19% of EME’s consolidated operating revenues during the six months ended June 30, 2007. Commonwealth Edison’s senior unsecured debt rating was downgraded below investment grade by S&P in October 2006 and by Moody’s in March 2007. As a result, Commonwealth Edison is required to pay EME twice a month for sales under these contracts. At June 30, 2007, EME’s account receivable due from Commonwealth Edison was $21 million. Commonwealth Edison has stated that it would face possible bankruptcy if an electric rate freeze, which expired January 1, 2007, was re-introduced. In addition, the Illinois Attorney General and other parties have appeals pending before the Illinois Supreme Court pertaining to the Illinois Commerce Commission orders which authorized Commonwealth Edison and Ameren to procure power through a reverse auction process. On July 24, 2007, Midwest Generation and EMMT, along with other power generation companies and utilities, entered into a settlement agreement with the Illinois Attorney General. The settlement is subject to enacting legislation. See “EMG: Current Developments—Illinois Settlement” for further discussion. EME is unable to predict whether the settlement agreement will be implemented as contemplated or that the legislation necessary for the settlement to become effective, or other policy changes affecting utility rates or procurement practices, will be enacted.

Edison Capital’s investments may be affected by the financial condition of other parties, the performance of the asset, economic conditions and other business and legal factors. Edison Capital generally does not control operations or management of the projects in which it invests and must rely on the skill, experience and performance of third party project operators or managers. These third parties may experience financial difficulties or otherwise become unable or unwilling to perform their obligations. Edison Capital’s investments generally depend upon the operating results of a project with a single asset. These results may be affected by general market conditions, equipment or process failures, disruptions in important fuel supplies or prices, or another party’s failure to perform material contract obligations, and regulatory actions affecting utilities purchasing power from the leased assets. Edison Capital has taken steps to mitigate these risks in the structure of each project through contract requirements, warranties, insurance, collateral rights and default remedies, but such measures may not be adequate to assure full performance. In the event of default, lenders with a security interest in the asset may exercise remedies that could lead to a loss of some or all of Edison Capital’s investment in that asset.

Interest Rate Risk

Interest rate changes can affect earnings and the cost of capital for capital improvements or new investments in power projects. EME mitigates the risk of interest rate fluctuations by arranging for fixed rate financing or variable rate financing with interest rate swaps, interest rate options or other hedging mechanisms for a number of its project financings. The fair market values of long-term fixed interest rate obligations are subject to interest rate risk. The fair market value of EME’s consolidated long-term obligations (including current portion) was $3.8 billion at June 30, 2007, compared to the carrying value of $4.0 billion.

 

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Foreign Exchange Rate Risk

EME is exposed to foreign currency risk associated with the purchase of certain turbines in which a portion of the purchase price is denominated in Japanese yen. Under the terms of the related agreement, EME has the option of fixing the foreign currency rate pertaining to the 2009 turbines through August 30, 2007. See “EMG: Current Developments—Business Development.”

Edison Capital holds a minority interest as a limited partner in three separate funds that invest in infrastructure assets in Latin America, Asia and countries in Europe with emerging economies. As of June 30, 2007, Edison Capital had investments in Latin America, Asia and Emerging Europe of $19 million, $15 million and $17 million, respectively. Edison Capital, through these investments, is exposed to foreign exchange risk in the currency of the ultimate investment.

Edison Capital’s cross-border leases are denominated in U.S. dollars and, therefore, are not exposed to foreign current rate risk.

 

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EDISON INTERNATIONAL (PARENT)

EDISON INTERNATIONAL (PARENT): LIQUIDITY

The parent company’s liquidity and its ability to pay interest and principal on debt, if any, operating expenses and dividends to common shareholders are affected by dividends and other distributions from subsidiaries, tax-allocation payments under its tax-allocation agreements with its subsidiaries, and access to capital markets or external financings. As of June 30, 2007, Edison International had no debt outstanding (excluding intercompany related debt).

Edison International (parent)’s cash requirements for the 12-month period following June 30, 2007 primarily consist of:

 

 

Dividends to common shareholders. On February 22, 2007, the Board of Directors of Edison International declared a $0.29 per share quarterly dividend which was paid in April 2007; On April 26, 2007 the Board of Directors of Edison International declared a $0.29 per share quarterly dividend which was paid in July 2007;

 

 

Intercompany related debt; and

 

 

General and administrative expenses.

Edison International (parent) expects to meet its continuing obligations through cash and cash equivalents on hand, borrowings, when necessary, and dividends from its subsidiaries. At June 30, 2007, Edison International (parent) had approximately $124 million of cash and cash equivalents on hand. On February 23, 2007, Edison International amended its credit facility, increasing the amount of borrowing capacity to $1.5 billion and extending the maturity to February 2012. At June 30, 2007, the entire credit facility was available for liquidity purposes. The ability of subsidiaries to make dividend payments to Edison International is dependent on various factors as described below.

SCE may pay dividends to Edison International subject to CPUC restrictions. The CPUC regulates SCE’s capital structure by requiring that SCE maintain prescribed percentages of common equity, preferred equity and long-term debt in the utility’s capital structure. SCE may not make any distributions to Edison International that would reduce the common equity component of SCE’s capital structure below the authorized level on a 13-month weighted average basis (see “SCE: Liquidity—Dividend Restrictions and Debt Covenants” for further discussion). The CPUC also requires that SCE establish its dividend policy as though it were a comparable stand-alone utility company and give first priority to the capital requirements of the utility as necessary to meet its obligation to serve its customers. Other factors at SCE that affect the amount and timing of dividend payments by SCE to Edison International include, among other things, SCE’s capital requirements, SCE’s access to capital markets, payment of dividends on SCE’s preferred and preference stock, and actions by the CPUC. SCE made dividend payments to Edison International of $60 million in January 2007, and $25 million in April 2007. On April 26, 2007, the Board of Directors of SCE declared a $25 million dividend which was paid to Edison International in July 2007.

EMG’s ability to pay dividends is dependent on its subsidiaries ability to pay dividends to EMG. EME’s corporate credit facility contains covenants that restrict its ability, and the ability of several of its subsidiaries, to pay dividends in the case of any event of default under the facility. As of June 30, 2007, EME was not in default under its credit facility. In addition, see “EMG Liquidity—Dividend Restrictions in Major Financings” section for further discussion. EMG has not declared or made dividend payments to Edison International in 2007. In April 2007, EMG made a $131 million dividend payment to Edison International and on June 26, 2007, the Board of Directors of EMG declared a $107 million dividend which was paid to Edison International in July 2007.

EDISON INTERNATIONAL (PARENT): OTHER DEVELOPMENTS

Federal and State Income Taxes

Edison International received Revenue Agent Reports from the IRS in August 2002 and in January 2005 asserting deficiencies in federal corporate income taxes with respect to audits of its 1994 to 1996 and 1997 to 1999 tax years, respectively. Edison International has protested certain issues which are currently being addressed at the IRS administration appeals phase of the audit. See “Other Developments—Federal and State Income Taxes” for further discussion of these matters.

 

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EDISON INTERNATIONAL (CONSOLIDATED)

The following sections of the MD&A are on a consolidated basis and should be read in conjunction with individual subsidiary discussion.

RESULTS OF OPERATIONS AND HISTORICAL CASH FLOW ANALYSIS

The following subsections of “Results of Operations and Historical Cash Flow Analysis” provide a discussion on the changes in various line items presented on the Consolidated Statements of Income, as well as a discussion of the changes on the Consolidated Statements of Cash Flows.

Results of Operations

The table below presents Edison International’s earnings and earnings per common share for the three- and six-month periods ended June 30, 2007 and 2006, and the relative contributions by its subsidiaries.

 

In millions, except per-share amounts      Earnings (Loss)     

Earnings (Loss)

per Share

 
Three-Month Period Ended June 30,      2007      2006      2007      2006  

Earnings (Loss) from Continuing Operations:

             

SCE

     $   144      $   234      $   0.44      $   0.72  

EMG

       (49 )      (56 )      (0.15 )      (0.17 )

Edison International (parent) and other

       (4 )      (5 )      (0.01 )      (0.02 )

Edison International Consolidated Earnings

from Continuing Operations

       91        173        0.28        0.53  

Earnings from Discontinued Operations

       2        4        0.01        0.01  
Edison International Consolidated      $ 93      $ 177      $ 0.29      $ 0.54  

 

In millions, except per-share amounts      Earnings (Loss)     

Earnings (Loss)

per Share

 
Six-Month Period Ended June 30,      2007      2006      2007      2006  

Earnings (Loss) from Continuing Operations:

             

SCE

     $   325      $   355      $   1.00      $   1.09  

EMG

       106        17        0.33        0.05  

Edison International (parent) and other

       (10 )      (15 )      (0.05 )      (0.06 )

Edison International Consolidated Earnings

from Continuing Operations

       421        357        1.28        1.08  

Earnings from Discontinued Operations

       5        77        0.01        0.24  

Cumulative Effect of Accounting Change

              1                
Edison International Consolidated      $   426      $   435      $   1.29      $   1.32  

Earnings (Loss) from Continuing Operations

Edison International’s earnings from continuing operations were $91 million and $421 million for the three- and six-month periods ended June 30, 2007, respectively, compared with earnings of $173 million and $357 million for the comparable periods in 2006.

SCE’s earnings from continuing operations were $144 million and $325 million for the three- and six-month periods ended June 30, 2007, compared to $234 million and $355 million for the respective periods in 2006. SCE’s quarter and year-to-date earnings decreased due to an $81 million benefit from the resolution of an outstanding issue involving a portion of revenue collected during 2001 – 2003 related to state income taxes recorded in 2006. The second quarter earnings also decreased by $9 million primarily due to the catch-up adjustment upon receipt of the 2006 GRC decision in May 2006, which was effective back to January 12, 2006,

 

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partially offset by the favorable resolution of an outstanding state income tax issue. The year-to-date decrease was partially offset by a $31 million tax benefit primarily reflecting progress on an appeal with the IRS related to the income tax treatment of costs associated with environmental remediation recorded in 2007 and increased earnings of approximately $20 million mainly due to higher revenue associated with the 2006 GRC decision and lower income taxes from the favorable resolution of an outstanding state income tax issue.

EMG’s losses from continuing operations were $49 million and $56 million for the three-month period ended June 30, 2007 and 2006, respectively. EMG’s earnings from continuing operations were $106 million and $17 million for the six-month periods ended June 30, 2007, and 2006, respectively. EMG’s quarter and year-to-date variances reflect after-tax charges of $148 million and $88 million in 2007 and 2006, respectively, associated with early extinguishment of debt related to EMG’s debt refinancing. These charges were partially offset by increases of $67 million and $149 million for the three- and six-month periods ended June 30, 2007, respectively, primarily due to an increase in energy margins at EMG’s Midwest Generation driven by higher generation and average realized energy prices, and higher earnings from Edison Capital. The $149 million increase also reflects higher energy margins at EMG’s Homer City due to higher average realized energy prices and generation.

Operating Revenue

Electric Utility Revenue

The following table sets forth the major changes in electric utility revenue:

 

In millions    Three Months
Ended June 30,
2007 vs. 2006
   

Six Months

Ended June 30,
2007 vs. 2006

 

Electric utility revenue

    

Rate changes and impact of tiered
rate structure (including unbilled)

   $  (148 )   $  (29 )

Sales volume changes (including unbilled)

   (2 )   71  

Balancing account over/under collections

   30     (98 )

Sales for resale

   42     11  

SCE’s VIEs

   25     1  

Other (including inter company transactions)

   (9 )   (14 )
Total    $  (62 )   $  (58 )

SCE’s retail sales represented approximately 87% of electric utility revenue for both the three- and six-month periods ended June 30, 2007, respectively, compared to approximately 89% for both comparable periods in 2006. Due to warmer weather during the summer months, electric utility revenue during the third quarter of each year is generally significantly higher than other quarters.

Total electric utility revenue decreased by $62 million and $58 million for the three- and six-month periods ended 2007, respectively (as shown in the table above). The variances for the revenue components are as follows:

 

 

Electric utility revenue from rate changes decreased for the three- and six-month periods ended June 30, 2007, mainly due to the impact of warmer weather experienced in the later part of second quarter of 2006 resulting in increased volumes sold at a higher rate due to SCE’s tiered rate structure. The year-to-date decrease was partially offset by increased rates in early 2007, compared to the same period in 2006. Effective February 14, 2007, SCE’s system average rate decreased to 13.9¢-per-kWh (including 3.0¢ per-kWh related to CDWR) mainly as the result of estimated lower natural gas prices in 2007, as well as the refund of overcollections in the ERRA balancing account that occurred in 2006 from lower than expected natural gas prices and higher than expected summer 2006 kWh sales (see “SCE: Regulatory Matters—Current Regulatory Developments—Impact of Regulatory Matters on Customer Rates,” and “—Energy Resource Recovery Account Proceedings” for further discussion of these rate changes);

 

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Electric utility revenue resulting from sales volume changes for the six months ended 2007 was mainly due to an increase in customer growth, partially offset by decreased sales volume resulting from the warmer weather experienced in the later part of second quarter of 2006;

 

 

SCE recognizes revenue, subject to balancing account treatment, equal to the amount of the actual costs incurred and up to its authorized revenue requirement. Any revenue collected in excess of actual costs incurred or above the authorized revenue requirement is not recognized as revenue and is deferred and recorded as regulatory liabilities to be refunded in future customer rates. Costs incurred in excess of revenue billed are deferred in a balancing account and recorded as regulatory assets for recovery in future customer rates. Balancing account over/undercollections represent these differences. For the three- and six-month periods ended June 30, 2007, SCE collected revenue in excess of actual costs incurred and as a result deferred approximately $44 million and $65 million, respectively. For the three months ended June 30, 2006, SCE collected revenue in excess of actual costs incurred and as a result deferred approximately $74 million, and for the six months ended June 30, 2006, SCE recognized approximately $34 million of revenue. The variance is mainly due to the impact of overcollections in 2006;

 

 

Electric utility revenue from sales for resale represents the sale of excess energy. Excess energy from SCE sources which may exist at certain times is resold in the energy markets. Sales for resale revenue increased due to higher excess energy in 2007, compared to the same periods in 2006. Revenue from sales for resale is refunded to customers through the ERRA balancing account and does not impact earnings; and

 

 

SCE’s VIEs revenue represents the recognition of revenue resulting from the consolidation of four gas-fired power plants where SCE is considered the primary beneficiary. These VIEs affect SCE’s revenue, but do not affect earnings; the increase in revenue from SCE’s VIEs during the second quarter of 2007 was primarily due to payments received in settlement of claims related to natural gas purchase contracts, a planned outage at one of the projects in 2006, partially offset by lower volumes sold in 2007 for one of the projects.

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 none of these collections are recognized as revenue by SCE. These amounts were $503 million and $1.1 billion for the three- and six-month periods ended June 30, 2007, respectively, compared to $553 million and $1.1 billion for the same respective periods in 2006.

Nonutility Power Generation Revenue

Nonutility power generation revenue increased $109 million and $271 million for the three- and six-month periods ended June 30, 2007.

Nonutility power generation revenue from EMG’s Illinois plants increased $68 million and $153 million for the three- and six-month periods ended June 30, 2007. The 2007 increase was mainly due to higher energy revenues resulting from higher generation and average realized energy prices as compared to 2006. The year-to-date increase was partially offset by unrealized losses of $18 million compared to unrealized gains of $11 million for the same period in 2006. Unrealized gains (losses) are primarily due to power contracts that did not qualify for hedge accounting under SFAS No. 133. These energy contracts were entered into to hedge the price risk related to projected sales of power. During 2007, power prices increased, resulting in mark-to-market losses on economic hedges. At June 30, 2007, unrealized losses of $11 million were recognized primarily from economic hedges related to subsequent periods. See “EMG: Market Risk Exposures—Commodity Price Risk” for more information regarding forward market prices.

Nonutility power generation from EMG’s Homer City facilities increased $25 million and $100 million for the three- and six-month periods ended June 30, 2007, respectively. The 2007 increase was primarily attributable to higher generation and average realized energy prices. On January 29, 2006, the main power transformer on Unit 3

 

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of the EMG Homer City facilities failed resulting in a suspension of operations at this unit. Homer City secured a replacement transformer and Unit 3 returned to service on May 5, 2006. The Unit 3 outage reduced the amount of generation during the six months ended June 30, 2006.

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

Operating Expenses

Fuel Expense

 

      Three Months
Ended June 30,
   Six Months
Ended June 30,
In millions    2007    2006    2007    2006

SCE

   $   285    $   237    $   595    $   548

EMG

     153      143      329      292
Edison International Consolidated    $ 438    $ 380    $ 924    $ 840

 

SCE’s fuel expense increased $48 million and $47 million for the three- and six-month periods ended June 30, 2007, respectively, as compared to the same periods in 2006. The quarter and year-to-date increases were mainly due to higher fuel expense at Mountainview of $20 million and $40 million for the three- and six-month periods ended June 30, 2007, respectively, due in part to an increase in natural gas prices. Also contributing to the increases was higher nuclear fuel expense of $10 million and $20 million, for the three- and six-month periods ended June 30, 2007, respectively, resulting primarily from a planned refueling and maintenance outage at SCE’s San Onofre Unit 2 in 2006. The quarter increase also reflects higher fuel expense of $25 million primarily related to one of the SCE VIE projects driven by a planned outage that occurred during the second quarter of 2006.

EMG’s fuel expense increased $10 million and $37 million for the three- and six-month periods ended June 30, 2007, respectively, mainly due to higher generation, partially offset by lower costs of SO2 allowances at EMG’s Homer City facilities.

Purchased-Power Expense

The following is a summary of purchased-power expense:

 

      Three Months
Ended June 30,
    Six Months
Ended June 30,
 
In millions    2007     2006     2007     2006  

Purchased-power from bilateral contracts, QFs, ISO, and exchange energy

   $   787     $   706     $   1,237     $   1,321  

Unrealized (gains) / losses on economic hedging activities

     45       9       (89 )     342  

Realized (gains) / losses on economic hedging activities

     23       91       52       166  

Energy settlements and refunds

     (26 )     (37 )     (54 )     (46 )
Total purchased-power expense    $ 829     $ 769     $ 1,146     $ 1,783  

 

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Purchased-power expense increased $60 million for the three months ended June 30, 2007 and decreased $637 million for the six months ended June 30, 2007, as compared to the same periods in 2006. The increase for the three months ended June 30, 2007 was mainly due to higher QF purchased power expense of approximately $60 million resulting from an increase in the average spot natural gas prices (as discussed further below), higher costs for ISO-related energy purchases of $30 million, and higher net unrealized losses on economic hedging activities of $36 million, primarily due to lower forward natural gas prices in the second quarter of 2007, compared to the same period in 2006. Due to expected recovery through regulatory mechanisms unrealized gains and losses may temporarily affect cash flows, but are not expected to affect earnings. The quarter variance reflects net realized losses on economic hedging activities of $23 million for the three months ended June 30, 2007 compared to net realized losses of $91 million for the same period in 2006. The year-to-date variance reflects net realized losses of $52 million for the six months ended June 30, 2007 compared to net realized losses of $166 million for the same period in 2006. The year-to-date variance reflects net unrealized gains on economic hedging activities of $89 million, compared to net unrealized losses on economic hedging activities of $342 million for the same period in 2006 (see “SCE: Market Risk Exposures—Commodity Price Risk” for further discussion). The changes in net unrealized (gains)/losses primarily resulted from changes in SCE’s gas hedge portfolio mix. In addition, the year-to-date decrease was due to lower ISO-related purchases of approximately $80 million resulting from lower kWh purchases, and lower firm related purchases of approximately $30 million.

Federal law and CPUC orders required SCE to enter into contracts to purchase power from QFs at CPUC-mandated prices. Energy payments to gas-fired QFs are generally tied to spot natural gas prices. Energy payments for most renewable QFs are at a fixed price of 5.37¢-per-kWh. In late 2006, certain renewable QF contracts were amended and energy payments for these contracts are at a fixed price of 6.15¢-per-kWh, effective May 2007.

Provisions for Regulatory Adjustment Clauses – Net

Provisions for regulatory adjustment clauses – net decreased $23 million and increased $626 million for the three- and six-month periods ended June 30, 2007, respectively, as compared to the same periods in 2006. The quarter and year-to-date variances reflect net unrealized losses on economic hedging activities of $45 million and $9 million for three-month periods ended June 30, 2007 and 2006, respectively, and net unrealized gains on economic hedging activities of approximately $89 million for the six-month period ended June 30, 2007, compared to $342 million of net unrealized losses for the same period last year (mentioned above in purchased-power expense). The quarter and year-to-date variances also reflect the resolution of a $135 million one-time gain related to a portion of revenue collected during the 2001 – 2003 period related to state income taxes recorded in the second quarter of 2006. The quarter decrease also reflects a change from net overcollections in 2006 to net undercollections for the same period in 2007 of $175 million primarily related to lower revenue resulting from the impact of warmer weather experienced in the later part of the second quarter of 2006 and lower rates. The year-to-date increase also reflects lower net undercollections of purchased-power, fuel, and operation and maintenance expense of approximately $15 million resulting from higher sales and lower procurement costs for the six-month period ended June 30, 2007, compared to the same period in 2006 (see “SCE: Regulatory Matters—Current Regulatory Developments—Impacts of Regulatory Matters on Customer Rates,” and “Energy Resource Recovery Account Proceedings” for further discussion of these rate changes).

 

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Other Operation and Maintenance Expense

 

      Three Months
Ended June 30,
   Six Months
Ended June 30,
In millions    2007    2006    2007    2006

SCE

   $ 715    $ 690    $ 1,372    $ 1,359

EMG

     273      238      493      442

Edison International (parent) and other

     11      5      14      17
Edison International Consolidated    $   999    $   933    $   1,879    $   1,818

SCE’s other operation and maintenance expense increased $25 million and $13 million for the three- and six-month periods ended June 30, 2007, respectively, as compared to the same periods in 2006. The quarter and year-to-date increases were mainly due to higher demand-side management and energy efficiency costs of approximately $35 million and $60 million for the three- and six-month periods ended June 30, 2007, respectively, (which are recovered through regulatory mechanisms approved by the CPUC) and higher benefit-related costs of $15 million for both the quarter and year-to-date periods. These increases were partially offset by lower must-run and must-offer obligation costs of $30 million and $40 million for the three- and six-month periods ended June 30, 2007 related to the reliability of the California ISO systems and higher generation-related costs of approximately $30 million for the six months ended June 30, 2007 resulting from the planned refueling and maintenance outages at SCE’s San Onofre Units 2 and 3 in the first quarter 2006. As a result of implementation of the 2006 GRC, beginning in May 2006, costs related to Mohave shutdown, postretirement benefits other than pensions and results sharing are being recovered through a balancing account mechanism.

EMG’s other operation and maintenance expense increased $35 million and $51 million for the three- and six-month periods ended June 30, 2007, respectively, mainly due to higher planned maintenance costs at EMG’s Illinois plants as well as EMG’s Homer City facilities related to the planned outage at Unit 2.

Depreciation, Decommissioning and Amortization Expense

 

      Three Months
Ended June 30,
   Six Months
Ended June 30,
In millions    2007    2006    2007    2006

SCE

   $ 271    $ 300    $ 546    $ 552

EMG

     42      39      80      79

Edison International (parent) and other

               1     
Edison International Consolidated    $   313    $   339    $   627    $   631

SCE’s depreciation, decommissioning and amortization expense decreased $29 million and $6 million for the three- and six-month periods ended June 30, 2007, respectively, compared to the same periods in 2006 primarily related to depreciation related to transmission and distribution assets and SCE’s decommissioning trusts.

The depreciation expense related to SCE’s transmission and distribution assets decreased approximately $15 million and increased $15 million for the three- and six-month periods ended June 30, 2007, respectively. The quarter decrease was mainly due to the implementation of the new depreciation rates approved in the 2006 GRC decision for the period January 12, 2006 through May 31, 2006 which resulted in increased depreciation expense recorded in the second quarter of 2006. The quarter and year-to-date variances reflect increased depreciation expense resulting from additions to transmission and distribution assets.

SCE’s decommissioning expense decreased $5 million and $20 million for the three- and six-month periods ended June 30, 2007, respectively, compared to the same periods in 2006. The decrease primarily resulted from

 

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other-than-temporary impairment losses associated with the nuclear decommissioning trust funds, which, due to its regulatory treatment, are recorded in electric utility revenue and are offset in decommissioning expense. As a result, these investment earnings have no impact on net income.

Other Income and Deductions

Interest and dividend income

 

      Three Months
Ended June 30,
   Six Months
Ended June 30,
In millions    2007    2006    2007    2006

SCE

   $ 8    $ 13    $ 17    $ 26

EMG

     36      28      66      52

Edison International (parent) and other

     1      2      2      2
Edison International Consolidated    $   45    $   43    $   85    $   80

SCE’s interest income decreased $5 million and $9 million for the three- and six-month periods ended June 30, 2007, respectively, compared to the same periods in 2006, mainly due to lower interest income resulting from lower balancing account undercollections in 2007, as compared to 2006.

EMG’s interest and dividend income increased $8 million and $14 million for the three- and six-month periods ended June 30, 2007, respectively, compared to the same periods in 2006. The increase was mainly due to $10 million for the three- and six-month periods ended June 30, 2007, of dividend income from EMG’s Doga project.

Equity in Income from Partnerships and Unconsolidated Subsidiaries – Net

Equity in income from partnerships and unconsolidated subsidiaries – net increased $10 million and $23 million for the three- and six-month periods ended June 30, 2007, respectively, compared to the same period in 2006. The 2007 increase was mainly due to higher earnings of $13 million and $18 million for the three- and six-month periods ended June 30, 2007, respectively, from Edison Capital’s global infrastructure funds.

Other Nonoperating Income

 

      Three Months
Ended June 30,
   Six Months
Ended June 30,
In millions    2007     2006    2007     2006

SCE

   $ 23     $ 19    $ 40     $ 46

EMG

     (1 )     14      (1 )     28
Edison International Consolidated    $   22     $   33    $   39     $   74

SCE’s other nonoperating income increased $6 million and decreased $5 million for the three- and six-month periods ended June 30, 2007, compared to the same periods in 2006. The variance was mainly due to an increase in allowance for funds used during construction – equity of approximately $3 million and $10 million for the three- and six-month periods ended June 30, 2007, respectively, resulting from an increase in construction work in progress due to planned capital expenditures (see “SCE: Liquidity—Capital Expenditures” for further discussion). The year-to-date increase was offset by an incentive reward in 2006 related to the efficient operation of Palo Verde compared to no incentive rewards in 2007 as a result of the incentive program ending in 2006. The incentive reward approved by the CPUC for the efficient operation of Palo Verde was $13 million in the first quarter of 2006.

 

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EMG’s other nonoperating income decreased $15 million and $29 million for the three- and six-month periods ended June 30, 2007, compared to the same period in 2006. The quarter and year-to-date decreases reflect the recognition of an estimated business interruption insurance claim in the amount of approximately $11 million. The year-to-date decrease also reflects an $8 million gain related to the receipt of shares from Mirant Corporation from settlement of a claim and a $4 million gain resulting from EMG’s sale of 25% of its ownership interest in the San Juan Mesa wind project to Citi Renewable Investments I LLC, both recognized in the first quarter of 2006.

Interest Expense—Net of Amounts Capitalized

 

      Three Months
Ended June 30,
   Six Months
Ended June 30,
In millions    2007    2006    2007    2006

SCE

   $ 105    $ 102    $ 213    $ 199

EMG

     82      106      171      209

Edison International (parent) and other

     1      1      2      1
Edison International Consolidated    $   188    $   209    $   386    $   409

SCE’s interest expense – net of amounts capitalized increased $3 million and $14 million for the three- and six-month periods ended June 30, 2007, respectively, mainly due to higher interest expense on balancing account overcollections in 2007, as compared to 2006. The increase was also due to higher interest expense on long-term debt resulting from higher balances outstanding as of June 30, 2007, compared to the same period in 2006.

EMG’s interest expense—net of amounts capitalized decreased $24 million and $38 million for the three- and six-month periods ended June 30, 2007, respectively, compared to the same periods in 2006 mainly due to the MEHC and EME repayment of debt in May 2007 (See EMG: Current Developments—Refinancing) and an increase in capitalized interest in 2007 related to wind projects under construction.

Income Tax Expense (Benefit)—Continuing Operations

 

      Three Months
Ended June 30,
    Six Months
Ended June 30,
 
In millions    2007     2006     2007     2006  

SCE

   $ 61     $   145     $ 114     $ 228  

EMG

       (54 )     (51 )     22       (19 )

Edison International (parent) and other

     (7 )     1       (7 )     (3 )
Edison International Consolidated    $     $ 95     $   129     $   206  

Edison International’s composite federal and state statutory income tax rate was approximately 40% (net of the federal benefit for state income taxes) for all periods presented. Edison International’s effective tax rate from continuing operations was 0% and 23% for the three- and six-month periods ended June 30, 2007, respectively, as compared to 35% and 37% for the respective periods in 2006. The decreased effective tax rate was primarily caused by reductions made to the income tax reserve at SCE during the first quarter of 2007 to reflect progress in an administrative appeal process with the IRS related to the income tax treatment of costs associated with environmental remediation and also due to a $15 million reduction made to the income tax reserves during the second quarter of 2007 to reflect settlement of a state tax issue related to the April 2007 state Notice of Proposed Adjustment discussed in “Other Developments—Federal and State Income Taxes.” Additional decreases to the 2007 effective tax rate resulted from accruing lower tax reserve interest expense at SCE in 2007, as compared to 2006, as a result of implementing FIN 48 and from year over year changes in property related flow-through items at SCE. In addition, the low effective tax rate in the second quarter of 2007 resulted from a reduction in pre-tax income.

 

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Income from Discontinued Operations

Edison International’s earnings from discontinued operations were $2 million and $5 million for the three- and six-month periods ended June 30, 2007, respectively, compared to $4 million and $77 million for the same periods in 2006. The earnings primarily are related to EMG’s former international projects.

Cumulative Effect of Accounting Change—Net of Tax

Effective January 1, 2006, Edison International adopted SFAS No. 123(R) that requires the fair value accounting method for stock-based compensation. Implementation of SFAS No. 123(R) resulted in a $1 million, after-tax, cumulative-effect adjustment in the first quarter of 2006.

 

Historical Cash Flow Analysis

The “Historical Cash Flow Analysis” section of this MD&A discusses consolidated cash flows from operating, financing and investing activities.

Cash Flows from Operating Activities

Net cash provided by operating activities:

 

In millions    Six-Month Period
Ended June 30,
          2007            2006    

Continuing operations

   $   1,229    $ 976

Discontinued operations

     5      82
     $ 1,234    $   1,058

Cash provided by operating activities from continuing operations increased $253 million in the first six months of 2007, compared to the first six months of 2006. The 2007 change reflects an increase of $119 million in required margin and collateral deposits in the first half of 2007 for EMG’s hedging and trading activities, compared to a decrease of $363 million in the first half of 2006. The change resulted from an increase in forward market prices in 2007 compared to 2006. The 2007 change was also due to the timing of cash receipts and disbursements related to working capital items.

Cash provided by operating activities from discontinued operations decreased $77 million in the first six months of 2007, compared to the same period in 2006. The 2007 decrease reflects higher distributions received in 2006, compared to 2007, from EMG’s Lakeland power project. See “Discontinued Operations” in the year-ended 2006 MD&A for more information regarding these distributions.

Cash Flows from Financing Activities

Net cash provided (used) provided by financing activities:

 

In millions    Six-Month Period
Ended June 30,
          2007            2006    
Continuing operations    $  (453)    $   212

Cash provided (used) by financing activities from continuing operations mainly consisted of long-term and short-term debt issuances (payments) at SCE and EMG.

Financing activities in 2007 were as follows:

 

 

During the first half of 2007 SCE’s net issuances of commercial paper classified as short-term debt was $175 million;

 

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In May 2007, EME issued $2.7 billion of senior notes, which was mostly used to repay $587 million of EME’s outstanding senior notes, repay $1 billion of Midwest Generation’s second priority senior secured notes, fund a dividend to MEHC which purchased approximately $796 million of its 13.5% senior secured notes, and repay $328 million of Midwest Generation’s senior secured term loan facility. In addition, EME and MEHC paid tender premiums and financing costs of $239 million related to the debt refinancing; and

 

 

Financing activities in 2007 include dividend payments of $189 million paid by Edison International to its shareholders.

Financing activities in the first quarter of 2006 included activities related to the rebalancing of SCE’s capital structure and rate base growth and the reduction of debt at EMG, as follows:

 

 

In January 2006, SCE issued $500 million of first and refunding mortgage bonds which consisted of $350 million of 5.625% bonds due in 2036 and $150 million of floating rate bonds due in 2009. The proceeds from this issuance were used in part to redeem $150 million of variable rate first and refunding mortgage bonds due in January 2006 and $200 million of its 6.375% first and refunding mortgage bonds due in January 2006;

 

 

In January 2006, SCE issued two million shares of 6% Series C preference stock (noncumulative, $100 liquidation value) and received net proceeds of $196 million;

 

 

In April 2006, SCE issued $331 million of tax-exempt bonds which consisted of $196 million of 4.10% bonds which are subject to remarketing in April 2013 and $135 million of 4.25% bonds which are subject to remarketing in November 2016. The proceeds from this issuance were used to call and redeem $196 million of tax-exempt bonds due February 2008 and $135 million of tax-exempt bonds due March 2008. This transaction was treated as a noncash financing activity;

 

 

In June 2006, EME issued $1 billion of senior notes. The proceeds from this issuance along with cash on hand were used to repay $965 million of EME’s outstanding senior notes and to pay $136 million for tender premiums and related fees; and

 

 

Financing activities in 2006 also included dividend payments of $176 million paid by Edison International to its shareholders.

Cash Flows from Investing Activities

Cash flows from investing activities are affected by capital expenditures, EME’s sales of assets and SCE’s funding of nuclear decommissioning trusts.

Net cash used by investing activities for the first six months of the year was $1.4 billion in 2007 and $1.3 billion in 2006.

Investing activities in 2007 reflect $1.1 billion in capital expenditures at SCE, primarily for transmission and distribution assets, including approximately $28 million for nuclear fuel acquisitions, and $244 million in capital expenditures at EMG. Investing activities also include net maturities and sales of marketable securities of $240 million at EMG and $11 million in payments made towards the purchase price of the Wildorado wind project during the second quarter of 2007.

Investing activities in 2006 reflect $1.1 billion in capital expenditures at SCE, primarily for transmission and distribution assets, including approximately $50 million for nuclear fuel acquisitions and approximately $8 million related to the Mountainview plant, and $118 million in capital expenditures at EMG largely related to the wind projects. In addition, investing activities include net maturities and sales of marketable securities of $76 million at EMG and received proceeds of $43 million from the sale of 25% of EME’s ownership interest in the San Juan Mesa wind project. EMG also paid $18 million towards the purchase price of the Wildorado wind project during the first quarter of 2006.

 

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NEW ACCOUNTING PRONOUNCEMENTS

Accounting Pronouncement Adopted

In July 2006, the FASB issued FIN 48 which clarifies the accounting for uncertain tax positions. FIN 48 requires an enterprise to recognize, in its financial statements, the best estimate of the impact of a tax position by determining if the weight of the available evidence indicates it is more likely than not, based solely on the technical merits, that the position will be sustained on audit. Edison International adopted FIN 48 effective January 1, 2007. Implementation of FIN 48 resulted in a cumulative-effect adjustment that increased retained earnings by $250 million upon adoption. Edison International will continue to monitor and assess new income tax developments including the IRS’ challenge of the sale/leaseback and lease/leaseback transactions discussed in “Other Developments—Federal and State Income Taxes.”

In July 2006, the FASB issued an FSP on accounting for a change in timing of cash flows related to income taxes generated by a leverage lease transaction (FSP FAS 13-2). Edison International adopted FSP FAS 13-2 effective January 1, 2007. The adoption did not have a material impact on Edison International’s consolidated financial statements.

Accounting Pronouncements Not Yet Adopted

In April 2007, the FASB issued FIN 39-1. FIN 39-1 amends paragraph 3 of FIN No. 39 to replace the terms conditional contracts and exchange contracts with the term derivative instruments as defined in SFAS No. 133. FIN 39-1 also states that under master netting arrangements if collateral is based on fair value, then it must be netted with the fair value of derivative assets/liabilities if an entity qualified and elected the option to net those amounts. Edison International will adopt FIN 39-1 on January 1, 2008. Adoption of this position will result in netting a portion of margin and cash collateral deposits with derivative liabilities on Edison International’s consolidated balance sheets, but will have no impact on Edison International’s consolidated statements of income.

In February 2007, the FASB issued SFAS No. 159, which provides an option to report eligible financial assets and liabilities at fair value, with changes in fair value recognized in earnings. Upon adoption, the first remeasurement to fair value would be reported as a cumulative-effect adjustment to the opening balance of retained earnings. Edison International will adopt SFAS No. 159 on January 1, 2008. Edison International is currently evaluating whether it will opt to report any financial assets and liabilities at fair value and the impact, if adopted, on its consolidated financial statements.

In September 2006, the FASB issued SFAS No. 157, which clarifies the definition of fair value, establishes a framework for measuring fair value and expands the disclosures on fair value measurements. Edison International will adopt SFAS No. 157 on January 1, 2008. Edison International is currently evaluating the impact of adopting SFAS No. 157 on its financial statements.

COMMITMENTS, GUARANTEES AND INDEMNITIES

Long-Term Debt

As of June 30, 2007, Edison International’s long-term debt maturities (including forecast interest payments) and sinking fund requirements for the next five years are: 2007 – $731 million; 2008 – $593 million; 2009 – $719 million; 2010 – $844 million; 2011 – $541 million. These amounts have been updated primarily to reflect EME’s financing activities completed during the second quarter of 2007. See “EMG: Current Developments—Refinancing” for additional details.

Fuel Supply Contracts

Midwest Generation and EME Homer City have entered into additional fuel purchase commitments during the first six months of 2007. These additional commitments are currently estimated to be $6 million for the remainder of 2007, $208 million in 2008, $153 million in 2009, and $77 million in 2010.

 

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SCE entered into service contracts associated with uranium enrichment and fuel fabrication during the first six months of 2007. SCE’s fuel supply commitments for the remainder of 2007 are estimated to be $143 million.

Gas and Coal Transportation

Midwest Generation has contractual agreements for the transport of coal to its facilities. The primary contract is with Union Pacific Railroad (and various delivering carriers) which extends through 2011. Midwest Generation’s commitments under this contract are based on actual coal purchases from the PRB. Accordingly, contractual obligations for transportation are based on coal volumes set forth in fuel supply contracts. The increase in transportation commitments entered into during the first six months of 2007 relates to additional volumes of fuel purchases using the terms of existing transportation agreements. These commitments are currently estimated to be $8 million for the remainder of 2007, $110 million for 2008, $75 million for 2009, and $77 million for 2010.

Operating and Capital Leases

SCE entered into a new operating lease for a power contract during the first six months of 2007. SCE’s additional operating lease commitments for this new power contract are estimated to be $68 million for 2008 and $114 million for each of the years 2009, 2010, and 2011.

SCE executed a power purchase contract in June 2007 which met the requirements for capital leases. As of June 30, 2007, the capital lease requires future minimum lease payments of $28 million (approximately $1 million per year) through May 2027. As of June 30, 2007, the executory costs and imputed interest for this capital lease are $11 million and $7 million, respectively.

Turbine Commitments

At June 30, 2007, EME had entered into agreements with vendors securing 669 wind turbines (1,414 MW) with remaining commitments of $382 million in 2007, $534 million in 2008, and $426 million in 2009.

In addition, EME had entered into an agreement to purchase five gas turbines and related equipment for an aggregate purchase price of approximately $145 million. In June 2007, EME entered into a change order agreement with the seller of the turbines reducing the number of gas turbines to four with a remaining commitment of $26 million at June 30, 2007. In addition, EME recorded $21 million included in other current assets in Edison International’s consolidated balance sheet with respect to a refund of the turbine payments. Subsequent to June 30, 2007, EME entered into additional change order agreements reducing the number of gas turbines to one. EME expects to receive refunds totaling $92 million during the third quarter of 2007 with respect to the four turbines.

Capital Improvements

At June 30, 2007, EME’s subsidiaries had firm commitments to spend approximately $229 million during the remainder of 2007 and $24 million in 2008 on capital and construction expenditures. The majority of these expenditures relate to the construction of wind projects. Also included are expenditures for dust collection and mitigation system and environmental improvements. These expenditures are planned to be financed by cash on hand, cash generated from operations or existing subsidiary credit agreements.

OTHER DEVELOPMENTS

Environmental Matters

The operating affiliates of Edison International are subject to numerous federal and state environmental laws and regulations, which require them 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. Edison International believes that its operating affiliates are in substantial compliance with existing environmental regulatory requirements.

 

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The domestic power plants owned or operated by Edison International’s operating affiliates, in particular their coal-fired plants, may be affected by recent developments in federal and state environmental laws and regulations. These laws and regulations, including those relating to SO2 and NOx emissions, mercury emissions, ozone and fine particulate matter emissions, regional haze, water quality, and climate change, may require significant capital expenditures at these facilities. The developments in certain of these laws and regulations are discussed in more detail below. These developments will continue to be monitored to assess what implications, if any, they will have on the operation of domestic power plants owned or operated by SCE, EME, or their subsidiaries, or the impact on Edison International’s results of operations or financial position.

For a discussion of Edison International’s environmental matters, refer to “Other Developments—Environmental Matters” in the year-ended 2006 MD&A. There have been no significant developments with respect to environmental matters affecting Edison International since the filing of Edison International’s Annual Report on Form 10-K, except as follows:

Air Quality Regulation

Clean Air Act

Illinois—

The Combined Pollutant Standard, filed on January 5, 2007 in the pending state rulemaking related to the Illinois SIP for the Clean Air Interstate Rule and previously reported as expected to become final in the spring of 2007, is currently expected to become final in the summer or early fall of 2007. The Illinois Pollution Control Board published a first notice order for the proposed Combined Pollutant Standard and Clean Air Interstate Rule rules on May 11, 2007. The written comment period, which follows the first notice order, expired on June 25, 2007. The Board published a second notice order on July 26, 2007. The second notice order marks the beginning of review by the Joint Committee on Administrative Rules, the final stage of rulemaking in Illinois.

Water Quality Regulation

Clean Water Act—Cooling Water Intake Structures

On July 9, 2007, the US EPA published in the Federal Register a notice immediately suspending the requirements for cooling water intake structures, pending further rulemaking. The US EPA is expected to begin another rulemaking process in October 2007. Although the rule to be generated in the new rulemaking process could have a material impact on Edison International’s operations, its compliance criteria have not yet been finalized, and Edison International cannot reasonably determine the financial impact at this time.

Pennsylvania

EME Homer City and the Pennsylvania Department of Environmental Protection have entered into a consent order and agreement related to selenium discharge, which was filed in Pennsylvania state court on July 17, 2007. Under the consent order and agreement, EME Homer City agreed to pay a civil penalty of $200,000 and to install modifications to its wastewater system to achieve consistent compliance with discharge limits. Until the pilot programs have been completed and the treatment system design has been finalized, EME will be unable to estimate the costs for ongoing treatment.

Midwest Generation Potential Environmental Proceeding

On July 31, 2007, the US EPA issued a NOV to Midwest Generation and Commonwealth Edison with respect to alleged violations of the Clean Air Act and certain opacity and particulate matter standards. See “EMG: Other Developments—Midwest Generation Potential Environmental Proceeding” for further discussion.

 

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Climate Change

In September 2006, California’s Governor Schwarzenegger signed two bills into law regarding GHG emissions. The first, known as AB 32 or the California Global Warming Solutions Act of 2006, establishes a comprehensive program of regulatory and market mechanisms to achieve reductions of GHG emissions. AB 32 requires the California Air Resources Board to develop regulations and market mechanisms targeted to reduce California’s GHG emissions to 1990 levels by 2020. California Air Resources Board’s mandatory program will take effect commencing 2012 and will implement incremental reductions so that GHG emissions will be reduced to 1990 levels by 2020. The second bill, known as SB 1368, relates specifically to power generation and requires the CPUC and the CEC to adopt GHG performance standards for investor owned and publicly owned utilities, respectively, for long-term procurement of electricity. The standards must equal the performance of a combined-cycle gas turbine generator. The CPUC adopted such a standard on January 25, 2007 (which limits emissions to 1,100 pounds of carbon dioxide per MWh). On May 28, 2007, the CEC adopted regulations pursuant to SB 1368 establishing and implementing a GHG EPS for baseload generation of local publicly owned electric utilities. These regulations were submitted to the Office of Administrative Law on June 1, 2007 and were subsequently disapproved. The CEC conducted public workshops to collect comments and draft new proposed language to address the Office of Administrative Law’s concerns. In addition, the CPUC is addressing climate change related issues in various regulatory proceedings. In a decision dated May 25, 2007, the CPUC expanded the scope of its GHG rulemaking to include GHG emissions associated with the transmission, storage, and distribution of natural gas in California, in addition to the combustion of natural gas by non-electricity generator end-use customers. SCE will continue to monitor the federal and state developments relating to regulation of GHG emissions to determine their impacts on SCE’s operations. Requirements to reduce emissions of CO2 and other GHG emissions could significantly increase SCE’s cost of generating electricity from fossil fuels, especially coal, as well as the cost of purchased power, which are generally borne by SCE’s customers. At this time, EME believes that all of its facilities in California meet the greenhouse gas emissions performance standard contemplated by SB 1368, but EME will continue to monitor both regulations, as they are developed, for potential impact on its existing facilities and its projects under development.

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 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 (classified as other long-term liabilities) at undiscounted amounts.

As of June 30, 2007, Edison International’s recorded estimated minimum liability to remediate the 37 identified sites at SCE (sites) and EME (14 sites related to Midwest Generation) was $77 million, $74 million of which 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 could exceed the recorded liability by up to $127 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 the identified sites (sites in which the upper end of the range of costs is at least $1 million), SCE also has 32 immaterial sites whose total liability ranges from $2 million (the recorded minimum liability) to $8 million.

 

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The CPUC allows SCE to recover environmental remediation costs at certain sites, representing $29 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 $72 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.

Edison International expects to clean up the identified sites over a period of up to 30 years. Remediation costs in each of the next several years are expected to range from $11 million to $31 million. Recorded costs for the 12 months ended June 30, 2007 were $18 million.

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 the 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 or financial position. 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.

Federal and State Income Taxes

Edison International received Revenue Agent Reports from the IRS in August 2002 and in January 2005 asserting deficiencies in federal corporate income taxes with respect to audits of its 1994 – 1996 and 1997 – 1999 tax years, respectively. Edison International expects to conclude the administrative phase of the audit of the 1994 – 1996 tax years by the end of 2007. Many of the asserted tax deficiencies are timing differences and, therefore, amounts ultimately paid (exclusive of penalties), if any, would be deductible on future tax returns of Edison International. Edison International has also submitted affirmative claims to the IRS and state tax agencies which are being addressed in administrative proceedings. Any benefits would be recorded at the earlier of when Edison International believes that the affirmative claim position has a more likely than not probability of being sustained or when a settlement is consummated. Certain affirmative claims have been recorded as part of the implementation of FIN 48.

As part of a nationwide challenge of certain types of lease transactions, the IRS has raised issues about the deferral of income taxes associated with Edison Capital’s cross-border, leveraged leases.

The IRS is challenging Edison Capital’s foreign power plant and electric locomotive sale/leaseback transactions entered into in 1993 and 1994 (Replacement Leases, which the IRS refers to as a sale-in/lease-out or SILO). The IRS is also challenging Edison Capital’s foreign power plant and electric transmission system lease/leaseback transactions entered into in 1997 and 1998 (Lease/Leaseback, which the IRS refers to as a lease-in/lease-out or LILO).

 

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Edison Capital also entered into a lease/service contract transaction in 1999 involving a foreign telecommunication system (Service Contract, which the IRS also refers to as a SILO). The IRS has not yet asserted any adjustment for the Service Contract but Edison International has been responding to data requests from the IRS about the transaction as part of an IRS examination of tax years 2000 – 2002. The following table summarizes estimated federal and state income taxes deferred from these leases as of December 31, 2006. Repayment of these deferred taxes would be accelerated if the IRS prevails:

 

In millions   

Tax Years Under

Appeal

1994 – 1999

  

Tax Years

Under Audit

2000 – 2002

  

Unaudited
Tax Years

2003 – 2006

   Total

Replacement Leases (SILO)

   $ 44    $ 19    $ 23    $ 86

Lease/Leaseback (LILO)

     558      562      6      1,126

Service Contract (SILO)

          126      199      325
     $   602    $   707    $   228    $   1,537

As of June 30, 2007, the interest (after tax) on the proposed tax adjustments is estimated to be approximately $451 million. The IRS also seeks a 20% penalty on any sustained tax adjustment.

Edison International believes it properly reported these transactions based on applicable statutes, regulations and case law in effect at the time the transactions were entered into, and it is vigorously defending its tax treatment of these leases. Written protests were filed to appeal the audit adjustments for the tax years under appeal asserting that the IRS’s position misstates material facts, misapplies the law and is incorrect. This matter is now being considered by the Administrative Appeals branch of the IRS.

In addition, the payment of taxes, interest and penalties could have a significant impact on earnings and cash flow. In order to commence litigation in certain forums, Edison International must make payments of disputed taxes, along with interest and any penalties asserted by the IRS, and thereafter pursue refunds. On May 26, 2006, Edison International paid $111 million of the taxes, interest and penalties for tax year 1999 followed by a refund claim for the same amount. The cash payment was funded by Edison Capital and accounted for as a deposit which will be refunded with interest to the extent Edison International prevails. Since the IRS did not act on this refund claim within six months from the date the claim was filed, it is deemed denied. Edison International is prepared to take legal action to assert its refund claim if an acceptable settlement cannot be reached with the IRS.

A number of other cases involving these kinds of lease transactions are pending before various courts. The first case involving a LILO was recently decided against the taxpayer on summary judgment in the Federal District Court in North Carolina. That taxpayer has announced its intention to appeal that decision to the Fourth Circuit Court of Appeals.

Edison International expects to file a refund claim for any taxes, interest and penalties paid pursuant to the administrative appeals settlement of the 1994 – 1996 tax years related to assessed tax deficiencies and penalties assessed on the Replacement Leases. These payments would be treated as a deposit. Edison International may make additional payments related to other tax years to preserve its litigation rights, although, at this time, the amount and timing of these additional payments is uncertain. At this time, Edison International is unable to predict the impact of the ultimate resolution of these matters.

The IRS Revenue Agent Report for the 1997 – 1999 audit also asserted deficiencies with respect to a transaction entered into by an SCE subsidiary which may be considered substantially similar to a listed transaction described by the IRS as a contingent liability company. This matter is currently being considered by the Administrative Appeals branch of the IRS where Edison International is defending its tax return position with respect to this transaction.

 

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In April 2004, Edison International filed California Franchise Tax amended returns for tax years 1997 – 2002 to mitigate the possible imposition of new California penalty provisions on transactions that may be considered as listed or substantially similar to listed transactions described in an IRS notice that was published in 2001. These transactions include certain Edison Capital leveraged lease transactions and the SCE subsidiary contingent liability company transaction described above. Edison International filed these amended returns under protest retaining its appeal rights.

In December 2006, Edison International reached a settlement with the California Franchise Tax Board regarding the sourcing of gross receipts from the sale of electric services for California state tax apportionment purposes for tax years 1981 to 2004. In the fourth quarter of 2006, Edison International recorded a $49 million benefit related to a tax reserve adjustment as a result of this settlement. In addition to this tax reserve adjustment, Edison International received a net cash refund of $52 million in April 2007 as a result of this same settlement.

Edison International remains subject to examination and administrative appeals by the IRS from 1994 – present. In addition, the statute of limitations remains open from 1986 – 1993 for certain affirmative claims. In July 2007, Edison International received a Notice of Proposed Adjustment from the IRS accepting an affirmative claim position involving the taxability of balancing account over-collections. This issue was addressed as part of the ongoing IRS examinations and administrative appeals process. The tax years affected by this Notice of Proposed Adjustment remain subject to examination and administrative appeals. The cash and earnings impacts of this position are dependent on the ultimate settlement of all issues in these tax years. Edison International expects earnings and cash flows to increase within the range of $65 million to $75 million and $275 million and $300 million, respectively.

In April 2007, Edison International received a Notice of Proposed Adjustment from the California Franchise Tax Board for tax years 2001 and 2002. In June 2007, Edison International filed its protest to deficiencies asserted in the April 2007 Notice of Proposed Adjustment. Edison International remains subject to examination by the California Franchise Tax Board for tax years from 2003 – present. Edison International is also subject to examination by select state tax authorities, with varying statute of limitations. Some state jurisdictions follow the federal statute for comparable issues.

Edison International continues its efforts to resolve open tax issues with the IRS and State authorities. The timing for resolving these open tax positions is subject to uncertainty, but it is reasonably possible that some portion of these open tax positions could be resolved in the next 12 months.

Enterprise-Wide Software System Project

Progress continued during the first six months of 2007 on preparation for the installation of an enterprise resources planning application from SAP. On July 2, 2007, Edison International implemented procurement and material management systems at three of EMG’s Illinois plants, as well as the EME financial systems. SCE is scheduled to implement financial, procurement, material management, work management and human resources systems in the second quarter of 2008.

Item 3. Quantitative and Qualitative Disclosures About Market Risk

Information responding to Part I, Item 3 is included in Part I, Item 2, “Management’s Discussion and Analysis of Financial Condition and Results of Operations,” under the headings “SCE: Market Risk Exposures” and “EMG: Market Risk Exposures.”

 

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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.

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 13a-15(f) or 15d-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

Midwest Generation Potential Environmental Proceeding

Information about the US EPA NOV issued to Midwest Generation appears in the MD&A under the heading “EMG: Other Developments—Midwe