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UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549



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FORM 10-Q



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(Mark One)

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

For the quarterly period ended September 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 1-2313



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SOUTHERN CALIFORNIA EDISON COMPANY

(Exact name of registrant as specified in
its charter)



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|                                                              |  |                                    
|------------------------------------------------------------- |  | -----------------------------------
|California                                                    |  | 95-1240335                         
|(State or other jurisdiction ofincorporation or organization) |  | (I.R.S. EmployerIdentification No.)
|                                                              | 
|2244 Walnut Grove Avenue (P. O. Box 800) Rosemead, California |  | 91770                              
|(Address of principal executive offices)                      |  | (Zip Code)                         

(626) 302-1212

(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 non-accelerated filer. See definition of accelerated filer and large accelerated filer in Rule 12b-2 of
the Exchange Act.

Large Accelerated Filer ̈Accelerated Filer ̈Non-Accelerated Filer  x

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 October 26, 2007
|Common Stock, no par value |  | 434,888,104                    



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GLOSSARY

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



|               |  |                                                                                                                                
|-------------- |  | -------------------------------------------------------------------------------------------------------------------------------
|               | 
|CARB           |  | California Air Resources Board                                                                                                 
|               | 
|CDWR           |  | California Department of Water Resources                                                                                       
|               | 
|CPSD           |  | Consumer Protection and Safety Division                                                                                        
|               | 
|CPUC           |  | California Public Utilities Commission                                                                                         
|               | 
|CRRs           |  | Congestion Revenue Rights                                                                                                      
|               | 
|District Court |  | U.S. District Court for the District of Columbia                                                                               
|               | 
|DRA            |  | Division of Ratepayer Advocates                                                                                                
|               | 
|DWP            |  | Los Angeles Department of Water & Power                                                                                        
|               | 
|EPS            |  | Earnings per share                                                                                                             
|               | 
|ERRA           |  | energy resource recovery account                                                                                               
|               | 
|FASB           |  | Financial Accounting Standards Board                                                                                           
|               | 
|FERC           |  | Federal Energy Regulatory Commission                                                                                           
|               | 
|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                                          
|               | 
|Midway-Sunset  |  | Midway-Sunset Cogeneration Company                                                                                             
|               | 
|Moodys        |  | Moodys Investors Service                                                                                                      
|               | 
|Mountainview   |  | Mountainview Power Company, LLC                                                                                                
|               | 
|MRTU           |  | Market Redesign Technical Upgrade                                                                                              
|               | 
|MW             |  | Megawatts                                                                                                                      
|               | 
|MWh            |  | megawatt-hours                                                                                                                 
|               | 
|Ninth Circuit  |  | United States Court of Appeals for the Ninth Circuit                                                                           
|               | 
|NOX            |  | nitrogen oxide                                                                                                                 
|               | 
|NOI            |  | Notice of Intent                                                                                                               
|               | 
|NRC            |  | Nuclear Regulatory Commission                                                                                                  
|               | 
|Palo Verde     |  | Palo Verde Nuclear Generating Station                                                                                          
|               | 
|PBR            |  | performance-based ratemaking                                                                                                   
|               | 
|PG&E           |  | Pacific Gas & Electric Company                                                                                                 





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##### Table of Contents

GLOSSARY (Continued)



|                |  |                                                                                                                                                                    
|--------------- |  | -------------------------------------------------------------------------------------------------------------------------------------------------------------------
|                | 
|POD             |  | Presiding Officers Decision                                                                                                                                       
|                | 
|PX              |  | California Power Exchange                                                                                                                                          
|                | 
|QF(s)           |  | Qualifying facility(ies)                                                                                                                                           
|                | 
|RICO            |  | Racketeer Influenced and Corrupt Organization                                                                                                                      
|                | 
|S&P             |  | Standard & Poors                                                                                                                                                  
|                | 
|San Onofre      |  | San Onofre Nuclear Generating Station                                                                                                                              
|                | 
|SCAQMD          |  | South Coast Air Quality Management District                                                                                                                        
|                | 
|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
|                | 
|SO2             |  | sulfur dioxide                                                                                                                                                     
|                | 
|VIE(s)          |  | variable interest entity(ies)                                                                                                                                      





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##### Table of Contents

SOUTHERN CALIFORNIA EDISON COMPANY

INDEX



|                               |  |           |  |                                                                                                           |  |         
|------------------------------ |  | --------- |  | --------------------------------------------------------------------------------------------------------- |  | --------
|                               |  |           |  |                                                                                                           |  | Page No.
|Part  I. Financial Information |  |          
|                               |  |           | 
|                               |  | Item 1.   |  | Financial Statements                                                                                      |  | 1       
|                               |  |           | 
|                               |  |           |  | Consolidated Statements of Income  Three and Nine Months Ended September 30, 2007and 2006                |  | 1       
|                               |  |           | 
|                               |  |           |  | Consolidated Statements of Comprehensive Income  Three and Nine Months Ended September 30, 2007 and 2006 |  | 1       
|                               |  |           | 
|                               |  |           |  | Consolidated Balance Sheets  September 30, 2007 and December 31, 2006                                    |  | 2       
|                               |  |           | 
|                               |  |           |  | Consolidated Statements of Cash Flows  Nine Months Ended September 30, 2007 and 2006                     |  | 4       
|                               |  |           | 
|                               |  |           |  | Notes to Consolidated Financial Statements                                                                |  | 5       
|                               |  |           | 
|                               |  | Item 2.   |  | Managements Discussion and Analysis of Financial Condition and Results of Operations                     |  | 26      
|                               |  |           | 
|                               |  | Item 3.   |  | Quantitative and Qualitative Disclosures About Market Risk                                                |  | 50      
|                               |  |           | 
|                               |  | Item 4.   |  | Controls and Procedures                                                                                   |  | 50      
|                               | 
|Part II. Other Information     |  |          
|                               |  |           | 
|                               |  | Item 1.   |  | Legal Proceedings                                                                                         |  | 51      
|                               |  |           | 
|                               |  | Item 6.   |  | Exhibits                                                                                                  |  | 52      
|                               |  |          
|                               |  | Signature |  | 53                                                                                                       



i



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SOUTHERN CALIFORNIA EDISON COMPANY

PART I FINANCIAL INFORMATION



|Item 1. | Financial Statements
|------- | --------------------

CONSOLIDATED STATEMENTS OF INCOME



|                                                                                |  |                                 |       |   |                                |   |       |      |  |   |       |   |  |   |       |  
|------------------------------------------------------------------------------- |  | ------------------------------- | ----- | - | ------------------------------ | - | ----- | ---- |  | - | ----- | - |  | - | ----- | -
|                                                                                |  | Three Months EndedSeptember 30, |       |   | Nine Months EndedSeptember 30, |  
|In millions                                                                     |  | 2007                            |       |   | 2006                           |   |       | 2007 |  |   | 2006  |  
|                                                                                |  | (Unaudited)                     |      
|Operating revenue                                                               |  | $                               | 3,214 |   |                                | $ | 3,079 |      |  | $ | 7,897 |   |  | $ | 7,818 |  
|Fuel                                                                            |  |                                 | 310   |   |                                |   | 286   |      |  |   | 904   |   |  |   | 836   |  
|Purchased power                                                                 |  |                                 | 1,284 |   |                                |   | 1,036 |      |  |   | 2,431 |   |  |   | 2,819 |  
|Provisions for regulatory adjustment clauses  net                              |  |                                 | (66   | ) |                                |   | 115   |      |  |   | 189   |   |  |   | (256  | )
|Other operation and maintenance                                                 |  |                                 | 726   |   |                                |   | 662   |      |  |   | 1,988 |   |  |   | 1,916 |  
|Depreciation, decommissioning and amortization                                  |  |                                 | 267   |   |                                |   | 254   |      |  |   | 813   |   |  |   | 806   |  
|Property and other taxes                                                        |  |                                 | 54    |   |                                |   | 53    |      |  |   | 164   |   |  |   | 158   |  
|Net gain on sale of utility property and plant                                  |  |                                 |      |   |                                |   |      |      |  |   |      |   |  |   | (1    | )
|Total operating expenses                                                        |  |                                 | 2,575 |   |                                |   | 2,406 |      |  |   | 6,489 |   |  |   | 6,278 |  
|Operating income                                                                |  |                                 | 639   |   |                                |   | 673   |      |  |   | 1,408 |   |  |   | 1,540 |  
|Interest income                                                                 |  |                                 | 13    |   |                                |   | 14    |      |  |   | 34    |   |  |   | 44    |  
|Other nonoperating income                                                       |  |                                 | 29    |   |                                |   | 13    |      |  |   | 68    |   |  |   | 61    |  
|Interest expense  net of amounts capitalized                                   |  |                                 | (117  | ) |                                |   | (98   | )    |  |   | (330  | ) |  |   | (297  | )
|Other nonoperating deductions                                                   |  |                                 | (7    | ) |                                |   | (12   | )    |  |   | (31   | ) |  |   | (32   | )
|Income before tax and minority interest                                         |  |                                 | 557   |   |                                |   | 590   |      |  |   | 1,149 |   |  |   | 1,316 |  
|Income tax expense                                                              |  |                                 | 150   |   |                                |   | 187   |      |  |   | 263   |   |  |   | 416   |  
|Minority interest                                                               |  |                                 | 132   |   |                                |   | 127   |      |  |   | 261   |   |  |   | 244   |  
|Net income                                                                      |  |                                 | 275   |   |                                |   | 276   |      |  |   | 625   |   |  |   | 656   |  
|Dividends on preferred and preference stock not subject to mandatory redemption |  |                                 | 13    |   |                                |   | 13    |      |  |   | 38    |   |  |   | 38    |  
|Net income available for common stock                                           |  | $                               | 262   |   |                                | $ | 263   |      |  | $ | 587   |   |  | $ | 618   |  
|                                                                                | 
|CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME                                 |  |                                 |       |   |                               
|                                                                                |  | Three Months EndedSeptember 30, |       |   | Nine Months EndedSeptember 30, |  
|In millions                                                                     |  | 2007                            |       |   | 2006                           |   |       | 2007 |  |   | 2006  |  
|                                                                                |  | (Unaudited)                     |      
|Net income                                                                      |  | $                               | 275   |   |                                | $ | 276   |      |  | $ | 625   |   |  | $ | 656   |  
|Other comprehensive income, net of tax:                                         |  |                                 |       |   |                                |   |       |      |  |   |       |   |  |   |       |  
|Amortization of cash flow hedges                                                |  |                                 |      |   |                                |   |      |      |  |   |      |   |  |   | 4     |  
|Pension and postretirement benefits other than pensions:                        |  |                                 |       |   |                                |   |       |      |  |   |       |   |  |   |       |  
|Amortization of loss and prior service cost  net                               |  |                                 |      |   |                                |   |      |      |  |   | 1     |   |  |   |      |  
|Comprehensive income                                                            |  | $                               | 275   |   |                                | $ | 276   |      |  | $ | 626   |   |  | $ | 660   |  



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



1



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##### Table of Contents

SOUTHERN CALIFORNIA EDISON COMPANY

CONSOLIDATED BALANCE SHEETS



|                                                                                                       |  |                    |        |   |                   |   |        |  
|------------------------------------------------------------------------------------------------------ |  | ------------------ | ------ | - | ----------------- | - | ------ | -
|In millions                                                                                            |  | September 30, 2007 |        |   | December 31, 2006 |  
|                                                                                                       |  | (Unaudited)        |        |   |                   |  
|ASSETS                                                                                                 |  |                    |        |   |                   |   |        |  
|Cash and equivalents                                                                                   |  | $                  | 115    |   |                   | $ | 83     |  
|Restricted cash                                                                                        |  |                    | 56     |   |                   |   | 56     |  
|Margin and collateral deposits                                                                         |  |                    | 46     |   |                   |   | 55     |  
|Receivables, less allowances of $30 and $29 for uncollectible accounts at respective dates             |  |                    | 1,027  |   |                   |   | 939    |  
|Accrued unbilled revenue                                                                               |  |                    | 506    |   |                   |   | 303    |  
|Inventory                                                                                              |  |                    | 272    |   |                   |   | 232    |  
|Accumulated deferred income taxes  net                                                                |  |                    | 213    |   |                   |   | 250    |  
|Derivative assets                                                                                      |  |                    | 83     |   |                   |   | 56     |  
|Regulatory assets                                                                                      |  |                    | 295    |   |                   |   | 554    |  
|Short-term investments                                                                                 |  |                    | 118    |   |                   |   |       |  
|Other current assets                                                                                   |  |                    | 117    |   |                   |   | 54     |  
|Total current assets                                                                                   |  |                    | 2,848  |   |                   |   | 2,582  |  
|Nonutility property  less accumulated provision for depreciation of $686 and $633 at respective dates |  |                    | 1,004  |   |                   |   | 1,046  |  
|Nuclear decommissioning trusts                                                                         |  |                    | 3,398  |   |                   |   | 3,184  |  
|Other investments                                                                                      |  |                    | 83     |   |                   |   | 62     |  
|Total investments and other assets                                                                     |  |                    | 4,485  |   |                   |   | 4,292  |  
|Utility plant, at original cost:                                                                       |  |                    |        |   |                   |   |        |  
|Transmission and distribution                                                                          |  |                    | 18,492 |   |                   |   | 17,606 |  
|Generation                                                                                             |  |                    | 1,681  |   |                   |   | 1,465  |  
|Accumulated provision for depreciation                                                                 |  |                    | (5,050 | ) |                   |   | (4,821 | )
|Construction work in progress                                                                          |  |                    | 1,584  |   |                   |   | 1,486  |  
|Nuclear fuel, at amortized cost                                                                        |  |                    | 224    |   |                   |   | 177    |  
|Total utility plant                                                                                    |  |                    | 16,931 |   |                   |   | 15,913 |  
|Regulatory assets                                                                                      |  |                    | 2,825  |   |                   |   | 2,818  |  
|Derivative assets                                                                                      |  |                    | 6      |   |                   |   | 17     |  
|Other long-term assets                                                                                 |  |                    | 489    |   |                   |   | 488    |  
|Total long-term assets                                                                                 |  |                    | 3,320  |   |                   |   | 3,323  |  
|                                                                                                       |  |                   
|Total assets                                                                                           |  | $                  | 27,584 |   |                   | $ | 26,110 |  



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



2



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##### Table of Contents

SOUTHERN CALIFORNIA EDISON COMPANY

CONSOLIDATED BALANCE SHEETS



|                                                                         |  |                    |        |   |                   |   |        |  
|------------------------------------------------------------------------ |  | ------------------ | ------ | - | ----------------- | - | ------ | -
|In millions, except share amounts                                        |  | September 30, 2007 |        |   | December 31, 2006 |  
|                                                                         |  | (Unaudited)        |        |   |                   |  
|LIABILITIES AND SHAREHOLDERS EQUITY                                     |  |                    |        |   |                   |   |        |  
|Long-term debt due within one year                                       |  | $                  | 220    |   |                   | $ | 396    |  
|Accounts payable                                                         |  |                    | 813    |   |                   |   | 856    |  
|Accrued taxes                                                            |  |                    | 317    |   |                   |   | 193    |  
|Accrued interest                                                         |  |                    | 96     |   |                   |   | 114    |  
|Counterparty collateral                                                  |  |                    | 42     |   |                   |   | 36     |  
|Customer deposits                                                        |  |                    | 217    |   |                   |   | 198    |  
|Book overdrafts                                                          |  |                    | 250    |   |                   |   | 140    |  
|Derivative liabilities                                                   |  |                    | 93     |   |                   |   | 99     |  
|Regulatory liabilities                                                   |  |                    | 1,316  |   |                   |   | 1,000  |  
|Other current liabilities                                                |  |                    | 594    |   |                   |   | 624    |  
|Total current liabilities                                                |  |                    | 3,958  |   |                   |   | 3,656  |  
|Long-term debt                                                           |  |                    | 5,117  |   |                   |   | 5,171  |  
|Accumulated deferred income taxes  net                                  |  |                    | 2,568  |   |                   |   | 2,675  |  
|Accumulated deferred investment tax credits                              |  |                    | 107    |   |                   |   | 112    |  
|Customer advances                                                        |  |                    | 158    |   |                   |   | 160    |  
|Derivative liabilities                                                   |  |                    | 39     |   |                   |   | 77     |  
|Power-purchase contracts                                                 |  |                    | 25     |   |                   |   | 32     |  
|Accumulated provision for pensions and benefits                          |  |                    | 857    |   |                   |   | 809    |  
|Asset retirement obligations                                             |  |                    | 2,823  |   |                   |   | 2,749  |  
|Regulatory liabilities                                                   |  |                    | 3,315  |   |                   |   | 3,140  |  
|Other deferred credits and other long-term liabilities                   |  |                    | 1,091  |   |                   |   | 802    |  
|Total deferred credits and other liabilities                             |  |                    | 10,983 |   |                   |   | 10,556 |  
|Total liabilities                                                        |  |                    | 20,058 |   |                   |   | 19,383 |  
|Commitments and contingencies (Note 5)                                   |  |                    |        |   |                   |   |        |  
|Minority interest                                                        |  |                    | 461    |   |                   |   | 351    |  
|Common stock, no par value (434,888,104 shares outstanding at each date) |  |                    | 2,168  |   |                   |   | 2,168  |  
|Additional paid-in capital                                               |  |                    | 407    |   |                   |   | 383    |  
|Accumulated other comprehensive loss                                     |  |                    | (13    | ) |                   |   | (14    | )
|Retained earnings                                                        |  |                    | 3,574  |   |                   |   | 2,910  |  
|Total common shareholders equity                                        |  |                    | 6,136  |   |                   |   | 5,447  |  
|Preferred and preference stock not subject to mandatory redemption       |  |                    | 929    |   |                   |   | 929    |  
|Total shareholders equity                                               |  |                    | 7,065  |   |                   |   | 6,376  |  
|                                                                         |  |                   
|Total liabilities and shareholders equity                               |  | $                  | 27,584 |   |                   | $ | 26,110 |  



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



3



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##### Table of Contents

SOUTHERN CALIFORNIA EDISON COMPANY

CONSOLIDATED STATEMENTS OF CASH FLOWS



|                                                                       |  |                                 |             |   |      |   |        |  
|---------------------------------------------------------------------- |  | ------------------------------- | ----------- | - | ---- | - | ------ | -
|                                                                       |  | Nine Months Ended September 30, |            
|In millions                                                            |  | 2007                            |             |   | 2006 |  
|                                                                       |  |                                 | (Unaudited) |  
|Cash flows from operating activities:                                  |  |                                 |             |   |      |   |        |  
|Net income                                                             |  | $                               | 625         |   |      | $ | 656    |  
|Adjustments to reconcile to net cash provided by operating activities: |  |                                 |             |   |      |   |        |  
|Depreciation, decommissioning and amortization                         |  |                                 | 813         |   |      |   | 806    |  
|Realized loss on nuclear decommissioning trusts                        |  |                                 | 42          |   |      |   |       |  
|Other amortization                                                     |  |                                 | 78          |   |      |   | 60     |  
|Minority interest                                                      |  |                                 | 261         |   |      |   | 244    |  
|Deferred income taxes and investment tax credits                       |  |                                 | (184        | ) |      |   | (354   | )
|Regulatory assets  long-term                                          |  |                                 | 53          |   |      |   | 117    |  
|Regulatory liabilities  long-term                                     |  |                                 | (4          | ) |      |   | (151   | )
|Derivative assets  long-term                                          |  |                                 | 11          |   |      |   | 13     |  
|Derivative liabilities  long-term                                     |  |                                 | (38         | ) |      |   | 72     |  
|Other assets                                                           |  |                                 | (28         | ) |      |   | 18     |  
|Other liabilities                                                      |  |                                 | 263         |   |      |   | 32     |  
|Margin and collateral deposits  net of collateral received            |  |                                 | 15          |   |      |   | (38    | )
|Receivables and accrued unbilled revenue                               |  |                                 | (291        | ) |      |   | (433   | )
|Derivative assets  short-term                                         |  |                                 | (27         | ) |      |   | 171    |  
|Derivative liabilities  short-term                                    |  |                                 | (13         | ) |      |   | 50     |  
|Inventory and other current assets                                     |  |                                 | (103        | ) |      |   | (32    | )
|Regulatory assets  short-term                                         |  |                                 | 259         |   |      |   | (20    | )
|Regulatory liabilities  short-term                                    |  |                                 | 316         |   |      |   | 606    |  
|Accrued interest and taxes                                             |  |                                 | 319         |   |      |   | 480    |  
|Accounts payable and other current liabilities                         |  |                                 | 1           |   |      |   | (234   | )
|Net cash provided by operating activities                              |  |                                 | 2,368       |   |      |   | 2,063  |  
|Cash flows from financing activities:                                  |  |                                 |             |   |      |   |        |  
|Long-term debt issued                                                  |  |                                 |            |   |      |   | 500    |  
|Long-term debt issuance costs                                          |  |                                 | (1          | ) |      |   | (9     | )
|Long-term debt repaid                                                  |  |                                 | (54         | ) |      |   | (351   | )
|Issuance of preference stock                                           |  |                                 |            |   |      |   | 196    |  
|Rate reduction notes repaid                                            |  |                                 | (178        | ) |      |   | (177   | )
|Change in book overdrafts                                              |  |                                 | 110         |   |      |   | (31    | )
|Shares purchased for stock-based compensation                          |  |                                 | (120        | ) |      |   | (75    | )
|Proceeds from stock option exercises                                   |  |                                 | 50          |   |      |   | 31     |  
|Excess tax benefits related to stock option exercises                  |  |                                 | 25          |   |      |   | 11     |  
|Minority interest                                                      |  |                                 | (151        | ) |      |   | (228   | )
|Dividends paid                                                         |  |                                 | (148        | ) |      |   | (227   | )
|Net cash used by financing activities                                  |  |                                 | (467        | ) |      |   | (360   | )
|Cash flows from investing activities:                                  |  |                                 |             |   |      |   |        |  
|Capital expenditures                                                   |  |                                 | (1,650      | ) |      |   | (1,615 | )
|Proceeds from nuclear decommissioning trust sales                      |  |                                 | 2,866       |   |      |   | 2,145  |  
|Purchases of nuclear decommissioning trust investments                 |  |                                 | (2,967      | ) |      |   | (2,253 | )
|Sales of short-term investments                                        |  |                                 | 4,861       |   |      |   | 4,082  |  
|Purchases of short-term investments                                    |  |                                 | (4,979      | ) |      |   | (4,054 | )
|Customer advances for construction and other investments               |  |                                 |            |   |      |   | 7      |  
|Net cash used by investing activities                                  |  |                                 | (1,869      | ) |      |   | (1,688 | )
|Net increase in cash and equivalents                                   |  |                                 | 32          |   |      |   | 15     |  
|Cash and equivalents, beginning of period                              |  |                                 | 83          |   |      |   | 143    |  
|Cash and equivalents, end of period                                    |  | $                               | 115         |   |      | $ | 158    |  

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



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SOUTHERN CALIFORNIA EDISON COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Managements Statement

In the opinion of management, all adjustments, including recurring accruals, have been made that are necessary for a fair statement of the 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 three- and nine-month periods ended
September 30, 2007 are not necessarily indicative of the operating results for the full year.

The quarterly report should be read in conjunction with
SCEs Annual Report to Shareholders incorporated by reference into SCE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

SCE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. SCE 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).

Certain prior-period amounts were reclassified to conform to the September 30, 2007 financial statement presentation.

Income Taxes

SCE and its eligible subsidiaries
are included in Edison Internationals consolidated federal income tax and combined state tax returns. 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, SCE is required to estimate its income taxes in each jurisdiction in which it
operates. This process involves estimating actual current tax expense together with assessing temporary differences resulting from differing treatment of items for tax and accounting purposes, such as depreciable property. These differences result
in deferred tax assets and liabilities, which are included within SCEs consolidated balance sheets.

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 3.

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



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technical merits, that the position will be sustained on audit. SCE adopted FIN 48 effective January 1, 2007. Implementation of FIN 48
resulted in a cumulative-effect adjustment that increased retained earnings by $213 million upon adoption. SCE will continue to monitor and assess new income tax developments.

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. SCE will adopt FIN 39-1 on January 1, 2008. Adoption of this
position may result in netting a portion of margin and cash collateral deposits with derivative liabilities on SCEs consolidated balance sheets, but will have no impact on SCE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. SCE is currently evaluating whether it will opt to report any current
or future financial assets and liabilities at fair value and the impact, if adopted, on its consolidated financial statements, beginning January 1, 2008.

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. SCE will adopt SFAS No. 157 on
January 1, 2008. SCE 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 operating revenue and other operation and maintenance expense. SCEs franchise fees billed to
customers and recorded as operating revenue were $34 million and $37 million for the three-month periods ended September 30, 2007 and 2006, respectively, and $81 million and $84 million for nine-month periods ended September 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

At September 30, 2007, SCE held various variable rate demand notes related to short-term cash management activities. The interest rate process for these securities
allow for a resetting of interest rates related to changes in terms and/or credit quality, similar to cash and cash equivalents. In accordance with SFAS No. 115, Accounting for Certain Investments in Debt and Equity Securities, these
notes are classified as short-term investments. As of September 30, 2007, the notes were classified as available-for-sale securities and were recorded at fair value in the amount of $118 million. There were no outstanding notes as of
December 31, 2006. Sales of the notes were $4.9 billion and $4 billion for the nine-month periods ended September 30, 2007 and 2006, respectively. Purchases of the notes were $5 billion and $4 billion for the nine-month periods ended
September 30, 2007, and 2006, respectively. There were no realized or unrealized gains or losses. The consolidated statements of cash flows was revised to reflect the 2006 sales and purchases activity on a gross basis.



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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 Edison
Internationals 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 September 30, 2007, Edison International has approximately 8.4 million shares remaining for future issuance under its stock-based compensation plans. For further discussion see Stock-Based
Compensation in Note 4.

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 MonthsEndedSeptember 30, |       |      | Nine MonthsEndedSeptember 30, |      
|In millions                                                                  |  | 2007                           |       | 2006 |                               |       | 2007 |  |   | 2006  |  
|                                                                             |  | (Unaudited)                    |      
|Purchased-power from bilateral contracts, QFs, ISO, FTRs and exchange energy |  | $                              | 1,153 |      | $                             | 1,028 |      |  | $ | 2,356 |   |  | $ | 2,351 |  
|Unrealized (gains) losses on economic hedging activities  net               |  |                                | 67    |      |                               | 9     |      |  |   | (23   | ) |  |   | 351   |  
|Realized losses on economic hedging activities  net                         |  |                                | 58    |      |                               | 114   |      |  |   | 111   |   |  |   | 279   |  
|Energy settlements and refunds                                               |  |                                | 6     |      |                               | (115  | )    |  |   | (13   | ) |  |   | (162  | )
|Total purchased-power expense                                                |  | $                              | 1,284 |      | $                             | 1,036 |      |  | $ | 2,431 |   |  | $ | 2,819 |  

The changes in net unrealized (gains) losses on economic hedging activities primarily resulted from changes in
SCEs gas hedge portfolio mix as well as the movements in the natural gas futures market. The changes in net realized losses on economic hedging activities primarily resulted from a more stable natural gas market in 2007.

Note 3. Income Taxes

SCE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. SCEs effective tax rate from operations was 35% and 30% for the three- and nine-month periods ended
September 30, 2007, respectively, as compared to 40% and 39% for the



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respective periods in 2006. The decreased effective tax rate realized for the three-months ended was caused primarily by year over year changes in property
related flow-through items as well as lower interest expense related to lower tax reserve in 2007 as compared to 2006 as a result of implementing FIN 48. In addition, the nine-month variance included reductions made to the income tax reserve 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 due to reductions 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.

The net
liability recorded for uncertain tax positions was $199 million and $98 million as of September 30, 2007 and the date of adoption (January 1, 2007) of FIN 48, respectively. The net liability as of September 30, 2007 and the date of
adoption consists of $240 million and $335 million, respectively, of unrecognized tax benefits, partially offset by $41 million and $237 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 $68 million from positions taken in prior periods
and $27 million from positions taken in 2007. The total amount of unrecognized tax benefits as of September 30, 2007 and the date of adoption that, if recognized, would affect the effective tax rate was $57 million and $35 million,
respectively.

The unrecognized tax benefits, as of September 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 $28 million and $71 million representing the difference between the amount filed on amended tax returns and the amount recognized pursuant to FIN 48 as of September 30, 2007
and the date of adoption, respectively, and $1.6 billion of claims for both periods 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 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 $95 million and $65 million as of September 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 September 30, 2007 was $10 million. The total benefit recognized in income tax expense for the nine months ended September 30, 2007 was $25
million.

Edison International and its subsidiaries remains subject to examination and administrative appeals by the IRS for tax years
1994  present. Edison International is challenging certain IRS examination adjustments for tax years 1994  1999 with the Administrative Appeals branch of the IRS and Edison International is currently under IRS
examination for tax years 2000  2002. In addition, the statute of limitations remains open for tax years 1986  1993 for certain affirmative claims.

In July 2007, Edison International and its subsidiaries received a Notice of Proposed Adjustment from the IRS on an affirmative claim position involving the taxability of balancing account over-collections. This issue
is 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. SCE expects earnings and cash flows to increase within the range of $70 million to $80 million and $300 million to $325 million, respectively.

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



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Edison International and SCE continue their efforts to resolve open tax issues through 2002 with the IRS and State
authorities. The timing for resolving these open tax positions is uncertain, but it is reasonably possible that all or some portion of these open tax positions could be resolved in the next 12 months.

As a matter of course, SCE is regularly audited by federal and state taxing authorities. For further discussion of this matter, see Federal and State Income
Taxes in Note 5.

Note 4. Compensation and Benefits Plans

Pension Plans

SCE 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 $50 million to its pension plan in 2007. As of September 30, 2007, SCE has made $45 million in contributions related to 2006 and $25 million related to
2007 and estimates to make $12 million of additional contributions in the last three months of 2007. Expected contribution funding 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.

Expense components are:



|                                   |  |                                 |     |   |                                |   |     |      |  |   |      |   |  |   |      |  
|---------------------------------- |  | ------------------------------- | --- | - | ------------------------------ | - | --- | ---- |  | - | ---- | - |  | - | ---- | -
|                                   |  | Three Months EndedSeptember 30, |     |   | Nine Months EndedSeptember 30, |  
|In millions                        |  | 2007                            |     |   | 2006                           |   |     | 2007 |  |   | 2006 |  
|                                   |  | (Unaudited)                     |    
|Service cost                       |  | $                               | 26  |   |                                | $ | 25  |      |  | $ | 78   |   |  | $ | 76   |  
|Interest cost                      |  |                                 | 44  |   |                                |   | 42  |      |  |   | 132  |   |  |   | 127  |  
|Expected return on plan assets     |  |                                 | (61 | ) |                                |   | (56 | )    |  |   | (183 | ) |  |   | (169 | )
|Special termination benefits       |  |                                 |    |   |                                |   | 4   |      |  |   |     |   |  |   | 8    |  
|Amortization of prior service cost |  |                                 | 4   |   |                                |   | 4   |      |  |   | 12   |   |  |   | 12   |  
|Amortization of net loss           |  |                                 | 1   |   |                                |   | 1   |      |  |   | 3    |   |  |   | 2    |  
|Subtotal                           |  |                                 | 14  |   |                                |   | 20  |      |  |   | 42   |   |  |   | 56   |  
|Regulatory adjustment  deferred   |  |                                 | 1   |   |                                |   | (2  | )    |  |   | 3    |   |  |   | (5   | )
|Total expense recognized           |  | $                               | 15  |   |                                | $ | 18  |      |  | $ | 45   |   |  | $ | 51   |  

Postretirement Benefits Other Than Pensions

SCE previously disclosed in Note 6 of Notes to Consolidated Financial Statements included in its 2006 Annual Report on Form 10-K that it expects to contribute
approximately $41 million to its postretirement benefits other than pension plans in 2007. As of September 30, 2007, SCE has made no contributions related to 2006 and $15 million related to 2007 and estimates to make $37 million of
additional contributions in the last three months of 2007. Expected contribution funding could vary from anticipated amounts depending on the funded status at year-end and tax-deductible funding limitations.



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Expense components are:



|                                     |  |                                 |     |   |                                |   |     |      |  |   |      |   |  |   |     |  
|------------------------------------ |  | ------------------------------- | --- | - | ------------------------------ | - | --- | ---- |  | - | ---- | - |  | - | --- | -
|                                     |  | Three Months EndedSeptember 30, |     |   | Nine Months EndedSeptember 30, |  
|In millions                          |  | 2007                            |     |   | 2006                           |   |     | 2007 |  |   | 2006 |  
|                                     |  | (Unaudited)                     |    
|Service cost                         |  | $                               | 10  |   |                                | $ | 11  |      |  | $ | 30   |   |  | $ | 35  |  
|Interest cost                        |  |                                 | 31  |   |                                |   | 31  |      |  |   | 93   |   |  |   | 92  |  
|Expected return on plan assets       |  |                                 | (30 | ) |                                |   | (27 | )    |  |   | (90  | ) |  |   | (81 | )
|Special termination benefits         |  |                                 |    |   |                                |   | 3   |      |  |   |     |   |  |   | 6   |  
|Amortization of prior service credit |  |                                 | (7  | ) |                                |   | (7  | )    |  |   | (21  | ) |  |   | (22 | )
|Amortization of net loss             |  |                                 | 6   |   |                                |   | 12  |      |  |   | 18   |   |  |   | 35  |  
|Total expense recognized             |  | $                               | 10  |   |                                | $ | 23  |      |  | $ | 30   |   |  | $ | 65  |  

Stock-Based Compensation

Total stock-based compensation expense (reflected in the caption Other operation and maintenance on the consolidated statements of income) was $5 million and $9 million for the three-month periods ended
September 30, 2007 and 2006, respectively and $22 million and $23 million for the nine-month periods ended September 30, 2007 and 2006, respectively. The income tax benefit recognized in the consolidated statements of income was $2 million
and $3 million for the three-month periods ended September 30, 2007 and 2006, respectively and $7 million and $8 million for the nine-month periods ended September 30, 2007 and 2006, respectively. Total stock-based compensation cost
capitalized was $1 million and $2 million for the three-month periods ended September 30, 2007 and 2006 and $4 million for both nine-month periods ended September 30, 2007 and 2006.

Stock Options

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



|                                                  |  |              |   |  |                    |       |                                  |      |                         |   |            
|------------------------------------------------- |  | ------------ | - |  | ------------------ | ----- | -------------------------------- | ---- | ----------------------- | - | -----------
|                                                  |  |              |   |  | Weighted - Average |       |                                 
|                                                  |  | StockOptions |   |  | ExercisePrice      |       | RemainingContractualTerm (Years) |      | AggregateIntrinsicValue
|Outstanding at December 31, 2006                  |  | 7,761,336    |   |  | $                  | 26.78 |                                  |      |                         |   |            
|Granted                                           |  | 913,947      |   |  | $                  | 47.62 |                                  |      |                         |   |            
|Forfeited                                         |  | (32,943      | ) |  | $                  | 39.94 |                                  |      |                         |   |            
|Exercised                                         |  | (2,165,160   | ) |  | $                  | 23.03 |                                  |      |                         |   |            
|Outstanding at September 30, 2007                 |  | 6,477,180    |   |  | $                  | 30.93 |                                  | 6.64 |                         |   |            
|Vested and expected to vest at September 30, 2007 |  | 6,188,873    |   |  | $                  | 30.56 |                                  | 6.58 |                         | $ | 146,877,428
|Exercisable at September 30, 2007                 |  | 3,210,605    |   |  | $                  | 23.76 |                                  | 5.34 |                         | $ | 98,027,797 

Stock options granted in 2007 do not accrue dividend equivalents.

The amount of cash used to settle stock options exercised was $7 million and $14 million for the three-month periods ended September 30, 2007 and 2006,
respectively, and $111 million and $60 million for the nine-month periods ended September 30, 2007 and 2006, respectively. Cash received from options exercised was $3 million and $8 million for the three-month periods ended
September 30, 2007 and 2006, respectively, and $50 million and $31 million for the nine-month periods ended September 30, 2007 and 2006, respectively. The estimated tax benefit from options exercised was $2 million and $3 million for
the three-month periods ended September 30, 2007 and 2006, respectively, and $25 million and $11 million for the nine-month periods ended September 30, 2007 and 2006, respectively.



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Note 5. Commitments and Contingencies

Lease Commitments

SCE entered into new power-purchase contracts during the first nine months of 2007. These
additional commitments are currently estimated to be $13 million for the remainder of 2007, $186 million for 2008, $114 million for 2009, $73 million for 2010, $41 million for 2011 and $198 million thereafter.

SCE entered into a new power-purchase contract, classified as an operating lease, during the first nine months of 2007. SCEs additional operating lease commitments
for this new power contract are currently 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, classified as a capital lease, in June 2007. As of September 30, 2007, the capital lease requires future minimum lease payments of $28 million (approximately $1 million per year) through May 2027. As of
September 30, 2007, the executory costs and imputed interest for this capital lease were $11 million and $7 million, respectively.

Other Commitments

SCE entered into service contracts associated with uranium enrichment and fuel fabrication during the first nine
months of 2007. As a result, SCEs additional fuel supply commitments are estimated to be $82 million for the remainder of 2007, zero for 2008, $14 million for 2009, $8 million for 2010, $7 million for 2011 and $40 million thereafter.

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 Mountain 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.

Mountainview Filter Cake Indemnity

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

Other Indemnities

SCE provides other
indemnifications through contracts entered into in the normal course of business. These are primarily indemnifications against adverse litigation outcomes in connection with underwriting agreements, and specified environmental indemnities and income
taxes with respect to assets sold. SCEs obligations under these



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agreements may be limited in terms of time and/or amount, and in some instances SCE may have recourse against third parties for certain indemnities. The
obligated amounts of these indemnifications often are not explicitly stated, and the overall maximum amount of the obligation under these indemnifications cannot be reasonably estimated. SCE has not recorded a liability related to these indemnities.

Contingencies

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

Environmental Remediation

SCE 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.

SCE 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 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 SCEs financial position and results of operations would not be materially affected.

SCE 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. SCE 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, SCE records the lower end of this reasonably likely range of costs (classified as other long-term liabilities) at undiscounted amounts.

As of September 30, 2007, SCEs recorded estimated minimum liability to remediate its 24 identified sites was $69 million. The ultimate costs to clean up
SCE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. SCE believes that, due to these uncertainties,
it is reasonably possible that cleanup costs could exceed its recorded liability by up to $132 million. The upper limit of this range of costs was estimated using assumptions least favorable to SCE 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 31 immaterial sites whose total liability ranges from $2 million (the recorded minimum liability) to
$7 million.

The CPUC allows SCE to recover environmental remediation costs at certain sites, representing $30 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
$66 million for its estimated minimum environmental-cleanup costs expected to be recovered through customer rates.



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SCE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 SCE may be held responsible for contributing to any costs incurred for remediating these sites. Thus, no reasonable estimate of cleanup costs can be made for these sites.

SCE expects to clean up its identified sites over a period of up to 30 years. Remediation costs in each of the next several years are expected to
range from $11 million to $31 million. Recorded costs for the 12 months ended September 30, 2007 were $22 million.

Based on currently
available information, SCE 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, SCE
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 remains subject to examination and administrative appeals by the IRS for tax years 1994 present. Edison International is challenging
certain IRS examination adjustments for tax years 1994  1999 with the Administrative Appeals branch of the IRS and Edison International is currently under IRS examination for tax years 2000  2002. In addition, the
statute of limitations remains open for tax years 1986  1993 for certain affirmative claims.

The IRS has asserted deficiencies in federal
corporate income taxes with respect to tax years 1994  1999. Many of the asserted tax deficiencies are timing differences and, therefore, amount ultimately paid (exclusive of penalties), if any, would be deductible on future tax returns of
Edison International. In addition, Edison International has also submitted affirmative claims to the IRS and state tax agencies. Any benefits associated with these affirmative claims 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.

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 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, SCE recorded a $49 million benefit related to a tax reserve adjustment as a result of this settlement. In addition to this tax
reserve adjustment, SCE received a net cash refund of $52 million in April 2007 as a result of this same settlement.

In July 2007, Edison
International received a Notice of Proposed Adjustment from the IRS on an affirmative claim position involving the taxability of balancing account over-collections. This issue is addressed as part of



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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 $70 million to
$80 million and $300 million to $325 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 and is currently protesting the deficiencies asserted. Edison International remains subject to examination by the California Franchise Tax Board for tax years 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 through 2002 with the IRS and various State authorities. The timing for resolving these open tax
positions is uncertain, but it is reasonably possible that all or some portion of these open tax positions could be resolved in the next 12 months.

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, in late 2005, the
Ninth Circuit ruled in Bonneville Power Admin 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 or refunds 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.

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 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 ISO and PX to immediately return collateral previously deposited by governmental
sellers and pay receivables that governmental sellers claim are owed to them.

On October 19, 2007, the FERC issued an order in the Bonneville case,
concluding that the Ninth Circuits decision required the FERC to vacate its previous orders compelling governmental sellers during the California energy crisis to pay refunds and to release to governmental suppliers the amounts that had been
withheld from, as well as collateral posted, from such suppliers for power delivered during the energy crisis. In its order, the FERC also expressly recognized that civil lawsuits against the governmental suppliers could provide an alternative
refund remedy for SCE and the other California utilities. It also left open the possibility that a court with



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jurisdiction over the matter could order the ISO or PX to retain collateral. SCE cannot predict at this time the impact of the FERCs order or whether
SCE may be able to recover any additional refunds from governmental power sellers as a result of the pending lawsuits.

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. In October 2007, SCE received an additional distribution on its allowed bankruptcy claim of approximately $10 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.

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



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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 for the years 1997  2003. SCE received $8 million in
reliability incentive awards for the period 1997  2000 and applied for a reward of $5 million for 2001. For 2002, SCEs data indicated that it earned no reward and incurred no penalty. For 2003, based on the application of the PBR
mechanism, it would incur a penalty of $3 million and accrued a charge for that amount in 2004. On February 28, 2005, SCE provided its final investigation report to the CPUC concluding that the reliability reporting system was 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. 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 DRA and The
Utility Reform Network, filed testimony on these matters recommending various refunds and penalties be imposed on SCE. In their testimony, the various parties made refund and penalty recommendations that range up to the following amounts: refund or
forgo $48 million in rewards for customer satisfaction, impose $70 million penalties for customer satisfaction, refund or forgo $35 million in rewards for employee safety, impose $35 million penalties for employee safety, impose
$102 million in statutory penalties, refund $84 million of amounts collected in rates for employee bonuses (results sharing), refund $4 million of miscellaneous survey expenses, and require $10 million of new employee
safety programs. These recommendations total up to $388 million. On October 16, 2006, SCE filed testimony opposing the various refund and penalty recommendations of the CPSD and other intervenors.

On October 1, 2007, a POD was released ordering SCE to refund $136 million, plus interest, and pay a penalty of $40 million. In addition, the POD requires SCE to
forgo an additional $35 million in rewards for which it would have otherwise been eligible. Included in the amount to be refunded or forgone is $48 million related to customer satisfaction rewards, $35 million related to employee safety
rewards, and $77 million related to results sharing. The decision requires that the proposed results sharing refund of $77 million (based on year 2000 data) be adjusted for attrition and escalation which increases the result sharing refund to $88
million. After the result sharing adjustment is made, the total amount SCE would be required to refund increases to $136 million, before



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interest. Interest to date, based on amounts collected for customer satisfaction, safety incentives and results sharing, including escalation and attrition
adjustments, would add an additional $26 million to this amount. On October 31, 2007, SCE appealed the POD to the CPUC.

SCE cannot predict the
outcome of the appeal. Based on SCEs proposed refunds, the combined recommendations of the CPSD and other intervenors, as well as the POD, 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 (approximately $15 million as of September 30, 2007) on collected amounts that SCE has proposed to refund to customers.

The system reliability component of PBR was not addressed in the POD. Pursuant to an earlier order in the case, system reliability incentives will be addressed in a
second phase of the proceeding, which commenced with the filing of SCEs opening testimony in September 2007. In that testimony, SCE confirmed that its PBR system reliability results, which reflected rewards of $13 million for 1997 through
2002 and a penalty of $3 million in 2003 were valid. The CPSD has requested an indefinite suspension of the schedule for the second phase of the proceeding pending resolution of the appeals of the POD. SCE cannot predict the outcome of the
second phase.

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 limited 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.

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



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reimbursed to Midway-Sunset would be recoverable from its customers through current regulatory mechanisms. SCE does not expect any reimbursement to
Midway-Sunset to have a material impact on earnings.

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 denied 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. In September 2007, the Federal Circuit reversed the lower court decision on remand in
the related lawsuit, finding that the U.S. Government had breached its trust obligation in connection with the setting of the royalty rate for the coal supplied to Mohave. The Federal Circuit decision is potentially subject to further review but it
is unknown at this time whether the U.S. Government will pursue such review.

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. Based on the information presented in the October 5, 2007 joint status report, the District Court directed the parties to file another status report by November 9, 2007, with
recommendations for further proceedings.

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



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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.

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 $46 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 were 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 based on the outcome of recently completed surveys of its plant
personnel and self-assessments of its programs and procedures. These corrective actions are currently being developed in conjunction with the NRC, and are forecast to be completed by the end of 2007. These corrective actions will increase costs to
both Palo Verde and its co-owners, including SCE. SCE cannot calculate the total increase in costs until the corrective actions are finalized, but presently estimates that operation and maintenance costs at Palo Verde will increase by approximately
$30 million (nominal) over the three year period 2007  2009, including overhead costs. 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. In March 2007, 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 prior to year end 2007. As of September 30, 2007, SCE has an accrued liability of $49 million (including $7 million of interest) representing total charges collected that are subject to
refund. 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. In
a FERC filing dated October 30, 2007, SCE forecasted that the refund to the DWP for the scheduling coordinator charges under the settlement would be made on January 1, 2008 and would be approximately $20 million. The amount is
proposed to be recovered from all transmission grid customers through SCEs transmission rates on that date.

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



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storage installation where all of Unit 1s spent fuel located at San Onofre and some of Unit 2s spent fuel 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 6. Supplemental Cash Flows Information



|                                                                   |  |                                |     |   |      |   |      |  
|------------------------------------------------------------------ |  | ------------------------------ | --- | - | ---- | - | ---- | -
|                                                                   |  | Nine Months EndedSeptember 30, |    
|In millions                                                        |  | 2007                           |     |   | 2006 |  
|                                                                   |  | (Unaudited)                    |    
|Cash payments for interest and taxes:                              |  |                                |     |   |      |   |      |  
|Interest  net of amounts capitalized                              |  | $                              | 241 |   |      | $ | 266  |  
|Tax payments                                                       |  |                                | 14  |   |      |   | 297  |  
|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                                                       |  | $                              | 25  |   |      | $ | 60   |  
|Preferred and Preference stock not subject to mandatory redemption |  |                                | 8   |   |      |   | 9    |  



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Note 7. Regulatory Assets and Liabilities

Regulatory assets included in the consolidated balance sheets are:



|                                                             |  |                   |       |                  |   |      
|------------------------------------------------------------ |  | ----------------- | ----- | ---------------- | - | -----
|In millions                                                  |  | September 30,2007 |       | December 31,2006
|                                                             |  | (Unaudited)       |       |                 
|Current:                                                     |  |                   |       |                  |   |      
|Regulatory balancing accounts                                |  | $                 | 99    |                  | $ | 128  
|Rate reduction notes  transition cost deferral              |  |                   | 34    |                  |   | 219  
|Direct access procurement charges                            |  |                   |      |                  |   | 63   
|Energy derivatives                                           |  |                   | 100   |                  |   | 88   
|Purchased-power settlements                                  |  |                   | 13    |                  |   | 31   
|Deferred FTR proceeds                                        |  |                   | 27    |                  |   | 14   
|Other                                                        |  |                   | 22    |                  |   | 11   
|                                                             |  |                   | 295   |                  |   | 554  
|Long-term:                                                   |  |                   |       |                  |   |      
|Flow-through taxes  net                                     |  |                   | 1,131 |                  |   | 1,023
|Unamortized nuclear investment  net                         |  |                   | 414   |                  |   | 435  
|Nuclear-related asset retirement obligation investment  net |  |                   | 302   |                  |   | 317  
|Unamortized coal plant investment  net                      |  |                   | 96    |                  |   | 102  
|Unamortized loss on reacquired debt                          |  |                   | 310   |                  |   | 318  
|SFAS No. 158 pensions and postretirement benefits            |  |                   | 306   |                  |   | 303  
|Energy derivatives                                           |  |                   | 100   |                  |   | 145  
|Environmental remediation                                    |  |                   | 66    |                  |   | 77   
|Other                                                        |  |                   | 100   |                  |   | 98   
|                                                             |  |                   | 2,825 |                  |   | 2,818
|Total Regulatory Assets                                      |  | $                 | 3,120 |                  | $ | 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 through January 2008.

Regulatory liabilities included in the consolidated balance
sheets are:



|                                                        |  |                   |       |                  |   |      
|------------------------------------------------------- |  | ----------------- | ----- | ---------------- | - | -----
|In millions                                             |  | September 30,2007 |       | December 31,2006
|                                                        |  | (Unaudited)       |       |                 
|Current:                                                |  |                   |       |                  |   |      
|Regulatory balancing accounts                           |  | $                 | 1,247 |                  | $ | 912  
|Direct access procurement charges                       |  |                   |      |                  |   | 63   
|Energy derivatives                                      |  |                   | 7     |                  |   | 7    
|Deferred FTR costs                                      |  |                   | 62    |                  |   | 11   
|Other                                                   |  |                   |      |                  |   | 7    
|                                                        |  |                   | 1,316 |                  |   | 1,000
|Long-term:                                              |  |                   |       |                  |   |      
|Asset retirement obligations                            |  |                   | 865   |                  |   | 732  
|Costs of removal                                        |  |                   | 2,207 |                  |   | 2,158
|SFAS No. 158 pensions and other postretirement benefits |  |                   | 157   |                  |   | 145  
|Energy derivatives                                      |  |                   | 8     |                  |   | 27   
|Employee benefit plans                                  |  |                   | 78    |                  |   | 78   
|                                                        |  |                   | 3,315 |                  |   | 3,140
|Total Regulatory Liabilities                            |  | $                 | 4,631 |                  | $ | 4,140



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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 in various periods through March 2008.

Note 8. Business Segments

SCEs reportable business segments
include the rate-regulated electric utility segment and the VIEs segment. The VIEs were consolidated as of March 31, 2004. Additional details on the VIE segment are in Note 14 of Notes to Consolidated Financial Statements
included in SCEs 2006 Annual Report on Form 10-K. The VIEs are gas-fired power plants that sell both electricity and steam. The VIE segment consists of non-rate-regulated entities (all in California). SCEs management has no control over
the resources allocated to the VIE segment and does not make decisions about its performance.

SCEs consolidated balance sheet captions impacted by
VIE activities are presented below:



|                                              |  |                 |        |      |   |              |  |   |     |   |  |   |       
|--------------------------------------------- |  | --------------- | ------ | ---- | - | ------------ |  | - | --- | - |  | - | ------
|In millions                                   |  | ElectricUtility |        | VIEs |   | Eliminations |  |   | SCE
|                                              |  | (Unaudited)    
|Balance Sheet Items as of September 30, 2007: |  |                 |        |      |   |              |  |   |     |   |  |   |       
|Cash and equivalents                          |  | $               | 11     |      | $ | 104          |  | $ |    |   |  | $ | 115   
|Accounts receivable  net                     |  |                 | 995    |      |   | 110          |  |   | (78 | ) |  |   | 1,027 
|Inventory                                     |  |                 | 258    |      |   | 14           |  |   |    |   |  |   | 272   
|Other current assets                          |  |                 | 111    |      |   | 6            |  |   |    |   |  |   | 117   
|Nonutility property  net of depreciation     |  |                 | 706    |      |   | 298          |  |   |    |   |  |   | 1,004 
|Other long-term assets                        |  |                 | 485    |      |   | 4            |  |   |    |   |  |   | 489   
|Total assets                                  |  |                 | 27,126 |      |   | 536          |  |   | (78 | ) |  |   | 27,584
|Long-term debt due within one year            |  |                 | 218    |      |   | 2            |  |   |    |   |  |   | 220   
|Accounts payable                              |  |                 | 834    |      |   | 57           |  |   | (78 | ) |  |   | 813   
|Accrued interest                              |  |                 | 95     |      |   | 1            |  |   |    |   |  |   | 96    
|Other current liabilities                     |  |                 | 592    |      |   | 2            |  |   |    |   |  |   | 594   
|Asset retirement obligations                  |  |                 | 2,809  |      |   | 14           |  |   |    |   |  |   | 2,823 
|Minority interest                             |  |                 | 1      |      |   | 460          |  |   |    |   |  |   | 461   
|Total liabilities and shareholders equity    |  | $               | 27,126 |      | $ | 536          |  | $ | (78 | ) |  | $ | 27,584
|Balance Sheet Items as of December 31, 2006:  |  |                 |        |      |   |              |  |   |     |   |  |   |       
|Cash and equivalents                          |  | $               | 5      |      | $ | 78           |  | $ |    |   |  | $ | 83    
|Accounts receivable  net                     |  |                 | 893    |      |   | 141          |  |   | (95 | ) |  |   | 939   
|Inventory                                     |  |                 | 218    |      |   | 14           |  |   |    |   |  |   | 232   
|Other current assets                          |  |                 | 50     |      |   | 4            |  |   |    |   |  |   | 54    
|Nonutility property  net of depreciation     |  |                 | 727    |      |   | 319          |  |   |    |   |  |   | 1,046 
|Other long-term assets                        |  |                 | 481    |      |   | 7            |  |   |    |   |  |   | 488   
|Total assets                                  |  |                 | 25,642 |      |   | 563          |  |   | (95 | ) |  |   | 26,110
|Accounts payable                              |  |                 | 809    |      |   | 142          |  |   | (95 | ) |  |   | 856   
|Other current liabilities                     |  |                 | 622    |      |   | 2            |  |   |    |   |  |   | 624   
|Long-term debt                                |  |                 | 5,117  |      |   | 54           |  |   |    |   |  |   | 5,171 
|Asset retirement obligations                  |  |                 | 2,735  |      |   | 14           |  |   |    |   |  |   | 2,749 
|Minority interest                             |  |                 |       |      |   | 351          |  |   |    |   |  |   | 351   
|Total liabilities and shareholders equity    |  | $               | 25,642 |      | $ | 563          |  | $ | (95 | ) |  | $ | 26,110



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SCEs consolidated statements of income, by business segment, are presented below:



|                                                                     |  |                 |       |   |      |   |      |               |  |   |      |   |  |   |       |  
|-------------------------------------------------------------------- |  | --------------- | ----- | - | ---- | - | ---- | ------------- |  | - | ---- | - |  | - | ----- | -
|In millions                                                          |  | ElectricUtility |       |   | VIEs |   |      | Eliminations* |  |   | SCE  |  
|                                                                     |  | (Unaudited)     |      
|Income Statement Items for theThree Months Ended September 30, 2007: |  |                 |       |   |      |   |      |               |  |   |      |   |  |   |       |  
|Operating revenue                                                    |  | $               | 3,133 |   |      | $ | 309  |               |  | $ | (228 | ) |  | $ | 3,214 |  
|Fuel                                                                 |  |                 | 147   |   |      |   | 163  |               |  |   |     |   |  |   | 310   |  
|Purchased power                                                      |  |                 | 1,512 |   |      |   |     |               |  |   | (228 | ) |  |   | 1,284 |  
|Provisions for regulatory adjustment clausesnet                     |  |                 | (66   | ) |      |   |     |               |  |   |     |   |  |   | (66   | )
|Other operation and maintenance                                      |  |                 | 706   |   |      |   | 20   |               |  |   |     |   |  |   | 726   |  
|Depreciation, decommissioning and amortization                       |  |                 | 258   |   |      |   | 9    |               |  |   |     |   |  |   | 267   |  
|Property and other taxes                                             |  |                 | 54    |   |      |   |     |               |  |   |     |   |  |   | 54    |  
|Total operating expenses                                             |  |                 | 2,611 |   |      |   | 192  |               |  |   | (228 | ) |  |   | 2,575 |  
|Operating income                                                     |  |                 | 522   |   |      |   | 117  |               |  |   |     |   |  |   | 639   |  
|Interest income                                                      |  |                 | 11    |   |      |   | 2    |               |  |   |     |   |  |   | 13    |  
|Other nonoperating income                                            |  |                 | 16    |   |      |   | 13   |               |  |   |     |   |  |   | 29    |  
|Interest expense  net of amounts capitalized                        |  |                 | (117  | ) |      |   |     |               |  |   |     |   |  |   | (117  | )
|Other nonoperating deductions                                        |  |                 | (7    | ) |      |   |     |               |  |   |     |   |  |   | (7    | )
|Income tax expense                                                   |  |                 | (150  | ) |      |   |     |               |  |   |     |   |  |   | (150  | )
|Minority interest                                                    |  |                 |      |   |      |   | (132 | )             |  |   |     |   |  |   | (132  | )
|Net income                                                           |  | $               | 275   |   |      | $ |     |               |  | $ |     |   |  | $ | 275   |  
|                                                                     |  |                 |       |  
|Income Statement Items for theThree Months Ended September 30, 2006: |  |                 |       |   |      |   |      |               |  |   |      |   |  |   |       |  
|Operating revenue                                                    |  | $               | 2,989 |   |      | $ | 327  |               |  | $ | (237 | ) |  | $ | 3,079 |  
|Fuel                                                                 |  |                 | 113   |   |      |   | 173  |               |  |   |     |   |  |   | 286   |  
|Purchased power                                                      |  |                 | 1,273 |   |      |   |     |               |  |   | (237 | ) |  |   | 1,036 |  
|Provisions for regulatory adjustment clausesnet                     |  |                 | 115   |   |      |   |     |               |  |   |     |   |  |   | 115   |  
|Other operation and maintenance                                      |  |                 | 644   |   |      |   | 18   |               |  |   |     |   |  |   | 662   |  
|Depreciation, decommissioning and amortization                       |  |                 | 245   |   |      |   | 9    |               |  |   |     |   |  |   | 254   |  
|Property and other taxes                                             |  |                 | 53    |   |      |   |     |               |  |   |     |   |  |   | 53    |  
|Total operating expenses                                             |  |                 | 2,443 |   |      |   | 200  |               |  |   | (237 | ) |  |   | 2,406 |  
|Operating income                                                     |  |                 | 546   |   |      |   | 127  |               |  |   |     |   |  |   | 673   |  
|Interest income                                                      |  |                 | 14    |   |      |   |     |               |  |   |     |   |  |   | 14    |  
|Other nonoperating income                                            |  |                 | 13    |   |      |   |     |               |  |   |     |   |  |   | 13    |  
|Interest expense  net of amounts capitalized                        |  |                 | (98   | ) |      |   |     |               |  |   |     |   |  |   | (98   | )
|Other nonoperating deductions                                        |  |                 | (12   | ) |      |   |     |               |  |   |     |   |  |   | (12   | )
|Income tax expense                                                   |  |                 | (187  | ) |      |   |     |               |  |   |     |   |  |   | (187  | )
|Minority interest                                                    |  |                 |      |   |      |   | (127 | )             |  |   |     |   |  |   | (127  | )
|Net income                                                           |  | $               | 276   |   |      | $ |     |               |  | $ |     |   |  | $ | 276   |  

|* | VIE segment revenue includes sales to the electric utility segment, which are eliminated in revenue and purchased power in the consolidated statements of income.
|- | -----------------------------------------------------------------------------------------------------------------------------------------------------------------



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|                                                                    |  |                 |       |   |      |   |      |               |  |   |      |   |  |   |       |  
|------------------------------------------------------------------- |  | --------------- | ----- | - | ---- | - | ---- | ------------- |  | - | ---- | - |  | - | ----- | -
|In millions                                                         |  | ElectricUtility |       |   | VIEs |   |      | Eliminations* |  |   | SCE  |  
|                                                                    |  | (Unaudited)     |      
|                                                                    |  |                 |       |  
|Income Statement Items for theNine Months Ended September 30, 2007: |  |                 |       |   |      |   |      |               |  |   |      |   |  |   |       |  
|Operating revenue                                                   |  | $               | 7,611 |   |      | $ | 877  |               |  | $ | (591 | ) |  | $ | 7,897 |  
|Fuel                                                                |  |                 | 368   |   |      |   | 536  |               |  |   |     |   |  |   | 904   |  
|Purchased power                                                     |  |                 | 3,022 |   |      |   |     |               |  |   | (591 | ) |  |   | 2,431 |  
|Provisions for regulatory adjustment clausesnet                    |  |                 | 189   |   |      |   |     |               |  |   |     |   |  |   | 189   |  
|Other operation and maintenance                                     |  |                 | 1,920 |   |      |   | 68   |               |  |   |     |   |  |   | 1,988 |  
|Depreciation, decommissioning and amortization                      |  |                 | 786   |   |      |   | 27   |               |  |   |     |   |  |   | 813   |  
|Property and other taxes                                            |  |                 | 164   |   |      |   |     |               |  |   |     |   |  |   | 164   |  
|Total operating expenses                                            |  |                 | 6,449 |   |      |   | 631  |               |  |   | (591 | ) |  |   | 6,489 |  
|Operating income                                                    |  |                 | 1,162 |   |      |   | 246  |               |  |   |     |   |  |   | 1,408 |  
|Interest income                                                     |  |                 | 32    |   |      |   | 2    |               |  |   |     |   |  |   | 34    |  
|Other nonoperating income                                           |  |                 | 55    |   |      |   | 13   |               |  |   |     |   |  |   | 68    |  
|Interest expense  net of amounts capitalized                       |  |                 | (330  | ) |      |   |     |               |  |   |     |   |  |   | (330  | )
|Other nonoperating deductions                                       |  |                 | (31   | ) |      |   |     |               |  |   |     |   |  |   | (31   | )
|Income tax expense                                                  |  |                 | (263  | ) |      |   |     |               |  |   |     |   |  |   | (263  | )
|Minority interest                                                   |  |                 |      |   |      |   | (261 | )             |  |   |     |   |  |   | (261  | )
|Net income                                                          |  | $               | 625   |   |      | $ |     |               |  | $ |     |   |  | $ | 625   |  
|                                                                    |  |                 |       |  
|Income Statement Items for theNine Months Ended September 30, 2006: |  |                 |       |   |      |   |      |               |  |   |      |   |  |   |       |  
|Operating revenue                                                   |  | $               | 7,524 |   |      | $ | 899  |               |  | $ | (605 | ) |  | $ | 7,818 |  
|Fuel                                                                |  |                 | 277   |   |      |   | 559  |               |  |   |     |   |  |   | 836   |  
|Purchased power                                                     |  |                 | 3,424 |   |      |   |     |               |  |   | (605 | ) |  |   | 2,819 |  
|Provisions for regulatory adjustment clausesnet                    |  |                 | (256  | ) |      |   |     |               |  |   |     |   |  |   | (256  | )
|Other operation and maintenance                                     |  |                 | 1,847 |   |      |   | 69   |               |  |   |     |   |  |   | 1,916 |  
|Depreciation, decommissioning and amortization                      |  |                 | 779   |   |      |   | 27   |               |  |   |     |   |  |   | 806   |  
|Property and other taxes                                            |  |                 | 158   |   |      |   |     |               |  |   |     |   |  |   | 158   |  
|Net gain on sale of utility property and plant                      |  |                 | (1    | ) |      |   |     |               |  |   |     |   |  |   | (1    | )
|Total operating expenses                                            |  |                 | 6,228 |   |      |   | 655  |               |  |   | (605 | ) |  |   | 6,278 |  
|Operating income                                                    |  |                 | 1,296 |   |      |   | 244  |               |  |   |     |   |  |   | 1,540 |  
|Interest income                                                     |  |                 | 44    |   |      |   |     |               |  |   |     |   |  |   | 44    |  
|Other nonoperating income                                           |  |                 | 61    |   |      |   |     |               |  |   |     |   |  |   | 61    |  
|Interest expense  net of amounts capitalized                       |  |                 | (297  | ) |      |   |     |               |  |   |     |   |  |   | (297  | )
|Other nonoperating deductions                                       |  |                 | (32   | ) |      |   |     |               |  |   |     |   |  |   | (32   | )
|Income tax expense                                                  |  |                 | (416  | ) |      |   |     |               |  |   |     |   |  |   | (416  | )
|Minority interest                                                   |  |                 |      |   |      |   | (244 | )             |  |   |     |   |  |   | (244  | )
|Net income                                                          |  | $               | 656   |   |      | $ |     |               |  | $ |     |   |  | $ | 656   |  

|* | VIE segment revenue includes sales to the electric utility segment, which are eliminated in revenue and purchased power in the consolidated statements of income.
|- | -----------------------------------------------------------------------------------------------------------------------------------------------------------------



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|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 nine-month periods ended September 30, 2007 discusses material changes in the financial condition, results of operations and other developments of SCE since December 31, 2006, and as compared to the three-
and nine-month periods ended September 30, 2006. This discussion presumes that the reader has read or has access to SCEs MD&A for the calendar year 2006 (the year-ended 2006 MD&A), which was included in SCEs 2006 annual
report to shareholders and incorporated by reference into SCE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 SCEs current expectations and projections about future events based on SCE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 SCE 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 SCE or its subsidiaries, include, but are not limited to:



| |  | 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;
|- |  | ----------------------------------------------



| |  | 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 cost and 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;
|- |  | --------------------------------------------------------------------------------------------------------------------------------



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



| |  | 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;
|- |  | ----------------------------------------------------------------------------------------------



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| |  | 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 SCE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 SCEs business. Forward-looking statements speak only as of the
date they are made and SCE is not obligated to publicly update or revise forward-looking statements. Readers should review future reports filed by SCE with the Securities & Exchange Commission.

This MD&A includes information about SCE, an investor-owned utility company providing electricity to retail customers in central, coastal and southern California.
SCE is regulated by the CPUC and FERC.

This MD&A is presented in 8 major sections: (1) current developments; (2) liquidity;
(3) regulatory matters; (4) other developments; (5) market risk exposures; (6) results of operations and historical cash flow analysis; (7) new accounting pronouncements; and (8) commitments and indemnities.

CURRENT DEVELOPMENTS

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 and should be read together with all sections of
this MD&A.

Investigations Regarding Performance Incentives Rewards

On October 1, 2007, a POD was released regarding the investigation into SCEs incentives claimed under a CPUC-approved PBR mechanism that allowed SCE to earn rewards or penalties for the period of
1997  2003 based on its performance in comparison to CPUC-approved standards of customer satisfaction, employee injury and illness reporting, and system reliability. The POD orders SCE to refund incentives already collected and forgo
incentives claimed but not collected in the total amount of $160 million, plus interest, and pay a penalty of $40 million. Included in the $160 million to be refunded or forgone is $48 million related to customer satisfaction rewards, $35
million related to employee safety rewards, and $77 million related to amounts collected in rates for employee bonuses (results sharing) (which is required to be adjusted for escalation). On October 31, 2007, SCE appealed the
POD to the CPUC. See Regulatory MattersInvestigations Regarding Performance Incentives Rewards for further discussion.

Energy
Efficiency Shareholder Risk/Reward Incentive Mechanism

On September 20, 2007, the CPUC issued a decision that adopted an Energy Efficiency
Risk/Reward Incentive mechanism covering two three year periods (2006  2008 and 2009  2011). The mechanism allows for both incentives and economic penalties based on SCEs performance toward meeting CPUC goals for energy efficiency.
The intent of the mechanism is to elevate the importance of customer energy efficiency programs by allowing utility shareholders to participate in the benefits produced by such programs, ensuring that energy efficiency is viewed as a core part of
the utilities operations. Both incentives and economic penalties for each three year period are capped at $200 million. Assuming SCE achieves its energy efficiency and net benefit goals of approximately $1.2 billion, the three-year earnings
opportunity would be approximately $146 million pre-tax,



27



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a portion of which is expected to be collected through rates beginning in 2009. See Regulatory MattersEnergy Efficiency Shareholder Risk/Reward
Incentive Mechanism for further discussion.

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 requested 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%. On September 20, 2007, SCE updated its requested cost of long-term debt to 6.22% and its requested cost of preferred equity to 6.01%. SCE
expects a decision on the 2008 cost of capital application by the end of 2007.

2009 General Rate Case

On September 19, 2007, the DRA accepted SCEs modified NOI. SCE expects to file its GRC application in November 2007. A final decision on SCEs 2009 GRC is
expected by December 2008. On July 23, 2007, SCE tendered to the CPUCs DRA its NOI to file a 2009 GRC application. 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 $251 million and $285 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 revenue requirement rather than the current structure under which SCE recovers Mountainview
generating costs through a power purchase agreement. SCE cannot predict the revenue requirement the CPUC will ultimately authorize or precisely when a final decision will be adopted.

EdisonSmartConnecttm

SCEs EdisonSmartConnecttmproject 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 expected 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 EdisonSmartConnecttmtechnologies, select the deployment vendor and finalize the EdisonSmartConnecttmbusiness case for full deployment, which is being conducted during 2007; and the final 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 approved $45 million for Phase II of this project. SCE filed its Phase III
application on July 31, 2007, requesting CPUC authorization to deploy EdisonSmartConnecttmmeters 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 July 2008.



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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 Regulatory MattersPeaker Plant Generation Projects for further discussion.

LIQUIDITY

Overview

As of September 30, 2007, SCE had cash and equivalents of $115 million ($104 million of which was held by SCEs consolidated VIEs). As of
September 30, 2007, long-term debt, including current maturities of long-term debt, was $5.3 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 September 30, 2007, the credit facility supported $200 million in letters of credit, leaving $2.3 billion available for liquidity purposes.

SCEs estimated cash outflows during the 12-month period following September 30, 2007 are expected to consist of:



| |  | Debt maturities of approximately $220 million, including $68 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 $830 million 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. The Board of Directors of SCE declared a $60 million dividend to Edison International which was paid in January 2007
and quarterly dividends of $25 million which were paid in April 2007, July 2007, and October 2007;
|- |  | ------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------



| |  | Fuel and procurement-related costs (see 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. 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 Regulatory Matters and Commitments and Indemnities.

Capital Expenditures

As discussed under the heading 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 and construct its distribution and transmission infrastructure, and to construct and replace major components of generation



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assets. SCEs 2007 through 2011 capital investment plan includes total capital spending of up to $17.3 billion. During the nine-month period ended
September 30, 2007, SCE spent $1.54 billion in capital expenditures related to its 2007 capital plan.

Credit Ratings

At September 30, 2007, SCEs credit ratings were as follows:



|                              |  |               |  |           |  |            
|----------------------------- |  | ------------- |  | --------- |  | -----------
|                              |  | MoodysRating |  | S&PRating |  | FitchRating
|Long-term senior secured debt |  | A2            |  | A         |  | A+         
|Short-term (commercial paper) |  | P-2           |  | A-2       |  | F-1        

On September 6, 2007, S&P raised SCEs credit rating for long-term senior secured debt to A from
BBB+. 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. 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 September 30, 2007, SCEs 13-month
weighted-average common equity component of total capitalization was 50.18%. At September 30, 2007, SCE had the capacity to pay $260 million in additional dividends based on the 13-month weighted-average method. However, based on recorded
September 30, 2007 balances, SCEs common equity to total capitalization ratio (as adjusted for rate-making purposes) was 51.58%. SCE had the capacity to pay $427 million of additional dividends to Edison International based on
September 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 September 30, 2007, SCEs debt to total capitalization ratio was 0.43 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
September 30, 2007, SCE had a net deposit of $195 million (consisting of $35 million in cash and reflected in Margin and collateral deposits on the consolidated balance sheet and $160 million in letters of credit)
with counterparties. In addition, SCE has deposited $51 million (consisting of $11 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.



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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 CDWR) mainly as the result of projected 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 redesign of SCEs tiered rate structure resulting in a decrease of rates in the higher tiers for residential customers and 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 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. 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 estimated 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 the current system average rate
of 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%. SCE will revise its requested 2008 ERRA revenue requirement
November 2007. Based on SCEs current ERRA balancing account overcollection, and anticipated lower 2008 power and gas prices, SCE expects the 2008 ERRA revenue requirement and bundled system average rate to decrease from its original forecast
of 14.4¢ per-kWh filed in August 2007.

Energy Efficiency Shareholder Risk/Reward Incentive Mechanism

On September 20, 2007, the CPUC issued a decision that adopted an Energy Efficiency Risk/Reward Incentive mechanism. The CPUC will review the operation of the
mechanism over two three year program periods (2006  2008 and 2009  2011) to determine if any modifications to the mechanism are warranted for the 2012  2014 program period. SCE has the opportunity to earn an
incentive of 9% of the value of the total energy efficiency savings if it achieves between 85% and 100% of its energy efficiency goals for the cumulative three year period and can earn 12% of the value of the energy efficiency savings if 100% or
greater of its goals are achieved. Economic penalties would be imposed in the event the utility achieves 65% or less of its goals. The mechanism also establishes a deadband between 65% and 85% of energy efficiency goals, where no economic penalty or
incentive would be earned. The mechanism allows for collection of 70% of the first two years (2006  2007) progress in customer rates, beginning in 2009; 70% of the next years (2008) progress in 2010 and collection of a
final true-up payment for the remaining 30%, as adjusted for actual performance in 2011. SCE is scheduled to file advice filings in September of each year requesting recovery of the progress payments in accordance with the mechanism. SCE expects it
will recognize earnings in the amount of the progress payments upon CPUC acceptance of its filing, expected in the fourth quarter of each year. On October 31, 2007, SCE and the other California utilities filed a joint petition for modification
which would allow the utilities to retain the first and second progress payments as long as the utilities meet a minimum of 65% of the anticipated goals. If the utilities fall below the 65% level, the progress payments would need to be refunded and
penalties would be



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incurred. In the event SCE reaches 100% of its goals for the 2006  2008 period, the approximate incentive would be $146 million pre-tax in total
for the three year period. SCE currently estimates it will meet 100% of its energy efficiency goals. In the event SCE reaches 65% or less of its goals for the 2006  2008 period, the approximate penalty could range between
$58 million to $200 million for the three year period, depending on SCEs performance against its energy efficiency goals.

FERC
Petition for Transmission Incentives

On May 18, 2007, SCE filed a petition seeking 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. A FERC ruling on the petition is likely to be issued before year-end 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 a 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 filed an appeal of the ACCs decision with the Maricopa County Superior Court on August 31, 2007 and agreed to a stay of the appeal until March 2008 in order to allow it to explore potential options with the Arizona
stakeholders, including the ACC. SCE continues to evaluate its options, which include filing a new application with the ACC and building the project in various phases. As of September 30, 2007, SCE has spent approximately $29 million on
this project. SCE expects to fully recover its costs from this project, but cannot predict the outcome of regulatory proceedings.

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 power 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 September 30, 2007, the ERRA was overcollected by $557 million. SCE had anticipated this overcollection to decrease during 2007, based on the reduced ERRA revenue requirement
approved by the CPUC on January 25, 2007. However, due to the impact of lower gas prices, as compared to forecast, and higher revenue resulting from warmer weather, SCEs ERRA overcollection balance began to increase in August 2007. SCE
will notify the CPUC that the 2007 ERRA overcollection has exceeded 5% of SCEs generation revenue from the prior year and will propose to include the refund of the ERRA overcollection in the planned rate change on January 1, 2008 or soon
thereafter. The 2008 ERRA revenue requirement will be updated in November 2007 to reflect the latest ERRA overcollection balance as discussed above in Impact of Regulatory Matters on Customer Rates.



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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 limited 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 and were dispatched in August to help meet peak customer demands. SCE continues to pursue the
construction of the fifth project, but the required construction permit has been denied by the City of Oxnard. SCE believes the permit denial to be without merit and has appealed this denial to the Coastal Commission and expects a decision in the
first quarter of 2008. 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 project. SCE has revised its budget for all five projects from its original estimate of $250 million to approximately $300 million. As of September 30, 2007, SCE
has spent or firmly committed approximately $280 million in costs for all five projects. SCE expects to fully recover its costs from these projects, but cannot predict the outcome of regulatory proceedings.

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. In March 2007, based on terms of the controlling California statute, 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 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.



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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 prior to year end 2007. As of September 30, 2007, SCE has an accrued liability of $49 million (including $7 million of interest)
representing total charges collected that are subject to refund. 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. In a FERC filing dated October 30, 2007, SCE forecasted that the refund to the DWP for the scheduling coordinator charges under the settlement would be made on January 1, 2008 and
would be approximately $20 million. The amount is proposed to be recovered from all transmission grid customers through SCEs transmission rates on that date.

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, in late 2005, the Ninth Circuit ruled in Bonneville Power Admin 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 or refunds 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.

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 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



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Bonneville required FERC to order the ISO and PX to immediately return collateral previously deposited by governmental sellers and pay receivables that
governmental sellers claim are owed to them.

On October 19, 2007, the FERC issued an order in the Bonneville case, concluding that the Ninth
Circuits decision required the FERC to vacate its previous orders compelling governmental sellers during the California energy crisis to pay refunds and to release to governmental suppliers the amounts that had been withheld from, as well as
collateral posted, from such suppliers for power delivered during the energy crisis. In its order, the FERC also expressly recognized that civil lawsuits against the governmental suppliers could provide an alternative refund remedy for SCE and the
other California utilities. It also left open the possibility that a court with jurisdiction over the matter could order the ISO or PX to retain collateral. SCE cannot predict at this time the impact of the FERCs order or whether SCE may be
able to recover any additional refunds from governmental power sellers as a result of the pending lawsuits.

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. In October 2007, SCE received an additional distribution on its allowed bankruptcy claim of approximately $10 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.



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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.

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 for the years 1997  2003. SCE received $8 million in reliability incentive awards for the
period 1997-2000 and applied for a reward of $5 million for 2001. For 2002, SCEs data indicated that it earned no reward and incurred no penalty. For 2003, based on the application of the PBR mechanism, it would incur a penalty of $3 million
and accrued a charge for that amount in 2004. On February 28, 2005, SCE provided its final investigation report to the CPUC concluding that the reliability reporting system was 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. 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 DRA and The Utility Reform Network,
filed testimony on these matters recommending various refunds and penalties be imposed on SCE. In their testimony, the various parties made refund and penalty recommendations that range up to the following amounts: refund or forgo $48 million in
rewards for customer satisfaction, impose $70 million penalties for customer satisfaction, refund or forgo $35 million in rewards for employee safety, impose $35 million penalties for employee safety, impose $102 million in statutory penalties,
refund $84 million of results sharing, refund $4 million of miscellaneous survey expenses, and require $10 million of new employee safety programs. These recommendations total up to $388 million. On October 16, 2006, SCE filed testimony
opposing the various refund and penalty recommendations of the CPSD and other intervenors.



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On October 1, 2007, a POD was released ordering SCE to refund $136 million, plus interest, and pay a penalty of $40
million. In addition, the POD requires SCE to forgo an additional $35 million in rewards for which it would have otherwise been eligible. Included in the amount to be refunded or forgone is $48 million related to customer satisfaction rewards, $35
million related to employee safety rewards, and $77 million related to results sharing. The decision requires that the proposed results sharing refund of $77 million (based on year 2000 data) be adjusted for attrition and escalation which increases
the result sharing refund to $88 million. After the result sharing adjustment is made, the total amount SCE would be required to refund increases to $136 million, before interest. Interest to date, based on amounts collected for customer
satisfaction, safety incentives and results sharing, including escalation and attrition adjustments, would add an additional $26 million to this amount. On October 31, 2007, SCE appealed the PODs to the CPUC.

SCE cannot predict the outcome of the appeal. Based on SCEs proposed refunds, the combined recommendations of the CPSD and other intervenors, as well as the POD,
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 (approximately $15 million as of
September 30, 2007) on collected amounts that SCE has proposed to refund to customers.

The system reliability component of PBR was not addressed in
the POD. Pursuant to an earlier order in the case, system reliability incentives will be addressed in a second phase of the proceeding, which commenced with the filing of SCEs opening testimony in September 2007. In that testimony, SCE
confirmed that its PBR system reliability results, which reflected rewards of $13 million for 1997 through 2002 and a penalty of $3 million in 2003 were valid. The CPSD has requested an indefinite suspension of the schedule for the second
phase of the proceeding pending resolution of the appeals of the POD. SCE cannot predict the outcome of the second phase.

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 were 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 based on the outcome of recently completed surveys of its plant personnel and self-assessments of its programs and procedures. These corrective actions are
currently being developed in conjunction with the NRC, and are forecast to be completed by the end of 2007. These corrective actions will increase costs to both Palo Verde and its co-owners, including SCE. SCE cannot calculate the total increase in
costs until the corrective actions are finalized, but presently estimates that operation and maintenance costs at Palo Verde will increase by approximately $30 million (nominal) over the three year period 2007  2009, including overhead
costs. SCE also is unable to estimate how long SCE will continue to incur these costs.



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Market Redesign Technical Upgrade

In early 2006, the ISO began a program to redesign and upgrade the wholesale energy market across ISOs controlled grid, known as the MRTU. The programs under the MRTU initiative are designed to implement market
improvements to assure grid reliability, more efficient and cost-effective use of resources, and to create technology upgrades that would strengthen the entire ISO computer system. The redesigned California energy market under the MRTU is expected
to include the following new features, among others, which are not part of the current ISO real-time only market:



| |  | An integrated forward market for energy, ancillary services and congestion management that operates on a day-ahead basis;
|- |  | -------------------------------------------------------------------------------------------------------------------------



| |  | Congestion management that represents all network transmission constraints;
|- |  | ---------------------------------------------------------------------------



| |  | CRRs to allow market participants to manage their costs of transmission congestion (see Market Risk ExposuresCommodity Price Risk for further
discussion);
|- |  | -------------------------------------------------------------------------------------------------------------------------------------------------------------



| |  | Local energy prices by price nodes (approximately 3,000 nodes in total), also known as locational marginal pricing; and
|- |  | -----------------------------------------------------------------------------------------------------------------------



| |  | New market rules and penalties to prevent gaming and illegal manipulation of the market as well as modifications to certain existing market rules.
|- |  | --------------------------------------------------------------------------------------------------------------------------------------------------

The MRTU is scheduled for implementation on March 31, 2008. Power will be scheduled on a nodal basis, rather than the current zonal
system, which will aid in grid reliability and congestion management. Furthermore, the MRTU will incorporate the CPUCs resource adequacy requirements to ensure that there are adequate energy resources in critical areas. The MRTU will not
affect how costs are recovered through rates. SCE continues to work with the ISO to develop the MRTU.

OTHER DEVELOPMENTS

Environmental Matters

SCE is 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. SCE believes that its
operating affiliates are in substantial compliance with existing environmental regulatory requirements.

SCEs power plants, 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 SO2and NOxemissions, mercury emissions, ozone and fine particulate
matter emissions, regional haze, water quality, and climate change, may require significant capital expenditures at these facilities. These laws and regulations 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, or the impact on SCEs results of operations or financial position.

For a
discussion of SCE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 SCE since
the filing of SCEs Annual Report on Form 10-K, except as follows:

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 CARB to develop regulations and market mechanisms targeted to reduce
Californias GHG emissions to 1990 levels by 2020. CARBs mandatory program will take effect commencing in 2012 and will implement



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incremental reductions so that GHG emissions will be reduced to 1990 levels by 2020. In addition, AB 32 requires the CARB to adopt regulations to require the
reporting and verification of statewide GHG emissions. See GHG Reporting/Tracking Regulations for further discussion. 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 August 29, 2007, the CEC adopted regulations pursuant to SB 1368 establishing and implementing a GHG EPS for baseload generation of local
publicly owned electric utilities.

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 CO2and 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.

GHG Reporting/Tracking
Regulations

AB 32 requires the CARB to adopt regulations to require the reporting and verification of statewide GHG emissions on or before
January 1, 2008. In September 2007, the CPUC and the CEC approved a joint decision recommending that the CARB adopt the proposed GHG emissions reporting and verification protocol for the electricity sector that was set forth in the joint
decision. The CPUCs and CECs proposed reporting and verification protocol includes specific GHG emissions reporting requirements for retail providers and marketers in the electricity sector, and would be applicable to SCE. The CARB
issues its own proposed regulations for the reporting of GHG emissions (including the reporting of GHG emissions for the electricity sector) on October 19, 2007 for public comment. The CARB will consider the adoption of such proposed
regulations at its December 6-7, 2007 meeting. SCE cannot estimate its total cost of compliance with the CARBs reporting regulations until the final regulations are adopted.

Environmental Remediation

SCE 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.

SCE 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 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 SCEs financial position and
results of operations would not be materially affected.

SCE 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. SCE 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, SCE records the lower end of this reasonably likely range of costs (classified as other long-term liabilities) at
undiscounted amounts.



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As of September 30, 2007, SCEs recorded estimated minimum liability to remediate its 24 identified sites was
$69 million. The ultimate costs to clean up SCE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. SCE believes that, due to these uncertainties, it is reasonably possible that cleanup costs could exceed its recorded liability by up to $132 million. The upper limit of this range of costs was estimated using assumptions least favorable
to SCE 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 31 immaterial sites whose total liability ranges from
$2 million (the recorded minimum liability) to $7 million.

The CPUC allows SCE to recover environmental remediation costs at certain sites,
representing $30 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 $66 million for its estimated minimum environmental-cleanup costs expected to be recovered through customer rates.

SCE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 SCE may be held
responsible for contributing to any costs incurred for remediating these sites. Thus, no reasonable estimate of cleanup costs can be made for these sites.

SCE expects to clean up its identified sites over a period of up to 30 years. Remediation costs in each of the next several years are expected to range from $11 million to $31 million. Recorded costs for the 12 months ended
September 30, 2007 were $22 million.

Based on currently available information, SCE 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, SCE 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.

Enterprise-Wide Software System Project

Progress
continued during the first nine months of 2007 on preparation for the installation of an enterprise resources planning application from SAP. SCE is scheduled to implement financial, procurement, material management, work management and human
resources systems in mid-2008.

Federal and State Income Taxes

Edison International remains subject to examination and administrative appeals by the IRS for tax years 1994 present. Edison International is challenging certain IRS examination adjustments for tax years
1994  1999 with the Administrative Appeals branch of the IRS and Edison International is currently under IRS examination for tax years 2000  2002. In addition, the statute of limitations remains open for tax years
1986  1993 for certain affirmative claims.

The IRS has asserted deficiencies in federal corporate income taxes with respect to tax years
1994  1999. Many of the asserted tax deficiencies are timing differences and, therefore, amount ultimately paid (exclusive of



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penalties), if any, would be deductible on future tax returns of Edison International. In addition, Edison International has also submitted affirmative
claims to the IRS and state tax agencies. Any benefits associated with these affirmative claims 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.

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 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, SCE recorded a $49 million benefit related to a tax reserve adjustment as a result of this settlement. In addition to this tax reserve adjustment, SCE received a net cash refund of $52 million in April 2007 as a result of this
same settlement.

In July 2007, Edison International received a Notice of Proposed Adjustment from the IRS on an affirmative claim position involving the
taxability of balancing account over-collections. This issue is 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 $70 million to $80
million and $300 million to $325 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 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 through 2002 with the IRS and various State authorities. The
timing for resolving these open tax positions is uncertain, but it is reasonably possible that all or some portion of these open tax positions could be resolved in the next 12 months.

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.



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In April 2004, the District Court denied 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. In September 2007, the Federal Circuit reversed the lower court
decision on remand in the related lawsuit, finding that the U.S. Government had breached its trust obligation in connection with the setting of the royalty rate for the coal supplied to Mohave. The Federal Circuit decision is potentially subject to
further review but it is unknown at this time whether the U.S. Government will pursue such review.

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. Based on the information presented in the October 5, 2007 joint status report, the District Court directed the parties to file another status report by
November 9, 2007, with recommendations for further proceedings.

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.

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.

In September 2007, the ISO allocated CRRs to SCE which will entitle SCE to receive (or pay) the value of transmission congestion at specific
locations. These rights will act as an economic hedge against transmission congestion costs in the MRTU environment which is expected to be operational March 31, 2008. The CRRs meet the definition of a derivative under FAS 133. There is
insufficient evidence of a measurement date, and no quoted market prices given that MRTU is not yet implemented. As a result, as of September 30, 2007, the CRRs had no value.

SCE has not elected to use hedge accounting for the CRRs. Future fair value changes will be recorded in purchased-power expense and offset through the provision for regulatory adjustments clauses as the CPUC allows
these costs to be recovered from or refunded to customers through a regulatory balancing account mechanism. As a result, fair value changes are not expected to affect earnings.

The following table summarizes the fair values of outstanding derivative financial instruments used at SCE to mitigate its exposure to spot market prices:



|                                                   |  |                    |    |                   |   |        |  |             |   |  |   |    
|-------------------------------------------------- |  | ------------------ | -- | ----------------- | - | ------ |  | ----------- | - |  | - | ---
|                                                   |  | September 30, 2007 |    | December 31, 2006
|In millions                                        |  | Assets             |    | Liabilities       |   | Assets |  | Liabilities
|Energy options                                     |  | $                  |   |                   | $ | 46     |  | $           |  |  | $ | 10 
|FTRs                                               |  |                    | 53 |                   |   |       |  |             |  |  |   |   
|Forward physicals (power) and tolling arrangements |  |                    |   |                   |   | 8      |  |             |  |  |   | 1  
|Gas options, swaps and forward arrangements        |  |                    |   |                   |   | 44     |  |             |  |  |   | 101
|Total                                              |  | $                  | 53 |                   | $ | 98     |  | $           |  |  | $ | 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.

In July 2007, SCE entered into interest-lock derivative instruments to economically hedge the
anticipated future issuance of long-term debt. SCE expects to recover any fair value changes associated with the interest-lock derivative instruments through regulatory mechanisms and has therefore elected not to use hedge accounting. Realized and
unrealized gains and losses do not affect current earnings. Realized gains and losses are amortized to interest expense over the life of the debt. At September 30, 2007, unrealized losses were $7 million and are reflected as derivative
liabilities on the consolidated balance sheets.

The increase for the nine months ended September 30, 2007 in net unrealized gains / losses on
economic hedging activities primarily resulted from changes in SCEs gas hedge portfolio mix as well as the movements in the natural gas futures market. 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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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

Net Income Available for Common Stock

SCEs net income available for common stock was $262 million and $587 million for the three- and nine-month periods ended September 30, 2007, respectively, compared to $263 million and $618 million for the respective periods in
2006. The quarter earnings reflect an increase primarily related to higher net revenue associated with the 2006 GRC, partially offset by a benefit from a generator settlement recorded in the third quarter of 2006. SCEs year-to-date variance
also reflects a benefit recorded in 2006 related to the resolution of an issue related to state income taxes and the generator settlement, partially offset by a benefit recorded in 2007 primarily reflecting progress on an appeal with the IRS related
to the income tax treatment of certain costs associated with environmental remediation and higher net revenue associated with the 2006 GRC and lower income taxes.

Operating Revenue

The following table sets forth the major changes in operating revenue:



|                                                                      |  |                                              |      |   |                                              |   |      |  
|--------------------------------------------------------------------- |  | -------------------------------------------- | ---- | - | -------------------------------------------- | - | ---- | -
|In millions                                                           |  | Three MonthsEnded September 30,2007 vs. 2006 |      |   | Nine Months Ended September 30,2007 vs. 2006 |  
|Operating revenue                                                     |  |                                              |      |   |                                              |   |      |  
|Rate changes and impact of tiered rate structure (including unbilled) |  | $                                            | (434 | ) |                                              | $ | (468 | )
|Sales volume changes (including unbilled)                             |  |                                              | 26   |   |                                              |   | 103  |  
|Balancing account over/under collections                              |  |                                              | 468  |   |                                              |   | 369  |  
|Sales for resale                                                      |  |                                              | 63   |   |                                              |   | 74   |  
|SCEs VIEs                                                            |  |                                              | (9   | ) |                                              |   | (7   | )
|Other (including inter company transactions)                          |  |                                              | 21   |   |                                              |   | 8    |  
|Total                                                                 |  | $                                            | 135  |   |                                              | $ | 79   |  

SCEs retail sales represented approximately 87% of operating revenue for both the three- and nine-month
periods ended September 30, 2007, respectively, compared to approximately 90% for both comparable periods in 2006. Due to warmer weather during the summer months and SCEs rate design, operating revenue during the third quarter of each
year is generally higher than other quarters.

Total operating revenue increased by $135 million and $79 million for the three- and nine-month periods
ended 2007, respectively (as shown in the table above). The variances for the revenue components are as follows:



| |  | Operating revenue from rate changes decreased for the three- and nine-month periods ended September 30, 2007, mainly due to the redesign of SCEs tiered
rate structure which resulted in a decrease of residential rates in the higher tiers. In addition, 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 projected 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 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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| |  | Operating revenue resulting from sales volume changes for the three- and nine-month periods ended September 30, 2007 was mainly due to an increase in customer
growth;
|- |  | ----------------------------------------------------------------------------------------------------------------------------------------------------------------------



| |  | 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 the difference for revenue collected in excess of actual costs. For the
three- and nine-month periods ended September 30, 2007, SCE collected revenue in excess of actual costs incurred and as a result deferred approximately $299 million and $364 million, respectively, compared to a deferral of
approximately $767 million and $733 million, for the same period in 2006, respectively, due to the impact of lower gas prices as compared to forecast and higher revenue resulting from warmer weather;
|- |  | -------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------



| |  | Operating 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.
|- |  | --------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------

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
$671 million and $1.8 billion for the three- and nine-month periods ended September 30, 2007, respectively, compared to $686 million and $1.8 billion for the same respective periods in 2006.

Operating Expenses

Fuel Expense

SCEs fuel expense increased $24 million and $68 million for the three- and nine-month periods ended September 30, 2007, respectively, as compared to the same
periods in 2006. The quarter and year-to-date increases were mainly due to an increase at Mountainview of $30 million and $65 million for the three- and nine-month periods ended September 30, 2007, respectively, due to higher generation in 2007
compared to 2006. Also contributing to the increase was higher nuclear fuel expense of $25 million for the nine-month period ended September 30, 2007 resulting primarily from a planned refueling and maintenance outage at SCEs San
Onofre Unit 2 and 3 in 2006. The quarter and year-to-date increases were partially offset by lower fuel expense of approximately $10 million and $25 million, respectively, related to the SCE VIE projects.

Purchased-Power Expense

The following is a summary of
purchased-power expense:



|                                                                             |  |                                 |       |      |                                |       |      |  |   |       |   |  |   |       |  
|---------------------------------------------------------------------------- |  | ------------------------------- | ----- | ---- | ------------------------------ | ----- | ---- |  | - | ----- | - |  | - | ----- | -
|                                                                             |  | Three MonthsEnded September 30, |       |      | Nine MonthsEnded September 30, |      
|In millions                                                                  |  | 2007                            |       | 2006 |                                |       | 2007 |  |   | 2006  |  
|Purchased-power from bilateral contracts, QFs, ISO, FTRs and exchange energy |  | $                               | 1,153 |      | $                              | 1,028 |      |  | $ | 2,356 |   |  | $ | 2,351 |  
|Unrealized (gains) losses on economic hedging activities  net               |  |                                 | 67    |      |                                | 9     |      |  |   | (23   | ) |  |   | 351   |  
|Realized losses on economic hedging activities  net                         |  |                                 | 58    |      |                                | 114   |      |  |   | 111   |   |  |   | 279   |  
|Energy settlements and refunds                                               |  |                                 | 6     |      |                                | (115  | )    |  |   | (13   | ) |  |   | (162  | )
|Total purchased-power expense                                                |  | $                               | 1,284 |      | $                              | 1,036 |      |  | $ | 2,431 |   |  | $ | 2,819 |  



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Purchased-power expense increased $248 million and decreased $388 million for the three and nine months ended
September 30, 2007, as compared to the same periods in 2006. The quarter and year-to-date variances reflect an increase in bilateral energy purchases of $110 million and $95 million for the three- and nine-month periods ended
September 30, 2007, respectively, resulting from greater power demand; lower energy settlement refunds of approximately $120 million and $150 million for the three-and nine month periods ended September 2007, respectively; higher QF purchased
power expense of $25 million and $15 million for the three- and nine-months ended September 30, 2007, respectively, resulting from an increase in the average spot natural gas prices (as discussed further below). The quarter and year-to-date
increases were partially offset by a decrease in ISO-related energy costs of $35 million and $110 million, for the three- and nine-month periods ended September 30, 2007, respectively. The year-to-date variance also reflects net
realized and unrealized losses on economic hedging activities of $88 million compared to $630 million for the nine-month periods ended September 30, 2007 and 2006, respectively (see Market Risk ExposuresCommodity Price Risk
for further discussion). The changes in net unrealized (gains) losses on economic hedging activities primarily resulted from changes in SCEs gas hedge portfolio mix as well as the movements in the natural gas futures market. The changes in net
realized losses on economic hedging activities primarily resulted from a more stable natural gas market in 2007. Due to expected recovery through regulatory mechanisms unrealized gains and losses may temporarily affect cash flows, but are not
expected to affect earnings.

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 $181 million and increased $445 million for the three- and nine-month periods ended
September 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 $67 million and $9 million for three-month periods ended
September 30, 2007 and 2006, respectively, and net unrealized gains on economic hedging activities of approximately $23 million for the nine-month period ended September 30, 2007, compared to $351 million of net unrealized
losses for the same period last year (mentioned above in purchased-power expense). The quarter and year-to-date variance also reflects a $60 million FERC refund settlement recorded in 2006. The year-to-date increase also reflects 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 and year-to-date variances also reflect timing differences for
operation and maintenance-related expenses that are recovered through regulatory mechanisms.

Other Operation and Maintenance Expense

SCEs other operation and maintenance expense increased $64 million and $72 million for the three- and nine-month periods ended September 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 $40 million and $95 million for the three- and
nine-month periods ended September 30, 2007, respectively, (which are recovered through regulatory mechanisms approved by the CPUC) and higher transmission and distribution maintenance cost of approximately $5 million and $25 million for
the three- and nine-month period ended September 30, 2007, respectively. This year-to-date increase was partially offset by lower must-run and must-offer obligation costs of $40 million related to the reliability of the ISO systems and lower
generation-related costs of approximately $35 million for the nine months ended September 30, 2007 resulting from the planned refueling and maintenance outages at SCEs San Onofre Units 2 and 3 in the first quarter 2006.



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Depreciation, Decommissioning and Amortization Expense

SCEs depreciation, decommissioning and amortization expense increased $13 million and $7 million for the three- and nine-month periods ended September 30,
2007, respectively, compared to the same periods in 2006 primarily due to transmission and distribution asset additions resulting in increased depreciation expense of $15 million and $30 million for the three- and nine-month periods ended
September 30, 2007, respectively (see LiquidityCapital Expenditures for a further discussion). In addition, the variance reflects a decrease in decommissioning expense of $1 million and $20 million for the three- and
nine-month periods ended September 30, 2007, respectively, compared to the same periods in 2006 primarily resulting from other-than-temporary impairment losses associated with the nuclear decommissioning trust funds, partially offset by an
increase in trust earnings. Due to its regulatory treatment, investment impairment losses and trust earnings are recorded in revenue and are offset in decommissioning expense and have no impact on net income.

Other Income and Deductions

Interest income

SCEs interest income decreased $1 million and $10 million for the three- and nine-month periods ended September 30, 2007, respectively,
compared to the same periods in 2006, mainly due to lower interest income resulting from lower undercollections on certain balancing accounts in 2007, as compared to 2006.

Other Nonoperating Income

SCEs other nonoperating income increased $16 million and $7 million for the
three- and nine-month periods ended September 30, 2007, compared to the same periods in 2006. The increase was primarily due to payments received in settlement of claims related to the natural gas purchased contracts for one of SCEs VIE
projects.

Interest Expense  Net of Amounts Capitalized

SCEs interest expense  net of amounts capitalized increased $19 million and $33 million for the three- and nine-month periods ended September 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 September 30, 2007, compared to the same period
in 2006.

Income Tax Expense

SCE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. SCEs effective tax rate from operations was 35% and 30% for the three- and nine-month periods
ended September 30, 2007, respectively, as compared to 40% and 39% for the respective periods in 2006. The decreased effective tax rate realized for the three-months ended was caused primarily by year over year changes in property related
flow-through items as well as lower interest expense related to lower tax reserve in 2007 as compared to 2006 as a result of implementing FIN 48. In addition, the nine-month variance included reductions made to the income tax reserve 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 due to reductions 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 under the heading Other DevelopmentFederal and State Income Taxes.

Historical Cash Flow Analysis

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



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Cash Flows from Operating Activities

Cash provided by operating activities was $2.4 billion for the nine-month period ended September 30, 2007, compared to $2.1 billion for the comparable period in 2006. The 2007 change reflects a decrease in
revenue collected from SCEs customers primarily due to lower rates in 2007, compared to 2006. On February 14, 2007, SCE reduced its system average rate mainly as the result of estimated lower natural gas prices in 2007, the refund of
overcollections in the ERRA balancing account that occurred in 2006 and the impact of the redesign of SCEs tiered rate structure in 2007 (see Regulatory MattersCurrent Regulatory DevelopmentsImpact of Regulatory Matters on
Customer Rates for further discussion). The 2007 change was also due to the timing of cash receipts and disbursements related to working capital items.

Cash Flows from Financing Activities

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

Financing activities in 2007 were as follows:



| |  | Dividend payments of $110 million paid to Edison International.
|- |  | ---------------------------------------------------------------

Financing activities in 2006 included activities related to the rebalancing of SCEs capital structure 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; and
|- |  | ----------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------



| |  | Financing activities in 2006 also included dividend payments of $191 million paid to Edison International.
|- |  | ----------------------------------------------------------------------------------------------------------

Cash Flows from Investing Activities

Cash flows from
investing activities are affected by capital expenditures and SCEs funding of nuclear decommissioning trusts.

Net cash used by investing activities
for the first nine months of the year was $1.9 billion in 2007 and $1.7 billion in 2006.

Investing activities in 2007 reflect $1.65 billion
in capital expenditures, primarily for transmission and distribution assets, including approximately $104 million for nuclear fuel acquisitions.

Investing activities in 2006 reflect $1.6 billion in capital expenditures, primarily for transmission and distribution assets, including approximately $63 million for nuclear fuel acquisitions.



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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. SCE adopted FIN 48 effective January 1, 2007. Implementation of FIN 48 resulted in a cumulative-effect adjustment that increased retained earnings by $213 million upon adoption. SCE
will continue to monitor and assess new income tax developments.

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. SCE will adopt FIN 39-1 on January 1, 2008. Adoption of this position may result in netting a portion of margin and cash collateral deposits with derivative liabilities on
SCEs consolidated balance sheets, but will have no impact on SCE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. SCE is currently evaluating whether it will opt to report any current or future financial assets and liabilities at fair value and the impact, if adopted, on its consolidated
financial statements, beginning January 1, 2008.

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. SCE will adopt SFAS No. 157 on January 1, 2008. SCE is currently evaluating the impact of adopting SFAS No. 157 on its financial
statements.

COMMITMENTS AND INDEMNITIES

The following
is an update to SCEs commitments and indemnities. See the section, Commitments and Indemnities, in the year-ended 2006 MD&A for a detailed discussion.

Fuel Supply Contracts

SCE entered into service contracts associated with uranium enrichment and fuel fabrication
during the first nine months of 2007. As a result, SCEs additional fuel supply commitments are estimated to be $82 million for the remainder of 2007, zero for 2008, $14 million for 2009, $8 million for 2010, $7 million for 2011 and
$40 million thereafter.

Operating and Capital Leases

SCE entered into new power-purchase contracts during the first nine months of 2007. These additional commitments are currently estimated to be $13 million for the remainder of 2007, $186 million for 2008, $114 million for 2009, $73
million for 2010, $41 million for 2011 and $198 million thereafter.

SCE entered into a new power-purchase contract, classified as an operating lease,
during the first nine months of 2007. SCEs additional operating lease commitments for this new power contract are currently estimated to be $68 million for 2008 and $114 million for each of the years 2009, 2010 and 2011.



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

Uncertain Tax Position Net Liability

At September 30, 2007, SCE had a total net liability recorded for uncertain tax positions of $199 million. SCE cannot make reliable estimates of the cash flows by period due to uncertainty surrounding the timing
of resolving these open tax issues with the IRS.

Indemnities

Mountainview Filter Cake Indemnity

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



|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 heading Market Risk Exposures is incorporated herein by this reference.



|Item 4. | Controls and Procedures
|------- | -----------------------

Disclosure Controls and Procedures

SCE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 SCE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, SCEs disclosure controls and procedures are effective.

Internal Control Over Financial Reporting

There were no changes in
SCE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, SCEs internal control over financial reporting.



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##### Table of Contents

PART II. OTHER INFORMATION



|Item 1. | Legal Proceedings
|------- | -----------------

Navajo Nation Litigation

Information about the Navajo Nation litigation appears in the MD&A under the heading Regulatory Matters  Navajo Nation Litigation.

Catalina South Coast Air Quality Management District Potential Environmental Proceeding

During the first half of 2006, the SCAQMD issued three NOVs alleging that Unit 15, SCEs primary diesel generation unit on Catalina Island, had exceeded the NOxemission limit dictated by its air permit. Prior to the NOVs, SCE had filed an application with the SCAQMD seeking a permit revision that would allow a three-hour averaging of the NOxlimit during normal (non-startup) operations and clarification regarding a startup exemption. In July 2006, the SCAQMD denied SCEs application to revise
the Unit 15 air permit, and informed SCE that several conditions would have to be satisfied prior to re-application. SCE is currently in the process of developing and supplying the information and analyses required by those conditions.

On October 2, 2006 and July 19, 2007, SCE received two additional NOVs
pertaining to two other Catalina Island diesel generation units, Unit 7 and Unit 10, alleging that these units have exceeded their annual NOxlimit in 2004
(Unit 10), 2005 (Unit 7), and 2006 (Unit 10). Going forward, SCE expects that the new Continuous Emissions Monitoring System, installed in late 2006, which monitors the emissions from these units, along with the employment of best practices, will
enable these units to meet their annual NOxlimits in 2007.

Settlement negotiations with the SCAQMD regarding the penalties are ongoing and the SCAQMD has not yet proposed any specific fines to be imposed on SCE.



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##### Table of Contents

|Item 6. | Exhibits
|------- | --------

Southern California Edison Company



|     |  |                                                                                                                                                                                                        
|---- |  | -------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
|     | 
|10.1 |  | 2008 Director Deferred Compensation Plan, effective January 1, 2008 (File No. 1-9936, filed as Exhibit 10.1 to Edison Internationals Form 10-Q for the quarter ended September 30,
2007)*             
|     | 
|10.2 |  | 2008 Executive Deferred Compensation Plan, effective January 1, 2008 (File No. 1-9936, filed as Exhibit 10.2 to Edison Internationals Form 10-Q for the quarter ended September 30, 2007)*            
|     | 
|10.3 |  | 2008 Executive Disability Plan, effective January 1, 2008 (File No. 1-9936, filed as Exhibit 10.3 to Edison Internationals Form 10-Q for the quarter ended September 30,
2007)*                       
|     | 
|10.4 |  | 2008 Executive Retirement Plan, effective January 1, 2008 (File No. 1-9936, filed as Exhibit 10.4 to Edison Internationals Form 10-Q for the quarter ended September 30,
2007)*                       
|     | 
|10.5 |  | Retirement Plan for Directors, as amended and restated effective January 1, 2008 (File No. 1-9936, filed as Exhibit 10.5 to Edison Internationals Form 10-Q for the quarter ended September
30, 2007)*
|     | 
|10.6 |  | 2008 Executive Severance Plan, as adopted effective January 1, 2008 (File No. 1-9936, filed as Exhibit 10.6 to Edison Internationals Form 10-Q for the quarter ended September 30, 2007)*             
|     | 
|10.7 |  | Executive Supplemental Benefit Program, as amended January 1, 2008 (File No. 1-9936, filed as Exhibit 10.7 to Edison Internationals Form 10-Q for the quarter ended September 30, 2007)*              
|     | 
|10.8 |  | 2008 Executive Survivor Benefit Plan, effective January 1, 2008 (File No. 1-9936, filed as Exhibit 10.8 to Edison Internationals Form 10-Q for the quarter ended September 30,
2007)*                 
|     | 
|10.9 |  | Executive Incentive Compensation Plan, as amended October 24, 2007 (File No. 1-9936, filed as Exhibit 10.9 to Edison Internationals Form 10-Q for the quarter ended September 30, 2007)*              
|     | 
|31.1 |  | Certification of the Chief Executive Officer pursuant to Section 302 of the Sarbanes-Oxley Act                                                                                                         
|     | 
|31.2 |  | Certification of the Chief Financial Officer pursuant to Section 302 of the Sarbanes-Oxley Act                                                                                                         
|     | 
|32   |  | Statement Pursuant to 18 U.S.C. Section 1350                                                                                                                                                           

---

|* | Incorporated by reference pursuant to Rule 12b-32.
|- | --------------------------------------------------



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SIGNATURE

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



SOUTHERN CALIFORNIA EDISON COMPANY(Registrant)By

/s/    LINDA G. SULLIVANLinda G. SullivanVice President and Controller(Duly Authorized Officer andPrincipal Accounting Officer)


Dated: November 2, 2007



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