##### Table of Contents





UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549





FORM 10-Q





(Mark One)

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

For the quarterly period ended September 30, 2008



| ̈ | 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





SOUTHERN CALIFORNIA EDISON COMPANY

(Exact name of registrant as specified in its charter)







|                                                              |  |                                    
|------------------------------------------------------------- |  | -----------------------------------
|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                      |  | Smaller reporting company   ̈
|                           |  |                      |  | (Do not check if a smaller reporting company) |  |                             

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange
Act).  Yes     ̈    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 November 5, 2008
|Common Stock, no par value |  | 434,888,104                    









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##### Table of Contents

SOUTHERN CALIFORNIA EDISON COMPANY

INDEX



|                              |  |         |  |                                                                                                 |  |        
|----------------------------- |  | ------- |  | ----------------------------------------------------------------------------------------------- |  | -------
|                              |  |         |  |                                                                                                 |  | PageNo.
|Part I. Financial Information |  |        
|                              |  |         | 
|                              |  | Item 1. |  | Financial Statements                                                                            |  | 1      
|                              |  |         | 
|                              |  |         |  | Consolidated Statements of Income  Nine Months Ended September 30, 2008 and 2007               |  | 1      
|                              |  |         | 
|                              |  |         |  | Consolidated Statements of Comprehensive Income  Nine Months Ended September 30, 2008 and
2007 |  | 1      
|                              |  |         | 
|                              |  |         |  | Consolidated Balance Sheets  September 30, 2008 and December 31, 2007                          |  | 2      
|                              |  |         | 
|                              |  |         |  | Consolidated Statements of Cash Flows  Nine Months Ended September 30, 2008 and 2007           |  | 4      
|                              |  |         | 
|                              |  |         |  | Notes to Consolidated Financial Statements                                                      |  | 5      
|                              |  |         | 
|                              |  | Item 2. |  | Managements Discussion and Analysis of Financial Condition and Results of Operations           |  | 30     
|                              |  |         | 
|                              |  | Item 3. |  | Quantitative and Qualitative Disclosures About Market Risk                                      |  | 63     
|                              |  |         | 
|                              |  | Item 4. |  | Controls and Procedures                                                                         |  | 63     
|                              | 
|Part II. Other Information    |  |        
|                              |  |         | 
|                              |  | Item 1. |  | Legal Proceedings                                                                               |  | 64     
|                              |  |         | 
|                              |  | Item 6. |  | Exhibits                                                                                        |  | 65     
|                              | 
|Signature                     |  | 66     



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##### Table of Contents

GLOSSARY

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



|                                    |  |                                                                                                                                                                                                                                                                                                                                                                                                                                     
|----------------------------------- |  | ------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
|                                    | 
|AB                                  |  | Assembly Bill                                                                                                                                                                                                                                                                                                                                                                                                                       
|                                    | 
|AFUDC                               |  | allowance for funds used during construction                                                                                                                                                                                                                                                                                                                                                                                        
|                                    | 
|APS                                 |  | Arizona Public Service Company                                                                                                                                                                                                                                                                                                                                                                                                      
|                                    | 
|ARO(s)                              |  | asset retirement obligation(s)                                                                                                                                                                                                                                                                                                                                                                                                      
|                                    | 
|CAA                                 |  | Clean Air Act                                                                                                                                                                                                                                                                                                                                                                                                                       
|                                    | 
|CARB                                |  | Clean Air Resources Board                                                                                                                                                                                                                                                                                                                                                                                                           
|                                    | 
|CDWR                                |  | California Department of Water Resources                                                                                                                                                                                                                                                                                                                                                                                            
|                                    | 
|CEC                                 |  | California Energy Commission                                                                                                                                                                                                                                                                                                                                                                                                        
|                                    | 
|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                                                                                                                                                                                                                                                                                                                                                                                    
|                                    | 
|DOE                                 |  | United States Department of Energy                                                                                                                                                                                                                                                                                                                                                                                                  
|                                    | 
|DPV2                                |  | Devers-Palo Verde II                                                                                                                                                                                                                                                                                                                                                                                                                
|                                    | 
|DRA                                 |  | Division of Ratepayer Advocates                                                                                                                                                                                                                                                                                                                                                                                                     
|                                    | 
|DWP                                 |  | Los Angeles Department of Water & Power                                                                                                                                                                                                                                                                                                                                                                                             
|                                    | 
|EME                                 |  | Edison Mission Energy                                                                                                                                                                                                                                                                                                                                                                                                               
|                                    | 
|ERRA                                |  | energy resource recovery account                                                                                                                                                                                                                                                                                                                                                                                                    
|                                    | 
|FASB                                |  | Financial Accounting Standards Board                                                                                                                                                                                                                                                                                                                                                                                                
|                                    | 
|FERC                                |  | Federal Energy Regulatory Commission                                                                                                                                                                                                                                                                                                                                                                                                
|                                    | 
|FGIC                                |  | Financial Guarantee Insurance Company                                                                                                                                                                                                                                                                                                                                                                                               
|                                    | 
|FIN 39-1                            |  | Financial Accounting Standards Interpretation No. 39-1, Amendment of FASB Interpretation No. 39                                                                                                                                                                                                                                                                                                                                     
|                                    | 
|FIN 48                              |  | Financial Accounting Standards Interpretation No. 48, Accounting for Uncertainty in Income Taxes  an interpretation of FAS 109                                                                                                                                                                                                                                                                                                     
|                                    | 
|FSP SFAS No. 133-1 and FIN No. 45-4 |  | Financial Accounting Standards Board Staff Position No. 133-1 and FIN No. 45-4, Disclosures about Credit Derivatives and Certain Guarantees: An Amendment of FASB Statement
No. 133 and FASB Interpretation No. 45; and Clarification of the Effective Date of FASB Statement No. 161.                                                                                                                                            
|                                    | 
|GAAP                                |  | generally accepted accounting principles                                                                                                                                                                                                                                                                                                                                                                                            
|                                    | 
|Global Settlement                   |  | A settlement currently being negotiated between Edison International and the IRS, which, if consummated, would resolve outstanding tax disputes for all Edison International subsidiaries,
including SCE, for open tax years 1986 through 2002, including affirmative claims for unrecognized tax benefits. There can be no assurance about the timing of such settlement or that a final settlement will be ultimately
consummated.
|                                    | 
|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                                                                                                                                                                                                                                                                                                                                                                                                  



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##### Table of Contents

GLOSSARY (Continued)



|             |  |                                                                                                                                                             
|------------ |  | ------------------------------------------------------------------------------------------------------------------------------------------------------------
|             | 
|Mohave       |  | Mohave Generating Station                                                                                                                                   
|             | 
|MRTU         |  | Market Redesign and Technology Upgrade                                                                                                                      
|             | 
|MW           |  | megawatts                                                                                                                                                   
|             | 
|MWh          |  | megawatt-hours                                                                                                                                              
|             | 
|NOx          |  | nitrogen oxide                                                                                                                                              
|             | 
|NRC          |  | Nuclear Regulatory Commission                                                                                                                               
|             | 
|Palo Verde   |  | Palo Verde Nuclear Generating Station                                                                                                                       
|             | 
|PBOP(s)      |  | postretirement benefits other than pension(s)                                                                                                               
|             | 
|PBR          |  | performance-based ratemaking                                                                                                                                
|             | 
|PG&E         |  | Pacific Gas & Electric Company                                                                                                                              
|             | 
|POD          |  | Presiding Officers Decision                                                                                                                                
|             | 
|PX           |  | California Power Exchange                                                                                                                                   
|             | 
|QF(s)        |  | qualifying facility(ies)                                                                                                                                    
|             | 
|RICO         |  | Racketeer Influenced and Corrupt Organization                                                                                                               
|             | 
|ROE          |  | return on equity                                                                                                                                            
|             | 
|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. 133 |  | Statement of Financial Accounting Standards No. 133, Accounting for Derivative Instruments and Hedging Activities                                           
|             | 
|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 Post-Retirement Plans                      
|             | 
|SFAS No. 159 |  | Statement of Financial Accounting Standards No. 159, The Fair Value Option for Financial Assets and Financial Liabilities                                   
|             | 
|SFAS No. 160 |  | Statement of Financial Accounting Standards No. 160, Noncontrolling Interests in Consolidated Financial Statements                                          
|             | 
|SFAS No. 161 |  | Statement of Financial Accounting Standards No. 161, Disclosures about Derivative Instruments and Hedging Activities, an amendment of FASB Statement No. 133
|             | 
|SO2          |  | sulfur dioxide                                                                                                                                              
|             | 
|TURN         |  | The Utility Reform Network                                                                                                                                  
|             | 
|US EPA       |  | United States Environmental Protection Agency                                                                                                               
|             | 
|VIE(s)       |  | variable interest entity(ies)                                                                                                                               



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##### Table of Contents

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                                                                     |  | 2008                            |       |   | 2007                           |   |       | 2008 |  |   | 2007  |  
|                                                                                |  | (Unaudited)                     |      
|Operating revenue                                                               |  | $                               | 3,285 |   |                                | $ | 3,214 |      |  | $ | 8,390 |   |  | $ | 7,897 |  
|Fuel                                                                            |  |                                 | 415   |   |                                |   | 310   |      |  |   | 1,161 |   |  |   | 904   |  
|Purchased power                                                                 |  |                                 | 1,962 |   |                                |   | 1,284 |      |  |   | 3,111 |   |  |   | 2,431 |  
|Provisions for regulatory adjustment clauses  net                              |  |                                 | (737  | ) |                                |   | (66   | )    |  |   | (286  | ) |  |   | 189   |  
|Other operation and maintenance                                                 |  |                                 | 711   |   |                                |   | 726   |      |  |   | 2,145 |   |  |   | 1,988 |  
|Depreciation, decommissioning and amortization                                  |  |                                 | 211   |   |                                |   | 267   |      |  |   | 750   |   |  |   | 813   |  
|Property and other taxes                                                        |  |                                 | 61    |   |                                |   | 54    |      |  |   | 179   |   |  |   | 164   |  
|Gain on sale of assets                                                          |  |                                 | (1    | ) |                                |   |      |      |  |   | (9    | ) |  |   |      |  
|Total operating expenses                                                        |  |                                 | 2,622 |   |                                |   | 2,575 |      |  |   | 7,051 |   |  |   | 6,489 |  
|Operating income                                                                |  |                                 | 663   |   |                                |   | 639   |      |  |   | 1,339 |   |  |   | 1,408 |  
|Interest income                                                                 |  |                                 | 2     |   |                                |   | 13    |      |  |   | 12    |   |  |   | 34    |  
|Other nonoperating income                                                       |  |                                 | 20    |   |                                |   | 29    |      |  |   | 69    |   |  |   | 68    |  
|Interest expense  net of amounts capitalized                                   |  |                                 | (104  | ) |                                |   | (117  | )    |  |   | (297  | ) |  |   | (330  | )
|Other nonoperating deductions                                                   |  |                                 | (81   | ) |                                |   | (7    | )    |  |   | (114  | ) |  |   | (31   | )
|Income before tax and minority interest                                         |  |                                 | 500   |   |                                |   | 557   |      |  |   | 1,009 |   |  |   | 1,149 |  
|Income tax expense                                                              |  |                                 | 158   |   |                                |   | 150   |      |  |   | 268   |   |  |   | 263   |  
|Minority interest                                                               |  |                                 | 94    |   |                                |   | 132   |      |  |   | 161   |   |  |   | 261   |  
|Net income                                                                      |  |                                 | 248   |   |                                |   | 275   |      |  |   | 580   |   |  |   | 625   |  
|Dividends on preferred and preference stock not subject to mandatory redemption |  |                                 | 13    |   |                                |   | 13    |      |  |   | 38    |   |  |   | 38    |  
|Net income available for common stock                                           |  | $                               | 235   |   |                                | $ | 262   |      |  | $ | 542   |   |  | $ | 587   |  
|                                                                                |  |                                
|CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME                                 |  |                                 |       |   |                                |   |       |      | 
|                                                                                |  | Three Months EndedSeptember 30, |       |   | Nine Months EndedSeptember 30, |  
|In millions                                                                     |  | 2008                            |       |   | 2007                           |   |       | 2008 |  |   | 2007  |  
|                                                                                |  | (Unaudited)                     |      
|Net income                                                                      |  | $                               | 248   |   |                                | $ | 275   |      |  | $ | 580   |   |  | $ | 625   |  
|Other comprehensive income, net of tax:                                         |  |                                 |       |   |                                |   |       |      |  |   |       |   |  |   |       |  
|Pension and postretirement benefits other than pensions:                        |  |                                 |       |   |                                |   |       |      |  |   |       |   |  |   |       |  
|Amortization of net gain (loss) included in expense  net of tax                |  |                                 | (1    | ) |                                |   |      |      |  |   | (2    | ) |  |   | 1     |  
|Comprehensive income                                                            |  | $                               | 247   |   |                                | $ | 275   |      |  | $ | 578   |   |  | $ | 626   |  



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



1



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SOUTHERN CALIFORNIA EDISON COMPANY

CONSOLIDATED BALANCE SHEETS



|                                                                                                       |  |                    |        |   |                   |   |        |  
|------------------------------------------------------------------------------------------------------ |  | ------------------ | ------ | - | ----------------- | - | ------ | -
|In millions                                                                                            |  | September 30, 2008 |        |   | December 31, 2007 |  
|                                                                                                       |  | (Unaudited)        |        |   |                   |  
|ASSETS                                                                                                 |  |                    |        |   |                   |   |        |  
|Cash and equivalents                                                                                   |  | $                  | 1,256  |   |                   | $ | 252    |  
|Short-term investments                                                                                 |  |                    | 3      |   |                   |   |       |  
|Receivables, less allowance of $33 and $34 for uncollectible accounts at respective dates              |  |                    | 1,030  |   |                   |   | 725    |  
|Accrued unbilled revenue                                                                               |  |                    | 518    |   |                   |   | 370    |  
|Inventory                                                                                              |  |                    | 352    |   |                   |   | 283    |  
|Derivative assets                                                                                      |  |                    | 125    |   |                   |   | 53     |  
|Margin and collateral deposits                                                                         |  |                    | 10     |   |                   |   | 35     |  
|Regulatory assets                                                                                      |  |                    | 454    |   |                   |   | 197    |  
|Accumulated deferred income taxes  net                                                                |  |                    | 215    |   |                   |   | 146    |  
|Other current assets                                                                                   |  |                    | 84     |   |                   |   | 188    |  
|Total current assets                                                                                   |  |                    | 4,047  |   |                   |   | 2,249  |  
|Nonutility property  less accumulated provision for depreciation of $748 and $701 at respective dates |  |                    | 967    |   |                   |   | 1,000  |  
|Nuclear decommissioning trusts                                                                         |  |                    | 2,855  |   |                   |   | 3,378  |  
|Other investments                                                                                      |  |                    | 86     |   |                   |   | 69     |  
|Total investments and other assets                                                                     |  |                    | 3,908  |   |                   |   | 4,447  |  
|Utility plant, at original cost:                                                                       |  |                    |        |   |                   |   |        |  
|Transmission and distribution                                                                          |  |                    | 19,776 |   |                   |   | 18,940 |  
|Generation                                                                                             |  |                    | 1,820  |   |                   |   | 1,767  |  
|Accumulated provision for depreciation                                                                 |  |                    | (5,526 | ) |                   |   | (5,174 | )
|Construction work in progress                                                                          |  |                    | 1,970  |   |                   |   | 1,693  |  
|Nuclear fuel, at amortized cost                                                                        |  |                    | 246    |   |                   |   | 177    |  
|Total utility plant                                                                                    |  |                    | 18,286 |   |                   |   | 17,403 |  
|Derivative assets                                                                                      |  |                    | 13     |   |                   |   | 28     |  
|Regulatory assets                                                                                      |  |                    | 2,880  |   |                   |   | 2,721  |  
|Other long-term assets                                                                                 |  |                    | 658    |   |                   |   | 629    |  
|Total long-term assets                                                                                 |  |                    | 3,551  |   |                   |   | 3,378  |  
|                                                                                                       |  |                   
|Total assets                                                                                           |  | $                  | 29,792 |   |                   | $ | 27,477 |  



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, 2008 |        |   | December 31, 2007 |  
|                                                                         |  | (Unaudited)        |        |   |                   |  
|LIABILITIES AND SHAREHOLDERS EQUITY                                     |  |                    |        |   |                   |   |        |  
|Short-term debt                                                          |  | $                  | 1,558  |   |                   | $ | 500    |  
|Long-term debt due within one year                                       |  |                    | 150    |   |                   |   |       |  
|Accounts payable                                                         |  |                    | 838    |   |                   |   | 914    |  
|Accrued taxes                                                            |  |                    | 128    |   |                   |   | 42     |  
|Accrued interest                                                         |  |                    | 105    |   |                   |   | 126    |  
|Counterparty collateral                                                  |  |                    | 9      |   |                   |   | 42     |  
|Customer deposits                                                        |  |                    | 226    |   |                   |   | 218    |  
|Book overdrafts                                                          |  |                    | 298    |   |                   |   | 204    |  
|Derivative liabilities                                                   |  |                    | 132    |   |                   |   | 97     |  
|Regulatory liabilities                                                   |  |                    | 1,179  |   |                   |   | 1,019  |  
|Other current liabilities                                                |  |                    | 682    |   |                   |   | 548    |  
|Total current liabilities                                                |  |                    | 5,305  |   |                   |   | 3,710  |  
|Long-term debt                                                           |  |                    | 5,714  |   |                   |   | 5,081  |  
|Accumulated deferred income taxes  net                                  |  |                    | 2,816  |   |                   |   | 2,556  |  
|Accumulated deferred investment tax credits                              |  |                    | 100    |   |                   |   | 105    |  
|Customer advances                                                        |  |                    | 134    |   |                   |   | 155    |  
|Derivative liabilities                                                   |  |                    | 30     |   |                   |   | 13     |  
|Power-purchase contracts                                                 |  |                    | 21     |   |                   |   | 22     |  
|Accumulated provision for pensions and benefits                          |  |                    | 857    |   |                   |   | 786    |  
|Asset retirement obligations                                             |  |                    | 2,966  |   |                   |   | 2,877  |  
|Regulatory liabilities                                                   |  |                    | 2,889  |   |                   |   | 3,433  |  
|Other deferred credits and other long-term liabilities                   |  |                    | 1,121  |   |                   |   | 1,136  |  
|Total deferred credits and other liabilities                             |  |                    | 10,934 |   |                   |   | 11,083 |  
|Total liabilities                                                        |  |                    | 21,953 |   |                   |   | 19,874 |  
|Commitments and contingencies (Note 5)                                   |  |                    |        |   |                   |   |        |  
|Minority interest                                                        |  |                    | 451    |   |                   |   | 446    |  
|Common stock, no par value (434,888,104 shares outstanding at each date) |  |                    | 2,168  |   |                   |   | 2,168  |  
|Additional paid-in capital                                               |  |                    | 529    |   |                   |   | 507    |  
|Accumulated other comprehensive loss                                     |  |                    | (17    | ) |                   |   | (15    | )
|Retained earnings                                                        |  |                    | 3,788  |   |                   |   | 3,568  |  
|Total common shareholders equity                                        |  |                    | 6,468  |   |                   |   | 6,228  |  
|Preferred and preference stock not subject to mandatory redemption       |  |                    | 920    |   |                   |   | 929    |  
|Total shareholders equity                                               |  |                    | 7,388  |   |                   |   | 7,157  |  
|                                                                         |  |                   
|Total liabilities and shareholders equity                               |  | $                  | 29,792 |   |                   | $ | 27,477 |  



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 EndedSeptember 30, |       
|In millions                                                            |  | 2008                           |        |   | 2007 |  
|                                                                       |  | (Unaudited)                    |       
|Cash flows from operating activities:                                  |  |                                |        |   |      |   |        |  
|Net income                                                             |  | $                              | 580    |   |      | $ | 625    |  
|Adjustments to reconcile to net cash provided by operating activities: |  |                                |        |   |      |   |        |  
|Depreciation, decommissioning and amortization                         |  |                                | 750    |   |      |   | 813    |  
|Other-than-temporary impairment on nuclear decommissioning trusts      |  |                                | 121    |   |      |   | 42     |  
|Other amortization                                                     |  |                                | 73     |   |      |   | 78     |  
|Stock-based compensation                                               |  |                                | 13     |   |      |   | 12     |  
|Minority interest                                                      |  |                                | 161    |   |      |   | 261    |  
|Deferred income taxes and investment tax credits                       |  |                                | (22    | ) |      |   | (184   | )
|Regulatory assets                                                      |  |                                | (246   | ) |      |   | 312    |  
|Regulatory liabilities                                                 |  |                                | 122    |   |      |   | 312    |  
|Derivative assets                                                      |  |                                | (57    | ) |      |   | (27    | )
|Derivative liabilities                                                 |  |                                | 52     |   |      |   | (31    | )
|Other assets                                                           |  |                                | (39    | ) |      |   | (28    | )
|Other liabilities                                                      |  |                                | (22    | ) |      |   | 254    |  
|Margin and collateral deposits  net of collateral received            |  |                                | (8     | ) |      |   | 6      |  
|Receivables and accrued unbilled revenue                               |  |                                | (453   | ) |      |   | (291   | )
|Inventory and other current assets                                     |  |                                | 42     |   |      |   | (102   | )
|Book overdrafts                                                        |  |                                | 94     |   |      |   | 110    |  
|Accrued interest and taxes                                             |  |                                | 65     |   |      |   | 319    |  
|Accounts payable and other current liabilities                         |  |                                | 87     |   |      |   | 1      |  
|Net cash provided by operating activities                              |  |                                | 1,313  |   |      |   | 2,482  |  
|Cash flows from financing activities:                                  |  |                                |        |   |      |   |        |  
|Long-term debt issued                                                  |  |                                | 1,000  |   |      |   |       |  
|Long-term debt issuance costs                                          |  |                                | (14    | ) |      |   | (1     | )
|Long-term debt repaid                                                  |  |                                | (3     | ) |      |   | (54    | )
|Bonds repurchased                                                      |  |                                | (212   | ) |      |   |       |  
|Preferred stock redeemed                                               |  |                                | (7     | ) |      |   |       |  
|Rate reduction notes repaid                                            |  |                                |       |   |      |   | (178   | )
|Short-term debt financing  net                                        |  |                                | 1,058  |   |      |   |       |  
|Shares purchased for stock-based compensation                          |  |                                | (28    | ) |      |   | (123   | )
|Proceeds from stock option exercises                                   |  |                                | 11     |   |      |   | 50     |  
|Excess tax benefits related to stock-based awards                      |  |                                | 7      |   |      |   | 25     |  
|Minority interest                                                      |  |                                | (156   | ) |      |   | (151   | )
|Dividends paid                                                         |  |                                | (263   | ) |      |   | (148   | )
|Net cash provided (used) by financing activities                       |  |                                | 1,393  |   |      |   | (580   | )
|Cash flows from investing activities:                                  |  |                                |        |   |      |   |        |  
|Capital expenditures                                                   |  |                                | (1,638 | ) |      |   | (1,650 | )
|Proceeds from nuclear decommissioning trust sales                      |  |                                | 2,279  |   |      |   | 2,866  |  
|Purchases of nuclear decommissioning trust investments and other       |  |                                | (2,329 | ) |      |   | (2,967 | )
|Sales of short-term investments                                        |  |                                |       |   |      |   | 4,861  |  
|Purchases of short-term investments                                    |  |                                | (3     | ) |      |   | (4,979 | )
|Restricted cash                                                        |  |                                |       |   |      |   | (1     | )
|Customer advances for construction and other investments               |  |                                | (11    | ) |      |   |       |  
|Net cash used by investing activities                                  |  |                                | (1,702 | ) |      |   | (1,870 | )
|Net increase in cash and equivalents                                   |  |                                | 1,004  |   |      |   | 32     |  
|Cash and equivalents, beginning of period                              |  |                                | 252    |   |      |   | 83     |  
|Cash and equivalents, end of period                                    |  | $                              | 1,256  |   |      | $ | 115    |  



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 consolidated financial
position, results of operations and cash flows in accordance with accounting principles generally accepted in the United States of America for the periods covered by this quarterly report on Form 10-Q. The results of operations for the three- and
nine-month periods ended September 30, 2008 are not necessarily indicative of the operating results for the full year.

This 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, 2007 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 2007 Annual Report on Form 10-K. SCE follows the same accounting policies for interim reporting purposes, with the exception of accounting principles adopted as of January 1, 2008 as discussed below in Margin and
Collateral Deposits and New Accounting Pronouncements.

The December 31, 2007 condensed balance sheet data was derived from audited
financial statements, but does not include all disclosures required by accounting principles generally accepted in the United States of America.

Certain
prior-period reclassifications have been made to conform to the current year financial statement presentation mostly pertaining to the adoption of FIN No. 39-1.

Cash Equivalents

At September 30, 2008, cash equivalents included U.S. treasury securities and U.S.
treasury and government agency money market funds totaling $1.1 billion. At December 31, 2007, cash equivalents included money market funds totaling $83 million. Cash equivalents, with the exception of money market funds, were stated
at cost plus accrued interest. The carrying value of cash equivalents approximates fair value due to maturities of less than three months. For further discussion of money market funds, see Note 7.

Margin and Collateral Deposits

Margin and collateral deposits
include margin requirements and cash deposited with and received from counterparties and brokers as credit support under energy contracts. The amount of margin and collateral deposits generally varies based on changes in the fair value of the
related positions. See New Accounting Pronouncements below for a discussion of the adoption of FIN No. 39-1. In accordance with FIN No. 39-1, SCE presents a portion of its margin and cash collateral deposits net with its
derivative positions on its consolidated balance sheets. Amounts recognized for cash collateral provided to others that have been offset against net derivative liabilities totaled $52 million and $2 million at September 30, 2008 and
December 31, 2007, respectively.

New Accounting Pronouncements

Accounting Pronouncement Adopted

In April 2007, the FASB issued FIN No. 39-1. This pronouncement permits
companies to offset fair value amounts recognized for the right to reclaim cash collateral (a receivable) or the obligation to return cash collateral (a payable) against fair value amounts recognized for derivative instruments executed with the same



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counterparty under a master netting arrangement. In addition, upon the adoption, companies were permitted to change their accounting policy to offset or not
offset fair value amounts recognized for derivative instruments under master netting agreements. SCE adopted FIN No. 39-1 effective January 1, 2008. The adoption resulted in netting a portion of margin and cash collateral deposits with
derivative positions on SCEs consolidated balance sheets, but had no impact on SCEs consolidated statements of income. The consolidated balance sheet at December 31, 2007 has been retroactively restated for the change, which
resulted in a decrease in margin and collateral deposits of $2 million. The consolidated statements of cash flows for the nine months ended September 30, 2007 has been retroactively restated to reflect the balance sheet changes but had no
impact on cash flows from operating activities.

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. SCE adopted this pronouncement effective January 1, 2008. The adoption had no impact because SCE did not make an optional election to report additional
financial assets and liabilities at fair value.

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 adopted SFAS No. 157 effective January 1, 2008. The adoption did not result in any retrospective adjustments to its
consolidated financial statements. The accounting requirements for employers pension and other postretirement benefit plans are effective at the end of 2008, which is the next measurement date for these benefit plans. The effective date will
be January 1, 2009 for asset retirement obligations and other nonfinancial assets and liabilities which are measured or disclosed on a non-recurring basis. For further discussion, see Note 7.

On October 10, 2008, the FASB issued FSP SFAS No. 157-3, Determining the Fair Value of a Financial Asset When the Market for That Asset Is Not
Active. This position clarifies the application of SFAS No. 157 in a market that is not active and provides an example to illustrate key considerations in determining the fair value of a financial asset when the market for that financial
asset is not active. It also reaffirms the notion of fair value as an exit price as of the measurement date. This position was effective upon issuance, including prior periods for which financial statements have not been issued. The adoption had no
impact on SCEs consolidated financial statements.

Accounting Pronouncements Not Yet Adopted

In December 2007, the FASB issued SFAS No. 160, which requires an entity to present minority interest that reflects the ownership interests in subsidiaries held
by parties other than the entity, within the equity section but separate from the entitys equity in the consolidated financial statements. It also requires the amount of consolidated net income attributable to the parent and to the
noncontrolling interest to be clearly identified and presented on the face of the consolidated statement of income; changes in ownership interest be accounted for similarly as equity transactions; and, when a subsidiary is deconsolidated, any
retained noncontrolling equity investment in the former subsidiary and the gain or loss on the deconsolidation of the subsidiary be measured at fair value. SCE will adopt SFAS No. 160 on January 1, 2009. In accordance with this
standard, SCE will reclassify minority interest to a component of shareholders equity (at September 30, 2008 this amount was $451 million).

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



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In May 2008, the FASB issued SFAS No. 162, The Hierarchy of Generally Accepted Accounting Principles,
which identifies the sources of accounting principles and the framework for selecting the principles to be used in the preparation of financial statements for nongovernmental entities that are presented in conformity with U.S. GAAP. This
statement transfers the GAAP hierarchy from the American Institute of Certified Public Accountants Statement on Auditing Standards No. 69, The Meaning of Present Fairly in Conformity With Generally Accepted Accounting Principles to
the FASB. SFAS No. 162 is effective on November 15, 2008. SCE expects that the adoption of this standard will not have an impact on SCEs consolidated results of operations, financial condition or cash flows.

In September 2008, the FASB issued FSP SFAS No. 133-1 and FIN No. 45-4. FSP SFAS No. 133-1 requires enhanced disclosures by sellers of credit
derivatives and amends FASB Interpretation No. 45 (FIN No. 45), Guarantors Accounting and Disclosure Requirements for Guarantees, Including Indirect Guarantees of Indebtedness to Others, to require additional disclosure
about the current status of the payment/performance risk of a guarantee. The provisions of the FSP that amend SFAS No. 133 and FIN No. 45 are effective for reporting periods ending after November 15, 2008. Since FSP FAS No. 133-1
and FIN No. 45-4 only require additional disclosures, the adoption will not impact SCEs consolidated financial position, results of operations or cash flows.

Property and Plant

Utility Plant

Utility plant additions, including replacements and betterments, are capitalized. Such costs include direct material and labor, construction overhead, a portion of administrative and general costs capitalized at a
rate authorized by the CPUC, and AFUDC. AFUDC represents the estimated cost of debt and equity funds that finance utility-plant construction. Currently, AFUDC debt and equity is capitalized during certain plant construction and reported in interest
expense and other nonoperating income, respectively. AFUDC is recovered in rates through depreciation expense over the useful life of the related asset.

On November 26, 2007, the FERC issued an order granting incentives on three of SCEs largest proposed transmission projects, DPV2, Tehachapi Transmission Project (Tehachapi), and Rancho Vista Substation Project
(Rancho Vista). The order permits SCE to include in rate base 100% of prudently-incurred capital expenditures during construction of all three projects. On February 29, 2008, the FERC approved SCEs revision to its Transmission
Owner Tariff to collect 100% of construction work in progress (CWIP) for these projects in rate base and earn a return on equity, rather than capitalizing AFUDC. SCE implemented the CWIP rate, subject to refund, on March 1, 2008. For further
discussion, see FERC Transmission Incentives in Note 5.

Related Party Transactions

During the first quarter of 2008, SCE entered, through a competitive bidding process, a ten-year power-purchase contract with a subsidiary of EME for the output of a 479
MW gas-peaking facility located in the City of Industry, California, which is referred to as the Walnut Creek project. The power-purchase agreement was approved by the CPUC on September 18, 2008 and by the FERC on October 2,
2008. Deliveries under the power-purchase agreement are expected to commence in 2013.

Note 2. Liabilities and Lines of Credit

Long-Term Debt

In January 2008, SCE issued $600 million
of 5.95% first and refunding mortgage bonds due in 2038. The proceeds were used to repay SCEs outstanding commercial paper of approximately $426 million and for general corporate purposes. In August 2008, SCE issued $400 million
of 5.50% first and refunding mortgage bonds due in 2018. The proceeds were used to repay SCEs outstanding commercial paper of approximately $110 million



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and borrowings under the credit facility of $200 million, as well as for general corporate purposes. In October 2008, SCE issued $500 million of
5.75% first and refunding mortgage bonds due in 2014. The proceeds were used for general corporate purposes.

The interest rates on one issue of SCEs
pollution control bonds insured by FGIC, totaling $249 million, were reset every 35 days through an auction process. Due to a loss of confidence in the creditworthiness of the bond insurers, there was a significant reduction in market
liquidity for auction rate bonds and interest rates on these bonds increased. Consequently, SCE purchased in the secondary market $37 million of its auction rate bonds in December 2007 and the remaining $212 million during the first three
months of 2008. In March 2008, SCE converted the issue to a variable rate mode and terminated the FGIC insurance policy. SCE continues to hold the bonds which remain outstanding and have not been retired or cancelled.

Short-Term Debt

Short-term debt is generally used to finance
fuel inventories, balancing account undercollections and general, temporary cash requirements including power-purchase payments. At September 30, 2008, the outstanding short-term debt was $1.56 billion at a weighted-average interest rate
of 3.53%. This short-term debt is supported by a $2.5 billion credit line. See below in Credit Agreements.

Credit Agreements

The following table summarizes the status of the SCE credit facility at September 30, 2008:



|                                                          |  |             |        |  
|--------------------------------------------------------- |  | ----------- | ------ | -
|In millions                                               |  | (Unaudited) |       
|Commitment                                                |  | $           | 2,500  |  
|Less: Unfunded commitment from Lehman Brothers subsidiary |  |             | (81    | )
|                                                          |  |             | 2,419  |  
|Outstanding borrowings                                    |  |             | (1,558 | )
|Outstanding letters of credit                             |  |             | (233   | )
|Amount available                                          |  | $           | 628    |  

On September 15, 2008, Lehman Brothers Holdings filed for protection under Chapter 11 of the U.S.
Bankruptcy Code. A subsidiary of Lehman Brothers Holding, Lehman Brothers Bank, FSB, is one of the lenders in SCEs credit agreement representing a total commitment of $106 million. In September 2008, Lehman Brothers Bank, FSB declined
requests for funding of the most recent borrowings, or approximately $42 million.

Note 3. Income Taxes

SCEs composite federal and state statutory income tax rate was approximately 40% (net of federal benefit for state income taxes) for all periods presented.
SCEs effective tax rate was 39% and 32% for the three- and nine-month periods ended September 30, 2008, as compared to 35% and 30% for the respective periods in 2007. The higher effective income tax rate for the three months ended September
30, 2008 as compared to the respective period in 2007, was primarily due to two non-deductible expenses recorded in 2008, consisting of a penalty assessed by the CPUC (see Investigation Regarding Performance Incentives Rewards in Note 5)
and higher lobbying expenses. The higher effective tax rates for the nine months ended September 30, 2008 as compared to the respective period in 2007, were due to both previously-mentioned non-deductible expenses and reductions in the income tax
reserve recorded in the first quarter of 2007 to reflect progress made in an administrative appeal process with the IRS related to the income tax treatment of certain costs associated with environmental remediation and to reflect a settlement of
state tax audit issues. The previously mentioned factors causing an increase to the 2008 federal and state effective tax rates as compared to 2007 were partially offset by higher software and property-related flow-through deductions recorded in
2008.



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Accounting for Uncertainty in Income Taxes

FIN 48 requires an enterprise to recognize, in its financial statements, the best estimate of the impact of a tax position by determining if the weight of the available evidence indicates it is more likely than not,
based solely on the technical merits, that the position will be sustained on audit. Edison International has filed affirmative tax claims related to tax positions, which, if accepted, could result in refunds of taxes paid or additional tax benefits
for positions not reflected on filed original tax returns. FIN 48 requires the disclosure of all unrecognized tax benefits, which includes the reserves recorded for tax positions on filed tax returns and the unrecognized portion of affirmative
claims.

Unrecognized Tax Benefits

The following table
provides a reconciliation of unrecognized tax benefits from January 1, 2008 to September 30, 2008 and the reasons for such changes:



|                                                           |  |             |       |  
|---------------------------------------------------------- |  | ----------- | ----- | -
|In millions                                                |  | (Unaudited) |      
|Balance at January 1, 2008                                 |  | $           | 1,950 |  
|Tax positions taken during the current year                |  |             |       |  
|Increases                                                  |  |             | 72    |  
|Decreases                                                  |  |             |      |  
|Tax positions taken during a prior year                    |  |             |       |  
|Increases                                                  |  |             | 106   |  
|Decreases                                                  |  |             | (129  | )
|Decreases for settlements during the period                |  |             |      |  
|Reductions for lapses of applicable statute of limitations |  |             |      |  
|Balance at September 30, 2008                              |  | $           | 1,999 |  

The unrecognized tax benefits in the table above reflects affirmative claims related to timing differences of
$1.5 billion and $1.6 billion at September 30, 2008 and January 1, 2008, respectively, but have not met the recognition threshold pursuant to FIN 48 and have been denied by the IRS as part of their examinations. These
affirmative claims remain unpaid by the IRS and no receivable has been recorded. Edison International has vigorously defended these affirmative claims in IRS administrative appeals proceedings and these claims are included in the ongoing Global
Settlement negotiations.

It is reasonably possible that Edison International could resolve, as part of the Global Settlement, or otherwise, with the IRS,
all or a portion of SCEs unrecognized tax benefits through tax year 2002 within the next 12 months, which could reduce unrecognized tax benefits by up to $1.3 billion.

The total amount of unrecognized tax benefits as of September 30, 2008 and January 1, 2008 that, if recognized, would have an effective tax rate impact is $62 million and $65 million, respectively.

Accrued Interest and Penalties

The total amounts of
accrued interest and penalties related to SCEs income tax reserve were $116 million and $96 million as of September 30, 2008 and January 1, 2008, respectively. The after-tax interest expense recognized and included in
income tax expense was $3 million and $12 million for the three- and nine- month periods ended September 30, 2008, respectively.

Tax
Positions being Addressed as Part of Active Examinations, Administrative Appeals and the Global Settlement

Edison International is challenging
certain IRS deficiency adjustments for tax years 1994  1999 with the Administrative Appeals branch of the IRS and Edison International is currently under active IRS examination for



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tax years 2000  2006. During the third quarter of 2008, the IRS commenced an examination of tax years 2003  2006. In addition, the statute of
limitations remains open for tax years 1986  1993, which has allowed Edison International to file certain affirmative claims related to these tax years. Tax years 1986  2002 are included in the scope of the Global Settlement and tax
years 2003  2006 are excluded.

Most of these tax positions relate to timing differences and, therefore, any amounts exclusive of any penalties that
would be paid if Edison Internationals position is not sustained would be deductible on future tax returns filed by Edison International. In addition, Edison International has filed affirmative claims with respect to certain tax years 1986
through 2005 with the IRS and state tax authorities. Any benefits associated with these affirmative claims would be recorded in accordance with FIN 48 which provides that recognition would occur at the earlier of when SCE would make an assessment
that the affirmative claim position has a more likely than not probability of being sustained or when a settlement of the affirmative claim is consummated with the tax authority. Certain of these affirmative claims have been recognized as part of
the implementation of FIN 48.

Currently, Edison International is under administrative appeals with the California Franchise Tax Board for tax years 1997
 2002 and under examination for tax years 2003  2004. Edison International remains subject to examination by the California Franchise Tax Board for tax years 2005 and forward. Edison International is also subject to examination by other
state tax authorities, subject to varying statute of limitations.

Edison International filed amended California Franchise tax returns for tax years 1997
 2002 to mitigate the possible imposition of new California non-economic substance 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 below. Edison International filed these amended returns under protest retaining its appeal rights.

As previously disclosed, Edison International is currently engaged in settlement negotiations with the IRS to reach a Global Settlement which, if consummated, would
resolve outstanding tax disputes for all Edison International subsidiaries, including SCE, for open tax years 1986 through 2002, including certain affirmative claims for unrecognized tax benefits. These negotiations have progressed to the point
where Edison International and the IRS have reached nonbinding, preliminary understandings on the material principles for resolution of all issues included in the Global Settlement. Final resolution of such disputes, as part of the Global
Settlement, is subject to reaching definitive agreements on final terms and calculations, mutually satisfactory documentation, and review of all or a portion of the Global Settlement by the Staff of the Joint Committee on Taxation, a committee of
the United States Congress (the Joint Committee). While not assured, Edison International believes that the Global Settlement will be submitted or substantially ready to be submitted to the Joint Committee during the fourth quarter of
2008.

There can be no assurance, however, about the timing of final settlements with the IRS or that such final settlements will be ultimately
consummated. Moreover, review by the Joint Committee could result in adjustments to the Global Settlement reached between Edison International and the IRS. The IRS and Edison International may not reach final agreements that implement the
preliminary understandings, or they may reach final agreements but conditions to consummating them may not be satisfied.

Balancing Account
Over-Collections

In response to an affirmative claim filed by Edison International related to balancing account over-collections, the IRS issued a
Notice of Proposed Adjustment in July 2007. This affirmative claim was addressed by the IRS as part of the ongoing IRS examinations and administrative appeals processes. The tax years to which adjustments are made pursuant to this Notice of Proposed
Adjustment are included in the scope of the Global Settlement. The cash and earnings impacts of this position are dependent on the ultimate settlement of all open tax issues, including this issue, in these tax years. Edison International expects
that resolution of this issue could potentially increase earnings and cash flows within the range of $70 million to $80 million and $300 million to $350 million, respectively.



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Contingent Liability Company

The IRS has asserted deficiencies with respect to a transaction entered into by a former SCE subsidiary which may be considered substantially similar to a Listed Transaction described by the IRS as a contingent liability company for tax
years 1997 and 1998. This issue is included in the Global Settlement and is being considered by the Administrative Appeals branch of the IRS where Edison International has been defending its income tax return position with respect to this
transaction.

Resolution of Federal and State Income Tax Issues Being Addressed in Ongoing Examinations, Administrative Appeals and the Global
Settlement

Edison International continues its efforts to resolve open tax issues through tax year 2002 as part of the Global Settlement. Although
the timing for resolving these open tax positions is uncertain, it is reasonably possible that all or a significant portion of these open tax issues through tax year 2002 could be resolved within the next 12 months.

Note 4. Compensation and Benefits Plans

Pension Plans

As of September 30, 2008, SCE has made $6 million in contributions related to 2007 and $37 million related to 2008 and estimates to make
$12 million of additional contributions in the last three months of 2008.

Volatile market conditions have affected the value of SCEs trusts
established to fund its future long-term pension benefits. The market value of the investments within the plan trusts declined 22% during the nine months ended September 30, 2008. These benefit plan assets and related obligations are remeasured
annually using a December 31 measurement date. Unless the market recovers, reductions in the value of plan assets will result in increased future expense, a change in the pension plan funding status from overfunded to underfunded and increased
future contributions. Changes in the plans funded status will affect the assets and liabilities recorded on the balance sheet in accordance with SFAS No. 158. Due to SCEs regulatory recovery treatment, the recognition of the funded
status is offset by regulatory liabilities and assets. In the 2009 GRC, SCE requested recovery of and continued balancing account treatment for amounts contributed to these trusts. The Pension Protection Act of 2006 establishes new minimum funding
standards and prohibits plans underfunded by more than 20% from providing lump sum distributions and adopting amendments that increase plan liabilities.

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                        |  | 2008                            |   |  | 2007                           |   |  | 2008  |   |  | 2007  |  
|                                   |  | (Unaudited)                     |  
|Service cost                       |  | $  27                           |   |  | $  26                          |   |  | $  81 |   |  | $  78 |  
|Interest cost                      |  | 46                              |   |  | 44                             |   |  | 138   |   |  | 132   |  
|Expected return on plan assets     |  | (63                             | ) |  | (61                            | ) |  | (189  | ) |  | (183  | )
|Amortization of prior service cost |  | 4                               |   |  | 4                              |   |  | 13    |   |  | 12    |  
|Amortization of net (gain)/loss    |  |                                |   |  | 1                              |   |  | (1    | ) |  | 3     |  
|Subtotal                           |  | 14                              |   |  | 14                             |   |  | 42    |   |  | 42    |  
|Regulatory adjustment  deferred   |  |                                |   |  | 1                              |   |  |      |   |  | 3     |  
|Total expense recognized           |  | $  14                           |   |  | $  15                          |   |  | $  42 |   |  | $  45 |  



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Postretirement Benefits Other Than Pensions

As of September 30, 2008, SCE has made no contributions related to 2007 and $14 million related to 2008 and estimates to make $26 million of additional contributions in the last three months of 2008.

Volatile market conditions have affected the value of SCEs trust established to fund its future other postretirement benefits. The market value of
the investments within the plan trust declined 21% during the nine months ended September 30, 2008. These benefit plan assets and related obligations are remeasured annually using a December 31 measurement date. Unless the market recovers,
reductions in the value of plan assets will result in increased future expense, an increase in the plan underfunded status and increased future contributions. Changes in the plans funded status will affect the assets and liabilities recorded
on the balance sheet in accordance with SFAS No. 158. Due to SCEs regulatory recovery treatment, the recognition of the funded status is offset by regulatory liabilities and assets. In the 2009 GRC, SCE requested recovery of and continued
balancing account treatment for amounts contributed to this trust.

Expense components are:



|                                     |  |                                 |   |  |                                |   |  |       |   |  |       |  
|------------------------------------ |  | ------------------------------- | - |  | ------------------------------ | - |  | ----- | - |  | ----- | -
|                                     |  | Three Months EndedSeptember 30, |   |  | Nine Months EndedSeptember 30, |  
|In millions                          |  | 2008                            |   |  | 2007                           |   |  | 2008  |   |  | 2007  |  
|                                     |  | (Unaudited)                     |  
|Service cost                         |  | $  11                           |   |  | $  10                          |   |  | $  33 |   |  | $  30 |  
|Interest cost                        |  | 33                              |   |  | 31                             |   |  | 99    |   |  | 93    |  
|Expected return on plan assets       |  | (31                             | ) |  | (30                            | ) |  | (93   | ) |  | (90   | )
|Amortization of prior service credit |  | (7                              | ) |  | (7                             | ) |  | (21   | ) |  | (21   | )
|Amortization of net loss             |  | 4                               |   |  | 6                              |   |  | 12    |   |  | 18    |  
|Total expense recognized             |  | $  10                           |   |  | $  10                          |   |  | $  30 |   |  | $  30 |  

Stock-Based Compensation

During the first quarter of 2008, Edison International granted its 2008 stock-based compensation awards, which included stock options, performance shares, deferred stock units and restricted stock units. Total
stock-based compensation expense (reflected in the caption Other operation and maintenance on the consolidated statements of income) was $2 million and $5 million for the three months ended September 30, 2008 and 2007,
respectively, and was $11 million and $22 million for the nine months ended September 30, 2008 and 2007, respectively. The income tax benefit recognized in the consolidated statements of income was $1 million and $2 million
for the three months ended September 30, 2008 and 2007, respectively, and was $5 million and $7 million for the nine months ended September 30, 2008 and 2007, respectively. Total stock-based compensation cost capitalized was less
than $1 million and $1 million for the three months ended September 30, 2008 and 2007, respectively, and was $2 million and $4 million for the nine months ended September 30, 2008 and 2007, respectively.



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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
|                                                  |  | (Unaudited) 
|Outstanding at December 31, 2007                  |  | 6,260,384    |   |  | $                | 31.21 |                                  |      |                         |   |           
|Granted                                           |  | 1,181,446    |   |  | $                | 50.01 |                                  |      |                         |   |           
|Expired                                           |  | (500         | ) |  | $                | 28.94 |                                  |      |                         |   |           
|Forfeited                                         |  | (75,472      | ) |  | $                | 48.67 |                                  |      |                         |   |           
|Exercised                                         |  | (421,973     | ) |  | $                | 25.16 |                                  |      |                         |   |           
|Transfer to associate                             |  | (296,039     | ) |  | $                | 38.77 |                                  |      |                         |   |           
|Outstanding at September 30, 2008                 |  | 6,647,846    |   |  | $                | 34.12 |                                  | 6.48 |                         |   |           
|Vested and expected to vest at September 30, 2008 |  | 6,406,430    |   |  | $                | 34.03 |                                  | 6.32 |                         | $ | 79,183,475
|Exercisable at September 30, 2008                 |  | 3,958,973    |   |  | $                | 26.60 |                                  | 5.27 |                         | $ | 78,348,076

Stock options granted in 2008 do not accrue dividend equivalents.

The amount of cash used to settle stock options exercised was $3 million and $7 million for the three months ended September 30, 2008 and 2007,
respectively, and $23 million and $111 million for the nine months ended September 30, 2008 and 2007, respectively. Cash received from options exercised was $2 million and $3 million for the three months ended
September 30, 2008 and 2007, respectively, and $11 million and $50 million for the nine months ended September 30, 2008 and 2007, respectively. The estimated tax benefit from options exercised was $1 million and
$2 million for the three months ended September 30, 2008 and 2007, respectively, and $5 million and $25 million for the nine months ended September 30, 2008 and 2007, respectively.

Note 5. Commitments and Contingencies

The following is an update to
SCEs commitments and contingencies. See Note 6 of Notes to Consolidated Financial Statements included in SCEs 2007 Annual Report on Form 10-K for a detailed discussion.

Lease Commitments

During the second quarter of 2008, SCE
entered into power-purchase contracts which are classified as operating leases. The contract terms range from 10 to 20 years. The delivery of energy under one of these contracts is not expected to commence until 2018. These additional commitments
are currently estimated to be: remainder of 2008  $4 million, 2009  $14 million, 2010  $15 million, 2011  $15 million, 2012  $15 million and thereafter 
$828 million.

During the third quarter of 2008, SCE entered into power-purchase contracts which are classified as capital leases. The contract terms
are 20 years. The delivery of energy under these contracts is expected to commence in 2010. These additional commitments are currently estimated to be: 2010  $32 million, 2011  $119 million, 2012 
$119 million and thereafter  $2.6 billion. The estimated executory costs and interest expense associated with these additional commitments are $699 million and $988 million, respectively. The total additional estimated net
commitments are $1.2 billion.



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Other Commitments

During the first nine months of 2008, SCE entered into service contracts associated with uranium enrichment and fuel fabrication. As a result, SCEs additional fuel supply commitments are estimated to be: 2009  $51 million,
2010  $54 million, 2011  $98 million, 2012  $146 million and thereafter  $671 million.

During the second
quarter of 2008, SCE entered into a new power-purchase contract. The delivery of energy under this contract is expected to commence in August 2010 with a 10 year term. SCEs additional commitments upon commencement are estimated to be:
2010  $188 million, 2011  $335 million, 2012  $341 million and thereafter  $2.7 billion.

Indemnities

Indemnity Provided as Part of the Acquisition of Mountainview

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

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 CEC 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 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 consolidated results of operations or liquidity.



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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 consolidated 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, 2008, SCEs recorded
estimated minimum liability to remediate its 24 identified sites was $47 million, of which $14 million was related to San Onofre. This remediation liability is undiscounted. 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 $167 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 30 immaterial sites whose total liability ranges from $3 million (the recorded minimum liability) to $9 million.

The CPUC allows SCE to recover environmental remediation costs at certain sites, representing $32 million of its recorded liability, through an incentive mechanism
(SCE may request to include additional sites). Under this mechanism, SCE will recover 90% of cleanup costs through customer rates; shareholders fund the remaining 10%, with the opportunity to recover these costs from insurance carriers and other
third parties. SCE has successfully settled insurance claims with all responsible carriers. SCE expects to recover costs incurred at its remaining sites through customer rates. SCE has recorded a regulatory asset of $42 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, 2008 were $32 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



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consolidated 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 various tax years. See Note 3 for further details.

FERC Transmission Incentives

On November 16,
2007, the FERC issued an order granting incentives on three of SCEs largest proposed transmission projects:



| |  | A 125 basis point ROE adder on SCEs future proposed base ROE (ROE Adder) for DPV2, which is a high voltage (500 kV) transmission line from the
Valley substation to the Devers substation near Palm Springs, California to a new substation near Palo Verde, west of Phoenix, Arizona;
|- |  | -----------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------



| |  | A 125 basis point ROE Adder for the Tehachapi Transmission Project, which is an eleven segment project consisting of newly-constructed and upgraded transmission
lines and associated substations to interconnect renewable generation projects near the Tehachapi and Big Creek area; and
|- |  | ------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------



| |  | A 75 basis point ROE Adder for the Rancho Vista Substation Project, which is a new 500 kV substation in the City of Rancho Cucamonga.
|- |  | -------------------------------------------------------------------------------------------------------------------------------------

The order also grants a higher return on equity on SCEs entire transmission rate base in SCEs next FERC transmission rate case for SCEs
participation in the CAISO. In September 2008, the FERC accepted SCEs revisions to its Transmission Owner Tariff, with a requested effective date of March 1, 2009 subject to refund and settlement procedures. In addition, the order permits
SCE to include in rate base 100% of prudently-incurred capital expenditures during construction, also known as CWIP, 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.

In June 2008, the FERC rejected petitions filed by certain parties, including the
CPUC, to address the CAISO higher return and the ROE project adders. In August 2008, the CPUC filed an appeal of the FERC incentives order at the DC Circuit Court of Appeals.

FERC Construction Work in Progress Mechanism

On December 21, 2007, SCE filed a revision to its Transmission
Owner Tariff to collect 100% of CWIP in rate base for its Tehachapi, DPV2, and Rancho Vista projects. In the CWIP filing, SCE proposed a rate adjustment ($45 million or a 14.4% increase) to SCEs currently authorized base transmission
revenue requirement to be made effective on March 1, 2008 and later adjusted for amounts actually spent in 2008 through a new balancing account mechanism. The rate adjustment represents actual expenditures from September 1, 2005 through
November 30, 2007, projected expenditures from December 1, 2007 through December 31, 2008, and a ROE (which includes the ROE adders approved for Tehachapi, DPV2 and Rancho Vista). The rate adjustment is based on a projection that SCE
will spend a total of approximately $244 million, $27 million, and $181 million for Tehachapi, DPV2, and Rancho Vista, respectively, from September 1, 2005 through the end of 2008. The 2008 DPV2 expenditure forecast is limited to
projected consulting and legal costs associated with SCEs continued efforts to obtain regulatory approvals necessary to construct the DPV2 Project. On February 29, 2008, the CWIP filing was approved and SCE implemented the CWIP rate on
March 1, 2008, subject to refund on the limited issue of whether SCEs proposed ROEs are reasonable. On March 28, 2008, the CPUC filed a Petition for Rehearing with the FERC on the FERCs acceptance of SCEs proposed ROE for
CWIP. Briefs addressing the appropriate ROE were filed by SCE and intervenors in May 2008. In addition, in the order, SCE was directed by



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FERC to make a compliance filing to provide greater detail on the costs reflected in CWIP rates for 2008. SCE made the compliance filing on March 31,
2008. On April 21, 2008, the CPUC filed a protest of the compliance filing at FERC and requested an evidentiary hearing to be set to further review the costs. SCE filed a response to the CPUCs protest on May 6, 2008 arguing that the
FERC should deny the CPUCs request for a further hearing. SCE cannot predict the outcome of the matters in this proceeding.

SCE filed its 2009
update to its CWIP rate adjustment on October 31, 2008. SCE proposed a reduction to its CWIP revenue requirement from $45 million to $39 million to be effective on January 1, 2009.

Investigation Regarding Performance Incentives Rewards

SCE was
eligible under the CPUC-approved PBR mechanism to earn rewards or incur penalties based on its performance in comparison to CPUC-approved standards of customer satisfaction, employee safety reporting, and system reliability. SCE conducted
investigations into its performance under the PBR mechanism and reported to the CPUC certain findings of misconduct and misreporting related to the first two components of the PBR program. Following SCEs reporting, the CPUC opened its own
investigation of SCEs activities relative to the PBR mechanism.

CPUC Decision

On September 18, 2008, the CPUC adopted a decision in the first phase of its investigation into SCEs incentives claimed under the CPUC-approved PBR mechanism that allowed SCE to earn rewards or incur
penalties for the period 1997  2003 based on its performance in comparison to CPUC-approved standards of customer satisfaction and employee safety reporting. The adopted decision required SCE to refund $28 million and $20 million
related to customer satisfaction and employee safety reporting incentives, respectively; and further required SCE to forego claimed incentives of $20 million and $15 million related to customer satisfaction and employee safety reporting,
respectively. The decision also required SCE to refund $33 million for employee bonuses and imposed a statutory penalty of $30 million. During the third quarter, SCE recorded a charge of $49 million, after-tax, reflected primarily in
Other nonoperating deductions in the consolidated statements of income related to this decision.

System Reliability

In light of the problems uncovered with the components of the PBR mechanism discussed above, SCE conducted an investigation into the third PBR standard, system
reliability, for the years 1997  2003. SCE received $8 million in reliability incentive awards for the period 1997  2000 and had 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, SCE determined that 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. System reliability incentives will be addressed in the second phase of the CPUCs investigation. SCE served its opening
testimony in the second phase in September 2007. In that testimony, SCE presented evidence that its PBR system reliability results were valid. The schedule for the second phase of the investigation has been deferred until November 21, 2008. SCE
cannot predict the outcome of the second phase but does not expect a material financial statement impact.

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. The order reversed an arbitrators award that had affirmed the ISOs characterization in May 2000 of the charges as Intra-Zonal Congestion costs and
allocation of those charges to scheduling coordinators in the affected zone within the ISO transmission grid. The April 20, 2004 order directed the ISO to shift the costs from scheduling coordinators in the affected zone to the responsible
participating transmission



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owner, SCE. The potential cost to SCE, net of amounts SCE expects to receive through the PX, SCEs scheduling coordinator at the time, is estimated to
be approximately $20 million to $25 million, including interest. On April 20, 2005, the FERC stayed its April 20, 2004 order during the pendency of SCEs appeal filed with the Court of Appeals for the D.C. Circuit. On
March 7, 2006, the Court of Appeals remanded the case back to the FERC at the FERCs request and with SCEs consent. 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 predict 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 predict whether recovery of these charges in its reliability service rates would
be permitted.

Four Corners CPUC Emissions Performance Standard Ruling

The CPUC adopted a GHG emission performance standard, effective January 2007. In January 2008, SCE filed a petition with the CPUC seeking clarification that the emission performance standard would not apply to capital
expenditures required by existing agreements among the owners at Four Corners. The CPUC issued a proposed decision finding that the emission performance standard was not intended to apply to capital expenditures at Four Corners requested by SCE in
its General Rate Case for the period 2007  2011. On October 23, 2008, the Assigned Commissioner and Administrative Law Judge issued a ruling withdrawing the proposed decision and seeking additional comment on whether the finding in the
proposed decision should be changed and whether SCE should be allowed to recover such capital expenditures. SCE estimates that its share of capital expenditures approved by the owners at Four Corners since the GHG emission performance standard
decision was issued in January 2007 is approximately $43 million, of which approximately $8 million had been expended through September 30, 2008. The ruling also directs SCE to explain why certain information was not included in its petition and why
the failure to include such information should not be considered misleading in violation of CPUC rules. SCE cannot predict the outcome of this proceeding or estimate the amount, if any, of penalties or disallowances that may be imposed.

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 market 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 market,
Midway-Sunset is potentially liable for refunds to purchasers in these markets.

On December 20, 2007, Midway-Sunset entered into a settlement
agreement in the amount of $86 million (including interest) with SCE, PG&E, SDG&E and certain California state parties to resolve Midway-Sunsets liability in the FERC refund proceedings. Midway-Sunset concurrently entered into a
separate agreement with SCE and PG&E that provides for pro-rata reimbursement to Midway-Sunset by the two utilities of the portions of the agreed to refunds that are attributable to sales made by Midway-Sunset for the benefit of the utilities
(Midway-Sunset did not retain any proceeds from power sold into the PX market 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). The settlement, which had been approved previously by the CPUC, was approved by the FERC on April 2, 2008.

During the period in which
Midway-Sunsets generation was sold into the PX market, amounts SCE received from Midway-Sunset for its pro-rata share of such sales were credited to SCEs customers against power purchase expenses through the ratemaking mechanism in place
at that time. During the second quarter of 2008,



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SCE reimbursed Midway-Sunset for its pro-rata share of the Midway-Sunset liability in the amount of approximately $43 million. In addition, SCE, as
party to the Midway-Sunset settlement agreement, received a $20 million generator refund. The amount reimbursed to and received from Midway-Sunset (net amount of $23 million) were charged/refunded to ratepayers through regulatory
mechanisms. As a result, the transactions associated with the Midway-Sunset settlement agreement did not impact earnings.

Navajo Nation Litigation

The Navajo Nation filed a complaint in June 1999 in the D.C. 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 March 2001, the Hopi Tribe was permitted to intervene as an additional plaintiff but has not yet identified a specific amount of damages claimed.

In April 2004, the D.C. District Court denied SCEs motion for summary judgment and concluded that a 2003 U.S. Supreme Court decision in an on-going 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 a 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. Subsequently, the Federal Circuit denied the U.S. Governments petition
for rehearing. On October 1, 2008, the U.S. Supreme Court granted the U.S. Governments petition seeking review of the Federal Circuits September 2007 decision. A decision from the U.S. Supreme Court is expected in mid-2009.

Pursuant to a joint request of the parties, the D.C. District Court granted a stay of the action in October 2004 to allow the parties to attempt to
negotiate a resolution of the issues associated with Mohave with the assistance of a facilitator. In a joint status report filed on November 9, 2007, the parties informed the court that their mediation efforts had terminated and subsequently
filed a joint motion to lift the stay. The parties have also filed recommendations for a scheduling order to govern the anticipated resumption of litigation. The Court granted the motion to lift the stay on March 6, 2008, reinstating the case
to the active calendar, but has deferred setting an overall schedule for the action pending a determination of disputes concerning the discoverability of certain Navajo documents. SCE cannot predict the outcome of the Navajo Nations and Hopi
Tribes complaints against SCE or the ultimate impact on these complaints of the Supreme Courts 2003 decision and the on-going litigation by the Navajo Nation against the U.S. Government in the related case.

Nuclear Insurance

Federal law limits public liability claims from a
nuclear incident to the amount of available financial protection, which is currently approximately $12.5 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. Beginning October 29, 2008, the maximum deferred premium for each nuclear incident is approximately $118 million per reactor, but not more than approximately
$18 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 at least once every five years
beginning August 20, 2003. The most recent inflation adjustment took effect on October 29, 2008. Based on its ownership interests, SCE could be required to pay a maximum of approximately $235 million per nuclear incident. However, it
would have to pay no more than approximately $35 million per incident in any one year.



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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 law contemplates that additional funds may be appropriated by Congress. This could include an additional assessment on all licensed reactor operators as a measure for raising further revenue.

Property damage insurance covers losses up to $500 million, including decontamination costs, at San Onofre and Palo Verde. Decontamination liability
and property damage coverage exceeding the primary $500 million also has been purchased in amounts greater than federal requirements. Additional insurance covers part of replacement power expenses during an accident-related nuclear unit outage.
A mutual insurance company owned by 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 approximately $45 million per year. Insurance premiums are charged to operating expense.

Palo Verde
Nuclear Generating Station Inspections

The NRC held three special inspections of Palo Verde, between March 2005 and February 2007. The combination of
the results of the first and third special inspections caused the NRC to undertake an additional oversight inspection of Palo Verde. This additional inspection, known as a supplemental inspection, was completed in December 2007. In addition, Palo
Verde was required to take additional corrective actions based on the outcome of completed surveys of its plant personnel and self-assessments of its programs and procedures. The NRC and APS defined and agreed to inspection and survey corrective
actions that the NRC embodied in a Confirmatory Action Letter, which was issued in February 2008. APS is presently on track to complete the corrective actions required to close the Confirmatory Action Letter by mid-2009. Palo Verde operation and
maintenance costs (including overhead) increased in 2007 by approximately $7 million from 2006. SCE estimates that operation and maintenance costs will increase by approximately $23 million (in 2007 dollars) over the two year period
2008  2009, from 2007 recorded costs including overhead costs. SCE is unable to estimate how long SCE will continue to incur these costs. In the 2009 GRC, SCE requested recovery of, and two-way balancing account treatment for, Palo Verde
operation and maintenance expenses including costs associated with these corrective actions. If approved, this would provide for recovery of these costs over the three-year GRC cycle.

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.

SCE filed its latest compliance report in August 2008. Through the use of flexible compliance rules, SCE demonstrated full compliance for the procurement year 2007 and forecasted full compliance for the procurement
years 2008 to 2020. It is unlikely that SCE will have 20% of its annual electricity sales procured from renewable resources by 2010. However, SCE may still meet the 20% target by utilizing the flexible compliance rules. SCE continues to engage in
several renewable procurement activities including formal solicitations approved by the CPUC, bilateral negotiations with individual projects and other initiatives.

Under current CPUC decisions, potential penalties for SCEs inability to achieve its renewable procurement objectives for any year will 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. SCE cannot predict whether it will be assessed penalties.

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



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for FERC-authorized scheduling coordinator and line loss charges incurred by SCE on the DWPs behalf. The scheduling coordinator charges had been billed
to the DWP under a FERC tariff that was 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 January 2008, an agreement between SCE and the DWP was executed settling the dispute discussed above. The settlement had been previously approved by the FERC in July
2007. The settlement agreement provides that the DWP will be responsible for line losses and SCE would be responsible for the scheduling coordinator charges. During the fourth quarter of 2007, SCE reversed and recognized in earnings (under the
caption Purchased power in the consolidated statements of income) $30 million of an accrued liability representing line losses previously collected from the DWP that were subject to refund. As of December 31, 2007, SCE had an
accrued liability of approximately $22 million (including $3 million of interest) representing the estimated amount SCE will refund for scheduling coordinator charges previously collected from the DWP. SCE made its first refund payment on
February 20, 2008 and the second refund payment was made on February 27, 2008. SCE previously received FERC approval to recover the scheduling coordinator charges from all transmission grid customers through SCEs transmission rates
and on December 11, 2007, the FERC accepted SCEs proposed transmission rates reflecting the forecast levels of costs associated with the settlement. Upon signing of the agreement in January 2008, SCE recorded a regulatory asset and
recognized in earnings the amount of scheduling coordinator charges to be collected through rates. On July 8, 2008, the FERC approved the refund report.

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 not later than 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, when SCE and the DOE filed a Joint Status Report in which SCE sought to lift the stay and the government opposed lifting the stay. On June 5, 2006, the Court of Federal Claims
lifted the stay on SCEs case and established a discovery schedule. In a Joint Status Report filed on July 1, 2008, the parties requested a trial date in mid-November 2008. On August 6, 2008, the Court set a trial date of
April 14  28, 2009.

SCE has primary responsibility for the interim storage of spent nuclear fuel generated at San Onofre. Spent nuclear
fuel is stored in the San Onofre Units 2 and 3 spent fuel pools and the San Onofre independent spent fuel storage installation where all of Unit 1s spent fuel located at San Onofre and some of Unit 2 and 3s spent fuel is
stored. SCE, as operating agent, plans to transfer fuel from the Unit 2 and 3 spent fuel pools to the independent storage installation on an as-needed basis to maintain full core off-load capability for Units 2 and 3. There are now sufficient
dry casks and modules available at the independent spent fuel storage installation to meet plant requirements through the end of 2008. SCE plans to add storage capacity incrementally 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. APS, as operating agent, plans to add storage capacity incrementally to maintain full core off-load capability for all three units.



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Note 6. Supplemental Cash Flows Information

SCEs supplemental cash flows information is:



|                                                                   |  |                                |     |      |   |     |  
|------------------------------------------------------------------ |  | ------------------------------ | --- | ---- | - | --- | -
|                                                                   |  | Nine Months EndedSeptember 30, |    
|In millions                                                        |  | 2008                           |     | 2007 |  
|                                                                   |  | (Unaudited)                    |    
|Cash payments for interest and taxes:                              |  |                                |     |      |   |     |  
|Interest  net of amounts capitalized                              |  | $                              | 250 |      | $ | 241 |  
|Tax payments                                                       |  |                                | 121 |      |   | 14  |  
|                                                                   |  |                               
|Noncash investing and financing activities:                        |  |                                |     |      |   |     |  
|Details of obligation under capital lease:                         |  |                                |     |      |   |     |  
|Capital lease asset purchased                                      |  | $                              |    |      | $ | (10 | )
|Capital lease obligation issued                                    |  |                                |    |      |   | 10  |  
|Dividends declared but not paid:                                   |  |                                |     |      |   |     |  
|Common stock                                                       |  | $                              | 100 |      | $ | 25  |  
|Preferred and preference stock not subject to mandatory redemption |  |                                | 13  |      |   | 8   |  

Note 7. Fair Values Measurements

SFAS No. 157 defines fair value as the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date (referred to as
an exit price in SFAS No. 157). SFAS No. 157 clarifies that a fair value measurement for a liability should reflect the entitys nonperformance risk. In addition, SFAS No. 157 establishes a fair value hierarchy that
prioritizes the inputs to valuation techniques used to measure fair value. The hierarchy gives the highest priority to unadjusted quoted market prices in active markets for identical asset and liabilities (Level 1 measurements) and the lowest
priority to unobservable inputs (Level 3 measurements). The three levels of the fair value hierarchy under SFAS No. 157 are:



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



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



| |  | Level 3  Prices or valuations that require inputs that are both significant to the fair value measurements and unobservable.
|- |  | -----------------------------------------------------------------------------------------------------------------------------

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

The fair value of derivative contracts takes into account quoted market prices, time value of money,
volatility of the underlying commodities and other factors. Derivatives that are exchange traded in active markets for identical assets or liabilities are classified as Level 1. SCEs Level 2 derivatives primarily consist of natural gas
swaps and natural gas physical trades for which SCE obtains the applicable Henry Hub and basis forward market prices from the New York Mercantile Exchange.

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



22



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quotes and models which may require SCE to extrapolate short-term observable inputs in order to calculate fair value. Level 3 also includes derivatives that
trade infrequently (such as firm transmission rights and CRRs in the California market and over-the-counter derivatives at illiquid locations), derivatives with counterparties that have significant non-performance risks, and long-term power
agreements. For illiquid firm transmission rights and CRRs, SCE reviews objective criteria related to system congestion on a quarterly basis and other underlying drivers and adjusts fair value when SCE concludes a change in objective criteria would
result in a new valuation that better reflects the fair value. Changes in fair values are based on the hypothetical sale of illiquid positions. For illiquid long-term power agreements, fair value is based upon a discounting of future electricity
prices derived from a proprietary model using the risk free discount rate for a similar duration contract, adjusted for credit risk and market liquidity. Changes in fair value are based on changes to forward market prices, including forecasted
prices for illiquid forward periods. In circumstances where SCE cannot verify fair value with observable market transactions, it is possible that a different valuation model could produce a materially different estimate of fair value. As markets
continue to develop and more pricing information becomes available, SCE continues to assess valuation methodologies used to determine fair value.

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

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



|                                  |  |             |       |   |         |   |       |         |  |   |                          |   |                           |   |    |  |   |       |  
|--------------------------------- |  | ----------- | ----- | - | ------- | - | ----- | ------- |  | - | ------------------------ | - | ------------------------- | - | -- |  | - | ----- | -
|In millions                       |  | Level 1     |       |   | Level 2 |   |       | Level 3 |  |   | Netting andCollateral(1) |   | Total atSeptember 30,2008 |  
|                                  |  | (Unaudited) |      
|Assets at Fair Value              |  |             |       |   |         |   |       |         |  |   |                          |   |                           |   |    |  |   |       |  
|Money market funds(2)             |  | $           | 1,088 |   |         | $ |      |         |  | $ |                         |   |                           | $ |   |  | $ | 1,088 |  
|Derivative contracts              |  |             | 1     |   |         |   | 2     |         |  |   | 135                      |   |                           |   |   |  |   | 138   |  
|Nuclear decommissioning trusts(3) |  |             | 1,855 |   |         |   | 999   |         |  |   |                         |   |                           |   |   |  |   | 2,854 |  
|Long-term disability plan         |  |             |      |   |         |   | 9     |         |  |   |                         |   |                           |   |   |  |   | 9     |  
|Total assets(4)                   |  |             | 2,944 |   |         |   | 1,010 |         |  |   | 135                      |   |                           |   |   |  |   | 4,089 |  
|Liabilities at Fair Value         |  |             |       |   |         |   |       |         |  |   |                          |   |                           |   |    |  |   |       |  
|Derivative contracts              |  |             | (2    | ) |         |   | (98   | )       |  |   | (114                     | ) |                           |   | 52 |  |   | (162  | )
|Net assets (liabilities)          |  | $           | 2,942 |   |         | $ | 912   |         |  | $ | 21                       |   |                           | $ | 52 |  | $ | 3,927 |  

|(1) | Represents cash collateral and the impact of netting across the levels of the fair value hierarchy. Netting among positions classified within the same level is included in that
level.
|--- | ---------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------



|(2) | Included in cash and cash equivalents on SCEs consolidated balance sheet
|--- | -------------------------------------------------------------------------



|(3) | Excludes net assets of $1 million of cash and equivalents, interest and dividend receivables and receivables related to pending securities sales and payables related to pending
securities purchases.
|--- | ------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------



|(4) | Excludes $32 million of cash surrender value of life insurance investments for deferred compensation.
|--- | -----------------------------------------------------------------------------------------------------



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The following table sets forth a summary of changes in the fair value of Level 3 derivative contracts, net for the
three- and nine- month periods ended September 30, 2008.



|                                                                                                                 |  |                                      |      |   |                                     |   |     |  
|---------------------------------------------------------------------------------------------------------------- |  | ------------------------------------ | ---- | - | ----------------------------------- | - | --- | -
|In millions                                                                                                      |  | Three Months EndedSeptember 30, 2008 |      |   | Nine Months EndedSeptember 30, 2008 |  
|                                                                                                                 |  | (Unaudited)                          |     
|Fair value of derivative contracts, net at beginning of period                                                   |  | $                                    | 265  |   |                                     | $ | (22 | )
|Total realized/unrealized losses:                                                                                |  |                                      |      |   |                                     |   |     |  
|Included in earnings                                                                                             |  |                                      |     |   |                                     |   |    |  
|Included in regulatory assets and liabilities(1)                                                                 |  |                                      | (264 | ) |                                     |   | (99 | )
|Included in accumulated other comprehensive loss                                                                 |  |                                      |     |   |                                     |   |    |  
|Purchases and settlements, net                                                                                   |  |                                      | 20   |   |                                     |   | 142 |  
|Transfers in or out of Level 3                                                                                   |  |                                      |     |   |                                     |   |    |  
|Fair value of derivative contracts, net at end of period                                                         |  | $                                    | 21   |   |                                     | $ | 21  |  
|Change during the period in unrealized losses related to net derivative contracts, held at September
30, 2008(2) |  | $                                    | (180 | ) |                                     | $ | (70 | )

|(1) | $(264) million and $(99) million reported in Purchased power expense and due to expected recovery through regulatory mechanisms, are offset in Provisions
for regulatory adjustment clauses  net on SCEs consolidated statements of income for the three- and nine-month periods ended September 30, 2008, respectively.
|--- | ------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------



|(2) | $(180) million and $(70) million reported in Purchased power expense and due to expected recovery through regulatory mechanisms, are offset in Provisions
for regulatory adjustment clauses  net on SCEs consolidated statements of income for the three- and nine-month periods ended September 30, 2008, respectively.
|--- | ------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------

Nuclear Decommissioning Trusts

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

Trust investments (at fair value) include:



|                                |  |               |  |                    |       |                  |   |      
|------------------------------- |  | ------------- |  | ------------------ | ----- | ---------------- | - | -----
|In millions                     |  | MaturityDates |  | September 30, 2008 |       | December 31,2007
|                                |  | (Unaudited)  
|Municipal bonds                 |  | 2008  2044   |  | $                  | 564   |                  | $ | 561  
|Stocks                          |  |              |  |                    | 1,672 |                  |   | 1,968
|United States government issues |  | 2008  2049   |  |                    | 318   |                  |   | 552  
|Corporate bonds                 |  | 2008  2047   |  |                    | 267   |                  |   | 241  
|Short-term                      |  | 2008  2009   |  |                    | 34    |                  |   | 56   
|Total                           |  |               |  | $                  | 2,855 |                  | $ | 3,378

Note: Maturity dates as of September 30, 2008.



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The following table sets forth a summary of changes in the fair value of the trust for the three- and nine-month periods
ended September 30, 2008:



|                                |  |                                      |       |   |                                     |   |       |  
|------------------------------- |  | ------------------------------------ | ----- | - | ----------------------------------- | - | ----- | -
|In millions                     |  | Three Months EndedSeptember 30, 2008 |       |   | Nine Months EndedSeptember 30,
2008 |  
|                                | 
|                                |  | (Unaudited)                          |      
|Balance at beginning of period  |  | $                                    | 3,152 |   |                                     | $ | 3,378 |  
|Realized losses  net           |  |                                      | (7    | ) |                                     |   | (13   | )
|Unrealized losses  net         |  |                                      | (240  | ) |                                     |   | (452  | )
|Other-than-temporary impairment |  |                                      | (49   | ) |                                     |   | (121  | )
|Earnings and other              |  |                                      | (1    | ) |                                     |   | 63    |  
|Balance at September 30, 2008   |  | $                                    | 2,855 |   |                                     | $ | 2,855 |  

The decrease in the trust investments was primarily due to net unrealized losses and other-than-temporary
impairment resulting from a volatile stock market environment.

Nuclear decommissioning costs are recovered in utility rates. These costs are expected to
be funded from independent decommissioning trusts, which effective January 2007, receive contributions of approximately $46 million per year. Contributions to the decommissioning trusts are reviewed every three years by the CPUC. The next
filing is in April 2009 for contribution changes in 2010. These contributions are determined based on an analysis of the current value of trusts assets and long-term forecasts of cost escalation, the estimate and timing of decommissioning costs, and
after-tax return on trust investments. Favorable or unfavorable investment performance in a period will not change the amount of contributions for that period. However, trust performance for the three years leading up to a CPUC review proceeding
will provide input into future contributions. The CPUC has set certain restrictions related to the investments of these trusts. If additional funds are needed for decommissioning, it is probable that the additional funds will be recoverable through
customer rates.

Note 8. Regulatory Assets and Liabilities

Regulatory assets included in the consolidated balance sheets are:



|                                                             |  |                   |       |                  |   |      
|------------------------------------------------------------ |  | ----------------- | ----- | ---------------- | - | -----
|In millions                                                  |  | September 30,2008 |       | December 31,2007
|                                                             |  | (Unaudited)       |       |                 
|Current:                                                     |  |                   |       |                  |   |      
|Regulatory balancing accounts                                |  | $                 | 260   |                  | $ | 99   
|Energy derivatives                                           |  |                   | 165   |                  |   | 71   
|Purchased-power settlements                                  |  |                   | 2     |                  |   | 8    
|Deferred firm transmission rights proceeds                   |  |                   | 24    |                  |   | 15   
|Other                                                        |  |                   | 3     |                  |   | 4    
|                                                             |  |                   | 454   |                  |   | 197  
|Long-term:                                                   |  |                   |       |                  |   |      
|Regulatory balancing accounts                                |  |                   | 14    |                  |   | 15   
|Flow-through taxes  net                                     |  |                   | 1,319 |                  |   | 1,110
|Unamortized nuclear investment  net                         |  |                   | 382   |                  |   | 405  
|Nuclear-related asset retirement obligation investment  net |  |                   | 282   |                  |   | 297  
|Unamortized coal plant investment  net                      |  |                   | 81    |                  |   | 94   
|Unamortized loss on reacquired debt                          |  |                   | 315   |                  |   | 331  
|SFAS No. 158 pensions and postretirement benefits            |  |                   | 240   |                  |   | 231  
|Energy derivatives                                           |  |                   | 77    |                  |   | 70   
|Environmental remediation                                    |  |                   | 42    |                  |   | 64   
|Other                                                        |  |                   | 128   |                  |   | 104  
|                                                             |  |                   | 2,880 |                  |   | 2,721
|Total Regulatory Assets                                      |  | $                 | 3,334 |                  | $ | 2,918



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Regulatory liabilities included in the consolidated balance sheets are



|                                                        |  |                   |       |                  |   |      
|------------------------------------------------------- |  | ----------------- | ----- | ---------------- | - | -----
|In millions                                             |  | September 30,2008 |       | December 31,2007
|                                                        |  | (Unaudited)       |       |                 
|Current:                                                |  |                   |       |                  |   |      
|Regulatory balancing accounts                           |  | $                 | 1,106 |                  | $ | 967  
|Rate reduction notes  transition cost overcollection   |  |                   | 20    |                  |   | 20   
|Energy derivatives                                      |  |                   | 7     |                  |   | 10   
|Deferred firm transmission rights costs                 |  |                   | 42    |                  |   | 19   
|Other                                                   |  |                   | 4     |                  |   | 3    
|                                                        |  |                   | 1,179 |                  |   | 1,019
|Long-term:                                              |  |                   |       |                  |   |      
|Regulatory balancing accounts                           |  |                   | 10    |                  |   |     
|Asset retirement obligations                            |  |                   | 167   |                  |   | 793  
|Costs of removal                                        |  |                   | 2,319 |                  |   | 2,230
|SFAS No. 158 pensions and other postretirement benefits |  |                   | 317   |                  |   | 308  
|Energy derivatives                                      |  |                   | 1     |                  |   | 27   
|Employee benefit plans                                  |  |                   | 75    |                  |   | 75   
|                                                        |  |                   | 2,889 |                  |   | 3,433
|Total Regulatory Liabilities                            |  | $                 | 4,068 |                  | $ | 4,452

Note 9. Preferred and Preference Stock Not Subject to Mandatory Redemption

In January 2008, SCE repurchased 350,000 shares of 4.08% cumulative preferred stock at a price of $19.50 per share. SCE retired this preferred stock in January 2008
and recorded a $2 million gain on the cancellation of reacquired capital stock (reflected in the caption Additional paid-in capital on the consolidated balance sheets). There is no sinking fund requirement for redemptions or
repurchases of preferred stock.

Note 10. Business Segments

SCEs reportable business segments include the rate-regulated electric utility segment and the VIEs segment. 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.



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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, 2008: |  |                 |        |      |   |              |  |   |     |   |  |   |       
|Cash and equivalents                          |  | $               | 1,138  |      | $ | 118          |  | $ |    |   |  | $ | 1,256 
|Accounts receivable  net                     |  |                 | 990    |      |   | 106          |  |   | (66 | ) |  |   | 1,030 
|Inventory                                     |  |                 | 336    |      |   | 16           |  |   |    |   |  |   | 352   
|Other current assets                          |  |                 | 79     |      |   | 5            |  |   |    |   |  |   | 84    
|Nonutility property  net of depreciation     |  |                 | 676    |      |   | 291          |  |   |    |   |  |   | 967   
|Other long-term assets                        |  |                 | 657    |      |   | 1            |  |   |    |   |  |   | 658   
|Total assets                                  |  |                 | 29,321 |      |   | 537          |  |   | (66 | ) |  |   | 29,792
|Accounts payable                              |  |                 | 836    |      |   | 68           |  |   | (66 | ) |  |   | 838   
|Other current liabilities                     |  |                 | 679    |      |   | 3            |  |   |    |   |  |   | 682   
|Asset retirement obligations                  |  |                 | 2,951  |      |   | 15           |  |   |    |   |  |   | 2,966 
|Minority interest                             |  |                 |       |      |   | 451          |  |   |    |   |  |   | 451   
|Total liabilities and shareholders equity    |  | $               | 29,321 |      | $ | 537          |  | $ | (66 | ) |  | $ | 29,792
|                                              |  |                 |        |     
|Balance Sheet Items as of December 31, 2007:  |  |                 |        |      |   |              |  |   |     |   |  |   |       
|Cash and equivalents                          |  | $               | 142    |      | $ | 110          |  | $ |    |   |  | $ | 252   
|Accounts receivable  net                     |  |                 | 684    |      |   | 110          |  |   | (69 | ) |  |   | 725   
|Inventory                                     |  |                 | 265    |      |   | 18           |  |   |    |   |  |   | 283   
|Other current assets                          |  |                 | 184    |      |   | 4            |  |   |    |   |  |   | 188   
|Nonutility property  net of depreciation     |  |                 | 700    |      |   | 300          |  |   |    |   |  |   | 1,000 
|Other long-term assets                        |  |                 | 627    |      |   | 2            |  |   |    |   |  |   | 629   
|Total assets                                  |  |                 | 27,002 |      |   | 544          |  |   | (69 | ) |  |   | 27,477
|Accounts payable                              |  |                 | 902    |      |   | 81           |  |   | (69 | ) |  |   | 914   
|Other current liabilities                     |  |                 | 545    |      |   | 3            |  |   |    |   |  |   | 548   
|Asset retirement obligations                  |  |                 | 2,862  |      |   | 15           |  |   |    |   |  |   | 2,877 
|Minority interest                             |  |                 | 1      |      |   | 445          |  |   |    |   |  |   | 446   
|Total liabilities and shareholders equity    |  | $               | 27,002 |      | $ | 544          |  | $ | (69 | ) |  | $ | 27,477



27



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##### Table of Contents

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



|                                                                      |  |                 |       |   |      |   |      |               |  |   |      |   |  |   |       |  
|--------------------------------------------------------------------- |  | --------------- | ----- | - | ---- | - | ---- | ------------- |  | - | ---- | - |  | - | ----- | -
|In millions                                                           |  | ElectricUtility |       |   | VIEs |   |      | Eliminations* |  |   | SCE  |  
|                                                                      |  | (Unaudited)     |      
|Income Statement Items for the Three Months Ended September 30, 2008: |  |                 |       |   |      |   |      |               |  |   |      |   |  |   |       |  
|Operating revenue                                                     |  | $               | 3,156 |   |      | $ | 358  |               |  | $ | (229 | ) |  | $ | 3,285 |  
|Fuel                                                                  |  |                 | 173   |   |      |   | 242  |               |  |   |     |   |  |   | 415   |  
|Purchased power                                                       |  |                 | 2,191 |   |      |   |     |               |  |   | (229 | ) |  |   | 1,962 |  
|Provisions for regulatory adjustment clauses  net                    |  |                 | (737  | ) |      |   |     |               |  |   |     |   |  |   | (737  | )
|Other operation and maintenance                                       |  |                 | 697   |   |      |   | 14   |               |  |   |     |   |  |   | 711   |  
|Depreciation, decommissioning and amortization                        |  |                 | 203   |   |      |   | 8    |               |  |   |     |   |  |   | 211   |  
|Property and other taxes                                              |  |                 | 61    |   |      |   |     |               |  |   |     |   |  |   | 61    |  
|Net gain on sale of assets                                            |  |                 | (1    | ) |      |   |     |               |  |   |     |   |  |   | (1    | )
|Total operating expenses                                              |  |                 | 2,587 |   |      |   | 264  |               |  |   | (229 | ) |  |   | 2,622 |  
|Operating income                                                      |  |                 | 569   |   |      |   | 94   |               |  |   |     |   |  |   | 663   |  
|Interest income                                                       |  |                 | 2     |   |      |   |     |               |  |   |     |   |  |   | 2     |  
|Other nonoperating income                                             |  |                 | 20    |   |      |   |     |               |  |   |     |   |  |   | 20    |  
|Interest expense  net of amounts capitalized                         |  |                 | (104  | ) |      |   |     |               |  |   |     |   |  |   | (104  | )
|Other nonoperating deductions                                         |  |                 | (81   | ) |      |   |     |               |  |   |     |   |  |   | (81   | )
|Income tax expense                                                    |  |                 | (158  | ) |      |   |     |               |  |   |     |   |  |   | (158  | )
|Minority interest                                                     |  |                 |      |   |      |   | (94  | )             |  |   |     |   |  |   | (94   | )
|Net income                                                            |  | $               | 248   |   |      | $ |     |               |  | $ |     |   |  | $ | 248   |  
|                                                                      |  |                 |       |  
|Income Statement Items for the Three Months EndedSeptember 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   |  

|* | 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 the Nine Months EndedSeptember 30, 2008: |  |                 |       |   |      |   |      |               |  |   |      |   |  |   |       |  
|Operating revenue                                                   |  | $               | 8,047 |   |      | $ | 933  |               |  | $ | (590 | ) |  | $ | 8,390 |  
|Fuel                                                                |  |                 | 480   |   |      |   | 681  |               |  |   |     |   |  |   | 1,161 |  
|Purchased power                                                     |  |                 | 3,701 |   |      |   |     |               |  |   | (590 | ) |  |   | 3,111 |  
|Provisions for regulatory adjustment clauses  net                  |  |                 | (286  | ) |      |   |     |               |  |   |     |   |  |   | (286  | )
|Other operation and maintenance                                     |  |                 | 2,076 |   |      |   | 69   |               |  |   |     |   |  |   | 2,145 |  
|Depreciation, decommissioning and amortization                      |  |                 | 724   |   |      |   | 26   |               |  |   |     |   |  |   | 750   |  
|Property and other taxes                                            |  |                 | 179   |   |      |   |     |               |  |   |     |   |  |   | 179   |  
|Net gain on sale of assets                                          |  |                 | (9    | ) |      |   |     |               |  |   |     |   |  |   | (9    | )
|Total operating expenses                                            |  |                 | 6,865 |   |      |   | 776  |               |  |   | (590 | ) |  |   | 7,051 |  
|Operating income                                                    |  |                 | 1,182 |   |      |   | 157  |               |  |   |     |   |  |   | 1,339 |  
|Interest income                                                     |  |                 | 10    |   |      |   | 2    |               |  |   |     |   |  |   | 12    |  
|Other nonoperating income                                           |  |                 | 67    |   |      |   | 2    |               |  |   |     |   |  |   | 69    |  
|Interest expense  net of amounts capitalized                       |  |                 | (297  | ) |      |   |     |               |  |   |     |   |  |   | (297  | )
|Other nonoperating deductions                                       |  |                 | (114  | ) |      |   |     |               |  |   |     |   |  |   | (114  | )
|Income tax expense                                                  |  |                 | (268  | ) |      |   |     |               |  |   |     |   |  |   | (268  | )
|Minority interest                                                   |  |                 |      |   |      |   | (161 | )             |  |   |     |   |  |   | (161  | )
|Net income                                                          |  | $               | 580   |   |      | $ |     |               |  | $ |     |   |  | $ | 580   |  
|                                                                    |  |                 |       |  
|Income Statement Items for the Nine Months EndedSeptember 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   |  

|* | 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 MD&A for the three- and nine-month periods ended September 30, 2008
discusses material changes in the consolidated financial condition, results of operations and other developments of SCE since December 31, 2007, and as compared to the three- and nine-month periods ended September 30, 2007. This discussion
presumes that the reader has read or has access to SCEs MD&A for the calendar year 2007 (the year-ended 2007 MD&A), which was included in SCEs 2007 annual report to shareholders and incorporated by reference into SCEs
Annual Report on Form 10-K for the year ended December 31, 2007, 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 cost of capital and the ability to borrow funds and access to capital markets on favorable terms, particularly in light of current credit conditions in the
capital markets and uncertainty over the global economic outlook;
|- |  | ---------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------



| |  | the availability and creditworthiness of counterparties to enter into hedge transactions to reduce market price risk;
|- |  | ---------------------------------------------------------------------------------------------------------------------



| |  | the ability to procure sufficient resources to meet expected customer needs in the event of significant counterparty defaults under power-purchase agreements;
|- |  | --------------------------------------------------------------------------------------------------------------------------------------------------------------



| |  | changes in the fair value of investments and other assets;
|- |  | ----------------------------------------------------------



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



| |  | changes in interest rates, rates of inflation beyond those rates which may be adjusted from year to year by public utility regulators, and foreign exchange rates;
|- |  | ------------------------------------------------------------------------------------------------------------------------------------------------------------------



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



| |  | environmental laws and regulations, both at the state and federal levels, 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;
|- |  | -----------------------------------------------------------------------------------------------------



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



| |  | the outcome of disputes with the IRS and other tax authorities regarding tax positions taken by SCE;
|- |  | ----------------------------------------------------------------------------------------------------



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



| |  | the cost and availability of emission credits or allowances for emission credits;
|- |  | ---------------------------------------------------------------------------------



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



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



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



| |  | general political, economic and business conditions;
|- |  | ----------------------------------------------------



| |  | weather conditions, natural disasters and other unforeseen events; 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 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 the 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 most important. This section is not intended to be an all-inclusive list of all current developments related to each principal business segment and should be read together with all sections of
this MD&A.

Financial Markets and Economic Conditions

Global financial markets are experiencing severe credit tightening and a significant increase in volatility, causing access to capital markets to become subject to increased uncertainty and borrowing costs to rise dramatically. In response,
U.S. and foreign governments and Central Banks have intervened with programs designed to increase liquidity.

SCE is a capital intensive business and
depends on access to the financial markets to fund capital expenditures, meet contractual obligations and support margin and collateral requirements. SCE has significant planned capital expenditures to replace and expand its distribution and
transmission infrastructure, and to construct and replace generation assets. See Liquidity and Commitments and Indemnities for further discussion.



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Due to the instability of the financial markets, and to provide protection against a dramatic liquidity crisis, in
September 2008 SCE borrowed under the credit facility a total of $958 million, although there was no immediate need for such funds. The proceeds from these borrowings were invested in U.S. treasury securities and U.S. treasury and government
agency money market funds. As of September 30, 2008, SCE had $1.89 billion of available liquidity made up of $1.26 billion of cash and short-term investments ($118 million of which was held by SCEs consolidated VIEs), as well as
$628 million available under the credit facility. In addition, in October 2008, SCE issued $500 million of 5.75% first and refunding mortgage bonds due in 2014. The bond proceeds further augmented SCEs cash position. SCE does not have any
material debt obligations that mature until 2014. See Liquidity for further discussion.

While the capital markets are expected to recover over
time, it is uncertain how long before a recovery occurs. The level of future growth for SCE will largely be dependent on the outcome of SCEs 2009 GRC (see LiquidityCapital Expenditures and Regulatory
MattersCurrent Regulatory Developments2009 General Rate Case Proceeding). Also, SCE relies on power-purchase contracts to meet its resource requirements. The financial crisis may adversely affect the ability of counterparties to
access the capital markets, as needed, to perform under contracts upon which SCE will rely to meet new generation and RPS requirements. Additionally, if counterparties fail to deliver under power-purchase contracts, SCE would be exposed to
potentially volatile spot markets for buying replacement power, but would expect to recover any additional costs through regulatory mechanisms. The volatile market conditions have also affected the value of trusts established at SCE to fund future
long-term pension, other postretirement benefits, and nuclear decommissioning obligations. The market decline has eroded the funded status of these plans and unless the market recovers, will result in increased future expense and higher funding
levels. SCE currently recovers and expects to continue to recover its pension, other postretirement benefits, and decommissioning costs, through customer rates and therefore funded cost increases are not expected to impact earnings, but may impact
the timing of cash flows (see Liquidity and Other Developments for further discussion).

Long-term disruption in the capital
markets could adversely affect SCEs business plans and potentially impact SCEs financial position.

Bankruptcy of Lehman Brothers Holdings
and Subsidiaries

On September 15, 2008, Lehman Brothers Holdings filed for protection under Chapter 11 of the U.S. Bankruptcy Code. A
subsidiary of Lehman Brothers Holdings, Lehman Brothers Bank, FSB is one of the lenders in SCEs credit agreement representing a total commitment of $106 million. In September 2008, Lehman Brothers Bank, FSB declined requests for funding
under SCEs credit agreement.

Federal and State Income Taxes

Edison International is currently engaged in settlement negotiations with the IRS to reach a Global Settlement, which, if consummated, would resolve outstanding tax disputes for all Edison International subsidiaries,
including SCE, for open tax years 1986 through 2002, including certain affirmative claims for unrecognized tax benefits. See Southern California Edison Company Notes to Consolidated Financial StatementsNote 3. Income Taxes. These
negotiations have progressed to the point where Edison International and the IRS have reached nonbinding, preliminary understandings on the material principles for resolution of all issues included in the Global Settlement. Final resolution of such
disputes, as part of the Global Settlement, is subject to reaching definitive agreements on final terms and calculations, mutually satisfactory documentation, and review of all or a portion of the Global Settlement by the Staff of the Joint
Committee on Taxation, a committee of the United States Congress (the Joint Committee). While not assured, Edison International believes that the Global Settlement will be submitted or substantially ready to be submitted to the Joint
Committee during the fourth quarter of 2008. See Other DevelopmentsFederal and State Income Taxes for further information.



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Investigation Regarding Performance Incentives Rewards CPUC Decision

On September 18, 2008, the CPUC adopted a decision in its investigation into SCEs incentives claimed under a CPUC-approved PBR mechanism that allowed SCE to
earn rewards or incur penalties for the period 1997  2003 based on its performance in comparison to CPUC-approved standards of customer satisfaction and employee safety reporting. The adopted decision required refunds or to forego incentives
of $48 million and $35 million related to previous customer satisfaction and employee safety reporting incentives, respectively. The decision also required SCE to refund $33 million for employee bonuses and imposed a statutory penalty
of $30 million. During the third quarter, SCE recorded a charge of $49 million, after-tax reflected primarily in Other nonoperating deductions in the consolidated statements of income related to this decision. See
Regulatory MattersCurrent Regulatory DevelopmentsInvestigations Regarding Performance Incentives Rewards for further discussion.

2009 General Rate Case Proceeding

SCE filed its GRC application requesting a 2009 base rate revenue requirement of $5.16 billion.
After considering the effects of sales growth and other offsets, SCEs request would be a $695 million increase over current authorized base rate revenue. On April 15, 2008, the DRA recommended that SCEs 2009 base rate revenue
requirement be increased by approximately $19 million, $676 million less than SCEs revised request, mainly due to reductions in capital-related costs, operating and maintenance expense, administrative and general expense, and other
miscellaneous proposed reductions. Testimony submitted by TURN, another intervenor, sought to reduce SCEs 2009 request by an additional $195 million over the DRA proposed adjustments, mainly due to reduced depreciation expense. In
September 2008, SCE submitted updated testimony, limited to changes in the escalation rate forecast and known changes due to governmental action which increased the requested 2009 base rate revenue requirement to $5.21 billion, an increase of
$739 million over current authorized base rate revenue. See Regulatory MattersCurrent Regulatory Developments2009 General Rate Case Proceeding for further discussion. A final decision is expected prior to year-end 2008.

2009 FERC Rate Case

In September 2008, the FERC
accepted SCEs revisions to its Transmission Owner Tariff, effective on March 1, 2009, subject to refund and settlement procedures. The revisions reflected changes to SCEs transmission revenue requirement and transmission rates for
customers taking service over SCEs transmission facilities.

SCE requested a $129 million increase in its retail transmission revenue
requirements (or a 39% increase over the current retail transmission revenue requirement). The requested increase amounts to a 1.2% system average rate increase due to an increase in transmission capital-related costs and increases in transmission
operating and maintenance expenses that SCE expects to incur in 2009 to maintain grid reliability. The transmission revenue requirement is based on an overall return on equity of 12.7%, which is composed of a 12.0% base ROE and 0.7% in transmission
incentives previously approved by the FERC (see Regulatory MattersCurrent Regulatory DevelopmentsFERC Construction Work in Progress Mechanism for further information). As discussed in LiquidityCapital
Expenditures, SCE has significant planned expenditures to replace and expand its transmission infrastructure.

Solar Photovoltaic Program

On March 27, 2008, SCE filed an application with the CPUC to implement its Solar Photovoltaic (PV) Program to develop up to 250 MW of utility-owned
Solar PV generating facilities ranging in size from 1 to 2 MW each. Targeted at commercial and industrial rooftop space in SCEs service territory, SCEs program will use rooftop space from entities that would not otherwise be typical
candidates for the net energy metering tariff, which allows customers to offset their usage with electricity generated at their own facilities. SCE proposes to develop these projects at a rate of approximately 50 MW per year at an average cost of
$3.50/watt. The estimated base case capital cost for the Solar PV Program is $875 million (2008 dollars) over the period of the program



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(20082013). SCE proposes a reasonableness threshold of $963 million in nominal dollars. Subject to CPUC approval, the capital expenditures will be
eligible to be included in SCEs earning asset base if the actual costs of the program are equal to or lower than the reasonableness threshold amount. SCE also proposes to apply the CPUC-approved 100 basis point incentive adder to SCEs
allowed rate of return on rate base on the project as allowed by the CPUC decision for qualifying utility-owned renewable energy generation facilities. In September 2008, the CPUC granted SCEs request to track costs spent on projects up to
$25 million incurred prior to the receipt of the CPUCs final decision in a memorandum account for potential future recovery. SCE expects to continue to move forward with projects in advance of the final CPUC decision subject to the
authorized tracking account mechanism. In September 2008, several parties filed testimony opposing SCEs Solar PV program application. Evidentiary hearings are scheduled for November 2008 and a final decision for March 2009. SCE
cannot predict the final outcome of this proceeding.

Enterprise-Wide Software System Project

On July 1, 2008, SCE implemented SAPs Enterprise Resource Planning system for financial, supply chain, and certain work management modules at SCE. In addition,
SCE also implemented the human resources module including payroll and timekeeping. SCE expects to implement additional SAP modules in the future.

LIQUIDITY

Overview

In light of current
market conditions, SCE borrowed against its credit facility in September 2008 and issued bonds in October 2008 to ensure the availability of funds to meet its future cash requirements. The proceeds were invested in U.S. treasury bills and U.S.
treasury and government agency money market funds. As of September 30, 2008, SCE had cash and equivalents of $1.26 billion ($118 million of which was held by SCEs consolidated VIEs).

On March 12, 2008, SCE amended its existing $2.5 billion credit facility, extending the maturity to February 2013 while retaining existing borrowing costs as
specified in the facility. The amendment also provides four extension options which, if all exercised, and agreed to by lenders, will result in a final termination in February 2017.

The following table summarizes the status of the SCE credit facility at September 30, 2008:



|                                                          |  |   |        |  
|--------------------------------------------------------- |  | - | ------ | -
|In millions                                               |  |   |       
|Commitment                                                |  | $ | 2,500  |  
|Less: Unfunded commitment from Lehman Brothers subsidiary |  |   | (81    | )
|                                                          |  |   | 2,419  |  
|Outstanding borrowings                                    |  |   | (1,558 | )
|Outstanding letters of credit                             |  |   | (233   | )
|Amount available                                          |  | $ | 628    |  

On September 15, 2008, Lehman Brothers Holdings filed for protection under Chapter 11 of the U.S.
Bankruptcy Code. A subsidiary of Lehman Brothers Holdings, Lehman Brothers Bank, FSB is one of the lenders in SCEs credit agreement representing a total commitment of $106 million. In September 2008, Lehman Brothers Bank, FSB declined
requests for funding of the most recent borrowings, or approximately $42 million.

As of September 30, 2008, SCEs long-term debt, including
current maturities of long-term debt, was $5.86 billion. In October 2008, SCE issued $500 million of 5.75% first and refunding mortgage bonds due in 2014.



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SCEs estimated cash outflows during the 12-month period following September 30, 2008 are expected to consist
of:



| |  | Projected capital expenditures 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 $25 million dividend to Edison International which was paid in January
2008 and three $100 million dividends which were paid in April 2008, July 2008, and October 2008, respectively;
|- |  | --------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------



| |  | Fuel and procurement-related costs (see Regulatory MattersCurrent Regulatory DevelopmentsEnergy Resource Recovery Account
Proceedings);
|- |  | -------------------------------------------------------------------------------------------------------------------------------------------



| |  | Maturity and interest payments on short- and long-term debt outstanding;
|- |  | ------------------------------------------------------------------------



| |  | General operating expenses; and
|- |  | -------------------------------



| |  | Pension and PBOP trust contributions (see Pension and PBOP trusts below).
|- |  | ----------------------------------------------------------------------------

As discussed above, SCE has increased its cash position and expects to meet its continuing obligations, including cash outflows for operating expenses and
power-procurement, through cash and equivalents on hand and operating cash flows. Projected capital expenditures are also expected to be financed through cash and cash equivalents on hand and operating cash flows and incremental capital market
financings of long-term debt and preferred equity. SCE expects that it would also be able to draw on the remaining availability of its credit facility and access capital markets if additional funding and liquidity is necessary to meet the estimated
capital requirements but given current market developments there can be no assurance.

On February 13, 2008, President Bush signed the Economic
Stimulus Act of 2008 (2008 Stimulus Act). The 2008 Stimulus Act includes a provision that provides accelerated bonus depreciation for certain capital expenditures incurred during 2008. SCE expects that certain capital expenditures incurred by SCE
during 2008 will qualify for this accelerated bonus depreciation, which would provide additional cash flow benefits estimated to be approximately $175 million for 2008. Any cash flow benefits resulting from this accelerated depreciation should
be timing in nature and therefore should result in a higher level of accumulated deferred income taxes reflected on SCEs consolidated balance sheets. Timing benefits related to deferred taxes will be incorporated into future ratemaking
proceedings, impacting future period cash flow and rate base.

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 2007 MD&A, SCE has significant planned capital expenditures to
replace and expand its distribution and transmission infrastructure, and to construct and replace generation assets. SCEs 2008 through 2012 capital forecast includes total expenditures of up to $19.9 billion, including capital investments
for SCEs Solar PV Program. Certain of these expenditures are subject to regulatory approvals. During the three- and nine-month periods ended September 30, 2008, SCEs capital expenditures were $383 million and
$1.55 billion, respectively, compared to a forecast of $2.1 billion for the nine months ended September 30, 2008. SCEs 2008 capital expenditures are likely to be less than the forecast for 2008, primarily due to delays in transmission
investments. SCE expects to update its 5-year capital forecast after receiving a final decision in its 2009 GRC. The developments in the financial markets, regulatory decisions, and the economic conditions in the U.S. may alter SCEs capital
expenditures plan. See Current DevelopmentsFinancial Markets and Economic Conditions for further discussion.

Pension and PBOP Trusts

Volatile market conditions have affected the value of SCEs trusts established to fund its future long-term pension benefits and other
postretirement benefits. The market value of the investments within the pension and



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PBOP plan trusts declined 22% and 21%, respectively, during the nine months ended September 30, 2008. These benefit plan assets and related obligations
are remeasured annually using a December 31 measurement date. Unless the market recovers, reductions in the value of plan assets will result in: increased future expense; a change in the pension plan funding status from overfunded to
underfunded; an increase in the PBOP plan underfunded status; and increased future contributions. Changes in the plans funded status will affect the assets and liabilities recorded on the balance sheet in accordance with SFAS No. 158. Due
to SCEs regulatory recovery treatment, the recognition of the funded status is offset by regulatory liabilities and assets. In the 2009 GRC, SCE requested recovery of and continued balancing account treatment for amounts contributed to these
trusts (see Regulatory MattersCurrent Regulatory Developments2009 General Rate Case Proceeding for further discussion). The Pension Protection Act of 2006 establishes new minimum funding standards and prohibits plans
underfunded by more than 20% from providing lump sum distributions and adopting amendments that increase plan liabilities.

Credit Ratings

At September 30, 2008, 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        

SCE credit ratings have remained consistent with the ratings that existed at year-end 2007. 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%. At September 30, 2008, SCE determined compliance with this capital structure based on a 13-month weighted-average calculation. At September 30, 2008, SCEs 13-month weighted-average
common equity component of total capitalization was 50.6% resulting in the capacity to pay $333 million in additional dividends.

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, 2008, SCEs debt to total capitalization ratio was 0.50 to 1.

Margin and Collateral Deposits

SCE has entered into certain
margining agreements for power and natural 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. Future collateral requirements may be higher (or lower) than collateral requirements at September 30, 2008, due to the
addition of incremental power and energy procurement contracts with margining agreements, if any, and the impact of changes in wholesale power and natural gas prices on SCEs contractual obligations.



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Certain requirements to post cash and/or collateral (primarily for changes in fair value and accounts payables on
delivered energy transactions) are triggered if SCEs credit ratings were downgraded to below investment grade.



|                                                                                                               |  |   |    
|-------------------------------------------------------------------------------------------------------------- |  | - | ---
|In millions                                                                                                    |  |  
|Collateral posted as of September 30, 2008(1)                                                                  |  | $ | 295
|Incremental collateral requirements resulting from a downgrade ofSCEs credit rating to below
investment grade |  |   | 282
|Total posted and potential collateral requirements(2)                                                          |  | $ | 577



|(1) | Collateral posted consisted of $52 million which were offset against net derivative liabilities in accordance with the implementation of FIN 39-1, and $243 million provided to
counterparties and other brokers (consisting of $10 million in cash reflected in Margin and collateral deposits on the consolidated balance sheets and $233 million in letters of credit).
|--- | ----------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------



|(2) | Total posted and potential collateral requirements may increase by an additional $183 million, based on SCEs forward position as of September 30, 2008, due to adverse
market price movements over the remaining life of the existing contracts using a 95% confidence level.
|--- | ------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------

SCEs incremental collateral
requirements are expected to be met from liquidity available from cash on hand of $1.26 billion at September 30, 2008, and available capacity of $628 million under SCEs $2.5 billion credit facility, discussed above.

REGULATORY MATTERS

Current Regulatory Developments

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

Impact of Regulatory Matters on Customer Rates

The following table summarizes SCEs system average rates and the portion related to CDWR which is not recognized as revenue by SCE, but included in the SCE system average rate, at various dates in 2007 and 2008:



|                  |  |                         |           |  |                         |          
|----------------- |  | ----------------------- | --------- |  | ----------------------- | ---------
|Date              |  | SCE System Average Rate |           |  | Portion Related to CDWR |          
|January 1, 2007   |  | 14.5                    | ¢ per-kWh |  | 3.1                     | ¢ per-kWh
|February 14, 2007 |  | 13.9                    | ¢ per-kWh |  | 3.0                     | ¢ per-kWh
|January 1, 2008   |  | 13.8                    | ¢ per-kWh |  | 2.9                     | ¢ per-kWh
|March 1, 2008     |  | 13.9                    | ¢ per-kWh |  | 2.9                     | ¢ per-kWh
|April 7, 2008     |  | 13.8                    | ¢ per-kWh |  | 2.9                     | ¢ per-kWh
|June 1, 2008      |  | 13.7                    | ¢ per-kWh |  | 2.8                     | ¢ per-kWh

The rate changes in 2008 resulted from the following:



| |  | March 2008: Increase to the FERC jurisdictional base transmission rates to include adopted CWIP incentives. See FERC Construction Work in Progress
Mechanism for further discussion.
|- |  | ---------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------



| |  | April 2008: Consolidation of the 2008 authorized CPUC jurisdictional revenue requirements. This decrease was primarily related to an increase in estimated 2008 kWh
sales which more than offset a small increase in 2008 CPUC authorized revenue requirements.
|- |  | ---------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------



| |  | June 2008: Decrease to the CDWR-related rates.
|- |  | ----------------------------------------------

2009 General Rate Case Proceeding

As discussed under the heading Regulatory MattersCurrent Regulatory Developments2009
General Rate Case Proceeding in the year-ended 2007 MD&A, SCE filed its GRC application on November 19, 2007. The



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application requested a 2009 base rate revenue requirement of $5.2 billion. Hearings and briefings were completed by August 2008. At the end of the
hearings, SCE agreed to several adjustments to its request and revised its forecasts to reflect lower customer growth and meter connections due to the economic downturn in southern California. SCEs revised request for 2009 was
$5.16 billion. In September 2008, SCE filed updated testimony which was limited to changes in the escalation rate forecast and known changes due to governmental action that increased SCEs request for 2009 to $5.21 billion. After
considering the effects of sales growth and other offsets, SCEs revised request would be a $739 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 16.54% and 6.33%, respectively. The revised request would result in 2010 and 2011 base rate revenue requirement
increases, net of sales growth, of $211 million and $256 million, respectively. As a result of SCEs post-hearing revised request, the DRAs recommended increase of approximately $19 million, which was submitted on
April 15, 2008, represented a difference of $676 million from SCEs post-hearing revised base rate revenue. The $676 million difference is mainly due to reductions proposed by DRA including: a reduction in capital-related costs
of approximately $186 million, which includes recommended changes in methods for calculating depreciation expense; a reduction in operating and maintenance expense of approximately $286 million; a reduction in administrative and general
expense of approximately $192 million mainly related to a reduction in pension and benefits, the elimination of results sharing as well as a reduction in long-term incentives and other executive compensation; and other miscellaneous proposed
reductions. Additionally, as a result of SCEs post-hearing revised request, TURNs recommendation sought to reduce SCEs post-hearing revised 2009 request by an additional $195 million over the DRA adjustments, primarily due to
a further reduction in depreciation expenses.

SCE cannot predict the revenue requirement the CPUC will ultimately authorize or precisely when a final
decision will be adopted, although a final decision is expected prior to year-end.

2008 Cost of Capital Proceeding

On December 21, 2007, the CPUC granted SCEs requested rate-making capital structure of 43% long-term debt, 9% preferred equity and 48% common equity for 2008.
The CPUC also authorized SCEs 2008 cost of long-term debt of 6.22%, cost of preferred equity of 6.01% and a return on common equity of 11.5%. The impact of this Phase I decision resulted in a $7 million decrease in SCEs 2008 annual
revenue requirement. On May 29, 2008, the CPUC issued a final decision on Phase II of the proceeding, replacing the former annual cost of capital application with a multi-year mechanism, which would not require a new cost of capital
application to be filed until April 2010. The decision also adopted a trigger mechanism which provides for an automatic adjustment to return on equity and embedded costs of long-term debt and preferred equity during the intervening years between the
cost of capital filings if certain thresholds are reached. At the end of September 2008, the trigger threshold was not reached for an automatic adjustment to the 2008 authorized return on equity and embedded costs of long-term debt and preferred
equity for 2009. SCEs next adjustment opportunity will occur at the end of September 2009, effective for 2010. As a result, depending on financial market conditions, SCE is exposed to financing costs that are above SCEs authorized rates
of 6.22% and 6.01% for new long-term debt and preferred equity financings, respectively, during 2009 which could impact earnings.

Energy Efficiency
Shareholder Risk/Reward Incentive Mechanism

As discussed under the heading Regulatory MattersEnergy Efficiency Shareholder Risk/Reward
Incentive Mechanism in the year-ended 2007 MD&A, the CPUC issued a decision in September 2007 that adopted an Energy Efficiency Risk/Reward Incentive mechanism. The mechanism allows for both incentives and economic penalties based on
SCEs performance toward meeting CPUC goals for energy efficiency.

Under this mechanism, the timing and amount of claims is linked to the completion
of CPUC reports including a verification report on all SCE energy savings estimates, customer benefits, and cost estimates. The first progress



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payment, for SCEs 2006-2007 energy efficiency portfolio performance, was to be filed in September 2008. SCE was not able to file its request for the
first progress payment as a result of a delay in the CPUCs verification report, which is now expected in January 2009.

In July 2008, the
Natural Resources Defense Council filed a request with the CPUC for an alternative dispute resolution process to address the first progress payment. While SCE committed to participation in the process, the alternate dispute resolution process has
not led to a timely result for the first progress payment.

As another alternate means to receive the first progress payment, SCE and the other California
investor-owned utilities filed a petition with the CPUC in August 2008. On November 4, 2008, the CPUC issued a proposed decision and an alternate proposed decision on the utilities petition.

The proposed decision denies the utilities petition and, if adopted, would result in the current process for earnings to continue without alteration. As a result,
SCEs first progress payment for 2006  2007 energy efficiency portfolio performance would be based on the CPUC verification report using updated cost effectiveness metrics. The CPUC verification report may result in further reductions to
SCEs projected saving and earnings amounts, beyond what was taken into account when calculating its first progress payment in the range of $41 million to $49 million.

The alternate proposed decision, if adopted, would approve SCEs first progress payment for SCEs 2006  2007 energy efficiency portfolio performances based on total earnings of $71 million, using
SCEs quarterly savings reports rather than the CPUC verification report. However, the holdback percentage would be increased from the currently approved 35% to 50%, resulting in a first progress payment of $35 million (rather than $46 million,
as requested in the petition) which would be recognized upon final approval of the alternate proposed decision. Future progress payments would be based on CPUC verification reports. If the CPUCs verification report is again delayed in 2009,
the CPUC may approve a second interim payment based upon SCEs saving reports, subject to another review of the progress payment holdback percentage.

SCE expects a final decision on the utilities petition in December 2008. Actual earnings may differ from SCEs previous projections and there is no assurance of earnings in any given year.

FERC Transmission Incentives

On November 16, 2007, the FERC
issued an order granting incentives on three of SCEs largest proposed transmission projects:



| |  | A 125 basis point ROE adder on SCEs future proposed base ROE (ROE Adder) for DPV2, which is a high voltage (500 kV) transmission line from the
Valley substation to the Devers substation near Palm Springs, California to a new substation near Palo Verde, west of Phoenix, Arizona;
|- |  | -----------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------



| |  | A 125 basis point ROE Adder for the Tehachapi Transmission Project, which is an eleven segment project consisting of newly-constructed and upgraded transmission
lines and associated substations to interconnect renewable generation projects near the Tehachapi and Big Creek area; and
|- |  | ------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------



| |  | A 75 basis point ROE Adder for the Rancho Vista Substation Project, which is a new 500 kV substation in the City of Rancho Cucamonga.
|- |  | -------------------------------------------------------------------------------------------------------------------------------------

The order also grants a higher return on equity on SCEs entire transmission rate base in SCEs next FERC transmission rate case for SCEs
participation in the CAISO. In September 2008, the FERC accepted SCEs revisions to its Transmission Owner Tariff, with a requested effective date of March 1, 2009 subject to refund and settlement procedures. In addition, the order permits
SCE to include in rate base 100% of prudently-incurred capital expenditures during construction, also known as CWIP, 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.

In June 2008, the FERC rejected petitions filed by certain parties, including the
CPUC, to address the CAISO higher return and the ROE project adders. In August 2008, the CPUC filed an appeal of the FERC incentives order at the DC Circuit Court of Appeals.



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FERC Construction Work in Progress Mechanism

As discussed under the heading Regulatory MattersCurrent Regulatory DevelopmentsFERC Construction Work in Progress Mechanism in the year-ended 2007 MD&A and FERC Transmission
Incentives above, on December 21, 2007, SCE filed a revision to its Transmission Owner Tariff to collect 100% of CWIP in rate base for its Tehachapi, DPV2, and Rancho Vista projects. In the CWIP filing, SCE proposed a rate adjustment
($45 million or a 14.4% increase) to SCEs currently authorized base transmission revenue requirement to be made effective on March 1, 2008 and later adjusted for amounts actually spent in 2008 through a new balancing account
mechanism. The rate adjustment represents actual expenditures from September 1, 2005 through November 30, 2007, projected expenditures from December 1, 2007 through December 31, 2008, and a ROE (which includes the ROE adders
approved for Tehachapi, DPV2 and Rancho Vista). The rate adjustment is based on a projection that SCE will spend a total of approximately $244 million, $27 million, and $181 million for Tehachapi, DPV2, and Rancho Vista, respectively,
from September 1, 2005 through the end of 2008. The 2008 DPV2 expenditure forecast is limited to projected consulting and legal costs associated with SCEs continued efforts to obtain regulatory approvals necessary to construct the DPV2
Project. On February 29, 2008, the CWIP filing was approved and SCE implemented the CWIP rate on March 1, 2008, subject to refund on the limited issue of whether SCEs proposed ROEs are reasonable. On March 28, 2008, the CPUC
filed a petition for rehearing with the FERC on the FERCs acceptance of SCEs proposed ROE for CWIP. Briefs addressing the appropriate ROE were filed by SCE and intervenors in May 2008. In addition, in the order, SCE was directed by FERC
to make a compliance filing to provide greater detail on the costs reflected in CWIP rates for 2008. SCE made the compliance filing on March 31, 2008. On April 21, 2008, the CPUC filed a protest of the compliance filing at FERC and
requested an evidentiary hearing to be set to further review the costs. SCE filed a response to the CPUCs protest on May 6, 2008 arguing that the FERC should deny the CPUCs request for a further hearing. SCE cannot predict the
outcome of the matters in this proceeding.

SCE filed its 2009 update to its CWIP rate adjustment on October 31, 2008. SCE proposed a reduction to its
CWIP revenue requirement from $45 million to $39 million to be effective on January 1, 2009.

Energy Resource Recovery Account
Proceedings

As discussed under the heading Regulatory MattersCurrent Regulatory DevelopmentsEnergy Resource Recovery Account
Proceedings in the year-ended 2007 MD&A, the ERRA is the balancing account mechanism to track and recover SCEs fuel and procurement-related costs. At September 30, 2008, the ERRA was under-collected by $181 million, which
was 3.4% of SCEs prior years generation revenue. The CPUC has established a trigger mechanism, whereby, SCE must file an application in which it can request an emergency rate adjustment if the ERRA under-collection exceeds 5%
of SCEs prior year generation revenue (base generation and procurement costs). If SCE files an ERRA trigger application in the fourth quarter of 2008, it is anticipated that the associated rate increase would be implemented during the first
quarter of 2009.

2009 ERRA Forecast

In September
2008, SCE filed its 2009 ERRA forecast application estimating its 2009 ERRA revenue requirement to be $4.69 billion, an increase of $984 million over SCEs adopted 2008 ERRA revenue requirement. However, for rate-making purposes, SCE
proposed to only increase rates by $342 million to remove the 2007 ERRA over-collected balance reflected as a reduction to current rates. Based on lower forecasts of natural gas prices in 2009, among other things, SCE expects to revise its 2009 ERRA
forecast downward.

To the extent the under-collection exceeds 5% of SCEs prior years generation revenue, as discussed in the year-ended 2007
MD&A under the heading, Regulatory MattersCurrent Regulatory DevelopmentsEnergy Resource Recovery Account Proceedings, SCE expects to use the ERRA balancing account trigger mechanism to recover incremental actual
under-collections, if any, that may occur.



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Peaker Plant Generation Projects

As discussed under the heading Regulatory MattersCurrent Regulatory DevelopmentsPeaker Plant Generation Projects in the year-ended 2007 MD&A, in response to a CPUC order, SCE constructed
four of the five combustion turbine peaker plants, four of which were placed online in August 2007 to help meet peak customer demands and other system requirements. SCE anticipates submitting updated testimony in connection with its December 2007
cost recovery application to revise the total recorded costs as of late 2008, for the first four peaker plants, to approximately $263 million with additional projected costs for those peaker plants of approximately $1 million. In its cost recovery
application, SCE proposed to continue tracking the capital costs of the fifth peaker plant according to the interim cost tracking mechanism that was previously approved by the CPUC for all five peaker projects while they were in construction.
Additionally, SCE proposed to file a separate cost recovery application for the fifth peaker after it is installed or its final disposition is otherwise determined (see below for further discussion on the status of the fifth peaker plant). As of
September 30, 2008, SCE has incurred capital costs of approximately $39 million for the fifth peaker. Several parties have filed protests or other filings in response to SCEs cost recovery application. SCE expects to fully recover
its costs from these projects, but cannot predict the outcome of regulatory proceedings. SCE expects a CPUC decision on its cost recovery application in 2009.

SCE has continued to pursue the construction of the fifth peaker plant. The required development permit was denied by the City of Oxnard in July 2007 and SCE appealed the denial to the California Coastal Commission. The Commission heard
SCEs appeal on August 6, 2008, but did not reach a final decision. The SCE expects the matter to be heard again by April 2009.

Procurement
of Renewable Resources

As discussed under the heading Regulatory MattersCurrent Regulatory DevelopmentsProcurement of Renewable
Resources in the year-ended 2007 MD&A, 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.

SCE filed its latest compliance report in August 2008. Through the use of flexible
compliance rules, SCE demonstrated full compliance for the procurement year 2007 and forecasted full compliance for the procurement years 2008 to 2020. It is unlikely that SCE will have 20% of its annual electricity sales procured from renewable
resources by 2010. However, SCE may still meet the 20% target by utilizing the flexible compliance rules. SCE continues to engage in several renewable procurement activities including formal solicitations approved by the CPUC, bilateral negotiations
with individual projects and other initiatives.

Under current CPUC decisions, potential penalties for SCEs inability to achieve its renewable
procurement objectives for any year will 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. SCE cannot predict whether it will be assessed penalties.

FERC Refund Proceedings

As discussed under the heading Regulatory MattersCurrent Regulatory DevelopmentsFERC Refund Proceedings in the year-ended 2007 MD&A, 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 certain refunds realized by SCE, net of litigation costs, and 10% will be retained by SCE as a shareholder incentive.

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 the second quarter of 2008 and in October 2008, SCE received distributions of approximately $25 million and



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$5 million, respectively, on its allowed bankruptcy claim. SCE has been advised that the Enron estate expects to conclude its liquidation in November of
this year and therefore the amount or timing of additional distributions, if any, is uncertain.

In May 2008, SCE and a number of other parties entered
into a settlement of the FERC refund proceeding issues with NEGT Energy Trading-Power, L.P. (NEGT) and a related party, both of which are debtors in a Chapter 11 proceeding pending in the Maryland bankruptcy court. Under the terms of the settlement,
NEGT will provide refunds valued at $66 million, a portion of which will be paid in the form of an allowed, unsecured claim in the Chapter 11 bankruptcy proceeding. SCEs share of this amount is expected to be approximately $19 million.
NEGT will also assign to SCE and the other parties to the settlement a corporate guarantee and surety bond that, subject to collection, will provide an additional $14 million. SCEs share of the $14 million is yet to be determined. The
settlement was approved by the Maryland bankruptcy court on July 24, 2008 but remains subject to approval by the FERC.

Investigation Regarding
Performance Incentives Rewards

SCE was eligible under the CPUC-approved PBR mechanism to earn rewards or incur penalties based on its performance in
comparison to CPUC-approved standards of customer satisfaction, employee safety reporting, and system reliability. SCE conducted investigations into its performance under the PBR mechanism and reported to the CPUC certain findings of misconduct and
misreporting related to the first two components of the PBR program. Following SCEs reporting, the CPUC opened its own investigation of SCEs activities relative to the PBR mechanism.

CPUC Decision

On September 18, 2008, the CPUC adopted a
decision in the first phase of its investigation into SCEs incentives claimed under the CPUC-approved PBR mechanism that allowed SCE to earn rewards or incur penalties for the period 1997  2003 based on its performance in comparison to
CPUC-approved standards of customer satisfaction and employee safety reporting. The adopted decision required SCE to refund $28 million and $20 million related to customer satisfaction and employee safety reporting incentives,
respectively; and further required SCE to forego claimed incentives of $20 million and $15 million related to customer satisfaction and employee safety reporting, respectively. The decision also required SCE to refund $33 million for
employee bonuses and imposed a statutory penalty of $30 million. During the third quarter, SCE recorded a charge of $49 million, after-tax, reflected primarily in Other nonoperating deductions in the consolidated statements of
income related to this decision.

System Reliability

In light of the problems uncovered with the components of the PBR mechanism discussed above, SCE conducted an investigation into the third PBR standard, system reliability, for the years 1997  2003. SCE received $8 million
in reliability incentive awards for the period 1997  2000 and had 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, SCE determined that 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. System reliability incentives will be addressed in the second phase of the CPUCs investigation. SCE served its opening testimony in the second phase in September 2007. In that testimony, SCE presented evidence
that its PBR system reliability results were valid. The schedule for the second phase of the investigation has been deferred until November 21, 2008. SCE cannot predict the outcome of the second phase but does not expect a material financial
statement impact.



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Market Redesign and Technology Upgrade

As discussed under the heading Regulatory MattersMarket Redesign and Technology Upgrade in the year ended 2007 MD&A, 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 CAISO has announced an implementation date of February 1, 2009, and expects to file a readiness application with the FERC in December 2008.

OTHER DEVELOPMENTS

Edison SmartConnect

SCEs Edison SmartConnect project involves installing state-of-the-art smart meters in approximately 5.3 million households and small businesses through its
service territory. The development of this advanced metering infrastructure is 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 Edison SmartConnect technologies, select the deployment vendor and finalize the Edison SmartConnect business case for full deployment, which was conducted during 2007; and the final deployment phase (Phase III), to deploy meters to all residential and small business customers under
200 kilowatts over a five-year period. SCE began deployment activities in 2008, expects to begin deployment of meters in 2009, and anticipates completion of the deployment in 2012. The total cost for this project, including Phase II
pre-deployment, is estimated to be $1.7 billion of which $1.25 billion is estimated to be capitalized and included in utility rate base. The remaining book value for SCEs existing meters at September 30, 2008 is
$396 million. SCE expects to recover the remaining book value of the existing meters over their remaining lives through its 2009 GRC application.

On July 26, 2007, the CPUC approved $45 million for Phase II of this project. The Phase II
work was completed in December 2007. SCE filed its Phase III application on July 31, 2007, requesting CPUC authorization to deploy Edison SmartConnect. In March 2008, SCE
reached a full settlement of the Phase III issues with the DRA, and requested CPUC approval of the settlement. In September 2008, the CPUC approved the settlement, authorizing SCE to recover $1.63 billion in ratepayer funding for the Phase III
deployment of Edison SmartConnect.

Environmental Matters

SCE is subject to numerous federal and state 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 existing environmental regulatory requirements.

SCE power plants, in particular its 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. The developments in certain of these laws and regulations are discussed in more detail below. These developments will continue to be monitored to assess what implications, if any, they will have on the operation of domestic power plants
owned or operated by SCE, or the impact on SCEs consolidated results of operations or financial position.



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For a discussion of SCEs environmental matters, refer to Other DevelopmentsEnvironmental Matters
in the year-ended 2007 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

Litigation Developments

On February 28, 2008, the Native Village of Kivalina and the City of Kivalina, located off the coast of Alaska, filed a complaint in federal court in California
against 24 defendants, including SCEs corporate parent, who directly or through subsidiaries engage in electric generating, oil and gas, or coal mining lines of business. The complaint contends that the alleged global warming impacts of the
GHG emissions associated with the defendants business activities are destroying the plaintiffs village through the melting of Arctic ice that had previously protected the village from winter storms. The plaintiffs further allege that the
village will soon need to be abandoned or relocated at a cost of between $95 million and $400 million. SCE cannot predict the outcome of this lawsuit.

State Specific Legislative Initiatives

SCE is evaluating the CARBs reporting regulations adopted pursuant to AB 32 and the draft
scoping plan described below to assess the total cost of compliance.

AB 32 requires the CARB to approve a scoping plan for achieving the maximum
technologically feasible and cost-effective reductions in GHG emissions on or before January 1, 2009. On June 26, 2008, the CARB released a draft scoping plan containing preliminary recommendations for measures that California will use to
reduce GHG. The preliminary recommendations include: a California cap-and-trade program linked to the Western Climate Initiative covering electricity, transportation, residential/commercial, and industrial sources by 2020; California light-duty
vehicle GHG standards; increased energy efficiency, including increasing combined heat and power use; a 33% by 2020 Renewable Portfolio Standard for both investor-owned and publicly owned utilities; a low-carbon fuel standard; measures to reduce
high global warming potential gases; sustainable forest measures; water sector measures; vehicle efficiency measures, goods movement measures; heavy/medium duty vehicle measures; the Million Solar Roofs program; local government actions and regional
targets; supporting implementation of a high-speed rail system; recycling and waste measures; agriculture measures; and energy efficiency and co-benefits audits for large industrial sources. Other measures under evaluation for inclusion in the
proposed scoping plan include, among other things, more aggressive energy efficiency programs and a coal emission reduction standard. The draft scoping plan was subject to public comment. The CARB issued a revised proposed scoping plan for public
comment on October 15, 2008, which is largely unchanged from the original draft scoping plan. However, the revised draft scoping plan does not include the more aggressive energy efficiency or coal emission reduction standard measures that were
under evaluation for inclusion in the proposed draft scoping plan. The CARB will consider adopting the proposed scoping plan by the end of 2008.

On
September 12, 2008, the CPUC and CEC issued a proposed opinion on GHG regulatory strategies providing additional recommendations to the CARB on measures and strategies for reducing GHG emissions in the electricity and natural gas sectors. The
proposed opinions recommendations address mandatory emission reduction measures including energy efficiency, renewable resources, and expansion of combined heat and power. The recommendations also include design suggestions for a multi-sector,
statewide, cap-and-trade program. The proposed opinion was adopted by the CPUC and CEC on October 16, 2008.

AB 32 also required the CARB to adopt
regulations requiring the reporting and verification of statewide GHG emissions on or before January 1, 2008. On December 6, 2007 the CARB approved regulations for the mandatory reporting of GHG emissions, including the reporting of GHG
emissions for the electricity sector. The CARB directed its staff to make some technical modifications to the proposed regulations, which had been issued in October 2007. The CARB staff issued revised regulations for public comment on May 15,
2008. Further revised regulations with changes based on public comments were issued by the CARB staff for public comment on June 30, 2008.



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As described in the section Environmental Matters affecting SCE included in the Business section of Part I,
Item 1 of SCEs Annual Report on Form 10-K, the CPUC adopted a GHG emission performance standard, effective January 2007. In January 2008, SCE filed a petition with the CPUC seeking clarification that the emission performance standard would not
apply to capital expenditures required by existing agreements among the owners at Four Corners. The CPUC issued a proposed decision finding that the emission performance standard was not intended to apply to capital expenditures at Four Corners
requested by SCE in its General Rate Case for the period 2007  2011. On October 23, 2008, the Assigned Commissioner and Administrative Law Judge issued a ruling withdrawing the proposed decision and seeking additional comment on whether the
finding in the proposed decision should be changed and whether SCE should be allowed to recover such capital expenditures. SCE estimates that its share of capital expenditures approved by the owners at Four Corners since the GHG emission performance
standard decision was issued in January 2007 is approximately $43 million, of which approximately $8 million had been expended through September 30, 2008. The ruling also directs SCE to explain why certain information was not included in its
petition and why the failure to include such information should not be considered misleading in violation of CPUC rules. SCE cannot predict the outcome of this proceeding or estimate the amount, if any, of penalties or disallowances that may be
imposed.

Water Quality Regulation

Clean
Water ActCooling Water Intake Structures

On March 21, 2008 the California State Water Resources Control Board released its draft scoping
document and preliminary draft Statewide Water Quality Control Policy on the Use of Coastal and Estuarine Waters for Power Plant Cooling. This state policy is being developed in advance of the issuance of a final rule from the US EPA on standards
for cooling water intake structures at existing large power plants. As anticipated, the Scoping Document establishes closed cycle wet cooling as the best technology available for retrofitting existing once-through cooled plants like San Onofre.
Additionally, the target levels for compliance with the state policy correspond to the high end of the ranges originally proposed in the US EPAs rule. Nuclear-fueled power plants, including San Onofre, would have until January 1, 2021 to
comply with the policy. The policy development schedule included in the scoping document scheduled workshops and the submission of public comments in May 2008 and a public hearing in September 2008. The State Board vote has been informally delayed
and is currently anticipated to occur in 2009. SCE continues to work with key government policy makers. This policy may significantly impact both operations at San Onofre and SCEs ability to procure timely supplies of generating capacity from
fossil-fueled plants that use ocean water in once-through cooling systems.

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 consolidated 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, 2008, SCEs recorded estimated minimum liability to remediate its 24 identified sites was
$47 million, of which $14 million was related to San Onofre. This remediation liability is undiscounted. 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
$167 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 30 immaterial sites whose total liability ranges from $3 million (the recorded minimum liability) to $9 million.

The CPUC allows SCE to recover environmental remediation costs at certain sites, representing $32 million of its recorded liability, through an incentive mechanism (SCE may request to include additional sites).
Under this mechanism, SCE will recover 90% of cleanup costs through customer rates; shareholders fund the remaining 10%, with the opportunity to recover these costs from insurance carriers and other third parties. SCE has successfully settled
insurance claims with all responsible carriers. SCE expects to recover costs incurred at its remaining sites through customer rates. SCE has recorded a regulatory asset of $42 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, 2008 were $32 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 consolidated 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

Tax Positions being Addressed as Part of Active Examinations, Administrative Appeals and the Global Settlement

Edison International is challenging certain IRS deficiency adjustments for tax years 1994  1999 with the Administrative Appeals branch of the IRS and Edison
International is currently under active IRS examination for tax years 2000  2006. During the third quarter of 2008, the IRS commenced an examination of tax years 2003  2006. In addition, the statute of limitations remains open
for tax years 1986  1993, which has allowed Edison International to file certain affirmative claims related to these tax years. Tax years 1986  2002 are included in the scope of Global Settlement and tax years 2003  2006 are
excluded.

Most of these tax positions relate to timing differences and, therefore, any amounts exclusive of any penalties would be paid if Edison
Internationals position is not sustained would be deductible on future tax returns filed by Edison International. In addition, Edison International has filed affirmative claims with respect to certain tax years 1986 through 2005 with the IRS
and state tax authorities. Any benefits associated with these affirmative claims would be recorded in accordance with FIN 48 which provides that recognition would occur at the earlier



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of when SCE would make an assessment that the affirmative claim position has a more likely than not probability of being sustained or when a settlement of
the affirmative claim is consummated with the tax authority. Certain of these affirmative claims have been recognized as part of the implementation of FIN 48.

Currently, Edison International is under administrative appeals with the California Franchise Tax Board for tax years 1997  2002 and under examination for tax years 2003  2004. Edison International remains subject to examination
by the California Franchise Tax Board for tax years 2005 and forward. Edison International is also subject to examination by other state tax authorities, subject to varying statute of limitations.

Edison International filed amended California Franchise tax returns for tax years 1997  2002 to mitigate the possible imposition of new California non-economic
substance 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 below. Edison International filed these amended returns under protest retaining its appeal rights.

As previously disclosed,
Edison International is currently engaged in settlement negotiations with the IRS to reach a Global Settlement which, if consummated, would resolve outstanding tax disputes for all Edison International subsidiaries, including SCE, for the years 1986
through 2002, including certain affirmative claims for unrecognized tax benefits. See Southern California Edison Company Notes to Consolidated Financial StatementsNote 3. Income Taxes. These negotiations have progressed to the
point where Edison International and the IRS have reached nonbinding, preliminary understandings on the material principles for resolution of all issues included in the Global Settlement. Final resolution of such disputes, as part of the Global
Settlement, is subject to reaching definitive agreements on final terms and calculations, mutually satisfactory documentation, and review of all or a portion of the Global Settlement by the Staff of the Joint Committee on Taxation, a committee of
the United States Congress (the Joint Committee). While not assured, Edison International believes that the Global Settlement will be submitted or substantially ready to be submitted to the Joint Committee during the fourth quarter of
2008.

There can be no assurance, however, about the timing of final settlements with the IRS or that such final settlements will be ultimately
consummated. Moreover, review by the Joint Committee could result in adjustments to the Global Settlement reached between Edison International and the IRS. The IRS and Edison International may not reach final agreements that implement the
preliminary understandings, or they may reach final agreements but conditions to consummating them may not be satisfied.

Balancing Account
Over-Collections

In response to an affirmative claim filed by Edison International related to balancing account over-collections, the IRS issued a
Notice of Proposed Adjustment in July 2007. This affirmative claim was addressed by the IRS as part of the ongoing IRS examinations and administrative appeals processes. The tax years to which adjustments are made pursuant to this Notice of Proposed
Adjustment are included in the scope of the Global Settlement. The cash and earnings impacts of this position are dependent on the ultimate settlement of all open tax issues, including this issue, in these tax years. Edison International expects
that resolution of this issue could potentially increase earnings and cash flows within the range of $70 million to $80 million and $300 million to $350 million, respectively.

Contingent Liability Company

The IRS has asserted deficiencies with respect to a transaction entered into by a
former SCE subsidiary which may be considered substantially similar to a Listed Transaction described by the IRS as a contingent liability company for tax years 1997 and 1998. This issue is included in the Global Settlement and is being considered
by the Administrative Appeals branch of the IRS where Edison International has been defending its income tax return position with respect to this transaction.



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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 market 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 market, Midway-Sunset is potentially liable for refunds to purchasers in these markets.

On
December 20, 2007, Midway-Sunset entered into a settlement agreement in the amount of $86 million (including interest) with SCE, PG&E, SDG&E and certain California state parties to resolve Midway-Sunsets liability in the FERC
refund proceedings. Midway-Sunset concurrently entered into a separate agreement with SCE and PG&E that provides for pro-rata reimbursement to Midway-Sunset by the two utilities of the portions of the agreed to refunds that are attributable to
sales made by Midway-Sunset for the benefit of the utilities (Midway-Sunset did not retain any proceeds from power sold into the PX market 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). The settlement, which had been approved previously by the CPUC, was approved by the FERC on April 2, 2008.

During the period in which Midway-Sunsets generation was sold into the PX market, amounts SCE received from Midway-Sunset for its pro-rata share of such sales were
credited to SCEs customers against power purchase expenses through the ratemaking mechanism in place at that time. During the second quarter of 2008, SCE reimbursed Midway-Sunset for its pro-rata share of the Midway-Sunset liability in the
amount of approximately $43 million. In addition, SCE, as party to the Midway-Sunset settlement agreement, received a $20 million generator refund. The amount reimbursed to and received from Midway-Sunset (net amount of $23 million)
were charged/refunded to ratepayers through regulatory mechanisms. As a result, the transactions associated with the Midway-Sunset settlement agreement did not impact earnings.

Nuclear Insurance

Federal law limits public liability claims from a nuclear incident to the amount of available
financial protection, which is currently approximately $12.5 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. Beginning October 29, 2008, the maximum deferred premium for each nuclear incident is approximately $118 million per reactor, but not more than approximately $18 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 at least once every five years beginning August 20, 2003. The most recent inflation adjustment
took effect on October 29, 2008. Based on its ownership interests, SCE could be required to pay a maximum of approximately $235 million per nuclear incident. However, it would have to pay no more than approximately $35 million per
incident in any one year. 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 law
contemplates that additional funds may be appropriated by Congress. This could include an additional assessment on all licensed reactor operators as a measure for raising further revenue.

Property damage insurance covers losses up to $500 million, including decontamination costs, at San Onofre and Palo Verde. Decontamination liability and
property damage coverage exceeding the primary $500 million also has been purchased in amounts greater than federal requirements. Additional insurance covers part of



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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 approximately $45 million per year.
Insurance premiums are charged to operating expense.

Nuclear Decommissioning Trusts

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

Trust investments (at fair value) include:



|                                |  |               |  |                    |       |                  |   |      
|------------------------------- |  | ------------- |  | ------------------ | ----- | ---------------- | - | -----
|In millions                     |  | MaturityDates |  | September 30, 2008 |       | December 31,2007
|Municipal bonds                 |  | 2008  2044   |  | $                  | 564   |                  | $ | 561  
|Stocks                          |  |              |  |                    | 1,672 |                  |   | 1,968
|United States government issues |  | 2008  2049   |  |                    | 318   |                  |   | 552  
|Corporate bonds                 |  | 2008  2047   |  |                    | 267   |                  |   | 241  
|Short-term                      |  | 2008  2009   |  |                    | 34    |                  |   | 56   
|Total                           |  |               |  | $                  | 2,855 |                  | $ | 3,378

Note: Maturity dates as of September 30, 2008.

The following table sets forth a summary of changes in the fair value of the trust for the three- and nine-month periods ended September 30, 2008:



|                                |  |                                      |       |   |                                     |   |       |  
|------------------------------- |  | ------------------------------------ | ----- | - | ----------------------------------- | - | ----- | -
|In millions                     |  | Three Months EndedSeptember 30, 2008 |       |   | Nine Months EndedSeptember 30,
2008 |  
|Balance at beginning of period  |  | $                                    | 3,152 |   |                                     | $ | 3,378 |  
|Realized losses  net           |  |                                      | (7    | ) |                                     |   | (13   | )
|Unrealized losses  net         |  |                                      | (240  | ) |                                     |   | (452  | )
|Other-than-temporary impairment |  |                                      | (49   | ) |                                     |   | (121  | )
|Earnings and other              |  |                                      | (1    | ) |                                     |   | 63    |  
|Balance at September 30, 2008   |  | $                                    | 2,855 |   |                                     | $ | 2,855 |  

The decrease in the trust investments was primarily due to net unrealized losses and other-than-temporary
impairment resulting from a volatile stock market environment.

Nuclear decommissioning costs are recovered in utility rates. These costs are expected to
be funded from independent decommissioning trusts, which effective January 2007, receive contributions of approximately $46 million per year. Contributions to the decommissioning trusts are reviewed every three years by the CPUC. The next
filing is in April 2009 for contribution changes in 2010. These contributions are determined based on an analysis of the current value of trusts assets and long-term forecasts of cost escalation, the estimate and timing of decommissioning costs, and
after-tax return on trust investments. Favorable or unfavorable investment performance in a period will not change the amount of contributions for that period. However, trust performance for the three years leading up to a CPUC review proceeding
will provide input into future contributions. The significant decrease recently experienced in the nuclear decommissioning trust assets, are expected to impact the CPUC established contributions for 2010. The CPUC has set certain restrictions
related to the investments of these trusts. If additional funds are needed for decommissioning, it is probable that the additional funds will be recoverable through customer rates.



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Palo Verde Nuclear Generating Station Inspections

As discussed under the heading Other DevelopmentsPalo Verde Nuclear Generating Station Inspection in the year-ended 2007 MD&A, the NRC held three special inspections of Palo Verde, between March
2005 and February 2007. The combination of the results of the first and third special inspections caused the NRC to undertake an additional oversight inspection of Palo Verde. This additional inspection, known as a supplemental inspection, was
completed in December 2007. In addition, Palo Verde was required to take additional corrective actions based on the outcome of completed surveys of its plant personnel and self-assessments of its programs and procedures. The NRC and APS defined and
agreed to inspection and survey corrective actions that the NRC embodied in a Confirmatory Action Letter, which was issued in February 2008. APS is presently on track to complete the corrective actions required to close the Confirmatory Action
Letter by mid-2009. Palo Verde operation and maintenance costs (including overhead) increased in 2007 by approximately $7 million from 2006. SCE estimates that operation and maintenance costs will increase by approximately $23 million (in
2007 dollars) over the two year period 2008  2009, from 2007 recorded costs including overhead costs. SCE is unable to estimate how long SCE will continue to incur these costs. In the 2009 GRC, SCE requested recovery of, and two-way
balancing account treatment for, Palo Verde operation and maintenance expenses including costs associated with these corrective actions. If approved, this would provide for recovery of these costs over the three-year GRC cycle (see Regulatory
MattersCurrent Regulatory Developments2009 General Rate Case Proceeding).

Priority Reserve Legal Challenges

In July 2008, the Los Angeles Superior Court found that actions taken by the SCAQMD in promulgating rules that had made available a Priority Reserve of
emissions credits for new power generation projects did not satisfy California environmental laws. In November 2008, the Superior Court issued a writ of mandate enjoining SCAQMD from issuing Priority Reserve emission credits to any facility,
including new power projects, until a satisfactory environmental analysis is completed. The writ also ordered the SCAQMD to refrain from taking any action relating to power plant projects approved after August 2007 pursuant to the Priority Reserve
rules until the SCAQMD completes a satisfactory environmental analysis. Separately, in August 2008, substantially the same plaintiffs sued the SCAQMD in federal court alleging that the emission credits contained in SCAQMDs New Source Review
offset accounts (which include the Priority Reserve) are invalid and seeking to enjoin SCAQMD from transferring them. The SCAQMD has filed a motion to dismiss the federal suit. SCE has joined a coalition of other interested parties that have
intervened in the federal litigation between the SCAQMD and environmental groups.

SCE is in the process of evaluating the impact of the two lawsuits on
certain power-purchase agreements that resulted from its new generation RFO and the potential implications for its long-term resource adequacy requirements.

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.

Interest Rate
Risk

SCE is exposed to changes in interest rates primarily as a result of its borrowing and investing activities used for liquidity purposes, to fund
business operations and to finance capital expenditures. Variances in actual financing costs compared to authorized financing costs either positively or negatively impact earnings. See Regulatory



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MattersCurrent Regulatory Developments2008 Cost of Capital Proceeding for further discussion on SCEs recoverability of financing
costs.

At September 30, 2008, SCE did not believe that its short-term debt was subject to interest rate risk, due to the fair market value being
approximately equal to the carrying value. At September 30, 2008, the fair market value of SCEs long-term debt (including long-term debt due within one year) was $5.57 billion, compared to a carrying value of $5.86 billion.

In July 2007, SCE entered into interest rate-locks to mitigate interest rate risk associated with future financings. Due to declining interest rates in
late 2007, at December 31, 2007, these interest rate locks had unrealized losses of $33 million. In January and February 2008, SCE settled these interest rate-locks resulting in realized losses of $33 million. A related regulatory
asset was recorded in this amount and SCE will amortize and recover this amount as interest expense associated with its Series 2008A and 2008B financings issued in January and August 2008.

Commodity Price Risk

As discussed in the year-ended 2007 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 SCEs 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, forward
physical contracts, and transmission congestion rights (firm transmission rights and CRRs). 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.

In September 2007,
the ISO allocated CRRs for the period March 2008 through December 2017 to SCE which will entitle SCE to receive (or pay) the value of transmission congestion between specific locations. These rights will act as an economic hedge against transmission
congestion costs in the MRTU environment which was expected to be operational March 31, 2008, but was delayed. The CRRs meet the definition of a derivative under SFAS No. 133. In accordance with SFAS No. 157, SCE recognized the CRRs
at a zero fair value due to liquidity reserves. Liquidity reserves against CRRs fair values were provided since there were no quoted long-term market prices for the CRRs allocated to SCE. Although an auction was held in December 2007, the auction
results did not provide sufficient evidence of long-term market prices.

During the first quarter of 2008, the ISO held an auction for firm transmission
rights. SCE participated in the ISO auction and paid $62 million to secure firm transmission rights for the period April 2008 through March 2009. The firm transmission rights will be replaced with CRRs in the MRTU environment. SCE recognized
the firm transmission rights at fair value. SCE anticipates amounts paid for firm transmission rights that will no longer be valid in the MRTU environment will be refunded to SCE and has recognized this amount as a receivable from the ISO.

Any future fair value changes, given a MRTU market, 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.



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

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



|                                                   |  |                    |     |             |                   |     |        |  |             |    |  |   |    |  
|-------------------------------------------------- |  | ------------------ | --- | ----------- | ----------------- | --- | ------ |  | ----------- | -- |  | - | -- | -
|                                                   |  | September 30, 2008 |     |             | December 31, 2007 |    
|In millions                                        |  | Assets             |     | Liabilities |                   |     | Assets |  | Liabilities |   
|Energy options                                     |  | $                  | 15  |             | $                 | 39  |        |  | $           | 6  |  | $ | 49 |  
|Firm transmission rights                           |  |                    | 34  |             |                   | 2   |        |  |             | 22 |  |   |   |  
|Forward physicals (power) and tolling arrangements |  |                    | 4   |             |                   | 7   |        |  |             | 7  |  |   | 8  |  
|Gas options, swaps and forward arrangements        |  |                    | 85  |             |                   | 166 |        |  |             | 46 |  |   | 22 |  
|Netting and collateral                             |  |                    |    |             |                   | (52 | )      |  |             |   |  |   | (2 | )
|Total                                              |  | $                  | 138 |             | $                 | 162 |        |  | $           | 81 |  | $ | 77 |  

SCE implemented SFAS No. 157 during the first quarter of 2008. SCEs assets and liabilities carried at
fair value primarily consist of derivatives, nuclear decommissioning trust investment and money market funds. Derivative contracts primarily relate to power and gas and include contracts for forward physical sales and purchases, options and forward
price swaps which settle only on a financial basis (including futures contracts). Derivative contracts can be exchange traded or over-the-counter traded. 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. Under SFAS No. 157, when actual
market prices, or relevant observable inputs are not available it is appropriate to use unobservable inputs which reflect management assumptions, including extrapolating limited short-term observable data and developing correlations between liquid
and non-liquid trading hubs.

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

Level 2 primarily consists of natural gas swap and natural gas physical trade derivatives for which SCE obtains the applicable Henry Hub and basis forward market prices from the New York Mercantile Exchange.

Level 3 includes the majority of SCEs derivatives, including over-the-counter options, bilateral contracts, and capacity and QF contracts. The fair value of
these derivatives is determined using uncorroborated non-binding broker quotes (from one or several brokers) and models which may require SCE to extrapolate short-term observable inputs in order to calculate fair value. Fair values that are obtained
from several brokers are compared against each other for reasonableness. Level 3 also includes derivatives that trade infrequently (such as firm transmission rights and CRRs in the California market and over-the-counter derivatives at illiquid
locations), derivatives with counterparties that have significant non-performance risks and long-term power agreements. For illiquid firm transmission rights and CRRs, SCE reviews objective criteria related to system congestion on a quarterly basis
and other underlying drivers and adjusts fair value when SCE concludes a change in objective criteria would result in a new valuation that better reflects the fair value. Changes in fair values are based on



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hypothetical sale of illiquid positions. For illiquid long-term power agreements, fair value is based upon a discounting of future electricity prices derived
from a proprietary model using the risk free discount rate for a similar duration contract, adjusted for credit risk and market liquidity. Changes in fair value are based on changes to forward market prices, including forecasted prices for illiquid
forward periods.

Firm transmission rights, capacity and QF contracts are in inactive markets. CRRs do not yet have a market. In circumstances where SCE
cannot verify fair value with observable market transactions, it is possible that a different valuation model could produce a materially different estimate of fair value. As markets continue to develop and more pricing information becomes available,
SCE continues to assess valuation methodologies used to determine fair value.

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

SCEs investment policies place
limitations on the types and investment grade ratings of the securities that may be held by the nuclear decommissioning trust fund. These policies restrict the trust fund from holding alternative investments and limit the trust funds exposures to
investments in highly illiquid markets. With respect to equity securities, the trustee obtains prices from pricing services, whose prices are obtained from direct feeds from market exchanges, which SCE is able to independently corroborate. Regarding
fixed income securities, the trustee receives multiple prices from pricing services, which enable cross-provider validations by the trustee in addition to unusual daily movement checks. A primary price source is identified based on asset type, class
or issue for each security. The trustee monitors prices supplied by pricing services and may use a supplemental price source or change the primary price source of a given security if the trustee challenges an assigned price and determines that
another price source is considered to be preferable. Additionally, SCE corroborates the fair values of securities by comparison to other market-based price sources obtained by SCEs investment managers.

The amount of SCEs level 3 derivative assets and liabilities measured using significant unobservable inputs as a percentage of the total derivative assets and
total derivative liabilities (excluding netting and collateral) measured at fair value were 98% and 53%, respectively. During the first nine months of 2008, the level 3 fair values decreased as a result of changes in realized and unrealized losses.

SCE recorded net realized and unrealized losses of $603 million and $138 million for the three months ended September 30, 2008 and 2007,
respectively. SCE recorded net realized and unrealized losses of $92 million and $97 million for the nine months ended September 30, 2008 and 2007, respectively. The changes in net realized and unrealized losses on economic hedging
activities were primarily due to significant decreases in forward natural gas prices in 2008, compared to the same periods 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.

Credit Risk

As part of SCEs procurement activities, SCE contracts with a number of utilities, energy companies, financial institutions, and other companies, collectively referred to as counterparties. If a counterparty were to default on its
contractual obligations, SCE could be exposed to potentially volatile spot markets for buying replacement power or selling excess power. In addition, SCE would be exposed to the risk of non-payment of accounts receivable, primarily related to sales
of excess energy and realized gains on derivative instruments.

To manage credit risk, SCE looks at the risk of a potential default by counterparties.
Credit risk is measured by the loss that would be incurred if counterparties failed to perform pursuant to the terms of their contractual



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obligations. SCE measures, monitors and mitigates credit risk to the extent possible. SCE manages the credit risk on the portfolio based on credit ratings
using published ratings of counterparties and other publicly disclosed information, such as financial statements, regulatory filings, and press releases, to guide it in the process of setting credit levels, risk limits and contractual arrangements,
including master netting agreements. SCEs risk management committee regularly reviews and evaluates procurement credit exposure and approves credit limits for transacting with counterparties. Despite this, there can be no assurance that these
efforts will be wholly successful in mitigating credit risk or that collateral pledged will be adequate. However, all of the contracts that SCE has entered into with counterparties are either entered into under SCEs short-term or long-term
procurement plan which has been approved by the CPUC, or the contracts are approved by the CPUC before becoming effective. As a result of regulatory recovery mechanisms, losses from non-performance are not expected to affect earnings, but may
temporarily affect cash flows. SCE anticipates future delivery of energy by counterparties, but given the current market condition, SCE cannot predict whether the counterparties will be able to continue operations and deliver energy under the
contractual agreements.

The credit risk exposure from counterparties for power and gas trading activities is measured as the sum of net accounts
receivable (accounts receivable less accounts payable) and the current fair value of net derivative assets reflected on the balance sheet. SCE enters into master agreements which typically provide for a right of setoff. Accordingly, SCEs
credit risk exposure from counterparties is based on a net exposure under these arrangements. At September 30, 2008, the amount of balance sheet exposure as described above, broken down by the credit ratings of SCEs counterparties, was as
follows:



|                                     |  |                    |    |            |   |              |  |   |   
|------------------------------------ |  | ------------------ | -- | ---------- | - | ------------ |  | - | --
|                                     |  | September 30, 2008
|In millions                          |  | Exposure(2)        |    | Collateral |   | Net Exposure
|S&P Credit Rating(1)                 |  |                    |    |            |   |              |  |   |   
|A or higher                          |  | $                  | 3  |            | $ |             |  | $ | 3 
|A-                                   |  |                    | 36 |            |   |             |  |   | 36
|BBB+                                 |  |                    |   |            |   |             |  |   |  
|BBB                                  |  |                    |   |            |   |             |  |   |  
|BBB-                                 |  |                    |   |            |   |             |  |   |  
|Below investment grade and not rated |  |                    |   |            |   |             |  |   |  
|Total                                |  | $                  | 39 |            | $ |             |  | $ | 39

|(1) | SCE assigns a credit rating based on the lower of a counterpartys S&P or Moodys rating. For ease of reference, the above table uses the S&P classifications to
summarize risk, but reflects the lower of the two credit ratings.
|--- | ----------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------



|(2) | Exposure excludes amounts related to contracts classified as normal purchase and sales and non-derivative contractual commitments that are not recorded on the consolidated balance
sheet, except for any related net accounts receivable.
|--- | ------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------

The credit risk exposure set forth in the above table is comprised of $5 million
of net accounts receivable and payables and $34 million representing the fair value of derivative contracts.

Included in the table above are
exposures to counterparties with credit ratings of A- or above. Due to recent developments in the financial markets, the credit ratings may not be reflective of the related credit risk. The CAISO comprises 83% of the total net exposure above and is
mainly related to purchases of firm transmission rights (see Commodity Price Risk for further information).



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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 Operation

Net Income Available for Common Stock

SCEs net income available for common stock was $235 million and $542 million for the three- and nine-month periods ended September 30, 2008, respectively, compared to $262 million and $587 million for the respective periods in 2007.
SCEs quarter and year-to-date earnings reflect a charge of $49 million associated with a decision adopted by the CPUC which required SCE to refund or forego incentives and imposed a penalty related to previously earned customer satisfaction
and employee safety incentives. Earnings also reflect higher operating income and lower financing costs. The year-to-date earnings also reflect a $31 million tax benefit recognized in 2007 related to the income tax treatment of certain costs
including those associated with environmental remediation and lower income taxes.

Operating Revenue

The following table sets forth the major components of operating revenue:



|                                            |  |                                  |       |   |                                 |   |       |      |  |      |       |  |   |       |  
|------------------------------------------- |  | -------------------------------- | ----- | - | ------------------------------- | - | ----- | ---- |  | ---- | ----- |  | - | ----- | -
|                                            |  | Three Months Ended September 30, |       |   | Nine Months Ended September 30, |  
|In millions                                 |  | 2008                             |       |   | 2007                            |   |       | 2008 |  | 2007 |      
|Operating revenue                           |  |                                  |       |   |                                 |   |       |      |  |      |       |  |   |       |  
|Retail billed and unbilled revenue          |  | $                                | 3,192 |   |                                 | $ | 3,125 |      |  | $    | 7,334 |  | $ | 7,312 |  
|Balancing account (over)/under collections  |  |                                  | (222  | ) |                                 |   | (300  | )    |  |      | 35    |  |   | (409  | )
|Sales for resale                            |  |                                  | 141   |   |                                 |   | 168   |      |  |      | 466   |  |   | 333   |  
|SCEs VIEs                                  |  |                                  | 129   |   |                                 |   | 81    |      |  |      | 343   |  |   | 286   |  
|Other (including intercompany transactions) |  |                                  | 45    |   |                                 |   | 140   |      |  |      | 212   |  |   | 375   |  
|Total                                       |  | $                                | 3,285 |   |                                 | $ | 3,214 |      |  | $    | 8,390 |  | $ | 7,897 |  

SCEs retail sales represented approximately 90% and 88% of operating revenue for the three- and nine-month
periods ended September 30, 2008, respectively, compared to approximately 88% and 87% for both of the comparable periods in 2007. 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 $71 million and $493 million for the three-
and nine-month periods ended September 30, 2008, respectively, compared to the same periods in 2007 (as shown in the table above). The variances for the revenue components are as follows:



| |  | Retail billed and unbilled revenue increased $67 million and $22 million for the three- and nine-month periods ended September 30, 2008,
respectively, compared to the same periods in 2007. The quarter and year-to-date increases reflect a rate increase (including impact of tiered rate structure) of $70 million and $29 million, respectively, and a sales volume decrease of
$3 million and $7 million, respectively. The increase for the quarter and year-to-date was due to minor variations of usage by rate class.
|- |  | -------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------



| |  | 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. Costs incurred in excess of revenue billed are deferred in a
balancing account and recorded as regulatory assets for recovery in future rates. If amounts collected are below the
|- |  | ------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------



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| | authorized revenue requirement the difference is recognized as revenue and recorded as regulatory assets for recovery in future rates (see
Provision for Regulatory Adjustment Clauses  Net discussed below). For the three months ended September 30, 2008 and 2007, SCE deferred approximately $222 million and $300 million, respectively and for the nine
months ended September 30, 2008 and 2007, SCE recognized approximately $35 million and deferred approximately $409 million, respectively. The quarter change in balancing account revenue is primarily due to SCE deferring less revenue
in 2008. The year-to-date change in balancing account revenue is primarily due to SCE recognizing deferred revenue resulting from prior year over-collections.
| | -------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------



| |  | Sales for resale represent 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 decreased for the three months ended September 30, 2008 due to a lesser amount of excess energy available for resale during the quarter. Sales for resale revenue increased for the nine months ended September 30, 2008 due to
higher excess energy in 2008, compared to the same periods in 2007, resulting from increased kWh purchases from new contracts, as well as increased sales from least cost dispatch energy. Revenue from sales for resale is refunded to customers through
the ERRA balancing account and does not impact earnings.
|- |  | ----------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------



| |  | The decrease in other revenue for the three- and nine-month periods ended September 30, 2008 was primarily related to lower net investment earnings and higher
other-than-temporary impairment losses from SCEs nuclear decommissioning trust due to a volatile stock market environment. Due to regulatory treatment, investment impairment losses and trust earnings and losses are offset in depreciation,
decommissioning and amortization expense and as a result, have no impact on net income.
|- |  | ------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------

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 $583 million and $1.68 billion for the three- and nine-month periods ended September 30, 2008, respectively, compared to $671 million and $1.8 billion for the same respective periods in 2007.

Operating Expenses

Fuel Expense

SCEs fuel expense increased $105 million and $257 million for the three- and nine-month periods ended September 30, 2008, as compared to the same
periods in 2007. The quarter and year-to-date increases were mainly due to an increase at SCEs Mountainview plant of $15 million and $100 million resulting from higher gas costs in 2008; higher gas costs at SCEs VIEs which
resulted in increases of $80 million and $145 million; an increase of $5 million at SCEs Mohave plant representing use tax due on coal consumed during the March 2005 through December 2005 period; and a $5 million increase
at SCEs Four Corners coal facility resulting from higher coal costs in 2008. The year-to date variance was also due to a decrease of $5 million mainly due to refueling and maintenance outages at SCEs San Onofre Unit 3 and SCEs
Palo Verde Unit 3 during the third quarter of 2008.

Purchased-Power Expense

The following is a summary of SCE purchased-power expense:



|                                                               |  |                                 |   |                                |          |  |          |   |  |          |  
|-------------------------------------------------------------- |  | ------------------------------- | - | ------------------------------ | -------- |  | -------- | - |  | -------- | -
|                                                               |  | Three Months EndedSeptember 30, |   | Nine Months EndedSeptember 30, |         
|In millions                                                    |  | 2008                            |   |                                | 2007     |  | 2008     |   |  | 2007     |  
|Purchased-power                                                |  | $  1,360                        |   |                                | $  1,146 |  | $  3,045 |   |  | $  2,389 |  
|Unrealized (gains) losses on economic hedging activities  net |  | 617                             |   |                                | 80       |  | 131      |   |  | (14      | )
|Realized (gains) losses on economic hedging activities  net   |  | (14                             | ) |                                | 58       |  | (39      | ) |  | 111      |  
|Energy settlements and refunds                                 |  | (1                              | ) |                                |         |  | (26      | ) |  | (55      | )
|Total purchased-power expense                                  |  | $  1,962                        |   |                                | $  1,284 |  | $  3,111 |   |  | $  2,431 |  



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Total purchased-power expense increased $678 million and $680 million for the three- and nine-month periods
ended September 30, 2008, respectively, as compared to the same periods in 2007.

Purchased power, in the table above, increased $214 million and
$656 million for the three- and nine-month periods ended September 30, 2008, respectively, as compared to the same periods in 2007. The quarter and year-to-date increases were due to: higher bilateral energy purchases of $160 million
and $410 million, respectively, resulting from higher costs per kWh due to higher gas prices and increased kWh purchases; higher QF purchased-power expense of $55 million and $120 million, respectively, resulting from increased kWh
purchases and an increase in the average spot natural gas prices for certain contracts (as discussed further below). The quarter increase also reflects higher exchange energy purchases of $10 million. The year-to-date increase also reflects
higher ISO-related energy costs of $115 million.

Net realized and unrealized losses on economic hedging activities, in the table above, was
$603 million and $138 million for the three months ended September 30, 2008 and 2007, respectively. Net realized and unrealized losses on economic hedging activities, in the table above, was $92 million and $97 million for
the nine months ended September 30, 2008 and 2007, respectively (see Market Risk ExposuresCommodity Price Risk for further discussion). The changes in net realized and unrealized losses on economic hedging activities were
primarily due to significant decreases in forward natural gas prices in 2008, compared to the same periods in 2007. Due to expected recovery through regulatory mechanisms realized and unrealized gains and losses may temporarily affect cash flows,
but are not expected to affect earnings (see Market Risk ExposuresCommodity Price Risk for further discussion).

SCE energy settlement
refunds and generator settlements decreased $29 million for the nine months ended September 30, 2008 as compared to the same period in 2007 (see Regulatory MattersCurrent Regulatory DevelopmentsFERC Refund Proceedings for
further discussion).

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 $671 million and $475 million for the three- and nine-month
periods ended September 30, 2008, respectively, compared to the same periods in 2007. The quarter and year-to date variances reflect a decrease of $75 million and $190 million, respectively, as a result of the rate reduction notes
being fully repaid as of December 31, 2007 (see LiquidityRate Reduction Notes in the year-ended 2007 MD&A). The quarter variance also reflects net unrealized losses on economic hedging activities of approximately
$617 million and $80 million for the three months ended September 30, 2008 and 2007, respectively (discussed above in Purchased-Power Expense); lower exchange energy of $10 million; and approximately
$50 million resulting from higher net under-collections of purchased-power and fuel expenses resulting from higher procurement costs which are being recovered through regulatory mechanisms. The year-to-date variance also reflects net unrealized
losses on economic hedging activities of approximately $131 million in 2008, compared to gains of $14 million for the same period in 2007, respectively (discussed above in Purchased-Power Expense); approximately
$29 million related to a generator settlement recorded in 2007; higher firm transmission rights costs of $45 million; and $70 million of higher net under-collections of purchased-power, fuel, and operation and maintenance expenses
resulting from higher procurement costs which are being recovered through regulatory mechanisms, partially offset by the Midway-Sunset settlement which was charged/refunded to ratepayers through regulatory mechanisms (see Other
DevelopmentsMidway-Sunset Cogeneration Company for further information).



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Other Operation and Maintenance Expense

SCEs other operation and maintenance expense decreased $15 million for the three months ended September 30, 2008 and increased $157 million for the nine months ended September 30, 2008,
compared to the same periods in 2007. The quarter decrease was primarily due to a decrease of approximately $25 million related to lower transmission and distribution maintenance costs partially offset by an increase of $20 million related
to higher administrative and general costs. Certain of SCEs operation and maintenance expense accounts are recovered through regulatory mechanisms approved by the CPUC and do not impact earnings. The costs associated with these regulatory
balancing accounts increased $65 million for the nine months ended September 30, 2008 mainly related to higher demand-side management costs and energy efficiency costs. The increases in operation and maintenance expense for the
year-to-date period also reflect: higher administrative and general costs of $60 million; higher generation expenses of $30 million related to maintenance and refueling outage expenses at San Onofre and higher overhaul and outage costs at
Four Corners and Palo Verde; and higher customer service costs (including labor) of $10 million. The year-to-date variance also reflects a decrease of approximately $10 million related to lower transmission and distribution maintenance
costs.

Depreciation, Decommissioning and Amortization Expense

SCEs depreciation, decommissioning and amortization expense decreased $56 million and $63 million for the three- and nine-month periods ended September 30, 2008, respectively, compared to the same
periods in 2007. The quarter and year-to-date variances were due to a decrease of $80 million and $140 million, respectively, in nuclear decommissioning trust earnings and higher other-than-temporary impairment losses associated with the
nuclear decommissioning trust funds primarily related to a volatile stock market environment. Due to its regulatory treatment, investment impairment losses and trust earnings and losses are recorded in operating revenue and are offset in
decommissioning expense and have no impact on net income. The quarter and year-to-date decreases were partially offset by an increase in depreciation expense of $20 million and $60 million, respectively, resulting from additions to
transmission and distribution assets (see LiquidityCapital Expenditures for a further discussion); and a $17 million cumulative depreciation rate adjustment recorded in the second quarter of 2008.

Property and Other Taxes

SCEs property and other
taxes increased by $7 million and $15 million for the three- and nine-month periods ended September 30, 2008, respectively, compared to the same periods in 2007. The increases were primarily due to higher employer payroll taxes paid in 2008 compared
to the same periods in 2007.

Gain on Sale of Assets

Gain on sale of assets increased $9 million for the nine months ended September 30, 2008, compared to the
same period in 2007. The year-to-date increase reflects gains of $8 million from the sale of SO2emission allowances at SCE. Due to regulatory
treatment, gains from the sale of emission allowances are offset in provisions for regulatory adjustment clausesnet and, as a result, have no impact on net income.

Other Income and Deductions

Interest Income

SCEs interest income decreased $11 million and $22 million for the three- and nine-month periods ended September 30, 2008, respectively, compared to
the same periods in 2007. The 2008 decreases were mainly due to lower under-collection balances in certain balancing accounts and lower interest rates applied to those under-collections.



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Other Nonoperating Income

SCEs other nonoperating income decreased $9 million for the three months ended September 30, 2008, compared to the same period in 2007. The decrease for the quarter was due to payments received for settlement of claims
related to the natural gas purchased contracts for one of SCEs VIE projects recorded in the third quarter of 2007.

Interest
Expense  Net of Amounts Capitalized

SCEs interest expense  net of amounts capitalized decreased $13 million and
$33 million for the three- and nine-month periods ended September 30, 2008, respectively, compared to the same periods in 2007. The quarter and year-to-date decreases were mainly due to lower over-collections of certain balancing accounts
and lower interest rates applied to those over-collections during 2008 compared to the same periods in 2007. This decrease for quarter and year-to-date was partially offset by higher interest expense on short-term debt and long-term debt resulting
from higher balances outstanding as of September 30, 2008, compared to the same period in 2007.

Other Nonoperating Deductions

SCEs other nonoperating deductions increased $74 million and $83 million for the three- and nine-month periods ended September 30, 2008,
respectively. The increase was primarily due to approximately $60 million related to the CPUC adopted decision on the investigation into SCEs incentives claimed under a CPUC-approved PBR mechanism in September 2008 (see Current
DevelopmentsInvestigation Regarding Performance Incentives Rewards CPUC Decision for further information). The quarter and year-to-date increases were also due to approximately $10 million and $20 million, respectively, for
expenditures related to civic, political and related activities, and donations.

Income Tax Expense

SCEs composite federal and state statutory income tax rate was approximately 40% (net of federal benefit for state income taxes) for all periods presented.
SCEs effective tax rate was 39% and 32% for the three- and nine-month periods ended September 30, 2008, as compared to 35% and 30% for the respective periods in 2007. The higher effective income tax rate for the three months ended September
30, 2008 as compared to the respective period in 2007, was primarily due to two non-deductible expenses recorded in 2008, consisting of a penalty assessed by the CPUC (see Current DevelopmentsInvestigation Regarding Performance
Incentives Rewards CPUC Decision for further information), and higher lobbying expenses. The higher effective tax rates for the nine months ended September 30, 2008 as compared to the respective period in 2007, were due to both
previously-mentioned non-deductible expenses and reductions in the income tax reserve recorded in the first quarter of 2007 to reflect progress made in an administrative appeal process with the IRS related to the income tax treatment of certain
costs associated with environmental remediation and to reflect a settlement of state tax audit issues. The previously mentioned factors causing an increase to the 2008 federal and state effective tax rates as compared to 2007 were partially offset
by higher software and property-related flow-through deductions recorded in 2008.

Minority Interest

Minority interest decreased $38 million and $100 million for the three- and nine-month periods ended September 30, 2008, respectively, as compared to the
same periods in 2007. The decrease was a result of lower earnings from two of SCEs VIE projects due to lower pricing. The year-to-date decrease was also due to lower earnings from another SCE VIE project attributable to a planned outage in the
first quarter of 2008.

Earnings from the SCE VIE, Watson project, are based on revised pricing effective January 1, 2008. Watson Cogeneration and SCE
have disputed the commencement date of the prior contract which in turn affected the expiration date (Watson Cogenerations position is April 2008 whereby SCEs position is December 2007). See Market Risk ExposuresBig 4
Projects Power Purchase Agreements in the year-ended 2007 MD&A for further discussion.



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Historical Cash Flow Analysis

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

Cash Flows from Operating Activities

Cash provided by operating activities decreased $1.17 billion in
the first nine months of 2008, compared to the first nine months of 2007. The decrease was mainly due to ERRA under-collections in 2008, compared to ERRA over-collections in 2007 as well as the rate reduction notes being fully repaid as of
December 31, 2007 (see LiquidityRate Reduction Notes in the year-ended 2007 MD&A) partially offset by refund payments made in 2008 for SCEs public purpose program. The 2008 change was also due to the timing of cash
receipts and disbursements related to working capital items.

Cash Flows from Financing Activities

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

Financing activities in the first nine-months of 2008 were as follows:



| |  | In January, SCE issued $600 million of first refunding mortgage bonds due in 2038. The proceeds were used to repay SCEs outstanding commercial paper of
approximately $426 million and for general corporate purposes.
|- |  | -----------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------



| |  | During the first quarter, SCE purchased $212 million of its auction rate bonds, converted the issue to a variable rate mode, and terminated the FGIC insurance
policy. SCE continues to hold the bonds which remain outstanding and have not been retired or cancelled.
|- |  | -----------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------



| |  | In January, SCE repurchased 350,000 shares of 4.08% cumulative preferred stock at a price of $19.50 per share. SCE retired this preferred stock in January 2008 and
recorded a $2 million gain on the cancellation of reacquired capital stock (reflected in the caption Common stock on the consolidated balance sheets).
|- |  | ----------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------



| |  | In August, SCE issued $400 million of 5.50% first and refunding mortgage bonds due in 2018. The proceeds were used to repay SCEs outstanding commercial
paper of approximately $110 million and borrowings under the credit facility of $200 million, as well as for general corporate purposes.
|- |  | -------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------



| |  | During the first nine months of 2008, SCEs net issuances of short-term debt was $1.1 billion.
|- |  | ----------------------------------------------------------------------------------------------



| |  | Other financing activities in 2008 include dividend payments of $225 million paid to Edison International and $28 million for stock purchased for
stock-based compensation.
|- |  | ---------------------------------------------------------------------------------------------------------------------------------------------------------------------------

Financing activities in the first nine months of 2007 were as follows:



| |  | Other financing activities in 2007 include dividend payments of $110 million paid to Edison International and $123 million for stock purchased for
stock-based compensation.
|- |  | ----------------------------------------------------------------------------------------------------------------------------------------------------------------------------

Cash Flows from Investing Activities

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

Investing activities in 2008 reflect $1.64 billion in capital expenditures at SCE, primarily for transmission and distribution assets,
including approximately $70 million for nuclear fuel acquisitions. Investing activities also include net purchases of nuclear decommissioning trust investments and other of $50 million.

Investing activities in 2007 reflect $1.65 billion in capital expenditures at SCE, primarily for transmission and distribution assets, including approximately
$104 million for nuclear fuel acquisitions. Investing activities also include net purchases of nuclear decommissioning trust investments and other of $101 million.



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NEW ACCOUNTING PRONOUNCEMENTS

Accounting Pronouncements Adopted

In April 2007, the FASB issued FIN No. 39-1. This pronouncement permits companies to offset fair
value amounts recognized for the right to reclaim cash collateral (a receivable) or the obligation to return cash collateral (a payable) against fair value amounts recognized for derivative instruments executed with the same counterparty under a
master netting arrangement. In addition, upon the adoption, companies were permitted to change their accounting policy to offset or not offset fair value amounts recognized for derivative instruments under master netting agreements. SCE adopted FIN
No. 39-1 effective January 1, 2008. The adoption resulted in netting a portion of margin and cash collateral deposits with derivative positions on SCEs consolidated balance sheets, but had no impact on SCEs consolidated
statements of income. The consolidated balance sheet at December 31, 2007 has been retroactively restated for the change, which resulted in a decrease in margin and collateral deposits of $2 million. The consolidated statements of cash
flows for the nine months ended September 30, 2007 has been retroactively restated to reflect the balance sheet changes but had no impact on cash flows from operating activities.

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. SCE adopted this
pronouncement effective January 1, 2008. The adoption had no impact because SCE did not make an optional election to report additional financial assets and liabilities at fair value.

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 adopted SFAS No. 157 effective January 1, 2008. The adoption did not result in any retrospective adjustments to its consolidated financial statements. The accounting requirements for
employers pension and other postretirement benefit plans are effective at the end of 2008, which is the next measurement date for these benefit plans. The effective date will be January 1, 2009 for asset retirement obligations and other
nonfinancial assets and liabilities which are measured or disclosed on a non-recurring basis.

On October 10, 2008, the FASB issued FSP SFAS
No. 157-3, Determining the Fair Value of a Financial Asset When the Market for That Asset Is Not Active. This position clarifies the application of SFAS No. 157 in a market that is not active and provides an example to
illustrate key considerations in determining the fair value of a financial asset when the market for that financial asset is not active. It also reaffirms the notion of fair value as an exit price as of the measurement date. This position was
effective upon issuance, including prior periods for which financial statements have not been issued. The adoption had no impact on SCEs consolidated financial statements.

Accounting Pronouncements Not Yet Adopted

In December 2007, the FASB issued SFAS No. 160, which requires
an entity to present minority interest that reflects the ownership interests in subsidiaries held by parties other than the entity, within the equity section but separate from the entitys equity in the consolidated financial statements. It
also requires the amount of consolidated net income attributable to the parent and to the noncontrolling interest to be clearly identified and presented on the face of the consolidated statement of income; changes in ownership interest be accounted
for similarly as equity transactions; and, when a subsidiary is deconsolidated, any retained noncontrolling equity investment in the former subsidiary and the gain or loss on the deconsolidation of the subsidiary be measured at fair value. SCE will
adopt SFAS No. 160 on January 1, 2009. In accordance with this standard, SCE will reclassify minority interest to a component of shareholders equity (at September 30, 2008 this amount was $451 million).

In March 2008, the FASB issued SFAS No. 161, which requires additional disclosures related to derivative instruments, including how and why an entity uses
derivative instruments, how derivative instruments and related hedged items are accounted for and how derivative instruments and related hedged items affect an entitys



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financial position, financial performance, and cash flows. SFAS No. 161 is effective for fiscal years beginning after November 15, 2008, with early
adoption permitted. SCE will adopt SFAS No. 161 in the first quarter of 2009. SFAS No. 161 will impact disclosures only and will not have an impact on SCEs consolidated results of operations, financial condition or cash flows.

In May 2008, the FASB issued SFAS No. 162, The Hierarchy of Generally Accepted Accounting Principles, which identifies the sources of
accounting principles and the framework for selecting the principles to be used in the preparation of financial statements for nongovernmental entities that are presented in conformity with U.S. GAAP. This statement transfers the GAAP hierarchy
from the American Institute of Certified Public Accountants Statement on Auditing Standards No. 69, The Meaning of Present Fairly in Conformity With Generally Accepted Accounting Principles to the FASB. SFAS No. 162 is
effective on November 15, 2008. SCE expects that the adoption of this standard will not have an impact on SCEs consolidated results of operations, financial condition or cash flows.

In September 2008, the FASB issued FSP SFAS No. 133-1 and FIN No. 45-4. FSP SFAS No. 133-1 requires enhanced disclosures by sellers of credit
derivatives and amends FASB Interpretation No. 45 (FIN No. 45), Guarantors Accounting and Disclosure Requirements for Guarantees, Including Indirect Guarantees of Indebtedness to Others, to require additional disclosure
about the current status of the payment/performance risk of a guarantee. The provisions of the FSP that amend SFAS No. 133 and FIN No. 45 are effective for reporting periods ending after November 15, 2008. Since FSP FAS No. 133-1
and FIN No. 45-4 only require additional disclosures, the adoption will not impact SCEs consolidated financial position, results of operations or cash flows.

COMMITMENTS AND INDEMNITIES

The following is an update to SCEs commitments and indemnities. See the section,
Commitments and Indemnities in the year-ended 2007 MD&A for a detailed discussion.

Long-Term Debt

SCEs long-term principal debt maturities plus interest payments as of September 30, 2008 are estimated to be: remainder of 2008  $79 million,
2009  $460 million, 2010  $542 million, 2011  $291 million, 2012  $291 billion and thereafter  $10.4 billion.

Fuel Supply Contracts

During the first nine months of 2008, SCE entered into service contracts associated with
uranium enrichment and fuel fabrication. As a result, SCEs additional fuel supply commitments are estimated to be: 2009  $51 million, 2010  $54 million, 2011  $98 million, 2012  $146 million and
thereafter  $671 million.

Power-Purchase Contracts

During the second quarter of 2008, SCE entered into a new power-purchase contract. The delivery of energy under this contract is expected to commence in August 2010 with a 10 year term. SCEs additional commitments upon commencement
are estimated to be: 2010  $188 million, 2011  $335 million, 2012  $341 million and thereafter  $2.7 billion.

Operating and Capital Leases

During the second quarter of 2008, SCE entered into power-purchase contracts which are classified as operating
leases. The contract terms range from 10 to 20 years. The delivery of energy under one of these contracts is not expected to commence until 2018. These additional commitments are currently estimated to be: remainder of 2008 
$4 million, 2009  $14 million, 2010  $15 million, 2011  $15 million, 2012  $15 million and thereafter  $828 million.



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During the third quarter of 2008, SCE entered into power-purchase contracts which are classified as capital leases. The
contract terms are 20 years. The delivery of energy under these contracts is expected to commence in 2010. These additional commitments are currently estimated to be: 2010  $32 million, 2011  $119 million, 2012 
$119 million and thereafter  $2.6 billion. The estimated executory costs and interest expense associated with these additional commitments are $699 million and $988 million, respectively. The total additional estimated net
commitments are $1.2 billion.

Uncertain Tax Position Net Liability

At September 30, 2008, SCEs recorded net liability for uncertain tax positions was $297 million. SCE currently cannot reliably predict the timing of cash flows associated with the resolution of
uncertain tax positions due to the uncertainty as to the timing for resolving tax issues with the IRS related to ongoing examinations and administrative appeals. See Other DevelopmentsFederal and State Income Taxes for further
information.



|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

As discussed above,
effective July 1, 2008, SCE implemented a series of SAP enterprise resource planning (ERP) modules, including financial reporting, general ledger, consolidation, property accounting, treasury, supply chain, payroll, human resources
and work management. The implementation of these ERP modules and the related workflow capabilities resulted in material changes to SCEs internal controls over financial reporting (as that term is defined in Rules 13(a)-15(f) or 15(d)-15(f)
under the Exchange Act). Therefore, SCE has modified the design and documentation of internal control processes and procedures relating to the new system to replace and supplement existing internal controls over financial reporting, as appropriate.
The system changes were undertaken to integrate systems and consolidate information, and were not undertaken in response to any actual or perceived deficiencies in SCEs internal control over financial reporting.

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

SCE has not designed, established, or maintained internal
control over financial reporting for four variable interest entities, referred to as VIEs, that SCE was required to consolidate under an accounting interpretation issued by the Financial Accounting Standards Board. SCEs evaluation
of internal control over financial reporting does not include these VIEs.



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PART II. OTHER INFORMATION



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

Catalina South Coast Air Quality Management
District Potential Environmental Proceeding

During the first half of 2006, the South Coast Air Quality Management District (SCAQMD) issued three NOVs
alleging that Unit 15, SCEs primary diesel generation unit on Catalina Island, had exceeded the NOx emission 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 NOx limit 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 NOx limit 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, would enable these units to meet their annual NOx limits in 2007.

In July 2008, SCE received an additional NOV for emitting NOx in excess of SCEs Regional Clean Air Incentives Market (RECLAIM) credits. Under the RECLAIM program, a RECLAIM-regulated facility must have sufficient RECLAIM Trading
Credits to equal the amount of NOx that the facility emits. The NOV alleges that SCE did not have sufficient RECLAIM Trading Credits in the first and second quarters of 2007 to match the actual NOx emissions at Catalinas generating units.

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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PART II. OTHER INFORMATION



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

Southern California Edison Company



|     |  |                                                                                               
|---- |  | ----------------------------------------------------------------------------------------------
|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. Sullivan Vice President and Controller (Duly Authorized Officer and Principal Accounting Officer)


Dated: November 7, 2008



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