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UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549





FORM 10-Q





(Mark One)

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

For the quarterly period ended June 30, 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 August 6, 2008
|Common Stock, no par value |  | 434,888,104                  









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SOUTHERN CALIFORNIA EDISON COMPANY

INDEX



|                              |  |         |  |                                                                                           |  |        
|----------------------------- |  | ------- |  | ----------------------------------------------------------------------------------------- |  | -------
|                              |  |         |  |                                                                                           |  | PageNo.
|Part I. Financial Information |  |        
|                              |  |         | 
|                              |  | Item 1. |  | Financial Statements                                                                      |  | 1      
|                              |  |         | 
|                              |  |         |  | Consolidated Statements of Income  Six Months Ended June 30, 2008 and 2007               |  | 1      
|                              |  |         | 
|                              |  |         |  | Consolidated Statements of Comprehensive Income  Six Months Ended June 30, 2008 and 2007 |  | 1      
|                              |  |         | 
|                              |  |         |  | Consolidated Balance Sheets  June 30, 2008 and December 31, 2007                         |  | 2      
|                              |  |         | 
|                              |  |         |  | Consolidated Statements of Cash Flows  Six Months Ended June 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     |  | 29     
|                              |  |         | 
|                              |  | Item 3. |  | Quantitative and Qualitative Disclosures About Market Risk                                |  | 53     
|                              |  |         | 
|                              |  | Item 4. |  | Controls and Procedures                                                                   |  | 53     
|                              | 
|Part II. Other Information    |  |        
|                              |  |         | 
|                              |  | Item 1. |  | Legal Proceedings                                                                         |  | 54     
|                              |  |         | 
|                              |  | Item 4. |  | Submission of Matters to a Vote of Security Holders                                       |  | 54     
|                              |  |         | 
|                              |  | Item 6. |  | Exhibits                                                                                  |  | 56     
|                              | 
|Signature                     |  | 57     



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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                                                                                                           
|               | 
|DWP            |  | Los Angeles Department of Water & Power                                                                                        
|               | 
|EITF           |  | Emerging Issues Task Force                                                                                                     
|               | 
|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
|               | 
|FTRs           |  | firm transmission rights                                                                                                       
|               | 
|GRC            |  | General Rate Case                                                                                                              
|               | 
|IRS            |  | Internal Revenue Service                                                                                                       
|               | 
|ISO            |  | California Independent System Operator                                                                                         
|               | 
|kWh(s)         |  | kilowatt-hour(s)                                                                                                               
|               | 
|MD&A           |  | Managements Discussion and Analysis of Financial Condition and Results of Operations                                          
|               | 
|Midway-Sunset  |  | Midway-Sunset Cogeneration Company                                                                                             
|               | 
|Mohave         |  | Mohave Generating Station                                                                                                      



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##### Table of Contents

GLOSSARY (Continued)



|               |  |                                                                                                                                                             
|-------------- |  | ------------------------------------------------------------------------------------------------------------------------------------------------------------
|               | 
|MRTU           |  | Market Redesign 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                                                                                                                       
|               | 
|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                                           
|               | 
|FSP SFAS 142-3 |  | FASB Staff Position No. SFAS 142-3, Determination of the Useful Life of Intangible Assets                                                                   
|               | 
|SFAS No. 157   |  | Statement of Financial Accounting Standards No. 157, Fair Value Measurements                                                                                
|               | 
|SFAS No. 158   |  | Statement of Financial Accounting Standards No. 158, Employers Accounting for Defined Benefit Pension and Other 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 Ended June 30, |       |   | Six Months Ended June 30, |  
|In millions                                                                     |  | 2008                        |       |   | 2007                      |   |       | 2008 |  |   | 2007  |  
|                                                                                |  | (Unaudited)                 |      
|Operating revenue                                                               |  | $                           | 2,755 |   |                           | $ | 2,460 |      |  | $ | 5,106 |   |  | $ | 4,682 |  
|Fuel                                                                            |  |                             | 397   |   |                           |   | 285   |      |  |   | 746   |   |  |   | 595   |  
|Purchased power                                                                 |  |                             | 656   |   |                           |   | 829   |      |  |   | 1,149 |   |  |   | 1,146 |  
|Provisions for regulatory adjustment clauses  net                              |  |                             | 279   |   |                           |   | (33   | )    |  |   | 452   |   |  |   | 255   |  
|Other operation and maintenance                                                 |  |                             | 757   |   |                           |   | 661   |      |  |   | 1,435 |   |  |   | 1,262 |  
|Depreciation, decommissioning and amortization                                  |  |                             | 286   |   |                           |   | 271   |      |  |   | 539   |   |  |   | 546   |  
|Property and other taxes                                                        |  |                             | 56    |   |                           |   | 55    |      |  |   | 118   |   |  |   | 110   |  
|Gain on sale of assets                                                          |  |                             | (7    | ) |                           |   |      |      |  |   | (8    | ) |  |   |      |  
|Total operating expenses                                                        |  |                             | 2,424 |   |                           |   | 2,068 |      |  |   | 4,431 |   |  |   | 3,914 |  
|Operating income                                                                |  |                             | 331   |   |                           |   | 392   |      |  |   | 675   |   |  |   | 768   |  
|Interest income                                                                 |  |                             | 5     |   |                           |   | 10    |      |  |   | 10    |   |  |   | 21    |  
|Other nonoperating income                                                       |  |                             | 25    |   |                           |   | 25    |      |  |   | 44    |   |  |   | 41    |  
|Interest expense  net of amounts capitalized                                   |  |                             | (96   | ) |                           |   | (105  | )    |  |   | (193  | ) |  |   | (213  | )
|Other nonoperating deductions                                                   |  |                             | (14   | ) |                           |   | (13   | )    |  |   | (26   | ) |  |   | (23   | )
|Income before income tax and minority interest                                  |  |                             | 251   |   |                           |   | 309   |      |  |   | 510   |   |  |   | 594   |  
|Income tax expense                                                              |  |                             | 30    |   |                           |   | 61    |      |  |   | 111   |   |  |   | 114   |  
|Minority interest                                                               |  |                             | 51    |   |                           |   | 91    |      |  |   | 67    |   |  |   | 129   |  
|Net income                                                                      |  |                             | 170   |   |                           |   | 157   |      |  |   | 332   |   |  |   | 351   |  
|Dividends on preferred and preference stock not subject to mandatory redemption |  |                             | 13    |   |                           |   | 13    |      |  |   | 25    |   |  |   | 26    |  
|Net income available for common stock                                           |  | $                           | 157   |   |                           | $ | 144   |      |  | $ | 307   |   |  | $ | 325   |  
|                                                                                |  |                            
|CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME                                 |  |                             |       |   |                           |   |       |      | 
|                                                                                |  | Three Months Ended June 30, |       |   | Six Months Ended June 30, |  
|In millions                                                                     |  | 2008                        |       |   | 2007                      |   |       | 2008 |  |   | 2007  |  
|                                                                                |  | (Unaudited)                 |      
|Net income                                                                      |  | $                           | 170   |   |                           | $ | 157   |      |  | $ | 332   |   |  | $ | 351   |  
|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    | ) |  |   | 1     |  
|Comprehensive income                                                            |  | $                           | 170   |   |                           | $ | 157   |      |  | $ | 331   |   |  | $ | 352   |  



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                                                                                            |  | June 30, 2008 |        |   | December 31, 2007 |  
|                                                                                                       |  | (Unaudited)   |        |   |                   |  
|ASSETS                                                                                                 |  |               |        |   |                   |   |        |  
|Cash and equivalents                                                                                   |  | $             | 185    |   |                   | $ | 252    |  
|Short-term investments                                                                                 |  |               | 2      |   |                   |   |       |  
|Receivables, less allowance of $32 and $34 for uncollectible accounts at respective dates              |  |               | 811    |   |                   |   | 725    |  
|Accrued unbilled revenue                                                                               |  |               | 528    |   |                   |   | 370    |  
|Inventory                                                                                              |  |               | 317    |   |                   |   | 283    |  
|Derivative assets                                                                                      |  |               | 363    |   |                   |   | 53     |  
|Margin and collateral deposits                                                                         |  |               | 7      |   |                   |   | 35     |  
|Regulatory assets                                                                                      |  |               | 203    |   |                   |   | 197    |  
|Accumulated deferred income taxes  net                                                                |  |               | 129    |   |                   |   | 146    |  
|Other current assets                                                                                   |  |               | 213    |   |                   |   | 188    |  
|Total current assets                                                                                   |  |               | 2,758  |   |                   |   | 2,249  |  
|Nonutility property  less accumulated provision for depreciation of $732 and $701 at respective dates |  |               | 984    |   |                   |   | 1,000  |  
|Nuclear decommissioning trusts                                                                         |  |               | 3,152  |   |                   |   | 3,378  |  
|Other investments                                                                                      |  |               | 83     |   |                   |   | 69     |  
|Total investments and other assets                                                                     |  |               | 4,219  |   |                   |   | 4,447  |  
|Utility plant, at original cost:                                                                       |  |               |        |   |                   |   |        |  
|Transmission and distribution                                                                          |  |               | 19,279 |   |                   |   | 18,940 |  
|Generation                                                                                             |  |               | 1,818  |   |                   |   | 1,767  |  
|Accumulated provision for depreciation                                                                 |  |               | (5,344 | ) |                   |   | (5,174 | )
|Construction work in progress                                                                          |  |               | 2,048  |   |                   |   | 1,693  |  
|Nuclear fuel, at amortized cost                                                                        |  |               | 251    |   |                   |   | 177    |  
|Total utility plant                                                                                    |  |               | 18,052 |   |                   |   | 17,403 |  
|Derivative assets                                                                                      |  |               | 212    |   |                   |   | 28     |  
|Regulatory assets                                                                                      |  |               | 2,723  |   |                   |   | 2,721  |  
|Other long-term assets                                                                                 |  |               | 636    |   |                   |   | 629    |  
|Total long-term assets                                                                                 |  |               | 3,571  |   |                   |   | 3,378  |  
|                                                                                                       |  |              
|Total assets                                                                                           |  | $             | 28,600 |   |                   | $ | 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                                        |  | June 30, 2008 |        |   | December 31, 2007 |  
|                                                                         |  | (Unaudited)   |        |   |                   |  
|LIABILITIES AND SHAREHOLDERS EQUITY                                     |  |               |        |   |                   |   |        |  
|Short-term debt                                                          |  | $             | 800    |   |                   | $ | 500    |  
|Long-term debt due within one year                                       |  |               | 150    |   |                   |   |       |  
|Accounts payable                                                         |  |               | 951    |   |                   |   | 914    |  
|Accrued taxes                                                            |  |               | 45     |   |                   |   | 42     |  
|Accrued interest                                                         |  |               | 158    |   |                   |   | 126    |  
|Counterparty collateral                                                  |  |               | 24     |   |                   |   | 42     |  
|Customer deposits                                                        |  |               | 223    |   |                   |   | 218    |  
|Book overdrafts                                                          |  |               | 290    |   |                   |   | 204    |  
|Derivative liabilities                                                   |  |               | 26     |   |                   |   | 97     |  
|Regulatory liabilities                                                   |  |               | 1,223  |   |                   |   | 1,019  |  
|Other current liabilities                                                |  |               | 520    |   |                   |   | 548    |  
|Total current liabilities                                                |  |               | 4,410  |   |                   |   | 3,710  |  
|Long-term debt                                                           |  |               | 5,316  |   |                   |   | 5,081  |  
|Accumulated deferred income taxes  net                                  |  |               | 2,593  |   |                   |   | 2,556  |  
|Accumulated deferred investment tax credits                              |  |               | 101    |   |                   |   | 105    |  
|Customer advances                                                        |  |               | 146    |   |                   |   | 155    |  
|Derivative liabilities                                                   |  |               | 13     |   |                   |   | 13     |  
|Power-purchase contracts                                                 |  |               | 22     |   |                   |   | 22     |  
|Accumulated provision for pensions and benefits                          |  |               | 845    |   |                   |   | 786    |  
|Asset retirement obligations                                             |  |               | 2,934  |   |                   |   | 2,877  |  
|Regulatory liabilities                                                   |  |               | 3,356  |   |                   |   | 3,433  |  
|Other deferred credits and other long-term liabilities                   |  |               | 1,164  |   |                   |   | 1,136  |  
|Total deferred credits and other liabilities                             |  |               | 11,174 |   |                   |   | 11,083 |  
|Total liabilities                                                        |  |               | 20,900 |   |                   |   | 19,874 |  
|Commitments and contingencies (Note 5)                                   |  |               |        |   |                   |   |        |  
|Minority interest                                                        |  |               | 448    |   |                   |   | 446    |  
|Common stock, no par value (434,888,104 shares outstanding at each date) |  |               | 2,168  |   |                   |   | 2,168  |  
|Additional paid-in capital                                               |  |               | 525    |   |                   |   | 507    |  
|Accumulated other comprehensive loss                                     |  |               | (16    | ) |                   |   | (15    | )
|Retained earnings                                                        |  |               | 3,655  |   |                   |   | 3,568  |  
|Total common shareholders equity                                        |  |               | 6,332  |   |                   |   | 6,228  |  
|Preferred and preference stock not subject to mandatory redemption       |  |               | 920    |   |                   |   | 929    |  
|Total shareholders equity                                               |  |               | 7,252  |   |                   |   | 7,157  |  
|                                                                         |  |              
|Total liabilities and shareholders equity                               |  | $             | 28,600 |   |                   | $ | 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



|                                                                       |  |                           |        |   |      |   |        |  
|---------------------------------------------------------------------- |  | ------------------------- | ------ | - | ---- | - | ------ | -
|                                                                       |  | Six Months Ended June 30, |       
|In millions                                                            |  | 2008                      |        |   | 2007 |  
|                                                                       |  | (Unaudited)               |       
|Cash flows from operating activities:                                  |  |                           |        |   |      |   |        |  
|Net income                                                             |  | $                         | 332    |   |      | $ | 351    |  
|Adjustments to reconcile to net cash provided by operating activities: |  |                           |        |   |      |   |        |  
|Depreciation, decommissioning and amortization                         |  |                           | 539    |   |      |   | 546    |  
|Realized loss on nuclear decommissioning trusts                        |  |                           | 72     |   |      |   | 23     |  
|Other amortization                                                     |  |                           | 47     |   |      |   | 50     |  
|Stock-based compensation                                               |  |                           | 8      |   |      |   | 8      |  
|Minority interest                                                      |  |                           | 67     |   |      |   | 129    |  
|Deferred income taxes and investment tax credits                       |  |                           | 6      |   |      |   | (242   | )
|Regulatory assets                                                      |  |                           | 8      |   |      |   | 245    |  
|Regulatory liabilities                                                 |  |                           | 374    |   |      |   | 120    |  
|Derivative assets                                                      |  |                           | (494   | ) |      |   | (83    | )
|Derivative liabilities                                                 |  |                           | (71    | ) |      |   | (90    | )
|Other assets                                                           |  |                           | (19    | ) |      |   | (23    | )
|Other liabilities                                                      |  |                           | 28     |   |      |   | 219    |  
|Margin and collateral deposits  net of collateral received            |  |                           | 10     |   |      |   | 4      |  
|Receivables and accrued unbilled revenue                               |  |                           | (244   | ) |      |   | (181   | )
|Inventory and other current assets                                     |  |                           | (51    | ) |      |   | (78    | )
|Book overdrafts                                                        |  |                           | 86     |   |      |   | 62     |  
|Accrued interest and taxes                                             |  |                           | 35     |   |      |   | 296    |  
|Accounts payable and other current liabilities                         |  |                           | 56     |   |      |   | (15    | )
|Net cash provided by operating activities                              |  |                           | 789    |   |      |   | 1,341  |  
|Cash flows from financing activities:                                  |  |                           |        |   |      |   |        |  
|Long-term debt issued                                                  |  |                           | 600    |   |      |   |       |  
|Long-term debt issuance costs                                          |  |                           | (9     | ) |      |   | (1     | )
|Long-term debt repaid                                                  |  |                           | (1     | ) |      |   | (23    | )
|Bonds repurchased                                                      |  |                           | (212   | ) |      |   |       |  
|Preferred stock redeemed                                               |  |                           | (7     | ) |      |   |       |  
|Rate reduction notes repaid                                            |  |                           |       |   |      |   | (116   | )
|Short-term debt financing  net                                        |  |                           | 300    |   |      |   | 175    |  
|Shares purchased for stock-based compensation                          |  |                           | (25    | ) |      |   | (115   | )
|Proceeds from stock option exercises                                   |  |                           | 9      |   |      |   | 47     |  
|Excess tax benefits related to stock-based awards                      |  |                           | 8      |   |      |   | 22     |  
|Minority interest                                                      |  |                           | (65    | ) |      |   | (63    | )
|Dividends paid                                                         |  |                           | (150   | ) |      |   | (111   | )
|Net cash provided (used) by financing activities                       |  |                           | 448    |   |      |   | (185   | )
|Cash flows from investing activities:                                  |  |                           |        |   |      |   |        |  
|Capital expenditures                                                   |  |                           | (1,241 | ) |      |   | (1,091 | )
|Proceeds from nuclear decommissioning trust sales                      |  |                           | 1,501  |   |      |   | 2,017  |  
|Purchases of nuclear decommissioning trust investments                 |  |                           | (1,560 | ) |      |   | (2,084 | )
|Sales of short-term investments                                        |  |                           |       |   |      |   | 2,097  |  
|Purchases of short-term investments                                    |  |                           | (2     | ) |      |   | (2,097 | )
|Restricted cash                                                        |  |                           |       |   |      |   | 7      |  
|Customer advances for construction and other investments               |  |                           | (2     | ) |      |   | 3      |  
|Net cash used by investing activities                                  |  |                           | (1,304 | ) |      |   | (1,148 | )
|Net increase (decrease) in cash and equivalents                        |  |                           | (67    | ) |      |   | 8      |  
|Cash and equivalents, beginning of period                              |  |                           | 252    |   |      |   | 83     |  
|Cash and equivalents, end of period                                    |  | $                         | 185    |   |      | $ | 91     |  



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 six-month periods ended June 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.

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.

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 received
from others that have been offset against net derivative assets totaled $18 million at June 30, 2008 compared to $2 million cash collateral provided to others that have been offset against net derivative liabilities at
December 31, 2007.

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 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 six months ended June 30, 2007 has been retroactively restated to reflect the balance sheet changes but had no impact on cash flows from operating activities.



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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.

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 June 30, 2008 this amount was $448 million).

In March 2008, the FASB issued SFAS No. 161, which requires additional disclosure 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.

In April 2008, the FASB issued FSP FAS No. 142-3 which amends the factors that
should be considered in developing renewal or extension assumptions used to determine the useful life of a recognized intangible asset under SFAS No. 142, Goodwill and Other Intangible Assets. The intent of the position is to
improve the consistency between the useful life of a recognized intangible asset under SFAS No. 142 and the period of expected cash flows used to measure the fair value of the asset under SFAS No. 141(R) and other U.S. generally accepted
accounting principles. SCE will adopt FSP FAS No. 142-3 on January 1, 2009. SCE is currently evaluating the impact, if any, that the adoption of this position could have on its consolidated financial statements.

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.



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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 is subject to approval of the CPUC which SCE requested on April 4, 2008. CPUC approval is expected to be granted by late 2008. As an affiliate transaction, the contract is also subject to FERC approval,
which was requested on May 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.

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. In the first three months of 2008, SCE purchased the remaining $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.

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 June 30, 2008, the outstanding short-term debt was $800 million at a weighted-average interest rate of 2.58%. This short-term debt is supported by a $2.5 billion credit line. See below in
Credit Agreement Amendment.

Credit Agreement Amendment

On March 12, 2008, SCE amended its existing 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, will result in a final termination in February 2017. At June 30, 2008, the $2.5 billion credit facility supported $197 million in letters of credit and $800 million of short-term debt
outstanding, leaving $1.5 billion available for liquidity purposes.

Note 3. Income Taxes

SCEs composite federal and state statutory income tax rate was approximately 40% (net of the federal benefit for state income taxes) for all periods presented.
SCEs effective tax rate was 15% and 25% for the three- and six-month periods ended June 30, 2008, as compared to 28% and 25% for the respective periods in 2007. The



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lower effective tax rates in 2008, as compared to the statutory rate and between comparable periods, were primarily due to internally developed software and
property related flow-through tax deductions recorded in 2008. The lower effective tax rates in 2008, as compared to 2007, were partially offset by reductions during 2007, as discussed below. The effective tax rates in 2007 were lower than the
statutory rate primarily due to progress made in the first quarter of 2007 in an administrative appeal process with the IRS related to the income tax treatment of certain costs associated with environmental remediation; reductions made during the
second quarter of 2007 to reflect receipt of a state Notice of Proposed Adjustment; and also due to property related flow-through items.

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 Tabular
Disclosure

The following table provides a reconciliation of unrecognized tax benefits from January 1, 2008 to June 30, 2008:



|                                                           |  |             |       |  
|---------------------------------------------------------- |  | ----------- | ----- | -
|In millions                                                |  | (Unaudited) |      
|Balance at January 1, 2008                                 |  | $           | 1,950 |  
|Tax positions taken during the current year                |  |             |       |  
|Increases                                                  |  |             | 53    |  
|Decreases                                                  |  |             |      |  
|Tax positions taken during a prior year                    |  |             |       |  
|Increases                                                  |  |             | 85    |  
|Decreases                                                  |  |             | (97   | )
|Decreases for settlements during the period                |  |             |      |  
|Reductions for lapses of applicable statute of limitations |  |             |      |  
|Balance at June 30, 2008                                   |  | $           | 1,991 |  

The unrecognized tax benefits in the table above reflects affirmative claims related to timing differences of
$1.5 billion and $1.6 billion at June 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 is vigorously defending these affirmative claims in IRS administrative appeals proceedings.

It is reasonably possible that Edison International could reach a settlement with the IRS for all or a portion of the 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 June 30, 2008 and January 1, 2008
that, if recognized, would have an effective tax rate impact is $62 million and $65 million, respectively.

The total amount of accrued interest
and penalties were $111 million and $96 million as of June 30, 2008 and January 1, 2008, respectively. The after-tax interest expense recognized and included in income tax expense was $3 million and $9 million for the
three- and six- month periods ended June 30, 2008, respectively.



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Tax Positions being addressed as part of active examinations and administrative appeals processes

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  2002. 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.

Most of these tax positions relate to timing differences and, therefore, any amounts that would be paid if
Edison Internationals position is not sustained (exclusive of any penalties) 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 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 has been engaged in settlement negotiations with the IRS. These negotiations seek to resolve outstanding tax disputes for
all Edison International subsidiaries, including SCE, for the years 1994 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 resolving such tax disputes on a global basis. Final resolution of such disputes, however, is subject to reaching definitive agreements on final terms and
calculations, mutually satisfactory documentation, and review of all or a portion of such settlements by the Staff of the Joint Committee on Taxation, a committee of the United States Congress (the Joint Committee).

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, even if
final settlements are reached with the IRS, review by the Joint Committee could result in adjustments. 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 related to balancing account over-collections, Edison International received an IRS Notice of Proposed Adjustment in July 2007. This
affirmative claim is part of the ongoing IRS examinations and administrative appeals process and all of the tax years included in this Notice of Proposed Adjustment remain subject to ongoing examination and administrative appeals. The cash and
earnings impacts of this position are dependent on the ultimate settlement of all open tax issues in these tax years. SCE expects that resolution of this particular 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  1998. This is being considered by the Administrative Appeals branch of the IRS where Edison International is defending its tax return position with respect to this transaction.

Resolution of Federal and State Income Tax Issues Being Addressed in Ongoing Examinations and Administrative Appeals

Edison International continues its efforts to resolve open tax issues through tax year 2002. 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 June 30, 2008, SCE has made $6 million in contributions related to 2007 and $24 million related to 2008 and estimates to make $13 million of additional contributions in the last six months of
2008. Expected contribution funding could vary from anticipated amounts depending on the funded status at year-end and tax-deductible funding limitations.

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

Expense components are:



|                                   |  |                            |   |  |                          |   |  |       |   |  |       |  
|---------------------------------- |  | -------------------------- | - |  | ------------------------ | - |  | ----- | - |  | ----- | -
|                                   |  | Three Months EndedJune 30, |   |  | Six Months EndedJune 30, |  
|In millions                        |  | 2008                       |   |  | 2007                     |   |  | 2008  |   |  | 2007  |  
|                                   |  | (Unaudited)                |  
|Service cost                       |  | $  27                      |   |  | $  26                    |   |  | $  54 |   |  | $  52 |  
|Interest cost                      |  | 46                         |   |  | 44                       |   |  | 93    |   |  | 88    |  
|Expected return on plan assets     |  | (63                        | ) |  | (61                      | ) |  | (126  | ) |  | (122  | )
|Amortization of prior service cost |  | 4                          |   |  | 4                        |   |  | 8     |   |  | 9     |  
|Amortization of net (gain)/loss    |  |                           |   |  | 1                        |   |  | (1    | ) |  | 1     |  
|Subtotal                           |  | 14                         |   |  | 14                       |   |  | 28    |   |  | 28    |  
|Regulatory adjustment  deferred   |  |                           |   |  | 1                        |   |  |      |   |  | 2     |  
|Total expense recognized           |  | $  14                      |   |  | $  15                    |   |  | $  28 |   |  | $  30 |  

Postretirement Benefits Other Than Pensions

As of June 30, 2008, SCE has made no contributions related to 2007 and $11 million related to 2008 and estimates to make $43 million of additional
contributions in the last six months of 2008. Expected contribution funding could vary from anticipated amounts depending on the funded status at year-end and tax-deductible funding limitations.



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Expense components are:



|                                     |  |                            |   |  |                          |   |  |      |     |   |      |   |     |  
|------------------------------------ |  | -------------------------- | - |  | ------------------------ | - |  | ---- | --- | - | ---- | - | --- | -
|                                     |  | Three Months EndedJune 30, |   |  | Six Months EndedJune 30, |  
|In millions                          |  | 2008                       |   |  | 2007                     |   |  | 2008 |     |   | 2007 |  
|                                     |  | (Unaudited)                |  
|Service cost                         |  | $  11                      |   |  | $  10                    |   |  | $    | 22  |   |      | $ | 20  |  
|Interest cost                        |  | 33                         |   |  | 31                       |   |  |      | 66  |   |      |   | 62  |  
|Expected return on plan assets       |  | (31                        | ) |  | (30                      | ) |  |      | (62 | ) |      |   | (60 | )
|Amortization of prior service credit |  | (7                         | ) |  | (7                       | ) |  |      | (14 | ) |      |   | (14 | )
|Amortization of net loss             |  | 4                          |   |  | 6                        |   |  |      | 8   |   |      |   | 12  |  
|Total expense recognized             |  | $  10                      |   |  | $  10                    |   |  | $    | 20  |   |      | $ | 20  |  

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 $5 million and $11 million for the three months ended June 30, 2008 and 2007,
respectively, and was $10 million and $14 million for the six months ended June 30, 2008 and 2007, respectively. The income tax benefit recognized in the consolidated statements of income was $2 million and $4 million for
the three months ended June 30, 2008 and 2007, respectively, and was $4 million and $6 million for the six months ended June 30, 2008 and 2007, respectively. Total stock-based compensation cost capitalized was $1 million and
$2 million for the three months ended June 30, 2008 and 2007, respectively, and was $2 million and $3 million for the six months ended June 30, 2008 and 2007, respectively.

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                                      |  | 1,288,070    |   |  | $                | 50.01 |                                  |      |                         |   |            
|Expired                                      |  | (500         | ) |  | $                | 28.94 |                                  |      |                         |   |            
|Forfeited                                    |  | (60,583      | ) |  | $                | 48.75 |                                  |      |                         |   |            
|Exercised                                    |  | (361,981     | ) |  | $                | 25.38 |                                  |      |                         |   |            
|Transfer to associate                        |  | (91,569      | ) |  | $                | 34.78 |                                  |      |                         |   |            
|Outstanding at June 30, 2008                 |  | 7,033,821    |   |  | $                | 34.76 |                                  | 6.69 |                         |   |            
|Vested and expected to vest at June 30, 2008 |  | 6,769,460    |   |  | $                | 34.31 |                                  | 6.62 |                         | $ | 116,028,544
|Exercisable at June 30, 2008                 |  | 4,117,169    |   |  | $                | 26.99 |                                  | 5.44 |                         | $ | 100,705,954

Stock options granted in 2008 do not accrue dividend equivalents.

The amount of cash used to settle stock options exercised was $10 million and $54 million for the three months ended June 30, 2008 and 2007, respectively,
and $19 million and $104 million for the six months ended June 30, 2008 and 2007, respectively. Cash received from options exercised was $5 million and $23 million for the three months ended June 30, 2008 and 2007,
respectively, and $9 million and $47 million for the six months ended



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June 30, 2008 and 2007, respectively. The estimated tax benefit from options exercised was $2 million and $13 million for the three months
ended June 30, 2008 and 2007, respectively, and $4 million and $23 million for the six months ended June 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 40 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  $27 million, 2009 
$48 million, 2010  $48 million, 2011  $48 million, 2012  $48 million and thereafter  $1.9 billion.

Other Commitments

During the first six 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: remainder of 2008  $15 million, 2009  $49 million, 2010  $50 million, 2011  $96 million, 2012
 $141 million and thereafter  $665 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.



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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.

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 June 30, 2008, SCEs recorded estimated minimum liability to remediate its 24 identified sites was $59 million, of which $24 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 $155 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 $33 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



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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 $56 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 June 30, 2008 were $25 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

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. On August 1, 2008, SCE filed a revision to its Transmission Owner Tariff with a requested effective date of October 1, 2008. 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.

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 single-issue
rate adjustment ($45 million or a 14.4% increase) to SCEs currently authorized base transmission revenue



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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). SCE projects that it 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.

Investigations Regarding Performance Incentives Rewards

SCE was eligible under its CPUC-approved PBR mechanism to
earn rewards or penalties based on its performance in comparison to CPUC-approved standards of customer satisfaction, employee injury and illness reporting, and system reliability. SCE conducted investigations into its performance under these PBR
mechanisms and has reported to the CPUC certain findings of misconduct and misreporting as further discussed below.

Customer Satisfaction

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

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

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



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Employee Injury and Illness Reporting

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

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

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

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

System Reliability

In light of the problems uncovered with the PBR
mechanisms discussed above, SCE conducted an investigation into the third PBR metric, system reliability for the years 1997  2003. SCE received $8 million in reliability incentive awards for the period 1997  2000 and
applied for a reward of $5 million for 2001. For 2002, SCEs data indicated that it earned no reward and incurred no penalty. For 2003, based on the application of the PBR mechanism, it would incur a penalty of $3 million and accrued
a charge for that amount in 2004. On February 28, 2005, SCE provided its final investigation report to the CPUC concluding that the reliability reporting system was working as intended.

CPUC Investigation

On June 15, 2006, the CPUC instituted a
formal investigation to determine whether and in what amounts to order refunds or disallowances of past and potential PBR rewards for customer satisfaction, employee safety and system reliability portions of PBR. In June 2006, the CPSD of the CPUC
issued its report regarding SCEs PBR program, recommending that the CPUC impose various refunds and penalties on SCE. Subsequently, in September 2006, the CPSD and other intervenors, such as the CPUCs DRA and The Utility Reform Network,
filed testimony on these matters recommending various refunds and penalties be imposed on SCE. In their testimony, the various parties made refund and penalty recommendations that range up to the following amounts: refund or forgo $48 million
in rewards for customer satisfaction, impose $70 million in penalties for customer satisfaction, refund or forgo $35 million in rewards for employee safety, impose $35 million in penalties for employee safety, impose $102 million
in statutory penalties, refund $84 million related to amounts collected in rates for employee bonuses (results sharing), refund $4 million of miscellaneous survey expenses, and require $10 million of new employee safety
programs. These recommendations total up to $388 million. On October 16, 2006, SCE filed testimony opposing the various refund and penalty recommendations of the CPSD and other intervenors.

On October 1, 2007, a POD was released ordering SCE to refund $136 million, before interest, and pay a statutory penalty of $40 million. Included in the
amount to be refunded are $28 million related to customer satisfaction rewards, $20 million related to employee safety rewards, and $77 million related to results sharing. The decision requires that the proposed results sharing refund
of $77 million (based on year 2000 data) be



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adjusted for attrition and escalation which increases the results sharing refund to $88 million. Interest as of June 30, 2008, based on amounts
collected for customer satisfaction, employee safety incentives and results sharing, including escalation and attrition adjustments, would add an additional $31 million to this amount. The POD also requires SCE to forgo $35 million in
rewards for which it would have otherwise been eligible. Included in the amount to be forgone is $20 million related to customer satisfaction rewards and $15 million related to employee safety rewards.

On October 31, 2007, SCE appealed the POD to the CPUC. The CPSD and an intervenor also filed appeals. The CPSD appeal requested that: (1) the statutory penalty
be increased from $40 million to $83 million (2) a penalty be imposed under the PBR customer satisfaction and employee safety mechanisms in the amount of $48 million and $35 million, respectively, and (3) SCE
refund/forgo rewards earned under the customer satisfaction and employee safety mechanisms of $48 million and $35 million, respectively. The appealing intervenor asked that the statutory penalty be increased to as much as
$102 million. Oral argument on the appeals took place on January 30, 2008, and it is uncertain when the CPUC will issue a decision.

SCE cannot
predict the outcome of the appeal. Based on SCEs proposed refunds, the combined recommendations of the CPSD and other intervenors, as well as the POD, the potential refunds and penalties could range from $52 million up to
$388 million. SCE has recorded an accrual at the lower end of this range of potential loss and is accruing interest (approximately $17 million as of June 30, 2008) on collected amounts.

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

ISO Disputed Charges

On April 20, 2004,
the FERC issued an order concerning a dispute between the ISO and the Cities of Anaheim, Azusa, Banning, Colton and Riverside, California over the proper allocation and characterization of certain transmission service related charges. 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 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.



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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.

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 May 13, 2008, the U.S. Government filed a petition seeking review by the U.S. Supreme Court of the Federal Circuits September 2007 decision. The Navajo
Nations response to the petition was due on August 4, 2008.

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



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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 $10.8 billion. SCE and other owners of San Onofre and Palo Verde have purchased the maximum private primary insurance available ($300 million). The balance is covered by the industrys retrospective rating plan that
uses deferred premium charges to every reactor licensee if a nuclear incident at any licensed reactor in the United States results in claims and/or costs which exceed the primary insurance at that plant site.

Federal regulations require this secondary level of financial protection. The NRC exempted San Onofre Unit 1 from this secondary level, effective June 1994. The
current maximum deferred premium for each nuclear incident is approximately $101 million per reactor, but not more than $15 million per reactor may be charged in any one year for each incident. The maximum deferred premium per reactor and
the yearly assessment per reactor for each nuclear incident will be adjusted for inflation at least once every five years beginning August 20, 2003. The next inflation adjustment should occur no later than August 20, 2008. Based on its
ownership interests, SCE could be required to pay a maximum of approximately $201 million per nuclear incident. However, it would have to pay no more than approximately $30 million per incident in any one year. Such amounts include a 5%
surcharge if additional funds are needed to satisfy public liability claims and are subject to adjustment for inflation. If the public liability limit above is insufficient, federal 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 Outage and Inspection

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.



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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 compliance report in March 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 2010. 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 failure 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 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. SCE filed a refund report with the FERC on March 4, 2008. FERC approved the refund report on July 8, 2008.

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



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(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.

Note 6. Supplemental Cash Flows Information

SCEs supplemental cash flows information is:



|                                                                   |  |                          |     |      |   |     |  
|------------------------------------------------------------------ |  | ------------------------ | --- | ---- | - | --- | -
|                                                                   |  | Six Months EndedJune 30, |    
|In millions                                                        |  | 2008                     |     | 2007 |  
|                                                                   |  | (Unaudited)              |    
|Cash payments for interest and taxes:                              |  |                          |     |      |   |     |  
|Interest  net of amounts capitalized                              |  | $                        | 139 |      | $ | 141 |  
|Tax payments (receipts)                                            |  |                          | 46  |      |   | (18 | )
|                                                                   |  |                         
|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  |      |   | 13  |  

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.

The standard establishes a hierarchy for fair value measurements. Financial assets and liabilities carried at fair value on a recurring basis are classified and disclosed in the three categories outlined below:



| |  | Level 1  Observable inputs that reflect quoted market prices (unadjusted) for identical assets and liabilities in active markets;
|- |  | ----------------------------------------------------------------------------------------------------------------------------------



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| |  | Level 2  Inputs other than quoted market prices included in Level 1 that are observable for the asset or liability either directly or indirectly; and
|- |  | ------------------------------------------------------------------------------------------------------------------------------------------------------



| |  | Level 3  Unobservable inputs using data that is not corroborated by market data and primarily based on internal company analysis.
|- |  | ----------------------------------------------------------------------------------------------------------------------------------

SCEs assets and liabilities carried at fair value primarily consist of derivative positions. These positions may include forward
sales and purchases of physical power, options and forward price swaps which settle only on a financial basis (including futures contracts). In assessing the fair value of SCEs derivative financial instruments, SCE uses quoted market prices
and forward market prices adjusted for credit risk. The fair value of commodity price contracts takes into account quoted market prices, time value of money, volatility of the underlying commodities and other factors. In addition, the nuclear
decommissioning trust investments include equity securities, U.S. treasury securities and other fixed income securities.

Level 1 includes the nuclear
decommissioning trust investments in equity and U.S. treasury securities. The fair values for equity securities are determined using quoted exchange transaction market prices. U.S. treasury securities are categorized as Level 1 because they trade in
a highly liquid and transparent market.

Level 2 includes traded derivatives using over-the-counter markets and exchange traded derivatives not
classified as Level 1. The fair value of these derivatives is determined using forward market prices adjusted for credit risk. Level 2 also includes the nuclear decommissioning trust investments in other fixed income securities. The fair value of
these financial instruments is based on evaluated prices that reflect observable market information, such as actual trade information of similar securities, adjusted for observable differences.

Level 3 includes the majority of SCEs derivatives, including over-the-counter options, bilateral contracts, FTRs and CRRs in the California market, capacity
and QF contracts. The fair value of these derivatives is determined using uncorroborated broker quotes and models that mainly extrapolate short-term observable inputs. Level 3 also includes derivatives that trade infrequently such as FTRs and
over-the-counter derivatives at illiquid locations and long-term power agreements. For illiquid FTRs, 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 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 and 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.

When appropriate, valuations are adjusted for various factors including liquidity, bid/offer spreads and credit considerations. Such
adjustments are generally based on available market evidence. In the absence of such evidence, managements best estimate is used.



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



|                                  |  |             |       |   |         |   |         |  |   |                          |   |  |                       |     |   |  |   |       |  
|--------------------------------- |  | ----------- | ----- | - | ------- | - | ------- |  | - | ------------------------ | - |  | --------------------- | --- | - |  | - | ----- | -
|In millions                       |  | Level 1     |       |   | Level 2 |   | Level 3 |  |   | Netting andCollateral(1) |   |  | Total atJune 30, 2008 |    
|                                  |  | (Unaudited) |      
|Assets at Fair Value              |  |             |       |   |         |   |         |  |   |                          |   |  |                       |     |   |  |   |       |  
|Derivative contracts              |  | $           |      |   |         | $ | 291     |  | $ | 304                      |   |  | $                     | (20 | ) |  | $ | 575   |  
|Nuclear decommissioning trusts(2) |  |             | 2,080 |   |         |   | 997     |  |   |                         |   |  |                       |    |   |  |   | 3,077 |  
|Long-term disability plan         |  |             |      |   |         |   | 6       |  |   |                         |   |  |                       |    |   |  |   | 6     |  
|Total assets(3)                   |  |             | 2,080 |   |         |   | 1,294   |  |   | 304                      |   |  |                       | (20 | ) |  |   | 3,658 |  
|Liabilities at Fair Value         |  |             |       |   |         |   |         |  |   |                          |   |  |                       |     |   |  |   |       |  
|Derivative contracts              |  |             | (2    | ) |         |   |        |  |   | (39                      | ) |  |                       | 2   |   |  |   | (39   | )
|Net assets (liabilities)          |  | $           | 2,078 |   |         | $ | 1,294   |  | $ | 265                      |   |  | $                     | (18 | ) |  | $ | 3,619 |  

|(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) | Excludes net assets of $75 million of cash and equivalents, interest and dividend receivables and receivables related to pending securities sales and payables related to
pending securities purchases.
|--- | -------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------



|(3) | Excludes $32 million of cash surrender value of life insurance investments for deferred compensation.
|--- | -----------------------------------------------------------------------------------------------------

The following table sets forth a summary of changes in the fair value of Level 3 derivative contracts, net for the six months ended June 30, 2008.



|                                                                                                           |  |                                 |     |                               |   |     |  
|---------------------------------------------------------------------------------------------------------- |  | ------------------------------- | --- | ----------------------------- | - | --- | -
|In millions                                                                                                |  | Three Months EndedJune 30, 2008 |     | Six Months EndedJune 30, 2008 |  
|                                                                                                           |  | (Unaudited)                     |    
|Fair value of derivative contracts, net at beginning of period                                             |  | $                               | 79  |                               | $ | (22 | )
|Total realized/unrealized gains:                                                                           |  |                                 |     |                               |   |     |  
|Included in earnings(1)                                                                                    |  |                                 | 112 |                               |   | 165 |  
|Included in accumulated other comprehensive loss                                                           |  |                                 |    |                               |   |    |  
|Purchases and settlements, net                                                                             |  |                                 | 74  |                               |   | 122 |  
|Transfers in or out of Level 3                                                                             |  |                                 |    |                               |   |    |  
|Fair value of derivative contracts, net at end of period                                                   |  | $                               | 265 |                               | $ | 265 |  
|Change during the period in unrealized gains related to net derivative contracts, held at
June 30, 2008(2) |  | $                               | 149 |                               | $ | 176 |  

|(1) | $112 million and $165 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 six-month periods ended June 30, 2008, respectively.
|--- | ---------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------



|(2) | $149 million and $176 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 six-month periods ended June 30, 2008, respectively.
|--- | ---------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------



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Nuclear Decommissioning Trusts

SCE has collected 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 |  | June 30, 2008 |       | December 31,2007
|                                |  |               |  | (Unaudited)   |       |                 
|Municipal bonds                 |  | 2008  2044   |  | $             | 570   |                  | $ | 561  
|Stocks                          |  |              |  |               | 1,841 |                  |   | 1,968
|United States government issues |  | 2008  2049   |  |               | 362   |                  |   | 552  
|Corporate bonds                 |  | 2008  2047   |  |               | 304   |                  |   | 241  
|Short-term                      |  | 2008          |  |               | 75    |                  |   | 56   
|Total                           |  |               |  | $             | 3,152 |                  | $ | 3,378

Note: Maturity dates as of June 30, 2008.

Trust fund earnings (based on specific identification) increase the trust fund balance and the ARO regulatory liability. Net earnings were $26 million and $34 million for the three months ended June 30,
2008 and 2007, respectively, and $57 million and $71 million for the six months ended June 30, 2008 and 2007, respectively. Proceeds from sales of securities (which are reinvested) were $668 million and $987 million for the
three months ended June 30, 2008 and 2007, respectively, and $1.5 billion and $2.0 billion for the six months ended June 30, 2008 and 2007, respectively. Cumulative unrealized holding gains, net of losses, were $950 million
and $1.1 billion at June 30, 2008 and December 31, 2007, respectively. Realized losses for other-than-temporary impairments were $27 million and $15 million for the three months ended June 30, 2008 and 2007,
respectively, and $72 million and $23 million for the six months ended June 30, 2008 and 2007, respectively. Approximately 92% of the cumulative trust fund contributions were tax-deductible.



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Note 8. Regulatory Assets and Liabilities

Regulatory assets included in the consolidated balance sheets are:



|                                                             |  |              |       |                  |   |      
|------------------------------------------------------------ |  | ------------ | ----- | ---------------- | - | -----
|In millions                                                  |  | June 30,2008 |       | December 31,2007
|                                                             |  | (Unaudited)  |       |                 
|Current:                                                     |  |              |       |                  |   |      
|Regulatory balancing accounts                                |  | $            | 167   |                  | $ | 99   
|Energy derivatives                                           |  |              | 8     |                  |   | 71   
|Purchased-power settlements                                  |  |              | 4     |                  |   | 8    
|Deferred FTR proceeds                                        |  |              | 12    |                  |   | 15   
|Other                                                        |  |              | 12    |                  |   | 4    
|                                                             |  |              | 203   |                  |   | 197  
|Long-term:                                                   |  |              |       |                  |   |      
|Regulatory balancing accounts                                |  |              | 11    |                  |   | 15   
|Flow-through taxes  net                                     |  |              | 1,155 |                  |   | 1,110
|Unamortized nuclear investment  net                         |  |              | 391   |                  |   | 405  
|Nuclear-related asset retirement obligation investment  net |  |              | 287   |                  |   | 297  
|Unamortized coal plant investment  net                      |  |              | 83    |                  |   | 94   
|Unamortized loss on reacquired debt                          |  |              | 320   |                  |   | 331  
|SFAS No. 158 pensions and postretirement benefits            |  |              | 237   |                  |   | 231  
|Energy derivatives                                           |  |              | 61    |                  |   | 70   
|Environmental remediation                                    |  |              | 56    |                  |   | 64   
|Other                                                        |  |              | 122   |                  |   | 104  
|                                                             |  |              | 2,723 |                  |   | 2,721
|Total Regulatory Assets                                      |  | $            | 2,926 |                  | $ | 2,918

Regulatory liabilities included in the consolidated balance sheets are:



|                                                        |  |               |       |                  |   |      
|------------------------------------------------------- |  | ------------- | ----- | ---------------- | - | -----
|In millions                                             |  | June 30, 2008 |       | December 31,2007
|                                                        |  | (Unaudited)   |       |                 
|Current:                                                |  |               |       |                  |   |      
|Regulatory balancing accounts                           |  | $             | 895   |                  | $ | 967  
|Rate reduction notes  transition cost overcollection   |  |               | 20    |                  |   | 20   
|Energy derivatives                                      |  |               | 248   |                  |   | 10   
|Deferred FTR costs                                      |  |               | 56    |                  |   | 19   
|Other                                                   |  |               | 4     |                  |   | 3    
|                                                        |  |               | 1,223 |                  |   | 1,019
|Long-term:                                              |  |               |       |                  |   |      
|Regulatory balancing accounts                           |  |               | 7     |                  |   |     
|Asset retirement obligations                            |  |               | 502   |                  |   | 793  
|Costs of removal                                        |  |               | 2,256 |                  |   | 2,230
|SFAS No. 158 pensions and other postretirement benefits |  |               | 314   |                  |   | 308  
|Energy derivatives                                      |  |               | 202   |                  |   | 27   
|Employee benefit plans                                  |  |               | 75    |                  |   | 75   
|                                                        |  |               | 3,356 |                  |   | 3,433
|Total Regulatory Liabilities                            |  | $             | 4,579 |                  | $ | 4,452



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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.

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 June 30, 2008:     |  |                 |        |      |   |              |  |   |     |   |  |   |       
|Cash and equivalents                         |  | $               | 73     |      | $ | 112          |  | $ |    |   |  | $ | 185   
|Accounts receivable  net                    |  |                 | 760    |      |   | 140          |  |   | (89 | ) |  |   | 811   
|Inventory                                    |  |                 | 303    |      |   | 14           |  |   |    |   |  |   | 317   
|Nonutility property  net of depreciation    |  |                 | 685    |      |   | 299          |  |   |    |   |  |   | 984   
|Total assets                                 |  |                 | 28,124 |      |   | 565          |  |   | (89 | ) |  |   | 28,600
|Accounts payable                             |  |                 | 944    |      |   | 96           |  |   | (89 | ) |  |   | 951   
|Other current liabilities                    |  |                 | 514    |      |   | 6            |  |   |    |   |  |   | 520   
|Asset retirement obligations                 |  |                 | 2,919  |      |   | 15           |  |   |    |   |  |   | 2,934 
|Minority interest                            |  |                 |       |      |   | 448          |  |   |    |   |  |   | 448   
|Total liabilities and shareholders equity   |  | $               | 28,124 |      | $ | 565          |  | $ | (89 | ) |  | $ | 28,600
|                                             |  |                 |        |     
|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



26



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



|                                                                |  |                 |       |   |      |   |     |               |  |   |      |   |  |   |       |  
|--------------------------------------------------------------- |  | --------------- | ----- | - | ---- | - | --- | ------------- |  | - | ---- | - |  | - | ----- | -
|In millions                                                     |  | ElectricUtility |       |   | VIEs |   |     | Eliminations* |  |   | SCE  |  
|                                                                |  | (Unaudited)     |      
|Income Statement Items for the Three Months EndedJune 30, 2008: |  |                 |       |   |      |   |     |               |  |   |      |   |  |   |       |  
|Operating revenue                                               |  | $               | 2,638 |   |      | $ | 326 |               |  | $ | (209 | ) |  | $ | 2,755 |  
|Fuel                                                            |  |                 | 149   |   |      |   | 248 |               |  |   |     |   |  |   | 397   |  
|Purchased power                                                 |  |                 | 865   |   |      |   |    |               |  |   | (209 | ) |  |   | 656   |  
|Provisions for regulatory adjustment clauses  net              |  |                 | 279   |   |      |   |    |               |  |   |     |   |  |   | 279   |  
|Other operation and maintenance                                 |  |                 | 735   |   |      |   | 22  |               |  |   |     |   |  |   | 757   |  
|Depreciation, decommissioning and amortization                  |  |                 | 278   |   |      |   | 8   |               |  |   |     |   |  |   | 286   |  
|Property and other taxes                                        |  |                 | 56    |   |      |   |    |               |  |   |     |   |  |   | 56    |  
|Net gain on sale of assets                                      |  |                 | (7    | ) |      |   |    |               |  |   |     |   |  |   | (7    | )
|Total operating expenses                                        |  |                 | 2,355 |   |      |   | 278 |               |  |   | (209 | ) |  |   | 2,424 |  
|Operating income                                                |  |                 | 283   |   |      |   | 48  |               |  |   |     |   |  |   | 331   |  
|Interest income                                                 |  |                 | 4     |   |      |   | 1   |               |  |   |     |   |  |   | 5     |  
|Other nonoperating income                                       |  |                 | 23    |   |      |   | 2   |               |  |   |     |   |  |   | 25    |  
|Interest expense  net of amounts capitalized                   |  |                 | (96   | ) |      |   |    |               |  |   |     |   |  |   | (96   | )
|Other nonoperating deductions                                   |  |                 | (14   | ) |      |   |    |               |  |   |     |   |  |   | (14   | )
|Income tax expense                                              |  |                 | (30   | ) |      |   |    |               |  |   |     |   |  |   | (30   | )
|Minority interest                                               |  |                 |      |   |      |   | (51 | )             |  |   |     |   |  |   | (51   | )
|Net income                                                      |  | $               | 170   |   |      | $ |    |               |  | $ |     |   |  | $ | 170   |  
|                                                                |  |                 |       |  
|Income Statement Items for the Three Months EndedJune 30, 2007: |  |                 |       |   |      |   |     |               |  |   |      |   |  |   |       |  
|Operating revenue                                               |  | $               | 2,349 |   |      | $ | 308 |               |  | $ | (197 | ) |  | $ | 2,460 |  
|Fuel                                                            |  |                 | 98    |   |      |   | 187 |               |  |   |     |   |  |   | 285   |  
|Purchased power                                                 |  |                 | 1,026 |   |      |   |    |               |  |   | (197 | ) |  |   | 829   |  
|Provisions for regulatory adjustment clauses  net              |  |                 | (33   | ) |      |   |    |               |  |   |     |   |  |   | (33   | )
|Other operation and maintenance                                 |  |                 | 640   |   |      |   | 21  |               |  |   |     |   |  |   | 661   |  
|Depreciation, decommissioning and amortization                  |  |                 | 262   |   |      |   | 9   |               |  |   |     |   |  |   | 271   |  
|Property and other taxes                                        |  |                 | 55    |   |      |   |    |               |  |   |     |   |  |   | 55    |  
|Total operating expenses                                        |  |                 | 2,048 |   |      |   | 217 |               |  |   | (197 | ) |  |   | 2,068 |  
|Operating income                                                |  |                 | 301   |   |      |   | 91  |               |  |   |     |   |  |   | 392   |  
|Interest income                                                 |  |                 | 10    |   |      |   |    |               |  |   |     |   |  |   | 10    |  
|Other nonoperating income                                       |  |                 | 25    |   |      |   |    |               |  |   |     |   |  |   | 25    |  
|Interest expense  net of amounts capitalized                   |  |                 | (105  | ) |      |   |    |               |  |   |     |   |  |   | (105  | )
|Other nonoperating deductions                                   |  |                 | (13   | ) |      |   |    |               |  |   |     |   |  |   | (13   | )
|Income tax expense                                              |  |                 | (61   | ) |      |   |    |               |  |   |     |   |  |   | (61   | )
|Minority interest                                               |  |                 |      |   |      |   | (91 | )             |  |   |     |   |  |   | (91   | )
|Net income                                                      |  | $               | 157   |   |      | $ |    |               |  | $ |     |   |  | $ | 157   |  

|* | 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 Six Months EndedJune 30, 2008: |  |                 |       |   |      |   |      |               |  |   |      |   |  |   |       |  
|Operating revenue                                             |  | $               | 4,891 |   |      | $ | 575  |               |  | $ | (360 | ) |  | $ | 5,106 |  
|Fuel                                                          |  |                 | 306   |   |      |   | 440  |               |  |   |     |   |  |   | 746   |  
|Purchased power                                               |  |                 | 1,509 |   |      |   |     |               |  |   | (360 | ) |  |   | 1,149 |  
|Provisions for regulatory adjustment clauses  net            |  |                 | 452   |   |      |   |     |               |  |   |     |   |  |   | 452   |  
|Other operation and maintenance                               |  |                 | 1,380 |   |      |   | 55   |               |  |   |     |   |  |   | 1,435 |  
|Depreciation, decommissioning and amortization                |  |                 | 522   |   |      |   | 17   |               |  |   |     |   |  |   | 539   |  
|Property and other taxes                                      |  |                 | 118   |   |      |   |     |               |  |   |     |   |  |   | 118   |  
|Net gain on sale of assets                                    |  |                 | (8    | ) |      |   |     |               |  |   |     |   |  |   | (8    | )
|Total operating expenses                                      |  |                 | 4,279 |   |      |   | 512  |               |  |   | (360 | ) |  |   | 4,431 |  
|Operating income                                              |  |                 | 612   |   |      |   | 63   |               |  |   |     |   |  |   | 675   |  
|Interest income                                               |  |                 | 8     |   |      |   | 2    |               |  |   |     |   |  |   | 10    |  
|Other nonoperating income                                     |  |                 | 42    |   |      |   | 2    |               |  |   |     |   |  |   | 44    |  
|Interest expense  net of amounts capitalized                 |  |                 | (193  | ) |      |   |     |               |  |   |     |   |  |   | (193  | )
|Other nonoperating deductions                                 |  |                 | (26   | ) |      |   |     |               |  |   |     |   |  |   | (26   | )
|Income tax expense                                            |  |                 | (111  | ) |      |   |     |               |  |   |     |   |  |   | (111  | )
|Minority interest                                             |  |                 |      |   |      |   | (67  | )             |  |   |     |   |  |   | (67   | )
|Net income                                                    |  | $               | 332   |   |      | $ |     |               |  | $ |     |   |  | $ | 332   |  
|                                                              |  |                 |       |  
|Income Statement Items for the Six Months EndedJune 30, 2007: |  |                 |       |   |      |   |      |               |  |   |      |   |  |   |       |  
|Operating revenue                                             |  | $               | 4,478 |   |      | $ | 568  |               |  | $ | (364 | ) |  | $ | 4,682 |  
|Fuel                                                          |  |                 | 221   |   |      |   | 374  |               |  |   |     |   |  |   | 595   |  
|Purchased power                                               |  |                 | 1,510 |   |      |   |     |               |  |   | (364 | ) |  |   | 1,146 |  
|Provisions for regulatory adjustment clauses  net            |  |                 | 255   |   |      |   |     |               |  |   |     |   |  |   | 255   |  
|Other operation and maintenance                               |  |                 | 1,215 |   |      |   | 47   |               |  |   |     |   |  |   | 1,262 |  
|Depreciation, decommissioning and amortization                |  |                 | 528   |   |      |   | 18   |               |  |   |     |   |  |   | 546   |  
|Property and other taxes                                      |  |                 | 110   |   |      |   |     |               |  |   |     |   |  |   | 110   |  
|Total operating expenses                                      |  |                 | 3,839 |   |      |   | 439  |               |  |   | (364 | ) |  |   | 3,914 |  
|Operating income                                              |  |                 | 639   |   |      |   | 129  |               |  |   |     |   |  |   | 768   |  
|Interest income                                               |  |                 | 21    |   |      |   |     |               |  |   |     |   |  |   | 21    |  
|Other nonoperating income                                     |  |                 | 41    |   |      |   |     |               |  |   |     |   |  |   | 41    |  
|Interest expense  net of amounts capitalized                 |  |                 | (213  | ) |      |   |     |               |  |   |     |   |  |   | (213  | )
|Other nonoperating deductions                                 |  |                 | (23   | ) |      |   |     |               |  |   |     |   |  |   | (23   | )
|Income tax expense                                            |  |                 | (114  | ) |      |   |     |               |  |   |     |   |  |   | (114  | )
|Minority interest                                             |  |                 |      |   |      |   | (129 | )             |  |   |     |   |  |   | (129  | )
|Net income                                                    |  | $               | 351   |   |      | $ |     |               |  | $ |     |   |  | $ | 351   |  

|* | 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 six-month periods ended June 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 six-month periods ended June 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 Edison Internationals current expectations and projections about future events based on
Edison Internationals knowledge of present facts and circumstances and assumptions about future events and include any statement that does not directly relate to a historical or current fact. Other information distributed by Edison
International that is incorporated in this report, or that refers to or incorporates this report, may also contain forward-looking statements. In this report and elsewhere, the words expects, believes,
anticipates, estimates, projects, intends, plans, probable, may, will, could, would, should, and variations of such
words and similar expressions, or discussions of strategy or of plans, are intended to identify forward-looking statements. Such statements necessarily involve risks and uncertainties that could cause actual results to differ materially from those
anticipated. Some of the risks, uncertainties and other important factors that could cause results to differ, or that otherwise could impact Edison International or its subsidiaries, include, but are not limited to:



| |  | the ability of SCE to meet its financial obligations and to pay dividends on its common stock if its subsidiaries are unable to pay dividends;
|- |  | ----------------------------------------------------------------------------------------------------------------------------------------------



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



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



| |  | market risks affecting SCEs energy procurement activities;
|- |  | -----------------------------------------------------------



| |  | access to capital markets and the cost of capital;
|- |  | --------------------------------------------------



| |  | changes in interest rates, rates of inflation 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;
|- |  | -----------------------------------------------------------------------------------------------------



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



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##### Table of Contents

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



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



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

Additional information about risks and
uncertainties, including more detail about the factors described above, are discussed throughout this MD&A and in the Risk Factors section included in Part I, Item 1A of SCEs 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 of most importance. 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.

2009 General Rate Case Proceeding

On November 19, 2007, SCE filed its GRC application and subsequently revised its requested 2009 base rate revenue requirement to $5.162 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 submitted testimony recommending 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, seeks to reduce SCEs 2009 request by an additional $195 million over the DRA proposed adjustments, mainly due to reduced depreciation expense. See Regulatory MattersCurrent Regulatory
Developments2009 General Rate Case Proceeding for further discussion.



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##### Table of Contents

2009 FERC Rate Case

On August 1, 2008, SCE filed a revision to its Transmission Owner Tariff with a requested effective date of October 1, 2008 to reflect a proposed $129 million increase in its retail transmission revenue requirements (or a 39%
increase over the current retail transmission revenue requirement). If the FERC approves this requested increase, this would amount to a 1.2% system average rate increase due to an increase in transmission capital-related costs as well as the
increases in transmission operating and maintenance expenses that SCE expects to incur in 2009 to maintain grid reliability. The proposed 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 is experiencing significant growth in actual and 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 over the period of the program (2008  2013). SCE proposes a reasonableness threshold of
$963 million. 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 for qualifying utility-owned renewable energy investments. SCE also requested to track costs spent on projects prior to the receipt of the CPUCs final decision in a memorandum
account for potential future recovery. SCE expects a decision on the memorandum account in the fourth quarter of 2008. SCE expects to continue to move forward with projects in advance of the final CPUC decision. Several parties have filed protests
to SCEs Solar PV program application. A scoping memorandum was issued on July 27, 2008 which identified issues to be addressed in the proceeding as well as set evidentiary hearings for November 2008 and a final decision for
March 2009. SCE cannot predict the final outcome of this proceeding.

Impacts on Customer Rates

Natural gas prices have significantly increased during 2008 over forecasted prices used to set current generation rate levels and are subject to considerable volatility
for the remainder of 2008 and in 2009. The increase in natural gas prices and the effect on power prices have, and are expected to continue to negatively impact SCEs ERRA balancing account which is expected to result in customer rate
increases. For further discussion of the ERRA regulatory matters and the impact on customer rates, see Regulatory MattersCurrent Regulatory DevelopmentsImpact of Regulatory Matters on Customer Rates and Regulatory
MattersCurrent Regulatory DevelopmentsEnergy Resource Recovery Account Proceedings.

Enterprise-Wide Software System Project

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



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LIQUIDITY

Overview

As of June 30, 2008, SCE had cash and equivalents of $185 million ($112 million of which was held by SCEs
consolidated VIEs). As of June 30, 2008, long-term debt, including current maturities of long-term debt, was $5.47 billion. 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, will result in a final termination in February 2017. At June 30, 2008, the credit facility
supported $197 million in letters of credit and $800 million of short-term debt outstanding, leaving $1.5 billion available for liquidity purposes.

SCEs estimated cash outflows during the 12-month period following June 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 two $100 million dividends which were paid in April 2008 and July 2008, respectively;
|- |  | ---------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------



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



| |  | General operating expenses.
|- |  | ---------------------------

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

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. Edison International 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 is experiencing significant growth in actual and
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 spending of up to $19.9 billion,
including capital spending for SCEs Solar PV Program. Recovery of certain of these expenditures is subject to regulatory approvals. During the three-and six-month periods ended June 30, 2008, SCE spent $608 million and
$1.17 billion, respectively, in capital expenditures related to its 2008 capital plan. SCE projected capital expenditures for the next five years are as follows: remainder of 2008  $1.7 billion, 2009  $4.1 billion, 2010
 $4.5 billion, 2011 $4.6 billion and 2012  $3.8 billion.



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##### Table of Contents

Credit Ratings

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

Dividend Restrictions and Debt Covenants

The CPUC regulates SCEs capital structure and limits the dividends it
may pay Edison International. In SCEs most recent cost of capital proceeding, the CPUC set an authorized capital structure for SCE which included a common equity component of 48%. SCE determines compliance with this capital structure based on
a 13-month weighted-average calculation. At June 30, 2008, SCEs 13-month weighted-average common equity component of total capitalization was 50.5% resulting in the capacity to pay $307 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 June 30, 2008,
SCEs debt to total capitalization ratio was 0.46 to 1.

Margin and Collateral Deposits

SCE has entered into certain margining agreements for power and gas trading activities in support of its procurement plan as approved by the CPUC. SCEs margin
deposit requirements under these agreements can vary depending upon the level of unsecured credit extended by counterparties and brokers, changes in market prices relative to contractual commitments, and other factors. During the first quarter of
2008, SCE implemented FIN 39-1 and elected the option to net collateral with the fair value of derivative assets/liabilities under master netting arrangements. Amounts recognized for cash collateral received from others that have been offset against
net derivative assets totaled $18 million at June 30, 2008. In addition, at June 30, 2008, SCE had deposits of $204 million (consisting of $7 million in cash that was not offset against net derivative positions and was
reflected in Margin and collateral deposits on the consolidated balance sheets and $197 million in letters of credit) with counterparties and other brokers. Cash deposits with brokers and counterparties earn interest at various
rates.

Future cash collateral requirements may be higher than the margin and collateral requirements at June 30, 2008, due to changes in wholesale
power and natural gas prices. SCE estimates that margin and collateral requirements for energy contracts outstanding as of June 30, 2008, could increase by approximately $555 million over the remaining life of the contracts using a 95%
confidence level.



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##### Table of Contents

The credit risk exposure from counterparties for power and gas trading activities are measured as the difference between
the contract price and current fair value of open positions. 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 June 30, 2008, the amount of exposure as described above, broken down by the credit ratings of SCEs counterparties, was as follows:



|                                     |  |              |    
|------------------------------------ |  | ------------ | ---
|In millions                          |  | June 30,2008
|S&P Credit Rating                    |  |              |    
|A or higher                          |  | $            | 114
|A-                                   |  |              | 12 
|BBB+                                 |  |              | 13 
|BBB                                  |  |              | 7  
|BBB-                                 |  |              |   
|Below investment grade and not rated |  |              | 112
|Total                                |  | $            | 258

SCE has tolling contracts in which SCE purchases the output of a plant from the counterparty. SCEs
structured transactions may be for multiple years which increases the volatility of the fair value position of the transaction. A number of the counterparties with which SCE has structured transactions do not currently have an investment grade
rating or are below investment grade. SCE seeks to mitigate this risk through diversification of its structured transactions, when available. Despite this, there can be no assurance that these efforts will be successful in mitigating credit risk
from contracts.

SCE requires that counterparties with below investment grade ratings or those that do not currently have an investment grade rating post
collateral. In the event of default by the counterparty, SCE would be able to use that collateral to pay for the commodity purchased or to pay the associated obligation in the event of default by the counterparty. Furthermore, all of the contracts
that SCE has entered into with counterparties are entered into under SCEs short-term and long-term procurement plan which has been approved by the CPUC. As a result, SCE would qualify for regulatory recovery for any defaults by counterparties
on these transactions. In addition, SCE closely monitors any changes that may affect the counterparties ability to perform.

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 operation.

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



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##### Table of Contents

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.
|- |  | ----------------------------------------------

SCE
expects to file an ERRA Trigger Application in the third quarter of 2008 due to higher gas and power prices than the forecast prices used to set current generation rate levels and expects to increase customer rates before year-end 2008.

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 application requested a 2009 base rate
revenue requirement of $5.199 billion. Hearings were completed in June 2008 and briefing is expected to be completed on August 8, 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 is $5.162 billion. After considering the effects of sales growth and other offsets, SCEs
revised request would be a $695 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 15.57% and 5.96%, respectively. The revised request would result in 2010 and 2011 base rate revenue requirement increases, net of sales growth, of $197 million and
$257 million, respectively. As a result of SCEs revised request, the DRAs recommended increase of approximately $19 million, which was submitted on April 15, 2008, now represents a difference of $676 million from
SCEs 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 revised request, TURNs
recommendation now seeks to reduce SCEs 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
stock during the intervening years between the cost of capital filings if certain thresholds are reached.



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##### Table of Contents

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, SCE is scheduled to file an advice letter in September 2008 requesting recovery of the earnings claim for the 2006 and 2007
timeframe, however, the timing of claims is linked to the completion of CPUC reports. The first progress payment, for SCEs 2006-2007 energy efficiency portfolio performance, will be based on a CPUC report scheduled to be complete in August
2008. SCE currently projects, based on preliminary results and through the advice letter process (see below for discussion of an alternative dispute resolution process), that it will record a progress payment in the range of $41 million to
$49 million in the fourth quarter of 2008 for the first two years (2006  2007) of the program cycle. Delays in the CPUC report expected in August 2008 could cause a delay in recognizing earnings for the progress payment.

On July 3, 2008, the Natural Resources Defense Council filed a request with the CPUC for an alternative dispute resolution process to address the
first interim earnings claim for the 2006-2008 energy efficiency program cycle. The alternative dispute resolution process may be requested by a party at any time and is a voluntary process which may be utilized by parties to ensure a timely
solution to cases. The alternative dispute resolution process could modify or negate the use of the advice letter process, including the results of the CPUC report expected in August 2008. Depending on the outcome of the alternative dispute
resolution process, the parties may revert to the advice letter process. Under the alternative dispute resolution process, the progress payment amount, as well as timing of recognition, may differ from SCEs current projection.

FERC Construction Work in Progress Mechanism

As discussed
under the headings Regulatory MattersCurrent Regulatory DevelopmentsFERC Transmission Incentives and FERC Construction Work in Progress Mechanism in the year-ended 2007 MD&A, 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 single-issue 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). SCE
projects that it 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.



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##### Table of Contents

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 June 30, 2008, the ERRA was undercollected by $95 million, which was 1.8% of SCEs prior years generation revenue. Based on a forecast of
procurement costs, SCEs ERRA balancing account is estimated to be undercollected by more than 5% by the end of August 2008, and 14.5% by the end of December 2008. This significant undercollection is due to higher gas and power prices than the
forecast prices used to set current generation rate levels. SCE expects to file an ERRA Trigger Application in the third quarter of 2008 and expects to increase customer rates before year-end 2008.

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 mid-2008, for the first four peaker plants, to approximately $261 million with additional projected costs for those peaker plants of approximately $2 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 June 30, 2008, SCE has incurred capital costs of
approximately $38 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 late 2008.

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 and continued the matter until at least October 2008.

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 compliance report in March 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 2010. 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 failure 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.



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California Proposition 7- Solar and Clean Energy Initiative

A renewable initiative has qualified for the November 4, 2008 California ballot that would impose a 50% Renewable Portfolio Standard (RPS) on all electric utilities
in the state, including investor-owned and municipally-owned utilities. The measure would set an RPS of 20% by 2010, 40% by 2020, and 50% by 2025. It would also reduce, but uncap, penalties for not meeting the annual RPS requirement. Additionally,
it would set the minimum price of renewable energy at market price and authorize purchases up to 10% above market price. The measure would also require utilities to sign 20-year bilateral agreements for offers meeting that threshold. Finally, it
would shift jurisdiction for setting a market price and permitting transmission from the CPUC to the CEC. The measure is opposed by a coalition of environmentalists, renewable power developers, labor, taxpayer groups, and utilities, and has not
received any significant endorsements among these sectors. It is also opposed by both political parties. While the fiscal impacts of the initiative are unknown at this time, SCE is evaluating them and is actively participating in the campaign
against the measure.

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, SCE received distributions of approximately $25 million on its allowed bankruptcy claim. Additional distributions are expected but SCE cannot currently predict the amount or timing of such distributions.

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.

Market Redesign Technology Upgrade

As
discussed under the heading Regulatory MattersMarket Redesign 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 MRTU was scheduled for implementation in the fall of 2008, however, the ISO recently announced a further delay beyond 2008. Discussions will be held in September 2008 to determine the timing of the MRTU
implementation.



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OTHER DEVELOPMENTS

Environmental Matters

SCE is subject to numerous federal and state environmental laws and regulations, which requires 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 their coal-fired plants, may be affected by recent
developments in federal and state environmental laws and regulations. These laws and regulations, including those relating to SO2and NOXemissions, mercury emissions, ozone and fine particulate matter emissions, regional haze, water quality, and climate change, may require significant capital
expenditures at these facilities. 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.

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, Edison International, 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
litigation.

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 is subject to public comment. CARB will consider adopting the proposed scoping plan in November 2008.



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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.

A renewable initiative that would impose a 50% RPS on all California electric utilities
has qualified for the November 2008 ballot (see Regulatory MattersCalifornia Proposition 7Solar and Clean Energy Initiative for further discussion).

Water Quality Regulation

Clean Water ActCooling Water Intake Structures

California

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 SONGS. 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 SONGS, 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 SONGS 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 June 30, 2008, SCEs recorded estimated minimum liability to remediate its 24 identified sites was
$59 million, of which $24 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
$155 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 $33 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 $56 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 June 30, 2008 were $25 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 and administrative appeals processes

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  2002. 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.

Most of these tax positions relate to timing differences and, therefore, any amounts that would be paid if Edison
Internationals position is not sustained (exclusive of any penalties) 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.



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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 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 has been engaged in settlement negotiations with the IRS. These negotiations seek to resolve outstanding tax disputes for
all Edison International subsidiaries, including SCE, for the years 1994 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 resolving such tax disputes on a
global basis. Final resolution of such disputes, however, is subject to reaching definitive agreements on final terms and calculations, mutually satisfactory documentation, and review of all or a portion of such settlements by the Staff
of the Joint Committee on Taxation, a committee of the United States Congress (the Joint Committee).

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, even if final settlements are reached with the IRS, review by the Joint Committee could result in adjustments. 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 related to balancing account
over-collections, Edison International received an IRS Notice of Proposed Adjustment in July 2007. This affirmative claim is part of the ongoing IRS examinations and administrative appeals process and all of the tax years included in this Notice of
Proposed Adjustment remain subject to ongoing examination and administrative appeals. The cash and earnings impacts of this position are dependent on the ultimate settlement of all open tax issues in these tax years. SCE expects that resolution of
this particular 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  1998. This is being considered by the Administrative Appeals branch of the
IRS where Edison International is defending its tax return position with respect to this transaction.

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



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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.

Palo Verde Nuclear Generating Station Outage and Inspection

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.

Priority Reserve Ruling

In July 2008, the Los Angeles Superior Court
found that actions taken by the South Coast Air Quality Management District in promulgating rules that had made available a Priority Reserve of emissions credits for new power generation projects did not satisfy California environmental
laws. SCE is in the process of evaluating the impact of the decision 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.



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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 expects to amortize and recover this amount as interest expense associated with its 2008 financings.

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 congestion rights (FTRs 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 FTRs. SCE participated in the ISO auction and paid $62 million to secure FTRs for the
period April 2008 through March 2009. The FTRs will be replaced with CRRs in the MRTU environment. SCE recognized the FTRs at fair value. SCE anticipates amounts paid for FTRs 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.

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
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offset through the provision for regulatory adjustment clausesnet; therefore, fair value changes do not affect earnings. Hedge accounting is not used
for these transactions due to this regulatory accounting treatment.

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



|                                                   |  |               |     |   |                   |   |    |        |  |             |    |  |   |    |  
|-------------------------------------------------- |  | ------------- | --- | - | ----------------- | - | -- | ------ |  | ----------- | -- |  | - | -- | -
|                                                   |  | June 30, 2008 |     |   | December 31, 2007 |  
|In millions                                        |  | Assets        |     |   | Liabilities       |   |    | Assets |  | Liabilities |   
|Energy options                                     |  | $             | 16  |   |                   | $ | 31 |        |  | $           | 6  |  | $ | 49 |  
|FTRs                                               |  |               | 90  |   |                   |   |   |        |  |             | 22 |  |   |   |  
|Forward physicals (power) and tolling arrangements |  |               | 73  |   |                   |   | 6  |        |  |             | 7  |  |   | 8  |  
|Gas options, swaps and forward arrangements        |  |               | 416 |   |                   |   | 4  |        |  |             | 46 |  |   | 22 |  
|Netting and collateral                             |  |               | (20 | ) |                   |   | (2 | )      |  |             |   |  |   | (2 | )
|Total                                              |  | $             | 575 |   |                   | $ | 39 |        |  | $           | 81 |  | $ | 77 |  

Quoted market prices, if available, are used for determining the fair value of contracts, as discussed above. If
quoted market prices are not available, internally maintained standardized or industry accepted models are used to determine the fair value. The models are updated with spot prices, forward prices, volatilities and interest rates from regularly
published and widely distributed independent sources. SCE implemented SFAS No. 157 during the first quarter of 2008. 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. The derivative assets and liabilities whose fair value is
based on unobservable inputs are classified as level 3 measurements under SFAS No. 157. 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 measured at fair value was 53% and 100%, respectively. During the first six months of 2008, the level 3 fair values increased as a result of changes in realized and unrealized gains. SCE recorded net realized
and unrealized gains of $361 million for the three months ended June 30, 2008 and net realized and unrealized losses of $63 million for the three months ended June 30, 2007. SCE recorded net realized and unrealized gains of
$512 million and $42 million for the six months ended June 30, 2008 and 2007, respectively. The changes in net realized and unrealized gains on economic hedging activities were primarily due to increases in forward natural gas prices
in 2008, compared to the same period 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.

RESULTS OF OPERATIONS AND HISTORICAL CASH FLOW ANALYSIS

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

Results of Operations

Net Income Available for Common Stock

SCEs net income available for common stock was $157 million and $307 million
for the three- and six-month periods ended June 30, 2008, compared to $144 million and $325 million for the respective periods in 2007. SCEs quarter and year-to-date earnings reflect lower taxes and interest, partially offset by
lower operating income. 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.



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Operating Revenue

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



|                                            |  |                             |       |      |                           |       |      |  |      |       |  |   |       |  
|------------------------------------------- |  | --------------------------- | ----- | ---- | ------------------------- | ----- | ---- |  | ---- | ----- |  | - | ----- | -
|                                            |  | Three Months Ended June 30, |       |      | Six Months Ended June 30, |      
|In millions                                 |  | 2008                        |       | 2007 |                           |       | 2008 |  | 2007 |      
|Operating Revenue                           |  |                             |       |      |                           |       |      |  |      |       |  |   |       |  
|Retail billed and unbilled revenue          |  | $                           | 2,244 |      | $                         | 2,174 |      |  | $    | 4,143 |  | $ | 4,133 |  
|Balancing account over/under collections    |  |                             | 164   |      |                           | (43   | )    |  |      | 257   |  |   | (56   | )
|Sales for resale                            |  |                             | 143   |      |                           | 102   |      |  |      | 325   |  |   | 166   |  
|SCEs VIEs                                  |  |                             | 117   |      |                           | 111   |      |  |      | 214   |  |   | 205   |  
|Other (including intercompany transactions) |  |                             | 87    |      |                           | 116   |      |  |      | 167   |  |   | 234   |  
|Total                                       |  | $                           | 2,755 |      | $                         | 2,460 |      |  | $    | 5,106 |  | $ | 4,682 |  

SCEs retail sales represented approximately 87% and 86% of operating revenue for the three- and six-month
periods ended June 30, 2008, respectively, compared to approximately 86% 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 $295 million and $424 million for the three- and six-month
periods ended June 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 $70 million and $10 million for the three- and six-month periods ended June 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 $44 million and a decrease of $4 million, respectively, and a sales volume increase of
$26 million and $14 million, respectively. The increase for the quarter was due to warmer weather experienced in June 2008 resulting in increased volumes sold at a higher rate due to SCEs tiered rate structure.
|- |  | ---------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------



| |  | Balancing account over/under collections increased $207 million and $313 million for the three- and six-month periods ended June 30, 2008, respectively. 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 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- and six-month periods ended June 30, 2008, SCE recognized approximately $164 million and $257 million, respectively, compared to a deferral of approximately $43 million and $56 million for
the respective periods in 2007. The change in balancing account revenue is primarily due to SCE recognizing deferred revenue resulting from prior year overcollections.
|- |  | ---------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------



| |  | Sales for resale represents the sale of excess energy. Excess energy from SCE sources which may exist at certain times is resold in the energy markets. Sales for
resale revenue increased due to higher excess energy in 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 six-month periods ended June 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.
|- |  | ------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------



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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 $539 million and $1.1 billion for the three- and
six-month periods ended June 30, 2008, respectively, compared to $503 million and $1.1 billion for the same respective periods in 2007.

Operating Expenses

Fuel Expense

SCEs fuel expense increased $112 million and $151 million for the three- and six-month periods ended June 30, 2008, respectively, 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 $50 million and $85 million, respectively, resulting from higher gas costs in 2008; and higher gas costs at SCEs VIEs which resulted in increases of $60 million and
$65 million, respectively.

Purchased-Power Expense

The following is a summary of purchased-power expense:



|                                                               |  |                            |   |  |                          |   |  |          |   |  |          |  
|-------------------------------------------------------------- |  | -------------------------- | - |  | ------------------------ | - |  | -------- | - |  | -------- | -
|                                                               |  | Three Months EndedJune 30, |   |  | Six Months EndedJune 30, |  
|In millions                                                    |  | 2008                       |   |  | 2007                     |   |  | 2008     |   |  | 2007     |  
|Purchased-power                                                |  | $  1,064                   |   |  | $  792                   |   |  | $  1,708 |   |  | $  1,242 |  
|Unrealized (gains) losses on economic hedging activities  net |  | (333                       | ) |  | 40                       |   |  | (486     | ) |  | (94      | )
|Realized (gains) losses on economic hedging activities  net   |  | (28                        | ) |  | 23                       |   |  | (26      | ) |  | 52       |  
|Energy settlements and refunds                                 |  | (47                        | ) |  | (26                      | ) |  | (47      | ) |  | (54      | )
|Total purchased-power expense                                  |  | $     656                  |   |  | $  829                   |   |  | $  1,149 |   |  | $  1,146 |  

Total purchased-power expense decreased $173 million for the three months ended June 30, 2008 and
increased $3 million for the six months ended June 30, 2008, as compared to the same periods in 2007.

Purchased power, in the table above,
increased $272 million and $466 million for the three- and six-month periods ended June 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 $205 million and $250 million, respectively, resulting from higher costs per kWh due to higher gas prices and increased kWh purchases from new contracts entered into in late 2007; higher QF purchased-power expense of
$30 million and $90 million, respectively, resulting from increased kWh purchases and an increase in the average spot natural gas prices for certain contracts (as discussed further below); and higher ISO-related energy costs of
$30 million and $115 million, respectively. SCE energy settlement refunds and generator settlements increased by $21 million for the three months ended June 30, 2008 (see Regulatory MattersCurrent Regulatory
DevelopmentsFERC Refund Proceedings for further discussion).

Net realized and unrealized gains on economic hedging activities, in the table
above, was $361 million for the three months ended June 30, 2008, compared to losses of $63 million for the three months ended June 30, 2007. Net realized and unrealized gains on economic hedging activities, in the table above,
was $512 million and $42 million for the six months ended June 30, 2008 and 2007, respectively (see Market Risk ExposuresCommodity Price Risk for further discussion). The changes in net realized and unrealized gains
on economic hedging activities were primarily due to increases in forward natural gas prices in 2008, compared to the same period 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).



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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 increased $312 million for the three-month period ended June 30, 2008, and increased
$197 million for the six-month period ended June 30, 2008, compared to the same periods in 2007. The quarter and year-to date variances reflect a decrease of $55 million and $115 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 gains on economic hedging activities of
approximately $333 million in 2008, compared to losses of $40 million for the same period in 2007 (discussed above in Purchased-Power Expense); higher FTR costs of $10 million; and approximately $15 million
resulting from lower net undercollections primarily due to the Midway-Sunset settlement which was charged/refunded to ratepayers through regulatory mechanisms (see Other Developments: Midway-Sunset Cogeneration Company for further
information). The year-to-date variance also reflects net unrealized gains on economic hedging activities of approximately $486 million and $94 million for the six months ended June 30, 2008 and 2007, respectively (discussed above in
Purchased-Power Expense); approximately $29 million related to a generator settlement recorded in 2007; higher FTR costs of $45 million; lower exchange energy of $10 million; and $15 million of higher net
undercollections 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 discussed above.

Other Operation and Maintenance Expense

SCEs
other operation and maintenance expense increased $96 million and $173 million for the three- and six-month periods ended June 30, 2008, respectively, compared to the same periods in 2007. 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 $50 million and $60 million for the three-
and six-month periods ended June 30, 2008 mainly related to higher demand-side management costs and energy efficiency costs. The increases in operation and maintenance expense also reflect: higher administrative and general costs (including
health care costs and other employee-related expenses) of $30 million and $40 million for the three- and six-month periods ended June 30, 2008, respectively; higher customer service cost (including labor and uncollectible accounts) of
$5 million and $15 million, respectively; and higher transmission and distribution maintenance costs of approximately $5 million and $20 million for the three- and six-month periods ended June 30, 2008, respectively. The year-to-date
increase also reflects 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.

Depreciation, Decommissioning and Amortization Expense

SCEs
depreciation, decommissioning and amortization expense increased $15 million and decreased $7 million for the three- and six-month periods ended June 30, 2008, respectively, compared to the same periods in 2007. The quarter and
year-to-date variances were mainly due to an increase in depreciation expense of $20 million and $40 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. The quarter and year-to-date variances were partially offset by a decrease of $20 million and
$60 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.



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Gain on sale of assets

Gain on sale of assets increased $7 million and $8 million for the three- and six-month periods ended
June 30, 2008, respectively. The quarter and year-to-date increases reflect 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 provision 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 $5 million and $11 million for the three- and six-month periods ended June 30, 2008, respectively,
compared to the same periods in 2007. The 2008 decreases were mainly due to lower undercollections balances in certain balancing accounts and lower interest rates applied to those undercollections.

Interest Expense  Net of Amounts Capitalized

SCEs interest expense  net of amounts capitalized decreased $9 million and $20 million for the three- and six-month periods ended June 30, 2008, respectively, compared to the same periods in 2007. The quarter
and year-to-date decreases were mainly due to lower overcollections of certain balancing accounts and lower interest rates applied to those overcollections in the first and second quarters of 2008 compared to the same periods in 2007.

Income Tax Expense

SCEs composite federal and state
statutory income tax rate was approximately 40% (net of the federal benefit for state income taxes) for all periods presented. SCEs effective tax rate was 15% and 25% for the three- and six-month periods ended June 30, 2008, as compared
to 28% and 25% for the respective periods in 2007. The lower effective tax rates in 2008, as compared to the statutory rate and between comparable periods, were primarily due to internally developed software and property related flow-through tax
deductions recorded in 2008. The lower effective tax rates in 2008, as compared to 2007, were partially offset by reductions during 2007, as discussed below. The effective tax rates in 2007 were lower than the statutory rate primarily due to
progress made in the first quarter of 2007 in an administrative appeal process with the IRS related to the income tax treatment of certain costs associated with environmental remediation; reductions made during the second quarter of 2007 to reflect
receipt of a state Notice of Proposed Adjustment; and also due to property related flow-through items.

Minority Interest

Minority interest decreased $40 million and $62 million for the three- and six-month periods ended June 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 higher gas costs at the VIEs. 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.

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 $552 million in the first six months of 2008, compared to the first six months of 2007. The decrease was mainly due to ERRA undercollections in 2008, compared to ERRA overcollections in 2007. The increase in
natural gas prices and the indirect affect on power prices have resulted in



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SCE using cash to pay for these higher costs in excess of amounts received from customers (see Regulatory MattersCurrent Regulatory
DevelopmentsEnergy Resource Recovery Account Proceedings). 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 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.
|- |  | -----------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------



| |  | During the first half of 2008, SCEs net issuances of commercial paper classified as short-term debt was $300 million.
|- |  | ----------------------------------------------------------------------------------------------------------------------



| |  | 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).
|- |  | ----------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------



| |  | Other financing activities in 2008 include dividend payments of $125 million paid to Edison International and $25 million for stock purchased for
stock-based compensation.
|- |  | ---------------------------------------------------------------------------------------------------------------------------------------------------------------------------

Financing activities in 2007 were as follows:



| |  | During the first half of 2007 SCEs net issuances of commercial paper classified as short-term debt was $175 million.
|- |  | ---------------------------------------------------------------------------------------------------------------------



| |  | Other financing activities in 2007 include dividend payments of $85 million paid to Edison International and $115 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 $1.2 billion in capital expenditures at SCE, primarily for transmission and distribution assets,
including approximately $55 million for nuclear fuel acquisitions. Investing activities also include net purchases of nuclear decommissioning trust investments and other of $59 million.

Investing activities in 2007 reflect $1.1 billion in capital expenditures at SCE, primarily for transmission and distribution assets, including approximately
$28 million for nuclear fuel acquisitions. Investing activities also include net purchases of nuclear decommissioning trust investments and other of $67 million.



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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 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 six months ended June 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.

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 June 30, 2008 this amount was $448 million).

In
March 2008, the FASB issued SFAS No. 161, which requires additional disclosure 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.

In April 2008, the FASB issued FSP FAS No. 142-3 which amends the factors that should be considered in developing renewal or extension assumptions used to determine
the useful life of a recognized intangible asset



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under SFAS No. 142, Goodwill and Other Intangible Assets. The intent of the position is to improve the consistency between the useful life
of a recognized intangible asset under SFAS No. 142 and the period of expected cash flows used to measure the fair value of the asset under SFAS No. 141(R) and other U.S. generally accepted accounting principles. SCE will adopt FSP FAS
No. 142-3 on January 1, 2009. SCE is currently evaluating the impact, if any, that the adoption of this position could have on its consolidated financial statements.

COMMITMENTS AND INDEMNITIES

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

Fuel Supply Contracts

During the first six 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: remainder of 2008  $15 million, 2009  $49 million, 2010  $50 million, 2011  $96 million, 2012  $141 million and thereafter  $665 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 40 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  $27 million, 2009  $48 million, 2010 
$48 million, 2011  $48 million, 2012  $48 million and thereafter  $1.9 billion.

Uncertain Tax Position Net
Liability

At June 30, 2008, SCEs recorded net liability for uncertain tax positions was $306 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.



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|Item 3. | Quantitative and Qualitative Disclosures About Market Risk
|------- | ----------------------------------------------------------

Information responding to Part I, Item 3 is included in Part I, Item 2, Managements Discussion and Analysis of Financial Condition and Results of Operations, under the heading Market Risk Exposures is
incorporated herein by this reference.



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

Disclosure Controls and Procedures

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

Internal Control Over Financial Reporting

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

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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##### Table of Contents

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.



|Item 4. | Submission of Matters to a Vote of Security Holders
|------- | ---------------------------------------------------

At SCEs
Annual Meeting of Shareholders on April 24, 2008, two matters were put to a vote of the shareholders: the election of twelve directors and ratification of the appointment of the independent public accounting firm.

Shareholders elected twelve nominees to the Board of Directors. The number of broker non-votes for each nominee was zero. The number of votes cast for and withheld from
each Director-nominee were as follows:



|                           |  |                 |  |          
|-------------------------- |  | --------------- |  | ---------
|                           |  | Number of Votes
|Name                       |  | For             |  | Witheld  
|John E. Bryson             |  | 458,389,930     |  | 559,038  
|Vanessa C.L. Chang         |  | 458,382,178     |  | 566,790  
|France A. Córdova          |  | 458,395,810     |  | 553,158  
|Charles B. Curtis          |  | 458,394,976     |  | 553,992  
|Alan J. Fohrer             |  | 458,397,958     |  | 551,010  
|Bradford M. Freeman        |  | 458,370,862     |  | 578,106  
|Luis G. Nogales            |  | 458,381,998     |  | 566,970  
|Ronald L. Olson            |  | 455,800,996     |  | 3,147,972
|James M. Rosser            |  | 458,395,360     |  | 553,608  
|Richard T. Schlosberg, III |  | 458,356,828     |  | 592,140  
|Thomas C. Sutton           |  | 458,372,926     |  | 576,042  
|Brett White                |  | 458,364,004     |  | 584,964  



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The proposal to ratify the appointment of the independent public accounting firm which received the affirmative vote of a
majority of the votes cast was adopted. The proposal received the following numbers of votes:



|            |  |         |  |             |  |                 
|----------- |  | ------- |  | ----------- |  | ----------------
|For         |  | Against |  | Abstentions |  | Broker Non-Votes
|458,399,014 |  | 317,232 |  | 232,722     |  | 0               



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PART II. OTHER INFORMATION



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

Southern California Edison Company



|     |  |                                                                                                                                                                                                     
|---- |  | ----------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
|10.1 |  | Edison International Director Nonqualified Stock Options Terms and Conditions 2008 (File No. 1-9936, filed as Exhibit 10.1 to Edison Internationals Form 10-Q for the quarter ended
June 30, 2008)*
|     | 
|10.2 |  | Edison International Director Compensation Schedule, as adopted June 27, 2008 (File No. 1-9936, filed as Exhibit 10.2 to Edison Internationals Form 10-Q for the quarter ended June 30,
2008)*     
|     | 
|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: August 8, 2008



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