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UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549



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FORM 10-Q



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(Mark One)

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



For the quarterly period ended September 30, 2005



or



| ̈ | 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 000-50039



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OLD DOMINION ELECTRIC COOPERATIVE

(Exact Name of Registrant as Specified in Its Charter)



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|                                                               |  |                                     
|-------------------------------------------------------------- |  | ------------------------------------
|VIRGINIA                                                       |  | 23-7048405                          
|(State or Other Jurisdiction of Incorporation or Organization) |  | (I.R.S. Employer Identification No.)
|                                                               | 
|4201 Dominion Boulevard, Glen Allen, Virginia                  |  | 23060                               
|(Address of Principal Executive Offices)                       |  | (Zip Code)                          



(804) 747-0592

(Registrants Telephone Number, Including Area Code)



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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 an accelerated filer (as defined in the Exchange Act of Rule 12b-2).    Yes ̈No  x



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



The Registrant is a membership corporation and has no authorized or outstanding equity securities.



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OLD DOMINION ELECTRIC COOPERATIVE



INDEX



|                              |  |                                                                                                                                                     |  |           
|----------------------------- |  | --------------------------------------------------------------------------------------------------------------------------------------------------- |  | ----------
|                              |  |                                                                                                                                                     |  | PageNumber
|PART I.
Financial Information |  |                                                                                                                                                    
|                              |  |                                                                                                                                                    
|Item 1.                       |  | Financial Statements                                                                                                                                |  |           
|                              |  |                                                                                                                                                    
|                              |  | Condensed Consolidated Balance Sheets  September 30, 2005 (Unaudited) and December 31, 2004                                                        |  | 3         
|                              |  |                                                                                                                                                    
|                              |  | Condensed Consolidated Statements of Revenues, Expenses and Patronage Capital (Unaudited)  Three and Nine months ended September 30, 2005 and 2004 |  | 4         
|                              |  |                                                                                                                                                    
|                              |  | Condensed Consolidated Statements of Comprehensive Income (Unaudited) - Three and Nine months ended September 30, 2005 and 2004                     |  | 4         
|                              |  |                                                                                                                                                    
|                              |  | Condensed Consolidated Statements of Cash Flows (Unaudited)  Nine Months Ended September 30, 2005 and 2004                                         |  | 5         
|                              |  |                                                                                                                                                    
|                              |  | Notes to Condensed Consolidated Financial Statements                                                                                                |  | 6         
|                              |  |                                                                                                                                                    
|Item 2.                       |  | Managements Discussion and Analysis of Financial Condition and Results of Operations                                                               |  | 8         
|                              |  |                                                                                                                                                    
|Item 3.                       |  | Quantitative and Qualitative Disclosures About Market Risk                                                                                          |  | 17        
|                              |  |                                                                                                                                                    
|Item 4.                       |  | Controls and Procedures                                                                                                                             |  | 17        
|                              | 
|PART II.
Other Information    |  |                                                                                                                                                    
|                              |  |                                                                                                                                                    
|Item 1.                       |  | Legal Proceedings                                                                                                                                   |  | 18        
|                              |  |                                                                                                                                                    
|Item 6.                       |  | Exhibits                                                                                                                                            |  | 19        
|                              | 
|Signature                     |  | 20                                                                                                                                                 



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O
LD DOMINION ELECTRIC COOPERATIVE

PART 1. FINANCIAL INFORMATION



ITEM 1. FINANCIAL STATEMENTS

CONDENSED CONSOLIDATED BALANCE SHEETS



|                                             |  |                   |           |   |                   |   |           |  
|-------------------------------------------- |  | ----------------- | --------- | - | ----------------- | - | --------- | -
|                                             |  | September 30,2005 |           |   | December 31, 2004 |  
|                                             |  | (in thousands)    |          
|                                             |  | (unaudited)       |           |   |                   |  
|ASSETS:                                      |  |                   |           |   |                   |   |           |  
|Electric Plant:                              |  |                   |           |   |                   |   |           |  
|In service                                   |  | $                 | 1,518,309 |   |                   | $ | 1,511,848 |  
|Less accumulated depreciation                |  |                   | (462,113  | ) |                   |   | (431,678  | )
|                                             |  |                   |           |   |                   |   |           |  
|                                             |  |                   | 1,056,196 |   |                   |   | 1,080,170 |  
|Nuclear fuel, at amortized cost              |  |                   | 6,250     |   |                   |   | 10,493    |  
|Construction work in progress                |  |                   | 17,311    |   |                   |   | 10,832    |  
|                                             |  |                   |           |   |                   |   |           |  
|Net Electric Plant                           |  |                   | 1,079,757 |   |                   |   | 1,101,495 |  
|                                             |  |                   |           |   |                   |   |           |  
|Investments:                                 |  |                   |           |   |                   |   |           |  
|Nuclear decommissioning trust                |  |                   | 78,500    |   |                   |   | 75,917    |  
|Lease deposits                               |  |                   | 160,568   |   |                   |   | 156,909   |  
|Other                                        |  |                   | 30,698    |   |                   |   | 17,694    |  
|                                             |  |                   |           |   |                   |   |           |  
|Total Investments                            |  |                   | 269,766   |   |                   |   | 250,520   |  
|                                             |  |                   |           |   |                   |   |           |  
|Current Assets:                              |  |                   |           |   |                   |   |           |  
|Cash and cash equivalents                    |  |                   | 155,950   |   |                   |   | 17,564    |  
|Deposits                                     |  |                   | 42,447    |   |                   |   |          |  
|Accounts receivable                          |  |                   | 19,626    |   |                   |   | 9,438     |  
|Accounts receivable - members                |  |                   | 72,055    |   |                   |   | 62,402    |  
|Fuel, materials and supplies                 |  |                   | 25,257    |   |                   |   | 29,153    |  
|Deferred energy                              |  |                   | 33,815    |   |                   |   |          |  
|Prepayments                                  |  |                   | 2,171     |   |                   |   | 2,866     |  
|                                             |  |                   |           |   |                   |   |           |  
|Total Current Assets                         |  |                   | 351,321   |   |                   |   | 121,423   |  
|                                             |  |                   |           |   |                   |   |           |  
|Deferred Charges:                            |  |                   |           |   |                   |   |           |  
|Regulatory assets                            |  |                   | 46,336    |   |                   |   | 53,920    |  
|Other                                        |  |                   | 62,596    |   |                   |   | 22,980    |  
|                                             |  |                   |           |   |                   |   |           |  
|Total Deferred Charges                       |  |                   | 108,932   |   |                   |   | 76,900    |  
|                                             |  |                   |           |   |                   |   |           |  
|Total Assets                                 |  | $                 | 1,809,776 |   |                   | $ | 1,550,338 |  
|                                             |  |                   |           |   |                   |   |           |  
|CAPITALIZATION AND LIABILITIES:              |  |                   |           |   |                   |   |           |  
|Capitalization:                              |  |                   |           |   |                   |   |           |  
|Patronage capital                            |  | $                 | 268,565   |   |                   | $ | 259,724   |  
|Non-controlling interest                     |  |                   | 30,986    |   |                   |   | 8,225     |  
|Long-term debt                               |  |                   | 855,149   |   |                   |   | 852,910   |  
|                                             |  |                   |           |   |                   |   |           |  
|Total Capitalization                         |  |                   | 1,154,700 |   |                   |   | 1,120,859 |  
|                                             |  |                   |           |   |                   |   |           |  
|Current Liabilities                          |  |                   |           |   |                   |   |           |  
|Long-term debt due within one year           |  |                   | 22,917    |   |                   |   | 22,917    |  
|Accounts payable                             |  |                   | 124,213   |   |                   |   | 59,798    |  
|Accounts payable-members                     |  |                   | 66,019    |   |                   |   | 38,655    |  
|Accounts payable-deposits                    |  |                   | 42,447    |   |                   |   |          |  
|Accrued expenses                             |  |                   | 36,859    |   |                   |   | 14,527    |  
|Deferred energy                              |  |                   |          |   |                   |   | 4,807     |  
|Deferred taxes                               |  |                   | 13,970    |   |                   |   |          |  
|                                             |  |                   |           |   |                   |   |           |  
|Total Current Liabilities                    |  |                   | 306,425   |   |                   |   | 140,704   |  
|                                             |  |                   |           |   |                   |   |           |  
|Deferred Credits and Other Liabilities       |  |                   |           |   |                   |   |           |  
|Asset retirement obligation                  |  |                   | 48,149    |   |                   |   | 46,295    |  
|Obligations under long-term leases           |  |                   | 163,351   |   |                   |   | 159,902   |  
|Regulatory liabilities                       |  |                   | 98,384    |   |                   |   | 41,782    |  
|Other                                        |  |                   | 38,767    |   |                   |   | 40,796    |  
|                                             |  |                   |           |   |                   |   |           |  
|Total Deferred Credits and Other Liabilities |  |                   | 348,651   |   |                   |   | 288,775   |  
|                                             |  |                   |           |   |                   |   |           |  
|Commitments and Contingencies                |  |                   |          |   |                   |   |          |  
|                                             |  |                   |           |   |                   |   |           |  
|Total Capitalization and Liabilities         |  | $                 | 1,809,776 |   |                   | $ | 1,550,338 |  
|                                             |  |                   |           |   |                   |   |           |  



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





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OLD DOMINION ELECTRIC COOPERATIVE



CONDENSED CONSOLIDATED STATEMENTS OF REVENUES,

EXPENSES AND PATRONAGE CAPITAL (UNAUDITED)



|                                                            |  |                                 |         |   |                                |   |         |      |  |   |         |   |  |   |         |  
|----------------------------------------------------------- |  | ------------------------------- | ------- | - | ------------------------------ | - | ------- | ---- |  | - | ------- | - |  | - | ------- | -
|                                                            |  | Three Months EndedSeptember 30, |         |   | Nine Months EndedSeptember 30, |  
|                                                            |  | 2005                            |         |   | 2004                           |   |         | 2005 |  |   | 2004    |  
|                                                            |  | (in thousands)                  |         |   | (in thousands)                 |  
|Operating Revenues                                          |  | $                               | 207,491 |   |                                | $ | 145,169 |      |  | $ | 539,539 |   |  | $ | 412,776 |  
|                                                            |  |                                 |         |  
|Operating Expenses:                                         |  |                                 |         |   |                                |   |         |      |  |   |         |   |  |   |         |  
|Fuel                                                        |  |                                 | 62,754  |   |                                |   | 25,700  |      |  |   | 112,539 |   |  |   | 67,300  |  
|Purchased power                                             |  |                                 | 118,171 |   |                                |   | 92,194  |      |  |   | 325,908 |   |  |   | 239,730 |  
|Deferred energy                                             |  |                                 | (22,144 | ) |                                |   | (7,360  | )    |  |   | (38,622 | ) |  |   | (14,797 | )
|Operations and maintenance                                  |  |                                 | 9,190   |   |                                |   | 2,817   |      |  |   | 25,614  |   |  |   | 23,538  |  
|Administrative and general                                  |  |                                 | 10,175  |   |                                |   | 6,425   |      |  |   | 25,942  |   |  |   | 20,994  |  
|Depreciation, amortization and decommissioning              |  |                                 | 9,798   |   |                                |   | 7,817   |      |  |   | 29,113  |   |  |   | 22,485  |  
|Amortization of regulatory asset/(liability), net           |  |                                 | 175     |   |                                |   | 1,577   |      |  |   | 1,348   |   |  |   | 5,863   |  
|Taxes other than income taxes                               |  |                                 | 1,562   |   |                                |   | 1,390   |      |  |   | 4,724   |   |  |   | 3,809   |  
|Accretion                                                   |  |                                 | 618     |   |                                |   | 558     |      |  |   | 1,854   |   |  |   | 1,664   |  
|                                                            |  |                                 |         |   |                                |   |         |      |  |   |         |   |  |   |         |  
|Total Operating Expenses                                    |  |                                 | 190,299 |   |                                |   | 131,118 |      |  |   | 488,420 |   |  |   | 370,586 |  
|                                                            |  |                                 |         |   |                                |   |         |      |  |   |         |   |  |   |         |  
|Operating Margin                                            |  |                                 | 17,192  |   |                                |   | 14,051  |      |  |   | 51,119  |   |  |   | 42,190  |  
|                                                            |  |                                 |         |   |                                |   |         |      |  |   |         |   |  |   |         |  
|Other (Expense)/Income, net                                 |  |                                 | (76     | ) |                                |   | 15      |      |  |   | (202    | ) |  |   | 47      |  
|Investment Income                                           |  |                                 | 1,362   |   |                                |   | 262     |      |  |   | 3,602   |   |  |   | 2,225   |  
|Interest Charges, net                                       |  |                                 | (14,717 | ) |                                |   | (11,517 | )    |  |   | (44,033 | ) |  |   | (35,700 | )
|                                                            |  |                                 |         |   |                                |   |         |      |  |   |         |   |  |   |         |  
|Net Margin Before Income Taxes and Non-Controlling Interest |  |                                 | 3,761   |   |                                |   | 2,811   |      |  |   | 10,486  |   |  |   | 8,762   |  
|                                                            |  |                                 |         |   |                                |   |         |      |  |   |         |   |  |   |         |  
|Income Taxes                                                |  |                                 | (322    | ) |                                |   |        |      |  |   | (658    | ) |  |   |        |  
|Non-Controlling Interest                                    |  |                                 | (483    | ) |                                |   |        |      |  |   | (987    | ) |  |   |        |  
|                                                            |  |                                 |         |   |                                |   |         |      |  |   |         |   |  |   |         |  
|Net Margin                                                  |  |                                 | 2,956   |   |                                |   | 2,811   |      |  |   | 8,841   |   |  |   | 8,762   |  
|                                                            |  |                                 |         |   |                                |   |         |      |  |   |         |   |  |   |         |  
|Patronage Capital - Beginning of Period                     |  |                                 | 265,609 |   |                                |   | 253,541 |      |  |   | 259,724 |   |  |   | 247,590 |  
|                                                            |  |                                 |         |   |                                |   |         |      |  |   |         |   |  |   |         |  
|Patronage Capital - End of Period                           |  | $                               | 268,565 |   |                                | $ | 256,352 |      |  | $ | 268,565 |   |  | $ | 256,352 |  
|                                                            |  |                                 |         |   |                                |   |         |      |  |   |         |   |  |   |         |  



OLD DOMINION ELECTRIC COOPERATIVE



CONDENSED CONSOLIDATED STATEMENTS

OF COMPREHENSIVE INCOME (UNAUDITED)



|                                           |  |                                  |        |                                 |   |       |  |      |        |  |   |      
|------------------------------------------ |  | -------------------------------- | ------ | ------------------------------- | - | ----- |  | ---- | ------ |  | - | -----
|                                           |  | Three Months Ended September 30, |        | Nine Months Ended September 30,
|                                           |  | 2005                             |        | 2004                            |   | 2005  |  | 2004
|                                           |  | (in thousands)                   |        | (in thousands)                 
|Net Margin                                 |  | $                                | 2,956  |                                 | $ | 2,811 |  | $    | 8,841  |  | $ | 8,762
|                                           |  |                                  |        |                                 |   |       |  |      |        |  |   |      
|Unrealized gain on derivative contracts(1) |  |                                  | 14,712 |                                 |   |      |  |      | 21,850 |  |   |     
|                                           |  |                                  |        |                                 |   |       |  |      |        |  |   |      
|Comprehensive Income                       |  | $                                | 17,668 |                                 | $ | 2,811 |  | $    | 30,691 |  | $ | 8,762
|                                           |  |                                  |        |                                 |   |       |  |      |        |  |   |      

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|(1) | Unrealized gain on derivative contracts net of tax expense of $9.4 million for the three months ended September 30, 2005, and net of tax expense of $14.0 million for the nine months
ended September 30, 2005.
|--- | ---------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------



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



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OLD DOMINION ELECTRIC COOPERATIVE



CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS (UNAUDITED)



|                                                                                              |  |                                |         |   |      |   |          |  
|--------------------------------------------------------------------------------------------- |  | ------------------------------ | ------- | - | ---- | - | -------- | -
|                                                                                              |  | Nine Months EndedSeptember 30, |        
|                                                                                              |  | 2005                           |         |   | 2004 |  
|                                                                                              |  | (in thousands)                 |        
|Operating Activities:                                                                         |  |                                |         |   |      |   |          |  
|Net Margin                                                                                    |  | $                              | 8,841   |   |      | $ | 8,762    |  
|Adjustments to reconcile net margins to net cash provided by (used for) operating activities: |  |                                |         |   |      |   |          |  
|Depreciation, amortization and decommissioning                                                |  |                                | 29,113  |   |      |   | 22,485   |  
|Other non-cash charges                                                                        |  |                                | 7,586   |   |      |   | 3,345    |  
|Non-controlling interest                                                                      |  |                                | 987     |   |      |   |         |  
|Amortization of lease obligations                                                             |  |                                | 7,766   |   |      |   | 7,465    |  
|Interest on lease deposits                                                                    |  |                                | (7,453  | ) |      |   | (7,148   | )
|Change in current assets                                                                      |  |                                | (57,696 | ) |      |   | (3,684   | )
|Change in deferred energy                                                                     |  |                                | (38,622 | ) |      |   | (14,797  | )
|Change in current liabilities                                                                 |  |                                | 156,558 |   |      |   | (26,224  | )
|Change in regulatory assets and liabilities                                                   |  |                                | 63,857  |   |      |   | 8,697    |  
|Deferred charges and credits                                                                  |  |                                | (3,830  | ) |      |   | 351      |  
|                                                                                              |  |                                |         |   |      |   |          |  
|Net Cash Provided by (Used for) Operating Activities                                          |  |                                | 167,107 |   |      |   | (748     | )
|                                                                                              |  |                                |         |   |      |   |          |  
|Financing Activities:                                                                         |  |                                |         |   |      |   |          |  
|Obligations under long-term leases                                                            |  |                                | (523    | ) |      |   | (529     | )
|                                                                                              |  |                                |         |   |      |   |          |  
|Net Cash Used for Financing Activities                                                        |  |                                | (523    | ) |      |   | (529     | )
|                                                                                              |  |                                |         |   |      |   |          |  
|Investing Activities:                                                                         |  |                                |         |   |      |   |          |  
|Purchases of available for sale securities                                                    |  |                                | (60,693 | ) |      |   | (108,400 | )
|Proceeds from sale of available for sale securities                                           |  |                                | 45,000  |   |      |   | 155,901  |  
|Decrease (Increase) in other investments                                                      |  |                                | 435     |   |      |   | (6,181   | )
|Electric plant additions                                                                      |  |                                | (12,940 | ) |      |   | 88       |  
|                                                                                              |  |                                |         |   |      |   |          |  
|Net Cash (Provided by) Used for Investing Activities                                          |  |                                | (28,198 | ) |      |   | 41,408   |  
|                                                                                              |  |                                |         |   |      |   |          |  
|Net Change in Cash and Cash Equivalents                                                       |  |                                | 138,386 |   |      |   | 40,131   |  
|Cash and Cash Equivalents - Beginning of Period                                               |  |                                | 17,564  |   |      |   | 31,758   |  
|                                                                                              |  |                                |         |   |      |   |          |  
|Cash and Cash Equivalents - End of Period                                                     |  | $                              | 155,950 |   |      | $ | 71,889   |  
|                                                                                              |  |                                |         |   |      |   |          |  



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



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OLD DOMINION ELECTRIC COOPERATIVE



NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS



|1. | In the opinion of our management, the accompanying unaudited condensed consolidated financial statements contain all adjustments, which include only normal recurring adjustments,
necessary for a fair statement of our consolidated financial position as of September 30, 2005, and our consolidated results of operations, comprehensive income, and cash flows for the three and nine months ended September 30, 2005 and 2004. The
consolidated results of operations for the three and nine months ended September 30, 2005, are not necessarily indicative of the results to be expected for the entire year. These financial statements should be read in conjunction with the financial
statements and notes thereto included in our 2004 Annual Report on Form 10-K filed with the Securities and Exchange Commission.
|-- | ---------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------



|2. | Presentation. The accompanying financial statements reflect the consolidated accounts of Old Dominion Electric Cooperative (Old Dominion or we or
our) and TEC Trading, Inc. (TEC). We are a not-for-profit wholesale power supply cooperative, incorporated under the laws of the Commonwealth of Virginia in 1948. We have two classes of members. Our Class A members are twelve
customer-owned electric distribution cooperatives engaged in the retail sale of power to member consumers located in Virginia, Delaware, Maryland, and parts of West Virginia. Our sole Class B member is TEC, a taxable corporation owned by our member
distribution cooperatives. Our board of directors is composed of two representatives from each of the member distribution cooperatives and one representative from TEC.
|-- | ----------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------



TEC was formed in 2001 for the primary purpose of purchasing from us, to sell in the market, power that is not needed to
meet the actual needs of our member distribution cooperatives, acquiring natural gas and forward purchase contracts to hedge the price of natural gas to supply our combustion turbine facilities, and taking advantage of other power-related trading
opportunities in the market which will help lower our member distribution cooperatives costs. TEC does not engage in speculative trading. TEC is a taxable corporation and a provision for income taxes has been established based upon TECs
pre-tax income using statutory tax rates of 35% for federal purposes and 4% for state purposes.



In accordance with Financial Accounting Standards Board (FASB) Interpretation No. 46R, Consolidation of Variable Interest Entities, an
Interpretation of Accounting Research Bulletin No. 51 (the Interpretation), TEC is considered a variable interest entity for which we are the primary beneficiary. We became the primary beneficiary of TEC in 2001. We first
consolidated TECs financial position as of December 31, 2004, and beginning January 1, 2005, TECs operations were also consolidated as a result of our adoption of the Interpretation. We have eliminated all balances and transactions in
consolidation. The assets and liabilities and non-controlling interest of TEC are recorded at carrying value and the net assets consolidated were $37.7 million and $10.2 million at September 30, 2005, and December 31, 2004, respectively. As TEC is
100% owned by our twelve member distribution cooperatives, its equity is presented as a non-controlling interest in our consolidated financial statements. Our non-controlling, 50% or less, ownership interest in other entities is recorded using the
equity method of accounting.



Our rates are not regulated by
the respective states public service commissions, but are set periodically by a formula that was accepted for filing by the Federal Energy Regulatory Commission (FERC) on December 23, 2003. An amendment to the formula was accepted
for filing by FERC on February 19, 2005, subject to the outcome of our other pending FERC proceedings.



We comply with the Uniform System of Accounts as prescribed by FERC. In conformity with accounting principles generally accepted in the United States
(GAAP), the accounting policies and practices applied by us in the determination of rates are also employed for financial reporting purposes.



The preparation of our consolidated financial statements in conformity with GAAP requires management to make estimates and assumptions that affect the
amounts reported therein. Actual results could differ from those estimates.



|3. | Financial Instruments (including Derivatives). Financial instruments included in the decommissioning fund are classified as available for sale, and accordingly, are carried
at fair value. Unrealized gains and losses on investments held in the decommissioning fund are deferred as a regulatory liability and a regulatory asset until realized.
|-- | -----------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------



Our investments in marketable securities, which are actively managed, are classified as available for sale and are recorded
at fair value. Unrealized gains or losses on these investments, if material, are reflected as a component of capitalization. Investments in debt securities that we have the positive intent and ability to hold to maturity are classified as held to
maturity and are recorded at amortized cost. Other investments are recorded at cost, which approximates market value.



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We primarily purchase power under both long-term and short-term forward physical delivery contracts to
supply power to our member distribution cooperatives under all requirements wholesale power contracts. These forward purchase contracts meet the accounting definition of a derivative; however, a majority of the forward purchase
derivative contracts qualify for the normal purchases/normal sales exception under Statement of Financial Accounting Standards (SFAS) No. 133 Accounting for Derivative Instruments and Hedging Activities. As a result, these
contracts are not recorded at fair value. We record a liability and purchased power expense when the power under the forward physical delivery contract is delivered. We also purchase natural gas futures generally for two years or less to hedge the
price of natural gas for the operation of our combustion turbine facilities and for use as a basis in determining the price of power in certain forward power purchase agreements. These derivatives do not qualify for the normal purchases/normal sales
exception.



For all derivative contracts that do not qualify
for the normal purchases/normal sales accounting exception, we may elect cash flow hedge accounting in accordance with SFAS No. 133. Accordingly, gains and losses on derivative contracts are deferred into Other Comprehensive Income until the hedged
underlying transaction occurs or is no longer likely to occur. For derivative contracts where hedge accounting is not utilized, or for which ineffectiveness exists, we defer all remaining gains and losses on a net basis as a regulatory asset or
liability in accordance with SFAS No. 71 Accounting for the Effects of Certain Types of Regulation. These amounts are subsequently reclassified as purchased power or fuel expense in our Consolidated Statements of Revenues, Expenses, and
Patronage Capital as the power or fuel is delivered and/or the contract settles.



Generally, derivatives are reported on the Consolidated Balance Sheet at fair value. The measurement of fair value is based on actively quoted market prices, if available. Otherwise, we seek indicative price
information from external sources, including broker quotes and industry publications. For individual contracts, the use of differing assumptions could have a material effect on the contracts estimated fair value. Hedge ineffectiveness was
immaterial for the three and nine months ended September 30, 2005 and 2004.



We are exposed to credit risk in our business operations. We have adopted a Credit Risk Policy that establishes the basis for determining counterparty credit standards and processes to determine credit limits. Our
risk management committee monitors credit exposure on a regular basis. Formal counterparty credit reviews are performed at least annually and informal reviews are performed on an ongoing basis. At September 30, 2005, due to significant increases in
energy prices, our counterparties were required to post $42.4 million in deposits in accordance with the terms of our respective master power purchase and sales agreements with them. We have separately shown these deposits in our balance sheet as
deposits and accounts payabledeposits.



|4. | Commitments and Contingencies. See Note 15Commitments and Contingencies to the Notes to the Consolidated Financial Statements in our 2004 Annual Report on Form 10-K.
|-- | ----------------------------------------------------------------------------------------------------------------------------------------------------------------------



On April 1, 2005, during the discovery phase of
our litigation with Ragnar Benson, Inc. (RBI), RBI revised its claim from $15.0 million to $33.0 million. During the trial, which began on October 11, 2005, and concluded October 26, 2005, RBI further revised its claim from $33.0 million
to $36.0 million. We have reviewed the asserted claims of RBI and believe they are without merit. We do not believe any liability is estimable or probable and we intend to vigorously defend these claims.



|5. | New Accounting Pronouncement. In March 2005, the FASB issued Interpretation No. 47 Accounting for Conditional Asset Retirement Obligations, an Interpretation of FASB
Statement No. 43 (FIN 47). FIN 47 is a further clarification of SFAS No. 143 Accounting for Asset Retirement Obligations and requires the establishment of a liability for conditional asset retirement obligations. A
conditional asset retirement obligation is a legal obligation to perform an asset retirement activity in which the timing and/or method of settlement are conditional on a future event that may or may not be within the control of the entity.
Uncertainty about the timing and/or method of settlement is required to be considered in the measurement of the liability when sufficient information exists. FIN 47 also clarifies when an entity would have sufficient information to reasonably
estimate the fair value of an asset retirement obligation. FIN 47 is effective for us December 31, 2005. We are currently evaluating the impact that FIN 47 may have on our results of operations and financial condition.
|-- | ---------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------



|6. | Reclassifications. Certain reclassifications have been made to the prior years condensed consolidated financial statements to conform to the current years
presentation.
|-- | --------------------------------------------------------------------------------------------------------------------------------------------------------------------------



|7. | Subsequent Event.On October 12, 2005, our Board of Directors approved an increase to our fuel factor adjustment rate, resulting in an increase to our total energy rate of
approximately 8.1%, effective October 1, 2005. This increase was implemented due to continued rising energy costs.
|-- | ---------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------



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##### Table of Contents

OLD DOMINION ELECTRIC COOPERATIVE



ITEM 2. MANAGEMENTS DISCUSSION AND ANALYSIS

OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS



Caution Regarding Forward-Looking Statements



Managements Discussion and Analysis of Financial Condition and Results
of Operations contains forward-looking statements regarding matters that could have an impact on our business, financial condition, and future operations. These statements, based on our expectations and estimates, are not guarantees of future
performance and are subject to risks, uncertainties, and other factors that could cause actual results to differ materially from those expressed in the forward-looking statements. These risks, uncertainties, and other factors include, but are not
limited to, general business conditions, increased competition in the electric utility industry, changes in our tax status, demand for energy, federal and state legislative and regulatory actions and legal and administrative proceedings, changes in
and compliance with environmental laws and policies, weather conditions, the cost of commodities used in our industry, and unanticipated changes in operating expenses and capital expenditures. Our actual results may vary materially from those
discussed in the forward-looking statements as a result of these and other factors. Any forward-looking statement speaks only as of the date on which the statement is made, and we undertake no obligation to update any forward-looking statement or
statements to reflect events or circumstances after the date on which the statement is made even if new information becomes available or other events occur in the future.



Critical Accounting Policies



As of September 30, 2005, there have been no significant changes in our critical accounting policies as disclosed in our Annual Report on Form 10-K for
the fiscal year ended December 31, 2004. These policies include the accounting for rate regulation, deferred energy, asset retirement obligations, derivative contracts and our margin stabilization plan.



Basis of Presentation



The accompanying financial statements reflect the consolidated accounts of Old Dominion Electric Cooperative
(Old Dominion or we or our) and TEC Trading, Inc. (TEC) effective December 31, 2004. See Note 2Notes to Condensed Consolidated Financial Statements in Part 1, Item 1.



Overview



Old Dominion is a not-for-profit power supply cooperative owned entirely by its twelve member distribution cooperatives and
a thirteenth member, TEC. We supply our member distribution cooperatives power requirements, consisting of capacity requirements and energy requirements through a portfolio of resources including generating facilities, power purchase
contracts, and forward, short-term and spot market energy purchases.



The event having the most significant effect on our financial results for the nine months ended September 30, 2005, was a delay encountered by Virginia Electric and Power Company (Virginia Power) in becoming a member of PJM
Interconnection, LLC (PJM) and the resulting postponement of the transfer of operational control of its transmission facilities to PJM. See Other Information in Part II, Item 5 of our Quarterly Report on Form 10-Q for the
three-months ended March 31, 2005, for more information relating to the effects of Virginia Powers joining PJM.



In anticipation of Virginia Powers becoming a member of PJM on January 1, 2005, we purchased several forward energy contracts for delivery to the
PJM control area beginning on that date for the purpose of serving the needs of our member distribution cooperatives on the Virginia mainland. Virginia Power did not join PJM and transfer operational control of its transmission facilities to PJM
until May 1, 2005. Although we could have arranged for the energy under these forward energy contracts to be transmitted to our member distribution cooperatives, it was more economical to sell this energy to non-members and procure a similar amount
of energy from other sources. As a result, our sales to non-members increased dramatically because we sold significant amounts of energy to the market that we had initially scheduled for delivery to the PJM control area. Relatedly, our purchased
power expense also rose 35.9% for the nine months ended September 30, 2005, because we procured significant replacement energy outside of the PJM control area to serve these requirements.



8



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##### Table of Contents

Our non-member revenues also increased as a result of the consolidation of TEC Trading, Inc.
(TEC), our sole Class B member, in accordance with Financial Accounting Standards Board Interpretation No. 46R, Consolidation of Variable Interest Entities, an Interpretation of Accounting Research Bulletin No. 51 (the
Interpretation). Under the Interpretation, revenues from sales by TEC are presented as non-member revenues effective January 1, 2005. Previously, our sales of energy to TEC were reflected as member revenues and TECs sales to third
parties were not reflected in our financial statements.



Other
factors impacting our financial results include changing conditions in the energy markets and increases in fuel costs, which have impacted our purchased power costs. Additionally, as a result of these increases, our derivative activity includes
significant unrealized gains. Sales of energy to non-members increased as a result of our strategy to hedge a greater percentage of our exposure to spot market prices under purchasing arrangements. Also, our 2005 financial results were affected by
the availability of our Marsh Run combustion turbine facility (Marsh Run) for commercial operation effective in September 2004. As a result, depreciation, amortization and decommissioning expense and fuel expense increased; and interest
charges, net increased because we ceased capitalizing interest with respect to the facility.



Results of Operations



Operating
Revenues



Our power sales are comprised of two power
products  energy and capacity (also referred to as demand). Energy is the physical electricity delivered through transmission and distribution facilities to customers. We must have sufficient committed energy available to us for delivery to
our member distribution cooperatives to meet their maximum energy needs at any time, with limited exceptions. This committed available energy at any time is referred to as capacity.



The rates we charge our member distribution cooperatives for sales of energy and capacity are determined by a formulary rate
accepted by the Federal Energy Regulatory Commission (FERC), which is intended to permit collection of revenues which will equal the sum of:



| |  |  | all of our costs and expenses;
| | - |  | ------------------------------



| |  |  | 20% of our total interest charges; and
| | - |  | --------------------------------------



| |  |  | additional equity contributions approved by our board of directors.
| | - |  | -------------------------------------------------------------------



The formulary rate has three components: a demand rate, a base energy rate and a fuel factor adjustment rate. The formulary rate identifies the cost
components that we can collect through rates, but not the actual amounts to be collected. With limited exceptions, we can change our rates periodically to match the costs we have incurred and we expect to incur without seeking FERC approval.



Energy costs, which are primarily variable costs, such as
nuclear, coal and natural gas fuel costs and the energy costs under our power purchase contracts with third parties, are recovered through two separate energy rates, the base energy rate and the fuel factor adjustment rate. The base energy rate is a
fixed rate that requires FERC approval prior to adjustment. However, to the extent the base energy rate over- or under-collects all of our energy costs, we refund or collect the difference through a fuel factor adjustment rate. We review our energy
costs at least every six months to determine whether the base energy rate and the current fuel factor adjustment rate together are adequately recovering our actual and anticipated energy costs, and revise the fuel factor adjustment rate accordingly.
Because the fuel factor adjustment rate can be revised without FERC approval, we can effectively change our total energy rate to recover all of our energy costs without seeking the approval of FERC.



Capacity costs, which are primarily fixed costs, such as depreciation
expense, interest expense, administrative and general expenses, capacity costs under power purchase contracts with third parties, transmission costs, and our margin requirements and additional amounts approved by our board of directors are recovered
through our demand rate. The formulary rate allows us to change the actual demand rate we charge as our capacity-related costs change, without seeking FERC approval, with the exception of extraordinary deductions, and decommissioning cost, which is
a fixed amount in the formulary rate that requires FERC approval prior to any adjustment. Our demand rate is revised automatically to recover the costs contained in our annual budget and any revisions made by our Board of Directors to our annual
budget.



Our operating revenues are derived from power sales to
our members and non-members. Sales to members include sales to our Class A members, which are our twelve member distribution cooperatives. Prior to January 1, 2005, sales to members also included sales to our single Class B member, TEC. We
consolidated TECs financial position as of December 31, 2004, and beginning January 1, 2005, TECs operations were also consolidated as a result of the adoption of the Interpretation. Subsequent to January 1, 2005, sales between Old
Dominion and TEC have been eliminated from our financial statements. TECs sales to third parties



9



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##### Table of Contents

are reflected as non-member revenues. See Note 2Notes to Condensed Consolidated Financial Statements in Part 1, Item 1. Our operating revenues by type
of purchaser for the three and nine months ended September 30, 2005 and 2004, were as follows:



|                                 |  |                                 |         |                                |   |         |  |      |         |  |   |        
|-------------------------------- |  | ------------------------------- | ------- | ------------------------------ | - | ------- |  | ---- | ------- |  | - | -------
|                                 |  | Three Months EndedSeptember 30, |         | Nine Months EndedSeptember 30,
|                                 |  | 2005                            |         | 2004                           |   | 2005    |  | 2004
|                                 |  | (in thousands)                  |         | (in thousands)                
|Member revenues:                 |  |                                 |         |                                |   |         |  |      |         |  |   |        
|Member distribution cooperatives |  | $                               | 181,607 |                                | $ | 142,585 |  | $    | 484,367 |  | $ | 405,336
|TEC                              |  |                                 |        |                                |   | 1,596   |  |      |        |  |   | 3,497  
|                                 |  |                                 |         |                                |   |         |  |      |         |  |   |        
|Total member revenues            |  |                                 | 181,607 |                                |   | 144,181 |  |      | 484,367 |  |   | 408,833
|Non-member revenues              |  |                                 | 25,884  |                                |   | 988     |  |      | 55,172  |  |   | 3,943  
|                                 |  |                                 |         |                                |   |         |  |      |         |  |   |        
|Total revenues                   |  | $                               | 207,491 |                                | $ | 145,169 |  | $    | 539,539 |  | $ | 412,776
|                                 |  |                                 |         |                                |   |         |  |      |         |  |   |        



Non-member revenues
for 2005 include our sales to TEC of $25.6 million and $50.7 million for the three and nine months ended September 30, 2005, respectively. TEC is our sole Class B member, the sales of which are now recorded as non-member sales as a result of the
consolidation of TEC. Non-member revenues for the three months ended September 30, 2005, are higher than the prior year primarily as a result of an increase in the prices at which we sold excess energy to non-members and an increase in the volume of
excess energy sales. Non-member revenues for the three and nine months ended September 30, 2005, are higher than the prior year as a result of increased sales of excess energy due to changes in our purchased power portfolio, differences between
actual and forecasted energy needs, as well as changes in market conditions. Non-member revenues for the nine months ended September 30, 2005, also include increased sales of excess energy as a result of the delay of Virginia Power joining PJM from
January 1, 2005, to May 1, 2005.



Our energy sales in megawatt
hours (MWh) to our members and non-members for the three months and nine months ended September 30, 2005 and 2004, were as follows:



|                                 |  |                                  |  |                                 |  |           |  |          
|-------------------------------- |  | -------------------------------- |  | ------------------------------- |  | --------- |  | ---------
|                                 |  | Three Months Ended September 30, |  | Nine Months Ended September 30.
|                                 |  | 2005                             |  | 2004                            |  | 2005      |  | 2004     
|                                 |  | (in MWh)                         |  | (in MWh)                       
|Member energy sales:             |  |                                  |  |                                 |  |           |  |          
|Member distribution cooperatives |  | 3,164,270                        |  | 2,780,422                       |  | 8,462,122 |  | 8,033,709
|TEC                              |  |                                 |  | 35,662                          |  |          |  | 82,059   
|                                 |  |                                  |  |                                 |  |           |  |          
|Total energy sales to members    |  | 3,164,270                        |  | 2,816,084                       |  | 8,462,122 |  | 8,115,768
|Non-member energy sales          |  | 298,634                          |  | 12,737                          |  | 967,141   |  | 68,979   
|                                 |  |                                  |  |                                 |  |           |  |          
|Total energy sales               |  | 3,462,904                        |  | 2,828,821                       |  | 9,429,263 |  | 8,184,747
|                                 |  |                                  |  |                                 |  |           |  |          



Sales to Member
Distribution Cooperatives. Revenues from sales to our member distribution cooperatives are a function of our formulary rate for sales of power to our member distribution cooperatives and our member distribution cooperatives
consumers requirements for power. Operating revenues on our Condensed Consolidated Statements of Revenues, Expenses and Patronage Capital reflect the actual capacity-related costs we incurred plus the energy costs that we collected during the
quarter. Estimated capacity-related costs are collected during the period through the demand component of our formulary rate. Under our formulary rate, we make adjustments for the refund or recovery of amounts under our Margin Stabilization Plan. We
adjust demand revenues and accounts payablemembers or accounts receivablemembers each quarter to reflect these adjustments. See Critical Accounting PoliciesMargin Stabilization Plan in Part II, Item 7 of our Annual
Report on Form 10-K for the fiscal year ended December 31, 2004, for a discussion of our Margin Stabilization Plan.



10



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##### Table of Contents

Revenues from sales to our member distribution cooperatives by formulary rate component and average costs
to our member distribution cooperatives in MWh for the three and nine months ended September 30, 2005 and 2004, were as follows:



|                                                               |  |                                 |         |                                |   |         |  |      |         |  |   |        
|-------------------------------------------------------------- |  | ------------------------------- | ------- | ------------------------------ | - | ------- |  | ---- | ------- |  | - | -------
|                                                               |  | Three Months EndedSeptember 30, |         | Nine Months EndedSeptember 30,
|                                                               |  | 2005                            |         | 2004                           |   | 2005    |  | 2004
|                                                               |  | (in thousands)                  |         | (in thousands)                
|Revenues from sales to member distribution cooperatives:       |  |                                 |         |                                |   |         |  |      |         |  |   |        
|Base energy revenues                                           |  | $                               | 56,655  |                                | $ | 50,249  |  | $    | 151,980 |  | $ | 145,301
|Fuel factor adjustment revenues                                |  |                                 | 67,503  |                                |   | 39,301  |  |      | 165,512 |  |   | 101,358
|                                                               |  |                                 |         |                                |   |         |  |      |         |  |   |        
|Total energy revenues                                          |  |                                 | 124,158 |                                |   | 89,550  |  |      | 317,492 |  |   | 246,659
|Demand (capacity) revenues                                     |  |                                 | 57,449  |                                |   | 53,035  |  |      | 166,875 |  |   | 158,677
|                                                               |  |                                 |         |                                |   |         |  |      |         |  |   |        
|Total revenues from sales to member distribution cooperatives  |  | $                               | 181,607 |                                | $ | 142,585 |  | $    | 484,367 |  | $ | 405,336
|                                                               |  |                                 |         |                                |   |         |  |      |         |  |   |        
|Average costs to member distribution cooperatives (per MWh)(1) |  | $                               | 57.39   |                                | $ | 51.28   |  | $    | 57.24   |  | $ | 50.45  

---

|(1) | Our average costs to member distribution cooperatives are based on the blended cost of power.
|--- | ---------------------------------------------------------------------------------------------



Growth in the number of consumers and growth in
consumers requirements for power significantly affect our member distribution cooperatives consumers requirements for power. Factors affecting our member distribution cooperatives consumers requirements for power
include the amount, size, and usage of electronics and machinery and the expansion of operations among their commercial and industrial customers. Weather also affects the requirement for electricity. Relatively higher or lower temperatures tend to
increase the requirement for energy to use air conditioning and heating systems. Mild weather generally reduces the requirement because air conditioning and heating systems are operated less.



Three Months Ended September 30, 2005 compared to Three Months ended
September 30, 2004:



Total revenues from sales to our
member distribution cooperatives for the three months ended September 30, 2005, increased $39.0 million, or 27.4%, over the same period in 2004, primarily as a result of higher energy rates, a 13.8% increase in energy sales volume and higher
incurred capacity costs (which are reflected in revenues in the period in which they are expensed).



Our total energy rate (including our base energy rate and our fuel factor adjustment rate) was 21.8% higher during the three months ended September 30,
2005, as compared to the same period in 2004. We increased our fuel factor adjustment rate effective October 1, 2004, and April 1, 2005, resulting in an increase to our total energy rate of approximately 6.3% and 14.6%, respectively. These increases
were implemented due to continued rising energy costs in 2004 and 2005 resulting in increased fuel and purchased power costs.



The capacity costs we incurred, and thus the capacity-related revenues we reflected pursuant to the formulary rate, for the three months ended September
30, 2005, as compared to the same period in 2004, increased $4.4 million, or 8.3%, primarily as a result of legal fees which were previously capitalized and are now reflected in administrative and general expense associated with the litigation
against Ragnar Benson, Inc., (RBI) and slightly higher depreciation and interest expense because of the commercial operation of Marsh Run which began in September 2004. See Interest Charges for a discussion of interest
expenses.



Our average costs to member distribution
cooperatives per MWh increased $6.11 per MWh, or 11.9%, for the three months ended September 30, 2005, as compared to the same period in 2004, primarily as a result of the increase in our total energy rates related to increased fuel and purchased
power costs.



Nine Months Ended September 30, 2005 compared
to Nine Months Ended September 30, 2004:



Total
revenues from sales to our member distribution cooperatives for the nine months ended September 30, 2005, increased $79.0 million, or 19.5%, as compared to the same period in 2004 primarily as a result of higher energy rates, a 5.3% increase in
energy sales volume and slightly higher incurred capacity costs (which are reflected in revenues in the period in which they are expensed).



Our total energy rate (including our base energy rate and our fuel factor adjustment rate) was 22.2% higher during the nine months ended September 30,
2005, as compared to the same period in 2004. We increased our fuel factor adjustment rate effective October 1, 2004, and April 1, 2005, resulting in an increase to our total energy rate of approximately 6.3% and 14.6%, respectively. These increases
were implemented due to higher than anticipated energy costs in 2004 and 2005 related to continued increased fuel and purchased power costs.



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##### Table of Contents

The capacity costs we incurred for the nine months ended September 30, 2005, as compared to the same
period in 2004, increased $8.2 million, or 5.2%, primarily as a result of slightly higher depreciation and interest expense because of the commercial operation of Marsh Run which began in September 2004 as well as legal fees which were previously
capitalized and are now reflected in administrative and general expense associated with the litigation against RBI. For the nine months ended September 30, 2004, costs for Marsh Run, including interest, were being capitalized. See Interest
Charges for a discussion of interest expenses.



Our
average costs to member distribution cooperatives per MWh increased $6.79 per MWh, or 13.5%, for the nine months ended September 30, 2005, as compared to the same period in 2004, primarily as a result of the increase in our total energy rates
related to increased fuel and purchased power costs.



Sales to TEC.Beginning January 1, 2005, we reported no sales to TEC because TEC is now consolidated as a result of the adoption of the Interpretation. Sales between Old Dominion and TEC have been eliminated in
consolidation and TECs sales to third parties are reflected as non-member revenues. See Note 2Notes to Condensed Consolidated Financial Statements in Part 1, Item 1. Prior to January 1, 2005, sales to TEC consisted primarily of sales of
excess energy that we did not need to meet the actual needs of our member distribution cooperatives. We sold the portion of this energy that could not be utilized by our member distribution cooperatives to TEC for resale into the market, or to
non-members.



Sales to Non-Members.Sales to
non-members consist of sales of excess purchased energy and sales of excess generated energy. We primarily sell excess purchased energy to PJM under its rates for providing energy imbalance services. Prior to May 1, 2005, we also sold excess energy
from the Clover Power Station (Clover) to Virginia Power pursuant to the requirements of the Clover operating agreement. Beginning in 2005, TECs sales to third parties are also reflected as sales to non-members. Non-member revenue
increased by $24.9 million and $51.2 million in the three and nine months ended September 30, 2005, respectively, over the same periods in 2004. The increase in non-member revenue for the three months ended September 30, 2005, is primarily due to an
increase in the prices at which we sold excess energy to non members and an increase in the volume of excess energy sales. The increase in non-member revenue for the three and nine months ended September 30, 2005, is primarily due to increased sales
of excess energy. Excess energy, which is sold to third parties, is the result of changes in our purchased power portfolio, differences between actual and forecasted energy needs, as well as changes in market conditions. The increase in non-member
sales in MWh is driven by our strategy to hedge a greater percentage of our exposure to spot market prices under purchasing arrangements. Additionally, sales to non-members for the nine months ended September 30, 2005, also include increased sales
of excess energy as a result of the delay of Virginia Power joining PJM from January 1, 2005, to May 1, 2005.



Operating Expenses



We supply our member distribution cooperatives power requirements, consisting of capacity requirements and energy requirements, through (i) our owned or leased interests in electric generating facilities which consist of a 50%
interest in Clover, an 11.6% interest in the North Anna Nuclear Power Station (North Anna), our Louisa combustion turbine facility (Louisa), Marsh Run, our Rock Springs combustion turbine facility (Rock Springs),
and our distributed generation facilities, and (ii) power purchases from third parties through power purchase contracts and forward, short-term and spot market energy purchases. Our energy supply for the three and nine months ended September 30,
2005 and 2004, was as follows:



|                       |  |                                  |  |       |                                 |  |           |      |       |   |      |           |  |       |   |  |           |  |       |  
|---------------------- |  | -------------------------------- |  | ----- | ------------------------------- |  | --------- | ---- | ----- | - | ---- | --------- |  | ----- | - |  | --------- |  | ----- | -
|                       |  | Three Months Ended September 30, |  |       | Nine Months Ended September 30, | 
|                       |  | 2005                             |  |       | 2004                            |  |           | 2005 |       |   | 2004 |          
|                       |  | (in MWh and percentages)         |  |       | (in MWh and percentages)        | 
|Generated:             |  |                                  |  |       |                                 |  |           |      |       |   |      |           |  |       |   |  |           |  |       |  
|Clover                 |  | 879,854                          |  | 24.9  | %                               |  | 904,361   |      | 30.7  | % |      | 2,338,480 |  | 24.2  | % |  | 2,438,161 |  | 28.8  | %
|North Anna             |  | 457,806                          |  | 13.0  |                                 |  | 421,587   |      | 14.3  |   |      | 1,389,300 |  | 14.4  |   |  | 1,263,297 |  | 14.9  |  
|Louisa                 |  | 144,271                          |  | 4.1   |                                 |  | 73,035    |      | 2.5   |   |      | 174,990   |  | 1.8   |   |  | 198,490   |  | 2.3   |  
|Marsh Run              |  | 137,400                          |  | 3.9   |                                 |  | 1,417     |      |      |   |      | 198,473   |  | 2.1   |   |  | 1,417     |  |      |  
|Rock Springs           |  | 86,348                           |  | 2.4   |                                 |  | 26,878    |      | 0.9   |   |      | 108,876   |  | 1.1   |   |  | 110,318   |  | 1.3   |  
|Distributed generation |  | 1,534                            |  |      |                                 |  | 277       |      |      |   |      | 2,171     |  |      |   |  | 277       |  |      |  
|                       |  |                                  |  |       |                                 |  |           |      |       |   |      |           |  |       |   |  |           |  |       |  
|Total generated        |  | 1,707,213                        |  | 48.3  |                                 |  | 1,427,555 |      | 48.4  |   |      | 4,212,290 |  | 43.6  |   |  | 4,011,960 |  | 47.3  |  
|                       |  |                                  |  |       |                                 |  |           |      |       |   |      |           |  |       |   |  |           |  |       |  
|Purchased:             |  |                                  |  |       |                                 |  |           |      |       |   |      |           |  |       |   |  |           |  |       |  
|Total purchased        |  | 1,830,414                        |  | 51.7  |                                 |  | 1,522,137 |      | 51.6  |   |      | 5,458,631 |  | 56.4  |   |  | 4,467,968 |  | 52.7  |  
|                       |  |                                  |  |       |                                 |  |           |      |       |   |      |           |  |       |   |  |           |  |       |  
|Total available energy |  | 3,537,627                        |  | 100.0 | %                               |  | 2,949,692 |      | 100.0 | % |      | 9,670,921 |  | 100.0 | % |  | 8,479,928 |  | 100.0 | %
|                       |  |                                  |  |       |                                 |  |           |      |       |   |      |           |  |       |   |  |           |  |       |  



We satisfy the
majority of our member distribution cooperatives capacity requirements and a portion of their energy requirements through our ownership interests in Clover, North Anna, Louisa, Marsh Run and Rock Springs. We purchase capacity and energy from
the market to supply the remaining needs of our member distribution cooperatives.



12



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##### Table of Contents

Our operating expenses are significantly affected by the extent to which we purchase power and,
relatedly, the availability of our base load generating facilities, Clover and North Anna. Base load generating facilities, particularly nuclear power plants such as North Anna, generally have relatively high fixed costs, but nuclear facilities
operate with relatively low variable costs due to lower fuel costs and technological efficiencies. In addition, coal-fired facilities also have relatively low variable costs, as compared to combustion turbine facilities such as Louisa, Marsh Run and
Rock Springs. Owners of nuclear and other power plants incur the embedded fixed costs of these facilities whether or not the units operate. When either Clover or North Anna is off-line, we must purchase replacement energy from the PJM market, which
may be more or less costly. Our combustion turbine facilities have relatively low fixed costs and greater operational flexibility, but are more expensive to operate; therefore, we operate them only when the market price of energy makes their
operation economical. As a result, our operating expenses, and consequently our rates to our member distribution cooperatives, are more significantly affected by the operations of Clover and North Anna than by our combustion turbine facilities. The
output of Clover and North Anna for the three and nine months ended September 30, 2005 and 2004, as a percentage of the maximum net dependable capacity rating of the facilities was as follows:



|         |  |                                 |   |  |                                |   |  |                                 |   |  |                                |   |  |      |   |  |      |   |  |      |   |  |      |  
|-------- |  | ------------------------------- | - |  | ------------------------------ | - |  | ------------------------------- | - |  | ------------------------------ | - |  | ---- | - |  | ---- | - |  | ---- | - |  | ---- | -
|         |  | Clover                          |   |  | North Anna                     |  
|         |  | Three Months EndedSeptember 30, |   |  | Nine Months EndedSeptember 30, |   |  | Three Months EndedSeptember 30, |   |  | Nine Months EndedSeptember 30, |  
|         |  | 2005                            |   |  | 2004                           |   |  | 2005                            |   |  | 2004                           |   |  | 2005 |   |  | 2004 |   |  | 2005 |   |  | 2004 |  
|Unit 1   |  | 91.5                            | % |  | 93.9                           | % |  | 86.3                            | % |  | 78.5                           | % |  | 97.6 | % |  | 78.8 | % |  | 99.8 | % |  | 90.8 | %
|Unit 2   |  | 91.5                            |   |  | 93.6                           |   |  | 77.8                            |   |  | 91.4                           |   |  | 96.5 |   |  | 99.5 |   |  | 99.2 |   |  | 88.9 |  
|Combined |  | 91.5                            |   |  | 93.8                           |   |  | 82.1                            |   |  | 85.0                           |   |  | 97.1 |   |  | 89.2 |   |  | 99.5 |   |  | 89.9 |  



Clover.During the three months ended September 30, 2005, both Clover Units 1 and 2 were available for dispatch. Clover Units 1 and 2 experienced minor unscheduled outages during the nine months ended September 30,
2005, and September 30, 2004. On May 1, 2005, operational control of Virginia Powers transmission facilities was transferred to PJM. With that transfer, all of our member distribution cooperatives capacity and energy requirements are now
within the PJM control area and our generating facilities are now under dispatch control of PJM. Accordingly, Clover Units 1 and 2 are operated pursuant to PJM dispatching requirements. During the nine months ended September 30, 2005, Clover Units 1
and 2 were dispatched less by PJM based upon economic factors. When our generating facilities are dispatched less, we purchase more power to meet the needs of our member distribution cooperatives. Clover Unit 1 was off-line for 37 days for scheduled
maintenance outages during the nine months ended September 30, 2004.



North Anna.North Anna Units 1 and 2 experienced minor unscheduled outages during the three and nine months ended September 30, 2005. North Anna Unit 1 was off-line for 19 days for a scheduled refueling outage during
the three and nine months ended September 30, 2004. North Anna Unit 2 was off-line for 28 days for a scheduled refueling outrage during the nine months ended September 30, 2004.



Combustion turbine facilities.During the three and nine months ended September 30, 2005, the operational
availability of our Louisa, Marsh Run and Rock Springs combustion turbine facilities was as follows:



|             |  |                                 |   |  |                                |   |  |      |   |  |      |  
|------------ |  | ------------------------------- | - |  | ------------------------------ | - |  | ---- | - |  | ---- | -
|             |  | Three Months EndedSeptember 30, |   |  | Nine Months EndedSeptember 30, |  
|             |  | 2005                            |   |  | 2004                           |   |  | 2005 |   |  | 2004 |  
|Louisa       |  | 98.9                            | % |  | 94.9                           | % |  | 97.6 | % |  | 95.9 | %
|Marsh Run(1) |  | 93.6                            |   |  |                               |   |  | 96.6 |   |  |     |  
|Rock Springs |  | 97.9                            |   |  | 99.9                           |   |  | 97.6 |   |  | 96.0 |  

---

|(1) | Marsh Run became commercially operable in September 2004.
|--- | ---------------------------------------------------------



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The components of our operating expenses for the three and nine months ended September 30, 2005 and 2004,
were as follows:



|                                                  |  |                                 |         |   |                                |   |         |      |  |   |         |   |  |   |         |  
|------------------------------------------------- |  | ------------------------------- | ------- | - | ------------------------------ | - | ------- | ---- |  | - | ------- | - |  | - | ------- | -
|                                                  |  | Three Months EndedSeptember 30, |         |   | Nine Months EndedSeptember 30, |  
|                                                  |  | 2005                            |         |   | 2004                           |   |         | 2005 |  |   | 2004    |  
|                                                  |  | (in thousands)                  |         |   | (in thousands)                 |  
|Fuel                                              |  | $                               | 62,754  |   |                                | $ | 25,700  |      |  | $ | 112,539 |   |  | $ | 67,300  |  
|Purchased power                                   |  |                                 | 118,171 |   |                                |   | 92,194  |      |  |   | 325,908 |   |  |   | 239,730 |  
|Deferred energy                                   |  |                                 | (22,144 | ) |                                |   | (7,360  | )    |  |   | (38,622 | ) |  |   | (14,797 | )
|Operations and maintenance                        |  |                                 | 9,190   |   |                                |   | 2,817   |      |  |   | 25,614  |   |  |   | 23,538  |  
|Administrative and general                        |  |                                 | 10,175  |   |                                |   | 6,425   |      |  |   | 25,942  |   |  |   | 20,994  |  
|Depreciation, amortization and decommissioning    |  |                                 | 9,798   |   |                                |   | 7,817   |      |  |   | 29,113  |   |  |   | 22,485  |  
|Amortization of regulatory asset/(liability), net |  |                                 | 175     |   |                                |   | 1,577   |      |  |   | 1,348   |   |  |   | 5,863   |  
|Taxes, other than income taxes                    |  |                                 | 1,562   |   |                                |   | 1,390   |      |  |   | 4,724   |   |  |   | 3,809   |  
|Accretion                                         |  |                                 | 618     |   |                                |   | 558     |      |  |   | 1,854   |   |  |   | 1,664   |  
|                                                  |  |                                 |         |   |                                |   |         |      |  |   |         |   |  |   |         |  
|Total Operating Expenses                          |  | $                               | 190,299 |   |                                | $ | 131,118 |      |  | $ | 488,420 |   |  | $ | 370,586 |  
|                                                  |  |                                 |         |   |                                |   |         |      |  |   |         |   |  |   |         |  



Three Months Ended
September 30, 2005 compared to Three Months ended September 30, 2004:



Aggregate operating expenses increased $59.2 million, or 45.1%, for the three months ended September 30, 2005, as compared to the same period in 2004, primarily due to increases in fuel and purchased power expense,
partially offset by the change in deferred energy expense.



Fuel expense increased $37.1 million, or 144.2%, for the three months ended September 30, 2005, as compared to the same period in 2004, primarily as a result of the 70.2% increase in the average cost of natural gas, the 25.6% increase in
the average cost of coal and the increased operation of our combustion turbine facilities.



Purchased power expense increased $26.0 million, or 28.2%, for the three months ended September 30, 2005, as compared to the same period in 2004, primarily due to a 20.3% increase in the volume of purchased power and
a 6.6% increase in the average cost of purchased power. The increase in the average cost of purchased power is reflective of the overall price increases in energy costs across all markets.



Deferred energy expense changed $14.8 million, or 200.9%, for the three
months ended September 30, 2005, as compared to the same period in 2004. During the three months ended September 30, 2005, we under-collected $22.1 million in energy costs; whereas in the three months ended September 30, 2004, we under-collected
$7.4 million in energy costs. At September 30, 2005, we had an under-collected deferred energy balance of $33.8 million.



Nine Months Ended September 30, 2005 compared to Nine Months Ended September 30, 2004:



Aggregate operating expenses increased $117.8 million, or 31.8%, for the
nine months ended September 30, 2005, as compared to the same period in 2004, primarily due to increases in purchased power, fuel, and depreciation, amortization and decommissioning expense, partially offset by the change in deferred energy.



Purchased power expense increased $86.2 million, or 35.9%, for
the nine months ended September 30, 2005, as compared to the same period in 2004, due to a 22.2% increase in the volume of purchased power and a 11.3% increase in the average cost of purchased power. The increase in the average cost of purchased
power is reflective of the overall price increases in energy costs across all markets. As described above, on May 1, 2005, operational control of Virginia Powers transmission facilities was transferred to PJM. With this transfer, all of our
member distribution cooperatives capacity and energy requirements are now within the PJM control area and our generating facilities are now under dispatch control of PJM.



Fuel expense increased $45.2 million, or 67.2%, for the nine months ended September 30, 2005, as compared to the same period
in 2004, primarily as a result of a 62.8% increase in the average cost of natural gas, a 40.3% increase in the average cost of coal and the increased operation of Marsh Run.



Depreciation, amortization and decommissioning increased $6.6 million, or 29.5%, for the nine months ended September 30,
2005, primarily as a result of nine months of deprecation expense related to our Marsh Run combustion turbine facility in 2005 versus only one half of a month of depreciation for the nine months ended September 30, 2004. Marsh Run became
commercially operable in September 2004.



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Deferred energy expense changed $23.8 million, or 161.0%, for the nine months ended September 30, 2005,
as compared to the same period in 2004. During the first nine months of 2005, we under-collected $38.6 million in energy costs; whereas in the first nine months of 2004 we under-collected $14.8 million in energy costs. At September 30, 2005, we had
an under-collected deferred energy balance of $33.8 million.



On April 13, 2005, our Board of Directors approved an increase to our fuel factor adjustment rate, resulting in an increase to our total energy rate of approximately 14.6% effective April 1, 2005, due to continued rising energy costs.
Additionally, our Board of Directors approved a decrease in our demand rate of approximately 4.3%, effective April 1, 2005. This decrease was implemented due to an overall decline in fixed costs. The increase to our total energy rate effective April
1, 2005, was not sufficient to permit us to collect all incurred energy expenses and on October 12, 2005, our Board of Directors approved an increase to our fuel factor adjustment rate, resulting in an increase to our total energy rate of
approximately 8.1%, effective October 1, 2005.



Other Items



Investment Income.Investment
income increased $1.1 million, or 420.2%, for the three months ended September 30, 2005, and $1.4 million or 61.9% for the nine months ended September 30, 2005, as compared to the same periods in 2004, primarily due to income earned on our increased
balance in cash and temporary investments.



Interest
Charges, net. The primary factors affecting our interest expense are scheduled payments of principal on our indebtedness, issuance of new indebtedness and capitalized interest.



The major components of interest charges, net for the three and nine months
ended September 30, 2005 and 2004, were as follows:



|                                                      |  |                                 |         |   |                                |   |         |      |  |   |         |   |  |   |         |  
|----------------------------------------------------- |  | ------------------------------- | ------- | - | ------------------------------ | - | ------- | ---- |  | - | ------- | - |  | - | ------- | -
|                                                      |  | Three Months EndedSeptember 30, |         |   | Nine Months EndedSeptember 30, |  
|                                                      |  | 2005                            |         |   | 2004                           |   |         | 2005 |  |   | 2004    |  
|                                                      |  | (in thousands)                  |         |   | (in thousands)                 |  
|Interest expense on long-term debt                    |  | $                               | (14,161 | ) |                                | $ | (14,148 | )    |  | $ | (42,546 | ) |  | $ | (42,153 | )
|Other                                                 |  |                                 | (614    | ) |                                |   | 99      |      |  |   | (1,657  | ) |  |   | (1,658  | )
|                                                      |  |                                 |         |   |                                |   |         |      |  |   |         |   |  |   |         |  
|Total Interest Charges                                |  |                                 | (14,775 | ) |                                |   | (14,049 | )    |  |   | (44,203 | ) |  |   | (43,811 | )
|Allowance for borrowed funds used during construction |  |                                 | 58      |   |                                |   | 2,532   |      |  |   | 170     |   |  |   | 8,111   |  
|                                                      |  |                                 |         |   |                                |   |         |      |  |   |         |   |  |   |         |  
|Interest Charges, net                                 |  | $                               | (14,717 | ) |                                | $ | (11,517 | )    |  | $ | (44,033 | ) |  | $ | (35,700 | )
|                                                      |  |                                 |         |   |                                |   |         |      |  |   |         |   |  |   |         |  



Interest charges, net
increased by $3.2 million, or 27.8%, for the three months ended September 30, 2005, and $8.3 million, or 23.3%, for the nine months ended September 30, 2005, as compared to the same periods in 2004, primarily due to the reduction in capitalized
interest associated with Marsh Run. We ceased capitalizing interest on Marsh Run in September 2004 when the facility became commercially operable. Capitalized interest is computed monthly using an interest rate, which reflects our embedded cost of
indebtedness, multiplied by our investment in projects under construction.



Net Margin.Our net margin, which is a function of our total interest charges, remained relatively flat for the three and nine months ended September 30, 2005, as compared to the same period in
2004.



Financial Condition



The principal changes in our financial condition from December 31, 2004 to
September 30, 2005, were caused by increases in accounts payable, regulatory liabilities, accounts payabledeposits, deferred chargesother, accounts payablemembers, non-controlling interest related to the consolidation of TEC, and
the change in deferred energy. Accounts payable increased $64.4 million as a result of increased purchased power. Regulatory liabilities increased $56.6 million primarily due to deferred derivative activity. Accounts payabledeposits increased
$42.4 million because our counterparties were required to post deposits pursuant to credit terms in our master power purchase and sales agreements with them. Deferred chargesother increased $39.6 million as a result of derivative activity.
Accounts payablemembers increased $27.4 million primarily due to increased sales as well as member prepayments. Non-controlling interest related to the consolidation of TEC increased $22.8 million due to the increase in unrealized gains on
derivatives recorded on TECs financial statements as a result of a change in the market value of its contracts for delivery of gas in the future at specified prices. Our deferred energy balance represents the net under- or over-collection of
energy



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##### Table of Contents

costs as of the end of the reporting period. These amounts are recovered from or refunded to our member distribution
cooperatives in subsequent periods. The deferred energy balance changed from a $4.7 million liability (over-collection of costs) at December 31, 2004, to a $33.8 million asset (under-collection of costs) at September 30, 2005.



Liquidity and Capital Resources



Operations. Historically, our operating cash flows have been
sufficient to meet our short- and long-term capital expenditures related to our existing generating facilities, our debt service requirements, and our ordinary business operations. Our operating activities provided cash flow of $167.1 million during
the first nine months of 2005. During the first nine months of 2004, our cash needs exceeded our cash flows from operating activities by $0.7 million. Operating activities in the first nine months of 2005 were primarily impacted by the change in
current liabilities, the change in regulatory assets and liabilities, partially offset by the change in deferred energy. Current liabilities increased $156.6 million primarily as a result of increased accounts payable related to purchased power and
fuel costs, accounts payablemembers as a result of increased sales and member prepayments, accounts payabledeposits as a result of our counterparties posting deposits in accordance with the terms of our respective master power purchase
and sales agreements with them, and accrued interest. Regulatory assets and liabilities changed $63.9 primarily due to deferred derivative activity. Also, the increase in the price of natural gas has increased the aggregate value of our natural gas
futures portfolio, allowing us to withdraw equity from our portfolio account in the form of cash. At September 30, 2005, we had an under-collected deferred energy balance of $33.8 million as compared to an over-collected deferred energy balance of
$4.8 million at December 31, 2004, which resulted in a cash outflow of $38.6 million.



Financing Activities.In addition to liquidity from our operating activities, we maintain committed lines of credit to cover short-term funding needs. As of September 30, 2005, we had short-term
committed variable rate lines of credit in an aggregate amount of $230.0 million. Of this amount, $180.0 million was available for general working capital purposes and $50.0 million was available for capital expenditures related to our generating
facilities. Additionally, we have a $50.0 million three-year revolving credit facility, which expires on March 18, 2007.



At September 30, 2005 and 2004, we had no short-term borrowings or letters of credit outstanding under any of these arrangements. We expect the working
capital lines of credit to be renewed as they expire. We expect the construction-related line of credit to be renewed until such time as we determine it is not needed.



Investing Activities.Investing activities in the first nine months of 2005 was primarily impacted by activity
related to available for sale securities, interest earned on investments-other and cash and cash equivalents, as well as electric plant additions for our generation facilities.



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##### Table of Contents

OLD DOMINION ELECTRIC COOPERATIVE



ITEM 3. QUANTITATIVE AND QUALITATIVE

DISCLOSURES ABOUT MARKET RISK



No material changes occurred in our exposure to market risk during the third
quarter of 2005.



ITEM 4. CONTROLS AND PROCEDURES



As of the end of the period covered by this report, our management, including the President and Chief Executive Officer and Senior Vice President and Chief Financial Officer conducted an evaluation of the effectiveness of our disclosure
controls and procedures. Based upon that evaluation, the President and Chief Executive Officer and Senior Vice President and Chief Financial Officer concluded that our disclosure controls and procedures are effective in ensuring that all material
information required to be filed in this report has been made known to them in a timely matter. We have established a Disclosure Assessment Committee comprised of members from senior and middle management to assist in this evaluation. There have
been no significant changes in our internal controls over financial reporting or in other factors that could significantly affect such controls during the past fiscal quarter.



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##### Table of Contents

OLD DOMINION ELECTRIC COOPERATIVE



PART II. OTHER INFORMATION



ITEM 1. LEGAL PROCEEDINGS



FERC Proceedings
Related to Potential Reorganization



The hearing at the
Federal Energy Regulatory Commission (FERC) regarding the proposed assignment of our wholesale power contracts with our member distribution cooperatives to New Dominion Energy Cooperative (New Dominion) was conducted on
October 18 through 20, 2005, and concluded on November 2, 2005. The initial decision is scheduled to be issued no later than February 6, 2006.



On August 30, 2005, a joint motion to revise the procedural schedule related to the applications for an amended cost-of service formula for New
Dominions sales to the member distribution cooperatives and for the cost allocation formula for our sales to New Dominion, was filed in light of continuing settlement discussions and on September 1, 2005, the request for the revision in the
procedural schedule was granted. On October 5, 2005, a joint motion to suspend the procedural schedule was filed as a result of progressing settlement discussions and on October 6, 2005, the motion was granted and the procedural schedule was
suspended.



On October 14, 2005, we filed an offer of partial
settlement with Bear Island Paper Company and the Virginia State Corporation Commission to settle all the issues in the FERC proceedings related to the applications for an amended cost-of service formula for New Dominions sales to the member
distribution cooperatives and for the cost allocation formula for our sales to New Dominion. Initial comments on the proposed partial settlement were filed on November 3, 2005, and reply comments are due by November 14, 2005. We cannot predict
whether a settlement will be reached on the basis of this or another proposal.



For further description of our legal proceedings for the FERC Proceedings Related to Potential Reorganization, see Legal Proceedings in our Quarterly Report on Form 10-Q for the quarter ended June 30,
2005, and in Part 1, Item 3 of our 2004 Annual Report on Form 10-K.



Ragnar
Benson, Inc.



On September 27, 2005, the U.S. District
Court for the Eastern District of Virginia, Richmond Division, ruled on motions for partial summary judgment in our claims against the EPC contractor of the Marsh Run facility. Specifically, the court granted Old Dominions motion for partial
summary judgment pertaining to claims of entitlement to a change order and fraud allegations, it dismissed six of Ragnar Benson, Inc.s (RBI) counterclaims, including all counterclaims pertaining to fraud, and it limited Old
Dominions possible recovery of liquidated damages to the liquidated damages cap of approximately $4.7 million. The trial began October 11, 2005 and concluded October 26, 2005. During the trial, RBI revised its claim from $33.0 million to $36.0
million. The case is pending in the U.S. District Court for the Eastern District of Virginia, Richmond Division.



RBI and its parent companies, The Austin Company and Austin Holdings, Inc., filed for bankruptcy under Chapter 11 of the bankruptcy code on October 14,
2005. The automatic litigation stay was lifted for the case between RBI and Old Dominion.



Other Matters



No
material developments have occurred in our legal proceedings with Norfolk Southern Railway Company since the filing of our Annual Report on Form 10-K for the fiscal year ended December 31, 2004. See Legal Proceedings in Part 1, Item 3 of
our 2004 Annual Report on Form 10-K. Other than legal proceedings arising out of the ordinary course of business, which management believes will not have a material adverse impact on our results of operations or financial condition, there is no
other litigation pending or threatened against us.





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##### Table of Contents

ITEM 6. EXHIBITS



|31.1 | Certification of the Chief Executive Officer pursuant to Rule 13a-14(a)
|---- | -----------------------------------------------------------------------

|31.2 | Certification of the Chief Financial Officer pursuant to Rule 13a-14(a)
|---- | -----------------------------------------------------------------------

|32.1 | Certification of the Chief Executive Officer pursuant to 18 U.S.C. § 1350
|---- | -------------------------------------------------------------------------

|32.2 | Certification of the Chief Financial Officer pursuant to 18 U.S.C. § 1350
|---- | -------------------------------------------------------------------------



19



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##### Table of Contents

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.



|                        |  |                                                  
|----------------------- |  | -------------------------------------------------
|                        |  | OLD DOMINION ELECTRIC COOPERATIVE                
|                        |  | Registrant                                       
|                        | 
|Date: November 10, 2005 |  | /s/ Daniel M. Walker                             
|                        |  | Daniel M. Walker                                 
|                        |  | Senior Vice President and Chief Financial Officer
|                        |  | (Principal Financial and Accounting Officer)     



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##### Table of Contents

EXHIBIT INDEX



|               |  |                                                                          
|-------------- |  | -------------------------------------------------------------------------
|Exhibit Number |  | Description of Exhibit                                                   
|31.1           |  | Certification of the Chief Executive Officer pursuant to Rule 13a-14(a)  
|               | 
|31.2           |  | Certification of the Chief Financial Officer pursuant to Rule 13a-14(a)  
|               | 
|32.1           |  | Certification of the Chief Executive Officer pursuant to 18 U.S.C. § 1350
|               | 
|32.2           |  | Certification of the Chief Financial Officer pursuant to 18 U.S.C. § 1350



21