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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 March 31, 2004



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 Exchange Act Rule 12b-2).    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



|                              |  |                                                                                                                                        |  |            
|----------------------------- |  | -------------------------------------------------------------------------------------------------------------------------------------- |  | -----------
|                              |  |                                                                                                                                        |  | Page Number
|PART I. Financial Information |  |                                                                                                                                       
|                              |  |                                                                                                                                       
|Item 1.                       |  | Financial Statements                                                                                                                   |  |            
|                              |  |                                                                                                                                       
|                              |  | Condensed Consolidated Balance Sheets  March 31, 2004 (Unaudited) and December 31, 2003                                               |  | 3          
|                              |  |                                                                                                                                       
|                              |  | Condensed Consolidated Statements of Revenues, Expenses and Patronage Capital (Unaudited)  Three Months Ended March 31, 2004 and 2003 |  | 4          
|                              |  |                                                                                                                                       
|                              |  | Condensed Consolidated Statements of Comprehensive Income (Unaudited) - Three Months Ended March 31, 2004 and 2003                     |  | 4          
|                              |  |                                                                                                                                       
|                              |  | Condensed Consolidated Statements of Cash Flows (Unaudited)  Three Months Ended March 31, 2004 and 2003                               |  | 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                                                                             |  | 16         
|                              |  |                                                                                                                                       
|Item 4.                       |  | Controls and Procedures                                                                                                                |  | 16         
|                              | 
|PART II. Other Information    |  |                                                                                                                                       
|                              |  |                                                                                                                                       
|Item 1.                       |  | Legal Proceedings                                                                                                                      |  | 17         
|                              |  |                                                                                                                                       
|Item 5.                       |  | Other Information                                                                                                                      |  | 17         
|                              |  |                                                                                                                                       
|Item 6.                       |  | Exhibits and Reports on Form 8-K                                                                                                       |  | 17         
|                              | 
|Signatures                    |  | 18                                                                                                                                    



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OLD DOMINION ELECTRIC COOPERATIVE

PART I. FINANCIAL INFORMATION



ITEM 1. FINANCIAL STATEMENTS

CONDENSED CONSOLIDATED BALANCE SHEETS



|                                              |  |                |           |   |                    |   |           |  
|--------------------------------------------- |  | -------------- | --------- | - | ------------------ | - | --------- | -
|                                              |  | March 31, 2004 |           |   | December 31, 2003* |  
|                                              |  | (in thousands) |          
|                                              |  | (unaudited)    |           |   |                    |  
|ASSETS:                                       |  |                |           |   |                    |   |           |  
|Electric Plant:                               |  |                |           |   |                    |   |           |  
|In service                                    |  | $              | 1,316,749 |   |                    | $ | 1,313,649 |  
|Less accumulated depreciation                 |  |                | (405,312  | ) |                    |   | (397,327  | )
|                                              |  |                |           |   |                    |   |           |  
|                                              |  |                | 911,437   |   |                    |   | 916,322   |  
|Nuclear fuel, at amortized cost               |  |                | 6,075     |   |                    |   | 7,439     |  
|Construction work in progress                 |  |                | 177,924   |   |                    |   | 161,645   |  
|                                              |  |                |           |   |                    |   |           |  
|Net Electric Plant                            |  |                | 1,095,436 |   |                    |   | 1,085,406 |  
|                                              |  |                |           |   |                    |   |           |  
|Investments:                                  |  |                |           |   |                    |   |           |  
|Nuclear decommissioning trust                 |  |                | 70,123    |   |                    |   | 68,780    |  
|Lease deposits                                |  |                | 149,889   |   |                    |   | 150,559   |  
|Other                                         |  |                | 68,742    |   |                    |   | 57,659    |  
|                                              |  |                |           |   |                    |   |           |  
|Total Investments                             |  |                | 288,754   |   |                    |   | 276,998   |  
|                                              |  |                |           |   |                    |   |           |  
|Current Assets:                               |  |                |           |   |                    |   |           |  
|Cash and cash equivalents                     |  |                | 25,260    |   |                    |   | 31,758    |  
|Receivables                                   |  |                | 53,652    |   |                    |   | 59,708    |  
|Fuel, materials and supplies, at average cost |  |                | 26,304    |   |                    |   | 23,523    |  
|Prepayments                                   |  |                | 2,454     |   |                    |   | 2,571     |  
|                                              |  |                |           |   |                    |   |           |  
|Total Current Assets                          |  |                | 107,670   |   |                    |   | 117,560   |  
|                                              |  |                |           |   |                    |   |           |  
|Deferred Charges:                             |  |                |           |   |                    |   |           |  
|Regulatory assets                             |  |                | 65,603    |   |                    |   | 68,234    |  
|Other                                         |  |                | 14,089    |   |                    |   | 14,138    |  
|                                              |  |                |           |   |                    |   |           |  
|Total Deferred Charges                        |  |                | 79,692    |   |                    |   | 82,372    |  
|                                              |  |                |           |   |                    |   |           |  
|Total Assets                                  |  | $              | 1,571,552 |   |                    | $ | 1,562,336 |  
|                                              |  |                |           |   |                    |   |           |  
|CAPITALIZATION AND LIABILITIES:               |  |                |           |   |                    |   |           |  
|Capitalization:                               |  |                |           |   |                    |   |           |  
|Patronage capital                             |  | $              | 250,542   |   |                    | $ | 247,590   |  
|Long-term debt                                |  |                | 873,736   |   |                    |   | 873,041   |  
|                                              |  |                |           |   |                    |   |           |  
|Total Capitalization                          |  |                | 1,124,278 |   |                    |   | 1,120,631 |  
|                                              |  |                |           |   |                    |   |           |  
|Current Liabilities:                          |  |                |           |   |                    |   |           |  
|Accounts payable                              |  |                | 42,188    |   |                    |   | 66,812    |  
|Accounts payable  members                    |  |                | 72,461    |   |                    |   | 47,788    |  
|Accrued expenses                              |  |                | 50,043    |   |                    |   | 36,439    |  
|Deferred energy                               |  |                | 5,713     |   |                    |   | 13,582    |  
|                                              |  |                |           |   |                    |   |           |  
|Total Current Liabilities                     |  |                | 170,405   |   |                    |   | 164,621   |  
|                                              |  |                |           |   |                    |   |           |  
|Deferred Credits and Other Liabilities        |  |                |           |   |                    |   |           |  
|Asset retirement obligation                   |  |                | 43,551    |   |                    |   | 42,997    |  
|Obligations under long-term leases            |  |                | 152,659   |   |                    |   | 153,659   |  
|Regulatory liabilities                        |  |                | 37,912    |   |                    |   | 37,024    |  
|Other                                         |  |                | 42,747    |   |                    |   | 43,404    |  
|                                              |  |                |           |   |                    |   |           |  
|Total Deferred Credits and Other Liabilities  |  |                | 276,869   |   |                    |   | 277,084   |  
|                                              |  |                |           |   |                    |   |           |  
|Commitments and Contingencies                 |  |                |          |   |                    |   |          |  
|                                              |  |                |           |   |                    |   |           |  
|Total Capitalization and Liabilities          |  | $              | 1,571,552 |   |                    | $ | 1,562,336 |  
|                                              |  |                |           |   |                    |   |           |  

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|* | The Condensed Consolidated Balance Sheet at December 31, 2003, has been taken from the audited financial statements at that date, but does not include all disclosures required by
generally accepted accounting principles.
|- | ----------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------



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 Ended March 31, |        
|                                                                      |  | 2004                         |         |   | 2003 |  
|                                                                      |  | (in thousands)               |        
|Operating Revenues                                                    |  | $                            | 134,961 |   |      | $ | 143,917 |  
|                                                                      |  |                              |         |   |      |   |         |  
|Operating Expenses:                                                   |  |                              |         |   |      |   |         |  
|Fuel                                                                  |  |                              | 20,125  |   |      |   | 13,269  |  
|Purchased power                                                       |  |                              | 80,933  |   |      |   | 109,672 |  
|Deferred energy                                                       |  |                              | (7,869  | ) |      |   | (16,261 | )
|Operations and maintenance                                            |  |                              | 8,826   |   |      |   | 15,385  |  
|Administrative and general                                            |  |                              | 7,612   |   |      |   | 5,181   |  
|Depreciation, amortization and decommissioning                        |  |                              | 7,332   |   |      |   | 5,438   |  
|Amortization of regulatory asset/(liability), net                     |  |                              | 1,756   |   |      |   | (4,354  | )
|Taxes other than income taxes                                         |  |                              | 1,220   |   |      |   | 837     |  
|Accretion                                                             |  |                              | 553     |   |      |   | 517     |  
|                                                                      |  |                              |         |   |      |   |         |  
|Total Operating Expenses                                              |  |                              | 120,488 |   |      |   | 129,684 |  
|                                                                      |  |                              |         |   |      |   |         |  
|Operating Margin                                                      |  |                              | 14,473  |   |      |   | 14,233  |  
|Other Expense, net                                                    |  |                              | (12     | ) |      |   | (20     | )
|Investment Income                                                     |  |                              | 561     |   |      |   | 145     |  
|Interest Charges, net                                                 |  |                              | (12,070 | ) |      |   | (8,371  | )
|                                                                      |  |                              |         |   |      |   |         |  
|Net Margin Before Cumulative Effect of Change in Accounting Principle |  |                              | 2,952   |   |      |   | 5,987   |  
|Cumulative Effect of Change in Accounting Principle                   |  |                              |        |   |      |   | (3,271  | )
|                                                                      |  |                              |         |   |      |   |         |  
|Net Margin After Cumulative Effect of Change in Accounting Principle  |  |                              | 2,952   |   |      |   | 2,716   |  
|                                                                      |  |                              |         |   |      |   |         |  
|Patronage Capital  Beginning of Period                               |  |                              | 247,590 |   |      |   | 235,534 |  
|                                                                      |  |                              |         |   |      |   |         |  
|Patronage Capital  End of Period                                     |  | $                            | 250,542 |   |      | $ | 238,250 |  
|                                                                      |  |                              |         |   |      |   |         |  



OLD DOMINION ELECTRIC COOPERATIVE



CONDENSED CONSOLIDATED STATEMENTS

OF COMPREHENSIVE INCOME (UNAUDITED)



|                                        |  |                              |       |      |   |       
|--------------------------------------- |  | ---------------------------- | ----- | ---- | - | ------
|                                        |  | Three Months Ended March 31,
|                                        |  | 2004                         |       | 2003
|                                        |  | (in thousands)              
|Net Margin                              |  | $                            | 2,952 |      | $ | 2,716 
|                                        |  |                              |       |      |   |       
|Other Comprehensive Income:             |  |                              |       |      |   |       
|Unrealized gain on derivative contracts |  |                              |      |      |   | 10,480
|                                        |  |                              |       |      |   |       
|Other comprehensive income              |  |                              |      |      |   | 10,480
|                                        |  |                              |       |      |   |       
|Comprehensive Income                    |  | $                            | 2,952 |      | $ | 13,196
|                                        |  |                              |       |      |   |       



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 FLOW (UNAUDITED)



|                                                                                              |  |                              |         |   |      |   |         |  
|--------------------------------------------------------------------------------------------- |  | ---------------------------- | ------- | - | ---- | - | ------- | -
|                                                                                              |  | Three Months Ended March 31, |        
|                                                                                              |  | 2004                         |         |   | 2003 |  
|                                                                                              |  | (in thousands)               |        
|Operating Activities:                                                                         |  |                              |         |   |      |   |         |  
|Net Margin                                                                                    |  | $                            | 2,952   |   |      | $ | 2,716   |  
|Adjustments to reconcile net margins to net cash provided by (used for) operating activities: |  |                              |         |   |      |   |         |  
|Cumulative effect of change in accounting principle                                           |  |                              |        |   |      |   | 3,271   |  
|Depreciation, amortization and decommissioning                                                |  |                              | 7,332   |   |      |   | 5,438   |  
|Other non-cash charges                                                                        |  |                              | 2,577   |   |      |   | 1,801   |  
|Amortization of lease obligations                                                             |  |                              | 2,481   |   |      |   | 2,372   |  
|Interest on lease deposits                                                                    |  |                              | (2,375  | ) |      |   | (2,263  | )
|Change in current assets                                                                      |  |                              | 3,392   |   |      |   | 1,456   |  
|Change in deferred energy                                                                     |  |                              | (7,869  | ) |      |   | (16,261 | )
|Change in current liabilities                                                                 |  |                              | 13,655  |   |      |   | (32     | )
|Change in regulatory assets and liabilities                                                   |  |                              | 2,772   |   |      |   | (4,540  | )
|Deferred charges and credits                                                                  |  |                              | 79      |   |      |   | 3,421   |  
|                                                                                              |  |                              |         |   |      |   |         |  
|Net Cash Provided by (Used for) Operating Activities                                          |  |                              | 24,996  |   |      |   | (2,621  | )
|                                                                                              |  |                              |         |   |      |   |         |  
|Financing Activities:                                                                         |  |                              |         |   |      |   |         |  
|Obligations under long-term leases                                                            |  |                              | (436    | ) |      |   | (109    | )
|                                                                                              |  |                              |         |   |      |   |         |  
|Net Cash Used for Financing Activities                                                        |  |                              | (436    | ) |      |   | (109    | )
|                                                                                              |  |                              |         |   |      |   |         |  
|Investing Activities:                                                                         |  |                              |         |   |      |   |         |  
|Investments, net                                                                              |  |                              | (11,679 | ) |      |   | 6,803   |  
|Electric plant additions                                                                      |  |                              | (19,379 | ) |      |   | (39,035 | )
|Decommissioning fund deposits                                                                 |  |                              |        |   |      |   | (170    | )
|                                                                                              |  |                              |         |   |      |   |         |  
|Net Cash Used for Investing Activities                                                        |  |                              | (31,058 | ) |      |   | (32,402 | )
|                                                                                              |  |                              |         |   |      |   |         |  
|Net Change in Cash and Cash Equivalents                                                       |  |                              | (6,498  | ) |      |   | (35,132 | )
|Cash and Cash Equivalents  Beginning of Period                                               |  |                              | 31,758  |   |      |   | 67,829  |  
|                                                                                              |  |                              |         |   |      |   |         |  
|Cash and Cash Equivalents  End of Period                                                     |  | $                            | 25,260  |   |      | $ | 32,697  |  
|                                                                                              |  |                              |         |   |      |   |         |  



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 March 31, 2004, and our consolidated results of operations, comprehensive income, and cash flows for the three months ended March 31, 2004 and 2003. The consolidated results
of operations for the three months ended March 31, 2004, 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 2003 Annual Report on Form 10-K filed with the Securities and Exchange Commission.
|-- | ---------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------



|2. | We adopted Statement of Financial Accounting Standards (SFAS) No. 143 Accounting for Asset Retirement Obligations effective January 1, 2003. SFAS No. 143
requires legal obligations associated with the retirement of long-lived assets to be recognized at fair value when incurred and capitalized as part of the related long-lived asset. Over time, the liability is accreted to its present value each
period, and the capitalized asset is depreciated over the useful life of the long-lived asset. SFAS No. 143 requires that any transition adjustment determined at adoption be recognized as a cumulative effect of change in accounting principle.
|-- | --------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------



In the absence of quoted market prices, we
determined fair value by using present value techniques, in which estimates of future cash flows associated with retirement activities are discounted using a credit adjusted risk free rate. Our estimated liability could change significantly if
actual costs vary from assumptions or if governmental regulations change significantly.



SFAS No. 143 applies to the decommissioning of the North Anna Nuclear Power Plant (North Anna), certain asset retirement obligations at the Clover Power Station (Clover), as well as certain
asset retirement obligations at our Rock Springs, Louisa, and Marsh Run combustion turbine facilities and our distributed generation facilities. At December 31, 2002, we had recorded a liability for the decommissioning of North Anna of $56.7
million, which equaled the balance in our nuclear decommissioning trust fund. At January 1, 2003, our liability for the decommissioning of North Anna as well as our liabilities associated with Clover and the distributed generation facilities as
calculated under SFAS No. 143 were $39.0 million. This liability was calculated using the present value of estimated future cash flows. We also recorded plant assets totaling $12.3 million and offsetting accumulated depreciation of $4.4 million. The
majority, $28.8 million, of the difference between what was recorded prior to January 1, 2003, and the net amount of what we recorded under SFAS No. 143 has been deferred as a regulatory liability. The remainder, $3.3 million, represents the
cumulative effect of change in accounting principle. See Notes to Consolidated Financial Statements  Note 3 Accounting for Asset Retirement Obligations of our Annual Report on Form 10-K for the fiscal year ended December 31,
2003, for further discussion of SFAS No. 143.



|3. | In December 1992, we entered into an agreement with Public Service Electric & Gas Company (PSE&G) to purchase capacity, reserves and associated energy, through
2004. In 1997, we filed a complaint with FERC to modify the transmission charges we pay PSE&G under the agreement to reflect the restructuring of PJM into an independent system operator. In 1998, the Federal Energy Regulatory Commission
(FERC) directed PSE&G to remove all transmission costs from its charges to us, effective April 1, 1998, in a general order addressing several cases relating to the restructuring of PJM (the PJM Order). PSE&G complied
with the PJM Order but appealed to the United States Court of Appeals for the District of Columbia Circuit. In July 2002, the Court of Appeals vacated the PJM Order and remanded the cases related to the PJM Order to FERC for further consideration.
Later in 2002, FERC reversed the PJM Order. FERC noted that there was no evidence in the PJM Order proceedings to demonstrate any unduly discriminatory effects of our contract with PSE&G, but stated that we could present evidence specific to our
contract.
|-- | -------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------



In January 2003, we filed an amended
and renewed complaint against PSE&G requesting that FERC (1) reopen our 1997 complaint and (2) eliminate rate pancaking (incurring charges from multiple transmission owners due to transmission across several systems) under our agreement
effective April 1, 1998. We also requested FERC stay any payment obligation to PSE&G for surcharges relating to the pancaked rates from April 1, 1998, through December 31, 2002.



We received an invoice from PSE&G in January 2003, for these additional surcharges in the amount of $26.2 million, plus
$4.7 million in interest. We responded to PSE&G that surcharges for any past amount due under our agreement remains unauthorized and premature until ordered by FERC. Effective February 1, 2003, however, we began collecting approximately $32.9
million, which includes interest and related margin requirement, from our member distribution cooperatives, over 48 months to recover these amounts. We are paying PSE&G surcharges for pancaked rates on a prospective basis, subject to protest and
FERC action



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on our renewed and amended complaint. On October 22, 2003, FERC denied our request to reopen the 1997
proceeding. We filed a request for rehearing in November 2003. On December 22, 2003, FERC issued a tolling order on our request for rehearing. The tolling order gives FERC an indefinite amount of time to rule on our request. As of May 14, 2004, FERC
has not ruled on this matter.



On December 8, 2003, PSE&G
filed a lawsuit in the United States Court of the District of New Jersey in Newark, seeking payment of $26.2 million plus late payment charges, interest, and costs, including attorney fees. On January 29, 2004, we filed a motion to dismiss or,
alternatively stay, any litigation pending a FERC decision on our request. On February 13, 2004, PSE&G filed a motion for summary judgment. Pending a hearing date on the cross motions, the New Jersey court has stayed discovery in the matter.



|4. | In October 2003, Norfolk Southern Railway Company (Norfolk Southern) notified an affiliate of Virginia Electric & Power Company (Virginia Power) that
Norfolk Southern intended, effective January 1, 2004, to correct the rates and method of quarterly adjustment in its Coal Transportation Agreement (Agreement) for Clover. Norfolk Southern alleges that the Agreement specifies
the use of a revised index instead of the initial index that has served as the basis of payment from inception of the Agreement. The Agreement, dated April 5, 1989, originally between Norfolk and Western Railway Company (Norfolk Western)
and us, has an initial term of 20 years after the first shipment of coal. We have the right to extend the Agreement for two additional five-year terms. The Agreement has since been assigned to Virginia Power in connection with its purchase of a 50%
undivided interest in Clover and its responsibilities as operating agent. Norfolk Western and Norfolk Southern merged in 1998. Coal has been delivered pursuant to the Agreement for over 10 years, and Norfolk Southern has accepted payment at the
initial index. We are continuing to pay Norfolk Southern at the initial index rate.
|-- | ------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------



In order to prevent the index change sought by Norfolk Southern, we and Virginia Power filed suit against Norfolk Southern on November 26, 2003, in the
Circuit Court of Halifax County, Virginia, requesting specific performance in the form of an injunction declaring that Norfolk Southern cannot change the initial index rate and, in the alternative, that the court enter a declaratory judgment
confirming the applicability of the initial index to the Agreement. On January 15, 2004, Norfolk Southern filed an answer and counterclaim (for declaratory judgment, specific performance and damages) and a pleading under which Virginia law alleges
that we and Virginia Power have failed to state a claim. A procedural schedule in the proceeding has not been set. We continue to work together with Virginia Power to prevent Norfolk Southern from depriving us of the economic benefits of the
Agreement. If it is ultimately determined that we owe any amounts to Norfolk Southern, such amounts are not expected to have a material impact on our financial position, results of operations, or cash flow due to our ability to collect such amounts
through rates.



|5. | TEC Trading, Inc. (TEC), which is owned by our member distribution cooperatives, was formed 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 to supply our three combustion turbine facilities, and taking advantage of other power-related trading opportunities in the market, which will
help lower our member distribution cooperatives costs. To fully participate in power and natural gas related markets, TEC must maintain credit support sufficient to meet delivery and payment obligations associated with power and natural gas
trades. To assist TEC in providing this credit support, we have agreed to guarantee up to $42.5 million of TECs delivery and payment obligations associated with its power and natural gas trades. At March 31, 2004, and December 31, 2003, we had
guaranteed $14.5 million and $9.5 million, respectively, of obligations of TEC. In April and May of 2004, we guaranteed an additional $6.75 million of obligations of TEC for a total of $21.25 million. During the three months ended March 31,
2004 and March 31, 2003, we had sales to TEC of $1.1 million and $6.0 million, respectively. During the three months ended March 31, 2004 and March 31, 2003, we charged administrative service fees to TEC of $3,000.
|-- | ------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------



|6. | In January 2003, the Financial Accounting Standards Board issued Interpretation No. 46, Consolidation of Variable Interest Entities, an Interpretation of Accounting Research
Bulletin No. 51 (the Interpretation). The Interpretation requires the consolidation of entities in which an enterprise absorbs a majority of the entitys expected losses, receives a majority of the entitys expected
residual returns, or both, as a result of ownership, contractual or other financial interests in the entity. Currently, entities are generally consolidated by an enterprise when it has a controlling financial interest through ownership of a majority
voting interest in the entity. For new entities created after February 1, 2003, the Interpretation is effective immediately; this new interpretation is effective for us by the end of 2004 for existing entities. Our affiliate, TEC, has been
identified as a variable interest entity and will be consolidated as of December 31, 2004. We believe that the consolidation of TEC will not have a material impact on our financial position, results of operations, or cash flow; however, the ultimate
impact on our financial statements at December 31, 2004, is dependent upon the level of TEC activity at year-end. We are continuing to evaluate the impact of applying this new statement and we believe that it will not have a material impact on our
financial position, results of operations, or cash flow.
|-- | ----------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------



|7. | Subsequent event  On May 11, 2004, our Board of Directors approved an increase to our fuel factor adjustment rate, resulting in an increase to our total energy rate of
approximately 15.6%, effective April 1, 2004. This increase was implemented due to higher than anticipated energy costs for the first quarter of 2004 and projected higher than previously anticipated energy costs for the remainder of 2004.
|-- | -----------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------



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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



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 March 31, 2004, 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, 2003. These policies included the accounting for rate regulation, deferred energy, asset retirement obligations, derivative contracts, and our margin stabilization plan.



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 the 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 the two separate 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 our energy costs without seeking the approval of FERC.



8



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##### Table of Contents

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 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 the board of directors to our annual budget.



Our operating revenues are derived from power sales to our members and
non-members. Our sales to members include sales to our Class A members, which are our twelve member distribution cooperatives, and sales to our single Class B member, TEC Trading, Inc. (TEC). Our operating revenues by type of purchaser
for the three months ended March 31, 2004 and 2003, were as follows:



|                                 |  |                              |         |      |   |        
|-------------------------------- |  | ---------------------------- | ------- | ---- | - | -------
|                                 |  | Three Months Ended March 31,
|                                 |  | 2004                         |         | 2003
|                                 |  | (in thousands)              
|Member revenues:                 |  |                              |         |      |   |        
|Member distribution cooperatives |  | $                            | 132,604 |      | $ | 136,185
|TEC                              |  |                              | 1,136   |      |   | 6,009  
|                                 |  |                              |         |      |   |        
|Total member revenues            |  |                              | 133,740 |      |   | 142,194
|Non-member revenues              |  |                              | 1,221   |      |   | 1,723  
|                                 |  |                              |         |      |   |        
|Total revenues                   |  | $                            | 134,961 |      | $ | 143,917
|                                 |  |                              |         |      |   |        



Our energy sales in megawatt-hours
(MWh) to our members and non-members were as follows:



|                                 |  |                              |  |          
|-------------------------------- |  | ---------------------------- |  | ---------
|                                 |  | Three Months Ended March 31,
|                                 |  | 2004                         |  | 2003     
|                                 |  | (in MWh)                    
|Member energy sales:             |  |                              |  |          
|Member distribution cooperatives |  | 2,841,956                    |  | 2,736,504
|TEC                              |  | 32,630                       |  | 104,000  
|                                 |  |                              |  |          
|Total energy sales to members    |  | 2,874,586                    |  | 2,840,504
|Non-member energy sales          |  | 33,547                       |  | 39,884   
|                                 |  |                              |  |          
|Total energy sales               |  | 2,908,133                    |  | 2,880,388
|                                 |  |                              |  |          



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, our member distribution cooperatives
consumers requirements for power and adjustments for the recovery or refund of amounts under our Margin Stabilization Plan. We adjust revenues and accounts payable-members or accounts receivable each quarter to reflect adjustments under the
Margin Stabilization Plan. 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, 2003, for a discussion of the Margin Stabilization
Plan. Our revenues from sales to our member distribution cooperatives by formulary rate component and average costs to our member distribution cooperatives in



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##### Table of Contents

MWh for the three months ended March 31, 2004, and 2003 were as follows:



|                                                               |  |                              |         |      |   |        
|-------------------------------------------------------------- |  | ---------------------------- | ------- | ---- | - | -------
|                                                               |  | Three Months Ended March 31,
|                                                               |  | 2004                         |         | 2003
|                                                               |  | (in thousands)              
|Revenues from sales to member distribution cooperatives:       |  |                              |         |      |   |        
|Base energy revenues                                           |  | $                            | 51,358  |      | $ | 49,455 
|Fuel factor adjustment revenues                                |  |                              | 28,004  |      |   | 23,385 
|                                                               |  |                              |         |      |   |        
|Total energy revenues                                          |  |                              | 79,362  |      |   | 72,840 
|                                                               |  |                              |         |      |   |        
|Demand (capacity) revenues                                     |  |                              | 53,242  |      |   | 63,345 
|                                                               |  |                              |         |      |   |        
|Total revenues from sales to member distribution cooperatives  |  | $                            | 132,604 |      | $ | 136,185
|                                                               |  |                              |         |      |   |        
|Average costs to member distribution cooperatives (per MWh)(1) |  | $                            | 46.66   |      | $ | 49.77  

---

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



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 weather, as well as, the
amount, size, and usage of electronics and machinery and the expansion of operations among their commercial and industrial customers. Weather affects the demand for electricity. Relatively higher or lower temperatures tend to increase the demand for
energy to use air conditioning and heating systems. Mild weather generally reduces the demand because heating and air conditioning systems are operated less.



Total revenues from sales to our member distribution cooperatives for the three months ended March 31, 2004, decreased $3.6 million, or 2.6%, over the
same period in 2003 primarily as a result of lower incurred capacity costs (which are reflected in revenues in the period in which they are expensed), partially offset by increased sales of energy and higher energy rates. Sales volumes increased
slightly as a result of colder weather experienced by consumers of our member distribution cooperatives in January and February which created a greater requirement for power to operate heating systems. This increase was partially offset by milder
weather in March.



The capacity costs we incurred, and thus the
capacity-related revenues we reflected, during the first three months of 2004 as compared to 2003, declined 16.0% primarily as a result of lower operations and maintenance expense. See Operating Expenses for a discussion of operations
and maintenance expense.



Our total energy rate (including our
base energy rate and our fuel factor adjustment rate) was 4.9% higher during the first three months of 2004 as compared to 2003. We decreased our fuel factor adjustment rate effective January 1, 2004, anticipating that a lower total energy rate
combined with the December 31, 2003, $13.6 million over-collected deferred energy balance would adequately recover our future energy costs. However, this new rate was higher than the average energy rate we charged during the first three months of
2003. Effective March 31, 2003, we increased the fuel factor adjustment rate component of our total energy rate to recover higher than expected actual energy costs incurred in the first two months of 2003 and higher anticipated energy costs for the
remainder of the year.



Sales to TEC.Our sales
to TEC are primarily sales of energy that we do not need to meet the actual needs of our member distribution cooperatives. We refer to this as excess energy. Revenue from sales to TEC is generated pursuant to our power sales contract with it. Sales
to TEC for the first quarter of 2004, were lower than in 2003 by $4.9 million, or 81.1%, because we had less excess energy in the first quarter of 2004 than in the first quarter of 2003. During the first quarter of 2003, we exercised a contractual
option to purchase energy at then favorable market prices. 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 from the Clover Power Station (Clover). We sell excess purchased energy that is not sold to TEC to PJM Interconnection, LLC (PJM) under its rates for providing
energy imbalance services. We sell excess energy from Clover to Virginia Electric and Power Company (Virginia Power) pursuant to the requirements of the Clover Operating Agreement. Non-member revenues for the three months ended March 31,
2004, were lower than in 2003 by $0.5 million, or 29.1%, primarily because of decreased sales of excess purchased energy to PJM. During the first quarter of 2003, we exercised a contractual option to purchase energy at then favorable market prices
and 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.



10



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##### Table of Contents

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 and Rock Springs
combustion turbine facilities, and distributed generation, 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 months ended March 31,
2004 and 2003, was as follows:



|                         |  |                              |  |       |      |  |           |  |       |  
|------------------------ |  | ---------------------------- |  | ----- | ---- |  | --------- |  | ----- | -
|                         |  | Three Months Ended March 31, | 
|                         |  | 2004                         |  |       | 2003 | 
|                         |  | (in MWh and percentages)     | 
|Generated:               |  |                              |  |       |      |  |           |  |       |  
|Mainland Virginia area:  |  |                              |  |       |      |  |           |  |       |  
|Clover                   |  | 878,791                      |  | 29.2  | %    |  | 802,393   |  | 27.0  |  
|North Anna               |  | 452,475                      |  | 15.0  |      |  | 262,454   |  | 8.9   |  
|Louisa                   |  | 41,754                       |  | 1.5   |      |  |          |  |      |  
|Distributed generation   |  |                             |  |      |      |  |          |  |      |  
|                         |  |                              |  |       |      |  |           |  |       |  
|Total Mainland Virginia  |  | 1,373,020                    |  | 45.7  |      |  | 1,064,847 |  | 35.9  |  
|                         |  |                              |  |       |      |  |           |  |       |  
|Delmarva Peninsula area: |  |                              |  |       |      |  |           |  |       |  
|Rock Springs             |  | 1,052                        |  |      |      |  |          |  |      |  
|Distributed generation   |  |                             |  |      |      |  | 271       |  |      |  
|                         |  |                              |  |       |      |  |           |  |       |  
|Total Delmarva Peninsula |  | 1,052                        |  |      |      |  | 271       |  |      |  
|                         |  |                              |  |       |      |  |           |  |       |  
|Total Generated          |  | 1,374,072                    |  | 45.7  |      |  | 1,065,118 |  | 35.9  |  
|                         |  |                              |  |       |      |  |           |  |       |  
|Purchased:               |  |                              |  |       |      |  |           |  |       |  
|Mainland Virginia area   |  | 999,178                      |  | 33.2  |      |  | 1,141,932 |  | 38.5  |  
|Delmarva Peninsula area  |  | 636,297                      |  | 21.1  |      |  | 759,414   |  | 25.6  |  
|                         |  |                              |  |       |      |  |           |  |       |  
|Total Purchased          |  | 1,635,475                    |  | 54.3  |      |  | 1,901,346 |  | 64.1  |  
|                         |  |                              |  |       |      |  |           |  |       |  
|Total Available Energy   |  | 3,009,547                    |  | 100.0 | %    |  | 2,966,464 |  | 100.0 | %
|                         |  |                              |  |       |      |  |           |  |       |  



In mainland Virginia,
we satisfy the majority of our member distribution cooperatives capacity and energy requirements through our ownership interests in Clover, North Anna, and Louisa, and we purchase energy from the market to supply the remaining needs of our
mainland Virginia member distribution cooperatives. To serve the Delmarva Peninsula, we rely on Rock Springs and power purchase agreements to provide the capacity to meet our member distribution cooperatives capacity requirements. To meet our
member distribution cooperatives energy requirements on the Delmarva Peninsula, we purchase energy from the market, or when economical, we utilize the PJM power pool or generate power from Rock Springs.



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. Nuclear
facilities operate with relatively low variable costs due to lower fuel costs and technological efficiencies. In addition, coal-fired facilities have relatively low variable costs, as compared to combustion turbine facilities such as Rock Springs
and Louisa. 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 either Virginia Power,
which is more costly, or from the market, which may be more or less costly. As a result, our operating expenses, and consequently our rates to our member distribution cooperatives, are significantly affected by the operations of Clover and North
Anna rather than our combustion turbine facilities. The output of Clover and North Anna for the first quarter of 2004 and 2003 as a percentage of the maximum dependable capacity rating of the facilities was as follows:



|         |  |                              |   |  |                              |   |  |       |   |  |      |  
|-------- |  | ---------------------------- | - |  | ---------------------------- | - |  | ----- | - |  | ---- | -
|         |  | Clover                       |   |  | North Anna                   |  
|         |  | Three Months Ended March 31, |   |  | Three Months Ended March 31, |  
|         |  | 2004                         |   |  | 2003                         |   |  | 2004  |   |  | 2003 |  
|Unit 1   |  | 90.3                         | % |  | 94.0                         | % |  | 92.8  | % |  | 52.4 | %
|Unit 2   |  | 94.2                         |   |  | 76.2                         |   |  | 100.7 |   |  | 61.4 |  
|Combined |  | 92.3                         |   |  | 85.1                         |   |  | 96.8  |   |  | 56.9 |  



During the first
quarter of 2004, the operational availability of our Louisa and Rock Springs combustion turbine facilities was 94.0% and 88.4%, respectively. Our combustion turbine facilities have relatively low fixed costs and greater operational flexibility, but
are more expensive to operate, and, as a result, we operate them only when the market price of energy makes their operation economical.



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##### Table of Contents

The components of our operating expenses for the three months ended March 31, 2004 and 2003, were as
follows:



|                                                  |  |                              |         |   |      |   |         |  
|------------------------------------------------- |  | ---------------------------- | ------- | - | ---- | - | ------- | -
|                                                  |  | Three Months Ended March 31, |        
|                                                  |  | 2004                         |         |   | 2003 |  
|                                                  |  | (in thousands)               |        
|Fuel                                              |  | $                            | 20,125  |   |      | $ | 13,269  |  
|Purchased power                                   |  |                              | 80,933  |   |      |   | 109,672 |  
|Deferred energy                                   |  |                              | (7,869  | ) |      |   | (16,261 | )
|Operations and maintenance                        |  |                              | 8,826   |   |      |   | 15,385  |  
|Administrative and general                        |  |                              | 7,612   |   |      |   | 5,181   |  
|Depreciation, amortization and decommissioning    |  |                              | 7,332   |   |      |   | 5,438   |  
|Amortization of regulatory asset/(liability), net |  |                              | 1,756   |   |      |   | (4,354  | )
|Taxes, other than income taxes                    |  |                              | 1,220   |   |      |   | 837     |  
|Accretion                                         |  |                              | 553     |   |      |   | 517     |  
|                                                  |  |                              |         |   |      |   |         |  
|Total operating expenses                          |  | $                            | 120,488 |   |      | $ | 129,684 |  
|                                                  |  |                              |         |   |      |   |         |  



Aggregate
operating expenses for the first quarter of 2004 decreased $9.2 million, or 7.1%, over the same period in 2003 because of a decrease in purchased power expense and operations and maintenance expense, partially offset by an increase in fuel expense,
and changes in deferred energy expense and the amortization of regulatory asset/(liability), net. Purchased power expense decreased $28.7 million, or 26.2%, as a result of an increase in the available capacity at North Anna in 2004 as compared to
2003 when the units were off-line for the replacement of the reactor vessel heads. Also in 2004, the Louisa and Rock Springs combustion turbine facilities were available for operation. These factors resulted in a decreased need for purchased power
to meet our power needs for the first quarter of 2004. In addition, the average cost of the power we purchased decreased 14.2% in the first quarter of 2004 as compared to the first quarter of 2003.



Operations and maintenance expense decreased in the first quarter of 2004 by
$6.6 million or 42.6%, as compared to the first quarter of 2003. The first quarter of 2003 includes costs incurred for the replacement of the reactor vessel heads at North Anna. There were no such costs in the first quarter of 2004.



Fuel expense increased $6.9 million, or 51.72%, due to the increase in the
average cost of coal per ton for Clover and the increased operation of Clover Unit 2 in 2004 as compared to 2003. Also, fuel expense increased in the first quarter of 2004 due to the operation of the Louisa and Rock Springs combustion turbine
facilities, which are fueled by natural gas and fuel oil. Louisa and Rock Springs did not begin commercial operations until June of 2003.



Deferred energy expense changed $8.4 million, or 51.6%, in the first quarter of 2004 as compared to the first quarter of 2003. During the first quarter of
2004, we under-collected $7.9 million in energy costs versus the first quarter of 2003 when we had under-collected $16.3 million in energy costs. At March 31, 2004, we had an over-collected deferred energy balance of $5.7 million.



Amortization of regulatory asset/(liability), net changed $6.1 million, or
140.3% primarily because in the first quarter of 2003 we recognized the $5.6 million revenue deferral that had been established in 2002. There was no such transaction in the first quarter of 2004.



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Other Items



Other Expense, net. The major components of our other expense, net for the three months ended March 31, 2004 and 2003, were as follows:



|                            |  |                             |     |   |      |   |     |  
|--------------------------- |  | --------------------------- | --- | - | ---- | - | --- | -
|                            |  | Three Months EndedMarch 31, |    
|                            |  | 2004                        |     |   | 2003 |  
|                            |  | (in thousands)              |    
|Gain on sale of investments |  | $                           |    |   |      | $ | 5   |  
|Donations and other         |  |                             | (12 | ) |      |   | (25 | )
|                            |  |                             |     |   |      |   |     |  
|Total Other Expense, net    |  | $                           | (12 | ) |      | $ | (20 | )
|                            |  |                             |     |   |      |   |     |  



Other expense, net
decreased in the first quarter of 2004 by approximately $8,000, or 40.0%, as compared to the first quarter of 2002 mainly due to a reduction of donations in 2004 as compared to 2003.



Investment Income.Investment income increased $0.4 million, or 286.9%, in the first quarter of 2004 as
compared to the same period in 2003 primarily due to an increase in the realized gains on the decommissioning fund as compared to the first quarter of 2003.



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



The major components of interest charges, net for the three months ended March 31, 2004 and 2003, were as follows:



|                                                      |  |                              |         |   |      |   |         |  
|----------------------------------------------------- |  | ---------------------------- | ------- | - | ---- | - | ------- | -
|                                                      |  | Three Months Ended March 31, |        
|                                                      |  | 2004                         |         |   | 2003 |  
|                                                      |  | (in thousands)               |        
|Interest expense on long-term debt                    |  | $                            | (13,936 | ) |      | $ | (12,886 | )
|Other                                                 |  |                              | (821    | ) |      |   | (693    | )
|                                                      |  |                              |         |   |      |   |         |  
|Total Interest Charges                                |  |                              | (14,757 | ) |      |   | (13,579 | )
|Allowance for borrowed funds used during construction |  |                              | 2,687   |   |      |   | 5,208   |  
|                                                      |  |                              |         |   |      |   |         |  
|Interest Charges, net                                 |  | $                            | (12,070 | ) |      | $ | (8,371  | )
|                                                      |  |                              |         |   |      |   |         |  



Interest charges, net
increased in 2004 by $3.7 million, or 44.2%, as compared to the same period in 2003 due to an increase in interest expense on long-term debt as a result of our $250.0 million debt issuance in July 2003, and a decrease in the amount of capitalized
interest relating to the development and construction of our three combustion turbine facilities. We began capitalizing interest on the Rock Springs and Louisa facilities in October 2001 and January 2002, respectively, and ceased capitalizing
interest in June 2003 when the facilities became commercially operable. We began capitalizing interest on the Marsh Run facility in April 2003. 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 interest charges, increased $0.2 million, or 8.7%, in the first quarter of 2004 as compared to the same period in 2003,
due to the $1.2 million increase in our total interest charges.



Financial
Condition



The principal changes in our financial
condition from December 31, 2003 to March 31, 2004, were caused by increases in accounts payablemembers, construction work in progress and accrued expenses and decreases in accounts payable and deferred energy. Accounts payablemembers
increased $24.7 million, or 51.6%, from December 31, 2003 to March 31, 2004, as a result of an increase in the amount of power bill prepayments that we received from our member distribution cooperatives and an increase in the amounts owed to our
member distribution cooperatives under our Margin Stabilization Plan. Construction work in progress increased $16.3 million, or 10.1%, from December 31, 2003 to March 31, 2004, due to the development and construction of our Marsh Run combustion
turbine facility. Accrued expenses increased $13.6 million, or 37.3%, from December 31, 2003 to March 31, 2004, primarily due to the increase in interest payable related to the timing of interest payments on long-term debt. Accounts payable
decreased $24.6 million, or 36.9%, from December 31, 2003 to March 31, 2004, due to timing differences on invoices associated with



13



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##### Table of Contents

purchased power, and operation and construction of our generating facilities. Our deferred energy balance represents the
net under- or over-collection of energy costs as of the end of the reporting period. These amounts are charged to or recovered from our member distribution cooperatives in subsequent periods. The deferred energy balance changed from a $13.6 million
liability (over-collection of costs) at December 31, 2003, to a $5.7 million liability (over-collection of costs) at March 31, 2004.



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
generating facilities, our debt service requirements, and our ordinary business operations. Operating activities were impacted primarily by changes in the first quarter in accrued interest and in our deferred energy account as a result of the timing
of interest payments on long-term debt and the change in our deferred energy account. Our operating activities provided excess cash flow of $25.0 million during the first quarter of 2004. Our cash needs exceeded our cash flows from operating
activities by $2.6 million during the first quarter of 2003.



Financing Activities.In addition to liquidity from our operating activities, we maintain committed lines of credit to cover short-term funding needs. As of March 31, 2004, we had short-term committed variable rate lines of
credit in an aggregate amount of $230.0 million. Of this amount, $110.0 million was available for general working capital purposes and $120.0 million was available for capital expenditures related to our generating facilities, including the
development and construction of our combustion turbine facilities. Our JPMorgan Chase Bank line of credit, which was to expire May 11, 2004, was renewed through May 10, 2005, and the use of proceeds was changed from construction of generating
facilities to working capital, which results in $180.0 million available for general working capital purposes and $50.0 million available for capital expenditures related to our generating facilities. Additionally, we have a $50.0 million three-year
revolving credit facility.



At March 31, 2004, and 2003, 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 lines of credit to be renewed until no longer
necessary for the development and construction of the combustion turbine facilities.



To fully participate in power-related markets, TEC must maintain credit support sufficient to meet delivery and payment obligations associated with power and natural gas trades. To assist TEC in providing this credit
support, we have agreed to guarantee up to $42.5 million of TECs delivery and payment obligations associated with its power and natural gas trades. At March 31, 2004, we had guaranteed $14.5 million of obligations of TEC. In April and May of
2004, we guaranteed an additional $6.75 million of obligatons of TEC for a total of $21.25 million.



Investing Activities.Investing activities in the first quarter of 2004 consisted primarily of expenditures for
our Marsh Run combustion turbine facility and the liquidation of investments to fund these expenditures.



Capped Rates



To
address stranded costs and to facilitate the implementation of retail competition, legislation in Virginia, Maryland and Delaware requires the incumbent utility to cap the bundled rates that it can charge customers in its certificated service
territory during a specified transition period. Capped rates extend until March 31, 2005, for our Delaware member distribution cooperative, and until June 30, 2005 for our Maryland member distribution cooperative. Legislation was recently passed
which extends capped rates in Virginia through December 31, 2010. The legislation allows the Virginia member distribution cooperatives to request one change in their capped rates prior to July 1, 2007, and one additional time between July 1, 2007
and December 31, 2010. The Virginia member distribution cooperatives will continue to have the opportunity to pass changes in energy costs through to their customers while under capped rates and additionally, the new legislation allows the Virginia
member distribution cooperatives to seek recovery of any and all costs associated with system reliability and environmental compliance through rate increases. See Competition and Changing Regulations in Part II, Item 7 of our Annual
Report on From 10-K for the fiscal year ended December 31, 2003.



Potential
Restructuring



We are exploring a possible restructuring
of our relationship with our member distribution cooperatives. See Potential Restructuring in Item 1 of our Annual Report on Form 10-K for the fiscal year ended December 31, 2003 for a description of the potential restructuring.
Currently, six of our member distribution cooperatives have adopted resolutions approving the restructuring. Our remaining member distribution cooperatives are still considering the potential restructuring but we currently anticipate that those
members, including Northern Virginia Electric Cooperative, will approve the transaction. We do not intend to pursue the restructuring unless all of our directors and the boards of directors of our member distributions cooperatives approve the
restructuring.



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Subsequent Event



On May 11, 2004, our Board of Directors approved an increase to the fuel factor adjustment rate, resulting in an increase to our total energy rate of
approximately 15.6%, effective April 1, 2004. This increase was implemented due to higher than anticipated energy costs for the first quarter of 2004 and projected higher than previously anticipated energy costs for the remainder of 2004. We
decreased the demand component of our formulary rate approximately 7.0%, effective April 1, 2004.



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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 first
quarter of 2004.



ITEM 4. CONTROLS AND PROCEDURES



Our management, including the President and Chief Executive Officer, and Senior Vice President Accounting and Finance, the 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 Accounting and Finance, the 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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OLD DOMINION ELECTRIC COOPERATIVE



PART II. OTHER INFORMATION



ITEM 1. LEGAL PROCEEDINGS



We have
a contract with Ragnar Benson, Inc. for engineering, procurement and construction services relating to the construction of our Marsh Run combustion turbine facility. Construction of the facility began in April 2003 and was scheduled for commercial
operation in the second quarter of 2004. The facility is currently scheduled to be commercially operable in the third quarter of 2004. Ragnar Benson, Inc. has asserted entitlement to additional time and compensation as a result of weather,
permitting and subsurface conditions. Ragnar Benson, Inc. continues to work towards completion of the facility in accordance with the contract.



We have reviewed the asserted claims of Ragnar Benson, Inc. and believe they are without merit. We currently are billing liquidated damages under the
contract for this delay. We do not expect any additional costs resulting from the delay, including those relating to the purchase of replacement power, to have a material impact on our financial position, results of operations or cash flow due to
our ability to collect such amounts through our rates to our member distribution cooperatives.



No material developments have occurred in our legal proceedings with PSE&G or Norfolk Southern since the filing of our Annual Report on Form 10-K for the fiscal year ended December 31, 2003. 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.



ITEM 5. OTHER INFORMATION



Construction of our Marsh Run facility began in April 2003 and we currently anticipate that the facility will be available for commercial operation in the third quarter of 2004.



ITEM 6. EXHIBITS AND REPORTS ON FORM 8-K



|     |  |                                                                                      |  |   
|---- |  | ------------------------------------------------------------------------------------ |  | --
|(a)  |  | Exhibits                                                                             |  |   
|     |  |                                                                                     
|31.1 |  | Certification of the Chief Executive Officer pursuant to Rule 13a-14(a)              |  | 19
|     |  |                                                                                     
|31.2 |  | Certification of the Principal Financial Officer pursuant to Rule 13a-14(a)          |  | 20
|     |  |                                                                                     
|32.1 |  | Certification of the Chief Executive Officer pursuant to 18 U.S.C. § 1350            |  | 21
|     |  |                                                                                     
|32.2 |  | Certification of the Principal Financial Officer pursuant to 18 U.S.C. § 1350        |  | 22
|     |  |                                                                                     
|(b)  |  | Reports on Form 8-K                                                                  |  |   
|     |  |                                                                                     
|     |  | The Registrant filed no reports on Form 8-K during the quarter ended March 31, 2004. |  |   



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SIGNATURE



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



|                   |  |                                                  
|------------------ |  | -------------------------------------------------
|                   |  | OLD DOMINION ELECTRIC COOPERATIVE                
|                   |  | Registrant                                       
|                   | 
|Date: May 17, 2004 |  | /s/ Daniel M. Walker                             
|                   |  | Daniel M. Walker                                 
|                   |  | Senior Vice President and Chief Financial Officer
|                   |  | (Principal Financial and Accounting Officer)     



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