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UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549



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FORM 10-Q



(Mark One)

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



For the quarterly period ended June 30, 2003



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



OLD DOMINION ELECTRIC COOPERATIVE

(Exact Name of Registrant as Specified in Its Charter)



|VIRGINIA (State or Other Jurisdiction of Incorporation or Organization) |  | 23-7048405 (I.R.S. Employer Identification No.)
|----------------------------------------------------------------------- |  | -----------------------------------------------



|4201 Dominion Boulevard, Glen Allen, Virginia (Address of Principal Executive Offices) |  | 23060 (Zip Code)
|-------------------------------------------------------------------------------------- |  | ----------------



(804) 747-0592

(Registrants Telephone Number, Including Area Code)



Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the
Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes x  No ̈



Indicate by check mark whether the registrant is an accelerated filer (as defined in the Exchange Act of 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  June 30, 2003 (Unaudited) and December 31, 2002                                                       |  | 3          
|          |  |                                                                                                                                              
|          |  | Condensed Consolidated Statements of Revenues, Expenses and Patronage Capital (Unaudited)  Three and Six Months Ended June 30, 2003 and 2002 |  | 4          
|          |  |                                                                                                                                              
|          |  | Condensed Consolidated Statements of Comprehensive Income (Unaudited)Three and Six Months Ended June 30, 2003 and 2002                       |  | 4          
|          |  |                                                                                                                                              
|          |  | Condensed Consolidated Statements of Cash Flows (Unaudited)  Six Months Ended June 30, 2003 and 2002                                         |  | 5          
|          |  |                                                                                                                                              
|          |  | Notes to Condensed Consolidated Financial Statements                                                                                          |  | 6          
|          |  |                                                                                                                                              
|Item 2.   |  | Managements Discussion and Analysis of Financial Condition and Results of Operations                                                         |  | 9          
|          |  |                                                                                                                                              
|Item 3.   |  | Quantitative and Qualitative Disclosures About Market Risk                                                                                    |  | 18         
|          |  |                                                                                                                                              
|Item 4.   |  | Controls and Procedures                                                                                                                       |  | 18         
|          |  |                                                                                                                                              
|PART II.  |  | Other Information                                                                                                                             |  |            
|          |  |                                                                                                                                              
|Item 1.   |  | Legal Proceedings                                                                                                                             |  | 19         
|          |  |                                                                                                                                              
|Item 6.   |  | Exhibits and Reports on Form 8-K                                                                                                              |  | 19         
|          | 
|Signature |  | 20                                                                                                                                           





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OLD DOMINION ELECTRIC COOPERATIVE

PART I. FINANCIAL INFORMATION



ITEM 1. FINANCIAL STATEMENTS

CONDENSED CONSOLIDATED BALANCE SHEETS



|                                              |  | June 30, 2003  |           |   | December 31, 2002* |  
|--------------------------------------------- |  | -------------- | --------- | - | ------------------ | -
|                                              |  | (in thousands) |          
|ASSETS:                                       |  | (unaudited)    |           |   |                    |  
|Electric Plant:                               |  |                |           |   |                    |  
|In service                                    |  | $              | 946,153   |   |                    | $
|Less accumulated depreciation                 |  |                | (380,948  | ) |                    |  
|                                              |  |                |           |   |                    |  
|                                              |  |                | 565,205   |   |                    |  
|Nuclear fuel, at amortized cost               |  |                | 2,041     |   |                    |  
|Construction work in progress                 |  |                | 447,165   |   |                    |  
|                                              |  |                |           |   |                    |  
|Net Electric Plant                            |  |                | 1,014,411 |   |                    |  
|                                              |  |                |           |   |                    |  
|Investments:                                  |  |                |           |   |                    |  
|Nuclear decommissioning trust                 |  |                | 62,822    |   |                    |  
|Lease deposits                                |  |                | 146,144   |   |                    |  
|Other                                         |  |                | 15,362    |   |                    |  
|                                              |  |                |           |   |                    |  
|Total Investments                             |  |                | 224,328   |   |                    |  
|                                              |  |                |           |   |                    |  
|Current Assets:                               |  |                |           |   |                    |  
|Cash and cash equivalents                     |  |                | 36,208    |   |                    |  
|Receivables                                   |  |                | 60,630    |   |                    |  
|Fuel, materials and supplies, at average cost |  |                | 14,073    |   |                    |  
|Prepayments                                   |  |                | 2,258     |   |                    |  
|Deferred energy                               |  |                | 6,549     |   |                    |  
|                                              |  |                |           |   |                    |  
|Total Current Assets                          |  |                | 119,718   |   |                    |  
|                                              |  |                |           |   |                    |  
|Deferred Charges:                             |  |                |           |   |                    |  
|Regulatory assets                             |  |                | 62,252    |   |                    |  
|Other                                         |  |                | 11,631    |   |                    |  
|                                              |  |                |           |   |                    |  
|Total Deferred Charges                        |  |                | 73,883    |   |                    |  
|                                              |  |                |           |   |                    |  
|Total Assets                                  |  | $              | 1,432,340 |   |                    | $
|                                              |  |                |           |   |                    |  
|CAPITALIZATION AND LIABILITIES:               |  |                |           |   |                    |  
|Capitalization:                               |  |                |           |   |                    |  
|Patronage capital                             |  | $              | 241,018   |   |                    | $
|Accumulated other comprehensive income (loss) |  |                |          |   |                    |  
|Long-term debt                                |  |                | 752,021   |   |                    |  
|                                              |  |                |           |   |                    |  
|Total Capitalization                          |  |                | 993,039   |   |                    |  
|                                              |  |                |           |   |                    |  
|Current Liabilities:                          |  |                |           |   |                    |  
|Long-term debt due within one year            |  |                | 11,913    |   |                    |  
|Accounts payable                              |  |                | 52,536    |   |                    |  
|Accounts payable  members                    |  |                | 58,039    |   |                    |  
|Accrued expenses                              |  |                | 44,233    |   |                    |  
|Deferred energy                               |  |                |          |   |                    |  
|Deferred revenue                              |  |                |          |   |                    |  
|                                              |  |                |           |   |                    |  
|Total Current Liabilities                     |  |                | 166,721   |   |                    |  
|                                              |  |                |           |   |                    |  
|Deferred Credits and Other Liabilities        |  |                |           |   |                    |  
|Asset retirement obligations                  |  |                | 42,712    |   |                    |  
|Decommissioning reserve                       |  |                |          |   |                    |  
|Obligations under long-term leases            |  |                | 149,120   |   |                    |  
|Regulatory liabilities                        |  |                | 29,353    |   |                    |  
|Other                                         |  |                | 51,395    |   |                    |  
|                                              |  |                |           |   |                    |  
|Total Deferred Credits and Other Liabilities  |  |                | 272,580   |   |                    |  
|                                              |  |                |           |   |                    |  
|Commitments and Contingencies                 |  |                |          |   |                    |  
|                                              |  |                |           |   |                    |  
|Total Capitalization and Liabilities          |  | $              | 1,432,340 |   |                    | $
|                                              |  |                |           |   |                    |  



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



|* |  | The Condensed Consolidated Balance Sheet at December 31, 2002, has been taken from the audited financial statements at that date, but does not include all disclosures required by
generally accepted accounting principles.
|- |  | ----------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------



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OLD DOMINION ELECTRIC COOPERATIVE



CONDENSED CONSOLIDATED STATEMENTS OF REVENUES,

EXPENSES AND PATRONAGE CAPITAL (UNAUDITED)



|                                                                      |  | Three Months Ended June 30, |         |   | Six Months Ended June 30, |  
|--------------------------------------------------------------------- |  | --------------------------- | ------- | - | ------------------------- | -
|                                                                      |  | 2003                        |         |   | 2002                      |  
|                                                                      |  | (in thousands)              |         |   | (in thousands)            |  
|Operating Revenues                                                    |  | $                           | 132,120 |   |                           | $
|                                                                      |  |                             |         |   |                           |  
|Operating Expenses:                                                   |  |                             |         |   |                           |  
|Fuel                                                                  |  |                             | 15,886  |   |                           |  
|Purchased power                                                       |  |                             | 73,573  |   |                           |  
|Deferred energy                                                       |  |                             | 6,673   |   |                           |  
|Operations and maintenance                                            |  |                             | 10,047  |   |                           |  
|Administrative and general                                            |  |                             | 6,686   |   |                           |  
|Depreciation, amortization and decommissioning                        |  |                             | 5,387   |   |                           |  
|Amortization of regulatory asset/(liability), net                     |  |                             | 1,777   |   |                           |  
|Taxes other than income taxes                                         |  |                             | 826     |   |                           |  
|Accretion                                                             |  |                             | 529     |   |                           |  
|                                                                      |  |                             |         |   |                           |  
|Total Operating Expenses                                              |  |                             | 121,384 |   |                           |  
|                                                                      |  |                             |         |   |                           |  
|Operating Margin                                                      |  |                             | 10,736  |   |                           |  
|Other (Expense)/Income, net                                           |  |                             | (234    | ) |                           |  
|Investment Income                                                     |  |                             | 1,340   |   |                           |  
|Interest Charges, net                                                 |  |                             | (9,074  | ) |                           |  
|                                                                      |  |                             |         |   |                           |  
|Net Margin Before Cumulative Effect of Change in Accounting Principle |  |                             | 2,768   |   |                           |  
|Cumulative Effect of Change in Accounting Principle                   |  |                             |        |   |                           |  
|                                                                      |  |                             |         |   |                           |  
|Net Margin After Cumulative Effect of Change in Accounting Principle  |  |                             | 2,768   |   |                           |  
|                                                                      |  |                             |         |   |                           |  
|Patronage CapitalBeginning of Period                                 |  |                             | 238,250 |   |                           |  
|                                                                      |  |                             |         |   |                           |  
|Patronage CapitalEnd of Period                                       |  | $                           | 241,018 |   |                           | $
|                                                                      |  |                             |         |   |                           |  



OLD DOMINION ELECTRIC COOPERATIVE



CONDENSED CONSOLIDATED STATEMENTS

OF COMPREHENSIVE INCOME (UNAUDITED)



|                                                               |  | Three Months Ended June 30, |       |      | Six Months Ended June 30, |        
|-------------------------------------------------------------- |  | --------------------------- | ----- | ---- | ------------------------- | -------
|                                                               |  | 2003                        |       | 2002 |                           |        
|                                                               |  | (in thousands)              |       |      | (in thousands)            |        
|Net Margin                                                     |  | $                           | 2,768 |      | $                         | 2,527  
|                                                               |  |                             |       |      |                           |        
|Other Comprehensive Income/(Loss):                             |  |                             |       |      |                           |        
|Unrealized gain/(loss) on investments                          |  |                             |       |      |                           | 32     
|Cumulative effect of accounting change on derivative contracts |  |                             |       |      |                           | (15,944
|Unrealized gain /(loss) on derivative contracts                |  |                             | 431   |      |                           | 959    
|                                                               |  |                             |       |      |                           |        
|Other comprehensive income/(loss)                              |  |                             | 431   |      |                           | (14,953
|                                                               |  |                             |       |      |                           |        
|Comprehensive Income/(Loss)                                    |  | $                           | 3,199 |      | $                         | (12,426
|                                                               |  |                             |       |      |                           |        



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



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OLD DOMINION ELECTRIC COOPERATIVE



CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS (UNAUDITED)



|                                                                                   |  | Six Months Ended June 30, |        
|---------------------------------------------------------------------------------- |  | ------------------------- | -------
|                                                                                   |  | 2003                      |        
|                                                                                   |  | (in thousands)            |        
|Operating Activities:                                                              |  |                           |        
|Net Margin                                                                         |  | $                         | 5,484  
|Adjustments to reconcile net margins to net cash provided by operating activities: |  |                           |        
|Cumulative effect of change in accounting principle                                |  |                           | 3,271  
|Depreciation, amortization and decommissioning                                     |  |                           | 10,825 
|Other non-cash charges                                                             |  |                           | 4,571  
|Amortization of lease obligations                                                  |  |                           | 4,748  
|Interest on lease deposits                                                         |  |                           | (4,530 
|Change in current assets                                                           |  |                           | (8,774 
|Change in deferred energy                                                          |  |                           | (9,588 
|Change in current liabilities                                                      |  |                           | (15,718
|Change in regulatory assets and liabilities                                        |  |                           | (13,488
|Deferred charges and credits                                                       |  |                           | 9,359  
|                                                                                   |  |                           |        
|Net Cash (Used for) Provided by Operating Activities                               |  |                           | (13,840
|                                                                                   |  |                           |        
|Financing Activities:                                                              |  |                           |        
|Obligations under long-term leases                                                 |  |                           | (109   
|                                                                                   |  |                           |        
|Net Cash Used for Financing Activities                                             |  |                           | (109   
|                                                                                   |  |                           |        
|Investing Activities:                                                              |  |                           |        
|Investments, net                                                                   |  |                           | 62,574 
|Electric plant additions                                                           |  |                           | (79,906
|Decommissioning fund deposits                                                      |  |                           | (340   
|                                                                                   |  |                           |        
|Net Cash Used for Investing Activities                                             |  |                           | (17,672
|                                                                                   |  |                           |        
|Net Change in Cash and Cash Equivalents                                            |  |                           | (31,621
|Cash and Cash Equivalents  Beginning of Period                                    |  |                           | 67,829 
|                                                                                   |  |                           |        
|Cash and Cash Equivalents  End of Period                                          |  | $                         | 36,208 
|                                                                                   |  |                           |        



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 June 30, 2003, and our consolidated results of operations, comprehensive income, and cash flows for the three and six months ended June 30, 2003 and 2002. The consolidated
results of operations for the three and six months ended June 30, 2003, 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 2002 Annual Report on Form 10-K filed with the Securities and Exchange Commission.
|-- |  | ----------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------



|2. |  | We adopted the Financial Accounting Standards Board 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 a
change in accounting principle.
|-- |  | ---------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------



SFAS No. 143
applies to the decommissioning of the North Anna Nuclear Power Station (North Anna), certain asset retirement obligations at the Clover Power Station (Clover), as well as certain asset retirement obligations at the Rock
Springs and Louisa combustion turbine facilities and our diesel 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 diesel 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.



In June 2003, our new Rock Springs and Louisa combustion turbine facilities
began commercial operations and as a result we recorded $2.6 million in asset retirement obligations.



The following represents changes in our Asset Retirement Obligations for the six months ended June 30, 2003:



|                                                         |  | Six Months Ended June 30, 2003 |        
|-------------------------------------------------------- |  | ------------------------------ | -------
|                                                         |  | (in thousands)                 |        
|Decommissioning reserve                                  |  | $                              | 56,684 
|Cumulative effect of change in accounting principle      |  |                                | (17,641
|                                                         |  |                                |        
|Asset retirement obligations at January 1, 2003          |  |                                | 39,043 
|Additional asset retirement obligations  new facilities |  |                                | 2,623  
|Accretion expense                                        |  |                                | 1,046  
|                                                         |  |                                |        
|Asset retirement obligations at June 30, 2003            |  | $                              | 42,712 
|                                                         |  |                                |        



Net margin for the
three and six months ended June 30, 2002, or the twelve months ended December 31, 2002, would not have differed if this statement had been adopted as of January 1, 2002.



|3. |  | In December 1992, we entered into an agreement with Public Service Electric & Gas Company (PSE&G) to purchase 150 megawatts (MW) of
capacity, consisting of 75 MW of intermediate or peaking capacity and 75 MW of base load capacity, as well as reserves and associated energy, through 2004. The agreement with PSE&G contains fixed capacity charges, including transmission charges,
for the base, intermediate, and peaking capacity to be provided under the
|-- |  | -----------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------



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| | agreement. However, either party can apply to the Federal Energy Regulatory Commission (FERC) in some circumstances to recover changes in
specified costs of providing services. If a change in rate occurs, the party adversely affected may terminate the agreement on one years notice. We may purchase the energy associated with the PSE&G capacity from PSE&G or other power
suppliers. If purchased from PSE&G, the energy cost is based on PSE&Gs incremental cost above its own power supply requirements.
| | -----------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------



In October 1997, we filed with FERC a complaint against PSE&G asserting that our agreement with PSE&G should be modified to conform to the
restructuring of PJM Interconnection LLC (PJM). Under the PJM structure, we pay for the transmission of PSE&G power through the zonal rate we currently pay Conectiv Energy. On May 14, 1998, FERC ruled in our favor as part of its
ruling on several cases relating to the restructuring of PJM, ordering PSE&G to remove all transmission costs from its rates for capacity and associated energy sold to us, effective April 1, 1998. PSE&G complied with the FERC order by virtue
of a compliance filing submitted to FERC on June 15, 1998. On November 30, 2000, PSE&G filed with the United States Court of Appeals for the District of Columbia Circuit a petition for review of FERCs orders in this matter. On July 12,
2002, the Court of Appeals vacated FERCs May 14, 1998 ruling and remanded all of these cases relating to the restructuring of PJM to FERC for further consideration.



On December 19, 2002, FERC issued an order on remand reversing its May 14, 1998 generic PJM restructuring ruling. FERC noted
that there was no evidence on record in the generic restructuring proceeding to demonstrate what, if any, unduly discriminatory effects could be attributable to our particular contract, but went on to state that we are free to present evidence based
on the specifics of our contract with PSE&G under Section 206 of the Federal Power Act. On January 24, 2003, we filed an amended and renewed complaint against PSE&G with FERC, requesting that FERC reopen the proceeding regarding the matters
raised by our October 1997 complaint. That initial complaint was dismissed by FERC in August 1998, based on FERCs generic PJM restructuring ruling that ruled in our favor. Our January 24, 2003, complaint renewal and amendment urges FERC to
find that rate pancaking (incurring charges from multiple transmission owners due to transmission across several systems) to us under our agreement with PSE&G is unlawful and eliminate this rate pancaking treatment effective April 1, 1998,
forward. We also requested that FERC stay any payment obligation by us to PSE&G for surcharge amounts of pancaked rates from April 1, 1998 through December 31, 2002. We received an invoice from PSE&G on January 22, 2003, for this surcharge
amount of $26.2 million, plus $4.7 million in accumulated interest.



On February 10, 2003, we informed PSE&G in writing that a payment obligation for any past amount under the 1992 agreements surcharge authority remains unauthorized and premature, until so ordered by FERC. On January 14, 2003, our
board of directors approved the collection from our member distribution cooperatives of approximately $32.9 million including interest and related margin requirement beginning February 1, 2003, over 48 months, to recover these amounts. We are paying
the amount of pancaked rates on a prospective basis, subject to protest and FERC action on our renewed and amended complaint.



|4. |  | On May 9, 2001, we entered into a master power purchase and sales agreement with Enron Power Marketing, Inc. (EPMI). Pursuant to transactions we entered into under this
agreement, EPMI was obligated to deliver power to us through December 31, 2003. Following its filing for bankruptcy protection on December 2, 2001, EPMI ceased scheduling deliveries of power under the agreement beginning December 15, 2001. We then
terminated the agreement. EPMI claims that a termination payment is due from us pursuant to the terms of the contract; however, we have disputed that obligation due to EPMIs fraudulent conduct. On December 11, 2002, EPMI filed an adversary
proceeding against us in the United States Bankruptcy Court for the Southern District of New York seeking to collect a $10.4 million termination payment. We moved to dismiss that action and to compel arbitration. On March 4, 2003, the Bankruptcy
Court ordered the parties to take the dispute to nonbinding mediation. The adversary action is stayed pending the mediation. The parties have met before the mediator and have made progress towards a settlement. Based on the progress made towards a
settlement, we have accrued an anticipated amount, which we do not expect 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 Trading), 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 Trading must maintain credit support sufficient to meet delivery and payment obligations
associated with power and natural gas trades. To assist TEC Trading in providing this credit support, we have agreed to guarantee up to $42.5 million of TEC Tradings delivery and payment obligations associated with its power and natural gas
trades. At June 30, 2003, we had guaranteed $5.5 million of obligations of TEC Trading and we guaranteed an additional $4.5 million in July 2003 for a total of $10.0 million. During the three and six
|-- |  | -------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------



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months ended June 30, 2003, we had sales to TEC Trading of $8.0 million and $14.0 million, respectively. During the three and six months ended June 30, 2003,
we had charged administrative services fees to TEC Trading of $3,000 and $6,000, respectively.



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



This new
interpretation will be effective for us beginning in the third quarter of 2003. We are continuing to evaluate the impact of applying this new statement, but do not currently anticipate that the Interpretation will have any material effect on our
financial position, results of operations or cash flows.



|7. |  | In May 2003, the Financial Accounting Standards Board issued SFAS No. 150, Accounting for Certain Financial Instruments with Characteristics of both Liabilities and
Equity. SFAS No. 150 establishes standards for how an issuer classifies and measures certain financial instruments with characteristics of both liabilities and equity. SFAS No. 150 requires that an issuer classify a financial instrument that
is within the scope of SFAS No. 150 as a liability (or an asset in some circumstances), which previously may have been classified as equity.
|-- |  | ---------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------



We do not believe that this statement will have a material effect on the classification of Patronage Capital in our Consolidated Balance Sheet because any
distributions of Patronage Capital are subject to the discretion of our board of directors and the restrictions contained in the Indenture of Mortgage and Deed of Trust, dated as of May 1, 1992, between Old Dominion and Crestar Bank (predecessor to
Sun Trust Bank), as trustee, as supplemented and amended.



|8. |  | Subsequent eventIn July 2003, we issued $250.0 million of 2003 Series A Bonds under our Indenture. The bonds bear interest at 5.676% and mature in 2028. The majority of the
proceeds will be used to fund construction costs associated with our combustion turbine facilities. Additionally, a portion of the funds may be used to redeem some of our outstanding indebtedness in the future.
|-- |  | ------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------



|9. |  | Certain reclassifications have been made to the prior years condensed consolidated financial statements to conform to the current years presentation.
|-- |  | -------------------------------------------------------------------------------------------------------------------------------------------------------



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OLD DOMINION ELECTRIC COOPERATIVE



ITEM 2. MANAGEMENTS DISCUSSION AND ANALYSIS

OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS



Caution Regarding Forward-Looking Statements



Managements Discussion and Analysis of Financial Condition and
Results of Operations contains forward-looking statements regarding matters that could have an impact on our business, financial condition, and future operations. These statements, based on our expectations, assumptions, and estimates, are not
guarantees of future performance or the occurrence of any event 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, interest rates, future costs, 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 June 30, 2003, other than the adoption of Statement of Financial
Accounting Standards (SFAS) No. 143,Accounting for Asset Retirement Obligations, there have been no significant changes with regard to our critical accounting policies as disclosed in our Annual Report on Form 10-K for the fiscal
year ended December 31, 2002. The policies disclosed included the accounting for rate regulation and our margin stabilization plan.



On January 1, 2003, we adopted SFAS No. 143, which provides accounting requirements for the recognition and measurement of liabilities associated with the
retirement of tangible long-lived assets. At June 30, 2003, our asset retirement obligations totaled $42.7 million, the majority of which relates to the decommissioning of our undivided ownership interest in the North Anna Nuclear Power Station
(North Anna) and asset retirement obligations relating to the Clover Power Station (Clover), the Rock Springs and Louisa combustion turbine facilities and our diesel facilities.



Asset retirement obligations are recognized at fair value as incurred and
capitalized as part of the cost of the related tangible long-lived assets. In the absence of quoted market prices, we base our estimates of the fair value of asset retirement obligations using present value techniques, involving discounted cash flow
analysis. Measurement using these techniques is dependent upon many subjective factors, including the selection of discount and cost escalation rates, identification of planned retirement activities and related cost estimates and assertions of
probability regarding the timing, nature and costs of these activities. We base inputs and assumptions on the best information available to us at the time the estimates are made. However, estimates of future cash flows relating to these asset
retirement obligations are highly uncertain by nature and may vary significantly from actual results.



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Results of Operations



Operating Revenues



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 Trading). Our operating revenues by type of purchaser for the three and six months ended June 30, 2003 and 2002, were as follows:



|                                 |  | Three Months Ended June 30, |         | Six Months Ended June 30,
|-------------------------------- |  | --------------------------- | ------- | -------------------------
|                                 |  | 2003                        |         | 2002                     
|                                 |  | (in thousands)              |         | (in thousands)           
|Member revenues:                 |  |                             |         |                          
|Member distribution cooperatives |  | $                           | 118,797 |                          
|TEC Trading                      |  |                             | 8,048   |                          
|                                 |  |                             |         |                          
|Total member revenues            |  |                             | 126,845 |                          
|Non-member revenues              |  |                             | 5,275   |                          
|                                 |  |                             |         |                          
|Total revenues                   |  | $                           | 132,120 |                          
|                                 |  |                             |         |                          



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



|                                                            |  | Three Months Ended June 30, |           | Six Months Ended June 30,
|----------------------------------------------------------- |  | --------------------------- | --------- | -------------------------
|                                                            |  | 2003                        |           | 2002                     
|                                                            |  | (in MWh)                    |           | (in MWh)                 
|Members energy sales:                                       |  |                             |           |                          
|Member distribution cooperatives                            |  |                             | 2,018,888 |                          
|TEC Trading                                                 |  |                             | 178,391   |                          
|                                                            |  |                             |           |                          
|Total energy sales for members                              |  |                             | 2,197,279 |                          
|Non-member energy sales                                     |  |                             | 136,021   |                          
|                                                            |  |                             |           |                          
|Total energy sales                                          |  |                             | 2,333,300 |                          
|                                                            |  |                             |           |                          
|Average costs to member distribution cooperatives (per MWh) |  | $                           | 58.84     |                          



Revenues from sales to
our member distribution cooperatives are a function of our formulary rate for sales of power to our member distribution cooperatives and our member distribution cooperatives consumers requirements for power. Our formulary rate is based
on our cost of service in meeting these requirements and consists of a demand rate, a base energy rate and a fuel factor adjustment rate. Our formulary rate also allows us to recover and refund amounts under our Margin Stabilization Plan. We adjust
revenues and our members accounts payable or accounts receivable each quarter to reflect these amounts. See Factors Affecting ResultsMargin Stabilization Plan in Part II, Item 7 of our Annual Report on Form 10-K for the fiscal year
ended December 31, 2002, for a discussion of the Margin Stabilization Plan. Revenue from sales to TEC Trading is made pursuant to our power sales contract with it.



Our power sales are comprised of two power products  energy and capacity (also referred to as demand). Energy is the
physical electricity delivered through transmission and distribution facilities to customers. We bill energy to each of our member and non-member customers based on the total MWh delivered to them each month and, with respect to our member
distribution cooperatives, charge them an amount based on the base energy rate and fuel factor adjustment rate. Because energy cannot be stored, 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 is referred to as capacity. We use our generating facilities and rely on power purchase contracts to satisfy substantially all of
our member



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distribution cooperatives capacity requirements. We bill capacity to each of our member distribution cooperatives monthly through our demand rate which
is based on our budgeted capacity costs. The quantity billed to each member distribution cooperative is based on its requirement for energy during the hour of the month when the need for energy among all of the consumers in mainland Virginia or the
Delmarva Peninsula, as applicable, is highest, measured in megawatts (MW).



Sales to Member Distribution Cooperatives



Our revenues from sales to our member distribution cooperatives by formulary rate component for the three and six months ended June 30, 2003 and 2002, were as follows:



|                                                              |  | Three Months Ended June 30, |         | Six Months Ended June 30,
|------------------------------------------------------------- |  | --------------------------- | ------- | -------------------------
|                                                              |  | 2003                        |         | 2002                     
|                                                              |  | (in thousands)              |         | (in thousands)           
|Base energy revenues                                          |  | $                           | 36,780  |                          
|Fuel factor adjustment revenues                               |  |                             | 25,098  |                          
|                                                              |  |                             |         |                          
|Total energy revenues                                         |  |                             | 61,878  |                          
|Demand (capacity) revenues                                    |  |                             | 56,919  |                          
|                                                              |  |                             |         |                          
|Total revenues from sales to member distribution cooperatives |  | $                           | 118,797 |                          
|                                                              |  |                             |         |                          



Three factors
significantly affect our member distribution cooperatives consumers requirements for power:



| |  |  | growth in the number of consumers,
| | - |  | ----------------------------------



| |  |  | growth in consumers requirements for power, and
| | - |  | ------------------------------------------------



| |  |  | weather fluctuations.
| | - |  | ---------------------



Weather affects the demand for electricity. Relatively higher or lower temperatures tend to increase the demand for energy to use air conditioning or
heating systems, respectively. Mild weather generally reduces the demand for energy because air conditioning and heating systems are operated less. Other factors affecting our member distribution cooperatives consumers demand for energy
include the amount, size, and usage of electronics and machinery, and the expansion of operations among their commercial and industrial customers.



Total revenues from our member distribution cooperatives for the three months ended June 30, 2003, increased $6.9 million, or 6.1%, over the same period
in 2002 as a result of increases in capacity and energy costs for the period. These increases in costs, combined with lower sales volumes, caused our average capacity and energy costs for the quarter to be approximately 27.0% and 10.4% higher than
for the same period in 2002, respectively.



Effective February
1, 2003, we increased the demand component of our formulary rate (which collects our capacity-related costs) approximately 5.0% to collect from our member distribution cooperatives transmission charges associated with our power purchase agreement
with Public Service Electric & Gas Company (PSE&G). We anticipate that the increase in the demand component of our formulary rate will recover over 48 months $32.9 million related to a surcharge billed to us by PSE&G, and
associated interest expense and margin requirement. Additionally, we anticipate that the revised demand component of our formulary rate will recover the amount of transmission costs that we are paying to PSE&G now until the termination of the
contract in December 2004. We are making these payments under protest and subject to FERC action on this issue. See Legal Proceedings in Part II, Item 1. This increase in the demand rate did not adequately recover all our demand costs
during the quarter, however, and our revenues from our member distribution cooperatives for the three months ended June 30, 2003, reflect a $7.6 million margin stabilization adjustment. See Factors Affecting ResultsMargin Stabilization
Plan in Part II, Item 7 of our Annual Report on Form 10-K for the fiscal year ended December 31, 2002.



Effective March 31, 2003, we increased our fuel factor adjustment rate, which resulted in an increase to our total energy rate (including our base energy
rate and our fuel factor adjustment rate) of approximately 21.8%. The increase in the fuel factor adjustment rate was necessary to recover higher than expected actual energy costs that we incurred in the first two months of 2003 and energy costs for
the remainder of the year that we anticipate will be higher than the energy costs we originally budgeted for 2003. The previous change to our fuel factor adjustment rate was effective October 1, 2002, when we reduced our



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total energy rate approximately 9.5% because we had over-collected our energy costs incurred to date and anticipated that the lower rate would adequately
recover our energy costs in the future. See Operating Expenses below for a discussion of factors impacting both capacity and energy costs.



In the second quarter of 2003, capacity sales, measured in MW, decreased 10.7% and energy sales, measured in MWh, decreased 9.2% over those realized in
the second quarter of 2002. Sales volumes decreased primarily as a result of milder weather conditions experienced by consumers of our member distribution cooperatives, which reduced the operating of home cooling systems.



Total revenues from our member distribution cooperatives for the six months
ended June 30, 2003, increased $11.2 million, or 4.6%, over the same period in 2002 primarily as a result of a 13.8% increase in the average capacity costs for the period. Our revenues from our member distribution cooperatives for the six months
ended June 30, 2003, and receivables at June 30, 2003, reflect a $6.0 million margin stabilization adjustment. See Factors Affecting ResultsMargin Stabilization Plan in Part II, Item 7 of our Annual Report on Form 10-K for the
fiscal year ended December 31, 2002. The increase in the average capacity costs was partially offset by a 5.7% decrease in the average energy costs between the two periods, reflecting the lower total energy rate that was in place during the first
quarter of 2003 as compared to the first quarter of 2002. For the six months ended June 30, 2003, energy sales increased 2.9% and there was no material change in the volume of capacity sales. Colder than normal weather experienced during the first
quarter of 2003 yielded an increase in sales volumes as compared with the first quarter of 2002, however, milder weather during the second quarter of 2003 tempered these increases.



Sales to TEC Trading.Our sales to TEC Trading are primarily sales of energy that we do not need to meet the
actual needs of our member distribution cooperatives. (We refer to this energy as excess energy). These sales increased $7.6 million and $13.6 million for the three and six months ended June 30, 2003, respectively. During the first five months 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 Trading for resale into the market or to
non-members. No sales were made to TEC Trading during the first quarter of 2002.



Sales to Non-Members.Sales to non-members consist of sales of excess purchased energy and sales of excess generated energy from Clover. We sell excess purchased energy to PJM Interconnection, LLC
(PJM) under its rates for providing energy imbalance services or to TEC Trading. We sell excess energy from Clover to Virginia Power pursuant to the requirements of the Clover Operating Agreement. Non-member revenues for the three and
six months ended June 30, 2003, were higher than in 2002 by $4.2 million and $5.5 million, respectively, primarily because of sales to PJM of excess energy purchased under the option contract discussed in TEC Trading above.



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 North Anna, our Rock Springs and Louisa
combustion turbine facilities, and ten diesel generators, and (ii) power purchases from third parties through power purchase contracts and forward, short-term and spot market energy purchases. Rock Springs two units began commercial operations
in June 2003 and Louisas five units began commercial operations in June and July of 2003. Our energy supply for the three and six months ended June 30, 2003 and 2002, was as follows:



|             |  | Three Months Ended June 30, |  |      | Six Months Ended June 30, | 
|------------ |  | --------------------------- |  | ---- | ------------------------- | 
|             |  | 2003                        |  |      | 2002                      | 
|             |  | (in MWh or percentages)     |  |      | (in MWh or percentages)   | 
|Generated:   |  |                             |  |      |                           | 
|Clover       |  | 608,470                     |  | 25.3 | %                         | 
|North Anna   |  | 389,370                     |  | 16.2 |                           | 
|Louisa       |  | 28,721                      |  | 1.2  |                           | 
|Rock Springs |  | 15,841                      |  | 0.7  |                           | 
|Diesels      |  | 40                          |  |     |                           | 
|             |  |                             |  |      |                           | 



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|Total Generated         |  | 1,042,442 |  | 43.4  |   |  | 1,084,623 |  | 47.2  |   |  | 2,107,560 |  | 38.6  |   |  | 2,245,752 |  | 46.9  |  
|----------------------- |  | --------- |  | ----- | - |  | --------- |  | ----- | - |  | --------- |  | ----- | - |  | --------- |  | ----- | -
|                        |  |           |  |       |   |  |           |  |       |   |  |           |  |       |   |  |           |  |       |  
|Purchased:              |  |           |  |       |   |  |           |  |       |   |  |           |  |       |   |  |           |  |       |  
|Mainland Virginia area  |  | 598,461   |  | 24.9  |   |  | 732,025   |  | 31.8  |   |  | 1,740,393 |  | 32.6  |   |  | 1,536,380 |  | 32.1  |  
|Delmarva Peninsula area |  | 760,109   |  | 31.7  |   |  | 483,280   |  | 21.0  |   |  | 1,519,523 |  | 28.8  |   |  | 1,008,616 |  | 21.0  |  
|                        |  |           |  |       |   |  |           |  |       |   |  |           |  |       |   |  |           |  |       |  
|Total Purchased         |  | 1,358,570 |  | 56.6  |   |  | 1,215,305 |  | 52.8  |   |  | 3,259,916 |  | 61.4  |   |  | 2,544,996 |  | 53.1  |  
|                        |  |           |  |       |   |  |           |  |       |   |  |           |  |       |   |  |           |  |       |  
|Total Available Energy  |  | 2,401,012 |  | 100.0 | % |  | 2,299,928 |  | 100.0 | % |  | 5,367,476 |  | 100.0 | % |  | 4,790,748 |  | 100.0 | %
|                        |  |           |  |       |   |  |           |  |       |   |  |           |  |       |   |  |           |  |       |  



Market forces
influence the structure of new power supply contracts into which we enter. 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. 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.



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 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 North Anna or Clover is off-line, we must purchase replacement energy from either Virginia
Power, which is more costly, or 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 North Anna and
Clover but not Rock Springs or Louisa. Our combustion turbine facilities have relatively low fixed costs and greater operational flexibility, but are more expensive to operate and, as a result, we will operate them only when the market price of
energy makes their operation economical. The output of North Anna and Clover for the three and six months ended June 30, 2003, and 2002, as a percentage of the maximum dependable capacity rating of the facilities was as follows:



|         |  | North Anna                |   |  | Clover                  |  
|-------- |  | ------------------------- | - |  | ----------------------- | -
|         |  | Three MonthsEndedJune 30, |   |  | Six MonthsEndedJune 30, |  
|         |  | 2003                      |   |  | 2002                    |  
|Unit 1   |  | 67.3                      | % |  | 101.0                   | %
|Unit 2   |  | 99.3                      |   |  | 100.2                   |  
|Combined |  | 83.3                      |   |  | 100.6                   |  



North Anna.North Anna Unit 1 began an outage for a scheduled refueling and to replace the reactor vessel head of the unit on February 23, 2003. The unit was returned to service on April 18, 2003. During the second quarter of 2003, North Anna Unit 1
experienced a non-nuclear unscheduled ten-day outage. North Anna Unit 2 began a scheduled refueling outage on September 8, 2002. After the outage began, the reactor vessel head was replaced and the unit and was returned to service on February 2,
2003. See also Part II, Item 7 of our Annual Report on Form 10-K for the fiscal year ended December 31, 2002, for a discussion of the replacement of the reactor vessel heads at North Anna. There were no maintenance outages at either of the North
Anna units during the second quarter or first six months of 2002.



Clover.Clover Unit 1 began a scheduled maintenance outage on April 11, 2003, and was returned to service on May 1, 2003. During the second quarter of 2002, Unit 1 was removed from service for a scheduled maintenance
outage on March 1, 2002, and was returned to service on April 20, 2002. Clover Unit 2 was removed from service on March 14, 2003, for a scheduled maintenance outage and was returned to service on April 19, 2003. Unit 2 was removed from service on
April 20, 2002, for a scheduled maintenance outage and was returned to service on May 3, 2002. Both Unit 1 and Unit 2 also experienced minor unscheduled outages during the second quarter of 2003 and 2002.



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The components of our operating expenses for the three and six months ended June 30, 2003 and 2002, were
as follows:



|                                                  |  | Three Months Ended June 30, |         |      | Six Months Ended June 30, |        
|------------------------------------------------- |  | --------------------------- | ------- | ---- | ------------------------- | -------
|                                                  |  | 2003                        |         | 2002 |                           |        
|                                                  |  | (in thousands)              |         |      | (in thousands)            |        
|Fuel                                              |  | $                           | 15,886  |      | $                         | 12,269 
|Purchased power                                   |  |                             | 73,573  |      |                           | 62,147 
|Deferred energy                                   |  |                             | 6,673   |      |                           | 10,933 
|Operations and maintenance                        |  |                             | 10,047  |      |                           | 8,200  
|Administrative and general                        |  |                             | 6,686   |      |                           | 6,065  
|Depreciation, amortization and decommissioning    |  |                             | 5,387   |      |                           | 5,860  
|Amortization of regulatory asset/(liability), net |  |                             | 1,777   |      |                           | (4,731 
|Taxes, other than income taxes                    |  |                             | 826     |      |                           | 842    
|Accretion                                         |  |                             | 529     |      |                           |       
|                                                  |  |                             |         |      |                           |        
|Total Operating Expenses                          |  | $                           | 121,384 |      | $                         | 101,585
|                                                  |  |                             |         |      |                           |        



Aggregate
operating expenses for the three months ended 2003 increased $19.8 million, or 19.5%, over the same period in 2002 primarily because of an increase in purchased power expense and a change in the amortization of regulatory asset/(liability), net
partially offset by a decrease in deferred energy expense. Purchased power expense increased $11.4 million, or 18.4%, because we exercised a contractual option to purchase energy at then favorable market prices for the use of our member distribution
cooperatives, and sold the energy that was not utilized by them to TEC Trading or non-members. Additionally, the average cost of the power we purchased increased 5.9% in the second quarter of 2003 as compared to the second quarter of 2002 primarily
as a result of increases in the price of natural gas, which is a significant component in the market price of energy. Purchased power expense for the second quarter of 2003 included $1.4 million associated with the current portion of disputed
charges under the PSE&G contract. There were no amounts included in the second quarter of 2002 for disputed charges under the PSE&G contract.



The expense incurred through amortization of regulatory asset/(liability), net increased $6.5 million, or 137.6%, for the second quarter of 2003 as
compared with the second quarter of 2002. During the second quarter of 2003, we recorded expense of $1.8 million relating primarily to the amortization of the regulatory asset associated with the PSE&G contract. During the second quarter of
2002, we reversed $4.7 million of deferred revenue recorded (collected) in 2001, creating an offset to operating expense.



Deferred energy expense decreased $4.3 million, or 39.0%, for the second quarter of 2003 as compared with the second quarter of 2002. During the second
quarter of 2003, we collected $6.7 million in energy costs in excess of the energy costs incurred during the quarter. During the second quarter of 2002, we collected $10.9 million in energy costs in excess of the energy costs incurred during the
quarter.



Aggregate operating expenses for the six months ended
June 30, 2003, increased $27.9 million, or 12.5%, over the same period in 2002 primarily because of an increase in purchased power expense and operations and maintenance expense, partially offset by a decrease in deferred energy expense. Purchased
power expense increased $56.5 million, or 44.6%. During the first quarter of 2003 we purchased additional energy from the market to supply our member distribution cooperatives requirements during unusually cold winter weather and to replace
energy normally provided by, but not available from, North Anna due to the replacement of the reactor vessel heads. Additionally, we exercised a contractual option to purchase energy at then favorable market prices for the use of our member
distribution cooperatives, and sold the energy that was not utilized by them to TEC Trading or non-members. The average cost of the power we purchased increased 12.9% for the first six months of 2003 as compared to the same period of 2002 primarily
as a result of increases in the price of natural gas, which is a significant component in the market price of energy. Purchased power expense for the first six months of 2003 included $2.3 million associated with the current portion of disputed
charges under the PSE&G contract. There were no amounts included in the first six months of 2002 for disputed charges under the PSE&G contract



Operations and maintenance expense increased $8.5 million, or 50.5%, for the first six months of 2003 as compared to the same period in 2002, due
primarily to costs incurred for the replacement of the reactor vessel heads at North Anna. The increased operations and maintenance expense was partially offset by the amortization of a regulatory liability as the result of the collection of
additional amounts from our member distribution cooperatives in 2002 to help mitigate these costs in 2003.



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Deferred energy expense decreased $42.9 million, or 128.8%, for the first six months of 2003 as compared
with the same period of 2002. For the first six months of 2003, our incurred energy cost exceeded the amount we collected through our total energy rate by $9.6 million. At June 30, 2003, we had an under-collected deferred energy balance of $6.5
million (as compared with a $13.2 million under-collection as of March 31, 2003), which we anticipate will be fully collected through rates by the end of 2003. During the first six months of 2002, we collected $33.3 million in energy costs in excess
of the energy costs incurred during that period.



Other
Items



Other (Expense)/Income, net. The
major components of our other (expense)/income, net for the three and six months ended June 30, 2003 and 2002, were as follows:



|                                  |  | Three Months Ended June 30, |      |   |      |   | Six Months Ended June 30, |  
|--------------------------------- |  | --------------------------- | ---- | - | ---- | - | ------------------------- | -
|                                  |  | 2003                        |      |   | 2002 |   |                           |  
|                                  |  | (in thousands)              |      |   |      |   | (in thousands)            |  
|Gain on sale of investments       |  | $                           | (5   | ) |      | $ |                          |  
|Reimbursement of prior costs      |  |                             |     |   |      |   | 16                        |  
|Donations and other               |  |                             | (229 | ) |      |   | (89                       | )
|                                  |  |                             |      |   |      |   |                           |  
|Total Other (Expense)/Income, net |  | $                           | (234 | ) |      | $ | (73                       | )
|                                  |  |                             |      |   |      |   |                           |  



Other
(expense)/income, net increased in the second quarter of 2003 by $0.2 million, or 220.5%, as compared to the same period in 2002 due to our donation of transmission assets to one of our member distribution cooperatives.



Other (expense)/income, net increased in the first six months of 2003 by $1.0
million, or 134.7% as compared to the same period in 2002 due to this donation of transmission assets offset by the reimbursement by the other participant in the Rock Springs facility in 2002 of previously incurred development costs.



Investment Income.Investment income increased in the second
quarter of 2003 by $0.8 million, or 142.8% as compared to the same period in 2002 mainly due to the inclusion of investment income from our nuclear decommissioning trust as the result of a change in accounting related to the adoption of SFAS No.
143. This income was partially offset by a reduction of investment income from investments-other, and cash and cash equivalents used to fund the development and construction of our three combustion turbine facilities.



Investment income decreased in the first six months of 2003 by $0.5 million,
or 26.0% as compared to the same period in 2002 primarily because of a reduction of investment income from investments-other, and cash and cash equivalents used to fund the development and construction of our three combustion turbine facilities
partially offset by investment income from our nuclear decommissioning trust.



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



The
major components of interest charges, net for the three and six months ended June 30, 2003 and 2002, were as follows:



|                                                      |  | Three Months Ended June 30, |         |   | Six Months Ended June 30, |  
|----------------------------------------------------- |  | --------------------------- | ------- | - | ------------------------- | -
|                                                      |  | 2003                        |         |   | 2002                      |  
|                                                      |  | (in thousands)              |         |   | (in thousands)            |  
|Interest expense on long-term debt                    |  | $                           | (12,970 | ) |                           | $
|Other                                                 |  |                             | (872    | ) |                           |  
|                                                      |  |                             |         |   |                           |  
|Total Interest Charges                                |  |                             | (13,842 | ) |                           |  
|Allowance for borrowed funds used during construction |  |                             | 4,768   |   |                           |  
|                                                      |  |                             |         |   |                           |  
|Interest Charges, net                                 |  | $                           | (9,074  | ) |                           | $
|                                                      |  |                             |         |   |                           |  



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Interest charges, net decreased in the second quarter and first six months 2003 by $0.7 million, or 7.3%,
and $2.8 million, or 13.7%, respectively, as compared to the same periods in 2002 due primarily to an increase 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. We ceased capitalizing interest for our Rock Springs and Louisa facilities when the facilities began commercial operations. Capitalized
interest is computed monthly using an interest rate, which reflects our embedded cost of indebtedness, multiplied by our investment in projects under construction. Other interest increased due to an amount in dispute with PSE&G. See Legal
Proceedings in Part II, Item 1.



Net
Margin.Our net margin, which is a function of our interest charges, increased $0.2 million, or 9.5%, and $0.4 million, or 8.7%, in the second quarter and first six months of 2003, respectively, as compared to the same periods
in 2002, due to the $1.2 million and $2.2 million increase in our total interest charges for the second quarter and first six months of 2003, respectively.



Financial Condition



The principal changes in our financial condition from December 31, 2002 to June 30, 2003, were caused by increases in construction work in progress
and accounts payable, changes in deferred energy, and adjustments related to the adoption of SFAS No. 143. The increase in construction work in progress of $75.4 million, or 20.3%, is primarily due to payments for construction of our three
combustion turbine facilities and the purchase of pollution control facilities at Clover. 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 recovered
from or refunded to our member distribution cooperatives in subsequent periods through changes in the fuel factor adjustment rate. The deferred energy balance changed from a $3.0 million liability (over-collection of costs) at December 31, 2002, to
a $6.5 million asset (under-collection of costs) at June 30, 2003, and is a result of higher energy costs incurred in the first six months of 2003 that were not completely recovered through our base energy rate and fuel factor adjustment rate.



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. Our cash needs exceeded our cash flows from operating activities by $13.8
million during the first six months of 2003. Our operating activities provided excess cash flows of $69.8 million for the first six months of 2002. Operating activities for the first six months of 2003 were affected primarily by changes between
periods in our current assets, deferred energy, current liabilities and regulatory assets and liabilities.



Financing Activities.In addition to liquidity from our operating activities, we maintain committed lines of credit to cover short-term
funding needs. Currently, we have short-term committed variable rate lines of credit in an aggregate amount of $245.0 million. Of this amount, $125.0 million is available for general working capital purposes and $120.0 million is available for
capital expenditures related to our generating facilities, including the development and construction of our three combustion turbine facilities.



At June 30, 2003 and 2002, 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 our combustion turbine facilities.



To fully participate in power-related markets, TEC Trading must maintain
credit support sufficient to meet delivery and payment obligations associated with power and natural gas trades. To assist TEC Trading in providing this support, we have agreed to guarantee up to $42.5 million of TEC Tradings delivery and
payment obligations associated with its power trades. At June 30, 2003, we had guaranteed $5.5 million of obligations of TEC Trading and we guaranteed an additional $4.5 million in July 2003, for a total of $10.0 million.



In July 2003, we issued $250.0 million of 2003 Series A Bonds under
our Indenture. The bonds bear interest at 5.676% and mature in 2028. The majority of the proceeds will be used to fund construction costs associated with our combustion turbine facilities. Additionally, a portion of the funds may be used to redeem
some of our outstanding indebtedness in the future.



Investing Activities.Investing activities in the first six months of 2003 consisted primarily of expenditures for our three combustion turbine facilities and liquidating investments to fund construction and development
expenses.





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Competition and Changing Regulations



All of the customers of our Delaware and Maryland member distribution cooperatives, and of Northern Virginia Electric
Cooperative, Rappahannock Electric Cooperative and Shenandoah Valley Electric Cooperative in Virginia, were free to choose an alternative power supplier as of June 30, 2003. These five member distribution cooperatives accounted for 75.6% of our
capacity requirements in 2002. As of August 13, 2003, none of the customers of these member distribution cooperatives had chosen an alternative power supplier and no alternative power suppliers were registered to provide power to customers of our
member distribution cooperatives.



Recent Developments



As part of our regular evaluation of our power supply and resource options,
on May 9, 2003, we issued a request for proposals to serve specified portions of our member distribution cooperatives capacity or energy requirements on the Delmarva Peninsula. We sought proposals for service beginning on January 1, 2004, and
ending on May 31 of 2008 or 2013. We are currently evaluating responses to this request.



In addition to the request for proposals relating to the Delmarva Peninsula, we are also exploring our power supply options to service our member distribution cooperatives requirements on the Virginia mainland.
Currently, we have negotiated an agreement in principle granting us the option to purchase over several years a portion of our intermediate energy requirements on the Virginia mainland at prices that will be based on specified heat rate and variable
gas prices.



We have a forward purchase contract to purchase
energy from Mirant Americas Energy Marketing, L.P. (Mirant) that expires December 31, 2003. On July 14, 2003, Mirant filed a voluntary petition for relief under Chapter 11 of the United States Bankruptcy Code. Mirant has continued to
perform its obligations to us under the terms of the contract with us and has stated its intention to continue to do so. If Mirant fails to perform its obligations to us under the contract, we do not anticipate any material adverse impact on our
financial condition or results of operations.



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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 second
quarter of 2003.



ITEM 4. CONTROLS AND PROCEDURES



Evaluation of
disclosure 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 as defined in

Rules 13a15(e) or 15d15(e) under the Securities Exchange Act of 1934 within 90 days of this report. 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. Due to some inherent limitations of the
effectiveness of any established controls or procedures, our management cannot provide absolute assurance that the objectives of their disclosure and controls procedures will be met.



Changes in Internal Controls



There has been no significant change in any of our internal control over financial reporting that occurred during our most recent fiscal quarter that has
materially affected, or is reasonably likely to materially affect, our internal control over financial reporting.



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OLD DOMINION ELECTRIC COOPERATIVE



PART II. OTHER INFORMATION



ITEM 1. LEGAL
PROCEEDINGS



No material developments have occurred in our
legal proceedings with PSE&G since the filing of our Annual Report on Form 10-K for the fiscal year ended December 31, 2002. We have met with Enron Power Marketing, Inc. before the mediator and have made progress towards a settlement. Based on
the progress made towards a settlement, we have accrued an anticipated amount, which we do not expect 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.
Other than certain 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 6. EXHIBITS AND REPORTS ON FORM 8-K



|(a) |  | Exhibits
|--- |  | --------



|     |  |                                                                          
|---- |  | -------------------------------------------------------------------------
|31.1 |  | Certification of the Chief Executive Officer pursuant to Rule 15d  14(a)
|     |  |                                                                          
|31.2 |  | Certification of the Chief Financial Officer pursuant to Rule 15d  14(a)
|     |  |                                                                          
|32.1 |  | Certification of the Chief Executive Officer pursuant to 18 U.S.C. § 1350
|     |  |                                                                          
|32.2 |  | Certification of the Chief Financial Officer pursuant to 18 U.S.C. § 1350



|(b) |  | Reports on Form 8-K.
|--- |  | --------------------



The Registrant filed no reports on Form 8-K during the quarter ended June 30, 2003.



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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: |  | August 14, 2003 |  |  |  |  |  |  |  |  |  |  |  |                                             
|      |  |                 |  |  |  |  |  |  |  |  |  |  |  |                                             



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EXHIBIT INDEX



|Exhibit Number |  | Description of Exhibit                                                    |  | PageNumber
|-------------- |  | ------------------------------------------------------------------------- |  | ----------
|               |  |                                                                          
|31.1           |  | Certification of the Chief Executive Officer pursuant to Rule 15d  14(a) |  | 22        
|               |  |                                                                          
|31.2           |  | Certification of the Chief Financial Officer pursuant to Rule 15d  14(a) |  | 23        
|               |  |                                                                          
|32.1           |  | Certification of the Chief Executive Officer pursuant to 18 U.S.C. § 1350 |  | 24        
|               |  |                                                                          
|32.2           |  | Certification of the Chief Financial Officer pursuant to 18 U.S.C. § 1350 |  | 25        



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