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UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-Q

(Mark One)

For the quarterly period ended March 31, 2004

or

For the transition period from              to             

Commission file number 000-50039

OLD DOMINION ELECTRIC COOPERATIVE

(Exact Name of Registrant as Specified in Its Charter)

(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 Exchange Act Rule 12b-2).    Yes  ¨    No  x

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

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OLD DOMINION ELECTRIC COOPERATIVE

INDEX

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OLD DOMINION ELECTRIC COOPERATIVE

PART I. FINANCIAL INFORMATION

ITEM 1. FINANCIAL STATEMENTS

CONDENSED CONSOLIDATED BALANCE SHEETS

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

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OLD DOMINION ELECTRIC COOPERATIVE

CONDENSED CONSOLIDATED STATEMENTS OF REVENUES,

EXPENSES AND PATRONAGE CAPITAL (UNAUDITED)

OLD DOMINION ELECTRIC COOPERATIVE

CONDENSED CONSOLIDATED STATEMENTS

OF COMPREHENSIVE INCOME (UNAUDITED)

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

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OLD DOMINION ELECTRIC COOPERATIVE

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOW (UNAUDITED)

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

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

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

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

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

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

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

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

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OLD DOMINION ELECTRIC COOPERATIVE

ITEM 2. MANAGEMENT’S DISCUSSION AND ANALYSIS

OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS

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

Critical Accounting Policies

As of March 31, 2004, there have been no significant changes in our critical accounting policies as disclosed in our Annual Report on Form 10-K for the fiscal year ended December 31, 2003. These policies included the accounting for rate regulation, deferred energy, asset retirement obligations, derivative contracts, and our margin stabilization plan.

Results of Operations

Operating Revenues

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

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

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

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

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

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

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

Sales to Member Distribution Cooperatives. Revenues from sales to our member distribution cooperatives are a function of our formulary rate for sales of power to our member distribution cooperatives, our member distribution cooperatives’ consumers’ requirements for power and adjustments for the recovery or refund of amounts under our Margin Stabilization Plan. We adjust revenues and accounts payable-members or accounts receivable each quarter to reflect adjustments under the Margin Stabilization Plan. See “Critical Accounting Policies – Margin Stabilization Plan” in Part II, Item 7 of our Annual Report on Form 10-K for the fiscal year ended December 31, 2003, for a discussion of the Margin Stabilization Plan. Our revenues from sales to our member distribution cooperatives by formulary rate component and average costs to our member distribution cooperatives in

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

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

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

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

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

Sales to TEC. Our sales to TEC are primarily sales of energy that we do not need to meet the actual needs of our member distribution cooperatives. We refer to this as excess energy. Revenue from sales to TEC is generated pursuant to our power sales contract with it. Sales to TEC for the first quarter of 2004, were lower than in 2003 by $4.9 million, or 81.1%, because we had less excess energy in the first quarter of 2004 than in the first quarter of 2003. During the first quarter of 2003, we exercised a contractual option to purchase energy at then favorable market prices. We sold the portion of this energy that could not be utilized by our member distribution cooperatives to TEC for resale into the market, or to non-members.

Sales to Non-Members. Sales to non-members consist of sales of excess purchased energy and sales of excess generated energy from the Clover Power Station (“Clover”). We sell excess purchased energy that is not sold to TEC to PJM Interconnection, LLC (“PJM”) under its rates for providing energy imbalance services. We sell excess energy from Clover to Virginia Electric and Power Company (“Virginia Power”) pursuant to the requirements of the Clover Operating Agreement. Non-member revenues for the three months ended March 31, 2004, were lower than in 2003 by $0.5 million, or 29.1%, primarily because of decreased sales of excess purchased energy to PJM. During the first quarter of 2003, we exercised a contractual option to purchase energy at then favorable market prices and we sold the portion of this energy that could not be utilized by our member distribution cooperatives to TEC for resale into the market, or to non-members.

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Operating Expenses

We supply our member distribution cooperatives’ power requirements, consisting of capacity requirements and energy requirements, through (i) our owned or leased interests in electric generating facilities which consist of a 50% interest in Clover, an 11.6% interest in the North Anna Nuclear Power Station (“North Anna”), our Louisa and Rock Springs combustion turbine facilities, and distributed generation, and (ii) power purchases from third parties through power purchase contracts and forward, short-term and spot market energy purchases. Our energy supply for the three months ended March 31, 2004 and 2003, was as follows:

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

Our operating expenses are significantly affected by the extent to which we purchase power and, relatedly, the availability of our base load generating facilities, Clover and North Anna. Base load generating facilities, particularly nuclear power plants such as North Anna, generally have relatively high fixed costs. Nuclear facilities operate with relatively low variable costs due to lower fuel costs and technological efficiencies. In addition, coal-fired facilities have relatively low variable costs, as compared to combustion turbine facilities such as Rock Springs and Louisa. Owners of nuclear and other power plants incur the embedded fixed costs of these facilities whether or not the units operate. When either Clover or North Anna is off-line, we must purchase replacement energy from either Virginia Power, which is more costly, or from the market, which may be more or less costly. As a result, our operating expenses, and consequently our rates to our member distribution cooperatives, are significantly affected by the operations of Clover and North Anna rather than our combustion turbine facilities. The output of Clover and North Anna for the first quarter of 2004 and 2003 as a percentage of the maximum dependable capacity rating of the facilities was as follows:

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

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

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

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

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

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

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

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Other Items

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

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

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

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

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

Interest charges, net increased in 2004 by $3.7 million, or 44.2%, as compared to the same period in 2003 due to an increase in interest expense on long-term debt as a result of our $250.0 million debt issuance in July 2003, and a decrease in the amount of capitalized interest relating to the development and construction of our three combustion turbine facilities. We began capitalizing interest on the Rock Springs and Louisa facilities in October 2001 and January 2002, respectively, and ceased capitalizing interest in June 2003 when the facilities became commercially operable. We began capitalizing interest on the Marsh Run facility in April 2003. Capitalized interest is computed monthly using an interest rate, which reflects our embedded cost of indebtedness, multiplied by our investment in projects under construction.

Net Margin. Our net margin, which is a function of our interest charges, increased $0.2 million, or 8.7%, in the first quarter of 2004 as compared to the same period in 2003, due to the $1.2 million increase in our total interest charges.

Financial Condition

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

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

Liquidity and Capital Resources

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

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

At March 31, 2004, and 2003, we had no short-term borrowings or letters of credit outstanding under any of these arrangements. We expect the working capital lines of credit to be renewed as they expire. We expect the construction-related lines of credit to be renewed until no longer necessary for the development and construction of the combustion turbine facilities.

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

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

Capped Rates

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

Potential Restructuring

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

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Subsequent Event

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

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OLD DOMINION ELECTRIC COOPERATIVE

ITEM 3. QUANTITATIVE AND QUALITATIVE

DISCLOSURES ABOUT MARKET RISK

No material changes occurred in our exposure to market risk during the first quarter of 2004.

ITEM 4. CONTROLS AND PROCEDURES

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

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OLD DOMINION ELECTRIC COOPERATIVE

PART II. OTHER INFORMATION

ITEM 1. LEGAL PROCEEDINGS

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

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

No material developments have occurred in our legal proceedings with PSE&G or Norfolk Southern since the filing of our Annual Report on Form 10-K for the fiscal year ended December 31, 2003. Other than legal proceedings arising out of the ordinary course of business, which management believes will not have a material adverse impact on our results of operations or financial condition, there is no other litigation pending or threatened against us.

ITEM 5. OTHER INFORMATION

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

ITEM 6. EXHIBITS AND REPORTS ON FORM 8-K

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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.

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