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UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-Q

(Mark One)

For the quarterly period ended June 30, 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 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

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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)

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)

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 Station (“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 have been paying PSE&G surcharges for pancaked rates on a prospective basis, subject to protest and FERC

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action 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. On July 13, 2004, FERC denied our request for rehearing.

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.

On August 12, 2004, we made a payment of $33.1 million to PSE&G in full settlement of our legal disputes with it. The terms of our agreement provide for (1) the dismissal of PSE&G’s lawsuit in the United States Court of the District of New Jersey in Newark with each party bearing its own respective costs and legal fees and (2) our agreement not to file a petition for review with the United States Court of Appeals of the FERC orders issued on October 22, 2003, and July 13, 2004, with respect to these matters in the complaint.

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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impact on our financial statements at December 31, 2004, is dependent upon the level of TEC’s activity at year-end. We continue to evaluate other existing entities and the impact of applying this new statement and we believe that it will not have a material impact on our financial position, results of operations, or cash flow.

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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 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 June 30, 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. The 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

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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.

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 and six months ended June 30, 2004 and 2003, 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 and our member distribution cooperatives’ consumers’ requirements for power. Under our formulary rate, we make adjustments for the recovery or refund of amounts under our Margin Stabilization Plan. We adjust demand revenues and accounts payable – members or accounts receivable each quarter to reflect these adjustments. See “Critical Accounting Policies – Margin Stabilization Plan” in Part II, Item 7 of our Annual Report on Form 10-K for the fiscal year ended December 31, 2003, for a discussion of the Margin Stabilization Plan. Revenues

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from sales to our member distribution cooperatives by formulary rate component and average costs to our member distribution cooperatives in MWh for the three and six months ended June 30, 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 requirement for electricity. Relatively higher or lower temperatures tend to increase the requirement for energy to use air conditioning and heating systems. Mild weather generally reduces the requirement because air conditioning and heating systems are operated less.

Total revenues from sales to our member distribution cooperatives for the three months ended June 30, 2004, increased $11.4 million, or 9.6%, over the same period in 2003, primarily as a result of increased sales of energy and higher energy rates partially offset by lower incurred capacity costs (which are reflected in revenues in the period in which they are expensed). For this period, sales volumes increased approximately 19.4% as a result of warmer weather experienced by consumers of our member distribution cooperatives in May and June as compared to the prior period, which created a greater requirement for power to operate air conditioning systems, partially offset by milder weather in April as compared to the prior period.

The capacity costs we incurred, and thus the capacity-related revenues we reflected, during the three months ended June 30, 2004, as compared to the same period in 2003, declined $4.5 million, or 7.9%, 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 11.5% higher during the three months ended June 30, 2004, as compared to the same period in 2003. We increased our fuel factor adjustment rate resulting in an increase to our total energy rate of approximately 15.6% effective April 1, 2004. This increase was implemented due to higher than anticipated energy costs in the first quarter of 2004 and projected higher than previously anticipated energy costs for the remainder of 2004.

Our average costs to member distribution cooperatives per MWh decreased $4.87 per MWh, or 8.3%, for the three months ended June 30, 2004, as compared to the same period in 2003, as a result of the increase in sales volumes and the decrease in capacity costs partially offset by the increase in our total energy rate.

Total revenues from sales to our member distribution cooperatives for the six months ended June 30, 2004, increased $7.8 million, or 3.0%, as compared to the same period in 2003 primarily as a result of increased sales of energy and higher energy rates partially offset by lower incurred capacity costs (which are reflected in revenues in the period in which they are expensed). Sales volumes increased approximately 10.5% as a result of colder weather experienced by consumers of our member distribution cooperatives in January and February as compared to the prior period, and warmer weather in May and June as compared to the prior period, which created a greater requirement for power to operate heating and air conditioning systems.

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The capacity costs we incurred, and thus the capacity-related revenues we reflected, for the six months ended June 30, 2004, as compared to the same period in 2003, declined $14.6 million, or 12.2%, 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 5.6% higher during the six months ended June 30, 2004, as compared to the same period in 2003. Due to higher than anticipated energy costs in the first quarter of 2004 and projected higher than previously anticipated energy costs for the remainder of 2004, we increased our fuel factor adjustment rate effective April 1, 2004, resulting in an increase to our total energy rate of approximately 15.6%. We had 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.

Our average costs to member distribution cooperatives per MWh decreased $3.60 per MWh, or 6.7%, for the six months ended June 30, 2004, as compared to the same period in 2003, as a result of the increase in sales volumes and the decrease in capacity costs partially offset by the increase in our total energy rate.

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 energy as excess energy. Sales to TEC for the second quarter and first six months of 2004, were lower than in 2003 by $7.3 million and $12.2 million, respectively, because we had less excess energy in the second quarter and first six months of 2004 than in the second quarter and first six months of 2003. 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 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”) to which we are entitled. 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 and six months ended June 30, 2004, were lower than in 2003 by $3.5 million and $4.0 million, respectively, primarily because of decreased sales of excess purchased energy to PJM. During the first five months 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 and six months ended June 30, 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. Our combustion turbine facilities have relatively low fixed costs and greater operational flexibility, but are more expensive to operate, and, therefore, we operate them only when the market price of energy makes their operation economical. As a result, our operating expenses, and consequently our rates to our member distribution cooperatives, are significantly affected by the operations of Clover and North Anna rather than our

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combustion turbine facilities. The output of Clover and North Anna for the three months and six months ended June 30, 2004 and 2003 as a percentage of the maximum dependable capacity rating of the facilities was as follows:

Clover. Clover Unit 1 was off-line for 37 days for a scheduled maintenance outage during the three and six months ended June 30, 2004. Clover Unit 1 was off-line for 20 days for a scheduled maintenance outage during the three and six months ended June 30, 2003. Clover Unit 2 was off-line for 18 days and 36 days for a scheduled maintenance outage during the three and six months ended June 30, 2003, respectively.

North Anna. North Anna Unit 2 was off-line for 28 days for a scheduled refueling outage during the three and six months ended June 30, 2004. North Anna Unit 1 was off-line for 17 days and 54 days for a scheduled refueling, replacement of the reactor vessel head and an unscheduled outage during the three and six months ended June 30, 2003, respectively.

Combustion turbine facilities. During the first quarter of 2004, the operational availability of our Louisa and Rock Springs combustion turbine facilities was 98.7% and 99.6%, respectively. During the first six months of 2004, the operational availability of our Louisa and Rock Springs combustion turbine facilities was 96.4% and 94.0%, respectively.

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The components of our operating expenses for the three and six months ended June 30, 2004 and 2003, were as follows:

Aggregate operating expenses decreased $2.4 million, or 2.0%, for the three months ended June 30, 2004, as compared to the same period in 2003 due to a decrease in purchased power, a change in deferred energy and a decrease in operations and maintenance expense, partially offset by an increase in fuel expense and depreciation, amortization and decommissioning.

Purchased power decreased $7.0 million, or 9.5%, for the three months ended June 30, 2004, as compared to the same period in 2003, due to a decreased need for purchased power as a result of increased generation associated with the Louisa and Rock Springs combustion turbine facilities, which became commercially operable in June 2003. In addition, the average cost of purchased power for the three months ended June 30, 2004, decreased 6.1%, as compared to the same period in 2003.

Deferred energy expense changed $6.2 million, or 93.5%, for the three months ended June 30, 2004, as compared to the same period of 2003. During the second quarter of 2004, we over-collected $0.4 million in energy costs versus the second quarter of 2003 when we had over-collected $6.7 million in energy costs. At June 30, 2004, we had an over-collected deferred energy balance of $6.1 million.

Operations and maintenance expense increased $1.8 million or 18.4%, for the three months ended June 30, 2004, as compared to the same period in 2003. The second quarter of 2004 included operations and maintenance costs incurred for the Louisa and Rock Springs combustion turbine facilities, which became commercially operable in June 2003.

Fuel expense increased $5.6 million, or 35.2%, for the three months ended June 30, 2004, as compared to the same period in 2003 due to the increase in the cost of coal for Clover and the increased operation of Clover Unit 2 in 2004. Also, fuel expense increased in 2004 due to the operation of the Louisa and Rock Springs combustion turbine facilities. Louisa and Rock Springs did not begin commercial operations until June of 2003.

Depreciation, amortization and decommissioning expense increased $1.9 million, or 36.2%, for the three months ended June 30, 2004, as compared to the same period in 2003 due to the depreciation recognized by our Louisa and Rock Spring combustion turbine facilities in 2004.

Aggregate operating expenses decreased $11.6 million, or 4.6%, for the six months ended June 30, 2004, as compared to the same period in 2003 due to decreases in purchased power and operations and maintenance expense, partially offset by an increase in fuel expense, a change in amortization of regulatory asset/(liability), net, an increase in depreciation, amortization and decommissioning, and the change in deferred energy.

Purchased power expense decreased $35.7 million, or 19.5%, for the six months ended June 30, 2004, as compared to the same period in 2003 as a result of increased 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 six months ended June 30, 2004, as compared to the same period in 2003. In addition, the average cost of purchased power for the six months ended June 30, 2004, decreased 10.9% as compared to the same period in 2003.

Operations and maintenance expense decreased $4.7 million, or 18.5%, for the six months ended June 30, 2004, as compared to the same period in 2003. The first six months of 2003 included costs incurred for the replacement of the reactor vessel heads at North Anna. There were no such costs in the first six months of 2004. These costs were partially offset by operations and maintenance costs related to our Louisa and Rock springs combustion turbine facilities, which became commercially operable in June 2003.

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Fuel expense increased $12.4 million, or 42.7%, for the six months ended June 30, 2004, as compared to the same period in 2003 due to the increase in the cost of coal for Clover and the increased operation of Clover Unit 2 in 2004 as compared to 2003. Also, fuel expense increased in 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.

Amortization of regulatory asset/(liability), net changed $6.9 million, or 266.3% primarily due to the $5.6 million revenue deferral recognized in 2003, which had been established in 2002. There was no such transaction in 2004.

Depreciation, amortization and decommissioning expense increased $3.8 million, or 35.5%, for the six months ended June 30, 2004, as compared to the same period in 2003 due to the depreciation recognized by our Louisa and Rock Spring combustion turbine facilities in 2004.

Deferred energy expense changed $2.2 million, or 22.4%, for the six months ended June 30, 2004, as compared to the same period in 2003. During the six months ended June 30, 2004, we under-collected $7.4 million in energy costs as compared to the same period in 2003, when we had under-collected $9.6 million in energy costs. At June 30, 2004, we had an over-collected deferred energy balance of $6.1 million.

Other Items

Other Income/(Expense), net. The major components of our other income/(expense), net for the three and six months ended June 30, 2004 and 2003, were as follows:

Other income/(expense), net increased by $0.3 million, for the three and six months ended June 30, 2004, as compared to the same periods in 2003 due to our donation of transmission assets to one of our member distribution cooperatives in 2003. There was no such transaction in 2004.

Investment Income. Investment income remained relatively flat for the three months ended June 30, 2004, as compared to the same period in 2003. Investment income increased by $0.5 million, or 32.2%, for the first six months of 2004 as compared to the same period in 2003 primarily due to an increase in the investment income on the decommissioning fund in 2004 as compared to 2003.

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

The major components of interest charges, net for the three and six months ended June 30, 2004 and 2003, were as follows: