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UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-Q

(Mark One)

For the quarterly period ended September 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)

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 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. These liabilities were 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 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

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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 alleging that we and Virginia Power have failed to state a claim under Virginia law. On November 5, 2004, the court heard arguments regarding whether we and Virginia Power failed to state a claim and has taken the matter under advisement; however, the court has not ruled on this or other matters related to these proceedings. Further proceedings have not been scheduled. 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

Caution Regarding Forward-Looking Statements

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

Critical Accounting Policies

As of September 30, 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.

Overview

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

Our results for the three and nine months ended September 30, 2004, were primarily impacted by the following factors:

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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 energy rates, the base energy rate and the fuel factor adjustment rate. The base energy rate is a fixed rate that requires FERC approval prior to adjustment. However, to the extent the base energy rate over- or under-collects all of our energy costs, we refund or collect the difference through a fuel factor adjustment rate. We review our energy costs at least every six months to determine whether the base energy rate and the current fuel factor adjustment rate together are adequately recovering our actual and anticipated energy costs, and revise the fuel factor adjustment rate accordingly. Because the fuel factor adjustment rate can be revised without FERC approval, we can effectively change our total energy rate to recover all our energy costs without seeking the approval of FERC.

Capacity costs, which are primarily fixed costs, such as depreciation expense, interest expense, administrative and general expenses, capacity costs under power purchase contracts with third parties, transmission costs, and our margin requirements and additional amounts approved by our board of directors are recovered through our demand rate. The formulary rate allows us to change the actual demand rate we charge as our capacity-related costs change, without seeking FERC approval, with the exception of extraordinary deductions, and decommissioning cost, which is a fixed amount in the formulary rate that requires FERC approval prior to any adjustment. As of December 23, 2003, decommissioning costs have been fixed at zero, reflecting our assessment that, based on current projections, our decommissioning trust fund is adequately funded. 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. 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. Our operating revenues by type of purchaser for the three and nine months ended September 30, 2004 and 2003, were as follows:

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Our energy sales in megawatt hours (“MWh”) to our members and non-members for the three and nine months ended September 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 from sales to our member distribution cooperatives by formulary rate component and average costs to our member distribution cooperatives in MWh for the three and nine months ended September 30, 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 operate 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 September 30, 2004, increased $8.9 million, or 6.6%, 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 8.3% as a result of warmer weather experienced by consumers of our member distribution cooperatives in July and September 2004 as compared to the same period in 2003, which created a greater requirement for power to operate air conditioning systems, partially offset by milder weather in August 2004 as compared to the same period in 2003.

Our total energy rate (including our base energy rate and our fuel factor adjustment rate) was 5.5% higher during the three months ended September 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.

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The capacity costs we incurred, and thus the capacity-related revenues we reflected, for the three months ended September 30, 2004, as compared to the same period in 2003, declined $2.3 million, or 4.2%, primarily as a result of lower interest expense and associated margin requirement. 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, and see “Interest Charges” for a discussion of interest expenses.

Our average costs to member distribution cooperatives per MWh decreased $0.81 per MWh, or 1.6%, for the three months ended September 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 nine months ended September 30, 2004, increased $16.6 million, or 4.3%, 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 9.7% as a result of colder weather experienced by consumers of our member distribution cooperatives in January and February as compared to the same period in 2003, and warmer weather in May, June, July and September as compared to the same period in 2003, which created a greater requirement for power to operate heating and air conditioning systems.

Our total energy rate (including our base energy rate and our fuel factor adjustment rate) was 5.5% higher during the nine months ended September 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.

The capacity costs we incurred, and thus the capacity-related revenues we reflected, for the nine months ended September 30, 2004, as compared to the same period in 2003, declined $17.0 million, or 9.7%, primarily as a result of lower capacity-related purchased power expenses. See “Operating Expenses” for a discussion of purchased power expense.

Our average costs per MWh to member distribution cooperatives decreased $2.63 per MWh, or 5.0%, for the nine months ended September 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. Sales to TEC consist primarily of sales of excess energy that we do not need to meet the actual needs of our member distribution cooperatives. Sales to TEC for the three months ended September 30, 2004, were $1.6 million higher, as compared to the same period in 2003, due to more excess energy during the quarter. Sales to TEC for the first nine months ended September 30, 2004, were $10.6 million lower than in the same period in 2003, because we had less excess energy in the first nine months of 2004 than in the first nine 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 nine months ended September 30, 2004, were lower than in 2003 by $1.4 million and $5.4 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 North Anna, our Louisa, Marsh Run, 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 nine months ended September 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, Louisa, and Marsh Run 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 Louisa, Rock Springs and Marsh Run. 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; 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,

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are more significantly affected by the operations of Clover and North Anna than by our combustion turbine facilities. The output of Clover and North Anna for the three months and nine months ended September 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 nine months ended September 30, 2004. Clover Unit 1 was off-line for 20 days for a scheduled maintenance outages during the nine months ended September 30, 2003. Clover Unit 2 was off-line for 18 days and 36 days for a scheduled maintenance outages during the three and nine months ended September 30, 2003, respectively.

North Anna. North Anna Unit 1 was off-line for 19 days for the three and nine months ended September 30, 2004, for a scheduled refueling outage and was returned to service on October 6, 2004. North Anna Unit 1 was off-line for 54 days for a scheduled refueling, replacement of the reactor vessel head and an unscheduled outage during the nine months ended September 30, 2003, respectively. North Anna Unit 2 was off-line for 28 days for a scheduled refueling outage during the nine months ended September 30, 2004.

Combustion turbine facilities. During the third quarter of 2004, the operational availability of our Louisa and Rock Springs combustion turbine facilities was 94.9% and 99.9%, respectively. During the first nine months of 2004, the operational availability of our Louisa and Rock Springs combustion turbine facilities was 95.9% and 96.0%, respectively. On September 15, 2004, our Marsh Run combustion turbine facility became commercially operable.

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

Aggregate operating expenses increased $12.1 million, or 10.1%, for the three months ended September 30, 2004, as compared to the same period in 2003, primarily due to increases in purchased power expense and operations and maintenance expense offset by a change in deferred energy.

Purchased power expense increased $24.7 million, or 41.3%, for the three months ended September 30, 2004, as compared to the same period in 2003, due to an increased need for purchased power caused by higher energy sales, the need to replace energy not available from North Anna due to its scheduled refueling outage and the fact that it was more economical to purchase power than to run our combustion turbine facilities. In addition, the average cost of purchased power for the three months ended September 30, 2004, increased 6.4%, as compared to the same period in 2003.

Deferred energy expense changed $13.1 million, or 227.6%, for the three months ended September 30, 2004, as compared to the same period of 2003. During the third quarter of 2004, we under-collected $7.4 million in energy costs versus the third quarter of 2003 when we had over-collected $5.8 million in energy costs. At September 30, 2004, we had an under-collected deferred energy balance of $1.2 million.

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Operations and maintenance expense increased $2.9 million or 38.1%, for the three months ended September 30, 2004, as compared to the same period in 2003, primarily due to increased operation and maintenance costs at North Anna related to the scheduled refueling outage. Operations and maintenance costs incurred for our Louisa and Rock Springs combustion turbine facilities, which became commercially operable in June 2003, increased slightly.

Aggregate operating expenses remained relatively flat for the nine months ended September 30, 2004, as compared to the same period in 2003 as a result of the net impact of increases in fuel expense, decreases in purchased power expense and changes in deferred energy and amortization of regulatory asset (liability), net.

Fuel expense increased $10.8 million, or 19.2%, for the nine months ended September 30, 2004, as compared to the same period in 2003 due to the increase in the cost of coal for Clover, the increased operation of North Anna during 2004 as compared to 2003, and the increased operation of our Louisa and Rock Springs combustion turbine facilities, which are fueled by natural gas and fuel oil. Louisa and Rock Springs began commercial operations June of 2003.

Purchased power expense decreased $11.0 million, or 4.5%, for the nine months ended September 30, 2004, as compared to the same period in 2003. North Anna operated more in 2004 as compared to 2003 when the units were off-line for repairs. In addition, the average cost of purchased power for the nine months ended September 30, 2004, decreased 5.9% as compared to the same period in 2003, thereby reducing purchased power expense.

Deferred energy expense changed $11.0 million, or 287.2%, for the nine months ended September 30, 2004, as compared to the same period in 2003. During the nine months ended September 30, 2004, we under-collected $15.0 million in energy costs as compared to the same period in 2003, when we had under-collected $3.8 million in energy costs. At September 30, 2004, we had an under-collected deferred energy balance of $1.2 million.

Amortization of regulatory asset/(liability), net changed $6.7 million, or 794.7% 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.

Other Items

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

Other income/(expense), net increased for the three and nine months ended September 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 decreased by $0.2 million or 42.2% for the three months ended September 30, 2004, as compared to the same period in 2003. Investment income increased by $0.3 million, or 14.8%, for the first nine 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.

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