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SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-Q

(Mark One)

For the quarterly period ended March 31, 2003

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.

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

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OLD DOMINION ELECTRIC COOPERATIVE

CONDENSED CONSOLIDATED STATEMENTS OF REVENUES,

EXPENSES AND PATRONAGE CAPITAL (UNAUDITED)

OLD DOMINION ELECTRIC COOPERATIVE

CONDENSED CONSOLIDATED STATEMENTS

OF COMPREHENSIVE INCOME (UNAUDITED)

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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

    The following represents changes in our Asset Retirement Obligation for the three months ended March 31, 2003:

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

Critical Accounting Policies

As of March 31, 2003, other than the adoption of Statement of Financial Accounting Standards (“SFAS”) No. 143, Accounting for Asset Retirement Obligations, there have been no significant changes with regard to our critical accounting policies as disclosed in our Annual Report on Form 10-K for the fiscal year ended December 31, 2002. The policies disclosed included the accounting for rate regulation and our margin stabilization plan.

On January 1, 2003, we adopted SFAS No. 143, which provides accounting requirements for the recognition and measurement of liabilities associated with the retirement of tangible long-lived assets. At March 31, 2003, our asset retirement obligations totaled $39.6 million, the majority of which relates to the decommissioning of our undivided ownership interest in the North Anna Nuclear Power Station (“North Anna”) as well as certain asset retirement obligations at the Clover Power Station (“Clover”) and our diesel facilities.

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

Results of Operations

Operating Revenues

Our operating revenues are derived from power sales to our members and non-members. Our sales to members include sales to our Class A members, which are our twelve member distribution cooperatives, and sales to our single Class B member, TEC Trading, Inc. (“TEC Trading”). Our operating revenues by type of purchaser for the three months ended March 31, 2003 and 2002, were as follows:

Revenues from sales to our member distribution cooperatives are a function of our formulary rate for sales of power to our member distribution cooperatives and our member distribution cooperatives’ consumers’ requirements for power. Our formulary rate is based on our cost of service in meeting these requirements and consists of a demand rate, a base energy rate and a fuel factor adjustment rate. Revenue from sales to TEC Trading is made pursuant to our power sales contract with it.

Our power sales are comprised of two power products – energy and capacity (also referred to as demand). Energy is the physical electricity delivered through transmission and distribution facilities to customers. We bill energy to each of our member and non-member customers based on the total megawatt-hours (“MWh”) delivered to them each month and, with respect to our member distribution cooperatives, charge them an amount based on the base energy rate and fuel factor adjustment rate. Because energy cannot be stored, we must have sufficient committed energy available to us for delivery to our member distribution cooperatives to meet their maximum energy needs at any time, with limited exceptions. This committed available energy is referred to as capacity. We use our generating facilities and rely on power purchase contracts to satisfy substantially all of our member distribution cooperatives’ capacity requirements. We bill capacity to each of our member distribution cooperatives monthly through our demand rate which is based on our budgeted capacity costs. The quantity billed to each member distribution cooperative is based on its requirement for energy during the hour of the month when the need for energy among all of the consumers in mainland Virginia or the Delmarva Peninsula, as applicable, is highest, measured in megawatts (“MW”).

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Sales to Member Distribution Cooperatives

Our revenues from sales to our member distribution cooperatives by formulary rate component, energy sales to our member distribution cooperatives, and average costs to our member distribution cooperatives per MWh for the three months ended March 31, 2003, and 2002 were as follows:

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

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

Total revenues from our member distribution cooperatives for the three months ended March 31, 2003, increased $4.3 million, or 3.3%, over the same period in 2002 as a result of increased sales of both capacity and energy and an increase in our average demand rate. Capacity sales in the first quarter of 2003, measured in MW, increased 11.3% and energy sales, measured in MWh, increased 18.4% over those realized in the first quarter of 2002. Sales volumes increased primarily as a result of unusually cold winter weather experienced by consumers of our member distribution cooperatives. Lower than normal temperatures created a greater requirement for power to operate heating systems.

Our average demand rate increased 4.0% in the first quarter of 2003 compared to the same period in 2002. The increase in our average demand rate resulted from an increase in the demand component of our formulary rate of approximately 5.0%, effective February 1, 2003, enacted to collect from our member distribution cooperatives transmission charges associated with our power purchase agreement with Public Service Electric & Gas Company (“PSE&G”). We anticipate that the increase in the demand component of our formulary rate will recover over 48 months a $32.9 million contingency we established to reflect a surcharge billed to us by PSE&G, and associated interest expense and margin requirement. Additionally, we anticipate that the revised demand component of our formulary rate will recover the amount of transmission costs that we are paying to PSE&G now until the termination of the contract in December 2004. We are making these payments under protest and subject to FERC action on this issue. See “Legal Proceedings” in Part II, Item 1.

The increase in total revenues attributable to a growth in sales volume was substantially offset by a decrease in the average energy rates that we charged in the first quarter of 2003 for power sold. Our average energy rate (including our base energy rate and our fuel factor adjustment rate) decreased 20.2% in the first quarter of 2003 compared to the same period in 2002 as a result of a drop in our average fuel factor adjustment rate. We reduced our fuel factor adjustment rate effective April 1, 2002, because the fuel

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factor adjustment rate that had been in effect since April 1, 2001, had fully recovered our deferred energy balance at December 31, 2001, (an $18.2 million under-collection of energy costs) and had resulted in a $4.1 million over-collection of energy costs at March 31, 2002, and we anticipated that future energy costs would be adequately recovered with the lower fuel factor adjustment rate. We reduced our fuel factor adjustment rate again effective October 1, 2002, because our deferred energy balance at September 30, 2002, represented a $5.0 million over-collection of energy costs, and we again anticipated that future energy costs would be adequately recovered with the lower fuel factor adjustment rate. Our board of directors approved a change to our fuel factor adjustment rate, which resulted in an increase to our total energy rate (including our base energy rate and our fuel factor adjustment rate) of approximately 18.0% effective March 1, 2003. The increase in the fuel factor adjustment rate was necessary to recover higher than expected actual energy costs that we incurred in the first two months of 2003 and energy costs for the remainder of the year that we anticipate will be higher than the energy costs we originally budgeted for 2003. See “Operating Expenses” below.

Sales to TEC Trading. Sales to TEC Trading were $6.0 million in the first quarter of 2003 compared with no sales to it in the first quarter of 2002. Our sales to TEC Trading are primarily sales of excess energy. Energy sales in MWh to TEC Trading for the first quarter of 2003 were 104,000 MWh.

Sales to Non-Members. Sales to non-members consist of sales of excess purchased energy and sales of excess generated energy from Clover. We sell excess purchased energy to PJM Interconnection, LLC (“PJM”) under its rates for providing energy imbalance services or to TEC Trading. We sell excess energy from Clover to Virginia Power pursuant to the requirements of the Clover Operating Agreement. Non-member revenues for the three months ended March 31, 2003, were higher than in 2002 by $1.3 million, or 324.4%, primarily because of increased sales of excess purchased energy to PJM. Our non-members energy sales in MWh for the three months ended March 31, 2003, and 2002 were 39,884, and 17,912, respectively.

Operating Expenses

We supply our member distribution cooperatives’ power requirements, consisting of capacity requirements and energy requirements, through (1) our owned or leased interests in electric generating facilities, a 50% interest in Clover, an 11.6% interest in North Anna and ten auxiliary diesel generators, and (2) 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, 2003 and 2002, was as follows:

Market forces influence the structure of new power supply contracts we enter into. To serve the Delmarva Peninsula, we rely on 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 utilize the PJM power pool when economical. In mainland Virginia, we satisfy the majority of our member distribution cooperatives’ capacity and energy requirements through our ownership interests in 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. Owners of nuclear and other power plants incur the embedded fixed costs of these facilities whether or not the units operate. When either North Anna or Clover is off-line, we must purchase replacement energy from either Virginia Power, which is more costly, or the market, which may be more or less costly. As a result, our operating expenses, and consequently our rates to our member distribution cooperatives, are significantly affected by the operations of North Anna and Clover. The output of North Anna and Clover for the first quarter of 2003 and 2002 as a percentage of the maximum dependable capacity rating of the facilities was as follows:

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North Anna. North Anna Unit 1 began an outage for a scheduled refueling and to replace the reactor vessel head of the unit on February 23, 2003. The unit returned to service on April 18, 2003. North Anna Unit 2 began a scheduled refueling outage on September 8, 2002. After the outage began, the reactor vessel head was replaced and the unit was returned to service on February 2, 2003. See also our Annual Report on Form 10-K for the fiscal year ended December 31, 2002, for a discussion of the replacement of the reactor vessel heads at North Anna. There were no maintenance outages at North Anna during the first quarter of 2002.

Clover. Clover Unit 1 experienced only minor unscheduled outages during the first quarter of 2003. In 2002, Unit 1 was removed from service on March 1, 2002, for a 54-day scheduled maintenance outage. Unit 1 also experienced two minor unscheduled outages during the first quarter of 2002. Clover Unit 2 was removed from service on March 14, 2003, for a 35-day scheduled maintenance outage. Unit 2 also experienced minor unscheduled outages during the first quarter of 2003 and 2002.

The components of our operating expenses for the three months ended March 31, 2003 and 2002, were as follows:

Aggregate operating expenses for the first quarter of 2003 increased $8.1 million, or 6.7%, over the same period in 2002 because of an increase in purchased power expense and operation and maintenance expense, partially offset by a decrease in deferred energy expense and the amortization of regulatory liability. Purchased power expense increased $45.0 million, or 69.8%, as a result of increased purchases of energy from the market to supply our member distribution cooperatives’ requirements during unusually cold winter weather during January and February 2003 and a reduction in the available capacity at North Anna. This resulted in a greater dependence on purchased power to meet our power needs for the first quarter of 2003. In addition, the average cost of the power we purchased increased 18.7% in the first quarter of 2003 primarily as a result of increases in the price of natural gas and the resulting impact on the energy market.

At March 31, 2003, we had an under-collected deferred energy balance of $13.2 million, which we anticipate will be fully collected through rates by the end of 2003. Deferred energy expense decreased $38.6 million, or was 172.7% lower in the first quarter of 2003 than in the first quarter of 2002, due to an under-collection of our energy costs during that period compared to an over-collection of energy costs in the first quarter of 2002.

Operations and maintenance expense increased in the first quarter of 2003 by $6.7 million or 76.9%, as compared to the first quarter of 2002, due to costs incurred for the replacement of the reactor vessel heads at North Anna. The increased operations and maintenance expense was partially offset by the amortization of a regulatory liability as the result of the collection of additional amounts from our member distribution cooperatives in 2002 to help mitigate the cost in 2003 of the North Anna reactor vessel heads replacement.

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Other Items

Other Income/(Expense), net. The major components of our other income/(expense), net for the three months ended March 31, 2003 and 2002 were as follows:

Other income/(expense), net decreased in the first quarter of 2003 by $0.8 million, or 102.5%, as compared to the first quarter of 2002 mainly due to a reduction in gains on the sale of investments and the reimbursement in 2002 of previously incurred development costs related to our Rock Springs facility.

Investment Income. Investment income decreased $1.3 million, or 90.0%, in the first quarter of 2003 as compared to the same period in 2002 as a result of a significant decrease in our average balance of investments-other, and cash and cash equivalents, and in the interest rates earned on our investments and cash equivalents. These investments were used during 2002 and 2003 to continue funding the development and construction of our three combustion turbine facilities.

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

The major components of interest charges, net for the three months ended March 31, 2003 and 2002, were as follows:

Interest charges, net decreased in 2003 by $2.1 million, or 19.7%, as compared to the same period in 2002 due to an increase in the amount of capitalized interest relating to the development and construction of our three combustion turbine facilities. We began capitalizing interest on the Rock Springs and Louisa facilities in October 2001 and January 2002, respectively. Capitalized interest is computed monthly using an interest rate, which reflects our embedded cost of indebtedness, multiplied by our investment in projects under construction. Other interest increased due to an amount in dispute with PSE&G. See “Legal Proceedings” in Part II, Item 1.

Net Margin. Our net margin, which is a function of our interest charges, increased $0.2 million, or 8.0%, in the first quarter of 2003 as compared to the same period in 2002, due to the $1.0 million increase in our total interest charges.

Financial Condition

        The principal changes in our financial condition from December 31, 2002 to March 31, 2003, were caused by increases in construction work in progress, changes in deferred energy, and adjustments related to the adoption of SFAS No. 143. The increase in construction work in progress of $37.9 million, or 10.2%, is primarily due to payments for construction of our three combustion turbine facilities and the purchase of pollution control facilities at Clover. Our deferred energy balance represents the net under- or over-collection of energy costs as of the end of the reporting period. These amounts are charged to or recovered from our member

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distribution cooperatives in subsequent periods. The deferred energy balance changed from a $3.0 million liability (over-collection of costs) at December 31, 2002, to a $13.2 million asset (under-collection of costs) at March 31, 2003 and is a result of higher energy costs incurred in the first quarter of 2003 that were not recovered through our base energy rate and fuel factor adjustment.

Liquidity and Capital Resources

Operations. Historically, our operating cash flows have been sufficient to meet our short- and long-term capital expenditures related to our generating facilities, our debt service requirements, and our ordinary business operations. Our cash needs exceeded our cash flows from operating activities by $2.6 million during the first quarter of 2003. Our operating activities provided excess cash flow of $36.8 million during the first quarter of 2002. Operating activities for the first three months of 2003 were affected primarily by changes between periods in our deferred energy account and the funding of construction and development expenses related to our combustion turbine facilities.

Financing Activities. In addition to liquidity from our operating activities, we maintain committed lines of credit to cover short-term funding needs. Currently, we have short-term committed variable rate lines of credit in an aggregate amount of $235.0 million. Of this amount, $95.0 million is available for general working capital purposes and $140.0 million is available for capital expenditures related to our generating facilities, including the development and construction of our three combustion turbine facilities.

At March 31, 2003, and 2002, we had no short-term borrowings or letters of credit outstanding under any of these arrangements. We expect the working capital lines of credit to be renewed as they expire. We expect the construction-related lines of credit to be renewed until no longer necessary for the development and construction of the combustion turbine facilities.

To fully participate in power-related markets, TEC Trading will be required to maintain credit support sufficient to meet delivery and payment obligations associated with power and natural gas trades. To assist TEC Trading in providing this credit support, we have agreed to guarantee up to $42.5 million of TEC Trading’s delivery and payment obligations associated with its power trades. At March 31, 2003, we had guaranteed $0.5 million of obligations of TEC Trading and we guaranteed an additional $2.0 million in April 2003, for a total of $2.5 million.

Investing Activities. Investing activities in the first quarter of 2003 consisted primarily of expenditures for our three combustion turbine facilities and additions to investments.

Competition and Changing Regulations

All of the customers of our Delaware and Maryland member distribution cooperatives, and of Northern Virginia Electric Cooperative and Rappahannock Electric Cooperative in Virginia, were free to choose an alternative power supplier as of March 31, 2003. Additionally, as of April 1, 2003, the customers of our Shenandoah Valley Electric Cooperative in Virginia, are now free to choose an alternative power supplier. These five member distribution cooperatives accounted for 75.6% of our capacity requirements in 2002. As of May 9, 2003, none of the customers of these member distribution cooperatives had chosen an alternative power supplier and no alternative power suppliers were registered to provide power to customers of our member distribution cooperatives.

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ITEM 3. QUANTITATIVE AND QUALITATIVE

DISCLOSURES ABOUT MARKET RISK

No material changes occurred in our exposure to market risk during the first quarter of 2003.

ITEM 4. CONTROLS AND PROCEDURES

(a) Evaluation of disclosure controls and procedures.

Our management, including the President and Chief Executive Officer, and Senior Vice President Accounting and Finance, the Chief Financial Officer, conducted an evaluation of the effectiveness of our disclosure controls and procedures as defined in Rules 13a-14(c) and 15d-14(c) under the Securities Exchange Act of 1934 within 90 days of this report. Based upon that evaluation, the President and Chief Executive Officer, and Senior Vice President Accounting and Finance, the Chief Financial Officer concluded that our disclosure controls and procedures are effective in ensuring that all material information required to be filed in this report has been made known to them in a timely matter. We have established a Disclosure Assessment Committee comprised of members from senior and middle management to assist in this evaluation.

(b) Changes in Internal Controls.

There have been no significant changes in our internal controls or in other factors that could significantly affect such controls.

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PART II. OTHER INFORMATION

ITEM 1. LEGAL PROCEEDINGS

No material developments have occurred in our legal proceedings with PSE&G and Enron Power Marketing, Inc. since the filing of our Annual Report on Form 10-K for the fiscal year ended December 31, 2002. Other than certain legal proceedings arising out of the ordinary course of business, which management believes will not have a material adverse impact on our results of operations or financial condition, there is no other litigation pending or threatened against us.

ITEM 5. OTHER INFORMATION

We expect to receive all necessary local building permits to begin construction of our Marsh Run facility in mid-2003 and we expect that the facility will be available for commercial operation in the second quarter of 2004.

ITEM 6. EXHIBITS AND REPORTS ON FORM 8-K

99.1 Certification of Jackson E. Reasor

99.2 Certification of Daniel M. Walker

The Registrant filed no reports on Form 8-K during the quarter ended March 31, 2003.

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SIGNATURE

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

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OLD DOMINION ELECTRIC COOPERATIVE

CERTIFICATIONS

I, Jackson E. Reasor, certify that:

Date: May 15, 2003

        /s/     JACKSON E. REASOR            

                                Jackson E. Reasor

                President and Chief Executive Officer

                        (Principal Executive Officer)

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CERTIFICATIONS

I, Daniel M. Walker, certify that:

Date: May 15, 2003

        /s/    DANIEL M. WALKER                

                                Daniel M. Walker

            Senior Vice President Accounting and Finance

              (Principal Financial and Accounting Officer)

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EXHIBIT INDEX

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