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SECURITIES AND EXCHANGE COMMISSION
Washington D.C. 20549

FORM 10-Q

(Mark One)

For the quarterly period ended September 30, 2002

or

For the transition period from __________ to __________

Commission File No. 33-46795

OLD DOMINION ELECTRIC COOPERATIVE
(Exact Name of Registrant as Specified in Its Charter)

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.

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

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OLD DOMINION ELECTRIC COOPERATIVE

CONTENTS

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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)

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

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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

          The preparation of our financial statements in conformity with generally accepted accounting principles requires that our management make estimates and assumptions that affect the amounts reported in our financial statements.  We base these estimates and assumptions on information available as of the date of the financial statements and they are not necessarily indicative of the results to be expected for the year.  We consider the following accounting policies to be critical accounting policies due to the estimation involved in each.

          Accounting for Rate Regulation.  We are a rate regulated entity and as such are subject to the accounting requirements of SFAS No. 71, “Accounting for Certain Types of Regulation.”   In accordance with SFAS No. 71, certain expenses and revenues normally reflected in income are deferred on the balance sheet and are recognized in income consistent with their recovery in rates.  We have deferred certain expenses and revenues on our balance sheet based on rate action by our board of directors and approval by the Federal Energy Regulatory Commission (“FERC”), which we are recognizing in income concurrent with their recovery in rates. 

          Margin Stabilization Plan.  We have a Margin Stabilization Plan that allows us to review our actual demand-related costs of service and demand revenue as of year end and adjust revenues from our member distribution cooperatives to meet our financial coverage requirements and accumulate additional equity as required by our board of directors. Our formulary rate allows us to recover and refund amounts under the Margin Stabilization Plan. We record all adjustments, whether increases or decreases, in the year affected and allocate any adjustments to our member distribution cooperatives based on power sales during that year.  We collect these increases from our member distribution cooperatives, or offset decreases against amounts owed by our member distribution cooperatives to us, in the succeeding year.  Each quarter we adjust revenues and accounts payable–members, or accounts receivable–members, as appropriate, to reflect these adjustments.

          Accounting for Decommissioning Costs.  We accrue decommissioning costs over the expected service life of the North Anna Nuclear Power Station, a two unit nuclear power facility in which we own an 11.6% undivided interest (“North Anna”), and make periodic deposits in a trust fund, such that the fund balance will equal our estimated decommissioning cost of the contaminated portion of the plant at the time of decommissioning.  The present value of our future decommissioning cost is credited to the decommissioning reserve; increases are charged to our members through their rates.  Our portion of the estimated cost to decommission North Anna is $91.3 million, based on a site-specific study performed by Virginia Electric and Power Company (“Virginia Power”) in 1998.  Virginia Power expects to complete a new site-specific study and related cost estimate in the fourth quarter of 2002. 

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Results of Operations

Operating Revenues

          Sales to Members.  Our operating revenues are derived from power sales to our members and to non-members. Revenues from sales to members are primarily a function of our member distribution cooperatives’ consumers’ requirement for power and our formulary rate for sales of power to our member distribution cooperatives.  Our formulary rate has three components: a demand rate, a base energy rate, and a fuel factor adjustment rate.  Of these components, only the base energy rate is a fixed rate that requires FERC approval prior to adjustment.  The demand rate is designed to recover all of our capacity-related 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, capacity-related transmission costs, our margin requirement and additional amounts approved by our board of directors. The base energy rate recovers energy costs, which are primarily variable costs, such as nuclear and coal fuel costs and the energy costs under our power purchase contracts with third parties.  To the extent the base energy rate either over or under collects all of our energy costs, we refund or collect the difference through a fuel factor adjustment rate. 

          The formulary rate identifies the types of costs that we can collect through the demand rate and the fuel factor adjustment rate, but not the actual amounts to be collected.  The actual amounts to be collected under the formulary rate typically change each year.  Specifically, the demand rate is revised automatically to recover the costs contained in our annual budget and any revision made by the board of directors to our annual budget.  In addition, we review our energy costs at least every six months to determine whether the base energy rate and the fuel factor adjustment rate adequately recover our energy costs.  Because the base energy rate does not change, we revise the fuel factor adjustment rate accordingly to minimize any under- or over-collection of energy costs.  Our deferred energy balance represents the net accumulation of any previous under- or over-collections of energy costs.

          Our member revenues by formulary rate component, energy sales to our members, and average member cost per megawatt-hour (“MWh”) based on the blended cost of power from all of our power supply resources, for the three and nine months ended September 30, 2002 and 2001, were as follows:

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Changes in our member revenues attributed to growth in sales volume, changes in our average rates for demand and energy (including our base energy rate and fuel factor adjustment rate), and changes in margin stabilization for the three and nine months ended September 30, 2002 as compared to 2001, were as follows:

          We increased our fuel factor adjustment rate effective April 1, 2001, to recover energy costs that we previously incurred but did not fully recover under the base energy rate and existing fuel factor adjustment rate, and to recover future energy costs that we expected to be more expensive than we originally budgeted.  We reduced our fuel factor adjustment rate effective April 1, 2002, because the fuel factor adjustment rate, which had been in effect since April 1, 2001, had adequately 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.  The resulting fuel factor adjustment rate was still greater than the fuel factor adjustment rate that was in effect on January 1, 2001.

          Total member revenues for the third quarter of 2002 decreased $2.2 million, or 1.7%, as compared to the same period in 2001.  Increases in member revenues generated by 11.5% and 13.3% increases in demand and energy sales volumes, respectively, were offset by a 13.9% decrease in our average energy rate and a $10.1 million change in the amount we owe to our member distribution cooperatives under our Margin Stabilization Plan.  The increase in our demand and energy sales volumes was primarily the result of the unusually hot weather in the third quarter of 2002.  Our average energy rate (including our base energy rate and our fuel factor adjustment rate) for the three months ended September 30, 2002, decreased 13.9% over the same period in 2001 as a result of the April 1, 2002 reduction in our fuel factor adjustment rate.

          Total member revenues for the first nine months of 2002 increased $10.7 million, or 3.0%, as compared to the same period in 2001 primarily because of increases in demand and energy sales volumes of 11.1% and 6.1%, respectively, primarily caused by the unusually hot weather during the summer of 2002.  The increase in member revenues was partially offset by a 7.5% decrease in the average demand rate, which largely resulted from reductions in our demand rate effective April 1, 2001 and June 1, 2001 and a $5.9 million change in the amount owed to our member distribution cooperatives under our Margin Stabilization Plan.  Effective April 1, 2002, we increased our demand rate because of anticipated higher demand costs, primarily transmission costs.  The resulting demand rate was still lower than the demand rate that was in effect on January 1, 2001.

          The change in member revenues resulting from the change in margin stabilization indicates that actual demand costs incurred for the three- and nine-month periods ended September 30, 2002 were $10.1 million and $5.9 million, respectively, less than the amounts we collected through our demand rates in effect for those periods.  As discussed in “Critical Accounting Policies,” under our Margin Stabilization Plan, revenues are adjusted for any over- or under-collection of actual costs of service and to obtain margins sufficient to meet financial coverage requirements and accumulate additional equity as required by our board of directors.

          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”).  During the nine month period ended September 30, 2002, we sold excess purchased energy to PJM and excess energy from Clover to Virginia Power pursuant to the Clover operating agreement.  Sales to non-members increased $2.1 million and $0.6 million during the third quarter and first nine months of 2002, respectively, as compared to the same periods in 2001 primarily as a result of sales of excess energy to PJM.

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Operating Expenses

          Most of our operating expenses relate to supplying our member distribution cooperatives’ power requirements. We supply these requirements, consisting of capacity requirements and energy requirements, in two separate transmission and distribution control areas–a mainland Virginia control area and a PJM control area on the Delmarva Peninsula.  We serve these requirements through (1) our interests in electric generating facilities, including 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 and nine months ended September 30, 2002 and 2001, was as follows:

          Generation.  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 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 third quarter and first nine months of 2002 and 2001 as a percentage of the maximum dependable capacity rating of the facilities was as follows: