<PAGE>



                       SECURITIES AND EXCHANGE COMMISSION
                             Washington, D.C. 20549
                                   -----------


                                    FORM 10-Q
(Mark One)

            X   QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE
           ---            SECURITIES EXCHANGE ACT OF 1934

                  For the quarterly period ended June 30, 2002

                                       or

               TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE
        ----                SECURITIES EXCHANGE ACT OF 1934

                        For the transition period from            to
                                                       ----------    ----------

                         Commission file number 33-46795


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



           VIRGINIA                                         23-7048405
  (State or Other Jurisdiction of                        (I.R.S. Employer
  Incorporation or Organization)                         Identification No.)

4201 Dominion Boulevard, Glen Allen, Virginia                 23060
(Address of Principal Executive Offices)                    (Zip Code)

                                   ----------

                                 (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       No  X

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


                                       1

<PAGE>

                        OLD DOMINION ELECTRIC COOPERATIVE

                                      INDEX
<TABLE>
<CAPTION>

                                                                                         Page
                                                                                        Number
                                                                                        ------
PART I. Financial Information
<S> <C>
Item 1.     Financial Statements

            Condensed Consolidated Balance Sheets - June 30, 2002 (Unaudited)
                 and December 31, 2001                                                     3

            Condensed Consolidated Statements of Revenues, Expenses and
                 Patronage Capital (Unaudited) - Three and Six Months Ended
                 June 30, 2002 and 2001                                                    4

            Condensed Consolidated Statements of Comprehensive Income (Unaudited) -
                 Three and Six Months Ended June 30, 2002 and 2001                         4

            Condensed Consolidated Statements of Cash Flows (Unaudited) - Six
                 Months Ended June 30, 2002 and 2001                                       5

            Notes to Condensed Consolidated Financial Statements                           6


Item 2.     Management's Discussion and Analysis of Financial Condition
                 and Results of Operations                                                 8


PART II. Other Information

Item 1.     Legal Proceedings                                                             15

Item 6.     Exhibits and Reports on Form 8-K                                              15

Signature                                                                                 16
</TABLE>


                                       2

<PAGE>


                        OLD DOMINION ELECTRIC COOPERATIVE
                          PART I. FINANCIAL INFORMATION

                          ITEM 1. FINANCIAL STATEMENTS
                      CONDENSED CONSOLIDATED BALANCE SHEETS


                                                     June 30,       December 31,
                                                      2002              2001*
                                                   -----------      ------------
                                                           (in thousands)
ASSETS:                                            (unaudited)
---------------------------------------------------
Electric Plant:
   In service                                       $  916,691       $  899,691
   Less accumulated depreciation                      (353,113)        (340,440)
                                                   -----------      -----------
                                                       563,578          559,251
   Nuclear fuel, at amortized cost                       5,493            8,487
   Construction work in progress                       205,660          127,270
                                                   -----------      -----------
     Net Electric Plant                                774,731          695,008
                                                   -----------      -----------
Investments:
   Nuclear decommissioning trust                        59,989           59,700
   Lease deposits                                      138,822          137,265
   Other                                               141,724          159,083
                                                   -----------      -----------
     Total Investments                                 340,535          356,048
                                                   -----------      -----------
Current Assets:
   Cash and cash equivalents                            53,723           77,981
   Receivables                                          55,830           61,097
   Fuel, materials and supplies, at average cost        18,263           13,936
   Prepayments                                           1,813            1,783
   Deferred energy                                           -           18,244
                                                   -----------      -----------
     Total Current Assets                              129,629          173,041
                                                   -----------      -----------
Deferred Charges                                        22,446           32,053
                                                   -----------      -----------
     Total Assets                                   $1,267,341       $1,256,150
                                                    ==========       ==========

CAPITALIZATION AND LIABILITIES:
---------------------------------------------------
Capitalization:
   Patronage capital                                $  230,142       $  225,538
   Accumulated other comprehensive income              (15,081)             398
   Long-term debt                                      626,599          625,232
                                                   -----------      -----------
     Total Capitalization                              841,660          851,168
                                                   -----------      -----------
Current Liabilities:
   Long-term debt due within one year                   39,927           39,927
   Accounts payable                                     59,914           59,525
   Accounts payable - members                           34,701           38,223
   Deferred energy                                      15,054                -
   Accrued expenses                                     24,827           16,415
                                                   -----------      -----------
     Total Current Liabilities                         174,423          154,090
                                                   -----------      -----------
Deferred Credits and Other Liabilities
   Decommissioning reserve                              59,989           59,700
   Obligations under long-term leases                  141,762          140,291
   Other                                                49,507           50,901
                                                   -----------      -----------
     Total Deferred Credits and Other Liabilities      251,258          250,892
                                                   -----------      -----------
Commitments and Contingencies                                -                -
                                                   -----------      -----------
     Total Capitalization and Liabilities           $1,267,341       $1,256,150
                                                   ===========      ===========

-------------------------------------------------------------------------------


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

*   The Condensed Consolidated Balance Sheet at December 31, 2001, has been
    taken from the audited financial statements at that date, but does not
    include all disclosures required by generally accepted accounting
    principles.

                                       3

<PAGE>


                        OLD DOMINION ELECTRIC COOPERATIVE

                 CONDENSED CONSOLIDATED STATEMENTS OF REVENUES,
                   EXPENSES AND PATRONAGE CAPITAL (UNAUDITED)

                                       Three Months Ended     Six Months Ended
                                            June 30,              June 30,
                                       -------------------   ------------------
                                         2002       2001       2002      2001
                                       --------   --------   --------  --------
                                                   (in thousands)

Operating Revenues                     $112,985   $111,933   $245,232  $234,221
                                       --------   --------   --------  --------

Operating Expenses:
   Fuel                                  12,269     14,046     25,865    27,753
   Purchased power                       72,151     61,404    160,053   123,428
   Operations and maintenance             8,197      8,767     16,894    17,304
   Administrative and general             6,065      4,888     10,732    11,455
   Depreciation, amortization and
       decommissioning                    2,058     11,429      7,899    31,658
   Taxes other than income taxes            842       783       1,707     1,587
                                       --------   --------   --------  --------
     Total Operating Expenses           101,582    101,317    223,150   213,185
                                       --------   --------   --------  --------
          Operating Margin               11,403     10,616     22,082    21,036
Other (Expense)/Income, net                 (73)       192        732       682
Investment Income                           552        700      2,006     1,467
Interest Charges, net                    (9,793)    (9,568)   (20,215)  (19,289)
                                       --------   --------   --------  --------
     Net Margin                           2,089      1,940      4,605     3,896
Patronage Capital - Beginning of Period 228,053    226,554    225,537   224,598
Payment of Capital Credits                    -     (7,500)         -    (7,500)
                                       --------   --------   --------  --------
Patronage Capital - End of Period      $230,142   $220,994   $230,142  $220,994
                                       ========   ========   ========  ========

--------------------------------------------------------------------------------



                        OLD DOMINION ELECTRIC COOPERATIVE

      CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (UNAUDITED)


                                          Three Months Ended   Six Months Ended
                                                  June 30,          June 30,
                                           -----------------  ------------------
                                              2002      2001     2002       2001
                                           --------   ------  ---------   ------
                                                       (in thousands)

Net Margin                                 $  2,089   $1,940   $  4,605   $3,896
Other Comprehensive Income:
   Unrealized gain/(loss) on investments         32      (15)      (494)     898
   Cumulative effect of accounting change
     on derivative contracts                (15,944)       -    (15,944)       -
   Unrealized gain on derivative contracts      959        -        959        -
                                           --------   ------   --------   ------
Comprehensive Income                       $(12,864)  $1,925   $(10,874)  $4,794
                                           ========   ======   ========   ======

------------------------------------------------------------------------

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


                                        4

<PAGE>


                        OLD DOMINION ELECTRIC COOPERATIVE

           CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOW (UNAUDITED)

                                                              Six Months Ended
                                                                   June 30,
                                                             ------------------
                                                               2002      2001
                                                             -------   --------
                                                                (in thousands)
Operating Activities:
   Net Margin                                                $ 4,605   $ 3,896
   Adjustments to reconcile net margins to net cash provided
   by operating activities:
     Depreciation, amortization and decommissioning           11,701    30,358
     Other non-cash charges                                    4,866     4,051
     Amortization of lease obligations                         4,938     4,729
     Interest on lease deposits                               (4,844)   (4,629)
     Change in current assets                                 19,154    (4,498)
     Change in current liabilities                            20,333    18,786
     Deferred charges and credits                             (5,899)     (827)
                                                             -------   -------
        Net Cash Provided by Operating Activities             54,854    51,866
                                                             -------   -------

Financing Activities:
   Principal payments and purchases of long-term debt              -    (3,572)
   Obligations under long-term leases                           (181)     (180)
                                                             -------   -------
        Net Cash Used for Financing Activities                  (181)   (3,752)
                                                             -------   -------

Investing Activities:
   Lease deposits and other investments                       16,865    (1,811)
   Electric plant additions                                  (95,456)  (34,176)
   Decommissioning fund deposits                                (340)     (340)
                                                             -------   -------
        Net Cash Used for Investing Activities               (78,931)  (36,327)
                                                             -------   -------
        Net Change in Cash and Cash Equivalents              (24,258)   11,787
Cash and Cash Equivalents - Beginning of Period               77,981    20,259
                                                             -------   -------
Cash and Cash Equivalents - End of Period                    $53,723   $32,046
                                                             =======   =======

------------------------------------------------------------------------------

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

                                       5

<PAGE>

                        OLD DOMINION ELECTRIC COOPERATIVE

              NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

1.   In the opinion of our management, the accompanying unaudited condensed
     consolidated financial statements contain all adjustments, which include
     only normal recurring adjustments, necessary for a fair statement of our
     consolidated financial position as of June 30, 2002, and our consolidated
     results of operations, comprehensive income, and cash flows for the three
     and six months ended June 30, 2002 and 2001. The consolidated results of
     operations for the three and six months ended June 30, 2002, are not
     necessarily indicative of the results to be expected for the entire year.
     These financial statements should be read in conjunction with the financial
     statements and notes thereto included in our 2001 Annual Report on Form
     10-K filed with the Securities and Exchange Commission.

2.   We ceased recording accelerated depreciation on our generation assets under
     our Strategic Plan Initiative effective June 1, 2001. At June 30, 2001,
     depreciation, amortization and decommissioning included $18.5 million of
     accelerated depreciation. Also effective June 1, 2001, our board of
     directors authorized a revenue deferral plan for the period June 1, 2001
     through December 31, 2002. Under this plan, we collected $11.4 million
     through the demand component of the formulary rate we charged our members
     in 2001, which we are using to partially offset the increases in the demand
     component of the formulary rate beginning April 1, 2002. At June 30, 2002,
     the remaining balance in deferred revenue was $7.6 million.

3.   In June 2001, the Financial Accounting Standards Board issued Statement of
     Financial Accounting Standards ("SFAS") No. 143 "Accounting for Asset
     Retirement Obligations" which will be effective for us beginning January 1,
     2003. The standard requires entities to record at fair value an asset
     retirement obligation in the period in which it is incurred. When the
     liability is initially recorded, the entity capitalizes the costs by
     increasing the carrying amount of the related long-lived asset. Over time,
     the liability is accreted to its present value each period, and the
     capitalized asset is depreciated over the useful life of the long-lived
     asset. We do not believe that this statement will have a material effect on
     results of our operations due to our ability to recover decommissioning
     costs through rate adjustments.

4.   In December 2001, certain interpretative guidance related to SFAS No. 133,
     "Accounting for Derivative Instruments and Hedging Activities," was
     revised. This revised interpretive guidance became effective for us
     beginning April 1, 2002. Under the new guidance, certain energy option
     contracts, which previously qualified for the normal purchases and sales
     exception under SFAS No. 133, were required to be recorded at market value.

     We entered into the energy option contracts to hedge the variability of
     cash flows associated with changes in the market prices of energy. At June
     30, 2002, we have recorded a net unrealized loss in accumulated other
     comprehensive income of approximately $15.0 million associated with the
     effective portion of the change in fair value of the option contracts
     designated as cash flow hedges. There was no hedge ineffectiveness during
     the three and six month periods ended June 30, 2002.

     Based on the balance at June 30, 2002, we expect to reclassify
     approximately $15.0 million of net unrealized losses from accumulated other
     comprehensive income to operating expense over the period of the contracts.
     The actual amounts that will be reclassified to operating expense will vary
     from this amount as a result of changes in market prices.

     At June 30, 2002, accrued expenses include an $8.4 million derivative
     liability relative to these contracts.

5.   On May 9, 2001, we entered into a Master Power Purchase and Sales Agreement
     with Enron Power Marketing, Inc. ("EPMI"). Pursuant to transactions entered
     into under this agreement, EPMI was obligated to deliver power to us
     through December 31, 2003. Following its filing for bankruptcy protection
     on December 2, 2001, EPMI ceased scheduling deliveries of power under the
     agreement beginning December 15, 2001.  We then terminated the agreement.
     While the terms of the agreement call for us to make a termination payment
     to EPMI, we have disputed

                                       6

<PAGE>

     that obligation due to fraudulent behavior on EPMI's part. If it is
     ultimately determined that we owe any amounts to EPMI, 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. We are currently in discussions with EPMI.

6.   TEC Trading, Inc. ("TEC Trading"), a corporation owned by our member
     distribution cooperatives, was formed for the primary purposes of
     purchasing power from us to sell in the market, acquiring natural gas to
     supply our three combustion turbine facilities, and taking advantage of
     other power-related trading opportunities in the market, which will help
     lower our member distribution cooperatives' costs. 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 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 June 30, 2002, we
     had a $0.5 million guarantee outstanding.

                                       7

<PAGE>

                        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. Our board of directors established a Margin
Stabilization Plan in 1984. This plan allows us to review our actual cost of
service and power sales as of year end and adjust revenues from our member
distribution cooperatives to meet our financial coverage requirements. 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.

     Accounting for Decommissioning Costs. We accrue decommissioning costs over
the expected service life of the North Anna Power Station ("North Anna") and
make periodic deposits in a trust fund, such that the fund balance will equal
our estimated decommissioning cost 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 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 cost estimate in 2002.

                                       8

<PAGE>

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 a function of
our member distribution cooperatives' consumers' requirement for power and our
formulary rate for sales of power to our member distribution cooperatives. The
formulary rate has three components: a demand rate, a base energy rate, and a
fuel factor adjustment rate. 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, and our margin requirement. 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. Of these components, only the base energy rate is a fixed rate that
requires FERC approval prior to adjustment.

     The formulary rate includes a fixed base energy rate and 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") for the three and six
months ended June 30, 2002 and 2001, were as follows:

<TABLE>
<CAPTION>

                                            Three Months Ended        Six Months Ended
                                                 June 30,                  June 30,
                                          ---------------------    ----------------------
                                             2002        2001         2002        2001
                                          --------    ---------    ----------  ----------
<S> <C>
     Member Revenues (in thousands)
        Demand rate                       $ 49,733     $ 45,498     $104,467     $106,097
        Base energy rate                    40,614       37,343       83,940       81,449
        Fuel factor adjustment rate         21,563       29,158       55,344       43,693
                                          --------     --------     --------     --------
              Total Member Revenues       $111,910     $111,999     $243,751     $231,239
                                          ========     ========     ========     ========

     Sales (in MWh)                      2,290,271    2,065,651    4,689,270    4,526,199
     Average Member Cost ($ per MWh)(1)     $48.86       $54.22       $51.98       $51.09
</TABLE>
     --------------------
     (1) Our average member cost is based on the blended cost of power from all
         of our sources.

                                        9

<PAGE>

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

<TABLE>
<CAPTION>

                                                     Three Months              Six Months
                                                     Ended June 30,          Ended June 30,
                                                 2002 Compared to 2001    2002 Compared to 2001
                                                 ---------------------   ----------------------
                                                                 (in thousands)
<S> <C>
    Change in member revenues due to change in:
      Demand sales volume                             $  7,029                $10,209
      Energy sales volume                                6,098                  4,844
                                                      --------                -------
           Total sales volume                           13,127                 15,053
                                                      --------                -------

      Demand rate                                       (2,794)               (11,839)
      Energy rate                                      (10,422)                 9,298
                                                      --------                -------
            Total rates                                (13,216)                (2,541)
                                                      --------                -------

               Total change in member revenues        $    (89)               $12,512
                                                      ========                =======
</TABLE>


     We increased our fuel factor adjustment rate 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 second quarter of 2002 were unchanged from
the same period in 2001. Increases in member revenues generated by 16.5% and
10.9% increases in demand and energy sales volumes, respectively, were offset by
a decrease in our average energy rate. Our average energy rate (including our
base energy rate and our fuel factor adjustment rate) for the three months ended
June 30, 2002, decreased 15.7% over the same period in 2001 as a result of a
reduction in our fuel factor adjustment rate.

     Total member revenues for the first six months of 2002 increased $12.5
million, or 5.4%, as compared to the same period in 2001 primarily because of an
increase in demand and energy sales and a higher average fuel factor adjustment
rate. The increase in member revenues was partially offset by a 6.1% decrease in
the average demand rate, which largely resulted from reductions in our demand
rate April 1, 2001 and June 1, 2001. Effective April 1, 2002, we increased our
demand rate because of anticipated higher demand costs, primarily transmission
costs.

     Sales to Non-Members. Sales to non-members represent sales of excess
purchased energy and sales of excess generated energy from the Clover Power
Station ("Clover"). Excess purchased energy is sold to Pennsylvania-New
Jersey-Maryland Interconnection, LLC ("PJM") under its rates for providing
energy imbalance service. Excess energy from Clover is sold to Virginia Power
pursuant to the Clover Operating Agreement. Non-member revenues increased $1.1
million in the second quarter of 2002 and decreased $1.5 million in the first
half of 2002 as compared to the same periods in 2001 primarily as a result of
sales of energy to PJM.

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 and an 11.6% interest in North Anna, 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 six months ended
June 30, 2002 and 2001, was as follows:

                                       10

<PAGE>


<TABLE>
<CAPTION>


                                       Three Months Ended                     Six Months Ended
                                           June 30,                              June 30,
                           --------------------------------------    ------------------------------------
                              2002                  2001               2002                 2001
                           -----------------    -----------------    ----------------    ----------------
                              (MWh)               (MWh)               (MWh)                (MWh)
<S> <C>
   Generated:
     Clover                  615,293    26.8%     743,644    32.2%   1,310,425   27.4%   1,579,313   33.6%
     North Anna              469,330    20.4      429,247    18.6      935,327   19.5      823,708   17.5
                           ---------   -----    ---------   -----    ---------  -----    ---------   ----
        Total generated    1,084,623    47.2    1,172,891    50.8    2,245,752   46.9    2,403,021   51.1
                           ---------   -----    ---------   -----    ---------  -----    ---------   ----
   Purchased:
     Virginia Area           678,991    29.5      596,587    25.9    1,416,424   29.6    1,169,411   24.9
     Delmarva Area           504,888    21.9      488,819    21.2    1,059,304   22.1    1,013,804   21.6
     Other                    31,427     1.4       49,511     2.1       69,268    1.4      112,110    2.4
                           ---------   -----    ---------   -----    ---------  -----    ---------  -----
        Total purchased    1,215,306    52.8    1,134,917    49.2    2,544,996   53.1    2,295,325   48.9
                           ---------   -----    ---------   -----    ---------  -----    ---------  -----
   Total Available Energy  2,299,929   100.0%   2,307,808   100.0%   4,790,748  100.0%   4,698,346  100.0%
                           =========   =====    =========   =====    =========  =====    =========  =====
</TABLE>

     Generated. 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
second quarter and first six months of 2002 and 2001 as a percentage of the
maximum dependable capacity rating of the facilities was as follows:

                            North Anna                          Clover
                ------------------------------     ----------------------------
                    Three             Six              Three          Six
                 Months Ended     Months Ended      Months Ended   Months Ended
                  June 30,           June 30,         June 30,        June 30,
                -------------   -------------     --------------  -------------
                 2002    2001    2002    2001     2002     2001   2002     2001
                -----   -----   -----   -----     ----     ----   ----     ----

     Unit 1     101.0%  100.6%  101.1%  100.8%    52.8%    87.5%  56.6%    83.0%
     Unit 2     100.2    86.9   100.4    76.7     75.0     71.6   81.6     83.8
     Combined   100.6    93.8   100.8    88.8     63.9     79.6   69.1     83.4

     North Anna. There were no maintenance outages at either of the North Anna
units during the first six months of 2002. During the first six months of 2001,
North Anna Unit 2 underwent a 30-day scheduled refueling outage. Unit 1 was not
off-line during the first six months of 2001.

     Clover. Clover Unit 1 was removed from service on March 1, 2002, for a
scheduled maintenance outage and was returned to service on May 2, 2002. The
unit also experienced minor unscheduled outages during the first half of 2002.
On February 16, 2002, the load on Clover Unit 2 was reduced to 125 MW due to a
forced draft fan motor failure. The unit was returned to full load operations on
March 2, 2002. Clover Unit 2 was removed from service April 20, 2002, for a
scheduled maintenance outage and was returned to service on May 3, 2002. During
the first six months of 2001, Clover Unit 1 was off-line 13 days and Clover Unit
2 was off-line 15 days for scheduled maintenance outages.

     Purchased. Load requirements and market forces influence the structure of
our new power supply contracts. Within PJM, our contracts reflect the need to
have capacity (either owned generation facilities or rights to the capacity of a
generating facility under power contracts) 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 Virginia,
capacity and energy requirements are provided principally by Virginia Power,
American Electric Power - Virginia, and Allegheny Power Resources.

                                       11

<PAGE>

     The major components of our operating expenses for the three and six months
ended June 30, 2002 and 2001, were as follows:

<TABLE>
<CAPTION>


                                                        Three Months Ended       Six Months Ended
                                                             June 30,               June 30,
                                                      ---------------------     -------------------
                                                        2002         2001         2002       2001
                                                      --------    --------      --------   --------
                                                                      (in thousands)
<S> <C>
     Fuel                                             $ 12,269    $ 14,046      $ 25,865   $ 27,753
     Purchased power (including deferred energy)        72,151      61,404       160,053    123,428
     Operations and maintenance                          8,197       8,767        16,894     17,304
     Administrative and general                          6,065       4,888        10,732     11,455
     Depreciation, amortization and decommissioning      2,058      11,429         7,899     31,658
     Taxes, other than income taxes                        842         783         1,707      1,587
                                                      --------    --------      --------   --------
        Total operating expenses                      $101,582    $101,317      $223,150   $213,185
                                                      ========    ========      ========   ========
</TABLE>

     Aggregate operating expenses for the second quarter and first six months of
2002 increased $0.3 million, or 0.3%, and $10.0 million, or 4.7%, respectively,
over the same periods in 2001 primarily because of an increase in purchased
power expenses. The cost of purchased power during the second quarter and first
half of 2002, excluding deferred energy, decreased $27.1 million, or 35.2%, and
$2.4 million, or 1.9%, respectively, over the same periods in 2001 because of a
decrease in the average cost of demand and energy purchased. However, as a
result of changes in the amount of deferred energy expensed as a component of
purchased power, our total purchased power expenses rose 17.5% and 29.7% in the
second quarter and first six months of 2002, respectively, as compared to the
same periods in 2001. The amount of deferred energy expensed through purchased
power is a function of our fuel factor adjustment rate and the cost of energy
purchased. The increase in purchased power was partially offset by a decrease in
depreciation, amortization and decommissioning expense because we stopped
recording accelerated depreciation in accordance with our Strategic Plan
Initiative effective June 1, 2001 and we began reversing the $11.4 million of
deferred revenue recorded in 2001 beginning April 1, 2002. At June 30, 2002, the
remaining deferred revenue balance was $7.6 million.

Other Items

     Investment Income. Investment income decreased $0.1 million, or 21.1%, and
$0.5 million, or 36.7%, in the second quarter and first half of 2002,
respectively, as compared to the same periods in 2001 because we liquidated
certain investments to fund construction expenses.

     Interest Charges, net. Net interest charges increased $0.2 million, or
2.4%, and $0.9 million, or 4.8%, in the second quarter and first six months of
2002 as compared to the same periods in 2001 because of interest on the $215.0
million of indebtedness issued in the third quarter of 2001, offset by interest
capitalized on our combustion turbine construction projects.

     Net Margin. Our net margin, which is a function of our interest charges and
our margin requirement, increased $0.1 million, or 7.7%, and $0.7 million, or
18.2%, in the second quarter and first six months of 2002 as compared to the
same periods in 2001, because our interest expense was higher due to our
issuance of indebtedness in 2001.

Financial Condition

     The principal changes in our financial condition from December 31, 2001 to
June 30, 2002, were caused by changes in construction work in progress, deferred
energy, and accrued expenses. The increase in construction work in progress of
$78.4 million, or 61.6%, is due to payments for construction of our three
combustion turbine facilities, which are being developed by our subsidiaries.
The change in deferred energy from an $18.2 million under collection of energy
costs to a $15.1 million over collection of energy costs resulted from
increasing our fuel factor adjustment rate. The increase in accrued expenses of
$8.4 million, or 51.2%, is due to the derivative liability of $8.4 million.

                                       12

<PAGE>

Liquidity and Capital Resources

     Operations. Historically, our operating cash flows have been sufficient to
meet our short- and long-term capital expenditures related to North Anna and
Clover, our debt service requirements, and our ordinary business operations. Our
operating activities provided cash flows of $54.9 million and $51.9 million for
the six month periods ended June 30, 2002 and 2001, respectively. Operating
activities in the first six months of 2002 were affected primarily by the
discontinuance of accelerated depreciation, changes in our fuel factor
adjustment rate, and changes between periods in non-cash working capital
accounts.

     Financing Activities. In October 2000, our subsidiaries submitted
applications to Rural Utilities Services ("RUS") for loan guarantees to finance
the entire cost of our three combustion turbine facilities currently under
development or construction. However, in July 2002, RUS determined that it would
not be able to approve our loan guarantee requests and advance funds before
2003. Because we estimate that additional funds will be needed during the fourth
quarter of 2002 to finance the development and construction of the combustion
turbine facilities, we withdrew our RUS applications and will pursue additional
financing through issuances of indebtedness under our indenture.

     If funding for the development or construction of the combustion turbine
facilities is needed prior to our next issuance of indebtedness under our
indenture, we will borrow funds under construction-related committed lines of
credit. These lines of credit totaled $115 million at June 30, 2002. Lines of
credit totaling $60 million expired during the second quarter of 2002 and were
subsequently renewed for additional one-year terms. One line of credit in the
amount of $55 million expired July 15, 2002. We are currently negotiating to
reinstate this line of credit in the amount of $50 million. A financial covenant
in our indenture limits our short-term indebtedness to the greater of $100
million and 15% of our total long-term debt and equities. As of June 30, 2002,
this covenant would have limited the aggregate amount we could have drawn under
all our lines of credit, which include an additional $95 million of general
working capital lines of credit, to approximately $128.6 million.

     Investing Activities. Investing activities in the second quarter of 2002
consisted primarily of expenditures for our three combustion turbine facilities
and a reduction in investments due to liquidating investments to fund
construction expenses.

Other Matters

     On May 9, 2001, we entered into a Master Power Purchase and Sales Agreement
with Enron Power Marketing, Inc. ("EPMI"). Pursuant to transactions entered into
under this agreement, EPMI was obligated to deliver power to us through December
31, 2003. Following its filing for bankruptcy protection on December 2, 2001,
EPMI ceased scheduling deliveries of power under the agreement beginning
December 15, 2001. We then terminated the agreement. While the terms of the
agreement call for us to make a termination payment to EPMI, we have disputed
that obligation due to fraudulent behavior on EPMI's part. If it is ultimately
determined that we owe any amounts to EPMI, 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. We are currently
in discussions with EPMI.

     During an inspection at North Anna, Virginia Power determined that the
reactor vessel heads on North Anna Units 1 and 2 need to be replaced. Virginia
Power plans to replace the heads in 2004 at an estimated cost to us of $9.5
million.

     Virginia Power plans to upgrade the main turbines on North Anna Units 1 and
2 during scheduled refueling outages in 2005 and 2006. The estimated cost to us
of the turbine upgrade project is approximately $19.8 million. Our expected
share of the capacity increase from the upgrades is 14 MW.

     In June 2001, Virginia Power filed applications with the Nuclear Regulatory
Commission ("NRC") to renew the operating licenses for both North Anna units.
The NRC issued a draft environmental impact statement in June 2002 that found
that the continued operation of North Anna would have minimal impact on the
environment if the operating licenses were renewed. The environmental impact
statement was open for public comment until August 1, 2002.


                                       13

<PAGE>


     On July 17, 2002, we received a Certificate of Convenience and Public
Necessity ("CPCN") from the Virginia State Corporation Commission for our
combustion turbine facility located in Louisa County, Virginia. We expect to
begin construction on the facility in the third quarter of 2002 and to have the
units available for commercial operation in 2003.

     In 1998, the Environmental Protection Agency issued a rule addressing
regional transport of ground-level ozone through reductions in nitrogen oxides
("NOx"), commonly known as the NOx State Implementation Plan ("SIP") call. The
NOx SIP call requires emissions reductions to be implemented by May 1, 2004. We
and Virginia Power have evaluated our options for meeting the NOx SIP call as
applicable to Clover and have determined the best alternative to be installation
of additional NOx controls at Clover combined with the purchase of emissions
credits. The estimated cost of these activities to us is expected to be
approximately $8.5 million. We expect to be in full compliance with the NOx SIP
call by May 1, 2003.

     In October 1997, we filed with FERC a Section 206 complaint against PSE&G
asserting that our power purchase agreement with PSE&G should be modified to
conform to the restructuring of PJM. Under the PJM structure, we pay for the
transmission of PSE&G power through Conectiv's zonal rate. On May 14, 1998, FERC
ruled in our favor, ordering PSE&G to remove any transmission costs from its
rates for capacity and associated energy sold to us. PSE&G complied with the
FERC order by virtue of a compliance filing submitted to FERC on June 15, 1998.
Still, in 2000, PSE&G filed a petition for review of FERC's orders in the matter
with the United States Court of Appeals for the District of Columbia Circuit.

     On July 12, 2002, the Court of Appeals vacated FERC's May 14, 1998 ruling
and remanded the complaint to FERC for further consideration and proceedings. We
intend to vigorously pursue our original complaint with FERC in the remanded
proceeding. Until FERC takes action on the matter on remand, we are aware of no
requirement that we pay for the disputed transmission costs since June 15, 1998.
We estimate these costs to be approximately $23.4 million for the period from
May 14, 1998 through June 30, 2002, and approximately $37.2 million for the
period from May 14, 1998 through the end of the term of the agreement. We cannot
predict the outcome of this proceeding. Any amount we ultimately may be required
to pay to PSE&G with respect to this matter would be recovered from our members
through our formulary rate.

     In August 2002, Virginia Power formally notified the Nuclear Regulatory
Commission that, due to drought conditions in Virginia, a dropping water level
in Lake Anna could force Virginia Power to temporarily discontinue operations at
North Anna. The water level of Lake Anna, which supplies cooling water for North
Anna's generators, has fallen below 246 feet above sea level. If the lake falls
to 244 feet above sea level, the plant is required to temporarily discontinue
operations. However, Virginia Power is examining ways to modify its procedures
at North Anna to allow it to keep the reactors operating even if the lake falls
below 244 feet. If North Anna is required to temporarily discontinue operations,
Virginia Power is required to supply us with reserve capacity and energy under
the Interconnection and Operating Agreement.




                                       14

<PAGE>

                        OLD DOMINION ELECTRIC COOPERATIVE

                           PART II. OTHER INFORMATION


Item 1.    Legal Proceedings.

               Other than certain legal proceedings arising out of the ordinary
           course of business, which management believes will not have a
           material adverse impact on the results of operations or financial
           condition of Old Dominion, there is no other litigation pending or
           threatened against Old Dominion.

Item 6.    Exhibits and Reports on Form 8-K.

     (b)   Reports on Form 8-K.

             The Registrant filed no reports on Form 8-K during the quarter
           ended June 30, 2002.

                                       15

<PAGE>

                                    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.

                                   OLD DOMINION ELECTRIC COOPERATIVE
                                             Registrant

Date:     August 13, 2002                  /s/Daniel M. Walker
                                -----------------------------------------------
                                              Daniel M. Walker
                                Senior Vice President of Accounting and Finance
                                           (Chief Financial Officer)



                                       16

<PAGE>

                                  EXHIBIT INDEX


Exhibit                                                                    Page
Number                        Description of Exhibit                      Number
------                        ----------------------                      ------
99.1a     Certificate of Principal Executive Officer Pursuant to
          18.U.S.C. Section 1350

99.1b     Certificate of Principal Financial Officer Pursuant to
          18.U.S.C. Section 1350



                                       17