##### Table of Contents

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SECURITIES AND EXCHANGE COMMISSION


Washington, D.C. 20549





---




FORM 10-Q/A


(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. EmployerIncorporation 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.





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OLD DOMINION ELECTRIC COOPERATIVE





INDEX





Page NumberPART I.    Financial InformationItem 1.

Financial StatementsCondensed Consolidated Balance SheetsJune 30, 2002 (Unaudited) and December 31, 2001

3Condensed Consolidated Statements of Revenues, Expenses and Patronage Capital (Unaudited)Three and Six Months Ended June 30, 2002 and 2001

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

4Condensed Consolidated Statements of Cash Flows (Unaudited)Six Months Ended June 30, 2002 and 2001

5Notes to Condensed Consolidated Financial Statements

6Item 2.

Managements Discussion and Analysis of Financial Condition and Results of Operations

8PART II.    Other InformationItem 1.

Legal Proceedings

15Item 6.

Exhibits and Reports on Form 8-K

15Signature

16




2




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##### Table of Contents




OLD DOMINION ELECTRIC COOPERATIVE





PART I.    FINANCIAL INFORMATION





ITEM 1.    FINANCIAL STATEMENTS


CONDENSED CONSOLIDATED BALANCE SHEETS





June 30, 2002


December 31, 2001*(in thousands)ASSETS:


(unaudited)Electric Plant:In service

$
916,691


$
899,691Less accumulated depreciation


(353,113
)


(340,440
)563,578



559,251Nuclear fuel, at amortized cost


5,493



8,487Construction work in progress


205,660



127,270Net Electric Plant


774,731



695,008Investments:Nuclear decommissioning trust


59,989



59,700Lease deposits


138,822



137,265Other


141,724



159,083Total Investments


340,535



356,048Current Assets:Cash and cash equivalents


53,723



77,981Receivables


55,830



61,097Fuel, materials and supplies, at average cost


18,263



13,936Prepayments


1,813



1,783Deferred energy






18,244Total Current Assets


129,629



173,041Deferred Charges


22,446



32,053Total Assets

$
1,267,341


$
1,256,150CAPITALIZATION AND LIABILITIES:Capitalization:Patronage capital

$
230,580


$
225,538Accumulated other comprehensive income


(15,081
)


398Long-term debt


626,599



625,232Total Capitalization


842,098



851,168Current Liabilities:Long-term debt due within one year


39,927



39,927Accounts payable


59,914



59,525Accounts payablemembers


34,260



38,223Deferred energy


15,054



Accrued expenses


24,830



16,415Total Current Liabilities


173,985



154,090Deferred Credits and Other LiabilitiesDecommissioning reserve


59,989



59,700Obligations under long-term leases


141,762



140,291Other


49,507



50,901Total Deferred Credits and Other Liabilities


251,258



250,892Commitments 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.
|- |  | ----------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------



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##### Table of Contents




OLD DOMINION ELECTRIC COOPERATIVE





CONDENSED CONSOLIDATED STATEMENTS OF REVENUES,


EXPENSES AND PATRONAGE CAPITAL (UNAUDITED)





Three Months Ended June
30,


Six Months EndedJune 30,2002


2001


2002


2001(in thousands)Operating Revenues

$
113,426


$
111,933


$
245,673


$
234,221Operating Expenses:Fuel


12,269



14,046



25,865



27,753Purchased power


72,151



61,404



160,053



123,428Operations and maintenance


8,200



8,767



16,897



17,304Administrative and general


6,065



4,888



10,732



11,455Depreciation, amortization anddecommissioning


2,058



11,429



7,899



31,658Taxes other than income taxes


842



783



1,707



1,587Total Operating Expenses


101,585



101,317



223,153



213,185Operating Margin


11,841



10,616



22,520



21,036Other (Expense)/Income, net


(73
)


192



732



682Investment Income


552



700



2,006



1,467Interest Charges, net


(9,793
)


(9,568
)


(20,215
)


(19,289
)Net Margin


2,527



1,940



5,043



3,896Patronage CapitalBeginning of Period


228,053



226,554



225,537



224,598Payment of Capital Credits






(7,500
)






(7,500
)Patronage CapitalEnd of Period

$
230,580


$
220,994


$
230,580


$
220,994





OLD DOMINION ELECTRIC COOPERATIVE





CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (UNAUDITED)





Three Months Ended June 30,


Six Months Ended June
30,2002


2001


2002


2001(in thousands)Net Margin

$
2,527


$
1,940


$
5,043


$
3,896Other Comprehensive Income:Unrealized gain/(loss) on investments


32



(15
)


(494
)


898Cumulative effect of accounting changeon derivative contracts


(15,944
)






(15,944
)


Unrealized gain on derivative contracts


959







959



Comprehensive Income

$
(12,426
)

$
1,925


$
(10,436
)

$
4,794


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)





Six MonthsEnded June 30,2002


2001(in thousands)Operating Activities:Net Margin

$
5,043


$
3,896Adjustments to reconcile net margins to net cash provided by operating activities:Depreciation, amortization and decommissioning


11,701



30,358Other non-cash charges


4,866



4,051Amortization of lease obligations


4,938



4,729Interest on lease deposits


(4,844
)


(4,629
)Change in current assets


19,154



(4,498
)Change in current liabilities


19,895



18,786Deferred charges and credits


(5,899
)


(827
)Net Cash Provided by Operating Activities


54,854



51,866Financing 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
)


11,787Cash and Cash EquivalentsBeginning of Period


77,981



20,259Cash and Cash EquivalentsEnd of Period

$
53,723


$
32,046


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





|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




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##### Table of Contents

| | 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.
|-- |  | -----------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------



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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.    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




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##### Table of Contents




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:





Three Months EndedJune 30,

Six Months EndedJune 30,2002

2001

2002

2001Member Revenues (in thousands)Demand rate

$
50,174

$
45,498

$
104,908

$
106,097Base energy rate


40,614


37,343


83,940


81,449Fuel factor adjustment rate


21,563


29,158


55,344


43,693Total Member Revenues

$
112,351

$
111,999

$
244,192

$
231,239Sales (in MWh)


2,290,271


2,065,651


4,689,270


4,526,199Average Member Cost ($ per MWh)(1)

$
49.06

$
54.22

$
52.07

$
51.09


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| |  | (1) Our average member cost is based on the blended cost of power from all of our sources.
| |  | ------------------------------------------------------------------------------------------



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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:





Three Months


Six MonthsEnded June 30,


Ended June 30,2002 Compared to 2001


2002 Compared to 2001(in thousands)Change in member revenues due to change in:Demand sales volume

$
7,091


$
10,252Energy sales volume


6,098



4,844Total sales volume


13,189



15,096Demand rate


(2,415
)


(11,442
)Energy rate


(10,422
)


9,299Total rates


(12,837
)


(2,143
)Total change in member revenues

$
352


$
12,953





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 increased by an insignificant amount 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 $13.0 million, or 5.6%, 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 10.8% 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




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##### Table of Contents




Three Months Ended June 30,


Six Months Ended June 30,2002


2001


2002


2001(MWh)




(MWh)




(MWh)




(MWh)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

17.5Total generated

1,084,623

47.2


1,172,891

50.8


2,245,752

46.9


2,403,021

51.1Purchased:Virginia Area

678,991

29.5


596,587

25.9


1,416,424

29.6


1,169,411

24.9Delmarva Area

504,888

21.9


488,819

21.2


1,059,304

22.1


1,013,804

21.6Other

31,427

1.4


49,511

2.1


69,268

1.4


112,110

2.4Total purchased

1,215,306

52.8


1,134,917

49.2


2,544,996

53.1


2,295,325

48.9Total Available Energy

2,299,929

100.0
%

2,307,808

100.0
%

4,790,748

100.0
%

4,698,346

100.0
%





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


CloverThree Months Ended June
30,


Six Months Ended June
30,


Three Months Ended June
30,


Six Months Ended June
30,2002


2001


2002


2001


2002


2001


2002


2001Unit 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


83.8Combined

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




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##### Table of Contents




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





Three Months Ended June
30,

Six Months EndedJune 30,2002

2001

2002

2001(in thousands)Fuel

$
12,269

$
14,046

$
25,865

$
27,753Purchased power (including deferred energy)


72,151


61,404


160,053


123,428Operations and maintenance


8,200


8,767


16,897


17,304Administrative and general


6,065


4,888


10,732


11,455Depreciation, amortization and decommissioning


2,058


11,429


7,899


31,658Taxes, other than income taxes


842


783


1,707


1,587Total operating expenses

$
101,585

$
101,317

$
223,153

$
213,185





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 $0.6 million, or 30.4%, and $1.2 million, or 29.5%, 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.




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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 $126.3 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.




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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.




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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.




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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.





OLD DOMINION ELECTRIC COOPERATIVE RegistrantDate:    October 8, 2002



/s/    DANIEL M.
WALKERDaniel M. Walker Senior Vice President of Accounting and Finance (Chief Financial Officer)




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