Old Dominion Electric Cooperative 10-K/A 2001 FY Annual report (amended)

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

Form 10-K/A

FOR ANNUAL AND TRANSITION REPORTS

PURSUANT TO SECTIONS 13 OR 15(d) OF THE

SECURITIES EXCHANGE ACT OF 1934

(Mark One)

x ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE

SECURITIES EXCHANGE ACT OF 1934

For the fiscal year ended December 31, 2001

¨ 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 incorporation or organization)	(I.R.S. employer 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)

Securities registered pursuant to Section 12(b) of the Act:

None

Securities registered pursuant to Section 12(g) of the Act:

None

Indicate by check mark whether the Registrant: (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the Registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days.  Yes  x  No  ¨

Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K is not contained herein, and will not be contained, to the best of Registrant’s knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this form 10-K.  x

State the aggregate market value of the voting and non-voting common equity held by non-affiliates of the Registrant. NONE

Indicate the number of shares outstanding of each of the Registrant’s classes of Common Stock, as of the latest practicable date. The Registrant is a membership corporation and has no authorized or outstanding equity securities.

DOCUMENTS INCORPORATED BY REFERENCE:

None

OLD DOMINION ELECTRIC COOPERATIVE

2001 ANNUAL REPORT ON FORM 10-K/A

Item Number		Page Number
	PART I
1.	Business	1
2.	Properties	19
3.	Legal Proceedings	19
4.	Submission of Matters to a Vote of Securities Holders	19
	PART II
5.	Market for Registrant’s Common Equity and Related Stockholder Matters	19
6.	Selected Financial Data	20
7.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	21
7A.	Quantitative and Qualitative Disclosures About Market Risk	41
8.	Financial Statements and Supplementary Data	43
9.	Changes in and Disagreements with Accountants on Accounting and Financial Disclosure	63
	PART III
10.	Directors and Executive Officers of Registrant	63
11.	Executive Compensation	65
12.	Security Ownership of Certain Beneficial Owners and Management	68
13.	Certain Relationships and Related Transactions	68
	PART IV
14.	Exhibits, Financial Statement Schedules, and Reports on Form 8-K	68
	Signatures	76

PART I

Item 1.    Business

OLD DOMINION ELECTRIC COOPERATIVE

General

Old Dominion Electric Cooperative was incorporated under the laws of the Commonwealth of Virginia in 1948 as a not-for-profit power supply cooperative. We were organized for the purpose of supplying the power our member distribution cooperatives require to serve their customers on a cost-effective basis. Through our member distribution cooperatives, we served more than 449,000 retail electric consumers (meters) representing a total population of approximately 1.1 million people in 2001. We provide this power pursuant to long-term, all-requirements wholesale power contracts. See “Member Distribution Cooperatives—Wholesale Power Contracts” below.

We supply our member distribution cooperatives’ power requirements, consisting of capacity requirements and energy requirements, through a portfolio of resources including generating facilities, power purchase contracts, and forward, short-term and spot market energy purchases. Our generating facilities consist of an 11.6% undivided ownership interest in the North Anna Nuclear Power Station (“North Anna”), a two-unit 1,842 megawatt (“MW”) (net capacity rating) nuclear power facility located in Louisa County, Virginia, and a 50% undivided ownership interest in the Clover Power Station (“Clover”), a two-unit 882 MW (net capacity rating) coal-fired electric generating facility located near Clover, Virginia.

Currently, we purchase a portion of the power we use to serve our member distribution cooperatives under contracts that expire before 2005. Since the late 1990s, we have restructured these power purchase contracts which increases our reliance on market purchases of energy to take advantage of our projections of relatively lower future market energy prices. See “Power Supply Resources—Other Power Supply Resources—Power Purchase Contracts” and “Management’s Discussion and Analysis of Financial Condition and Results of Operations—Future Issues—Reliance on Energy Purchases” in Item 7.

To meet our member distribution cooperatives’ future power requirements, we are developing three combustion turbine facilities, known as “Rock Springs,” “Louisa” and “Marsh Run,” through three separate, wholly-owned subsidiaries. We expect Rock Springs, Louisa and Marsh Run to supply 336, 504, and 672 MW of capacity, respectively, to us following completion. Rock Springs is being developed jointly with a third party. Our subsidiaries are seeking approvals and permits to begin construction of Louisa and Marsh Run. Construction of Rock Springs began in October 2001 and construction of Louisa and Marsh Run is expected to begin in 2002. See “Power Supply Resources—Combustion Turbine Facilities.”

We are owned entirely by our members, which are the primary purchasers of the power sold by us. We have two classes of members. Our Class A members are twelve customer-owned electric distribution cooperatives that sell electric service to customers in 70 counties throughout Virginia, Delaware, Maryland, and parts of West Virginia. Our sole Class B member is TEC Trading, Inc. (“TEC Trading”), formerly ODEC Power Trading, Inc. See “Member Distribution Cooperatives—TEC Trading.” TEC Trading is a corporation owned by our member distribution cooperatives. TEC Trading was formed to sell power in the market, manage the member distribution cooperatives’ exposure to changes in fuel prices and take advantage of other power-related trading opportunities which may become available in the market as necessary to serve our member distribution cooperatives’ power requirements.

Our member distribution cooperatives primarily serve suburban, rural and recreational areas. These areas predominantly reflect stable residential capacity requirements both in terms of power sales and number of customers. See “Members’ Service Territories and Customers.” Under recently enacted state restructuring legislation, between 2001 and 2004, nearly all customers of our member distribution cooperatives will be able to select their power suppliers. The member distribution cooperatives will continue to be the exclusive providers of distribution services and, at least initially, the default providers of power to their customers in their service territories. See “Management’s

Discussion and Analysis of Financial Condition and Results of Operations—Future Issues—Competition and Changing Regulations” In Item 7.

As a not-for-profit electric cooperative, we currently are exempt from federal income taxation under Section 501(c)(12) of the Internal Revenue Code of 1986, as amended. See “Management’s Discussion and Analysis of Financial Condition and Results of Operations—Factors Affecting Results—Tax Status” in Item 7 for further discussion of our tax status.

We are not a party to any collective bargaining agreement. We had 65 employees as of December 31, 2001, and believe that our relations with our employees are good.

Our principal executive offices are located in the Innsbrook Corporate Center, at 4201 Dominion Boulevard, Glen Allen, Virginia 23060-6721 (telephone 804-747-0592).

Cooperative Structure

In general, a cooperative is a business organization owned by its members, which are also either the cooperative’s wholesale or retail customers. Cooperatives are designed to give their members the opportunity to satisfy their collective needs in a particular area of business more effectively than if the members acted independently. As not-for-profit organizations, cooperatives are intended to provide services to their members on a cost-effective basis, in part by eliminating the need to produce profits or a return on equity in excess of required margins. Margins not distributed to members constitute patronage capital, a cooperative’s principal source of equity. Patronage capital is held for the account of the members without interest and returned when the board of directors of the cooperative deems it appropriate to do so.

We are a power supply cooperative. Electric distribution cooperatives form power supply cooperatives to acquire power supply resources, typically through the construction of generating facilities or the development of other power purchase arrangements, at a lower cost than if they were acquiring those resources alone.

Our Class A members are electric distribution cooperatives. Electric distribution cooperatives own and maintain nearly half of the distribution lines in the United States and serve three-quarters of the United States’ land mass. There are currently approximately 870 electric distribution cooperatives in the United States. Historically, the primary purpose of an electric distribution cooperative was to own and operate a distribution system and to supply the power requirements of its retail customers. With the advent of retail competition and regional transmission organizations in many areas, distribution cooperatives must adjust to changes in the distribution business, which typically remain regulated monopolies, and the power supply business, which is rapidly becoming competitive. See “Management’s Discussion and Analysis of Financial Condition and Results of Operations—Future Issues—Competition and Changing Regulations” in Item 7.

Member Distribution Cooperatives

General

Our member distribution cooperatives provide electric services, consisting of power supply, transmission services, and distribution services (including metering and billing) to residential, commercial, and industrial customers in 70 counties in Virginia, Maryland, Delaware, and West Virginia. The member distribution cooperatives’ distribution business involves the operation of substations, transformers, and electric lines that deliver power to customers. Three of our member distribution cooperatives provide electric services on the Delmarva Peninsula: A&N Electric Cooperative in Virginia, Choptank Electric Cooperative in Maryland, and Delaware Electric Cooperative in Delaware. The remaining nine members are: BARC Electric Cooperative, Community Electric Cooperative, Mecklenburg Electric Cooperative, Northern Neck Electric Cooperative, Northern Virginia Electric Cooperative, Prince George Electric Cooperative, Rappahannock Electric Cooperative, Shenandoah Valley Electric Cooperative, and Southside Electric Cooperative. The

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member distribution cooperatives are not our subsidiaries, but rather our owners. We have no interest in the properties, liabilities, equity, revenues, or margins of the member distribution cooperatives.

Historically, the member distribution cooperatives have been the exclusive providers of power to customers within their service territories. Recent restructuring legislation will permit nearly all of the member distribution cooperatives’ customers to select their power suppliers by 2004. The member distribution cooperatives will remain the exclusive provider of distribution services and, at least initially, the default provider of power within their service territories. See “Management’s Discussion and Analysis of Financial Condition and Results of Operations—Future Issues—Competition and Changing Regulations” in Item 7.

Wholesale Power Contracts

We sell power to our member distribution cooperatives under “all-requirements” wholesale power contracts. Each contract obligates us to sell and deliver to the member distribution cooperative, and the member distribution cooperative to purchase and receive from us, all power that it requires for the operation of its system, with limited exceptions, to the extent that we have the power and facilities available to do so. Each of these wholesale power contracts is effective through 2028 and continues in effect until we or the member distribution cooperative gives the other at least three years notice of termination.

There are two principal exceptions to the “all-requirements” obligations of the parties. First, each mainland Virginia member distribution cooperative may purchase power allocated to it from the Southeastern Power Administration (“SEPA”). In 2001, the total allocation of power from SEPA to the member distribution cooperatives was 84 MW plus associated energy, representing approximately 4.4% of our total member distribution cooperatives’ peak capacity requirements and approximately 1.2% of our total member distribution cooperatives’ energy requirements. Second, if pursuant to the Public Utility Regulatory Policies Act (“PURPA”) or other laws, a member distribution cooperative is required to purchase electric power from a qualifying facility, the member distribution cooperative must make the required purchases. Any required purchases made by the member distribution cooperative will be at a rate no more than our avoided cost, as established by us. At our option, the member distribution cooperative will sell that power to us at a price no more than that rate. The member distribution cooperative may appoint us to act as its agent in all dealings with the owner of any of these qualifying facilities. Purchases of power generated by qualifying facilities constituted less than 1.0% of our member distribution cooperatives’ capacity and energy requirements in 2001.

Each member distribution cooperative is required to pay us monthly for power furnished under its wholesale power contract in accordance with our formulary rate. The formulary rate is intended to allow us to meet all of our costs and expenses from the ownership, operation, maintenance, termination, retirement and decommissioning of and repairs, improvements, modifications to our generating plants, transmission system or related facilities and associated costs and expenses. See “Management’s Discussion and Analysis of Financial Condition and Results of Operations—Factors Affecting Results—Formulary Rate” in Item 7. In addition, the formulary rate includes our costs and expenses relating to the acquisition and sale of power or related services that we provide to our member distribution cooperatives under the wholesale power contracts, including:

• payments of principal of and premium, if any, and interest on all indebtedness issued by us (other than payments resulting from the acceleration of the maturity of the indebtedness);

• the cost of any power purchased for resale by us under the wholesale power contracts and the costs of transmission, scheduling, dispatching and controlling services for delivery of electric power;

• any additional cost or expense, imposed or permitted by any regulatory agency or which is paid or incurred by us relating to our generating plants, transmission system or related facilities or relating to the services we provide to our member distribution cooperatives that is not otherwise included in any of the costs specified in the wholesale power contracts;

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• additional amounts required to meet the requirement of any rate covenant with respect to coverage of principal of and interest on our indebtedness contained in any indenture or contract with holders of our indebtedness; and

• any additional amounts which our board of directors deems advisable in the marketing of our indebtedness.

The rates established under the wholesale power contracts are designed to enable us to comply with our mortgage, indenture, regulatory, and governmental requirements which apply to us from time to time.

We may revise our budget at any time to the extent that our current budget does not accurately reflect our costs and expenses or estimates of our sales of power. Increases or decreases in our annual budget automatically amend the demand component of our formulary rate. Also, the wholesale power contracts permit us to adjust the amounts to be collected from the member distribution cooperatives to equal our actual costs. We make these adjustments under the Margin Stabilization Plan. These adjustments are treated as due, owing, incurred and accrued for the year to which the increase or decrease relates. The member distribution cooperatives pay any amounts owed as a result of this adjustment in the following year. If at any time our board of directors determines that the formula does not meet all of our costs and expenses, it may adopt a new formula to meet those costs and expenses, subject to any necessary regulatory review and approval. See “Management’s Discussion and Analysis of Financial Condition and Results of Operations—Factors Affecting Results—Margin Stabilization Plan” in Item 7.

During the term of each wholesale power contract, each member distribution cooperative will not, without obtaining our written consent, take or permit to be taken any steps for reorganization or dissolution, consolidation with or merger into any corporation, or the sale, lease or transfer of all or a substantial portion of its assets. We will not, however, unreasonably withhold our consent to any reorganization, dissolution, consolidation, merger or sale, lease or transfer of assets. In addition, we will not withhold or condition our consent if the transaction would not (1) increase rates to our other members, (2) impair our ability to repay our indebtedness or any other obligation, or (3) affect our system performance in any material way. Despite these restrictions, a member distribution cooperative may reorganize or dissolve, consolidate with or merge into any corporation, or sell, lease or transfer a substantial portion of its assets without our consent if it:

• pays the portion of our indebtedness or other obligations as we determine, and

• complies with reasonable terms and conditions that we may require to eliminate any adverse effects on the rates of our other members, or provide assurance that we will have the ability to repay our indebtedness and abide by our other obligations.

As a result of deregulation and changes in the electric industry, we recognize that it may be desirable to modify the relationship between us and our member distribution cooperatives in the future. In particular, we recognize that our member distribution cooperatives may desire greater flexibility in their power supply options in the future, which may require an amendment to their wholesale power contracts. Currently, we are negotiating with one member distribution cooperative, Northern Virginia Electric Cooperative, possible amendments to its wholesale power contract with us. The negotiations center around changing the nature of the contract from an all-requirements contract to a contract under which Northern Virginia Electric Cooperative would take a percentage of the output of North Anna, Clover and the planned combustion turbine facilities and pay its share of our costs relating to these resources and the provision of services under the amended contract. Any amendments to our wholesale power contract with Northern Virginia Electric Cooperative would need to be approved by our board of directors before becoming effective. If approved, similar terms for the provision of power would be offered to all of our other member distribution cooperatives. In May 2001, our board of directors adopted a resolution stating that it would not approve any amendments to the wholesale power contract with a member distribution cooperative that could materially adversely affect our financial condition or cause us to fail to maintain our existing credit ratings.

Northern Virginia Electric Cooperative has told us that if the negotiation of an amendment to its wholesale power contract is not successful, it may bring an action before the Federal Energy Regulatory Commission (“FERC”)

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or the Virginia State Corporation Commission (the “VSCC”) seeking a reformation of the contract along the lines being negotiated. Northern Virginia Electric Cooperative would base its requested reformation on changes in circumstances since the execution of the wholesale power contract. It has acknowledged that it would not seek to be relieved of its obligation to buy power from us equal to its share of North Anna, Clover and the combustion turbine facilities. Nor would it seek to be relieved of its obligation to pay its share of the costs of those generating facilities, including debt service, lease rentals, operation and maintenance expenses, coverage and other costs and expenses related to the facilities or properly allocable to the services provided by us to it. Northern Virginia Electric Cooperative’s share of those generating facilities would be computed at an amount approximating its load ratio share of our Class A member load determined at an appropriate date. We do not believe any reformation of our wholesale power contract with Northern Virginia Electric Cooperative is justified if the parties do not agree to an amendment.

TEC Trading

Changes in the electric utility industry and our development of the combustion turbine facilities have made it more important for us to manage our activities in power-related markets. For instance, to obtain an economical power supply to meet our member distribution cooperatives’ energy peak requirements, we have occasionally purchased energy in excess of our member distribution cooperatives’ needs. We also intend to purchase natural gas or futures contracts to limit our exposure to fluctuating natural gas prices. In response to these changes, we formed TEC Trading in 2001 for the primary purpose of purchasing power from us to sell in the market, acquiring natural gas to supply the combustion turbine facilities, and taking advantage of other power-related trading opportunities in the market which will help lower our member distribution cooperatives’ costs. TEC Trading was not formed to engage in speculative trading.

On December 19, 2001, TEC Trading was granted market-based rate authority from FERC allowing TEC Trading to sell power at market rates. We have signed a power sales contract with TEC Trading for the sale of our excess energy which TEC Trading would then resell to the market. 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.

We expect that TEC Trading will engage ACES Power Marketing LLC (“APM”) to provide TEC Trading with contract review and compliance, credit analysis and monitoring, energy credit negotiations, portfolio modeling and structuring, reporting, trading controls, and settlement services.

We initially capitalized TEC Trading with a $7.5 million capital investment for all of its capital stock. We then distributed all of TEC Trading’s stock as a patronage capital distribution to our member distribution cooperatives. TEC Trading is our only Class B member and will be entitled to patronage from us. Its patronage will be based on our allocation of patronage to Class B members and its business with us.

We expect to enter into an agreement with TEC Trading whereby we agree to provide accounting, billing, reporting and other administrative services to TEC Trading. We will provide these services on an arm’s-length basis.

Members’ Service Territories and Customers

Historically, our member distribution cooperatives have had the exclusive right to provide electric service to customers within their exclusive service territories certified by their respective state public service commissions. Under this structure, the member distribution cooperatives, like other incumbent utilities, charged their customers a bundled rate for electric service, which included charges for power, transmission services, and distribution (including metering and billing) services.

Virginia, Maryland and Delaware have enacted legislation granting retail customers the right to choose their power supplier. This legislation maintains the exclusive right of the incumbent electric utilities, including our member distribution cooperatives, to continue to provide transmission and distribution services and, at least initially,

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to be the default providers of power to their customers in their service territories. See “Management’s Discussion and Analysis of Results of Operation and Financial Condition—Future Issues—Competition and Changing Regulations” in Item 7.

The territories served by the member distribution cooperatives cover large portions of Virginia, Maryland and Delaware. One of our member distribution cooperatives also serves a small area of West Virginia. These service territories range from the suburban metropolitan Washington, D.C. area in northern Virginia, to the Atlantic shore of Delaware, Maryland and Virginia, to the Appalachian Mountains and the North Carolina border. The service territories of member distribution cooperatives serving the high growth, increasingly suburban area between Washington, D.C. and Richmond, Virginia account for approximately half of our capacity requirements. While our member distribution cooperatives do not serve any major cities, several portions of their service territories are in close proximity to urban areas. These areas are experiencing growth due to the expansion of suburban communities into neighboring rural areas and the continuing development of resort and vacation communities within their service territories.

Our member distribution cooperatives’ service territories are diverse and encompass primarily suburban, rural and recreational areas. These territories predominantly reflect historically stable residential capacity requirements both in terms of power sales and number of customers. The major industries served by our member distribution cooperatives include manufacturing, fisheries, agriculture, forestry and wood products, paper, travel, and trade.

Sales of energy by our member distribution cooperatives in 2001 totaled approximately 8,738,106 MWh. Our member distribution cooperatives’ sales of energy were divided by type as follows:

Customer Class	Percentage of MWh Sales		Percentage of Customers
Residential	63.5	%	92.6	%
Commercial and industrial	35.2		6.8
Other	1.3		0.6

From 1996 through 2001, our member distribution cooperatives experienced an average annual compound growth rate of 2.9% in the number of customers and an average annual compound growth rate of 3.3% in energy sales.

Revenues from the following member distribution cooperatives equaled or exceeded 10% of Old Dominion’s total revenues in 2001:

Member Distribution Cooperative	Revenues		Percentage of Old Dominion’s Total Revenues
	(in millions)
Northern Virginia Electric Cooperative	$	129.5	26.6	%
Rappahannock Electric Cooperative		104.5	21.4
Delaware Electric Cooperative		48.9	10.0

The member distribution cooperatives’ average number of customers per mile of energized line has increased approximately 6.2% since 1996 to approximately 9.0 customers per mile in 2001. System densities of our member distribution cooperatives in 2001 ranged from 6.1 customers per mile in the service territory of BARC Electric Cooperative to 20.3 customers per mile in the service territory of Northern Virginia Electric Cooperative. In 2000, the average service density for all distribution electric cooperatives was approximately 6.9 customers per mile.

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COMPETITION AND CHANGING REGULATIONS

See Item 7, “Management’s Discussion and Analysis of Financial Condition and Results of Operations—Future Issues—Competition and Changing Regulations” for a discussion of the effects of competition and changing regulations on our members and us.

CONSERVATION AND LOAD MANAGEMENT

We seek to encourage and promote, through our member distribution cooperatives and their consumers, effective energy services, energy efficiency, and load reduction programs. Energy services programs offer commercial and industrial customers solutions to their energy needs. Energy efficiency programs encourage the construction of efficient and affordable housing, encourage the purchase of energy efficient water heaters and heating, ventilation, and air conditioning equipment, and provide affordable financing for energy efficiency improvements. Our member distribution cooperatives also support energy conservation efforts by providing home and business energy audits and educational materials. Load reduction efforts provide us the capability of reducing our peak load by over 200 MW. As competitive choices become available to our member distribution cooperatives’ retail consumers, the impact of each of these programs must be evaluated to ensure that value is added to the consumer and the cooperative.

Our member distribution cooperatives and we have entered into an agreement with the Department of Energy (“DOE”) to participate in the voluntary Climate Challenge Program under the United States Climate Challenge Action Plan. This voluntary program tracks reductions in carbon dioxide emissions from efficiency programs. A report was submitted to the DOE in 2000 summarizing various carbon dioxide reductions as a result of efficiency programs and distribution system upgrades.

POWER SUPPLY RESOURCES

General

We provide power to our members through a combination of our interests in North Anna and Clover, power purchase contracts and forward, short-term and spot purchases of power in the open market. Our power supply resources for the past three years have been as follows:

	Year Ended December 31,
	2001			2000			1999
	(in MWh and percentages)
Generated:
Clover	3,342,398	34.4	%	3,428,357	36.7	%	3,198,062	36.7	%
North Anna	1,519,223	15.7		1,767,053	18.9		1,775,915	20.3
Total generated	4,861,621	50.1		5,195,410	55.6		4,973,977	57.0
Purchased:
Virginia area	2,332,045	24.0		1,975,503	20.8		1,713,959	19.4
Delmarva area	2,285,585	23.6		1,943,920	12.8		1,831,589	16.5
Other	223,608	2.3		223,782	10.8		208,231	7.1
Total purchased	4,841,238	49.9		4,143,205	44.4		3,753,779	43.0
Total available energy	9,702,859	100.0	%	9,338,615	100.0	%	8,727,756	100.0	%

Our system is geographically divided into two separate and distinctive transmission and distribution control areas with limited capability to transmit power between the two control areas—a mainland Virginia control area and a PJM control area. The two control areas have similar customer usage characteristics and distribution of sales by customer classification. Typically, however, the mainland Virginia control area’s capacity requirements peak is in the winter months, while the Delmarva Peninsula control area’s capacity requirements peak is in the summer months. While there is little variance between our summer and winter peak capacity requirements, we typically have experienced a slightly higher peak demand for capacity in the winter months. This peak is due to the winter heating requirements of the

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member distribution cooperatives’ customers, which reflects the large residential component of our total capacity requirements.

The mainland Virginia control area represented approximately 77% of our member distribution cooperatives’ 2001 peak capacity requirements, which occurred in August. North Anna and Clover satisfied approximately 44.8% of our current capacity requirements and 68.8% of our energy requirements in the mainland Virginia control area in 2001. We obtain the remainder of our mainland Virginia control area and all of our Delmarva Peninsula control area requirements, both capacity and energy, from several suppliers, and short-term spot market purchases. Generally, power purchase contracts allow us to meet these requirements by purchasing fixed-price firm capacity and energy at market prices.

Between 2001 and 2005, these contracts will expire. Through our subsidiaries, we are developing the combustion turbine facilities to satisfy substantially all of the capacity and a portion of the energy currently supplied by the contracts. The timing and size of each combustion turbine facility was planned to meet our projected capacity requirements, which are a function of expiring power purchase contracts and our member distribution cooperatives’ capacity requirements growth projections. In addition, we are installing ten diesel generators across our member distribution cooperatives’ service territories primarily to enhance our system’s reliability.

North Anna

In 1983, we acquired an 11.6% undivided ownership interest in North Anna, including nuclear fuel and common facilities at the power station, and a portion of spare parts inventory and other support facilities. North Anna is a two unit, 1,842 MW (net capacity rating) facility located in Louisa County, Virginia, approximately 60 miles northwest of Richmond, Virginia. During 2001, North Anna provided approximately 15.7% of our energy requirements. North Anna Unit 1 commenced commercial operation in June 1978, and Unit 2 commenced commercial operation in December 1980. Virginia Electric and Power Company (“Virginia Power”), the co-owner of North Anna, operates the facility. Virginia Power also has the authority and responsibility to procure nuclear fuel for North Anna. See “Fuel Supply—Nuclear.”

Under the Amended and Restated Interconnection and Operating Agreement with Virginia Power (“I&O Agreement”), we are entitled to 11.6% of the power from North Anna. In addition, we can purchase from Virginia Power supplemental or peaking power or both through 2003. See “Other Power Supply Resources—Power Purchase Contracts—Virginia Power” for a description of the type and amount of power we may purchase under the contract. We intend to purchase our reserve capacity requirements for North Anna from Virginia Power for the term of the I&O Agreement, which expires on the earlier of the date on which all facilities at North Anna have been retired or decommissioned and the date we have no interest in North Anna.

Under the I&O Agreement, we are responsible for 11.6% of all post-acquisition date additions and operating costs associated with North Anna, as well as a pro-rata portion of Virginia Power’s administrative and general expenses directly attributable to North Anna. We are obligated to provide our own financing for these items. In addition, we separately fund our pro rata portion of the decommissioning costs of North Anna. We and Virginia Power also bear pro rata any liability arising from ownership of North Anna, except for liabilities resulting from the gross negligence of the other.

Like other nuclear facilities, North Anna is subject to unanticipated or extended outages for repairs, replacements, or modifications of equipment or to comply with regulatory requirements. These outages may involve significant expenditures not previously budgeted, including replacement energy costs. See “Management’s Discussion and Analysis of Financial Condition and Results of Operations—Results of Operations—Operating Expenses” in Item 7 for a discussion of recent operating history of North Anna.

Clover

We have a 50% undivided interest in Units 1 and 2 of Clover, a coal-fired generating facility jointly owned with Virginia Power. Clover has a net capacity rating of 882 MW and is located near Clover in Halifax County, Virginia,

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approximately 100 miles southwest of Richmond, Virginia. Clover Units 1 and 2 began commercial operations in October 1995 and March 1996, respectively.

Pursuant to the terms of the Clover operating agreement, Virginia Power, as the co-owner of Clover, is responsible for operating Clover and procuring and arranging for the transportation of the fuel required to operate Clover. See “Fuel Supply—Coal.” We are responsible for half of all additions and operating costs associated with Clover, as well as half of Virginia Power’s administrative and general expenses for Clover. We must provide our own financing for these expenses.

Under the terms of the Clover operating agreement, we and Virginia Power each are required to take half of the power produced by Clover. During 2001, Clover provided approximately 34.4% of our energy requirements. In those hours when we are not able to use our share of the energy produced by Clover, we are required to sell and Virginia Power is required to purchase our excess energy. In addition, if Virginia Power makes off-system sales from Clover, we will share in the net proceeds of those sales. In light of recent deregulation legislation enacted in Virginia, we and Virginia Power have agreed that the operating agreement for Clover will be restructured prior to January 1, 2003, to permit us to sell our excess energy from Clover to other power purchasers as well as to Virginia Power on changed terms. We expect to execute an amendment to the Clover operating agreement to grant us these rights prior to 2003. We intend to purchase our reserve capacity requirements for Clover from Virginia Power for the term of the I&O Agreement.

We have entered into a sale and leaseback of our undivided ownership interest in pollution control assets at Clover Units 1 and 2. In 1994, we sold these pollution control assets to an investor, subject to the lien of our Indenture of Mortgage and Deed of Trust, dated May 1, 1992, with Crestar Bank (predecessor to SunTrust Bank), as trustee (the “Existing Indenture”), and leased them back for a term extending until December 30, 2012. The lessor’s interest in these assets will no longer be subject to the lien of the Existing Indenture on the date the lien of the Existing Mortgage is released (the “Release Date”). See “Management’s Discussion and Analysis of Financial Condition and Results of Operations—Factors Affecting Results—Formulary Rate—Restated Indenture” in Item 7. We have an option to purchase the undivided interest in the pollution control assets sold to the investor on December 30, 2004 for a fixed purchase price. Our obligation to make periodic payments of basic rent and the fixed purchased option price payable in 2004 have been fully assumed and the payments are being made by a third party. We have been released from these payment obligations. The lessor’s interest in the undivided interest in the assets subject to the lease is subject to a lien in favor of us securing our purchase options under this lease. We have covenanted to exercise our option to purchase the assets subject to the lease on December 30, 2004.

We also have entered into separate lease and leaseback agreements of our undivided ownership interest in each Clover unit and related common facilities, including the pollution control assets at the facilities. In March, 1996, we entered into a lease with an owner trust for the benefit of an investor in which we leased our interest in Clover Unit 1, subject to the lien of the Existing Indenture, for a term extendable by the lessor up to the full productive life of Clover Unit 1, and simultaneously entered into an approximately 22-year lease of the interest back to us. After the Release Date, the interest of the owner trust in Clover Unit 1 will no longer be subject and subordinate to the lien of the Existing Indenture. See “Management’s Discussion and Analysis of Financial Condition and Results of Operations—Factors Affecting Results-Formulary Rate—Restated Indenture” in Item 7. The lease back to us includes a fixed price purchase option at the end of its term. We have provided for all of our periodic basic rent payments under the lease by investing in obligations issued or insured by entities, the claims paying ability or senior debt obligations of which are rated “AAA.” These obligations will mature at a time and in an amount sufficient to fully fund the fixed purchase option price in the lease to us. The lease to us contains events of default which, if they occur, could result in termination of the lease, and, consequently, our loss of possession and right to the output of Clover Unit 1.

In July, 1996, we entered into another lease subject to the lien of the Existing Indenture with an owner trust for the benefit of a different investor of our interest in Clover Unit 2 for a term extendable by the lessor up to the full productive life of Clover Unit 2. We simultaneously entered into an approximately 23-year lease of the interest back to us. After the Release Date, the interest of the owner trust will no longer be subject and subordinate to the lien of the Existing Indenture. See “Management’s Discussion and Analysis of Financial Condition and Results of

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Operations—Factors Affecting Results—Formulary Rate—Restated Indenture” in Item 7. The lease back to us includes a fixed price purchase option at the end of its term. We have provided for all of our periodic basic rent payments under the lease by investing in obligations issued or insured by entities, the claims paying ability or senior debt obligations of which are rated “AAA.” These obligations will mature at a time and in an amount sufficient to fully fund the fixed purchase option price in the lease to us. In addition, we granted a subordinated lien and security interest in Clover Unit 2 to secure our obligations under the lease and our reimbursement obligation to an insurer for its payments under a surety bond securing some of our payment obligations under the lease. This subordinated lien and security interest will be required to be released prior to the Release Date unless the holders of obligations issued under the Existing Indenture are equally and ratably secured with respect to the assets subject to the lease. As with the Clover Unit 1 lease, the lease back to us of Clover Unit 2 contains events of default which could result in termination of the lease and loss of possession and right to the output of the unit.

Combustion Turbine Facilities

Through our subsidiaries, we are developing Rock Springs, Louisa and Marsh Run to enable us to continue to serve our member distribution cooperatives’ power requirements. Upon completion of the facilities, our total system capacity from facilities owned by us or our subsidiaries will increase from 655 to 2,167 MW. The sites selected for Rock Springs, Louisa and Marsh Run contain the attributes required to support a combustion turbine facility. These sites have access to electric transmission lines, natural gas pipelines, and the other major infrastructure required to support a combustion turbine facility.

Rock Springs

The Rock Springs facility is currently being developed by our subsidiary together with another participant. Rock Springs will meet a substantial portion of the capacity requirements of our member distribution cooperatives on the Delmarva Peninsula and provide power to the other participant. Located in the community of Rock Springs, Cecil County, Maryland, the facility is currently expected to consist of six 168 MW (net capacity rating) General Electric 7FA combustion turbines, for a total of 1,008 MW. Power from the facility will be transmitted to our member distribution cooperatives over PJM’s transmission facilities under its open access transmission tariff.

The other party developing Rock Springs with our subsidiary is ConEdison Development, Inc. (“ConEd”). Another participant may join the project in the future. We expect that the participants, including our subsidiary, will each own two units with a total capability of 336 MW and a proportionate share (depending on the number of participants in Rock Springs) of the undivided interest in the common facilities. Our subsidiary will be responsible for all costs associated with the development, construction, additions and operating costs and administrative and general expenses relating to its two units and its proportional share of the costs relating to the common facilities for Rock Springs.

The Maryland Public Service Commission (the “Maryland PSC”) has issued a certificate of convenience and necessity for the construction and operation of the facility. All major environmental permits from the State of Maryland have been obtained, subject to compliance with customary conditions set forth in the certificate, and we have purchased the necessary nitrogen oxide (“NO_x”) emissions credits required prior to the start of construction of the facility. See “Regulation—Environmental.”

We have entered into a fixed-price contract with General Electric Company to purchase three General Electric 7FA combustion turbines, two of which will be installed at Rock Springs and the other at Louisa. The turbines will be fueled by natural gas and have dry low-NO_x burners which currently exceed Best Available Control Technology and meet the Lowest Achievable Emission Rate standards established by the Environmental Protection Agency (the “EPA”). We assigned our rights in the contract with respect to the two turbines to be installed at Rock Springs to our subsidiary developing the facility.

We are acting as construction agent on behalf of our subsidiary, ConEd, and any future participant or participants in Rock Springs to administer and supervise the development and construction of the facility. Our

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subsidiary and ConEd entered into a contract with Fru-Con Construction Corp. for engineering, procurement and construction services relating to Rock Springs. Construction began on the Rock Springs facility in October 2001 and we anticipate that commercial operation of the first unit will occur in 2002. ConEd will own the first unit but will sell the output from that unit to us for one year. We expect the two units owned by our subsidiary will begin commercial operation in 2003.

Louisa

The Louisa facility will be located near Gordonsville, in Louisa County, Virginia. The facility is currently expected to consist of five combustion turbines totaling 504 MW. We have entered into a fixed-price contract with General Electric Company to purchase four 84 MW (net capacity rating) General Electric 7EA combustion turbines in addition to one 168 MW (net capacity rating) General Electric 7FA combustion turbine purchased with the two turbines for Rock Springs. The combustion turbines are expected to be fueled by natural gas and, if necessary, No. 2 distillate fuel oil. We assigned our interest in the contracts relating to the turbines to be installed at the facility to our subsidiary developing Louisa. As with Rock Springs, we will act as construction agent on behalf of our subsidiary.

We expect construction of the facility to begin in the second quarter of 2002 and the units to be available for commercial operation in 2003. Power from Louisa will be transmitted to our member distribution cooperatives over the transmission facilities of Virginia Power under its open access tariff.

Marsh Run

The Marsh Run facility will be located near Remington in Fauquier County, Virginia, and is currently expected to consist of four 168 MW (net capacity rating) combustion turbines, for a total of 672 MW. We have entered into a fixed-price contract with General Electric Company to purchase three General Electric 7FA combustion turbines to be installed at Marsh Run. We assigned the contract to our subsidiary developing Marsh Run. The combustion turbines are expected to be fueled by natural gas and, if necessary, No. 2 distillate fuel oil. We have not determined how the fourth combustion turbine will be obtained.

We expect that construction of the facility will begin in 2002 and three units will be available for commercial operation in 2004. We expect to act as construction agent on behalf of our subsidiary. Power from Marsh Run will be transmitted to our member distribution cooperatives over the transmission facilities of Virginia Power under its open access tariff.

Other Power Supply Resources

In 2001, we purchased approximately 49.9% of our total energy requirements. These energy requirements are in excess of our owned generation and were provided principally by neighboring utilities through power purchase contracts and purchases of energy in the forward, short-term and the spot market.

Power Purchase Contracts

Historically, we satisfied our capacity and energy requirements not supplied by North Anna and Clover through power purchase contracts with Virginia Power, Allegheny Power Resources (“Allegheny”), American Electric Power Virginia (“AEP-Virginia”) and Delaware Power & Light, the predecessor to Conectiv Energy (“Conectiv”). Under these contracts, we purchased capacity and energy at a price determined by the seller’s average system cost. In the late 1990’s, we sought to take advantage of projected lower market prices of power by (1) restructuring or reducing the term of these contracts, (2) reducing the amount of capacity or energy or both we purchased under these contracts, and (3) entering into new contracts which contained market-based pricing provisions. As a result, we entered into power purchase contracts with Public Service Electric & Gas Company (“PSE&G”), Conectiv and Pennsylvania Power and Light (“PPL”), and Williams Marketing and Trading Compan (“Williams”). These contracts expire as the combustion turbine facilities become operational. See “Combustion Turbine Facilities.”

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Virginia Power.    Under the terms of the I&O Agreement, Virginia Power sells us reserve capacity and energy for North Anna and Clover. We plan to purchase our reserve capacity requirements for North Anna and Clover from Virginia Power for the term of the I&O Agreement, which expires on the earlier of the date on which all facilities at North Anna have been retired or decommissioned and the date we have no interest in North Anna. Through 2001, Virginia Power has the obligation to provide us with all the monthly supplemental and peaking demand and energy requirements to meet the needs of our mainland Virginia members not met from our portion of the output of North Anna and Clover. Under the I&O Agreement, we will purchase from Virginia Power half of these supplemental capacity requirements in 2002 and none in 2003. We will continue to purchase our peaking requirements from Virginia Power through 2003.

Beginning January 1, 2000, energy pricing for the peaking portion of Virginia Power purchases changed from Virginia Power’s system average cost to a charge that reflects Virginia Power’s owned combustion turbine costs. Beginning January 1 2001, energy pricing for the supplemental portion of Virginia Power purchases changed from Virginia Power’s system average cost to a charge that reflects an average price of predetermined Virginia Power owned combustion turbine and combined cycle costs. We have the contractual right to elect not to purchase energy under the I&O Agreement if we can purchase more economical energy from other sources.

Additionally, under the terms of the I&O Agreement, Virginia Power has unbundled the services it provides us and no longer provides transmission and ancillary services to us under the contract. These services are now provided under Virginia Power’s open access transmission tariff. Specific terms for the provision of those services are provided in a Service Agreement for Network Integration Transmission Service and a Network Operating Agreement with Virginia Power, both of which became effective as of January 1, 1998.

PSE&G.    We have entered into an agreement with PSE&G to purchase 150 MW of capacity, consisting of 75 MW of intermediate or peaking capacity and 75 MW of base load capacity, as well as reserves and associated energy, through 2004. The agreement with PSE&G contains fixed capacity charges for the base, intermediate, and peaking capacity to be provided under the agreement. However, either party can apply to FERC in some circumstances to recover changes in specified costs of providing services. If a change in rate occurs, the party adversely affected may terminate the agreement on one-year’s notice. We may purchase the energy associated with the PSE&G capacity from PSE&G or other power suppliers. If purchased from PSE&G, the energy cost is based on PSE&G’s incremental cost above its own capacity requirements, taking into account PJM pool energy transactions.

In October 1997, we filed with FERC a Section 206 complaint against PSE&G asserting that our 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 the zonal rate it currently pays Conectiv. 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 has complied with the FERC order by virtue of a compliance filing submitted to FERC on June 15, 1998. On November 30, 2000, PSE&G filed with the United States Court of Appeals for the District of Columbia Circuit a petition for review of FERC’s orders in this matter. PSE&G’s appeal is still pending before that court.

Conectiv and PPL.    We had a contract with Conectiv to purchase 220 MW of capacity through August 31, 2001 to satisfy our capacity requirements for our member distribution cooperatives providing service on the Delmarva Peninsula. There was no commitment to purchase energy under the contract, and we procured the energy in conjunction with our other PJM energy needs through bilateral agreements and economy energy purchases.

Additionally, we have a contract with a joint venture of Conectiv and PPL to purchase 60 MW of firm system capacity through December 2001. We did not purchase energy under the contract.

Williams Energy Agreement.    In April 2000, we executed an agreement with Williams Energy to meet a portion of our Delmarva Peninsula member distribution cooperatives’ demand and energy needs. We began making purchases under the Williams Energy agreement on September 1, 2001. We purchased 200 MW of capacity for the period September 1, 2001 through December 31, 2001 and will purchase 286 MW of capacity for the period January 1, 2002 through April 30, 2002. In addition to having rights to capacity, we will have rights to call on energy priced

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at fixed energy rates. This same agreement will also be used to meet portions of our load in the mainland Virginia control area beginning January 1, 2002.

Williams Energy Management Agreement.    In December 2000, we entered into an Energy Management Agreement with Williams Energy whereby Williams Energy agreed to deliver energy to serve the full hourly energy requirements of our Delmarva Peninsula load for the period January 1, 2001 through August 31, 2001. Under the agreement, the energy rates for each month were fixed.

AEP–Virginia.    We purchase power from AEP–Virginia pursuant to three agreements. Combined, the agreements allow for purchases of up to 108 MW a year. Charges for power purchased under these contracts are based on AEP–Virginia’s wholesale rate tariff filed with FERC. Each of the agreements will remain in effect until November 2003.

Allegheny Power.    We entered into a five-year fixed price full requirements contract with Allegheny beginning January 1997. The contract expired at the end of 2001 and has been replaced by a new contract with Allegheny Energy Supply, a subsidiary of Allegheny. Transmission service is supplied under Allegheny’s open access transmission tariff.

Other.    We also purchased a portion of our energy requirements from the short-term markets and the spot market. These purchases represent the purchasing strategies associated with the changing contracts and the ability to displace energy under existing contracts. These strategies, however, are not without risk. To mitigate the risks, we are attempting to match our energy purchases with our energy needs and are covering our energy positions in advance to hedge the spot market risk. Additionally, we have developed policies and procedures to manage the risks in the changing business environment and in March 2001, we became an equity owner in APM. See “Management’s Discussion and Analysis of Financial Condition and Results of Operations—Future Issues—Reliance on Energy Purchases.”

ConEd.    We are in the process of finalizing a purchase power agreement with ConEd for the purchase of capacity and energy from one of ConEd’s units at Rock Springs. As a part of the Joint Development Agreement with ConEd, ConEd has agreed to sell the power from the first combustion turbine generator to be installed for the period from the unit’s in-service date through May 31, 2003. This combustion turbine generator is expected to become operational sometime during the later half of 2002. We are evaluating the need to secure capacity and energy resources in case the unit’s in-service date is delayed.

Diesel Generators

We currently are installing ten Caterpillar 3516B utility-grade diesel generators throughout our member distribution cooperatives’ service territories. Each generator has a capacity of approximately two MW. We are installing the generators primarily to enhance our system’s reliability if other power supply resources are unavailable.

Transmission

We do not own any significant energized transmission or distribution facilities. We have entered into agreements with Virginia Power, PJM, AEP-Virginia and Allegheny which provide us with access to their transmission facilities as necessary to deliver energy to our members.

Virginia Power System

Under the operating agreements for both North Anna and Clover, Virginia Power makes available to us its transmission and distribution systems, as needed, to transmit our power from North Anna and Clover, as well as power purchased from other suppliers, to our member distribution cooperatives’ delivery points. Under the I&O Agreement, Virginia Power supplies all transmission services under its open access transmission tariff. In 2002, the terms for transmission and related services are described in our Service Agreement for Network Integration Transmission Service and the Network Operating Agreement with Virginia Power. Because Virginia Power has stated an intention to

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participate in the Alliance regional transmission organization, we will obtain transmission service from that organization when it becomes operational. See “—RTOs.”

PJM

We are a member of PJM to serve our member distribution cooperatives located on the Delmarva Peninsula. PJM is an independent system operator of transmission facilities serving all of Delaware and New Jersey and parts of Pennsylvania, Maryland and Virginia.

PJM continually balances its participants power requirements with the power resources available to supply those requirements. Based on this evaluation of supply and demand, PJM schedules available resources to meet the demand for power in the most efficient and cost effective manner. When available resources cannot be dispatched due to transmission constraints, more expensive generating facilities not subject to the transmission constraints must be dispatched to meet the requested power requirements. PJM participants whose power requirements cause the redispatch are obligated to pay those costs. Our PJM power requirements are located on the Delmarva Peninsula, which has been subject to significant congestion costs over the last two years. In 2001, we paid approximately $18.0 million in congestion charges to PJM. These charges were offset by credits of approximately $6.4 million for our ownership of fixed transmission rights. Net congestion costs for 2001 were approximately $11.4 million.

We attempt to mitigate some of the effects of congestion at PJM’s delivery points through the procurement of fixed transmission rights. Through fixed transmission rights we receive or pay the difference between the cost of energy delivered to our delivery points and the cost of energy delivery to other specified delivery points on the PJM system (which generally is less expensive than the cost we incur at our delivery points). As a result, fixed transmission rights generally reduce congestion charges resulting from having to purchase more expensive power if the energy we purchased for delivery is unable to be delivered because of transmission congestion. PJM allocates to us a specified number of fixed transmission rights. We purchase additional fixed transmission rights from PJM and negotiate to obtain additional fixed transmission rights from other members of PJM if economical.

Conectiv has been performing system upgrades to meet reliability criteria and to interconnect with a new generating facility located in the portion of Virginia on the Delmarva Peninsula. Conectiv expects that congestion will be reduced significantly once these upgrades are complete. In addition, we have agreed to pay for direct connection facilities and transmission network upgrades to the PJM in order to serve our member distribution cooperatives on the Delmarva Peninsula more reliably and economically.

Other Transmission Systems

Allegheny, in its power purchase contract with us, has agreed to transmit power pursuant to Allegheny’s open access transmission tariff. In addition, our power purchase contracts with AEP–Virginia require AEP–Virginia to transmit power purchased under our contracts with it. These transmission arrangements may change as these companies become part of an independent system operator as directed by FERC.

RTOs

In December 1999, FERC issued Order No. 2000 amending its regulations under the Federal Power Act to advance the formation of regional transmission organizations (“RTOs”). One of the major objectives of Order No. 2000 is to eliminate “pancaked” transmission rates (incurring charges from multiple transmission owners due to transmission across several systems). By paying a single transmission rate to access all the transmission facilities under the control of the RTO, the RTO will expand access to markets that were previously uneconomical due to having to pay each utility a transmission charge. FERC will regulate the rates established by the RTOs. The regulations require that each public utility that owns, operates or controls facilities for the transmission of electric energy in interstate commerce make required filings with respect to forming and participating in an RTO. Because we do not own any significant jurisdictional transmission or distribution facilities, our participation in any RTO would be as a market participant and not as a transmission owner. We will be impacted by Order No. 2000 because our members have power requirements for which we have the responsibility of providing transmission service. We

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will benefit from Order No. 2000 if, as intended, it increases competition and consequently reduces our transmission costs.

FERC noted in Order No. 2000, and on rehearing in Order No. 2000-A, that existing state and federal laws applicable to cooperatives may inhibit their participation in RTOs. These laws include tax laws that restrict the level of business a cooperative can conduct with non-members and still maintain its tax-exempt status. FERC obligated investor-owned utilities under Order No. 2000 to consider the constraints imposed on cooperatives and work with them to foster their participation in RTOs.

On July 12, 2001, FERC issued a series of orders in which it determined that it is necessary that the three independent system operators in the Northeastern United States, which includes PJM, combine to form one RTO. Similarly, FERC concluded that it is necessary that the transmission owners in the Southeastern United States combine to form one RTO. Accordingly, FERC initiated expedited mediation proceedings for the purpose of facilitating the formation of a single RTO for the Northeastern United States and one for the Southeastern United States. We currently are evaluating the effect of the orders on us.

Fuel Supply

Nuclear

Under the Purchase, Construction and Ownership Agreement for North Anna, the I&O Agreement, and the Nuclear Fuel Agreement between Virginia Power and us, Virginia Power, as operating agent, has the authority and responsibility to procure nuclear fuel for North Anna. Virginia Power employs both spot purchases and long-term contracts to satisfy North Anna’s nuclear fuel requirements. Virginia Power continually evaluates worldwide market conditions in order to ensure a range of supply options at reasonable prices. Virginia Power reports that current agreements, inventories, and spot market availability will support current and planned fuel cycles. Additional fuel is purchased as required to ensure optimum cost and inventory levels.

Coal

Under the Clover operating agreement, Virginia Power, as operating agent, has the authority and responsibility to procure sufficient coal for the operation of Clover. Virginia Power employs both spot purchases and long-term contracts to acquire the low sulfur bituminous coal used to fuel the facility. We anticipate that sufficient supplies of coal will be available in the future at reasonable prices, but market prices and price volatility both may be higher than we currently anticipate.

Gas

Natural gas has become the preferred fuel for new electric generating facilities, causing an increase in competition for natural gas capacity. The combustion turbine facilities are located adjacent to natural gas transmission lines. We anticipate that these natural gas transmission lines generally will have the capacity to meet the natural gas needs of the combustion turbine facilities. We are developing a fuel supply plan which is intended to provide an economical and reliable supply of gas to the combustion turbine facilities. To develop this plan, we are evaluating purchases of firm gas (delivery of which may not be interrupted even during periods of high demand for gas) and interruptible gas, and designing Louisa and Marsh Run to operate for a limited period of time on fuel oil reserves. Through APM and TEC Trading, we and the subsidiaries plan to utilize long-term contracts and spot purchases to support the natural gas needs of the combustion turbine facilities and enter into hedging instruments to minimize price volatility. We presently anticipate that sufficient supplies of natural gas will be available in the future at reasonable prices, but significant price volatility may occur, especially during the winter. See “Quantitative and Qualitative Disclosures About Market Risk” in Item 7A and “Business—Member Distribution Cooperatives—TEC Trading.”

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REGULATION

General

We are subject to regulation by FERC and to a limited extent, public service commissions. Some of our operations are also subject to regulation by the Virginia Department of Environmental Quality (“DEQ”), the DOE, the Nuclear Regulatory Commission (“NRC”), and other federal, state, and local authorities. Compliance with future laws or regulations may increase our operating and capital costs by requiring, among other things, changes in the design and operation of our generation facilities.

FERC regulates our rates for transmission services and wholesale sale of power in interstate commerce. We establish our rates for power furnished to our member distribution cooperatives pursuant to our comprehensive formulary rate, which has been accepted by FERC. The formulary rate is intended to permit us to collect revenues, which, together with revenues from all other sources, are equal to all of our costs and expenses, plus an additional 20% of our total interest charges, plus additional equity contributions as approved by our board of directors. The formula is comprised of three components: a demand rate, a base energy rate, and a fuel factor adjustment. See “Management’s Discussion and Analysis of Financial Condition and Results of Operations—Factors Affecting Results—Fomulary Rate” in Item 7.

The formula provides for periodic adjustment of rates to recover actual, prudently incurred costs, whether they increase or decrease, without further application to and acceptance by FERC. FERC also may review our rates upon its own initiative or upon complaint and order a reduction of any rates determined to be unjust, unreasonable, or otherwise unlawful and order a refund for amounts collected during such proceedings in excess of the just, reasonable, and lawful rates. Our charges to TEC Trading will be established under our market-based sales tariff filed with FERC.

In addition to its jurisdiction over rates, FERC regulates the issuance of securities and assumption of liabilities by us, as well as mergers, consolidations, the acquisition of securities of other utilities, and the disposition of property other than generating facilities. Under FERC regulations, we are prohibited from selling, leasing, or otherwise disposing of the whole of our facilities (other than generating facilities), or any part of such facilities having a value in excess of $50,000, without FERC approval. FERC also will regulate the sale of power by our subsidiaries owning the combustion turbine facilities unless the Rural Utilities Service (“RUS”) has guaranteed loans to the subsidiaries. The subsidiaries intend to seek approval from FERC as exempt wholesale generators.

Because we are regulated by FERC, the VSCC, the Delaware Public Service Commission (“Delaware PSC”), and the Maryland PSC do not have jurisdiction over our rates and services. The state commissions, however, do have oversight over the siting of our utility facilities in their respective jurisdictions. They also regulate the rates and services offered by our member distribution cooperatives.

Environmental

We are currently subject to regulation by the EPA and other federal, state, and local authorities regarding the emission, discharge, or release of materials into the environment. As with all electric utilities, the operation of our generating units could be affected by future environmental regulations. Capital expenditures and increased operating costs required to comply with any future regulations could be significant. Expenditures necessary to ensure compliance with environmental standards or deadlines will continue to be reflected in our capital and operating costs.

We are subject to the Clean Air Act. The Clean Air Act requires utilities owning fossil fuel fired-power stations to, among other things, limit emissions of sulfur dioxide and nitrogen oxide (“NO_x”), one of the precursors of ground-level ozone, or obtain allowances for these emissions. Through the use of pollution control facilities, Clover is designed and licensed to operate at full capacity below the current limitations for sulfur dioxide emissions levels and nitrogen oxides emissions. Pollution control facilities at Clover include wet limestone scrubbers, low NO_x burners, and fly ash collection facilities. Virginia Power, as operator of North Anna and Clover, is responsible for environmental compliance and reporting for the facilities. If, however, liabilities arise as a result of a failure of environmental compliance at North

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Anna or Clover, our respective responsibility for those liabilities is governed by the operating agreements for the facilities. See “Power Supply Resources—North Anna” and “—Clover.”

In 1998, the EPA issued a rule addressing regional transport of ground-level ozone through reductions in NO_x. The rule is commonly known as the NO_x State Implementation Plan (“SIP”) call. The NO_x SIP call affects 22 states, including Maryland and Virginia, and the District of Columbia, and required those states to develop a plan by October 30, 2000, to reduce NO_x emissions. The NO_x SIP call also required emissions reduction to be implemented by May 1, 2004. On December 26, 2000, the EPA found that several states, including Virginia, failed to submit a plan satisfying the rules. If a state fails to make the required submittal, which the EPA determines is complete, within 18 months of the findings, an emissions offset sanction will apply. This sanction requires new or modified sources of emissions to obtain allowances to emit two tons of NO_x for every one ton of NO_x emitted from the source, subject to the Clean Air Act new source review program for NO_x. The EPA will lift the sanctions when it finds that the state has made a complete filing under the SIP call. The EPA also can promulgate a federal implementation plan as late as two years after the initial findings, unless the affected state has submitted a complete plan by that time. In a federal plan, the EPA rather than the states would determine the specific sources that must reduce NO_x emissions. We anticipate that fossil fuel electric generating facilities greater than 250 mmBtu/hour will be required to reduce their NO_x emissions or obtain NO_x emissions credits from another source. We and Virginia Power are currently evaluating options in meeting the NO_x SIP call as applicable to Clover. These options include installing additional NO_x controls at Clover and purchasing emissions allowances or a combination of both. At this time, we and Virginia Power continue to evaluate NO_x controls to determine the best alternatives for Clover.

North Anna is not impacted by the SIP call because it does not have significant NO_x emissions. Louisa and Marsh Run will be required to obtain allowances to emit one ton of NO_x for every ton of NO_x emitted from the facility during the ozone season. Rock Springs is in an ozone non-attainment area and was required to obtain allowances to emit one ton of NO_x emissions for every ton of NO_x emitted as well as 1.3 NO_x emissions reduction credits for every ton of potential NO_x emissions. NO_x emission reduction credits were required to be obtained prior to the construction of the facility. We will purchase in the market the allowances and have purchased credits required for the operation of the combustion turbine facilities. We project that we will be able to obtain sufficient quantities of allowances in the future at commercially reasonable prices but increased NO_x emissions or increased restrictions could cause the price of allowances to be higher than we expect.

In addition to the NO_x SIP call, several Northeast utilities filed petitions under Section 126 of the Clean Air Act requesting that the EPA take action to mitigate interstate transportation of NO_x. In December 1999, the EPA established NO_x allocations for 392 generating facilities, including Clover, and many industrial facilities. Additionally, the EPA established a trading program to help those companies meet the required reductions in NO_x by May 3, 2003. The EPA has now changed the compliance date under Section 126 to be consistent with the NO_x SIP call date of May 1, 2004.

The EPA has promulgated a new regional haze rule, which affects any source that emits NO_x or sulfur dioxide and that may contribute to the degradation of visibility in national parks and wilderness areas. Currently, we do not know what controls, if any, may have to be installed at Clover to comply with this rule.

Each state regulates the discharge of process wastewater and some storm water discharges into its waters under the National Pollutant Discharge Elimination System program. This program was established as part of the Federal Clean Water Act. We are also subject to permit limitations for surface water discharges and for the operation of a waste landfill at Clover for disposal of ash and scrubber sludge. Permits required by the Clean Water Act and state laws have been issued to us. These permits are subject to reissuance and continued review. We and Virginia Power are evaluating relocating the future landfill discharge to the Roanoke River, which contains a larger flow and provides more dilution.

Clover has a Virginia water protection permit that regulates the amount of water allowed to be withdrawn from the Roanoke River. Clover has a 34-day on-site water supply reservoir to supply the facility during times of low flow when the Roanoke River is below the withdrawal level allowed in the permit.

Our direct capital expenditures for environmental control facilities at Clover and North Anna, excluding capitalized interest, were approximately $0.5 million and $0.2, respectively, in 2001. Based on information provided by Virginia

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Power, our portion of direct capital expenditures for environmental control facilities planned for Clover and North Anna over the next three years is estimated to be approximately $12.2 million and $0.4 million, respectively. These expenditures, which include amounts related to the above referenced NO_x emissions reduction plans, are included in our estimated capital expenditures for the years 2002 through 2004. See “Management’s Discussion and Analysis of Financial Condition and Results of Operations—Liquidity and Capital Resources” in Item 7.

The scientific community, regulatory agencies, and the electric utility industry are examining the issues of global warming and acidic deposition, and the possible health effects of electric and magnetic fields. While no definitive scientific conclusions have been reached regarding these issues, it is possible that new regulations pertaining to these matters could further increase the capital and operating costs of electric utilities.

In December 2000, the EPA announced that to reduce the health risk of mercury exposure, it will regulate emissions of mercury and other air toxins from coal and oil-fired electric utility steam generating units. Clover would be subject to such regulation but because existing pollution control systems on these units currently reduce mercury emissions, we do not anticipate installation of additional equipment will be required at this time. The EPA currently intends to propose regulations with respect to mercury emissions by December 15, 2003, and issue final regulations by December 15, 2004.

Finally, several studies required by the Clean Air Act examined the health effects of power plant emissions of various hazardous air pollutants. Emissions of other hazardous air pollutants, such as nickel and cadmium, also may become regulated. The EPA expects to follow a rulemaking schedule to establish limits on these emissions that would require compliance by 2007 to 2008. Depending on the outcome of this rulemaking, significant capital expenditures may be incurred at Clover.

Nuclear

North Anna is subject to regulation by the NRC. Operating licenses issued by the NRC are subject to revocation, suspension, or modification, and the operation of a nuclear unit may be suspended if the NRC determines that the public interest, health, or safety so requires. From time to time, new NRC regulations require changes in the design, operation, and maintenance of existing nuclear reactors. The operating licenses for North Anna Units 1 and 2 are scheduled to terminate in 2018 and 2020, respectively. In May 2001, Virginia Power applied to the NRC to extend the operating licenses for both North Anna units for an additional 20 years. The NRC has accepted and is reviewing the application and will perform site visits and review the application in detail over the next two years. See Notes 1 and 10 to the Consolidated Financial Statements for a discussion of other laws and regulations affecting us as a result of our ownership interest in North Anna.

Under the Nuclear Waste Policy Act, the DOE is required to provide for the permanent disposal of spent nuclear fuel produced by nuclear facilities, such as North Anna, in accordance with contracts executed with the DOE. However, since the DOE did not begin accepting spent fuel in 1998 as specified in its contracts, Virginia Power is providing on-site spent nuclear fuel storage at the North Anna facility. Virginia Power will continue to safely manage its spent nuclear fuel until the DOE begins accepting the spent nuclear fuel.

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Item 2.    Properties

Information with respect to our properties is set forth under the caption “Power Supply Resources” included in Item 1 and is incorporated herein by reference.

Item 3.    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 our results of operations or financial condition, there is no other litigation pending or threatened against us.

Item 4.    Submission of Matters to a Vote of Security Holders

None

PART II

Item 5.    Market for Registrant’s Common Equity and Related Stockholder Matters

Not Applicable

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Item 6.    Selected Financial Data

The selected financial data below present selected historical information relating to our financial condition and results of operations. The financial data for the five years ended December 31, 2001, are derived from our audited consolidated financial statements. You should read the information contained in this table together with our financial statements, the related notes to the financial statements, and the discussion of this information in “Management’s Discussion and Analysis of Financial Condition and Results of Operations.”

	Year Ended December 31,
	2001		2000		1999		1998		1997
	(in thousands except ratios)
Statement of Operations Data:
Operating Revenues	$	487,287	$	422,031	$	390,060	$	364,221	$	358,505
Operating Margin		44,895		44,696		53,325		66,195		72,336
Net Margin		8,440		8,229		9,839		12,094		12,799
Margins for Interest Ratio(1)		1.20		1.20		1.20		1.20		1.20

(1) Under our Indenture of Mortgage and Deed of Trust, dated as of May 1, 1992, with Crestar Bank, as amended and supplemented (the “Existing Indenture”), we are required, subject to regulatory approval, to establish and collect rates which are reasonably expected to yield margins for interest (“MFI”) for the 12-month period commencing with the effective date of such rates equal to at least 1.20 times total interest charges during such 12-month period on all indebtedness secured under the Existing Indenture or by a lien equal or prior to the lien of the Existing Indenture (“MFI Ratio”). Our MFI Ratio is determined by dividing our MFI by our Interest Charges (as defined in the Existing Indenture) where: MFI is defined as the sum of (i) net margins for the period, plus (ii) Interest Charges and accruals for Federal and other taxes imposed on income, minus (iii) the amount, if any, by which certain non-operating margins otherwise includable in net margins exceed 60% of such net margins. Interest Charges are defined as total interest charges (whether capitalized or expensed) on all indebtedness secured under the Existing Indenture or by a lien equal or prior to the lien of the Existing Indenture, including amortization of debt discount and expense or premium.

	December 31,
	2001			2000			1999			1998			1997
	(in thousands except ratios)
Balance Sheet Data:
Electric Plant:
In service, net	$	567,738		$	601,300		$	686,508		$	753,375		$	798,383
Construction work in progress		127,270			47,598			13,023			13,591			12,701
Net electric plant		695,008			648,898			699,531			766,966			811,084
Investments		356,048			246,730			262,024			211,044			191,611
Other Assets		205,094			114,944			88,957			148,534			127,561
Total Assets	$	1,256,150		$	1,010,572		$	1,050,512		$	1,126,544		$	1,130,256
Capitalization:
Patronage capital(1)	$	225,538		$	224,598		$	216,369		$	206,530		$	197,552
Accumulated other comprehensive income		398			(256	)		(2,316	)		697			344
Long-term debt		625,232			449,823			509,606			584,630			605,878
Total Capitalization	$	851,168		$	674,165		$	723,659		$	791,857		$	803,774
Equity Ratio(2)		26.5	%		33.3	%		29.8	%		26.1	%		24.6	%

(1) In 2001 and 1998, we retired $7.5 million and $3.1 million, respectively, of patronage capital.

(2) Equity ratio equals patronage capital divided by the sum of our long-term debt and patronage capital.

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Item 7.    Management’s Discussion and Analysis of Financial Condition and Results of Operations

Caution Regarding Forward-Looking Statements

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

Factors Affecting Results

Margins

We operate on a not-for-profit basis and, accordingly, seek to generate revenues sufficient to recover our cost of service and produce margins sufficient to establish reasonable reserves, meet financial coverage requirements, and accumulate additional equity required by our board of directors. Revenues in excess of expenses in any year are designated as net margins in our Consolidated Statements of Revenues, Expenses and Patronage Capital. We designate retained net margins in our Consolidated Balance Sheets as patronage capital, which we assign to each of our members on the basis of its class of membership and business with us. Any distributions of patronage capital are subject to the discretion of our board of directors and restrictions contained in our Indenture of Mortgage and Deed of Trust, dated as of May 1, 1992, with Crestar Bank (predecessor to SunTrust Bank), as trustee, as amended and supplemented (collectively the “Existing Indenture”).

Formulary Rate

Components.    Under a formulary rate accepted by the Federal Energy Regulatory Commission (“FERC”), we develop rates for sales of power to our member distribution cooperatives intended to permit collection of revenues which will equal the sum of:

• all of our costs and expenses,

• 20% of our total interest charges, and

• additional equity contributions approved by our board of directors.

The formulary rate has three components: a demand rate, a base energy rate, and a fuel factor adjustment. The demand rate is designed to recover all of our capacity-related costs, which are primarily fixed costs, such as depreciation expense, interest expense, administrative and general expenses, capacity costs under power purchase contracts with third parties, capacity-related transmission costs, and our margin requirements. 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 over or under collects all of our energy costs, we refund or collect the difference through a fuel factor adjustment. Of these components, only the base energy rate is a fixed rate that requires FERC approval prior to adjustment.

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The formulary rate identifies the costs that we can collect through the demand rate and the fuel factor adjustment, but not the actual amounts to be collected. Our costs to be collected under the components of 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 revisions 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 adequately recover our energy costs. We revise the fuel factor adjustment accordingly.

Existing Indenture.    Subject to any necessary regulatory approvals, the Existing Indenture requires us to establish and collect rates for the use or the sale of the output, capacity, or service of our electric generation, transmission, and distribution system which are reasonably expected to yield margins for interest for the 12-month period commencing with the effective date of the rates equal to at least 1.20 times total interest charges during that 12-month period.

Margins for interest under the Existing Indenture equal the total of net margins plus total interest charges and income tax accruals for the applicable period less:

• the amount, if any, by which non-operating margins (other than interest earnings on investments held by the trustee or on investments held by any trustee for the purpose of decommissioning or dismantling any of our assets) included in our net margins exceed 60% of net margins for that period; and

• the net earnings or losses of property with a fair value in excess of $25,000 released from the lien of the Existing Indenture during the period or thereafter.

Interest charges under the Existing Indenture equal our total interest charges (whether capitalized or expensed) on (i) all obligations under the Existing Indenture, (ii) indebtedness secured by a lien equal or prior to the lien of the Existing Indenture, and (iii) obligations secured by liens created or assumed in connection with a tax-exempt financing for the acquisition or construction of property used by us, in each case including amortization of debt discount and expense or premium.

Since 1992, when the Existing Indenture became effective, our non-operating margins have not exceeded 60% of our net margins in any year. We do not anticipate that our non-operating margins (after the above-described exclusions) will exceed 60% of net margins in the foreseeable future and believe that our formulary rate, and the rates and charges established under the wholesale power contracts with our member distribution cooperatives, will enable us to achieve the required margins for interest. Since 1992, we have always achieved a margins for interest ratio under the Existing Indenture of at least 1.20.

Amended Indenture.    We have entered into a supplemental indenture to the Existing Indenture which, when some provisions of it become effective, will amend several provisions of the Existing Indenture. The amendments include:

• modification of our rate covenant;

• modification of restrictions on the issuance of additional bonds and distributions to members; and

• elimination of restrictions on investments and short-term indebtedness and the obligation to make depreciation deposits.

These provisions of the supplemental indenture will become effective when the holders of a majority of the obligations outstanding under the Existing Indenture consent to the amendments (“Amendment Date”). The Existing Indenture as amended by these provisions of the supplemental indenture on the Amendment Date is referred to as the “Amended Indenture.”

Restated Indenture.    We also have entered into an Amended and Restated Indenture which, when it becomes effective, will amend and restate the Existing Indenture or the Amended Indenture, as the case may be (“Restated Indenture”). The Restated Indenture includes all of the amendments set forth in the Amended Indenture and releases the lien of the Existing Indenture or the Amended Indenture, as the case may be. The Restated Indenture will become

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effective when all obligations under the Existing Indenture issued prior to the 2001 Series A Bonds cease to be outstanding or when the holders of those obligations consent to the release of the lien of the Existing Indenture or the Amended Indenture, as the case may be (“Release Date”). The Release Date may occur before the Amendment Date and, in that case, the Amended Indenture will not become effective because the Restated Indenture includes all of the amendments set forth in the Amended Indenture. We do not anticipate that the Release Date will occur prior to December 2003. References to the “Indenture” mean the Existing Indenture, the Amended Indenture or the Restated Indenture, whichever is in effect.

After the earlier of the Amendment Date or the Release Date, the Amended Indenture or the Restated Indenture will require us, subject to any necessary approval or determination of any regulatory or judicial authority with jurisdiction, to establish and collect rates reasonably expected to yield margins for interest for each fiscal year equal to 1.10 times total interest charges for the fiscal year. Interest charges under the Amended Indenture are calculated in the same manner as under the Existing Indenture with the exclusion of capitalized interest. Interest charges under the Restated Indenture equal interest charges (other than capitalized interest) on all obligations under the Restated Indenture and all of our other obligations (other than subordinated indebtedness) to repay borrowed money or the deferred purchase price of property or services, including amortization of debt discount and premium on issuance, but excluding the interest charges on indebtedness attributed to any capitalized lease or similar agreement. After the earlier of the Amendment Date or the Release Date, margins for interest will equal the sum of our net margins, revenues that are subject to refund at a later date which were deducted in the determination of net margins, non-recurring charges that may have been deducted in determining net-margins, total interest charges (calculated as described above); and income tax accruals imposed on income after deduction of total interest for the applicable period.

In calculating margins for interest under the Amended Indenture and the Restated Indenture, we factor in any item of net margin, loss, income, gain, earnings or profits of any of our affiliates or subsidiaries, only if we have received those amounts as a dividend or other distribution from the affiliate or subsidiary or if we have made a contribution to, or payment under a guarantee or like agreement for an obligation of, the affiliate or subsidiary. Any amounts that we are required to refund in subsequent years do not reduce margins for interest as calculated under the Amended Indenture or the Restated Indenture for the year the refund is paid.

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. See “Business—Member Distribution Cooperatives—Wholesale Power Contracts” in Item 1. There was no adjustment to revenues from power sales to our member distribution cooperatives under our Margin Stabilization Plan in 2001 or 2000. We reduced revenues from power sales and increased accounts payable—members $7.2 million under our Margin Stabilization Plan in 1999.

Strategic Plan Initiative

In the late 1990’s, the possibility of retail competition and projected lower market power rates caused us to focus on reducing our costs. Specifically, we sought to lower our costs so that our member distribution cooperatives could set rates for power at or below market rates for power by the time competition for retail customers began in Virginia in 2004. See “Future Issues—Competition and Changing Regulations.” Our efforts to meet this objective became known as the “Strategic Plan Initiative.” Because our estimates of future market rates for power constantly change, we monitor and periodically reevaluate our methods and progress in achieving the goal of the Strategic Plan Initiative to identify and implement any appropriate changes.

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Our actions to reduce costs pursuant to the Strategic Plan Initiative have included:

• restructuring our power purchase contracts with neighboring utilities to reduce the term of the contracts or reduce the price or the amount of the capacity or energy or both purchased under the contracts;

• accelerating amortization of regulatory assets relating to North Anna and other items;

• accelerating depreciation of our generating facilities; and

• reducing our indebtedness by purchasing our bonds issued under the Indenture in the market.

See “Business—Power Supply Resources—Other Power Supply Resources—Power Purchase Contracts” in Item 1. The recovery of accelerated amortization and depreciation through our formulary rate generated cash. See “Formulary Rate.” We have used a portion of this cash to purchase bonds issued under the Existing Indenture. As a result, we have reduced our costs in future years in three ways: (1) we will incur less amortization and depreciation expense in the future, (2) our interest expense will be lower in the future as a result of less indebtedness outstanding under the Indenture, and (3) lower interest expense will require a lower level of margins for interest.

Our projections of future market prices of power are key factors in determining our progress in meeting the Strategic Plan Initiative’s objective. Beginning in 1999, our projections of market prices for power began to rise significantly. In June 2001, based on then current market projections, we believed that the $160.3 million we had accumulated through the Strategic Plan Initiative since 1998 and held as cash or investments, or already applied to reduce our indebtedness, was sufficient to reduce our costs to a level which would enable the member distribution cooperatives’ rates for power to their customers to be at or below projected market rates by January 1, 2004. As a result, we ceased recording accelerated depreciation of our generating facilities effective June 1, 2001.

Market prices for power can change significantly, however, due to several factors that we cannot control or predict. These factors include, among others, the price of fuel (including natural gas), the implementation of restructuring legislation, the amount of new generating capacity constructed by competitors, and the availability of transmission capacity into the service territories of our member distribution cooperatives. For these reasons, we cannot predict whether the member distribution cooperatives’ rates for power to their customers actually will be at or below market rates by January 1, 2004. We will continue to evaluate the various factors that impact our costs and the projected market prices of power in 2004 and take additional actions as appropriate in our efforts to meet the objective of the Strategic Plan Initiative.

Tax Status

To maintain our tax-exempt status under the Internal Revenue Code of 1986, as amended (the “Internal Revenue Code”), we must receive at least 85% of our gross receipts from our members. The major components of our non-member receipts include:

• investment interest;

• income on the decommissioning fund for North Anna;

• interest from deposits associated with two long-term lease transactions related to Clover; and

• sales of excess energy to non-members.

See “Business—Power Supply Resources—North Anna” and—“Clover” in Item 1.

If, in any given year, our member receipts are less than 85% of gross receipts, we would become a taxable entity in that year, and the potential tax liability could be significant. Our ability to maintain our tax-exempt status is dependent upon many factors, several of which are outside of our control, such as weather-related power sales and interest rates. Additionally, a decrease in member revenues resulting from the effect of retail competition could also cause us to lose our tax-exempt status. See “Competition and Changing Regulations.” We regularly monitor the

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level of our non-member gross receipts to assist us in making adjustments to preserve our tax-exempt status. Our member receipts in each year have been in excess of 85% of total gross receipts.

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’ requirements for power and our formulary rate for sales of power to our member distribution cooperatives. Our formulary rate is based on our cost of service in meeting these requirements. See “Factors Affecting Results—Formulary Rate.” Our member revenues by formulary rate component, energy sales to our members, and average member cost per megawatt-hour for the past three years were as follows:

	Year Ended December 31,
	2001		2000		1999
Member revenues (in thousands)
Demand	$	203,593	$	250,817	$	244,907
Base energy rate		164,632		160,530		150,454
Fuel factor adjustment		108,382		3,590		(6,393	)
Total Member Revenues	$	476,607	$	414,937	$	388,968
Energy sales (in MWh)		9,121,003		8,986,840		8,424,048
Average member cost (per MWh)(1)	$	52.25	$	46.17	$	46.17

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

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

• growth in the number of consumers,

• growth in consumers requirements for power, and

• seasonal weather fluctuations.

Weather affects the demand for electricity. Although the exact amount of sales attributable to weather conditions cannot be quantified, extreme temperatures tend to increase the demand for energy to use heating and air conditioning systems. Mild weather generally reduces the demand because heating and air conditioning systems are operated less. Other factors affecting our distribution cooperatives’ members’ consumers demand for energy include the amount, size, and usage of electronics and machinery and the expansion of operations among their commercial and industrial customers.

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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 our fuel factor adjustment) for the years 2001, 2000, and 1999 as compared with the prior years were as follows:

	Year Ended December 31,
Change in member revenues due to change in:	2001 Compared to 2000			2000 Compared to 1999			1999 Compared to 1998
	(in thousands)
Sales:
Demand sales volume	$	2,591		$	17,595		$	16,465
Energy sales volume		2,450			9,624			7,723
Total change in sales volume		5,041			27,219		$	24,188
Rates:
Demand rate		(49,815	)		(11,684	)		(9,984	)
Energy rate		106,444			10,434			11,332
Total change in rates		56,629			(1,250	)		1,348
Total change in member revenues	$	61,670		$	25,969		$	25,536

2001 Compared to 2000.    Total member revenue for the year ended December 31, 2001, increased by $61.7 million, or 14.9%, over the same period in 2000 primarily as a result of an increase in our average energy rate. The increase was offset partially by a decrease in demand revenues resulting from a decrease in our average demand rate.

Our average energy rate (including our base energy rate and our fuel factor adjustment) in 2001 increased 63.9% over 2000 as a result of changes in our fuel factor adjustment. Our base energy rate is a fixed rate in our formulary rate and did not change. We increased our fuel factor adjustment for two reasons. First, our energy costs were higher than we projected and we needed to recover energy costs that we previously incurred but did not fully recover under our base energy rate and existing fuel factor adjustment. Second, we increased our fuel factor adjustment to a level that, combined with our base energy rate, we anticipated would adequately recover future energy costs. These higher energy costs relate to, among other items, short-term power purchases, congestion charges, and coal purchases.

The increase in our energy costs was partially offset by a 19.7% decrease in our average demand rate in 2001 as compared to 2000, which resulted from three separate reductions in our demand rate. We reduced our demand rate by approximately 1.3% effective January 1, 2001, as a result of the elimination of the gross receipts tax, which had applied to providers of electricity in Virginia. We reduced our demand rate approximately 20.0% in April 2001 to recover evenly the remaining amounts then anticipated to be collected under our Strategic Plan Initiative. Finally, in response to new projected power prices, effective June 1, 2001, we stopped recovering accelerated depreciation under the Strategic Plan Initiative, which had the effect of amending our budget and automatically reducing our demand rate by the terms of the formulary rate and the wholesale power contracts with the member distribution cooperatives. At the same time, our board of directors authorized a revenue deferral plan for the period June 1, 2001 through December 31, 2002. Under this plan, we collected as deferred revenue approximately $11.4 million through our demand rate in 2001, which is included in other liabilities and depreciation, amortization and decommissioning expense. We will use these additional amounts to partially offset the anticipated increase in the demand rate in 2002. The net effect of these two actions by our board of directors was a decrease in our demand rate of approximately 5.0% effective June 1, 2001.

2000 Compared to 1999.    Member revenues increased by $26.0 million, or 6.7%, from 1999 to 2000 as a result of an increase in the amount of power we sold to our member distribution cooperatives to meet the power requirement of their customers. The number of customers buying power from our member distribution cooperatives grew by 3.1% while the average amount of power purchased by these customers increased by 3.3%.

Our average member cost per megawatt-hour did not change from 1999 to 2000. Our average energy rate (including the base energy rate and the fuel factor adjustment) increased 6.8% in 2000, however, this increase was offset by a reduction in our demand rate of approximately 4.0% that became effective April 1, 2000.

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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 the Pennsylvania—New Jersey—Maryland Interconnection, LLC (“PJM”) under its rates for providing energy imbalance service. Excess energy from Clover is sold to Virginia Electric and Power Company (“Virginia Power”) pursuant to the requirements of the Clover Operating Agreement. See “Business—Power Supply Resources—Purchased Power” in Item 1.

Non-member revenues in 2001 increased $3.6 million over 2000 primarily as a result of an increase in sales of energy to PJM. During the first eight months of 2001, we purchased the majority of the energy for our member distribution cooperatives located on the Delmarva Peninsula under an energy contract that matched those members’ needs for power. Beginning September 1, 2001, we met those needs through a combination of forward contracts and market purchases. During 2000 we purchased fixed amounts of power to meet our peak needs and sold the amounts not needed by those members to PJM.

The $6.0 million increase in non-member revenues in 2000 as compared to 1999 resulted from the sale of excess purchased energy to PJM. In 2000, we purchased sufficient blocks of power to meet our peak needs on the Delmarva Peninsula. During non-peak periods, the portions of these purchases not needed to meet the energy needs of our member distribution cooperatives were sold to PJM. During 1999, we purchased most of our energy under contracts that supplied varying amount of energy to meet our needs. The majority of our non-member revenues in 1999 were sales to Virginia Power of excess energy generated from Clover.

Operating Expenses

We have an 11.6% undivided ownership interest in the North Anna Nuclear Power Station (“North Anna”) and a 50% undivided ownership interest in Clover. In addition to power generated at Clover and North Anna, we purchase power from Virginia Power, Public Service Electric & Gas Company (“PSE&G”), Conectiv Energy (“Conectiv”) and Pennsylvania Power & Light (“PPL”), and others. Old Dominion’s energy supply for the past three years was as follows:

	Year Ended December 31,
	2001	2000	1999
	(in megawatt-hours)
Generated:
Clover	3,342,398	3,428,357	3,198,062
North Anna	1,519,223	1,767,053	1,775,915
Total generated	4,861,621	5,195,410	4,973,977
Purchased:
Virginia area	2,332,045	1,975,503	1,713,959
Delmarva area	2,285,585	1,943,920	1,831,589
Other	223,608	223,782	208,231
Total purchased	4,841,238	4,143,205	3,753,779
Total available energy	9,702,859	9,338,615	8,727,756

Market forces influence the structure of new power supply contracts we enter into. 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. See “Future Issues—Reliance on Energy Purchases.” In Virginia, capacity and energy requirements are provided principally by Virginia Power, American Electric Power—Virginia, and Allegheny Power Resources. See “Business—Power Supply Resources—Other Power Supply Resources” in Item 1.

Generating facilities, particularly nuclear generating facilities 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

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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 past three years as a percentage of the maximum dependable capacity rating of the facilities was as follows:

	North Anna						Clover
	Year Ended December 31,						Year Ended December 31,
	2001		2000		1999		2001		2000		1999
Unit 1	87.9	%	92.0	%	103.8	%	86.8	%	88.4	%	82.3	%
Unit 2	74.4		101.8		91.4		88.0		90.3		84.7
Combined	81.2		96.9		97.6		87.4		89.4		83.5

North Anna.    North Anna Unit 1 was on-line for 487 consecutive days before it began a scheduled refueling outage on September 10, 2001. The unit was returned to service on October 10, 2001. Before beginning a scheduled maintenance outage on March 12, 2000, North Anna Unit 1 ran for 522 days without outage. The Unit was returned to service on April 8, 2000.

Before beginning a scheduled refueling outage on March 11, 2001, North Anna Unit 2 was online 340 days. The unit was returned to service on April 10, 2001. The unit was brought off-line on October 28, 2001, for inspection and repair and returned to service on December 15, 2001. North Anna Unit 2 experienced only minor unscheduled outages during the year 2000.

There were no significant unplanned outages at North Anna during 1999.

Clover.    During 2001, Clover Unit 1 was off-line for 13 days in March for a scheduled maintenance outage. The unit had previously been online for 276 consecutive days. At December 31, 2001, Clover Unit 1 had been on-line for 85 consecutive days following an unscheduled maintenance outage. Clover Unit 1 was off-line for 15 days in April 2000 for a scheduled maintenance outage.

Clover Unit 2 was off-line for 15 days in April 2001 for a scheduled maintenance outage and had been on-line for 241 consecutive days prior to that. Clover Unit 2 experienced only minor outages during 2000.

During the summer of 1999, both Clover units experienced very low water flow due to lengthy drought conditions in Virginia. As a result, the units operated to meet peak capacity requirements during the day; but, beginning on August 7, 1999, the power generated at night was reduced on each unit to 150 MW in order to conserve water. On August 27, 1999, the units were authorized to resume full operations.

The major components of our operating expenses for the years ended December 31, 2001, 2000, and 1999, were as follows:

	Years Ended December 31,
	2001		2000		1999
	(in thousands)
Fuel	$	60,699	$	49,578	$	46,045
Purchased power		267,518		170,428		162,242
Operations and maintenance		34,758		34,855		34,096
Administrative and general		23,064		19,602		18,659
Depreciation, amortization and decommissioning		53,078		94,257		68,015
Taxes, other than income taxes		3,275		8,615		7,678
Total operating expenses	$	442,392	$	377,335	$	336,735

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2001 Compared to 2000.    Our aggregate operating expenses in 2001 increased $65.1 million, or 17.2%, over 2000 because of an increase in energy costs, which we recover through our base energy rate and the fuel factor adjustment. Primarily as a result of rising energy prices, our average cost of purchased power rose 34.3% in 2001 as compared to 2000. We have secured the majority of our energy needs for 2002 and 2003 at fixed prices that are below those that we paid in 2001. The average cost of fuel generated from Clover and North Anna increased 30.8% in 2001 as compared to 2000 because of the higher price of coal and fuel inventory adjustments. These increases were offset by a $41.2 million, or 43.7%, decrease in depreciation, amortization, and decommissioning expense because we ceased recording accelerated depreciation on our generating facilities effective June 1, 2001. Accelerated depreciation for 2001 and 2000 was $18.5 million and $65.0 million, respectively.

Administrative and general expenses increased in 2001 by $3.5 million, or 17.7%, primarily because of pre-construction activities for the combustion turbine facilities, the service fee paid to Aces Power Marketing LLC (“APM”) in connection with assisting us in managing our energy purchases, and additional administrative and general expenses relating to North Anna and Clover. Taxes, other than income taxes, decreased in 2001 as compared to 2000 because we are no longer subject to the Virginia gross receipts tax as of January 1, 2001.

2000 Compared to 1999.    Our aggregate operating expenses increased $40.6 million, or 12.1%, in 2000 as a result of a 6.8% increase in our energy sales and a $21.3 million, or 48.7%, increase in the amount of accelerated depreciation recorded under our Strategic Plan Initiative. At December 31, 2000, we had recorded $65.0 million of accelerated depreciation as compared to $43.7 million in 1999.

Administrative and general expenses increased in 2000 primarily because of legal and engineering consulting fees related to pre-construction activities for the combustion turbine facilities.

Other Items

Investment Income.    Investment income decreased in 2001 by $1.0 million, or 23.7%, as compared to 2000 primarily because of a decrease in our average investments and a reduction in the interest rate on our investments. Our average investments decreased primarily as a result of aggregate payments of $100.5 million made on combustion turbine generators to be used in connection with the combustion turbine facilities, of which $61.0 million was paid in 2001. The combustion turbine generator payments were funded with liquidated investments, cash and cash equivalents, and a portion of the proceeds of the issuance of $215.0 million of additional indebtedness under the Indenture. See “Liquidity and Capital Resources—Sources—Financings.”

Investment income decreased $1.5 million, or 26.3%, in 2000 as compared to 1999 because of a decrease in invested cash and cash equivalents resulting from the purchase of $33.3 million and $49.3 million of outstanding debt in 2000 and 1999, respectively, and $39.5 million in payments made for generators for the combustion turbine facilities. Additionally, on average we earned less interest on our investments in 2000.

Interest Charges.    The primary factors affecting our interest expense are scheduled payments of principal on our indebtedness, prepayments of indebtedness relating to the Strategic Plan Initiative, issuance of new indebtedness, and capitalized interest. See “Factors Affecting Results—Strategic Plan Initiative.”

Interest charges, net, increased minimally in 2001. Increased interest charges resulting from our issuing additional indebtedness under the Indenture in the third quarter of 2001 were offset by lower interest charges resulting from our purchase of $3.6 million and $33.3 million of our outstanding debt in 2001 and 2000, respectively, our payment of $28.5 million in principal in 2000, and $0.7 million of capitalized interest on the Rock Springs combustion turbine facility.

Interest charges, net, decreased $8.0 million, or 16.4%, in 2000 because we purchased $33.3 million and $49.3 million of our outstanding debt in 2000 and 1999, respectively, and made scheduled debt principal payments of $28.5 million in 1999.

Net Margin.    Our net margin, which is a function of our interest charges, increased $0.2 million, or 2.6%, in 2001 as compared to 2000, because our interest expense was slightly higher due to our issuance of indebtedness under the

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Indenture in 2001, which offset the effects of our purchases of outstanding debt and scheduled principal payments. Our net margin in 2000 decreased $1.6 million, or 16.4%, as compared to 1999 because we reduced our interest charges through scheduled principal payments and the purchase of outstanding indebtedness under our Existing Indenture in accordance with our Strategic Plan Initiative. See “Factors Affecting Results—Strategic Plan Initiative.”

Financial Condition

The principal changes in our financial condition during 2001 resulted from construction expenditures associated with our combustion turbine facilities and an increase in long-term indebtedness from the issuance of $215.0 million of indebtedness under the Indenture. The unexpended proceeds are included in other investments.

Our deferred energy balance increased from $15.4 million at December 31, 2000 to $18.2 million at December 31, 2001 because the base energy rate and fuel factor adjustment of our formulary rate inadequately recovered increased energy costs over the period. The fuel factor adjustment was increased to collect these energy costs and to attempt to reduce the deferred energy balance. See “Results of Operations—2001 Compared to 2000.” At February 28, 2002, our deferred energy balance had been fully collected from our member distribution cooperatives.

Construction work-in-progress and accounts payable increased primarily because of costs incurred for the development of our combustion turbine facilities.

Liquidity and Capital Resources

Sources

Cash generated by our operations, issuances of indebtedness and, periodically, borrowings under available lines of credit provide our sources of liquidity and capital.

Operations.    Historically, our operating cash flows have been sufficient to meet our short and long-term capital expenditures relating to the operation of North Anna and Clover, our debt service requirements and our ordinary business operations. Our operating activities provided cash flows of $74.5 million, $79.5 million, and $75.5 million in 2001, 2000, and 1999.

Lines of Credit.    In addition to liquidity from our operating activities, we maintain committed lines of credit to cover short-term funding needs. Currently, we have short-term committed variable rate lines of credit in an aggregate amount of $210 million. Of this amount, $95 million is available for general working capital purposes and $115 million is available for capital expenditures related to the development and construction of three combustion turbine facilities, known as “Rock Springs,” “Louisa,” and “Marsh Run,” by three separate subsidiaries or other generating facilities. See “Business—Power Supply Resources—Combustion Turbine Facilities” under Item 1.

The Existing Indenture limits our ability to borrow under these facilities. Under the Existing Indenture, our short-term indebtedness may not exceed the greater of $100 million and 15% of our total long-term debt and equities, or $127.7 million, as of December 31, 2001. We also have a $30.0 million uncommitted short-term line of credit. At December 31, 2001 and 2000, we had no short-term borrowings outstanding under any of these arrangements. We expect the working capital lines of credit to be renewed as they expire. We expect the construction-related lines of credit to be renewed until no longer necessary for the development and construction of the combustion turbine facilities.

Financings.    We fund the portion of our capital expenditures that we are not able to supply from operations through financings in the market. Since 1983, these capital expenditures have consisted of the costs related to the acquisition of our interest in North Anna and our share of the costs to construct Clover, and other capital improvements and additions to North Anna and Clover.

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In September 2001, we issued $215.0 million of 2001 Series A Bonds under the Existing Indenture. The bonds bear interest at 6.25% and mature in 2011. The proceeds will be used primarily for the construction of our combustion turbine facilities and the retirement of our higher cost outstanding debt.

During the past three years, we have refinanced $3.6 million of our First Mortgage Bonds, 1992 Series C, due 1999 through 2001. The refinanced bonds are due in 2002 at interest rates ranging from 2.60% to 5.25%.

Other.    Through our three subsidiaries, we are seeking Rural Utilities Service (“RUS”) guaranteed Federal Financing Bank loans to provide long-term financing for the cost of developing and constructing the combustion turbine facilities. The subsidiaries have submitted applications to RUS for loan guarantees to finance the entire cost of all three facilities. We are currently negotiating terms and conditions for the Rock Springs loan guarantee with the goal of obtaining funds under this loan guarantee by mid-year 2002. We cannot predict, however, whether any subsidiary will obtain an RUS-guaranteed loan, and if so, the amount and timing of the loan.

Uses

Our uses of liquidity and capital relate to funding our working capital needs, investment activities and financing activities. Substantially all of our investment activities relate to capital expenditures in connection with our generating facilities. In particular, the development and construction of the combustion turbine facilities currently are requiring significant capital expenditures. See “Uses—Capital Expenditures” and “Business—Power Supply Resources—Combustion Turbine Facilities” in Item 1. We expect that cash flows from our operations, the net proceeds of our issuance of indebtedness under the Existing Indenture in 2001, and existing lines of credit will be sufficient to meet our operational and capital requirements until the fourth quarter of 2002.

We intend to secure long-term sources of financing for the construction of the facilities through RUS-guaranteed loans to our subsidiaries or the issuance of additional indebtedness under the Indenture if the loans are not obtained or available or otherwise are not sufficient to meet our financing requirements. To the extent these amounts are financed on an interim basis under lines of credit, we anticipate that those borrowings will be repaid with the proceeds of an RUS-guaranteed loan or the offering of additional long-term indebtedness under the Indenture.

Capital Expenditures.    We regularly forecast our capital expenditures as part of our long-term business planning activities. We review these projections frequently in order to update our calculations to reflect changes in our future plans, construction costs, market factors, and other items affecting our forecasts. Our actual capital expenditures could vary significantly from these projections. The table below summarizes our actual and projected capital expenditures, including nuclear fuel and capitalized interest, for 1999 through 2004 (in millions):

	Actual						Projected
	1999		2000		2001		2002		2003		2004
Clover	$	0.6	$	2.4	$	1.9	$	9.5	$	4.2	$	1.6
North Anna		6.6		6.8		10.4		9.2		8.2		10.8
Combustion turbine facilities		—		41.2		73.1		256.3		197.7		40.7
Diesel generators		—		—		6.7		0.7		—		—
Other		0.5		0.7		.9		1.4		0.7		0.8
Total	$	7.7	$	51.1	$	93.0	$	276.8	$	211.2	$	53.9

Nearly all of our capital expenditures consist of additions to electric plant and equipment. In addition to the development and construction of combustion turbine facilities, our future capital requirements include our portion of the cost of the nuclear fuel purchased for North Anna and additions to the solid waste and emissions reduction facilities at Clover. Other capital expenditures include the installation of ten diesel generators and the purchase and development of computer software. We intend to use our cash from operations and the currently invested net proceeds of tax-exempt bonds loaned to us to fund all of our capital requirements not related to the development and construction of the combustion turbine facilities through 2004.

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Other Investments.    In March 2001, we purchased a one-sixth interest in APM for $750,000. As part of our investment, we extended a loan to APM in the amount of $500,000. Repayment of the loan is due on or prior to February 15, 2003. In addition, APM has the right to require us to contribute an additional $750,000 to APM as part of a required capital contribution of all investors in APM.

On June 12, 2001, we invested $7.5 million in TEC Trading, Inc. (“TEC Trading”) in exchange for all of its capital stock. We distributed the stock of TEC Trading as a patronage distribution to our member distribution cooperatives on the same date.

Financing Activities.    Pursuant to the Strategic Plan Initiative, we accumulated approximately $160.3 million to reduce our outstanding indebtedness. See “Factors Affecting Results—Strategic Plan Initiative.” Of this amount, we have spent $89.2 million (including premiums and discounts) to purchase indebtedness outstanding under the Indenture. These debt purchases resulted in principal retirements of $3.6 million, $33.3 million, and $49.3 million in 2001, 2000, and 1999, respectively. We intend to use the remaining $71.1 million to purchase additional indebtedness under the Indenture before 2004 in the most economical method from time to time.

Contractual Obligations

In the normal course of business, we enter into long-term arrangements relating to the construction, operation and maintenance of our owned and leased generating facilities, power purchases, the financing of our operations and other matters. See “Business—Power Supply Resources—Other Power Supply Resources—Power Purchase Contracts” in Item 1 and “Future Issues—Reliance on Energy Purchases.” The following table summarizes our long-term contractual obligations at December 31, 2001:

	2002		2003-2004		2005-2008		Thereafter		Total
	(in millions)
Long-term indebtedness	$	39.9	$	44.3	$	95.4	$	564.2	$	743.8
Lease obligations		3.7		7.5		17.4		374.2		402.8
Power purchase obligations		71.0		68.6		—		—		139.6
Construction contracts		206.4		74.9		—		—		284.3
Total	$	321.0	$	195.3	$	112.8	$	938.4	$	1,567.5

Long-Term Indebtedness.    At December 31, 2001, nearly all of our long-term indebtedness was issued under the Indenture. This indebtedness includes bonds issued to the public and bonds issued to local governmental authorities in consideration for loans to us of the proceeds of tax-exempt offerings of indebtedness by those governmental authorities.

Lease Obligations.    In 1996, we entered into two separate long-term lease transactions of our undivided interests in each of Clover Unit 1 and Clover Unit 2. See “Business—Power Supply Resources—Clover” in Item 1 and “Clover Lease Arrangements.” Our obligations described above relate to a portion of our obligations under these leases, including periodic basic rent. We fund the payment of these obligations through the application of the proceeds of investments we purchased at the time we entered into the leases. The investments are rated “AAA” by Standard & Poor’s Ratings Services (“S&P”) and “Aaa” by Moody’s Investors Service (“Moody’s”).

Power Purchase Contracts.    As part of our power supply strategy, we have entered into several agreements for the purchase of capacity and energy in order to meet our member distribution cooperatives’ requirements. See “Business—Power Supply Resources—Other Power Supply Resources—Power Purchase Agreements” in Item 1 and “Future Issues—Reliance on Energy Purchases.” Some of these power purchase agreements contain firm capacity and minimum energy purchase obligations. We have structured most of these agreements to expire as the combustion turbine facilities become operational.

Construction Contracts.    We have entered into several agreements relating to the development and construction of the combustion turbine facilities, including turbine purchase agreements, engineering, procurement and

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construction agreements, interconnection agreements, and joint ownership agreements. In some cases, we entered into the agreements directly and later assigned our interest in the agreement to the subsidiary owning the facility. In other cases, the subsidiary has entered into the agreement directly with a third party and we have guaranteed the subsidiary’s obligations. At December 31, 2001, nearly all of the construction agreements entered into related to the Rock Springs facility because construction of the Louisa and Marsh Run facilities has not yet begun. See “Business—Power Supply Resources—Combustion Turbine Facilities” in Item 1.

At December 31, 2001, we had outstanding letters of credit totaling $19.6 million to support a power purchase arrangement and a construction contract associated with the Rock Springs facility. One of these letters of credit, in the amount of $5.5 million, expired December 31, 2001. The remaining $14.1 million letter of credit expires March 31, 2002, and is expected to be renewed in an equal or lesser amount.No letters of credit were outstanding as of December 31, 2000.

Significant Contingent Obligations

In addition to these existing contractual obligations, we have significant contingent obligations. These obligations primarily relate to our power purchase arrangements and leases of our interest in Clover. See “Business—Power Supply Resources—Clover” in Item 1.

To facilitate the ability of TEC Trading to sell power in the market, we have agreed to guarantee a maximum of $42.5 million of TEC Trading’s delivery and payment obligations associated with its energy trades if requested. See “Business—TEC Trading” in Item 1. Our guarantee of TEC Trading’s obligations will enable it to maintain sufficient credit support to meet its delivery and payment obligations associated with its energy trades. At December 31, 2001, we had not issued any guarantee of TEC Trading’s obligations.

In limited circumstances, we have obligations to provide credit support if our obligations issued under the Indenture are rated below specified thresholds by S&P and Moody’s. These circumstances relate to our sale and leaseback of our interest in pollution control facilities at Clover, our lease and leaseback of our undivided interest in Clover Unit 1 and some of our purchases of power in the market.

In 1994, we sold pollution control facilities relating to Clover Units 1 and 2 to an institutional investor who leased them back to us for a term extending until December 30, 2012. See “Business—Power Supply Resources—Clover” in Item 1. Under the lease, we must provide support in the form of cash, letter of credit, guarantee, or other collateral satisfactory to the lessor within 90 days after the obligations issued under the Indenture are rated less than investment grade (i.e., “BBB-” by S&P or “Baa3” by Moody’s). At December 31, 2001, the maximum amount of collateral we could have been required to provide under this provision was $4.7 million. Under the terms of the lease, this maximum amount declines to zero by December 30, 2004.

In connection with the lease and leaseback of our undivided interest in Clover Unit 1, we agreed to deliver a letter of credit to the institutional investor party to the lease within 90 days after our obligations under the Indenture are rated less than a specified minimum rating. This minimum rating is “A-” by S&P or “A3” by Moody’s provided that our Moody’s rating may fall to “Baa1” if at that time our S&P rating is “A” or better and there is no public announcement of negative ratings implications by either S&P or Moody’s. If our ratings had been below this minimum rating at December 31, 2001, the amount of letter of credit we would have been required to provide was $50.7 million. The amount of any letter of credit required to be delivered in connection with the lease increases to approximately $53.9 million on January 5, 2005, and declines to zero by December 15, 2018.

In addition, like many other utilities, we purchase power in the market pursuant to a form master power purchase and sale agreement (“EEI Form Contract”) prepared by the Edison Electric Institute, an association of U.S. investor-owned electric utilities and industry affiliates. The EEI Form Contract is intended to standardize the terms and conditions of purchases of power in the market and consequently foster trading among utilities. Under the terms of the EEI Form Contract, a utility may agree to provide collateral if its ratings fall below a specified threshold. At December 31, 2001, we were party to eight agreements based on the EEI Form Contract and one other power purchase agreement obligating us to provide collateral if our ratings fell below specified thresholds. Collectively, at

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December 31, 2001, if the ratings by S&P and Moody’s of our obligations issued under the Indenture fell below investment grade (i.e., “BBB-” by S&P or “Baa3” by Moody’s), we would have been obligated to provide credit support in the amount of approximately $18.8 million. This calculation is based on energy prices on December 31, 2001. Depending on how large the difference is between the price of power under the contracts and the price of power in the market at the time of the calculation, this amount could increase or decrease accordingly.

Finally, several of the power purchase agreements we utilize to satisfy our member distribution cooperatives’ capacity and energy requirements obligate us to purchase capacity or energy or both beyond specified minimum amounts based on our requirements. See “Business—Power Supply Resources—Other Power Supply Resources—Power Purchase Agreements” in Item 1.

Clover Lease Arrangements

In connection with each of the Clover leases, we also entered into a payment agreement with a third party providing funding in timing and amount equal to a portion of our obligations under the lease, including periodic basic rent. Our financial statements do not reflect our obligation to pay those portions of such lease obligations or the value of our interests in the payment agreements because we are not primarily liable. At December 31, 2001, both the value of this portion of our lease obligations for Clover Unit 1 or Clover Unit 2, as applicable, as well as the value of our interest in the corresponding payment agreement were equal to approximately $269.4 million and $233.2 million, respectively. The claims paying ability or senior debt obligations of the entities making the payments under the payment agreements are rated “AAA” by S&P and “Aaa” by Moody’s.

Future Issues

Changes in the Electric Utility Industry

The electric utility industry is becoming increasingly competitive as a result of deregulation, competing energy suppliers, new technology, and other factors. The Energy Policy Act of 1992 amended the Federal Power Act and the Public Utilities Holding Company Act to allow for increased competition among wholesale electricity suppliers and increased access to transmission services by such suppliers. A number of other significant factors have affected the operations of electric utilities, including the availability and cost of fuel for the generation of electric energy; the use of alternative fuel sources for space and water heating and household appliances; fluctuating rates of load growth; compliance with environmental and other governmental regulations; licensing and other factors affecting the construction, operation, and cost of new and existing facilities; and the effects of conservation, energy management, and other governmental regulations on the use of electric energy. All of these factors present an increasing challenge to companies in the electric utility industry, including our member distribution cooperatives and us, to reduce costs, increase efficiency and innovation, and improve management of resources.

As a result of these factors, many member distribution cooperatives are providing or considering providing non-traditional products and services such as satellite television, propane and natural gas, and internet and other services. Depending on the impact of competition, there could be reasons for the member distribution cooperatives to restructure their current businesses to operate more effectively under retail competition.

In addition, these factors may cause our member distribution cooperatives to desire greater flexibility in their power supply options in the future, which may require an amendment to their wholesale power contracts. See “Business—Member Distribution Cooperatives—Wholesale Power Contracts.”

Competition and Changing Regulations

Virginia, Maryland, and Delaware have enacted legislation that restructures the electric utility industry and changes the manner in which electricity may be sold to customers. The individual restructuring plans adopted by Virginia, Maryland, and Delaware contain similar components.

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Retail Choice for Power.    The restructuring laws of Virginia, Maryland and Delaware generally deregulate the power component of electric service, permitting all retail customers to purchase power from the supplier of their choice. In other words, the utility with the historically exclusive territory, the incumbent electric utility, no longer has the exclusive right to provide power to customers located in its certificated service territory. Each of these states has implemented a schedule by which each incumbent electric utility will provide its customers with the opportunity to purchase power from licensed power suppliers. Transmission and distribution of power will remain regulated services.

Stranded Costs.    One consequence of the transition to competition for customers is that electric utilities may incur stranded costs. Stranded costs are generally described as the difference between what an electric utility would have recovered under regulated cost of service rates and what that electric utility will recover under competitive market rates. See “—Stranded Costs” below. The new legislation in all three jurisdictions generally allow the incumbent electric utilities an opportunity to recover stranded costs.

Capped Rates.    To address stranded costs and to facilitate the implementation of retail competition, the new legislation in all three states requires the incumbent utility to cap the bundled rates that it can charge customers in its certificated service territory during a specified transition period. These cappedrates are then unbundled, or itemized, into power, transmission and distribution components and, in some cases, a competitive transition charge.

Default Service Provider.    A customer who is either unable or has not selected an alternative power supplier will receive power from its “default” provider. The restructuring laws of Virginia, Maryland and Delaware each designate each of the member distribution cooperatives, at least initially, to be the default provider of power for all customers located in its certificated service territory who do not affirmatively select a competitive power supplier.

All of the customers of our Delaware and Maryland member distribution cooperatives are now free to choose an alternative power supplier. These customers accounted for 20.4% of our capacity requirements in 2001. By January 1, 2004, customers accounting for approximately 99.7% of our capacity requirements in 2001 will be free to choose an alternative power supplier. No timetable currently exists for permitting customers to select their provider of power in West Virginia. The West Virginia customers of our member distribution cooperative providing power in the state accounted for approximately 0.3% of our capacity requirements in 2001.

Distribution Service Provider.    Generally, the new legislation in each state also provides that each incumbent electric utility including, our member distribution cooperatives, still has the exclusive right to provide distribution services in its certificated territory. Member distribution cooperatives in Virginia, Maryland and Delaware also may exclusively provide metering and most billing services to all customers located in their certificated service territories.

Virginia

Retail Choice for Power.    The Virginia restructuring legislation provides for retail choice for power services to be phased in between January 1, 2002 and January 1, 2004, in accordance with a schedule developed by the Virginia State Corporation Commission (the “VSCC”). The member distribution cooperatives in Virginia may each set their own schedule for phase-in of competition between January 1, 2002 and January 1, 2004. Our Virginia member distribution cooperatives, which accounted for approximately 79.3% of our capacity requirement in 2001, are in the process of finalizing their schedules for the introduction of retail competition.

Capped Rates.    The Virginia restructuring legislation caps rates for power from January 1, 2001 to July 1, 2007. The rates of our Virginia member distribution cooperatives are capped at the levels that were in effect on July 1, 1999 in the absence of a petition to the VSCC for an increase in rates prior to January 1, 2001. The requests of three of our member distribution cooperatives for increases in their rates under this provision were approved by the VSCC in December 2001. The VSCC may adjust capped rates to permit the member distribution cooperative to recover their fuel costs. We expect our recent increases in the fuel factor adjustment to recover additional energy costs will be recovered by our Virginia member distribution cooperatives as increased fuel costs. See “Results of Operations—Operating Revenues—2001 Compared to 2000.” Upon petition by a utility, the VSCC may terminate the utility’s capped rates at any time after 2003 if it determines that an effectively competitive market for power exists within that utility’s service

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territory. If capped rates continue in the service territories of our member distribution cooperatives after 2003, each of our member distribution cooperatives may request a one-time change in the distribution component of its capped rate. Additionally, the member distribution cooperatives may seek increases in their capped rates at any time if they are in financial distress beyond their control.

Stranded Costs.    Between January 1, 2001 and January 1, 2007, the member distribution cooperatives may collect stranded costs through a competitive transition charge that will be collected from all customers that choose an alternative power supplier. To establish the competitive transition charge, the VSCC currently is conducting regulatory proceedings to (1) determine the unbundled rate components of power, transmission and distribution, by rate class, for each of our Virginia member distribution cooperatives, and (2) determine the projected market price for power. Once the projected market price for power is determined and allocated to each rate class, the VSCC will subtract it from the power component of the capped rate to determine the applicable competitive transition charge. Our Virginia member distribution cooperatives are then permitted to collect the competitive transition charge from their customers that choose an alternative power supplier during the capped rate period. The competitive transition charge will be adjusted by the VSCC not more than once a year.

Default Service Provider.    Under the restructuring legislation, each of our Virginia member distribution cooperatives will be the default provider of power unless (1) it seeks to become the default service provider in the certificated service territory of another utility, or (2) after July 1, 2004, the VSCC determines that a sufficient degree of competition exists in the service territory and elimination of default service is not contrary to the public interest. The legislation provides that our member distribution cooperatives’ rates for default service will be the same as the capped rates described above for the period from January 1, 2001 to July 1, 2007. After July 1, 2007, the default rates will be based on the member distribution cooperative’s prudently incurred costs of power.

Distribution Service Provider.    Each of our Virginia member distribution cooperatives will remain the exclusive provider of distribution services in its certificated service territory. Our Virginia member distribution cooperatives also will be the exclusive providers of metering and most billing services to all customers located in their certificated service territory.

Maryland

Retail Choice for Power.  �� The Maryland restructuring legislation required our member distribution cooperative in Maryland, Choptank Electric Cooperative (“Choptank”), to present to the Maryland Public Service Commission (“Maryland PSC”) a plan granting all of its cooperative customers a choice in their selection of a power supplier by July 1, 2003. Pursuant to a settlement with the Maryland PSC, Choptank, which accounted for 9.1% of our capacity requirement in 2001, volunteered to offer all of its customers a right to choose their power suppliers on July 1, 2001. In order for a competitive supplier to provide power to Choptank’s customers, the supplier must be qualified by the Maryland PSC and registered with Choptank. As of December 31, 2001, approximately 30 entities had obtained permission from the Maryland PSC to provide power in Maryland but to date no alternative power supplier has registered to serve the customers of Choptank.

Capped Rates and Stranded Costs.    Pursuant to its settlement with the Maryland PSC, Choptank’s rates are capped for a period of four years beginning on July 1, 2001, and ending on June 30, 2005. Choptank’s capped rates were developed using a forecast of its cost (including our forecasted rates) for the capped rate period.

Under the settlement, Choptank’s capped rates were unbundled into components for power, transmission, distribution and a competitive transition charge. The power component of Choptank’s capped rate was determined using forecasts developed in 1998. The Maryland PSC settlement recognized our efforts to mitigate stranded costs under the Strategic Plan Initiative. As part of the settlement, the Maryland PSC approved the collection of a competitive transition charge based on an amount equal to Choptank’s share of our above-market costs as determined under the Strategic Plan Initiative (and other transition costs). The competitive transition charges can be collected during the capped rate period from all of its customers, until we have successfully concluded the Strategic Plan Initiative. See “Factors Affecting Results—Strategic Plan Initiative.”

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On July 14, 2001, Choptank filed a proposal with the Maryland PSC to increase the power component of its rate by the amount of the competitive transition charge that would otherwise be eliminated from the total capped rate because we have ceased collecting amounts pursuant to the Strategic Plan Initiative. See “Factors Affecting Results—Strategic Plan Initiative.” On August 15, 2001, the Maryland PSC approved Choptank’s proposal.

Beginning in 1999, market prices for power rose significantly from the projections made in our 1998 study, causing an increase in our forecasted energy costs. As a result, the amounts recovered under the power component of Choptank’s capped rate may be less than the amounts we charge Choptank for power. The settlement with the Maryland PSC does not allow Choptank to automatically recover these increased energy costs. The settlement does allow Choptank to petition the Maryland PSC to change the capped rates if there are extraordinary circumstances or Choptank is under financial distress.

Choptank’s capped rate does not impair our ability to charge our costs to Choptank under our wholesale power contract with Choptank. If Choptank’s costs are greater than the rate capped by the Maryland PSC, Choptank must absorb any deficiency. If Choptank’s costs are less than the rate capped by the Maryland PSC, Choptank is allowed to retain the surplus. We believe that Choptank will be able to make its payments to us through a combination of revenues derived from the capped rate, revenues from other sources, reductions in its other costs, and its equity.

Default Service Provider.    Under the settlement with the Maryland PSC, Choptank will be the default provider of power services in the territory through 2010. Through June 30, 2005, Choptank will provide default services at the capped rate. Afterwards, Choptank will provide default services for power at a rate no greater than our annualized rates (including transmission charges).

Distribution Service Provider.    Choptank will remain the exclusive provider of distribution services in its certificated service territory. Choptank also will be the exclusive provider of metering and most billing services to all customers located in its certificated service territory.

Delaware

Retail Choice for Power.    The Delaware restructuring legislation required a phase-in of retail competition beginning April 1, 2000, and ending April 1, 2001, for the customers of Delaware Electric Cooperative (“DEC”), our Delaware Member. The customers of DEC that were given the option to select their power supplier during 2000 accounted for less than 1.0% of our capacity requirements in 2001. As of April 1, 2001, all customers of DEC, representing approximately 11.3% of the capacity that we sold to our member distribution cooperatives in 2001, have the option to choose their power supplier. To date, none of these customers has changed to an alternative power supplier. Additionally, there are no alternative suppliers serving residential customers in Delaware at this time.

Capped Rates.    Pursuant to the Delaware restructuring legislation, during the period from April 1, 2000 to March 31, 2005, rates for DEC’s customers are capped at the rates in effect on April 1, 2000, as adjusted by a one-time fuel adjustment. The power component of DEC’s capped rate was determined using a forecast that we developed in 1998. Market prices for power rose significantly, however, beginning in 1999. As a result, the amounts recovered under the power component of DEC’s capped rate may be less than the amounts we charge DEC for power. The Delaware restructuring legislation does not allow DEC to automatically recover increased fuel costs. The Delaware Public Service Commission (“Delaware PSC”) may change the capped rates in connection with any extraordinary costs that the Delaware PSC approves.

DEC’s capped rate does not impact our ability to charge our costs to DEC under our wholesale power contract with DEC. If DEC’s costs are greater than the rate capped by the Delaware PSC, DEC must absorb any deficiency. If DEC’s costs are less than the rate capped by the Delaware PSC, DEC is allowed to retain the surplus. We believe that DEC will be able to make its payments to us through a combination of revenues derived from the capped rate, revenues from other sources, reductions in its other costs, and its equity.

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Stranded Costs.    The restructuring legislation required the Delaware PSC to approve a restructuring and rate unbundling plan, including any proposed collection of stranded costs for each incumbent utility. DEC filed the required plan in September, 1999. On April 25, 2000, the Delaware PSC issued a final order determining that DEC did not have stranded costs and therefore that DEC is not permitted to collect a competitive transition charge from those customers that choose an alternative power supplier during the specified transition period.

Default Service Provider.    Under the new law, DEC will remain the default power provider to its current customers through March 31, 2005. After that date, DEC may continue as a default service provider unless the Delaware PSC determines that DEC is unable to provide default service or its current service is not adequate to meet the requirements of public necessity and convenience. The Delaware PSC has determined that DEC’s rates for default service will be the same as the capped rates described above for the period from April 1, 2001 to March 31, 2005. After March 31, 2005, the default service rate will be set by the Delaware PSC.

Distribution Service Provider.    DEC will remain the exclusive provider of distribution services in its certificated service territory. DEC also will be the exclusive provider of metering and most billing services to all customers located in its certificated service territory.

West Virginia.

On March 11, 2000, the West Virginia legislature adopted a restructuring plan that implemented customer choice on January 1, 2001, or a later date established by the state public service commission. Passage of a second resolution during the 2001 legislative session was necessary for the deregulation plan to proceed. During the 2001 legislative session, however, lawmakers did not pass the resolution necessary for the introduction of retail competition for power services. As a result, the legislation did not become effective and no timetable currently exists for the introduction of retail competition for electric services in West Virginia.

Stranded Costs

In a competitive environment, generating utilities are no longer assured the recovery of prudently incurred costs. Costs that are not recovered are commonly known as stranded costs. Generating utilities with costs that exceed market prices could suffer significant losses from stranded costs. Additionally, the loss of customers as a result of retail competition also could have a significant impact on a utility’s results of operations. We are allowed to recover all of our costs through the formulary rate we charge the member distribution cooperatives for power under our wholesale power contracts with them. See “Member Distribution Cooperatives—Wholesale Power Contracts” in Item 1. Because nearly all of the member distribution cooperatives’ customers will be permitted to select their power suppliers by 2004, the member distribution cooperatives may have stranded costs to the extent they are required to purchase power from us at a price that causes their customers to select another power supplier, and the competitive transition charges approved by their respective state public service commissions are insufficient to recover stranded costs. The member distribution cooperatives’ exposure to potentially stranded costs most likely would result from:

• power purchase contracts that regularly require us to purchase capacity or energy in excess of market prices; and

• the inability of our generating facilities to operate economically in a deregulated market.

The loss of a significant portion of the power purchased by the member distribution cooperatives’ customers could cause a reduction in our revenues and cash flows. The resulting decrease in our member revenues also could cause us to lose our tax-exempt status. See “Factors Affecting Results—Tax Status.”

Over the past years, we have taken several steps to (1) prepare for and adapt to the fundamental changes which have occurred or are likely to occur in the electric utility industry, (2) improve our member distribution cooperatives’ competitive positions, and (3) reduce the possibility that they will incur stranded costs. Most importantly, we have implemented the Strategic Plan Initiative. The objective of the Strategic Plan Initiative is to ensure that our member

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distribution cooperatives’ rates for power will be equal to or less than the market price of power by January 1, 2004. Based on the study conducted in 2001, we believe that we have reduced our indebtedness and future costs and acquired enough cash to further reduce our indebtedness in the future so that our costs under our formulary rate will be at or below our current projections of the price of power on January 1, 2004. Because several factors affect this determination, we continue to evaluate the events that could impact this calculation. See “Factors Affecting Results—Strategic Plan Initiative.”

Reliance on Energy Purchases

Our power supply strategy has evolved as the electric utility industry has changed. Historically, we satisfied that portion of our capacity and energy requirements not supplied by North Anna and Clover through long-term power purchase contracts with neighboring utilities at a price determined by the supplying utility’s average system cost. In the late 1990’s, we began reviewing whether this was the best strategy to serve the member distribution cooperatives’ power requirements because of the rapidly changing regulatory environment, the forecasted growth in our member distribution cooperatives’ power requirements, and projections of future market prices of capacity and energy below the prices we were paying under several power purchase contracts.

Based on our review of these matters, we took several actions. We began restructuring our existing long-term power purchase contracts to reduce the term or amount purchased or provide for purchases of capacity or energy at market-based pricing. At the same time, we entered into new power purchase contracts to acquire capacity or energy or both at fixed or market prices. In addition, we started purchasing increasing amounts of energy in the forward, short-term and spot markets by exercising our contractual rights to forego energy purchases under existing long-term power purchase contracts. See Business-Power Supply Resources—Other Power Supply Resources—Power Purchase Contracts” and “—Market Energy Purchases” in Item 1. Finally, in 1999, we determined that the construction of Rock Springs, Louisa and Marsh Run as combustion turbine facilities, coupled with additional forward, short-term and spot market energy purchases, was the most economical approach to satisfy our power requirements.

While the combustion turbine facilities will provide most of our capacity requirements above those met by Clover and North Anna, they will not satisfy a significant portion of our energy requirements. Combustion turbine facilities are most economical to operate when the market price of energy is relatively high. By operating the combustion turbine facilities during those times, we reduce our exposure to market energy price volatility risk but use the market to supply energy during other times. Currently, we expect in 2005 the combustion turbine facilities will supply approximately 10% of our energy requirements, the market will supply approximately 40% of our energy requirements and North Anna and Clover will supply the remaining approximate 50% of our energy requirements.

Because we have and will rely heavily on market purchases of energy, we have taken two primary steps to reduce our exposure to future price fluctuations in the energy market. First, in 2000, we began purchasing in the market blocks of short-term energy and options to purchase energy for significant periods into the future. Currently, we have secured through market purchases or energy contracts the majority of our energy requirements not supplied by our generating facilities or the combustion turbine facilities through the end of 2003. We plan to continue purchasing energy for significant periods into the future by utilizing option contracts for the purchase of energy, and forward, short-term and spot market purchases. In addition, we plan to use similar efforts to manage our exposure to market changes in the price of fuel, especially changes in the price of natural gas.

Second, in March, 2001, we engaged APM, an energy trading and risk management company, to assist us in executing trades to purchase energy, developing a strategy of when to operate the combustion turbine facilities or purchase energy, modeling our power requirements, and analyzing our power purchase contracts and credit risks of counterparties. See “Quantitative and Qualitative Disclosures About Market Risk.”

We continue to review our power supply resource options and future requirements. As we have done in the past, we expect to adjust our portfolio of power supply resources to reflect our projected power requirements and changes in the market.

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Recently Issued Accounting Standards

On August 15, 2001, the Financial Accounting Standards Board issued SFAS No. 143 “Accounting for Asset Retirement Obligations,” which will be effective with respect to us beginning in 2003. The new rules will change our current accounting and reporting relative to our decommissioning costs. 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 adverse effect on results of our operations due to our current and future ability to recover decommissioning costs through rate adjustments.

Extensions of North Anna Licenses

We expect that North Anna will begin decommissioning in 2018 if its operational licenses are not extended. If both units are decommissioned, we expect the timing of payments for decommissioning costs would extend for 32 years. We do not expect these payments to have a material adverse impact on our liquidity or capital resources because we have set aside appropriate reserves for this purpose. In June, 2001, Virginia Power filed applications with the Nuclear Regulatory Commission (the “NRC”) to renew the operating licenses for both North Anna units. If granted, the renewal licenses would permit operation of the facility for another 20 years, until 2038 for Unit 1 and 2040 for Unit 2. We cannot predict whether the NRC will grant the renewal licenses.

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Item 7A.    Quantitative and Qualitative Disclosures About Market Risk

We are exposed to market risk, including changes in interest rates and equity and market prices. Interest rate risk is generally associated with our outstanding debt and trust-issued securities. We are also subject to interest rate risk, as well as, equity price risk as a result of our nuclear decommissioning trust investments in debt and equity securities.

Interest Rate Risk

We use both fixed and variable rate debt as sources of financing. All of our outstanding long-term indebtedness accrued interest at fixed rates, except for two series of bonds, one of which matured December 3, 2001, with variable interest rates that are periodically re-priced which were issued to municipalities in connection with their issuance of tax-exempt bonds to finance the purchase of load management software and equipment, and pollution control facilities. The following table illustrates financial instruments that are held or issued by us at December 31, 2001, and are sensitive to interest rate changes:

																At December 31,
	Expected Maturity Value(1)															2001				2000
	2002			2003			2004			2005			There- after			Total		Fair Value		Total		Fair Value
	(in millions, except percentages)
Liabilities—Fixed Rate:
Taxable bonds	$	27.9		$	20.7		$	20.7		$	20.6		$	581.9		$	671.8	$	686.9	$	488.9	$	507.5
Average interest rate		7.7	%		7.7	%		7.6	%		7.6	%		7.8	%
Tax-exempt bonds	$	12.0		$	1.4		$	1.5		$	1.6		$	48.7		$	65.2	$	66.0	$	65.2	$	65.9
Average interest rate		6.1	%		6.4	%		6.5	%		6.5	%		6.7	%
Liabilities—Variable Rate:
Tax-exempt bonds	$	—		$	—		$	—		$	—		$	6.8		$	6.8	$	6.8	$	7.8	$	8.2
Average interest rate		—			—			—			—			2.9	%

(1) The maturities of the bonds reflect mandatory redemption obligations, if any.

Equity Price Risk

We are exposed to price fluctuations in equity markets with respect to certain of our investments. At December 31, 2001, our equity investments totaled approximately $35.9 million. We believe that exposure to fluctuations in equity prices will not have a material impact on our financial results.

We accrue decommissioning costs over the expected service life of North Anna and make periodic deposits to a trust fund so that the fund balance will equal the estimated cost to decommission North Anna at the time of decommissioning. At December 31, 2001, these funds were invested primarily in equity securities and corporate obligations. These equity securities expose us to price fluctuations in equity markets. To minimize the risk of price fluctuations, we actively monitor our portfolio by measuring the performance of our investments against market indexes and by maintaining and reviewing established target allocation percentages of assets in our trust to various investment options. Unrealized gains and losses on investments in the trust are deferred as an adjustment to the reserve until realized.

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Market Price Risk

Because our member distribution cooperatives’ power requirements are greater than our owned or contractual power supply resources, we must secure additional energy resources to meet our total energy requirements. Obtaining additional resources subjects us to market price risk for supplemental power purchases.

Through our relationship with APM, we have formulated policies and procedures to manage the risks associated with these price fluctuations and use various commodity instruments, such as hedges, futures and options, to reduce our risk exposure. We use, or intend to use, APM to assist us in managing our market price risks by:

• maintaining a portfolio model that identifies our power producing resources (including fuel supply, our power purchase contract positions and our generating capacity) and analyzing the optimal use of these resources in light of costs and market risks associated with using these resources;

• modeling our power obligations and assisting us with analyzing alternatives to meet our member distribution cooperatives’ power requirements;

• selling power as our agent and the agent of TEC Trading, including excess power produced by the combustion turbine facilities; and

• executing hedge trades to stabilize the cost of fuel requirements, primarily natural gas, used to operate the three combustion turbine facilities and to limit our exposure under power purchase contracts with variable rates based on natural gas prices.

We continually review various options to acquire low cost power and are developing the combustion turbine facilities as a means of maintaining stable power costs.

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Item 8.    Financial Statements and Supplementary Data

CONSOLIDATED FINANCIAL STATEMENTS

INDEX

	Page Number
Report of Independent Accountants	44
Consolidated Balance Sheets	46
Consolidated Statements of Revenues, Expenses and Patronage Capital	47
Consolidated Statements of Comprehensive Income	47
Consolidated Statements of Cash Flows	48
Notes to Consolidated Financial Statements	49

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REPORT OF INDEPENDENT ACCOUNTANTS

To The Board of Directors

Old Dominion Electric Cooperative

We have audited the accompanying consolidated balance sheets of Old Dominion Electric Cooperative as of December 31, 2001 and 2000, and the related consolidated statements of revenues, expenses and patronage capital, comprehensive income, and cash flows for the years then ended. These financial statements are the responsibility of the Cooperative’s management. Our responsibility is to express an opinion on these financial statements based on our audits.

We conducted our audits in accordance with auditing standards generally accepted in the United States. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.

In our opinion, the financial statements referred to above present fairly, in all material respects, the consolidated financial position of Old Dominion Electric Cooperative at December 31, 2001 and 2000, and the consolidated results of its operations and its cash flows for the years then ended in conformity with accounting principles generally accepted in the United States.

/s/    ERNST & YOUNG LLP

Richmond, Virginia

March 1, 2002

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REPORT OF INDEPENDENT ACCOUNTANTS

To The Board of Directors

Old Dominion Electric Cooperative

In our opinion, the accompanying consolidated statements of revenues, expenses and patronage capital, comprehensive income and cash flows present fairly, in all material respects, the results of operations and cash flows of Old Dominion Electric Cooperative (“the Cooperative”) for the year ended December 31, 1999, in conformity with accounting principles generally accepted in the United States of America. These financial statements are the responsibility of the Cooperative’s management; our responsibility is to express an opinion on these financial statements based on our audit. We conducted our audit of these statements in accordance with auditing standards generally accepted in the United States of America, which require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, and evaluating the overall financial statement presentation. We believe that our audit provides a reasonable basis for our opinion. We have not audited the consolidated financial statements of the Cooperative for any period subsequent to December 31, 1999.

/s/    PRICEWATERHOUSECOOPERS LLP

Richmond, Virginia

March 10, 2000

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OLD DOMINION ELECTRIC COOPERATIVE

CONSOLIDATED BALANCE SHEETS

As of December 31, 2001 and 2000

	2001			2000
	(In thousands)
ASSETS:
Electric Plant:
In service	$	899,691		$	900,290
Less accumulated depreciation		(340,440	)		(304,588	)
		559,251			595,702
Nuclear fuel, at amortized cost		8,487			5,598
Construction work in progress		127,270			47,598
Net Electric Plant		695,008			648,898
Investments:
Nuclear decommissioning trust		59,700			60,530
Lease deposits		137,265			131,364
Other		159,083			54,836
Total Investments		356,048			246,730
Current Assets:
Cash and cash equivalents		77,981			20,259
Receivables		61,097			46,769
Fuel, materials and supplies, at average cost		13,936			10,236
Prepayments		1,783			1,508
Deferred Energy		18,244			15,376
Total Current Assets		173,041			94,148
Deferred Charges		32,053			20,796
Total Assets	$	1,256,150		$	1,010,572
CAPITALIZATION AND LIABILITIES:
Capitalization:
Patronage capital	$	225,538		$	224,598
Accumulated other comprehensive income		398			(256	)
Long-term debt		625,232			449,823
Total Capitalization		851,168			674,165
Current Liabilities:
Long-term debt due within one year		39,927			30,488
Accounts payable		59,525			29,091
Accounts payable—members		38,223			20,912
Accrued expenses		16,415			6,849
Total Current Liabilities		154,090			87,340
Deferred Credits and Other Liabilities
Decommissioning reserve		59,700			60,530
Obligations under long-term leases		140,291			134,463
Other		50,901			54,074
Total Deferred Credits and Other Liabilities		250,892			249,067
Commitments and Contingencies		—			—
Total Capitalization and Liabilities	$	1,256,150		$	1,010,572

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

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OLD DOMINION ELECTRIC COOPERATIVE

CONSOLIDATED STATEMENTS OF REVENUES, EXPENSES AND PATRONAGE CAPITAL

For the Years Ended December 31, 2001, 2000 and 1999

	2001			2000			1999
	(In thousands)
Operating Revenues	$	487,287		$	422,031		$	390,060
Operating Expenses:
Fuel		60,699			49,578			46,045
Purchased power		267,518			170,428			162,242
Operations and maintenance		34,758			34,855			34,096
Administrative and general		23,064			19,602			18,659
Depreciation, amortization and decommissioning		53,078			94,257			68,015
Taxes other than income taxes		3,275			8,615			7,678
Total Operating Expenses		442,392			377,335			336,735
Operating Margin		44,895			44,696			53,325
Other Income/(Expense), net		1,654			323			(152	)
Investment Income		3,121			4,091			5,552
Interest Charges, net		(41,230	)		(40,881	)		(48,886	)
Net Margin		8,440			8,229			9,839
Patronage Capital—Beginning of Year		224,598			216,369			206,530
Capital Credits Payments		(7,500	)		—			—
Patronage Capital—End of Year	$	225,538		$	224,598		$	216,369

OLD DOMINION ELECTRIC COOPERATIVE

CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME

For the Years Ended December 31, 2001, 2000 and 1999

	2001		2000		1999
	(in thousands)
Net Margin	$	8,440	$	8,229	$	9,839
Other Comprehensive Income:
Unrealized gain/(loss) on investments		654		2,060		(3,013	)
Comprehensive Income	$	9,094	$	10,289	$	6,826

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

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OLD DOMINION ELECTRIC COOPERATIVE

CONSOLIDATED STATEMENTS OF CASH FLOW

For the Years Ended December 31, 2001, 2000 and 1999

	2001			2000			1999
	(In thousands)
Operating Activities:
Net Margin	$	8,440		$	8,229		$	9,839
Adjustments to reconcile net margins to net cash provided by operating activities:
Depreciation, amortization and decommissioning		53,078			94,257			68,015
Other non-cash charges		7,719			8,514			10,238
Amortization of lease obligations		9,563			9,093			8,725
Interest on lease deposits		(9,292	)		(8,894	)		(8,521	)
Change in current assets		(21,171	)		(28,289	)		3,591
Change in current liabilities		38,021			(1,226	)		(12,797	)
Deferred charges and credits		(11,903	)		(2,142	)		(3,615	)
Net Cash Provided by Operating Activities		74,455			79,542			75,475
Financing Activities:
Reductions to long-term debt		(34,309	)		(62,683	)		(78,427	)
Obligations under long-term leases		(344	)		(265	)		(262	)
Additions of long-term debt		216,526			1,190			1,130
Net Cash Provided by (Used for) Financing Activities		181,873			(61,758	)		(77,559	)
Investing Activities:
Lease deposits and other investments		(103,593	)		29,244			(46,344	)
Electric plant additions		(94,332	)		(51,176	)		(8,185	)
Decommissioning fund deposits		(681	)		(681	)		(681	)
Net Cash Used for Investing Activities		(198,606	)		(22,613	)		(55,210	)
Net Change in Cash and Cash Equivalents		57,722			(4,829	)		(57,294	)
Cash and Cash Equivalents—Beginning of Year		20,259			25,088			82,382
Cash and Cash Equivalents—End of Year	$	77,981		$	20,259		$	25,088

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

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OLD DOMINION ELECTRIC COOPERATIVE

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

NOTE 1—Summary of Significant Accounting Policies

General:

We are a not-for-profit wholesale power supply cooperative, incorporated under the laws of the Commonwealth of Virginia in 1948. We have two classes of members. Class A members include 12 consumer-owned electric distribution cooperatives engaged in the retail sale of power to member consumers located in Virginia, Delaware, Maryland, and parts of West Virginia. Our sole Class B member is TEC Trading, Inc. (“TEC Trading”). Our board of directors is composed of two representatives from each of the member distribution cooperatives and one representative from TEC Trading. Our rates are not regulated by the respective states’ public service commissions, but are set periodically by a formula that was accepted for filing by the Federal Energy Regulatory Commission (“FERC”) on May 18, 1992.

We comply with the Uniform System of Accounts prescribed by FERC. In conformity with accounting principles generally accepted in the United States (“GAAP”), the accounting policies and practices applied by us in the determination of rates are also employed for financial reporting purposes.

The preparation of our consolidated financial statements in conformity with GAAP requires management to make estimates and assumptions that affect the amounts reported therein. Actual results could differ from those estimates.

The accompanying financial statements reflect the consolidated accounts of Old Dominion and its subsidiaries. We have eliminated all intercompany balances and transactions in consolidation. Our non-controlling, 50% or less, ownership interest in other entities is recorded using the equity method of accounting.

Electric Plant:

Electric plant is stated at original cost when first placed in service. Such cost includes contract work, direct labor and materials, allocable overhead, and an allowance for borrowed funds used during construction. Upon the partial sale or retirement of plant assets, the original asset cost and current disposal costs less sale proceeds, if any, are charged or credited to accumulated depreciation. In accordance with industry practice, no profit or loss is recognized in connection with normal sales and retirements of property units.

Maintenance and repair costs are expensed as incurred. Replacements and renewals of items considered to be units of property are capitalized to the property accounts.

Depreciation, Amortization, and Decommissioning:

Depreciation is based on the straight-line method at rates that are designed to amortize the original cost of properties over their service lives. Depreciation rates, excluding accelerated depreciation associated with our “Strategic Plan Initiative”, for jointly owned depreciable plant balances at the North Anna Nuclear Power Station (“North Anna”) were approximately 3.1% in 2001, 3.0% in 2000, and 3.3% in 1999. The depreciation rates, excluding accelerated depreciation associated with our Strategic Plan Initiative, for jointly owned depreciable plant balances at the Clover Power Station (“Clover”) were approximately 2.7% in 2001, 2.7% in 2000, and 2.8% in 1999.

In accordance with our Strategic Plan Initiative, we recorded $18.5 million, $65.0 million, and $43.7 million of accelerated depreciation on our generation assets in 2001, 2000, and 1999, respectively. See Note 13 to the Consolidated Financial Statements.

We accrue decommissioning costs over the expected service life of North Anna and makes periodic deposits in a trust fund, such that the fund balance will equal our estimated decommissioning cost at the time of decommissioning. The

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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 expected to be $91.3 million, based on a site-specific study performed by Virginia Electric and Power Company (“Virginia Power”) in 1998. A new cost estimate will be completed in 2002. The cost estimate assumes that the plant will be dismantled when it is decommissioned. Under current operating licenses, the decommissioning of North Anna would begin in 2018 and 2020 for North Anna Units 1 and 2, respectively. In June 2001, Virginia Power filed an application with the NRC to renew the operating licenses for North Anna. The renewed licenses would extend the operation of North Anna Units 1 and 2 to 2038 and 2040, respectively. Annual decommissioning expense, net of earnings on the fund, was $0.7 million in 2001, 2000, and 1999.

Nuclear Fuel:

Owned nuclear fuel is amortized on a unit-of-production basis sufficient to fully amortize, over the estimated service life, the cost of fuel plus future storage and disposal costs.

Under the Nuclear Waste Policy Act of 1982, the Department of Energy (“DOE”) is required to provide for the permanent disposal of spent nuclear fuel produced by nuclear facilities, such as North Anna, in accordance with contracts executed with the DOE. However, since the DOE did not begin accepting spent fuel in 1998 as specified in its contracts, Virginia Power is providing on-site spent nuclear fuel storage at the North Anna facility. These facilities are expected to be adequate until the DOE begins accepting the spent nuclear fuel. In February 2002, the Secretary of Energy recommended that Yucca Mountain in Nevada be developed as a permanent repository for spent nuclear fuel. The plan may be appealed by the state of Nevada and is subject to various congressional approvals and NRC licensing.

Allowance for Borrowed Funds Used During Construction:

Allowance for borrowed funds used during construction is defined as the net cost during the construction period of borrowed funds used for construction purposes and a reasonable rate on other funds when so used. We capitalize interest on borrowings for significant construction projects. Interest capitalized in 2001, 2000, and 1999 was $1.0 million, $0.3 million, and $0.3 million, respectively.

Income Taxes:

As a not-for-profit electric cooperative, we are currently exempt from federal income taxation under Section 501(c)(12) of the Internal Revenue Code of 1986, as amended. Accordingly, provisions for income taxes have not been reflected in the accompanying consolidated financial statements.

Operating Revenues:

Our operating revenues are derived from sales to our member distribution cooperatives and to non-members. Sales to our member distribution cooperatives consist of power sales pursuant to long-term wholesale power contracts that we maintain with each of our member distribution cooperatives. These wholesale power contracts obligate each member distribution cooperative to pay us for power furnished in accordance with our rates. Power furnished is determined based on month-end meter readings.

Sales to non-members represent sales of excess purchased energy and sales of excess generated energy from Clover. Excess purchased energy is sold to the Pennsylvania-New Jersey-Maryland Interconnection, LLC (“PJM”) under its rates for providing energy imbalance service. Excess energy from Clover is sold to Virginia Power, a related party, under the terms of our contracts with Virginia Power relating to the construction and operation of Clover (“Clover Agreements”).

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Deferred Charges:

Certain costs have been deferred based on rate action by our board of directors and approval by FERC. These costs will be recognized as expenses concurrent with their recovery through rates. In 1999, we accelerated the amortization and recovery in rates of debt refinancing premiums in the amounts of $1.7 million.

Deferred charges also include costs associated with the issuance of debt. These costs, which totaled $7.1 million and $1.7 million at December 31, 2001 and 2000, respectively, are being amortized using the effective interest method over the life of the respective debt issues.

Deferred Energy:

We use the deferral method of accounting to recognize differences between our energy and fuel expenses and energy and fuel revenues collected from our member distribution cooperatives. Deferred energy charges at December 31, 2001 and 2000, were $18.2 and $15.4 million, respectively. Deferred energy charges are recovered from our member distribution cooperatives in the succeeding year in accordance with the tariffs then in effect.

Financial Instruments:

Financial instruments included in the decommissioning fund are classified as available-for-sale, and accordingly, are carried at fair value. Unrealized gains and losses on investments held in the decommissioning fund are deferred as an adjustment to the decommissioning reserve until realized.

Our investments in marketable securities, which are actively managed, are classified as available-for-sale and are recorded at fair value. Unrealized gains or losses on these investments, if material, are reflected as a component of capitalization. Investments in debt securities that we have the positive intent and ability to hold to maturity are classified as held-to-maturity and are recorded at amortized cost. Other investments are recorded at cost, which approximates market value.

Effective January 1, 2001, we adopted Statement of Financial Accounting Standards (“SFAS”) No. 133, “Accounting for Derivative Instruments and Hedging Activities,” as amended by SFAS No. 138, “Accounting for Certain Derivative Instruments and Certain Hedging Activities-An Amendment to SFAS Statement No. 133.” The adoption of these standards did not have a significant effect on our financial position or results of operations. In December 2001, certain interpretative guidance related to SFAS No. 133 was revised and will be effective for us in the second quarter of 2002. The revised guidance is not expected to have a material effect on our financial statements.

Patronage Capital:

We are organized and operate as a cooperative. Patronage capital represents our retained net margins, which have been allocated to our member distribution cooperatives based upon their respective power purchases in accordance with our bylaws. Any distributions are subject to the discretion of our board of directors and the restrictions contained in the Indenture of Mortgage and Deed of Trust, dated as of May 1, 1992, between Old Dominion and Crestar Bank (predecessor to SunTrust Bank), as trustee (as supplemented by twelve supplemental indentures thereto and hereinafter referred to as the “Indenture”).

Concentrations of Credit Risk:

Financial instruments that potentially subject us to concentrations of credit risk consist of cash equivalents, investments, and receivables arising from energy sales to our member distribution cooperatives and Virginia Power related to Clover and other transactions. We place our temporary cash investments with high credit quality financial institutions and invest in debt securities with high credit standards as required by the Indenture and the board of directors. Cash and cash investment balances may exceed FDIC insurance limits. Concentrations of credit risk with respect to receivables arising from energy sales to the member distribution cooperatives are limited due to the large member consumer base

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that represents our member distribution cooperatives’ accounts receivable. Receivables from the member distribution cooperatives at December 31, 2001 and 2000, were $42.4 million and $44.2 million, respectively.

Cash Equivalents:

For purposes of our Consolidated Statements of Cash Flows, we consider all unrestricted highly liquid debt instruments purchased with an original maturity of three months or less to be cash equivalents.

New Accounting Pronouncements:

On August 15, 2001, the Financial Accounting Standards Board issued SFAS No. 143 “Accounting for Asset Retirement Obligations,” which will be effective for us beginning January 1, 2003. The new rules will change our current accounting and reporting relative to our decommissioning retirement obligation. 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 adverse effect on results of our operations due to our current and future ability to recover decommissioning costs through rate adjustments.

NOTE 2—Jointly Owned Plants

We have an 11.6% undivided ownership interest in North Anna, a two-unit, 1,842 MW (net capacity rating) nuclear generating facility, as well as nuclear fuel and common facilities at the power station, and a portion of spare parts, inventory, and other support facilities. North Anna is operated by Virginia Power, which owns the balance of the plant. We are responsible for 11.6% of all post acquisition date additions and operating costs associated with the plant, as well as a pro rata portion of Virginia Power’s administrative and general expenses for North Anna, and must provide our own financing for these items. Our portion of assets, liabilities, and operating expenses associated with North Anna are included in our consolidated financial statements. At December 31, 2001, we had an outstanding accounts payable balance of $1.8 million due to Virginia Power for operation, maintenance, and capital investment at the facility. At December 31, 2000, we had an outstanding accounts receivable balance of $0.9 million due from Virginia Power for operation, maintenance, and capital investment at the facility.

We hold a 50% undivided ownership interest in Clover, a two-unit, 882 MW (net capacity rating) coal-fired generating facility operated by Virginia Power. We are responsible for 50% of all post-construction additions and operating costs associated with Clover, as well as a pro rata portion of Virginia Power’s administrative and general expenses for Clover, and must provide our own financing for these items. Our portion of assets, liabilities, and operating expenses associated with Clover are included in our consolidated financial statements. At December 31, 2001, we had an outstanding accounts payable balance of $5.8 million due to Virginia Power for operation, maintenance, and capital investment at the facility. At December 31, 2000, we had an outstanding accounts receivable balance of $2.5 million due from Virginia Power for operation, maintenance, and capital investment at the facility.

Our investment in jointly owned plants at December 31, 2001, excluding accelerated depreciation of $127.2 million, was as follows:

	North Anna			Clover
	(in millions, except percentages)
Ownership interest		11.6	%		50.0	%
Electric plant	$	352.6		$	636.1
Accumulated depreciation & amortization		(197.3	)		(103.8	)
Construction work in progress		6.0			4.1

Projected capital expenditures for North Anna for 2002 through 2004 are $9.2 million, $8.2 million, and $10.8 million, respectively. Projected capital expenditures for Clover for 2002 through 2004 are $9.2 million, $4.6 million, and $1.6 million, respectively.

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NOTE 3—Power Purchase Agreements

In 2001, 2000, and 1999, North Anna and Clover together furnished approximately 49.6%, 55.7%, and 57.0%, respectively, of our energy requirements. The remaining needs were satisfied through purchases of supplemental power from Virginia Power and other power companies.

Under the terms of the Amended and Restated Interconnection and Operating Agreement with Virginia Power (“I&O Agreement”), as accepted by FERC on March 11, 1998, we will purchase our reserve capacity requirements for North Anna and Clover from Virginia Power for the term of the I&O Agreement, which expires on the earlier of the date on which all facilities at North Anna have been retired or decommissioned and the date upon which our interest in North Anna is reduced to zero. Through the end of 2001, Virginia Power had the obligation to provide our entire monthly supplemental and peaking demand and energy requirements to meet the needs of our Virginia member distribution cooperatives (except A&N Electric Cooperative) not met from our portion of North Anna and Clover generation. Under the terms of the I&O Agreement, we will purchase from Virginia Power half of our supplemental requirements in 2002 and none in 2003. We will continue to purchase our peaking requirements from Virginia Power through 2003.

Beginning January 1, 2000, energy pricing for the peaking portion of Virginia Power purchases changed from Virginia Power’s system average cost to a charge that reflects Virginia Power’s owned combustion turbine costs. Beginning January 1 2001, energy pricing for the supplemental portion of Virginia Power purchases changed from Virginia Power’s system average cost to a charge that reflects an average price of predetermined Virginia Power owned combustion turbine and combined cycle costs. We have the contractual right to elect not to purchase energy under the I&O Agreement if we can purchase more economical energy from other sources.

Additionally, under the terms of the I&O Agreement, services to us have been unbundled and terms for the provision of transmission and ancillary services have been removed. These services are provided pursuant to Virginia Power’s open access transmission tariff. Specific terms are provided in our Service Agreement for Network Integration Transmission Service and a Network Operating Agreement with Virginia Power, both of which also were approved by FERC on March 11, 1998, retroactively effective to January 1, 1998.

We have an agreement with Public Service Electric & Gas (“PSE&G Agreement”) to purchase 150 MW of capacity, consisting of 75 MW intermediate and/or peaking capacity and 75 MW base load capacity, as well as reserves and associated energy, through 2004. The PSE&G Agreement contains fixed capacity charges for the base, intermediate, and peaking capacity to be provided under the agreement. However, either party can (within certain limits) apply to FERC to recover changes in certain costs of providing services. In the event of a change in rate, the party adversely affected may terminate the PSE&G Agreement, with one-year notice. We may purchase the energy associated with the PSE&G capacity from PSE&G or other power suppliers. If purchased from PSE&G, the energy cost is based on PSE&G’s incremental cost above its native load, taking into account PJM pool energy transactions. If purchased from other power suppliers, we pay a negotiated energy rate. In 2001, we did not purchase energy under this agreement but procured energy in conjunction with our other PJM energy needs via bilateral agreements and economy energy purchases from the short-term markets.

We had a contract with Conectiv to purchase 220 MW of capacity through August 31, 2001 to satisfy our capacity requirements for our member distribution cooperatives providing service on the Delmarva Peninsula. There was no commitment to purchase energy under the contract, and we procured the energy in conjunction with our other PJM energy needs through bilateral agreements and economy energy purchases.

Additionally, we have a contract with a joint venture of Conectiv and PPL to purchase 60 MW of firm system capacity through December 2001. We did not purchase energy under the contract.

On September 1, 2001 we began making purchases under an agreement with Williams Energy (“Williams”) to meet a portion of our Delmarva Peninsula member distribution cooperatives’ demand and energy needs. We purchased 200 MW of capacity for the period September 1, 2001 through December 31, 2001 and will purchase 286 MW of capacity for the period January 1, 2002 through April 30, 2002. In addition to having rights to capacity, we will

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have rights to call on energy priced at fixed energy rates. This same agreement will also be used to meet portions of our load in the Virginia Power control area beginning January 1, 2002.

We also entered into an agreement with Williams whereby Williams agreed to deliver energy to serve the full hourly energy requirements of our Delmarva Peninsula member distribution cooperatives served by PJM for the period January 1, 2001 through August 31, 2001. Under the agreement, the energy rates for each month were locked-in in advance. This contract provided us fixed pricing during this year of volatility in the energy markets.

Congestion.    Due to transmission import limitations into the Delmarva Peninsula, we paid approximately $18.0 million in congestion costs during 2001. These costs were incurred under the PJM Independent System Operator rules when higher cost generation must be run due to transmission contingencies or outages. The congestion charges were offset by credits of approximately $6.4 million for our ownership of Fixed Transmission Rights. Net congestion costs for 2001 were approximately $11.6 million.

Our purchased power costs for the past three years were as follows :

	Year Ended December 31,
	2001		2000		1999
	(in millions)
Virginia Area	$	110.9	$	68.9	$	69.8
Delmarva Area		152.1		67.1		66.5
Other		4.5		34.4		25.9
	$	267.5	$	170.4	$	162.2

Our power purchase agreements contain certain firm capacity and minimum energy requirements. As of December 31, 2001, our minimum purchase commitments under the various agreements, without regard to capacity reductions or cost adjustments, were as follows:

Year Ending December 31,	Firm Capacity Requirements		Minimum Energy Requirements		Total
	(in millions)
2002	$	34.8	$	36.2	$	71.0
2003		25.3		36.3		61.6
2004		7.0		—		7.0
2005		—		—		—
2006		—		—		—
	$	67.1	$	72.5	$	139.6

NOTE 4—Wholesale Power Contracts

We have a wholesale power contract with each of our member distribution cooperatives whereby each member distribution cooperative is obligated to purchase substantially all of its power requirements from us through the year 2028. Each such contract provides that we shall provide all of the power that the member distribution cooperative requires for the operation of its system to the extent that we have the power and facilities available. Each member

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distribution cooperative is required to pay us monthly for power furnished under its wholesale power contract in accordance with rates and charges established by us pursuant to our formulary rate filed with FERC. Under the accepted formulary rate, our rates are developed using a rate methodology under which all categories of costs are specifically separated as components of the formula to determine our revenue requirements. The formula is intended to permit collection of revenues, which, together with revenues from all other sources, are equal to all costs and expenses recorded on our books, plus an additional 20% of total interest charges, plus additional equity contributions as approved by our board of directors. It also provides for the periodic adjustment of rates to recover actual, prudently incurred costs, whether they increase or decrease, without further application to and acceptance by FERC. In accordance with the formula, the board of directors can authorize accelerating the recovery of costs in the establishment of rates. The formulary rate allows us to recover and refund amounts under our Margin Stabilization Plan (described below).

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. There was no adjustment to revenues from power sales under our Margin Stabilization Plan in 2001 or 2000. We reduced revenues from power sales and increased accounts payable—members $7.2 million under our Margin Stabilization Plan in 1999.

Revenues from the following member distribution cooperatives equaled or exceeded 10% of our total revenues for the past three years:

	Year Ended December 31,
	2001		2000		1999
	(in millions)
Northern Virginia Electric Cooperative	$	129.5	$	110.5	$	102.6
Rappahannock Electric Cooperative		104.5		89.0		82.2
Delaware Electric Cooperative		48.9		44.1		41.7

NOTE 5—Long-Term Lease Transactions

On March 1, 1996, we entered into a long-term lease transaction with an owner trust for the benefit of an institutional equity investor. Under the terms of the transaction, we entered into a 48.8-year lease of our interest in Clover Unit 1 (valued at $315.0 million) to such owner trust, and simultaneously entered into a 21.8-year lease of the interest back from such owner trust. As a result of the transaction, we recorded a deferred gain of $23.6 million, which is being amortized into income ratably over the 21.8-year operating lease term. A portion of the proceeds from the transaction, $23.9 million, was used to retire a portion of our 8.76% First Mortgage Bonds, 1992 Series A. Concurrent with the retirement of our 1992 Series A Bonds, we issued a like amount of zero coupon First Mortgage Bonds, 1996 Series A with an effective interest rate of 7.06%.

On July 31, 1996, we entered into a long-term lease transaction with a business trust created for the benefit of another equity investor. Under the terms of the transaction, we entered into a 63.4-year lease of our interest in Clover Unit 2 (valued at $320.0 million) to such business trust and simultaneously entered into a 23.4-year lease of the interest back from such business trust. As a result of the transaction, we recorded a deferred gain of $39.3 million, which is being amortized into income ratably over the 23.4-year operating lease term.

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NOTE 6—Investments

Investments were as follows at December 31, 2001 and 2000 (in thousands):

Description	Cost		Gross Unrealized Gains		Gross Unrealized Losses			Fair Value
December 31, 2001
Available-for-Sale:
U.S Government agencies	$	9,477	$	—	$	(22	)	$	9,455
Corporate obligations		7,563		127		(3	)		7,687
Registered investment companies(1)		25,621		—		(587	)		25,034
Asset-backed securities		9,475		166		(13	)		9,628
Mortgaged-backed securities		8,073		144		—			8,217
Common stock		32,293		3,659		(1,288	)		34,664
Short-term investments		64,788		—		—			64,788
	$	157,290	$	4,096	$	(1,913	)	$	159,473
Held-to-Maturity:
U.S. Government obligations	$	154,895	$	10,091	$	—		$	164,986
Corporate obligations		39,777		7		—			39,784
	$	194,672	$	10,098	$	—		$	204,770
Other	$	1,903	$	—	$	—		$	1,903
December 31, 2000
Available-for-Sale:
Corporate obligations	$	27,131	$	6	$	(268	)	$	26,869
Registered investment companies(1)		23,583		—		(1,181	)		22,402
Asset-backed securities		9,987		7		(23	)		9,971
Mortgaged-backed securities		7,967		32		(10	)		7,989
Common stock		29,371		9,383		(684	)		38,070
Short-term investments		64,046		—		—			64,046
Other		58		—		—			58
	$	162,143	$	9,428	$	(2,166	)	$	169,405
Held-to-Maturity:
U.S. Government obligations	$	43,541	$	13,171	$	—		$	56,712
Corporate obligations		32,512		—		—			32,512
	$	76,053	$	13,171	$	—		$	89,224
Other	$	1,272	$	—	$	—		$	1,272

(1) Investments included herein are primarily invested in corporate obligations.

Contractual maturities of debt securities at December 31, 2001 were as follows (in thousands):

Description	Less Than One Year		One Through Five Years		More Than Five Years		Total
Available-for-Sale	$	4,064	$	13,078	$	8,217	$	25,359
Held-to-Maturity		113,653		1,112		79,907		194,672
	$	117,717	$	14,190	$	88,124	$	220,031

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Realized gains and losses on the sale of securities are determined on the basis of specific identification. During 2001 and 2000, sales proceeds from the sale of available-for-sale securities were $97.9 million and $117.9 million, respectively. Gross realized gains on the sale of available-for-sale securities in 2001, 2000, and 1999 were $1.3 million, $0.6 million, and $0.2 million, respectively. Gross realized losses on the sale of available-for-sale securities in 2001, 2000, and 1999 were $0.3 million, $0.9 million, and $0.5 million, respectively.

NOTE 7—Long-Term Debt

Long-term debt consists of the following:

	December 31,
	2001			2000
	(in thousands)
$215,000,000 principal amount of First Mortgage Bonds, 2001 Series A, due 2011 at an interest rate of 6.25%	$	215,000		$	—
$5,000,000 principal amount of First Mortgage Bonds, 1998 Series B, due 2002 at an interest rate of 4.25%		5,000			5,000
$109,182,937 principal amount of First Mortgage Bonds, 1996 Series B, due 2018 at an effective interest rate of 7.06%		108,601			108,601
$130,000,000 principal amount of First Mortgage Bonds, 1993 Series A, due 2013 at an interest rate of 7.48%		125,300			125,300
$120,000,000 principal amount of First Mortgage Bonds, 1993 Series A, due 2023 at an interest rate of 7.78%		18,500			18,500
$150,000,000 principal amount of First Mortgage Bonds, 1992 Series A, due 2002 at an interest rate of 7.97%		27,922			56,322
$350,000,000 principal amount of First Mortgage Bonds, 1992 Series A, due 2022 at an interest rate of 8.76%		176,555			180,155
$60,210,000 principal amount of First Mortgage Bonds, 1992 Series C, due 1997 through 2022 at interest rates ranging from 4.90% to 6.50%		54,535			55,790
Louisa County Pollution Control Revenue Bonds (North Anna), due December 1, 2008 with variable interest rates (averaging 3.26 % in 2001 and 4.16% in 2000).		6,750			6,750
First Mortgage Bonds due 2002 at interest rates ranging from 2.60% to 5.25%		5,675			4,420
Non-recourse debt due 2001, with variable interest rates (averaging 5.46% in 2000 and 4.11% in 1999)		—			1,072
		743,838			561,910
Less unamortized discounts and premiums		(78,679	)		(81,599	)
Less current maturities		(39,927	)		(30,488	)
Total Long-Term Debt	$	625,232		$	449,823

Substantially all of our assets are pledged as collateral under the Indenture.

During 2001 and 2000, we purchased approximately $3.6 million and $33.3 million, respectively, of our First Mortgage Bonds, 1992 Series A and 1993 Series A. The transactions resulted in a net loss of approximately $0.4 million in 2001 and net gain of approximately $0.5 million in 2000, including the write-off of original issuance costs. The net gains and losses have been deferred and are being amortized over the life of the remaining bonds. At December 31, 2001, deferred gains and losses on reacquired debt totaled a net loss of approximately $11.6 million.

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During the past three years, we refinanced $3.6 million of our First Mortgage Bonds, 1992 Series C, due 1999 through 2001. The refinanced bonds are due in 2002 at interest rates ranging from 2.60% to 5.25%.

Estimated maturities of long-term debt for the next five years are as follows:

Years Ending December 31,	(in thousands)
2002	$	39,927
2003		22,146
2004		22,149
2005		22,152
2006		22,156

The aggregate fair value of long-term debt was $759.7 million and $581.6 million at December 31, 2001 and 2000, respectively, based on current market prices. For debt issues that are not quoted on an exchange, interest rates currently available to us for issuance of debt with similar terms and remaining maturities are used to estimate fair value. We believe that the carrying amount of debt issues with variable rates is a reasonable estimate of fair value.

NOTE 8—Short-Term Borrowing Arrangements

We have established unsecured short-term lines of credit to provide additional sources of financing. These include $210.0 million in committed lines of credit, which expire in 2002 and are expected to be renewed. Due to limitations contained in the indenture, our short-term indebtedness may not exceed the greater of $100 million and 15% of our total long-term debt and equities, or a total of $127.7 million, as of December 31, 2001. We also have a $30.0 million uncommitted short-term line of credit. At December 31, 2001, and 2000, we had no short-term borrowings outstanding under any of these arrangements. We had outstanding letters of credit totaling $19.6 million at December 31, 2001. No letters of credit were outstanding as of December 31, 2000.

We maintain a policy which allows our member distribution cooperatives to pay monthly power bills before their final due date. Under this policy, we pay interest on early payment balances at a blended investment and outside short-term borrowing rate. Amounts advanced by our member distribution cooperatives are classified as accounts payable—members and totaled $38.2 million and $20.9 million at December 31, 2001 and 2000, respectively.

NOTE 9—Employee Benefits

Substantially all of our employees participate in the National Rural Electric Cooperative Association (“NRECA”) Retirement and Security Program, a noncontributory, defined benefit multi-employer master pension plan. The cost of the plan is funded annually by payments to NRECA to ensure that annuities in amounts established by the plan will be available to individual participants upon their retirement. Pension expense for 2001, 2000, and 1999 was $479,000, $430,000, and $272,000, respectively.

We have also elected to participate in a defined contribution 401(k) retirement plan administered by Diversified Investment Advisors. Under the plan, employees may elect to have up to 23% or $10,500, whichever is less, of their salary withheld on a pre-tax basis, subject to Internal Revenue Service limitations, and invested on their behalf. We match up to the first 2% of each participant’s base salary. Our matching contributions were $79,000, $75,000, and $66,000 in 2001, 2000, and 1999, respectively. In 2000 and 1999, the plan was administered by the NRECA.

We provide no other significant postretirement benefits to our employees. However, in conjunction with the I&O Agreement, we are required to pay 11.6% of the operating costs associated with North Anna and 50% of the operating costs associated with Clover, including postretirement benefits of Virginia Power employees whose costs are allocated to those stations. These postretirement benefits other than pensions resulted in an increase in expense to us of approximately $0.8 million in 2001, $0.7 million in 2000, and $0.9 million in 1999. We are recovering the expense as it is billed by Virginia Power.

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NOTE 10—Insurance

As a joint owner of North Anna, we are a party to the insurance policies that Virginia Power procures to limit the risk of loss associated with a possible nuclear incident at the station, as well as policies regarding general liability and property coverage. All policies are administered by Virginia Power, which charges us for our proportionate share of the costs.

The Price-Anderson Act limits the public liability of an owner of a nuclear power plant to $9.5 billion for a single nuclear incident. The Price-Anderson Act Amendment of 1988 allows for an inflationary provision adjustment every five years. Virginia Power has purchased $200 million of coverage from the commercial insurance pools with the remainder provided through a mandatory industry risk-sharing program. In the event of a nuclear incident at any licensed nuclear reactor in the United States, we, jointly with Virginia Power, could be assessed up to $88.0 million for each licensed reactor not to exceed $10.0 million per year per reactor. There is no limit to the number of incidents for which this retrospective premium can be assessed.

The Price-Anderson Act was first enacted in 1957 and has been renewed three times—in 1967, 1975, and 1988. Price- Anderson expires August 1, 2002, but the operation of the reactors will continue to be covered by the law. Congress is currently holding hearings to reauthorize the legislation.

Virginia Power’s current level of property insurance coverage, $2.55 billion for North Anna, exceeds the Nuclear Regulatory Commission’s (“NRC”) minimum requirement for nuclear power plant licensees of $1.06 billion for each reactor site and includes coverage for premature decommissioning and functional total loss. The NRC requires that the proceeds from this insurance be used first to return the reactor to and maintain it in a safe and stable condition, and second to decontaminate the reactor and station site in accordance with a plan approved by the NRC. The property insurance coverage provided to Virginia Power and us, jointly, is provided by Nuclear Electric Insurance Limited (“NEIL”), a mutual insurance company, and is subject to retrospective premium assessments in any policy year in which losses exceed the funds available to the insurance company. The maximum assessment for the current policy period is $42.0 million. Based on the severity of the incident, the board of directors of the nuclear insurer has the discretion to lower or eliminate the maximum retrospective premium assessment. We, jointly with Virginia Power, have the financial responsibility for any losses that exceed the limits or for which insurance proceeds are not available, because they must first be used for stabilization and decontamination.

Virginia Power purchases insurance from NEIL to cover the cost of replacement power during a prolonged outage of a nuclear unit due to direct physical damage of the unit. Under this program, we, jointly with Virginia Power, are subject to a retrospective premium assessment for any policy year in which losses exceed funds available to NEIL. The current policy period’s maximum assessment is $19.0 million.

Our share of the contingent liability for the coverage assessments described above is a maximum of $27.5 million at December 31, 2001.

NOTE 11—Regional Headquarters, Inc.

We own 50% of RHI, which holds title to the office building that is being partially leased to us. We are obligated to make lease payments equal to one-half of RHI’s annual operating expenses, net of rental income from third party lessees, through the year 2016. During 2001, 2000, and 1999, our rent expense was $296,000, $236,000, and $236,000, respectively.

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Estimated future lease payments, without regard to changes in square footage, third party occupancy rates, operating costs, and inflation are as follows:

Year Ending December 31,	(in thousands)
2002	$	350
2003		350
2004		350
2005		350
2006		350
2007 and thereafter		3,500
	$	5,250

NOTE 12—Supplemental Cash Flows Information

Cash paid for interest, net of allowance for funds used during construction, in 2001, 2000, and 1999 was $40.3 million, $41.3 million, and $49.4 million, respectively.

Unrealized deferred gains on the decommissioning fund of approximately $1.8 million and $3.0 million in 2001 and 2000, respectively, have been included in the decommissioning reserve.

NOTE 13—Commitments and Contingencies

Strategic Plan Initiative—In 1997, we adopted certain strategic objectives designed to mitigate the effects of transition to a competitive electric market, which became known as our Strategic Plan Initiative. As part of our Strategic Plan Initiative, our board of directors unanimously approved a resolution to record accelerated depreciation on our generation assets from January 1, 1999 through December 31, 2003, and recover the additional expense through rates pursuant to our formulary rate. During 2001, 2000, and 1999 we recorded additional depreciation of $18.5 million, $65.0 million, and $43.7 million, respectively. To date we have collected $160.3 million through our Strategic Plan Initiative and have purchased $86.1 million of our outstanding debt ($3.6 million in 2001).

In May 2001, based on then current market projections, we believe that the $160.3 million accumulated through our Strategic Plan Initiative since 1998 and held as cash or investments or already applied to reduce our indebtedness is sufficient to reduce our costs to a level that would enable our member distribution cooperatives’ rates for power to their customers to be at or below market rates by January 1, 2004. As a result, we ceased recording accelerated depreciation on our generating facilities effective June 1, 2001. At the same time, 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 our formulary rate in 2001, which we will use to partially offset the increases in the demand component of our formulary rate in 2002. At December 31, 2001, the $11.4 million of deferred revenue is included in accrued expenses and depreciation, amortization, and decommissioning expense.

TEC Trading, Inc.    In June 2001, we formed TEC Trading, Inc. (“TEC Trading”) with $7.5 million of capital and immediately distributed the stock of TEC Trading as a patronage distribution to our member distribution cooperatives on the same date. TEC Trading is now owned by our member distribution cooperatives to sell power in the market, manage the member distribution cooperatives’ exposure to changes in fuel prices, and take advantage of other power trading opportunities, which may become available in the market. In addition, to facilitate TEC Trading’s ability to sell power in the market, we have agreed to guarantee a maximum of $42.5 million of TEC Trading’s delivery and payment obligations associated with its energy trades. Our guarantee of TEC Trading’s obligations will enable it to maintain credit support sufficient to meet its delivery and payment obligations associated with energy trades. At December 31, 2001, there were no guarantees outstanding.

Combustion Turbine Facilities—Old Dominion is developing generation projects in Virginia and Maryland to replace expiring power purchase contracts in those power supply areas. Through 2005, Old Dominion currently expects that development and construction of the combustion turbine facilities will require an aggregate of $654.9

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million. Construction began on the combustion turbine facility in Maryland in October 2001. The Virginia projects are still under development and in the permitting process.

Legal—Old Dominion is subject to legal proceedings and claims which arise from the ordinary course of business. In the opinion of management, the amount of ultimate liability with respect to such actions will not materially affect the consolidated financial position of Old Dominion.

Environmental—We are currently subject to regulation by the Environmental Protection Agency (“EPA”) and other federal, state, and local authorities regarding the emission, discharge, or release of certain materials into the environment. As with all electric utilities, the operation of our generating units could be affected by future environmental regulations. Capital expenditures and increased operating costs required to comply with any such future regulations could be significant. Expenditures necessary to ensure compliance with environmental standards or deadlines will continue to be reflected in our capital and operating costs.

We are subject to the Clean Air Act. The Clean Air Act requires utilities owning fossil fuel fired-power stations to, among other things, limit emissions of sulfur dioxide and nitrogen oxide (“NO_x”), one of the precursors of ground-level ozone, or obtain allowances for such emissions. Through the use of pollution control facilities, Clover is designed and licensed to operate at full capacity below the current limitations for sulfur dioxide emissions levels and NO_x emissions. Virginia Power, as operator of North Anna and Clover, is responsible for environmental compliance and reporting for the facilities. If, however, liabilities arise as a result of a failure of environmental compliance at North Anna or Clover, our respective responsibility for those liabilities is governed by the operating agreements for the facilities.

In 1998, the EPA issued a rule addressing regional transport of ground-level ozone through reductions in NO_x commonly known as the NO_x State Implementation Plan (“SIP”) call. The NO_x SIP call affects 22 states, including Maryland and Virginia, and the District of Columbia and required those states to develop a plan by October 30, 2000, to reduce NO_x emissions. The NO_x SIP call also required emissions reduction to be implemented by May 1, 2004. On December 26, 2000, the EPA found that several states, including Virginia, failed to submit a plan satisfying the rules. If a state fails to make the required submittal, which the EPA determines is complete, within 18 months of the findings, an emissions offset sanction will apply. This sanction requires new or modified sources of emissions to obtain allowances to emit two tons of NO_x for every one ton of NO_x emitted from the source, subject to the Clean Air Act new source review program for NO_x. The EPA will lift the sanctions when it finds that the state has made a complete filing under the SIP call. The EPA also can promulgate a federal implementation plan as late as two years after the initial findings, unless the affected state has submitted a complete plan by that time. In a federal plan, the EPA rather than the states would determine the specific sources that must reduce NO_x emissions. We anticipate that fossil fuel electric generating facilities greater than 250 mmBtu/hour will be required to reduce their NO_x emissions or obtain NO_x emissions credits from another source. We and Virginia Power are currently evaluating options in meeting the NO_x SIP call as applicable to Clover. These options include installing additional NO_x controls at Clover and purchasing emissions allowances or a combination of both. At this time, we and Virginia Power continue to evaluate NO_x controls to determine the best alternatives for Clover.

North Anna is not impacted by the SIP call because it does not have significant NO_x emissions. Louisa and Marsh Run will be required to obtain allowances to emit one ton of NO_x for every ton of NO_x emitted from the facility during the ozone season. Rock Springs is in an ozone non-attainment area and was required to obtain allowances to emit one ton of NO_x emissions for every ton of NO_x emitted as well as 1.3 NO_x emissions reduction credits for every ton of potential NO_x emissions. NO_x emission reduction credits were required to be obtained prior to the construction of the facility. We will purchase in the market the allowances and have purchased credits required for the operation of the combustion turbine facilities. We project that we will be able to obtain sufficient quantities of allowances in the future at commercially reasonable prices but increased NO_x emissions or increased restrictions could cause the price of allowances to be higher than we expect.

In addition to the NO_x SIP Call, several Northeast utilities filed petitions under Section 126 of the Clean Air Act requesting that the EPA take action to mitigate interstate transport of NO_x. In December 1999, the EPA established NO_x allocations for 392 power plants, including Clover, and many industrial facilities. Additionally, this final rule established a trading program to help those companies meet the required reductions in NO_x by May 3, 2003. The EPA

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has now changed the compliance date under Section 126 to be consistent with the NO_x SIP call compliance date of May 1, 2004.

The EPA has established a new regional haze rule, which affects any source that emits NO_x or sulfur dioxide and that may contribute to the degradation of visibility in national parks and wilderness areas. Currently, we do not know what controls, if any, may have to be installed at Clover to comply with this rule.

Each state regulates the discharge of process wastewater and some storm water discharges into its waters under the National Pollutant Discharge Elimination System program. This program was established as part of the Federal Clean Water Act. We are also subject to permit limitations for surface water discharges and for the operation of a waste landfill at Clover for disposal of ash and scrubber sludge. Permits required by the Clean Water Act and state laws have been issued to us. These permits are subject to reissuance and continued review. We and Virginia Power are evaluating relocating the future landfill discharge to the Roanoke River, which contains a larger flow and provides more dilution.

Clover has a Virginia water protection permit that regulates the amount of water allowed to be withdrawn from the Roanoke River. Clover has a 34-day on-site water supply reservoir to supply the facility during times of low flow when the Roanoke River is below the withdrawal level allowed in the permit.

The scientific community, regulatory agencies, and the electric utility industry are examining the issues of global warming and acidic deposition, and the possible health effects of electric and magnetic fields. While no definitive scientific conclusions have been reached regarding these issues, it is possible that new regulations pertaining to these matters could further increase the capital and operating costs of electric utilities.

In December 2000, the EPA announced that to reduce the health risk of mercury exposure, it will regulate emissions of mercury and other air toxins from coal and oil-fired electric utility steam generating units. Clover would be subject to such regulation but because existing pollution control systems on these units currently reduce mercury emissions, we do not anticipate installation of additional equipment will be required at this time. The EPA currently intends to propose regulations with respect to mercury emissions by December 15, 2003, and issue final regulations by December 15, 2004.

Finally, several studies required by the Clean Air Act examined the health effects of power plant emissions of various hazardous air pollutants. Emissions of other hazardous air pollutants also may become regulated. The EPA expects to follow a rulemaking schedule to establish limits on these emissions that would require compliance by 2007 to 2008. Depending on the outcome of this rulemaking, significant capital expenditures may be incurred at Clover.

Insurance—Under several of the nuclear insurance policies procured by Virginia Power and to which we are a party, we are subject to retrospective premium assessments in any policy year in which losses exceed the funds available to the insurance companies. See Note 10 to the Consolidated Financial Statements.

NOTE 14—Subsequent Events

Prior to the bankruptcy filing by Enron Power Marketing, Inc. (“Enron Power Marketing”), we were party to several power purchase transactions with Enron Power Marketing. In December 2001, we gave notice that we were terminating these transactions, effective January 10, 2002, pursuant to their terms because of the bankruptcy filing. We are in the process of determining what net termination payment may be due as a result of these terminations. We do not expect any payment that is due to have a material adverse effect on our business, operations or financial position. Also management believes any payment made would be collected in rates from our member distribution cooperatives.

In February 2002, we signed an agreement with Virginia Power whereby Virginia Power agreed to credit us $2.3 million for overscheduled energy in 2001 and $4.0 million to settle issues related to Virginia Power’s billing for our monthly reserve capacity charges prior to the year 2002. The $6.3 million has been credited to purchased power at December 31, 2001.

At February 28, 2002, our deferred energy balance had been fully collected from our member distribution cooperatives.

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Item 9.    Changes in and Disagreements with Accountants and Financial Disclosure

Not Applicable

PART III

Item 10.    Directors and Executive Officers of the Registrant

Directors of Old Dominion

We are governed by a board of 25 directors, consisting of two representatives from each of our member distribution cooperatives and one representative from TEC Trading. Each of our 12 member distribution cooperatives nominates two directors at least one of whom must be a director of that member in good standing. One director currently serves as a director on behalf of a member distribution cooperative and TEC Trading. The candidates for director are then elected to our board of directors by voting delegates from each of our members elected by each member’s local board of directors and authorized to represent such member at our annual meeting. Our board of directors sets policy and provides direction to our President and Chief Executive Officer. The board of directors generally meets monthly. The members do not vote on any matters other than the election of directors.

Information concerning our directors, including principal occupation and employment during the past five years and directorships in public corporations, if any, are listed below.

William M. Alphin(71).    Insurance advisor with Virginia Farm Bureau Insurance Company and a self-employed farmer. Mr. Alphin has been a Director of Old Dominion since 1980 and a Director of Rappahannock Electric Cooperative since 1980.

E. Paul Bienvenue (62).    President and Chief Executive Officer of Delaware Electric Cooperative. Mr. Bienvenue has been a Director of Old Dominion since 1981.

John E. Bonfadini (63).    Retired, formerly a professor at George Mason University. Mr. Bonfadini has been a Director of Old Dominion since 1977 and a Director of Northern Virginia Electric Cooperative since 1975.

Dick D. Bowman (73).    President of Bowman Brothers, Inc., a farm equipment retailer. Mr. Bowman has been a Director of Old Dominion since 1993 and a Director of Shenandoah Valley Electric Cooperative since 1970. Mr. Bowman is also a Director of Shenandoah Telecommunication Company.

M. Johnson Bowman (56).    President and Chief Executive Officer of Mecklenburg Electric Cooperative and Mecklenburg Communications Services, Inc. Mr. Bowman has been a Director of Old Dominion since 1974.

M Dale Bradshaw (48).    Chief Executive Officer of Prince George Electric Cooperative. Mr. Bradshaw has been a Director of Old Dominion since 1995.

Vernon N. Brinkley (55).    President and General Manager of A&N Electric Cooperative. Mr. Brinkley has been a Director of Old Dominion since 1982.

Calvin P. Carter (77).    Owner of Carter’s Store and Carter Stone Co., a stone quarry. Mr. Carter has been a Director of Old Dominion since 1991 and a Director of Southside Electric Cooperative since 1972.

Glenn F. Chappell (58).    Self-employed farmer. Mr. Chappell has been a Director of Old Dominion since 1995 and a Director of Prince George Electric Cooperative since 1985.

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Carl R. Eason (65).    Retired, formerly an electrical supervisor with International Paper. Mr. Eason has been a director of Old Dominion since 2000 and a director of Community Electric Cooperative since 1994.

Stanley C. Feuerberg (50).    President and Chief Executive Officer of Northern Virginia Electric Cooperative. Mr. Feuerberg has been a Director of Old Dominion since 1992.

Hunter R. Greenlaw, Jr. (56).    President of Greenlaw, Edwards & Leake, Inc., a real estate development and general contracting company. Mr. Greenlaw has been a Director of Old Dominion since 1991 and a Director of Northern Neck Electric Cooperative since 1979.

Bruce A. Henry (56).    Owner and Secretary/Treasurer of Delmarva Builders, Inc., a building contracting company. Mr. Henry has been a Director of Old Dominion since 1993 and a Director of Delaware Electric Cooperative since 1978.

Frederick L. Hubbard (61).    President and Chief Executive Officer of Choptank Electric Cooperative. Mr. Hubbard has been a Director of Old Dominion since 1991.

David J. Jones (53).    Vice President of Exchange Warehouse and owner/operator of Big Fork Farms. Mr. Jones has been a Director of Old Dominion since 1986 and a Director of Mecklenburg Electric Cooperative since 1982.

William M. Leech, Jr. (74).    Retired, former self-employed farmer. Mr. Leech has been a Director of Old Dominion since 1977 and a Director of BARC Electric Cooperative since 1970.

M. Larry Longshore(60).    President and Chief Executive Officer of Southside Electric Cooperative since 1998, prior to that Mr. Longshore was President and Chief Executive Officer of Newberry Electric Cooperative. Mr. Longshore has been a Director of Old Dominion since 1998.

James M. Reynolds (54).    President of Community Electric Cooperative. Mr. Reynolds has been a Director of Old Dominion since 1977.

Charles R. Rice, Jr. (59).    President and Chief Executive Officer of Northern Neck Electric Cooperative. Mr. Rice also served as interim President and Chief Executive Officer of Old Dominion in 1998. Mr. Rice has been a Director of Old Dominion since 1986.

Philip B. Tankard(73).    Office manager for Tankard Nurseries and retired superintendent of schools for Accomack County. Mr. Tankard has been a Director of Old Dominion since January 1, 2002 and a Director of A&N Electric Cooperative since 1960.

Cecil E. Viverette, Jr. (60).    President and Chief Executive Officer of Rappahannock Electric Cooperative. Mr. Viverette has been a Director of Old Dominion since 1988.

Richard L. Weaver (55).    Chief Executive Officer of BARC Electric Cooperative. Mr. Weaver has been a Director of Old Dominion since 1998.

Carl R. Widdowson (63).    Self-employed farmer. Mr. Widdowson has been a Director of Old Dominion since 1987 and a Director of Choptank Electric Cooperative since 1980.

C. Douglas Wine (59).    President and Chief Executive Officer of Shenandoah Valley Electric Cooperative and Manager of North River Telephone Cooperative. Mr. Wine has been a Director of Old Dominion since 1991.

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Executive Officers of Old Dominion

Our President and Chief Executive Officer administers our day-to-day business and affairs. Our executive officers, their respective ages and positions are listed below. Each executive officer serves at the discretion of our board of directors.

Jackson E. Reasor (49).    President and Chief Executive Officer of Old Dominion and the Virginia, Maryland and Delaware Association of Electric Cooperatives (“VMDA”) (an electric cooperative association which provides services to the Members and certain other electric cooperatives). Mr. Reasor served as Vice President of First Virginia Bank from 1997 until 1998; President and Chief Executive Officer of Premier Trust Company from 1995 until 1997; a Virginia State Senator from 1992 until 1998; and an attorney with Galumbeck, Simmons & Reasor from 1992 until 1995.

Daniel M. Walker (56).    Senior Vice President of Accounting and Finance.

Konstantinos N. Kappatos (59).    Senior Vice President of Engineering and Operations.

Gregory W. White (49).    Senior Vice President of Alliance Management. Mr. White also served as Vice President of the VMDA from 1996 until 1999, and interim Vice President of the VMDA from 1995 until 1996.

Item 11.    Executive Compensation

The following table sets forth information concerning compensation awarded to, earned by or paid to any person serving as our President and Chief Executive Officer or acting in a similar capacity during the last completed fiscal year and our three executive officers (collectively the “Named Executives”) for services rendered to us in all capacities during each of the last three fiscal years. The table also identifies the principal capacity in which each of the Named Executives served as of December 31, 2001.

SUMMARY COMPENSATION TABLE

	Annual Compensation
Name and Principal Position	Year	Salary(2)		Bonus		Other Annual Compen—sation(3)		All Other     Compen— sation(4)
Jackson E. Reasor(1)     President and Chief Executive Officer	2001 2000 1999	$	270,000 240,000 204,102	$	6,000 25,000 25,000	$	2,868 2,530 4,518	$	34,661 27,694 2,888
Daniel M. Walker Sr.     Vice President—Accounting & Finance	2001 2000 1999		168,178 161,245 155,043		—   —   8,000		—   —   —		24,390 22,064 26,928
Konstantinos N. Kappatos Sr.     Vice President—Engineering & Operations	2001 2000 1999		168,178 161,245 155,043		—   —   8,000		—   —   —		24,390 22,064 32,035
Gregory W. White Sr.     Vice President—Retail & Alliance Management	2001 2000 1999		135,200 128,333 66,714		—   —   —		—   —   —		19,651 16,464 6,082

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(1) In 1991, Old Dominion and the VMDA entered into an agreement pursuant to which the VMDA agreed to contribute to the President and Chief Executive Officer’s annual compensation. In 2001, 2000, and 1999, VMDA contributed $36,000, $36,000, and $24,000, respectively, toward the President and Chief Executive Officer’s annual compensation.

(2) Includes amounts deferred by the Named Executives under the provisions of a 401(k) retirement plan administered by Diversified Investment Advisors. In 2000 and 1999, the plan was administered by the National Rural Electric Cooperative Association. All employees of Old Dominion are eligible to become participants on the first day of the month following completion of one year of eligible service.

(3) Perquisites and other personal benefits paid to Mr. Reasor in 2001, 2000, and 1999 included expenses for a company automobile. Mr. Walker, Mr. Kappatos, and Mr. White did not receive any perquisites or other personal benefits in any of the fiscal years covered by the table.

(4) The amount reflected in this column for 2001 is composed of contributions made by Old Dominion under the Retirement and Security Plan and the 401(k) Plan, and payments made by Old Dominion for life insurance coverage. Specifically these amounts for 2001 were $29,616, $3,375, and $1,670 for Mr. Reasor; $19,898, $3,364, and $1,128 for Mr. Walker; $19,898, $3,364, and $1,128 for Mr. Kappatos; and $16,041, $2,704, and $905 for Mr. White, respectively.

On November 23, 2001, the initial term of the employment agreement with Jackson E. Reasor ended and the agreement was automatically extended for an additional year. Mr. Reasor’s employment agreement had an initial three-year term with a single one-year renewal unless either party gave notice of termination within 30 days prior to the third anniversary thereof. The agreement provided for an initial annual base salary of $200,000 and eligibility to receive a bonus as determined by our executive committee and approved by the board of directors. Pursuant to the agreement, if Mr. Reasor voluntarily terminates his employment without specified “good reason” or is terminated for specified causes prior to the expiration of the employment agreement, we will pay him base compensation and benefits through the effective date of his termination and we will have no obligation to pay Mr. Reasor his base salary, any bonus or other compensation for the remainder of the term of the employment agreement. If Mr. Reasor is terminated without cause or resigns for good reason prior to the expiration of the employment agreement, we must pay him his full base salary for a twelve-month period from the effective date of termination, at the rate effective on the date of termination, and medical benefits, subject to some exceptions. We currently are negotiating a new employment agreement with Mr. Reasor and expect it to be completed by the expiration of the renewal term.

Board Compensation

We pay our directors who are not employees of a member a monthly retainer of $1,350 plus $300 per day for any specially called meetings, $150 per travel day for other than a regular scheduled monthly board meeting. All directors are reimbursed for out-of-pocket expenses incurred in attending meetings.

Defined Benefit Plan

We have elected to participate in the NRECA Retirement and Security Program (the “Plan”), a noncontributory, defined benefit, multi-employer, master pension plan maintained and administered by the NRECA for the benefit of its member systems and their employees. The Plan is a qualified pension plan under Section 401(a) of the Internal Revenue Code of 1986. The following table lists the estimated current annual pension benefit payable at “normal retirement age,” age 62, for participants in the specified final average salary and years of benefit service categories for the given current multiplier of 1.7%. Benefits, which accrue under the Plan, are based upon the base annual salary as of November of the previous year. As a result of changes in Internal Revenue Service regulations, the base annual salary used in determining benefits is limited to $200,000 effective January 1, 2002.

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		Straight Life
		Years of Benefit Service
Final Average Salary		15		20		25		30		35
$  75,000	��	$	22,759	$	30,345	$	37,931	$	45,518	$	53,104
100,000			30,345		40,460		50,575		60,690		70,805
125,000			37,931		50,575		63,219		75,863		88,506
150,000			45,518		60,690		75,863		91,035		106,208
160,000			48,552		64,736		80,920		97,104		113,288
170,000			51,587		68,782		85,978		103,173		120,369
180,000			54,621		72,828		91,035		109,242		127,449
190,000			57,656		76,874		96,093		115,311		134,530
200,000			60,690		80,920		101,150		121,380		141,610

	50% Joint & Spouse
	Years of Benefit Service
Final Average Salary	15		20		25		30		35
$  75,000	$	19,125	$	25,500	$	31,875	$	38,250	$	44,625
100,000		25,500		34,000		42,500		51,000		59,500
125,000		31,875		42,500		53,125		63,750		74,375
150,000		38,250		51,000		63,750		76,500		89,250
160,000		40,800		54,400		68,000		81,600		95,200
170,000		43,350		57,800		72,250		86,700		101,150
180,000		45,900		61,200		76,500		91,800		107,100
190,000		48,450		64,600		80,750		96,900		113,050
200,000		51,000		68,000		85,000		102,000		119,000

The pension benefits indicated above are the estimated amounts payable by the Plan, and they are not subject to any deduction for Social Security or other offset amounts. The participant’s annual pension at his normal retirement date is equal to the product of his years of benefit service times final average salary times the multiplier in effect during years of benefit service. The multiplier was 1.7% commencing January 1, 1992.

As of December 31, 2001, years of credited service under the Plan at “normal retirement age” for each of the Named Executives was: Mr. Reasor, 2.08 years; Mr. Walker, 16.92 years; Mr. Kappatos, 16.92 years and Mr. White 23.22 years.

Salary Continuation Plan

In addition to the plan, two of our executive officers, Mr. Walker and Mr. Kappatos, also participate in salary continuation plans. In 1991, we entered into agreements with Mr. Walker and Mr. Kappatos to provide them with additional compensation after they reach the age of 65. The agreement states that if the executive is 50 or older on the date his employment is terminated for any reason whatsoever, absent malfeasance in office, we will pay compensation for 15 years after the executive has reached age 65. The amount of money payable to the executive is based on a formula that considers the executive’s age at termination of employment and years of service with us. The maximum annual compensation payable under the plan is $35,000 per year, payable if the executive’s employment is terminated at age 65 or older. Each agreement provides for payment of similar benefits to the executive’s beneficiaries in the event of his death or permanent disability. These agreements were terminated effective December 31, 2001 and no compensation or benefits are payable to Mr. Walker or Mr. Kappatos under the agreements.

Executive Severance Agreement

We have entered into executive severance agreements with Mr. Walker and Mr. Kappatos. Under the agreements, each executive is entitled to receive compensation in the amount of 1.5 times his base salary payable in 18 equal monthly installments if his employment is terminated other than due to death, disability, or for cause. If a change in

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control occurs and the executive’s employment is terminated by the executive for good reason or by us other than on account of the executive’s death, disability, or for cause, then the executive will be entitled to receive compensation in the amount of his base salary through his date of termination plus any benefits or awards earned but not yet paid and a lump sum payment equal to 2.99 times the executive’s base salary. Each agreement provides for payment of any remaining benefits to the executive’s beneficiaries in the event of death.

Option Agreements

On February 12, 2002, we adopted a plan permitting us to grant selected employees the option to purchase shares in specified mutual funds. On March 1, 2002, we entered into an option agreement under the plan with each of Mr. Walker and Mr. Kappatos. Under the agreements, we granted each of these officers the option to purchase from us shares of mutual funds. The price to be paid for exercise of the option shares is 25% of the stated total option value amount which has vested as of the date of the purchase. The stated total option value amount for both agreements is $408,000 and vests in equal amounts on March 1, 2002 and each January 1st thereafter until 2007 (in the case of Mr. Walker) and 2005 (in the case of Mr. Kappatos). Option value amounts vest under the agreement only if the officer is still an employee on the applicable vesting date. Vesting accelerates if a change of control occurs or if the officer dies or becomes disabled.

Neither officer can exercise his rights under the agreement unless he has attained retirement age as identified in our retirement policy (currently 62) and terminated his employment with us, including as a result of his death or disability. Each officer (or his beneficiary or representative) must exercise the option before March 1, 2017. If we terminate the officer for cause, all vested and unvested option rights expire immediately as of the date of the misconduct.

Item 12.    Security Ownership Of Certain Beneficial Owners And Management

Not Applicable

Item 13.    Certain Relationships And Related Transactions

Not Applicable

Item 14.    Exhibits, Financial Statement Schedules, And Reports On Form 8-k

(a)  The following documents are filed as part of this Form 10-K.

1.  Financial Statements

See Index on page 43.

2.  Financial Statement Schedules

All financial statement schedules have been omitted since they are not required or are not applicable or the required information is shown in the financial statements or notes thereto.

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3.  Exhibits

*3.1	Amended and Restated Articles of Incorporation of Old Dominion Electric Cooperative (filed as exhibit 3.1 to the Registrant’s Form 10-Q, File No. 33-46795, filed on August 11, 2000).
*3.2	Bylaws of Old Dominion Electric Cooperative, Amended and Restated as of November 9, 1999 (filed as exhibit 3.2 to the Registrant’s Form 10-Q, File No. 33-46795, filed on August 11, 2000).
*4.1	Indenture of Mortgage and Deed of Trust, dated as of May 1, 1992, between Old Dominion Electric Cooperative and Crestar Bank, as Trustee (filed as exhibit 4.1 to the Registrant’s Form 10-K for the year ended December 31, 1992, File No. 33-46795, filed on March 30, 1993).
*4.2	First Supplemental Indenture, dated as of August 1, 1992, to the Indenture of Mortgage and Deed of Trust, dated as of May 1, 1992, between Old Dominion Electric Cooperative and Crestar Bank, as Trustee (filed as exhibit 4.22 to the Registrant’s Form 10-K for the year ended December 31, 1992, File No. 33-46795, filed on March 30, 1993).
*4.3	Second Supplemental Indenture, dated as of December 1, 1992, to the Indenture of Mortgage and Deed of Trust, dated as of May 1, 1992, between Old Dominion Electric Cooperative and Crestar Bank, as Trustee (filed as exhibit 4.24 to the Registrant’s Form 10-K for the year ended December 31, 1992, File No. 33-46795, filed on March 30, 1993).
*4.4	Third Supplemental Indenture, dated as of May 1, 1993, to the Indenture of Mortgage and Deed of Trust, dated as of May 1, 1992, between Old Dominion Electric Cooperative and Crestar Bank, as Trustee (filed as exhibit 4.1 to the Registrant’s Form 10-Q for the quarter ended June 30, 1993, File No. 33-46795, filed on August 10, 1993).
*4.5	Fourth Supplemental Indenture, dated as of December 15, 1994, to the Indenture of Mortgage and Deed of Trust dated as of May 1, 1992, between Old Dominion Electric Cooperative and Crestar Bank, as Trustee (filed as exhibit 4.5 to the Registrant’s Form 10-K for the year ended December 31, 1996, File No. 33-46795, on March 20, 1997).
*4.6	Fifth Supplemental Indenture, dated as of February 29, 1996, to the Indenture of Mortgage and Deed of Trust dated as of May 1, 1992, between Old Dominion Electric Cooperative and Crestar Bank, as Trustee (filed as exhibit 4.6 to the Registrant’s Form 10-K for the year ended December 31, 1996, File No. 33-46795, on March 20, 1997).
*4.7	Sixth Supplemental Indenture, dated as of November 28, 1997, to the Indenture of Mortgage and Deed of Trust dated as of May 1, 1992, between Old Dominion Electric Cooperative and Crestar Bank, as Trustee (filed as exhibit 4.7 to the Registrant’s Form 10-K for the year ended December 31, 1998, File No. 33-46795, on March 25, 1999).
*4.8	Seventh Supplemental Indenture, dated as of November 1, 1998, to the Indenture of Mortgage and Deed of Trust dated as of May 1, 1992, between Old Dominion Electric Cooperative and Crestar Bank, as Trustee (filed as exhibit 4.8 to the Registrant’s Form 10-K for the year ended December 31, 1998, File No. 33-46795, on March 25, 1999).
*4.9	Eighth Supplemental Indenture, dated as of November 30, 1998, to the Indenture of Mortgage and Deed of Trust dated as of May 1, 1992, between Old Dominion Electric Cooperative and Crestar Bank, as Trustee (filed as exhibit 4.9 to the Registrant’s Form 10-K for the year ended December 31, 1998, File No. 33-46795, on March 25, 1999).
*4.10	Ninth Supplemental Indenture, dated as of November 1, 1999, to the Indenture of Mortgage and Deed of Trust dated as of May 1, 1992, between Old Dominion Electric Cooperative and Crestar Bank, as Trustee (filed as exhibit 4.10 to the Registrant’s Form 10-K for the year ended December 31, 1999, File No. 33-46795, on March 22, 2000).

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*4.11	Tenth Supplemental Indenture, dated as of November 1, 2000, to the Indenture of Mortgage and Deed of Trust dated as of May 1, 1992, between Old Dominion Electric Cooperative and Suntrust Bank (formerly Crestar Bank), as Trustee (filed as exhibit 4.11 to the Registrant’s Form 10-K for the year ended December 31, 2000, File No. 33-46795, on March 19, 2001).
*4.12	Eleventh Supplemental Indenture, dated as of September 1, 2001, to the Indenture of Mortgage and Deed of Trust dated as of May 1, 1992, between Old Dominion Electric Cooperative and SunTrust Bank (formerly Crestar Bank), as Trustee (filed as exhibit 4.1 to the Registrant’s Form 10-Q/A for the quarter ended September 30, 2001, File No. 33-46795, filed on November 20, 2001).
4.13	Twelfth Supplemental Indenture, dated as of November 1, 2001, to the Indenture of Mortgage and Deed of Trust dated as of May 1, 1992, between Old Dominion Electric Cooperative and SunTrust Bank (Formerly Crestar Bank), as Trustee.
*4.14	Amended and Restated Indenture, dated as of September 1, 2001, between Old Dominion Electric Cooperative and SunTrust Bank, as Trustee (filed as exhibit 4.2 to Registrant’s Form 10-Q/A for the quarter ended September 30, 2001, File No. 33-46795, filed on November 20, 2001).
*4.15	Form of Bonds, 1992 Series A (filed as exhibit 4.2 to Amendment No. 1 to the Registrant’s Form S-1 Registration Statement, File No. 33-46795, filed on May 6, 1992).
*4.16	Form of Bonds, 1992 Series C (filed as exhibit 4.23 to the Registrant’s Form 10-K for the year ended December 31, 1992, File No. 33-46795, filed on March 30, 1993).
*4.17	Form of Bonds, 1993 Series A (filed as exhibit 4.2 to the Registrant’s Form S-1 Registration Statement, File No. 33-61326, filed on April 19, 1993).
*4.18	Form of Bonds, 2001 Series A (filed as exhibit 4.13 to the Registrant’s Amendment No. 1 to Form S-1 Registration Statement, File No. 333-68014, filed on September 10, 2001).
*10.1	Nuclear Fuel Agreement between Virginia Electric and Power Company and Old Dominion Electric Cooperative, dated as of December 28, 1982, amended and restated October 17, 1983 (filed as exhibit 10.1 to the Registrant’s Form S-1 Registration Statement, File No. 33-46795, filed on March 27, 1992).
*10.2	Purchase, Construction and Ownership Agreement between Virginia Electric and Power Company and Old Dominion Electric Cooperative, dated as of December 28, 1982, amended and restated October 17, 1983 (filed as exhibit 10.2 to the Registrant’s Form S-1 Registration Statement, File No. 33-46795, filed on March 27, 1992).
***10.3	Amended and Restated Interconnection and Operating Agreement between Virginia Electric and Power Company and Old Dominion Electric Cooperative, dated as of July 29, 1997 (filed as exhibit 10.5 to the Registrant’s Form 10-K for the year ended December 31, 1998, File No. 33-46795, on March 25, 1999).
***10.4	Service Agreement for Network Integration Transmission Service to Old Dominion Electric Cooperative between Virginia Electric and Power Company and Old Dominion Electric Cooperative, dated as of July 29, 1997 (filed as exhibit 10.6 to the Registrant’s Form 10-K for the year ended December 31, 1998, File No. 33-46795, on March 25, 1999).
***10.5	Network Operating Agreement between Virginia Electric and Power Company and Old Dominion Electric Cooperative, dated as of July 29, 1997 (filed as exhibit 10.7 to the Registrant’s Form 10-K for the year ended December 31, 1998, File No. 33-46795, on March 25, 1999).
*10.6	Clover Purchase, Construction and Ownership Agreement between Old Dominion Electric Cooperative and Virginia Electric and Power Company, dated as of May 31, 1990 (filed as exhibit 10.4 to the Registrant’s Form S-1 Registration Statement, File No. 33-46795, filed on March 27, 1992).

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*10.7	Amendment No. 1 to the Clover Purchase, Construction and Ownership Agreement between Old Dominion Electric Cooperative and Virginia Electric and Power Company, effective March 12, 1993 (filed as exhibit 10.34 to the Registrant’s Form S-1 Registration Statement, File No. 33-61326, filed on April 19, 1993).
*10.8	Clover Operating Agreement between Virginia Electric and Power Company and Old Dominion Electric Cooperative, dated as of May 31, 1990 (filed as exhibit 10.6 to the Registrant’s Form S-1 Registration Statement, File No. 33-46795, filed on March 27, 1992).
*10.9	Amendment to the Clover Operating Agreement between Virginia Electric and Power Company and Old Dominion Electric Cooperative, effective January 17, 1995 (filed as exhibit 10.8 to the Registrant’s Form 10-K for the year ended December 31, 1994, File No. 33-46795, on March 15, 1995).
*10.10	Electric Service Agreement between Old Dominion Electric Cooperative and Appalachian Power Company, dated July 2, 1990 (filed as exhibit 10.8 to the Registrant’s Form S-1 Registration Statement, File No. 33-46795, filed on March 27, 1992).
*10.11	Electric Service Agreement between Old Dominion Electric Cooperative and Appalachian Power Company, dated March 6, 1991 (filed as exhibit 10.9 to the Registrant’s Form S-1 Registration Statement, File No. 33-46795, filed on March 27, 1992).
*10.12	Lease Agreement between Old Dominion Electric Cooperative and Regional Headquarters, Inc., dated July 29, 1986 (filed as exhibit 10.27 to the Registrant’s Form S-1 Registration Statement, File No. 33-46795, filed on March 27, 1992).
*10.13	Credit Agreement between Virginia Electric and Power Company and Old Dominion Electric Cooperative, dated as of December 1, 1985 (filed as exhibit 10.28 to the Registrant’s Form S-1 Registration Statement, File No. 33-46795, filed on March 27, 1992).
*10.14	Nuclear Decommissioning Trust Agreement between Old Dominion Electric Cooperative and Bankers Trust Company, dated March 1, 1991 (filed as exhibit 10.29 to the Registrant’s Form S-1 Registration Statement, File No. 33-46795, filed on March 27, 1992).
*10.15	Form of Salary Continuation Plan (filed as exhibit 10.31 to the Registrant’s Form S-1 Registration Statement, File No. 33-46795, filed on March 27, 1992).
*10.16	Amended and Restated Wholesale Power Contract between Old Dominion Electric Cooperative and A&N Electric Cooperative, dated April 24, 1992 (filed as exhibit 10.34 to Amendment No. 2 to the Registrant’s Form S-1 Registration Statement, File No. 33-46795, filed on May 27, 1992).
*10.17	Amended and Restated Wholesale Power Contract between Old Dominion Electric Cooperative and BARC Electric Cooperative, dated April 22, 1992 (filed as exhibit 10.35 to Amendment No. 1 to the Registrant’s Form S-1 Registration Statement, File No. 33-46795, filed on May 6, 1992).
*10.18	Amended and Restated Wholesale Power Contract between Old Dominion Electric Cooperative and Choptank Electric Cooperative, dated April 20, 1992 (filed as exhibit 10.36 to Amendment No. 1 to the Registrant’s Form S-1 Registration Statement, File No. 33-46795, filed on May 6, 1992).
*10.19	Amended and Restated Wholesale Power Contract between Old Dominion Electric Cooperative and Community Electric Cooperative, dated April 28, 1992 (filed as exhibit 10.37 to Amendment No. 1 to the Registrant’s Form S-1 Registration Statement, File No. 33-46795, filed on May 6, 1992).
*10.20	Amended and Restated Wholesale Power Contract between Old Dominion Electric Cooperative and Delaware Electric Cooperative, dated April 22, 1992 (filed as exhibit 10.38 to Amendment No. 1 to the Registrant’s Form S-1 Registration Statement, File No. 33-46795, filed on May 6, 1992).
*10.21	Amended and Restated wholesale Power Contract between Old Dominion Electric Cooperative and Mecklenburg Electric Cooperative, dated April 15, 1992 (filed as exhibit 10.39 to Amendment No. 1 to the Registrant’s Form S-1 Registration Statement, File No. 33-46795, filed on May 6, 1992).

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*10.22	Amended and Restated Wholesale Power Contract between Old Dominion Electric Cooperative and Northern Neck Electric Cooperative, dated April 21, 1992 (filed as exhibit 10.40 to Amendment No. 1 to the Registrant’s Form S-1 Registration Statement, File No. 33-46795, filed on May 6, 1992).
*10.23	Amended and Restated Wholesale Power Contract between Old Dominion Electric Cooperative and Northern Virginia Electric Cooperative, dated April 17, 1992 (filed as exhibit 10.41 to Amendment No. 1 to the Registrant’s Form S-1 Registration Statement, File No. 33-46795, filed on May 6, 1992).
*10.24	Amended and Restated Wholesale Power Contract between Old Dominion Electric Cooperative and Prince George Electric Cooperative, dated May 6, 1992 (filed as exhibit 10.42 to Amendment No. 2 to the Registrant’s Form S-1 Registration Statement, File No. 33-46795, filed on May 27, 1992).
*10.25	Amended and Restated Wholesale Power Contract between Old Dominion Electric Cooperative and Rappahannock Electric Cooperative, dated April 17, 1992 (filed as exhibit 10.43 to Amendment No. 1 to the Registrant’s Form S-1 Registration Statement, File No. 33-46795, filed on May 6, 1992).
*10.26	Amended and Restated Wholesale Power Contract between Old Dominion Electric Cooperative and Shenandoah Valley Electric Cooperative, dated April 23, 1992 (filed as exhibit 10.44 to Amendment No. 1 to the Registrant’s Form S-1 Registration Statement, File No. 33-46795, filed on May 6, 1992).
*10.27	Amended and Restated Wholesale Power Contract between Old Dominion Electric Cooperative and Southside Electric Cooperative, dated April 22, 1992 (filed as exhibit 10.45 to Amendment No. 1 to the Registrant’s Form S-1 Registration Statement, File No. 33-46795, filed on May 6, 1992).
*10.28	Capacity and Energy Sales Agreement between Old Dominion Electric Cooperative and Public Service Electric and Gas, dated December 17, 1992, effective January 1, 1995 (filed as exhibit 10.30 to the Registrant’s Form 10-K for the year ended December 31, 1992, File No. 33-46795, filed on March 30, 1993).
*10.29	First Supplement to Capacity and Energy Sales Agreement between Old Dominion Electric Cooperative and Public Service Electric & Gas, dated March 26, 1993 (filed as exhibit 10.32 to the Registrant’s Form S-1 Registration Statement, File No. 33-61326, filed on April 19, 1993).
*10.30	Interconnection Agreement between Delmarva Power & Light Company and Old Dominion Electric Cooperative, dated November 30, 1999 (filed as exhibit 10.33 to the Registrant’s Form 10-K for the year ended December 31, 2000, File No. 33-46795, on March 19, 2001).
*10.31	Transmission Service Agreement between Delmarva Power & Light Company and Old Dominion Electric Cooperative, effective January 1, 1995 (filed as exhibit 10.39 to the Registrant’s Form 10-K for the year ended December 31, 1994, File No. 33-46795, on March 15, 1995).
*10.32	Participation Agreement, dated as of February 29, 1996, among Old Dominion Electric Cooperative, State Street Bank and Trust Company, the Owner Participant named therein and Utrecht-America Finance Co (filed as exhibit 10.35 to the Registrant’s Form 10-K for the year ended December 31, 1996, File No. 33-46795, on March 20, 1997).
*10.33	Clover Unit 1 Equipment Interest Lease Agreement, dated as of February 29, 1996, between Old Dominion Electric Cooperative, as Equipment Head Lessor, and State Street Bank and Trust Company, as Equipment Head Lessee (filed as exhibit 10.36 to the Registrant’s Form 10-K for the year ended December 31, 1996, File No. 33-46795, on March 20, 1997).
**10.34	Equipment Operating Lease Agreement, dated as of February 29, 1996, between State Street Bank and Trust Company, as Lessor, and Old Dominion Electric Cooperative, as Lessee (filed as exhibit 10.37 to the Registrant’s Form 10-K for the year ended December 31, 1996, File No. 33-46795, on March 20, 1997).
**10.35	Corrected Option Agreement to Lease, dated as of February 29, 1996, among Old Dominion Electric Cooperative and State Street Bank and Trust Company (filed as exhibit 10.38 to the Registrant’s Form 10-K for the year ended December 31, 1996, File No. 33-46795, on March 20, 1997).

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*10.36	Clover Agreements Assignment and Assumption Agreement, dated as of February 29, 1996, between Old Dominion Electric Cooperative, as Assignor, and State Street Bank and Trust Company, as Assignee (filed as exhibit 10.39 to the Registrant’s Form 10-K for the year ended December 31, 1996, File No. 33-46795, on March 20, 1997).
*10.37	Deposit Agreement, dated as of February 29, 1996, between Old Dominion Electric Cooperative, as Depositor, and Cooperatieve Centrale Raiffeisen-Boerenleenbank B.A., “Rabobank Nederland”, New York Branch, as Issuer (filed as exhibit 10.40 to the Registrant’s Form 10-K for the year ended December 31, 1996, File No. 33-46795, on March 20, 1997).
*10.38	Deposit Pledge Agreement, dated as of February 29, 1996, between Old Dominion Electric Cooperative, as Pledgor, and State Street Bank and Trust Company, as Pledgee (filed as exhibit 10.41 to the Registrant’s Form 10-K for the year ended December 31, 1996, File No. 33-46795, on March 20, 1997).
*10.39	Payment Undertaking Agreement, dated as of February 29, 1996, between Old Dominion Electric Cooperative and Cooperatieve Centrale Raiffeisen-Boerenleenbank B.A., “Rabobank Nederland”, New York Branch (filed as exhibit 10.42 to the Registrant’s Form 10-K for the year ended December 31, 1996, File No. 33-46795, on March 20, 1997).
*10.40	Payment Undertaking Pledge Agreement, dated as of February 29, 1996, between Old Dominion Electric Cooperative, as Payment Undertaking Pledgor, and State Street Bank and Trust Company, as Payment Undertaking Pledgee (filed as exhibit 10.43 to the Registrant’s Form 10-K for the year ended December 31, 1996, File No. 33-46795, on March 20, 1997).
*10.41	Pledge Agreement, dated as of February 29, 1996, between Old Dominion Electric Cooperative, as Pledgor, and State Street Bank and Trust Company, as Pledgee (filed as exhibit 10.44 to the Registrant’s Form 10-K for the year ended December 31, 1996, File No. 33-46795, on March 20, 1997).
*10.42	Tax Indemnity Agreement, dated as of February 29, 1996, among Old Dominion Electric Cooperative, State Street Bank and Trust Company, the Owner Participant named therein and Utrecht-America Finance Co. (filed as exhibit 10.45 to the Registrant’s Form 10-K for the year ended December 31, 1996, File No. 33-46795, on March 20, 1997).
*10.43	Participation Agreement, dated as of July 1, 1996, among Old Dominion Electric Cooperative, Clover Unit 2 Generating Trust, Wilmington Trust Company, the Owner Participant named therein and Utrecht-America Finance Co. (filed as exhibit 10.46 to the Registrant’s Form 10-K for the year ended December 31, 1996, File No. 33-46795, on March 20, 1997).
**10.44	Clover Unit 2 Equipment Interest Agreement, dated as of July 1, 1996, between Old Dominion Electric Cooperative and Clover Unit 2 Generating Trust (filed as exhibit 10.47 to the Registrant’s Form 10-K for the year ended December 31, 1996, File No. 33-46795, on March 20, 1997).
**10.45	Operating Equipment Agreement, dated as of July 1, 1996, between Clover Unit 2 Generating Trust and Old Dominion Electric Cooperative (filed as exhibit 10.48 to the Registrant’s Form 10-K for the year ended December 31, 1996, File No. 33-46795, on March 20, 1997).
*10.46	Clover Agreements Assignment and Assumption Agreement, dated as of July 1, 1996, between Old Dominion Electric Cooperative, as Assignor, and Clover Unit 2 Generating Trust, as Assignee (filed as exhibit 10.49 to the Registrant’s Form 10-K for the year ended December 31, 1996, File No. 33-46795, on March 20, 1997).
*10.47	Deed of Ground Lease and Sublease Agreement, dated as of July 1, 1996, between Old Dominion Electric Cooperative, as Ground Lessor, and Clover Unit 2 Generating Trust, as Ground Lessee (filed as exhibit 10.50 to the Registrant’s Form 10-K for the year ended December 31, 1996, File No. 33-46795, on March 20, 1997).

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*10.48	Guaranty Agreement, dated as of July 1, 1996, between Old Dominion Electric Cooperative and AMBAC Indemnity Corporation (filed as exhibit 10.51 to the Registrant’s Form 10-K for the year ended December 31, 1996, File No. 33-46795, on March 20, 1997).
*10.49	Investment Agreement, dated as of July 31, 1996, among AMBAC Capital Funding, Inc., Old Dominion Electric Cooperative and AMBAC Indemnity Corporation (filed as exhibit 10.52 to the Registrant’s Form 10-K for the year ended December 31, 1996, File No. 33-46795, on March 20, 1997).
*10.50	Investment Agreement Pledge Agreement, dated as of July 1, 1996, among Old Dominion Electric Cooperative, as Investment Agreement Pledgor, AMBAC Indemnity Corporation, the Owner Participant named therein and Clover Unit 2 Generating Trust (filed as exhibit 10.53 to the Registrant’s Form 10-K for the year ended December 31, 1996, File No. 33-46795, on March 20, 1997).
*10.51	Equity Security Pledge Agreement, dated as of July 1, 1996, between Old Dominion Electric Cooperative, as Pledgor, and Wilmington Trust Company, as Collateral Agent (filed as exhibit 10.54 to the Registrant’s Form 10-K for the year ended December 31, 1996, File No. 33-46795, on March 20, 1997).
*10.52	Payment Undertaking Agreement, dated as of July 1, 1996, between Old Dominion Electric Cooperative and Cooperatieve Centrale Raiffeisen-Boerenleenbank B.A., “Rabobank Nederland”, New York Branch (filed as exhibit 10.55 to the Registrant’s Form 10-K for the year ended December 31, 1996, File No. 33-46795, on March 20, 1997).
*10.53	Payment Undertaking Pledge Agreement, dated as of July 1, 1996, between Old Dominion Electric Cooperative, as Payment Undertaking Pledgor, and Clover Unit 2 Generating Trust, as Payment Undertaking Pledgee (filed as exhibit 10.56 to the Registrant’s Form 10-K for the year ended December 31, 1996, File No. 33-46795, on March 20, 1997).
*10.54	Subordinated Deed of Trust and Security Agreement, dated as of July 1, 1996, among Old Dominion Electric Cooperative, Richard W. Gregory, Trustee, and Michael P. Drzal, Trustee (filed as exhibit 10.57 to the Registrant’s Form 10-K for the year ended December 31, 1996, File No. 33-46795, on March 20, 1997).
*10.55	Subordinated Security Agreement, dated as of July 1, 1996, among Old Dominion Electric Cooperative, the Owner Participant named therein, AMBAC Indemnity Corporation and Clover Unit 2 Generating Trust (filed as exhibit 10.58 to the Registrant’s Form 10-K for the year ended December 31, 1996, File No. 33-46795, on March 20, 1997).
*10.56	Tax Indemnity Agreement, dated as of July 1 1996, between Old Dominion Electric Cooperative and the Owner Participant named therein (filed as exhibit 10.59 to the Registrant’s Form 10-K for the year ended December 31, 1996, File No. 33-46795, on March 20, 1997).
*10.57	Special Terms and Conditions of Purchase, dated June 29, 2000, between Old Dominion Electric Cooperative and General Electric Company (filed as exhibit 10.60 to the Registrant’s Amendment No. 1 to Form S-1 Registration Statement, File No. 333-68014, on September 10, 2001).
*10.58	Special Terms and Conditions of Purchase, dated July 14, 2000, between Old Dominion Electric Cooperative and General Electric Company (filed as exhibit 10.61 to the Registrant’s Amendment No. 1 to Form S-1 Registration Statement, File No. 333-68014, on September 10, 2001).
*10.59	Special Terms and Conditions of Purchase, dated November 9, 2000, between Old Dominion Electric Cooperative and General Electric Company (filed as exhibit 10.62 to the Registrant’s Amendment No. 1 to Form S-1 Registration Statement, File No. 333-68014, on September 10, 2001).
*10.60	Employment Agreement, dated November 23, 1998, between Old Dominion Electric Cooperative and Jackson E. Reasor (filed as exhibit 10.63 to the Registrant’s Form S-1 Registration Statement, File No. 333-68014, on August 21, 2001).

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*10.61	Executive Severance Agreement, dated January 1, 2000, between Old Dominion Electric Cooperative and Daniel M. Walker (filed as exhibit 10.64 to the Registrant’s Form S-1 Registration Statement, File No. 333-68014, on August 21, 2001).
*10.62	Executive Severance Agreement, dated January 1, 2000, between Old Dominion Electric Cooperative and Konstantinos N. Kappatos (filed as exhibit 10.65 to the Registrant’s Form S-1 Registration Statement, File No. 333-68014, on August 21, 2001).
10.63	Old Dominion Electric Cooperative 2002 Option Plan, dated as of February 12, 2002.
10.64	Option Agreement between Old Dominion Electric Cooperative and Daniel M. Walker, dated as of March 1, 2002.
10.65	Option Agreement between Old Dominion Electric Cooperative and Konstantinos N. Kappatos, dated as of March 1, 2002.
21	Subsidiaries of Old Dominion Electric Cooperative (not included because Old Dominion Electric Cooperative’s subsidiaries, considered in the aggregate as a single subsidiary, would not constitute a “significant subsidiary” under Rule 1-02(w) of Regulation S-X).

(b)  Reports on Form 8-K.

No reports on form 8-K were filed during the fourth quarter of 2001.

* Incorporated herein by reference.

** These leases relate to our interest in all of Clover Unit 1 and Clover Unit 2, as applicable, other than the foundations. At the time these leases were executed, we had entered into identical leases with respect to the foundations as part of the same transactions. We agree to furnish to the Commission, upon request, a copy of the leases of our interest in the foundations for Clover Unit 1 and Clover Unit 2, as applicable.

*** This agreement consists of two separate signed documents, which have been combined.

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SIGNATURES

Pursuant to the requirements of Section 13 or 15(d) 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
By:	/s/    JACKSON E. REASOR
	Jackson E. Reasor President and Chief Executive Officer

Date: October 8, 2002

Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the Registrant and in the following capacities on October 8, 2002.

Signature	Title
/s/    JACKSON E. REASOR         Jackson E. Reasor	President (principal executive officer)
/s/    DANIEL M. WALKER         Daniel M. Walker	Sr. Vice President of Accounting & Finance (principal financial officer)
/s/    ROBERT L. KEES         Robert L. Kees	Assistant Vice President & Controller (principal accounting officer)
/s/    WILLIAM M. ALPHIN         William M. Alphin	Director
/s/    E. Paul Bienvenue         E. Paul Bienvenue	Director
/s/    JOHN E. BONFADINI         John E. Bonfadini	Director
/s/    DICK D. BOWMAN         Dick D. Bowman	Director
/s/    M. JOHNSON BOWMAN         M. Johnson Bowman	Director

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Signature	Title
/s/    M DALE BRADSHAW         M Dale Bradshaw	Director
/s/    VERNON N. BRINKLEY         Vernon N. Brinkley	Director
/s/    CALVIN P. CARTER         Calvin P. Carter	Director
Glenn F. Chappell	Director
/s/    CARL R. EASON         Carl R. Eason	Director
/s/    STANLEY C. FEUERBERG       �� Stanley C. Feuerberg	Director
/s/    HUNTER R. GREENLAW, JR.         Hunter R. Greenlaw, Jr	Director
/s/    BRUCE A. HENRY         Bruce A. Henry	Director
Frederick L. Hubbard	Director
/s/    DAVID J. JONES         David J. Jones	Director
/s/    HUGH M. LANDES         Hugh M. Landes	Director
/s/    WILLIAM M. LEECH, JR.         William M. Leech, Jr.	Director
/s/    M. LARRY LONGSHORE         M. Larry Longshore	Director
/s/    JAMES M. REYNOLDS         James M. Reynolds	Director
/s/    CHARLES R. RICE, JR.         Charles R. Rice, Jr.	Director
/s/    PHILIP B. TANKARD         Philip B. Tankard	Director

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Signature	Title
/s/    CECIL E. VIVERETTE, JR.         Cecil E. Viverette, Jr.	Director
/s/    CARL R. WIDDOWSON         Carl R. Widdowson	Director
/s/    C. DOUGLAS WINE         C. Douglas Wine	Director

SUPPLEMENTAL INFORMATION TO BE FURNISHED WITH REPORTS FILED PURSUANT TO SECTION 15(d) OF THE ACT BY REGISTRANTS WHICH HAVE NOT REGISTERED SECURITIES PURSUANT TO SECTION 12 OF THE ACT.

Old Dominion does not solicit proxies from its cooperative members and thus is not required to provide an annual report to its security holders and will not prepare such a report after filing this form 10-K for fiscal year 2001. Accordingly, Old Dominion will not file an annual report with the Securities and Exchange Commission.

78