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UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-K

(Mark One)

For the fiscal year ended December 31, 2003

OR

For the transition period from              to             

Commission file number 000-50039

OLD DOMINION ELECTRIC COOPERATIVE

(Exact name of Registrant as specified in its charter)

(804) 747-0592

(Registrant’s telephone number, including area code)

Securities registered pursuant to Section 12(b) of the Act: NONE

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

6.25% 2001 Series A Bonds due 2011

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

Indicate by check mark whether the Registrant is an accelerated filer (as defined in Exchange Act Rule 12b-2).    Yes  ¨    No  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

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OLD DOMINION ELECTRIC COOPERATIVE

2003 ANNUAL REPORT ON FORM 10-K

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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 479,000 retail electric consumers (meters) representing a total population of approximately 1.2 million people in 2003. 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 are fueled by a mix of coal, nuclear, natural gas, fuel oil, and diesel fuel. See “Power Supply Resources” and “Properties” in Item 2 for discussion and a description of these resources.

We are owned entirely by our members, which are the primary purchasers of the power we sell. We have two classes of members. Our Class A members are twelve customer-owned electric distribution cooperatives that sell electric service to their customers in 70 counties throughout Virginia, Delaware, Maryland, and a small portion of West Virginia. Our sole Class B member is TEC Trading, Inc. (“TEC”), a corporation owned by our member distribution cooperatives. TEC was formed for the primary purposes of purchasing power from us to sell in the market, acquiring natural gas to supply the three combustion turbine facilities, and taking advantage of other power-related trading opportunities in the market. TEC does not engage in speculative trading. See “TEC” below.

Our member distribution cooperatives primarily serve suburban, rural and recreational areas. These areas predominantly reflect stable growth in residential capacity and energy requirements both with respect to power sales and number of customers. See “Members’ Service Territories and Customers.” Under state restructuring legislation, nearly all customers of our member distribution cooperatives are able to select their power suppliers as of January 1, 2004. The member distribution cooperatives are 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 a further discussion of our tax status.

We are not a party to any collective bargaining agreement. We had 82 employees as of March 1, 2004.

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

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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 many changes in the electric utility industry, including 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 becoming competitive. See “Management’s Discussion and Analysis of Financial Condition and Results of Operations—Future Issues—Competition and Changing Regulations” in Item 7.

Potential Restructuring

As we strive to meet our member distribution cooperatives’ requirements in the most efficient and cost effective manner, we continually explore new ways to respond to the challenges facing us. We presently are exploring a possible restructuring that we believe could provide additional flexibility to finance capital expenditures and eliminate some existing operational constraints. This restructuring involves the creation of a new taxable power supply cooperative (“New Dominion”). All of our member distribution cooperatives would exchange their membership interests in us for a membership interest in New Dominion. All of their equity in us would be transferred to New Dominion in return for an equal amount of equity in New Dominion. As a result, New Dominion would become our sole member.

New Dominion would enter into a take-or-pay power sales contract with us, pursuant to which New Dominion would agree to purchase and receive 100% of the output and services of our power supply resources and to pay 100% of our costs, including amounts sufficient for us to meet the rate covenant under our Indenture of Mortgage and Deed of Trust, dated as of May 1, 1992, with Crestar Bank (predecessor to SunTrust Bank), as trustee (the “Indenture”). Payments required under this contract would not be excused by any event, including our inability or failure to perform. The wholesale power contracts we currently have with our member distribution cooperatives would be assigned to and assumed by New Dominion. We currently contemplate that there would not be any material changes in the terms and conditions of those contracts.

TEC would withdraw as a Class B member in conjunction with the completion of the restructuring and our power sales relationship with TEC also would be terminated in conjunction with the completion of the restructuring.

Following the restructuring, we anticipate that New Dominion would conduct physical and financial power and gas procurement activities and purchase, in the markets, the power and energy needed to supply the member distribution cooperatives over and above that obtained from us. New Dominion would not engage in speculative marketing or trading activities. We would expect to continue to perform all of our other current operations, including our obligations to operate and maintain our generating facilities. Future generating resources, including purchased power agreements, could be located in either New Dominion or Old Dominion, depending upon our analysis of the advantages and disadvantages at the time.

New Dominion would be a taxable cooperative; however, no change would occur in our tax-exempt status as a result of the reorganization. We would continue to be regulated by federal or state governmental authorities in the same manner as we currently are, and we expect that New Dominion would be regulated in a manner similar to us.

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Any restructuring we enter into would incorporate several measures intended to protect our credit profile. The restructuring would not affect the ownership of any of our tangible assets, including our interest in any of our generating facilities. We would continue to be responsible for all of our existing indebtedness, but New Dominion would guarantee all of our outstanding obligations under our Indenture. In addition, we would enter into a mutual credit agreement with New Dominion under which either of us could provide loans, guarantees, or other credit support to the other.

Following the restructuring, both our and New Dominion’s board of directors would consist of two representatives of each of the member distribution cooperatives. No changes in our management personnel are contemplated as a result of the restructuring. We would supply all administrative and management services required by New Dominion under a separate agreement.

On February 10, 2004, our board of directors voted 23 to 0, with two abstentions, to authorize our negotiating and entering into a definitive reorganization agreement and obtaining any necessary consents to implement the reorganization. The two board members who abstained from this vote are representatives of Northern Virginia Electric Cooperative, our largest member. The boards of directors of our member distribution cooperatives are considering resolutions approving the reorganization. We do not intend to pursue the restructuring unless all of our directors and the boards of directors of our member distribution cooperatives approve the restructuring. For this reason, we cannot determine when or if the restructuring will occur.

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, Delaware, Maryland, 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. Our remaining nine members, which serve mainland Virginia, 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 member distribution cooperatives are not our subsidiaries, but rather our owners. We have no interest in their properties, liabilities, equity, revenues, or margins.

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 obligates 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 beyond 2028 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”), which operates hydroelectric facilities in Virginia. In 2003, the total allocation of power from SEPA to the member distribution cooperatives was 84 megawatts (“MW”) plus associated energy, representing approximately 4.0% of our total member distribution cooperatives’ peak capacity requirements and approximately

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4.4% of our total member distribution cooperatives’ energy requirements. In 2003, the energy received by our member distribution cooperatives was greater than in 2002 due to the increased rainfall amounts in 2003 as compared to 2002. 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 2003.

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 designed to recover our total cost of service and create a firm equity base. See “Management’s Discussion and Analysis of Financial Condition and Results of Operations—Factors Affecting Results Formulary Rate” in Item 7. More specifically, the formulary rate is intended to meet all of our costs, expenses and financial obligations associated with our ownership, operation, maintenance, repair, replacement, improvement, modification, retirement and decommissioning of our generating plants, transmission system or related facilities, as well as, all of our costs, expenses and financial obligations 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:

The rates established under the wholesale power contracts are designed to enable us to comply with mortgage and indenture, and 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 demand-related costs and expenses or estimates of our demand (or capacity) 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 demand costs. We make these adjustments under our Margin Stabilization Plan. See “Management’s Discussion and Analysis of Financial Condition and Results of Operations—Critical Accounting Policies—Margin Stabilization Plan” in Item 7. These adjustments are treated as due, owed, incurred and accrued for the year to which the increase or decrease relates. The member distribution cooperatives pay or receive any amounts owed to or by us 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.

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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 member distribution cooperatives, (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:

We are considering a restructuring of our relationships with our member distribution cooperatives. See “Potential Restructuring” above.

Northern Virginia Electric Cooperative

For some time, we have been in discussions with Northern Virginia Electric Cooperative, our largest member distribution cooperative, about changing the nature of its wholesale power contract with us from an all-requirements contract to a partial-requirements contract. See “Member Distribution Cooperatives—Wholesale Power Contracts.” In prior years, Northern Virginia Electric Cooperative has stated that it may bring an action before the Federal Energy Regulatory Commission (“FERC”) or the Virginia State Corporation Commission (“VSCC”) to reform the contract along these terms if we did not reach mutually agreeable modifications to the contract. Northern Virginia Electric Cooperative has never sought, however, to be relieved from its obligations relating to our existing generating facilities, including debt service and other costs related or allocable to these facilities.

In our continuing discussions of this matter in 2003, Northern Virginia has not restated any intention or plans to seek recourse with FERC, VSCC or any other governmental authority. While we cannot predict the ultimate resolution of this matter, we will not amend or modify the wholesale power contract in any way that could adversely affect our financial condition or our other member distribution cooperatives.

TEC

TEC was formed in 2001 for the primary purpose of purchasing from us, to sell in the market, power that is not needed to meet the actual needs of our member distribution cooperatives, acquiring natural gas and forward purchase contracts to hedge the price of natural gas to supply our 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 does not engage in speculative trading.

TEC was initially capitalized in 2001 with a $7.5 million cash investment in exchange for all of its capital stock. We then distributed all of TEC’s stock as a patronage capital distribution to our member distribution cooperatives. TEC is owned entirely by our member distribution cooperatives, and is currently our only Class B member. As a member, TEC is entitled to receive patronage capital distributions from us based on our allocation of margins to Class B members and the amount of its business with us. We are considering restructuring our relationships with our members, including TEC. See “Potential Restructuring” above.

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We have a power sales contract with TEC, under which TEC purchases power that we do not need to meet the actual needs of our member distribution cooperative for resale to the market and sells this power to the market under market-based rate authority granted by FERC. To fully participate in power-related markets, TEC must maintain credit support sufficient to meet delivery and payment obligations associated with its power trades. To assist TEC in maintaining this credit support, we have agreed to guarantee up to a maximum of $42.5 million of TEC’s delivery and payment obligations associated with its power trades. As of December 31, 2003, we had guaranteed $9.5 million of TEC’s obligations and as of March 3, 2004, we had guaranteed $14.5 million of TEC’s obligations.

We also have an agreement with TEC whereby we provide certain accounting, billing, reporting and other administrative services to TEC on an arm’s-length basis. TEC engages ACES Power Marketing LLC (“APM”) to provide to it certain other services, including contract review and compliance, credit analysis and monitoring, energy credit negotiations, portfolio modeling and structuring, reporting, transaction reporting, trading controls, and settlement services.

In 2003, TEC purchased from us, and subsequently sold to the market, 291,653 megawatt-hours (“MWh”) of power. We charged TEC $12,000 for services we performed under the administrative services agreement discussed above.

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. The member distribution cooperatives, like other incumbent utilities, then charged their customers a bundled rate for electric service, which included charges for power, transmission services, and distribution (including metering and billing) services.

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

The territories served by our member distribution cooperatives cover large portions of Virginia, Delaware, and Maryland. One of our member distribution cooperatives also serves a small portion of West Virginia. These service territories range from the suburban metropolitan Washington, D.C. area in northern Virginia, to the Atlantic shore of Virginia, Delaware, and Maryland, 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 growth in residential capacity and energy requirements both with respect to power sales and number of customers. These customers’ requirements for capacity and energy generally follow a seasonal pattern where their requirements increase in winter and summer as home heating and cooling needs increase and then decline in the spring and fall as the weather becomes milder. Our member distribution cooperatives also serve major industries, which include manufacturing, fisheries, agriculture, forestry and wood products, paper, travel, and trade.

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Our member distribution cooperatives’ sales of energy in 2003 totaled approximately 9,629,681 MWh. These sales were divided by type as follows:

From 1998 through 2003, our member distribution cooperatives experienced an average annual compound growth rate of approximately 3.1% in the number of customers and an average annual compound growth rate of 4.4% in energy sales measured in MWh.

Revenues from the following member distribution cooperatives equaled or exceeded 10% of our total revenues in 2003:

The member distribution cooperatives’ average number of customers per mile of energized line has increased approximately 8.7% since 1998 to approximately 9.3 customers per mile in 2003. System densities of our member distribution cooperatives in 2003 ranged from 6.2 customers per mile in the service territory of BARC Electric Cooperative to 21.7 customers per mile in the service territory of Northern Virginia Electric Cooperative. In 2003, the average service density for all distribution electric cooperatives in the United States was approximately 6.6 customers per mile.

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 member distribution cooperatives and us.

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POWER SUPPLY RESOURCES

General

We provide power to our members through a combination of our interests in the Clover Power Station (“Clover”), North Anna Nuclear Power Station (“North Anna”), Louisa generating facility (“Louisa”), Rock Springs generating facility (“Rock Springs”) and distributed generation facilities, 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:

The service territory of our member distribution cooperatives is geographically divided into two separate areas – mainland Virginia and the Delmarva Peninsula. Because the ability to transmit power between these two areas is limited, we currently must generate or purchase power to meet the specific needs of each area separately. For example, power generated by Clover, North Anna, and Louisa is used exclusively by our member distribution cooperatives that are located in mainland Virginia. The costs of all of our power resources, however, are shared by all our member distribution cooperatives, regardless of their location. See “Management’s Discussion and Analysis of Financial Condition and Results of Operations—Factors Affecting Results—Formulary Rate” in Item 7. We transmit power to our nine member distribution cooperatives located in mainland Virginia through the transmission systems of Virginia Electric and Power Company (“Virginia Power”), American Electric Power Virginia (“AEP-Virginia”), and PJM Interconnection, LLC (“PJM”) – West Region. We transmit power to our three member distribution cooperatives located on the Delmarva Peninsula through the transmission system of PJM – Classic Region.

The member distribution cooperatives’ customers in mainland Virginia and on the Delmarva Peninsula have similar usage characteristics and distribution of sales by customer classification. Typically, both areas’ peak demand for energy, also referred to as capacity requirement, is in the summer months. This peak is due to the summer air conditioning requirements of the member distribution cooperatives’ customers, which reflects the large residential component of our total capacity requirements. However, in 2003, the peak for the member distribution cooperatives’ customers in mainland Virginia was in January due to a colder than usual winter and the resulting winter heating requirements.

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Mainland Virginia represented approximately 77.7% of our 2003 peak capacity requirements, which occurred in January. North Anna and Clover satisfied approximately 41.9% of our capacity requirements and 61.4% of our energy requirements in mainland Virginia in 2003. Louisa provided 1.5% of our 2003 mainland Virginia energy requirements. In 2003, we obtained the remainder of our mainland Virginia and the majority of our Delmarva Peninsula requirements, both capacity and energy, from numerous suppliers under various power purchase contracts and forward, short-term and spot market purchases. Rock Springs provided 1.0% of our 2003 Delmarva Peninsula energy requirements. Our Louisa and Rock Springs combustion turbine facilities were not commercially operable until June of 2003. Generally, power purchase contracts allow us to meet these requirements by purchasing fixed-price firm capacity and energy at market prices. See “Power Supply Resources—Power Purchase Contracts.”

Most of our long-term power purchase contracts will expire by 2005. We have developed the combustion turbine facilities to satisfy substantially all of the capacity and a portion of the energy currently supplied by these contracts. The timing and size of each combustion turbine facility has been 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 have ten distributed generation facilities across our member distribution cooperatives’ service territories, which enhance our system’s reliability.

Power Supply Resources

Generating Facilities

We have ownership interests in five electric generating facilities plus distributed generation facilities. For a description of these facilities see “Properties” in Item 2. In 2003, these facilities provided 48.3% of our energy requirements.

Power Purchase Contracts

In 2003, we purchased approximately 51.7% of our total energy requirements. These energy requirements were provided principally by neighboring utilities through power purchase contracts and purchases of energy in the forward, short-term and spot markets.

Virginia Power. Under the terms of the Amended and Restated Interconnection and Operating Agreement (“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. In 2003, Virginia Power provided us with peaking capacity requirements necessary to meet the needs of our mainland Virginia member distribution cooperatives not supplied from our portion of the output of North Anna, Clover, and Louisa. We will not purchase peaking capacity under the I&O agreement in 2004; however, we will purchase peaking capacity for January through March 2004 under a separate agreement with Virginia Power.

The price we pay for the reserve energy portion of our Virginia Power purchases equals Virginia Power’s owned combustion turbine costs used to generate that energy. We can elect not to purchase energy under the I&O Agreement if we can purchase more economical energy from other sources.

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 two separate agreements with Virginia Power. See “Transmission – Virginia Power System.”

PSE&G. In December 1992, we entered into an agreement with Public Service Electric & Gas Company (“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

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contains fixed capacity charges, including transmission 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 power supply requirements. We currently are in a dispute with PSE&G regarding this contract. See “Legal Proceedings” in Item 3.

Allegheny. We purchase capacity pursuant to a power purchase contract with Allegheny Energy Supply (“Allegheny”), a subsidiary of Allegheny Power Resources. This contract will meet up to 25 MW of the capacity requirements of our member distribution cooperatives in mainland Virginia through May 2005.

Constellation. To replace the contracts expiring at the end of 2003, we issued a request for power supply proposals in the fall of 2002. As a result of this request, we negotiated a fixed-price contract with Constellation Power Source, Inc. (“Constellation”) to supply these purchase power needs from January 1, 2003 through May 31, 2008. Transmission service with respect to energy purchased under this agreement is supplied under PJM’s transmission tariff for the Allegheny Power Resources service area power requirements, and the American Electric Power-Virginia (“AEP-Virginia”) open access transmission tariff for power requirements served in its area.

Other

We also purchase a portion of our energy requirements from the market using forward contracts, and short-term and spot purchases. These purchasing strategies are associated with the changing contracts and the ability to forego purchasing energy under existing contracts and at a lower cost than generating power from our combustion turbine facilities. These strategies, however, are not without risk. To mitigate the risks, we attempt to match our energy purchases with our energy needs to reduce our spot market purchases of energy. Additionally, we have developed policies and procedures to manage the risks in the changing business environment. These procedures, developed in cooperation with APM, are designed to strike the appropriate balance between minimizing costs and reducing energy cost volatility. See “Management’s Discussion and Analysis of Financial Condition and Results of Operations—Future Issues—Reliance on Market Purchases of Energy” in Item 7.

Transmission

We have agreements with Virginia Power, PJM, and AEP-Virginia, which provide us with access to their transmission facilities as necessary to deliver energy to our member distribution cooperatives. We own a small amount of transmission facilities. See “Properties” in Item 2.

On August 14, 2003, eight states in the Northeast United States and Southern Canada experienced a widespread power outage. According to the U.S.-Canada Power System Outage Task Force, the outage originated in Ohio and was caused by deficiencies in specific practices, equipment, and human decisions and is still under investigation. None of our member distribution cooperatives’ customers were affected by this outage.

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, Clover, and Louisa, as well as power purchased from other suppliers, to our member distribution cooperatives’ delivery points. Pursuant to the I&O Agreement, Virginia Power supplies all transmission services to us under its open access transmission tariff. The terms for transmission and related services are described in our Service Agreement for Network Integration Transmission Service (“NITS”) and the Network Operating Agreement (“NOA”) with Virginia Power. The NOA contains the terms and conditions under which we must operate our facilities and the technical and operational matters associated with the NITS. The NITS describes the specific services we purchase from Virginia Power and pricing of those services. Because Virginia Power has stated an intention to join the PJM regional transmission organization, we will obtain transmission service from that organization if and when Virginia Power grants control of its transmission facilities to PJM. See “—RTOs.”

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PJM

We are a member of PJM to serve our member distribution cooperatives located on the Delmarva Peninsula and a portion of mainland Virginia in the area served by Allegheny Power Resources. PJM is an independent system operator of transmission facilities serving all of Delaware and New Jersey and parts of Pennsylvania, Maryland, West Virginia 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 the incremental costs to dispatch the more expensive generating facilities known as congestion costs. The majority of our PJM power requirements are located on the Delmarva Peninsula, which has been subject to significant congestion costs.

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 partially offset congestion charges. In 2003, PJM allocated to us the rights to obtain a specified number of fixed transmission rights. We purchased additional fixed transmission rights from PJM and negotiated to obtain additional fixed transmission rights from other members of PJM when economical.

In 2003, we paid approximately $7.8 million in congestion charges to PJM. These charges were partially offset by credits from our fixed transmission rights and our auction revenue rights. Net congestion costs for 2003 were approximately $2.6 million.

Conectiv, the owner of the transmission facilities on the Delmarva Peninsula, has been performing system upgrades to meet reliability criteria and to interconnect generating facilities located on the Delmarva Peninsula. Conectiv has stated that it expects that congestion will be reduced significantly once these upgrades are complete. In addition, we have installed and paid for transmission network upgrades in order to serve our member distribution cooperatives on the Delmarva Peninsula more reliably and economically.

Other Transmission Systems

We obtain transmission service for purchases of power to serve our member distribution cooperatives’ requirements in the area under AEP–Virginia’s open access transmission tariff. These transmission arrangements may change as AEP–Virginia has announced its intention to become part of PJM.

RTOs

In December 1999, FERC issued Order No. 2000 amending its regulations to advance the formation of regional transmission organizations (“RTOs”). One of the major objectives of Order No. 2000 is to eliminate pancaked transmission rates (paying multiple charges for transmission service that crosses the facilities owned by several transmission owners). By paying a single transmission rate to access all the transmission facilities under the control of the RTO, the RTO may expand access to markets that were previously uneconomical due to having to pay each utility a separate transmission charge. FERC will regulate the transmission rates established by the RTOs. While FERC stated in Order No. 2000 that RTO formation would be voluntary, FERC required each public utility that owns, operates or controls facilities for the transmission of electric energy in interstate commerce to make

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filings with respect to their plans to form and/or participate 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 are impacted by Order No. 2000 because our member distribution cooperatives have power requirements for which we have the responsibility of providing transmission service. We will benefit from Order No. 2000 if, as intended, it increases competition and consequently reduces transmission and energy costs in general.

FERC noted in Order No. 2000, and on rehearing in Order No. 2000A, that existing state and fed