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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, 2004

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

OLD DOMINION ELECTRIC COOPERATIVE

2004 ANNUAL REPORT ON FORM 10-K

PART I

ITEM 1.    BUSINESS

OLD DOMINION ELECTRIC COOPERATIVE

General

Old Dominion Electric Cooperative (“Old Dominion” or “we” or “our”) 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 496,000 retail electric consumers (meters) representing a total population of approximately 1.2 million people in 2004. 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” below 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 taxable 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 our 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 84 employees as of March 1, 2005.

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 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, electric distribution cooperatives have owned and operated distribution systems to supply the power requirements of their retail customers. See also “—Competition and Changing Regulations” below.

Potential Reorganization

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. As part of this effort, on July 26, 2004, we entered into a reorganization agreement with our twelve member distribution cooperatives, TEC and a newly formed taxable power supply cooperative, New Dominion Energy Cooperative (“New Dominion”), to provide us additional flexibility to finance capital expenditures and eliminate some existing operational constraints.

Structurally, the reorganization contemplated by the reorganization agreement would result in all of our member distribution cooperatives exchanging their membership interests in Old Dominion for a membership interest in New Dominion. All of their equity in Old Dominion 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.

As part of the reorganization, the reorganization agreement requires that New Dominion 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 reorganization agreement further provides that the wholesale power contracts we currently have with our member distribution cooperatives would be assigned to and assumed by New Dominion. TEC would withdraw as a member in conjunction with the completion of the reorganization and our power sales relationship with TEC also would be terminated at that time.

The reorganization agreement includes several provisions intended to protect our credit profile. We will not transfer our ownership of any of our tangible assets, including our interest in any of our generation facilities, in connection with the reorganization. We would continue to be responsible for all of our existing indebtedness; the reorganization agreement would require New Dominion to guarantee all of our outstanding obligations under our Indenture at the time of the consummation of the reorganization. In addition, the reorganization agreement contemplates that we will 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.

If consummated, we anticipate that following the reorganization New Dominion would conduct physical and financial power and gas procurement activities and purchase, in the markets, the power and energy needed to

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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 owned by 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.

Following the reorganization, 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 reorganization. We would supply all administrative and management services required by New Dominion.

Several conditions must be satisfied before the reorganization will occur, including conditions relating to obtaining all necessary regulatory approvals. In October 2004, a large industrial customer of one of our member distribution cooperatives intervened in our proceedings with the Federal Energy Regulatory Commission (“FERC”) relating to approvals we are seeking relating to the reorganization. Subsequently, Northern Virginia Electric Cooperative, our largest member distribution cooperative, also intervened in these proceedings. See “Legal Proceedings” in Item 3.

The reorganization agreement granted us the right to terminate the reorganization agreement if the conditions to closing were not satisfied prior to December 31, 2004. We currently anticipate that we and our member distribution cooperatives will continue to pursue satisfaction of the conditions precedent to the reorganization in the reorganization agreement. Several of these conditions, including the obtainment of all necessary regulatory approvals, are beyond our control. For this reason, we cannot determine whether or if the reorganization 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 the Virginia Mainland, 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 either party gives the other at least three years notice of termination.

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There are two principal exceptions to the “all-requirements” obligations of the parties. First, each Virginia Mainland member distribution cooperative may purchase power allocated to it from the Southeastern Power Administration (“SEPA”), which operates hydroelectric facilities in Virginia. In 2004, the total allocation of power from SEPA to the member distribution cooperatives was 84 megawatts (“MW”) plus associated energy, representing approximately 3.8% of our total member distribution cooperatives’ peak capacity requirements and approximately 2.2% of our total member distribution cooperatives’ energy requirements. In 2004, the energy received by our member distribution cooperatives from SEPA was less than in 2003 due to the variability of production. 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 2004.

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, which has been filed with and accepted by FERC, 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 (or capacity)-related costs and expenses or estimates of our demand sales of power. Increases or decreases in our annual budget automatically amend the demand component of our formulary rate. See “Management’s Discussion and Analysis of Financial Condition and Results of Operations—Factors Affecting Results—Formulary

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Rate” in Item 7 for a description of capacity-related costs and 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.

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 Reorganization” above.

Northern Virginia Electric Cooperative

Over the past several years, we had been in discussions with Northern Virginia Electric Cooperative (“NOVEC”), 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, NOVEC has stated that it may bring an action before 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. NOVEC 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 January 2005, NOVEC intervened in our New Dominion proceedings at FERC. See “Legal Proceedings – FERC Proceedings Related to Potential Reorganization” in Item 3.

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.

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TEC is owned by our member distribution cooperatives, and currently is 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 reorganization our relationships with our members, including TEC. See “—Potential Reorganization” above.

We have a power sales contract with TEC, under which TEC purchases power from us 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 $60.0 million of TEC’s delivery and payment obligations associated with its power trades. As of December 31, 2004, we had issued guaranties for up to $27.9 million of TEC’s obligations and $2.5 million of such obligations were outstanding.

In 2004, TEC purchased from us, and subsequently sold to the market, 481,699 megawatt-hours (“MWh”) of power. In 2004, we purchased from TEC $18.3 million of natural gas to fuel our combustion turbine facilities. We charged TEC $12,000 for services we performed under an administrative services agreement.

As of December 31, 2004, in accordance with Financial Accounting Standards Board issued Interpretation No. 46R, “Consolidation of Variable Interest Entities, an Interpretation of Accounting Research Bulletin No. 51”, TEC has been consolidated and is now included in our financial statements. All intercompany balances have been eliminated.

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 have each enacted legislation granting retail customers the right to choose their power supplier. This legislation in each state 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 “—Competition and Changing Regulations.”

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 2004 totaled approximately 10,168,969 MWh. These sales were divided by type as follows:

From 1999 through 2004, our member distribution cooperatives experienced an average annual compound growth rate of approximately 3.3% in the number of customers and an average annual compound growth rate of 4.6% in energy sales measured in MWh.

Revenues from the following member distribution cooperatives equaled or exceeded 10% of our total revenues in 2004:

The member distribution cooperatives’ average number of customers per mile of energized line has increased approximately 7.0% since 1999 to approximately 9.4 customers per mile in 2004. System densities of our member distribution cooperatives in 2004 ranged from 6.1 customers per mile in the service territory of BARC Electric Cooperative to 22.2 customers per mile in the service territory of NOVEC. In 2004, the average service density for all distribution electric cooperatives in the United States was approximately 6.6 customers per mile.

COMPETITION AND CHANGING REGULATIONS

Virginia, Delaware and Maryland have each enacted legislation that restructures the electric utility industry in their states and changes the manner in which electricity may be sold to retail customers. Each state’s individual restructuring plan deregulated the power component (also known as generation) of electric service, while maintaining regulation of transmission and distribution services. All retail customers in Virginia, Delaware and Maryland, including retail customers of our member distribution cooperatives, are currently permitted to purchase power from the supplier of their choice. At March 1, 2005, no entity had registered to be an alternative power supplier in any of the service territories of our member distribution cooperatives and, as a result, none of their retail customers have switched to alternative providers. If customers of our member distribution cooperatives choose alternative power suppliers in the future, this could result in a reduction in our revenues and cash flows. If the resulting decrease in our member revenues is significant enough, we could lose our tax-exempt status. See “Management’s Discussion and Analysis of Financial Condition and Results of Operations —Factors Affecting Results—Tax Status” in Item 7.

To address 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, sometimes referred to as “stranded costs”, and to facilitate the implementation of retail competition, the legislation in all three states requires the incumbent utility to cap the bundled rates that it can charge its retail customers in its certificated service territory during a specified transition period. Capped rates extend until December 31, 2010, for our Virginia member distribution cooperatives, until March 31, 2005, for our Delaware member distribution cooperative, and until June 30, 2005 for our Maryland member distribution cooperative. These capped rates are then unbundled, or itemized, into power, transmission and distribution components and, in the case of Virginia, a competitive transition charge. Our member distribution cooperatives located in Virginia have the ability to pass through to their customers, changes in energy costs even while under capped rates. Additionally, our Virginia member distribution cooperatives may request one change in their capped rates prior to July 1, 2007, and one additional change between July 1, 2007 and December 31, 2010. Our ability to charge our member distribution cooperatives located in Delaware and Maryland amounts under their wholesale power contract with us is not impaired by these capped rates. If our Delaware and Maryland member distribution cooperatives’ costs are greater or lesser than their capped rates, they either absorb the deficiency or retain the benefit, respectively.

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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”), Marsh Run generating facility (“Marsh Run”), 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 –the Virginia Mainland and the Delmarva Peninsula. Because the ability to transmit power between these two areas is limited, we generally must generate or purchase power to meet the specific needs of each area separately. For example, power generated by Clover, North Anna, Louisa and Marsh Run is used exclusively by our member distribution cooperatives that are located in the Virginia Mainland. 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 the Virginia Mainland through the transmission systems of Virginia Electric and Power Company (“Virginia Power”) 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 the Virginia Mainland 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 2004, the peak for the member distribution cooperatives’ customers in the Virginia Mainland was in December due to a colder than usual winter and the resulting winter heating requirements.

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The Virginia Mainland represented approximately 78.0% of our 2004 peak capacity requirements, which occurred in December. North Anna and Clover satisfied approximately 46.8% of our capacity requirements and 58.6% of our energy requirements in the Virginia Mainland in 2004. Louisa and Marsh Run provided 1.9% and 0.2%, respectively, of our 2004 Virginia Mainland energy requirements. In 2004, we obtained the remainder of our Virginia Mainland 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 1.1% of our 2004 Delmarva Peninsula energy requirements. Our Louisa and Rock Springs combustion turbine facilities became commercially operable in June of 2003. Our Marsh Run combustion turbine facility became commercially operable in September 2004. 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 2011. The combustion turbine facilities will satisfy substantially all of the capacity and a portion of the energy currently supplied by these contracts following their termination. 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 2004, these facilities provided 47.4% of our energy requirements.

Power Purchase Contracts

In 2004, we purchased approximately 52.6% of our total energy requirements. These energy requirements were provided principally by neighboring utilities through long-term power purchase contracts and purchases of energy in the forward and spot markets.

Our most significant long-term power purchase arrangements are with Virginia Power, the operator and co-owner of Clover and North Anna. We have agreements with Virginia Power which grant us the right, but not the obligation, to purchase intermediate energy at a price determined by reference to a specified natural gas index. In addition, we have other contractual arrangements with Virginia Power which permit us to purchase reserve capacity and energy. We intend to purchase our reserve capacity requirements for Clover and North Anna from Virginia Power under these arrangements until either the date on which all facilities at North Anna have been retired or decommissioned or the date we have no interest in North Anna, whichever is earlier.

The purchase price we pay for any reserve energy purchased under these arrangements equals the natural gas-indexed price we pay for intermediate energy under our other agreements with Virginia Power. In addition to Virginia Power, we have other long-term power purchase agreements with Mid-Atlantic utilities which provide a small portion of our capacity and energy requirement.

The remainder of our energy requirements are provided by the market. When possible, we purchase power in the market through forward contracts and spot purchases if we believe the prices for such energy will be less than energy otherwise available to us under long-term contracts or energy generated from our combustion turbine facilities. This approach to meeting our member distribution cooperatives’ energy requirements is not without risks. To mitigate these 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 ACES Power Marketing LLC (“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.

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Transmission

We have agreements with Virginia Power and PJM, 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.

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, Louisa, and Marsh Run, as well as power purchased from other suppliers, to our member distribution cooperatives’ delivery points. Pursuant to existing agreements, 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 plans 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” below.

PJM

We are a member of PJM to serve our member distribution cooperatives located on the Delmarva Peninsula and portions of the Virginia Mainland in the areas served by Allegheny Power Resources and American Electric Power-Virginia. PJM is an independent system operator of transmission facilities serving all of Delaware and parts of Maryland, West Virginia and Virginia, as well as other areas outside our member distribution cooperatives’ service territories.

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 the effects of congestion 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. PJM has instituted a two-step process for annually allocating fixed transmission rights to entities with retail customers. They first allocate auction revenue rights, which entitle the owner to either convert the auction revenue rights into fixed transmission rights or to be paid based upon the value of the auction revenue rights as determined in an annual open auction process. In 2004, PJM allocated to us the rights to obtain a specified number of auction revenue rights. We purchased additional fixed transmission rights from PJM and can negotiate to obtain additional fixed transmission rights from other members of PJM when economical.

In 2004, we paid approximately $10.2 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 2004 were approximately $7.0 million.

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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 to serve our member distribution cooperatives on the Delmarva Peninsula more reliably and economically.

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 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 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 a 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.

In 2002, FERC issued its Notice of Proposed Rulemaking on Standard Market Design. FERC proposed to amend its regulations to modify the pro-forma transmission tariff to remedy remaining undue discrimination against non-owners of transmission facilities. In 2003, some aspects of the Standard Market Design became a part of the 2003 Congressional Energy Bill, which was not approved by the United States Congress. FERC is still pursuing its proposed rules on Standard Market Design and has issued a White Paper on its proposed changes to the Notice of Proposed Rulemaking. We are actively participating in the comment process on the proposed rules on an individual basis and jointly with other similarly aligned parties.

Legislation passed by the 2003 Virginia General Assembly prohibited the transfer of ownership or control of any transmission system located in Virginia prior to July 1, 2004. The law provides that the VSCC must approve any transfer and the application for transfer must include a study of the comparative costs and benefits of such transfer, including the effects of transmission congestion costs. Each incumbent electric utility was required to file their application for transfer by July 1, 2003 and was to transfer ownership or control by January 1, 2005, subject to VSCC approval. We believe this legislation should not affect our ability to serve our member distribution cooperatives through the transmission system of Virginia Power and PJM or affect our ability to transmit energy from our combustion turbine facilities because the transmission assets we own are minimal.

Fuel Supply

Nuclear

Virginia Power, as operating agent, has the sole authority and responsibility to procure nuclear fuel for North Anna. Historically, Virginia Power has employed both spot purchases and long-term contracts to satisfy North Anna’s nuclear fuel requirements. Virginia Power advises us that the percentage of long-term contracts versus spot purchases in any given year is primarily driven by current and projected market conditions, Virginia

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Power’s refueling cycles, industry consolidation, political conditions, and Virginia Power’s management decisions and strategies. Generally,