OLD DOMINION ELECTRIC COOPERATIVE - 10-K Annual Report

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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

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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.

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.

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 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.

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.

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.

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.

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

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.

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.

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 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.

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.

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.

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.

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.

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.

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.

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.

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

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.

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.

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.

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.”

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.

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.

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 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.

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 prohibits 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 shall 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, PJM or AEP-Virginia or affect our ability to transmit energy from our combustion turbine facilities because the transmission assets we own are minimal.

Under the Purchase, Construction and Ownership Agreement for North Anna, the I&O Agreement, and a Nuclear Fuel Agreement between Virginia Power and us, Virginia Power, as operating agent, has the sole 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. The percentage of long-term contracts versus spot purchases in any given year is primarily driven by current and projected market conditions, Virginia Power’s refueling cycles, industry consolidation, political conditions, and Virginia Power’s management decisions and strategies. Generally, long-term contracts are three to five years in length with pricing mechanisms such as discounted market, base escalated, fixed or a combination thereof. Spot purchases are purchases made with terms that are satisfied within a twelve-month period. These various contracts typically have quantity flexibilities and are strategically staggered to expire in different years. We are not a direct party to any of these procurement contracts, and as a result cannot control their terms or duration. Historically, Virginia Power has obtained the nuclear fuel requirements for North Anna under long-term contracts and short-term purchases. Virginia Power advises us that they continually evaluate 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 and that additional fuel is purchased as required to attempt to achieve optimum cost and inventory levels.

Under the Clover operating agreement, Virginia Power, as operating agent, has the sole authority and responsibility to procure sufficient coal for the operation of Clover. Virginia Power employs both spot market purchases and long-term contracts to acquire the low sulfur bituminous coal used to fuel the facility. Virginia Power’s procurement policy is to secure the bulk of the coal requirements under long-term contracts, with specific contract target percentages fluctuating, based on prevailing market conditions. These contracts are normally 12 to 18 months in duration, however; longer-term contracts sometimes are entered into if Virginia Power considers market conditions favorable. We are not a direct party to any of these procurement contracts, and therefore cannot control their terms or duration. In 2003 and 2002, Virginia Power obtained approximately 80% and 65%, respectively, of the coal requirements of Clover under long-term contracts. Virginia Power obtained the remaining coal needed for Clover in these years from the spot market. 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. See “Quantitative and Qualitative Disclosures About Market Risk” in Item 7A.

Natural gas has become the preferred fuel for new electric generating facilities, causing an increase in competition for natural gas capacity. Our two operating combustion turbine facilities and our combustion turbine facility currently under construction are powered by natural gas and 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 three combustion turbine facilities. With assistance from APM, we have developed and utilize a natural gas supply strategy for providing natural gas to each of the three combustion turbine facilities. We are responsible for procuring the natural gas to be used by all units at Rock Springs, Louisa and Marsh Run. The strategy includes securing transportation contracts and incorporating the ability to use No. 2 distillate fuel oil back up for Louisa and Marsh Run, as needed, to minimize transportation costs. We have targeted our primary natural gas suppliers and have negotiated the contracts needed for procurement of physical natural gas. We have put in place strategies and mechanisms to financially hedge our natural gas delivery needs through TEC. See “TEC.” We presently anticipate that sufficient supplies of natural gas will be available in the future at reasonable prices making the operation of the combustion turbine facilities economical, but significant price volatility may occur, especially during the winter. See “Quantitative and Qualitative Disclosures About Market Risk” in Item 7A.

We are subject to regulation by FERC and to a limited extent, state public service commissions. Some of our operations are also subject to regulation by the Virginia Department of Environmental Quality, the Department of Energy (“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 generating 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 amount up to 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 rate. See “Management’s Discussion and Analysis of Financial Condition and Results of Operations—Factors Affecting Results – Formulary Rate” in Item 7.

FERC 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 are 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.

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

We are subject to federal, state, and local laws and regulations designed to protect human health and the environment and regulating the emission, discharge, or release of pollutants into the environment. We believe we are in material compliance with all current requirements of such environmental laws and regulations. As with all electric utilities, the operation of our generating units could, however, be affected by future environmental regulations. Capital expenditures and increased operating costs required to comply with any future regulations could be significant.

Our direct capital expenditures for environmental control facilities at Clover, excluding capitalized interest, were approximately $2.3 million in 2003. We did not have any direct capital expenditures for environmental control facilities at North Anna in 2003. Based on information provided by Virginia Power, our portion of direct capital expenditures for environmental control facilities planned for Clover over the next three years is estimated to be approximately $1.6 million and none for North Anna. These expenditures are included in our estimated capital expenditures for the years 2004 through 2006. In 2003, we did not have any direct capital expenditures for environmental control facilities at our Louisa and Rock Springs combustion turbine facilities. See “Management’s Discussion and Analysis of Financial Condition and Results of Operations—Liquidity and Capital Resources” in Item 7.

The most important environmental law affecting our operations is the Clean Air Act. The Clean Air Act requires, among other things, that owners and operators of fossil fuel-fired power stations limit emissions of sulfur dioxide (“SO₂”) and nitrogen oxides (“NO_x”). Under the Clean Air Act’s Acid Rain Program, each of our fossil fuel-fired plants must obtain SO₂ allowances equal to the number of tons of SO₂ they emit into the atmosphere annually. As an existing facility, Clover receives an annual allocation of SO₂allowances at no cost based upon its baseline operations. Newer facilities, including Rock Springs, Louisa and Marsh Run, need to obtain allowances, but because they are gas-fired, the number of SO₂allowances they must obtain are expected to be minimal and we anticipate will be supplied from excess SO₂ allowances allocated to Clover. Future changes in the Acid Rain Program, including increases in the cost of SO₂allowances or the ratio of allowances to emissions, could increase our costs of operation.

Pursuant to the Clean Air Act, both Maryland and Virginia have enacted regulations to reduce the emissions of NO_x by establishing NO_x allowance programs similar to federal SO₂allowance programs. Clover is meeting its NO_x emissions limitations through the use of conventional and advanced pollution control equipment. NO_x emissions allowances will be purchased to meet the NO_x reduction requirement that is not met by the NO_x emission control equipment. We have an agreement with Virginia Power to provide us with the option each year to purchase from it the NO_x emissions allowances necessary to compensate for any shortfall between our NO_x emissions allowance requirement for Clover and our portion of the regulatory NO_xemissions allocation for Clover.

stringent NO_x emission limits. Each will be required to obtain allowances for every ton of NO_x they emit during the ozone season (May through September) beginning in 2003 for Rock Springs and beginning in 2004 for Louisa and Marsh Run. When designing their respective programs, Maryland and Virginia both set aside a number of NO_x allowances to be allocated to new sources based on their emissions rates. NO_x emission allowances that are not received from the new source set aside pools will be purchased in the market for the operation of all three combustion turbine facilities. We project that we will be able to obtain sufficient quantities of NO_x 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.

The Clean Air Act also directs the EPA to limit the emissions of hazardous air pollutants (“HAPs”). In January 2004, the EPA issued two alternative proposals for the regulation of mercury emissions from coal-fired power plants. One alternative would create an allowance trading program for mercury emissions (with decreasing caps in 2010 and 2018). The other alternative would require the installation of state-of-the-art pollution control equipment known as “maximum achievable control technology” (“MACT”). At this point, the ultimate outcome of the rulemaking process is unclear. Based on the proposals, most coal-fired facilities, including Clover, would probably be subject to such regulation. Based on the proposals, however, and the type of coal used to fuel Clover, we do not anticipate installation of additional equipment will be required for mercury reduction.

On March 5, 2004, the EPA promulgated new national emission standards for HAPs for stationary combustion turbines. The new rule requires the installation of MACT to reduce the emissions of HAPs from gas-fired combustion turbines only if such combustion turbines are major sources of HAPs as defined by the Clean Air Act, and if construction of the turbines started on or after January 15, 2003. Construction of Rock Springs and Louisa started before January 2003. Although construction of our Marsh Run combustion turbine facility began in March 2003, it is not a major source of HAPs and is not located at a facility which is a major source of HAPs; therefore, the new MACT standard does not apply to Marsh Run.

The Clean Water Act and applicable state laws regulate intake structures, discharges of cooling water, storm water and other wastewater discharges at our generating facilities. We are in material compliance with these requirements and with permits that must be obtained with respect to such discharges. Our permits are subject to periodic review and renewal proceedings, and can be made more restrictive over time. Limitations on the thermal discharges in cooling water, or withdrawal of cooling water during low flow conditions, can restrict our operations. During 2003, we experienced no such restrictions; however, such restrictions can arise during drought conditions.

New legislative and regulatory proposals are frequently proposed on both a federal and state level that would modify the environmental regulatory programs applicable to our facilities. An example is the control of carbon dioxide and other “greenhouse” gases that may contribute to global climate change. With respect to such proposed legislation and regulatory proposals that have not yet been formally proposed, we cannot provide meaningful predictions regarding their final form, or their possible effects upon our operations.

We incurred approximately $9.9 million, $8.8 million, and $10.0 million of expenses, including depreciation, during 2003, 2002, and 2001, respectively, in connection with environmental protection and monitoring activities, such as costs related to the disposal of solid waste, operation of landfills, operation of air emissions reduction equipment, and disposal of hazardous waste material. These expenses were included in fuel expense, operations and maintenance expense, and depreciation, amortization and decommissioning expense. We anticipate expenses to be approximately $7.3 million in 2004 in connection with environmental protection and monitoring activities, including depreciation.

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. In January 2004, Virginia Power filed a lawsuit seeking recovery damages for breach of the Standard Contract due to the DOE’s delay in accepting spent nuclear fuel at North Anna.

Our principal properties consist of our interest in five electric generating facilities, additional distributed generation facilities across our member distribution cooperatives’ service territories and a small amount of transmission facilities. Substantially all of our physical properties are subject to the lien of our Indenture. See “Management’s Discussion and Analysis – Future Issues – Restated Indenture” in Item 7. Our generating facilities consist of the following:

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 the town of Clover in Halifax County, Virginia, 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” in Item 1. We are responsible for and must fund half of all additions and operating costs associated with Clover, as well as half of Virginia Power’s administrative and general expenses for Clover.

Under the terms of the Clover operating agreement, we and Virginia Power each take half of the power produced by Clover. During 2003, Clover provided approximately 30.6% 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. We and Virginia Power may restructure the operating agreement for Clover, depending upon whether Virginia Power joins PJM, to permit us to sell our excess energy from Clover to other power purchasers as well as to Virginia Power. We intend to purchase our reserve capacity requirements for Clover from Virginia Power for the term of the I&O Agreement with it.

We have entered into a sale and lease back 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, and leased them back for a term extending until December 30, 2012. Because we may cause the release of the lien of the Indenture, the owner trust’s interest in these assets may no longer be subject and subordinate to the lien of the Indenture in the future. See “Management’s Discussion and Analysis of Financial Condition and Results of Operations—Future Issues—Restated Indenture” in Item 7 for a discussion of the possible release of the lien of the Indenture. 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 owner trust’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 exercised our option to purchase the assets subject to the lease on December 30, 2004.

We also have entered into separate lease and lease back 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 Indenture, for a term extendable by the owner trust up to the full productive life of Clover Unit 1, and simultaneously entered into an approximately 21.8 year lease of the interest back to us. Because we may cause the release of the Indenture, the interest of the owner trust in Clover Unit 1 may no longer be subject and subordinate to the lien of the lien of the Indenture in the future. See “Management’s Discussion and Analysis of Financial Condition and Results of Operations—Future Issues—Restated Indenture” in Item 7 for a discussion of the possible release of the lien of the Indenture. We have provided for substantially 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” by S&P and “Aaa” by Moody’s. 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.

At the end of the term of the lease back, we have three options: (1) retain possession of the interest in the unit by paying a fixed purchase price to the owner trust, (2) return possession of the interest to the owner trust and arrange for an acceptable third party to enter into a power purchase agreement with the owner trust, or (3) return possession of the interest and pay a termination amount to the owner trust. See “Management’s Discussion and Analysis of Financial Condition and Results of Operations—Liquidity and Capital Resources—Off-Balance Sheet Arrangements – Clover Leases” in Item 7 for a discussion of our obligations at the end of the term of the leaseback of Clover Unit 1 and sources of funding for these obligations.

In July 1996, we entered into another lease subject to the lien of the Indenture with an owner trust for the benefit of a different investor of our interest in Clover Unit 2 and related common facilities for a term extendable by the owner trust up to the full productive life of Clover Unit 2. We simultaneously entered into an approximately 23.4 year lease back of the interest. 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” by S&P and “Aaa” by Moody’s. As with the Clover Unit 1 lease, the leaseback 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.

In connection with this lease, 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 date of the release of the lien of the Indenture in connection with its amendment and restatement unless the holders of obligations issued under the Indenture are equally and ratably secured with respect to the assets subject to the lease. After that date, the interest of the owner trust would no longer be subject and subordinate to the lien of the Indenture. See “Management’s Discussion and Analysis of Financial Condition and Results of Operations—Future Issues—Restated Indenture” in Item 7 for a discussion of the possible amendment and restatement of the Indenture.

At the end of the term of the leaseback, we may either (1) retain possession of the interest in the unit by paying a fixed purchase price to the owner trust, or (2) return possession of the interest to the owner trust and arrange for an acceptable third party to enter into a power purchase agreement with the owner trust. See “Management’s Discussion and Analysis of Financial Condition and Results of Operations—Liquidity and Capital Resources—Off-Balance Sheet Arrangements—Clover Leases” in Item 7 for a discussion of our obligations at the end of the term of the leaseback of Clover Unit 2 and sources of funding for these obligations.

We own 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 nuclear power facility with a net capacity rating of 1,842 MW, located in Louisa County, Virginia, approximately 60 miles northwest of Richmond, Virginia. North Anna Unit 1 commenced commercial operation in June 1978, and Unit 2 commenced commercial operation in December 1980. We purchased our 11.6% undivided ownership interest in North Anna in December 1983. 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” in Item 1.

Under the I&O Agreement, we are entitled to 11.6% of the power generated by North Anna. Additionally, we are responsible for and must fund 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 fund 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. During 2003, North Anna provided approximately 15.2% of our energy requirements. We intend to purchase our reserve capacity requirements for North Anna from Virginia Power for the term of the I&O Agreement. See “Power Supply Resources—Power Purchase Contracts—Virginia Power” in Item 1 for a description of the type and amount of power we may purchase under this contract.

We have developed the Louisa and Rock Springs combustion turbine facilities to enable us to continue to serve our member distribution cooperatives’ power requirements and we are in the process of completing a third combustion turbine facility referred to as Marsh Run also to meet the needs of our member distribution cooperatives. During 2003, our combustion turbine facilities provided approximately 2.5% of our energy requirements. Upon completion of Marsh Run, our total system capacity from facilities owned by us will increase from 1,515 MW to 2,019 MW.

The Louisa facility is located near Gordonsville, in Louisa County, Virginia, and consists of five combustion turbines totaling 504 MW (net capacity rating). The facility includes four 84 MW General Electric 7EA combustion turbines and one 168 MW General Electric 7FA combustion turbine. The combustion turbines are fueled by natural gas and, if necessary, No. 2 distillate fuel oil. Construction began in July 2002 and the Louisa facility was available for commercial operation in June 2003.

In January 2003, we entered into an operation and maintenance service agreement with PIC Energy Services, Inc. (“PIC”). Under the agreement, PIC supplies all services, goods and materials required to operate the facility, other than natural gas and No. 2 distillate fuel oil. This agreement extends until the third anniversary of the commencement date of the Louisa facility, and expires on January 15, 2006 unless notice is given by either party. We arrange for the transportation and supply of the natural gas and No. 2 distillate fuel oil required by this facility. Power from Louisa is transmitted to our member distribution cooperatives over the transmission facilities of Virginia Power under its open access transmission tariff.

The Rock Springs facility was developed together with another participant, CED Rock Springs, Inc. (“ConEd”), and began commercial operations in June 2003. Rock Springs meets a substantial portion of the capacity requirements of our member distribution cooperatives on the Delmarva Peninsula and provides power to the other participant. Located in the community of Rock Springs, Cecil County, Maryland, the facility is currently permitted for six 168 MW (net capacity rating) General Electric 7FA combustion turbines, for a total of 1,008 MW. At this time, four units (672 MW) have been installed at the facility. We and ConEd each individually own two units and 50% of the common facilities.

In addition to ConEd, another participant may join the project in the future. We expect that each participant will own two units with a total capacity of 336 MW and a proportionate share of the undivided interest in the common facilities. We are responsible for all costs associated with the development, construction, additions and operating costs and administrative and general expenses relating to our two units and the proportional share of the costs relating to the common facilities for Rock Springs.

We acted as construction agent for ConEd, and will act as construction agent for any future participant or participants in Rock Springs to administer and supervise the development and construction of the facility. Construction began on the facility in October 2001 and was completed in June 2003. The power from the facility is transmitted to our member distribution cooperatives over PJM’s transmission facilities under its open access transmission tariff.

In July 2002, we and ConEd entered into an operation and maintenance agreement relating to the facility with CED Operating Co., L.P., an affiliate of ConEd. This agreement is for a three-year term which began on the commissioning date of the first unit and automatically extends for a one-year period unless notice is given by either party. CED Operating Co., L.P. supplies all services, goods and materials required to operate the facility other than natural gas. We arrange for the transportation of the natural gas required by the operator for all units at Rock Springs and arrange for the supply of natural gas to our units only.

The Marsh Run facility is located near Remington in Fauquier County, Virginia, and will consist of three 168 MW (net capacity rating) General Electric 7FA combustion turbines, for a total of 504 MW and our permit provides for a fourth unit. The combustion turbines will be fueled by natural gas and, if necessary, No. 2 distillate fuel oil. Our cost to develop and construct three units at Marsh Run is currently estimated to be approximately $230 million of which $163.9 million had been expended by the end of 2003.

We have a contract with Ragnar Benson, Inc. for engineering, procurement and construction services relating to Marsh Run. Construction of the facility began in April 2003 and we anticipate the three units will be available for commercial operation in the second quarter of 2004. Power from Marsh Run will be transmitted to our member distribution cooperatives over the transmission facilities of Virginia Power under its open access transmission tariff.

The operation and maintenance service agreement we entered into with PIC for Louisa also requires PIC to provide the services necessary for the transition from construction to operation of Marsh Run and supply all services, goods and materials required to operate that facility, other than natural gas and No. 2 distillate fuel oil, following completion of construction. This agreement will extend until the third anniversary of the commencement date of the Louisa facility and will expire on January 15, 2006 unless notice is given by either party. We will arrange for the transportation and supply of the natural gas and No. 2 distillate fuel oil required by this facility.

We have ten Caterpillar 3516B utility grade diesel generators throughout our member distribution cooperatives’ service territories. Each generator has a capacity of approximately two MW, for a total of 20 MW. We installed the generators primarily to enhance our system’s reliability. Four of the diesel generators service our member distributions cooperatives’ mainland Virginia territory and six of the diesel generators service our member distribution cooperatives’ Delmarva Peninsula territory.

We own two 1,100 foot 500 kilovolt (“kV”) transmission lines and a 500 kV substation at the Rock Springs site jointly with the other participant in the facility. As a transmission owner in PJM we have relinquished control of these transmission facilities to PJM and contracted with Con Edison Operation Company, Inc. and InfraSource to operate and maintain the transmission facilities.

In December 1992, we entered into an agreement with PSE&G to purchase capacity, reserves and associated energy, through 2004. See “Power Supply Resources—PSE&G” in Item 1. In 1997, we filed a complaint with FERC to modify the transmission charges we pay PSE&G under the agreement to reflect the restructuring of PJM into an independent system operator. In 1998, FERC directed PSE&G to remove all transmission costs from its charges to us, effective April 1, 1998, in a general order addressing several cases relating to the restructuring of PJM (the “PJM Order”). PSE&G complied with the PJM Order but appealed to the United States Court of Appeals for the District of Columbia Circuit. In July 2002, the Court of Appeals vacated the PJM Order and remanded the cases related to the PJM Order to FERC for further consideration. Later in 2002, FERC reversed the PJM Order. FERC noted that there was no evidence in the PJM Order proceedings to demonstrate any unduly discriminatory effects of our contract with PSE&G, but stated that we could present evidence specific to our contract.

In January 2003, we filed an amended and renewed complaint against PSE&G requesting FERC (1) reopen our 1997 complaint and (2) eliminate rate pancaking (incurring charges from multiple transmission owners due to transmission across several systems) under our agreement effective April 1, 1998. We also requested FERC stay any payment obligation to PSE&G for surcharges relating to the pancaked rates from April 1, 1998 through December 31, 2002.

We received an invoice from PSE&G in January 2003, for these additional surcharges in the amount of $26.2 million, plus $4.7 million in interest. We responded to PSE&G that surcharges for any past amount due under our agreement remains unauthorized and premature until ordered by FERC. Effective February 1, 2003, however, we began collecting approximately $32.9 million, which includes interest and related margin requirement, from our member distribution cooperatives, over 48 months to recover these amounts. We are paying PSE&G surcharges for pancaked rates on a prospective basis, subject to protest and FERC action on our renewed and amended complaint. On October 22, 2003, FERC denied our request to reopen the 1997 proceeding. We filed a request for rehearing in November 2003. On December 22, 2003, FERC issued a tolling order on our request for rehearing. The tolling order gives FERC an indefinite amount of time to rule on our request.

On December 8, 2003, PSE&G filed a lawsuit in the United States Court of the District of New Jersey in Newark, seeking payment of $26.2 million plus late payment charges, interest, and costs, including attorney fees. On January 29, 2004, we filed a motion to dismiss or, alternatively stay, any litigation pending a FERC decision on our request. On February 13, 2004, PSE&G filed a motion for summary judgment. Pending a hearing date on the cross motions, the New Jersey court has stayed discovery in the matter.

In October 2003, Norfolk Southern Railway Company (“Norfolk Southern”) notified an affiliate of Virginia Power that Norfolk Southern intended, effective January 1, 2004, to “correct” the rates and method of quarterly adjustment in its Coal Transportation Agreement (“Agreement”) for Clover. Norfolk Southern alleges that the Agreement specifies the use of a revised index instead of the initial index that has served as the basis of payment from inception of the Agreement. The Agreement, dated April 5, 1989, originally between Norfolk and Western Railway Company (“Norfolk Western”) and us, has an initial term of 20 years after the first shipment of coal. We have the right to extend the Agreement for two additional five-year terms. The Agreement has since been assigned to Virginia Power in connection with its purchase of a 50% undivided interest in Clover and its responsibilities as operating agent. Norfolk Western and Norfolk Southern merged in 1998. Coal has been delivered pursuant to the Agreement for over 10 years, and Norfolk Southern has accepted payment at the initial index. In order to prevent the index change sought by Norfolk Southern, we and Virginia Power filed suit against Norfolk Southern on November 26, 2003, in the Circuit Court of Halifax County, Virginia, requesting specific performance in the form of an injunction declaring that Norfolk Southern cannot change the initial index rate and, in the alternative, that the court enter a declaratory judgment confirming the applicability of the initial index to the Agreement. On January 15,

2004, Norfolk Southern filed an answer and counterclaim (for declaratory judgment, specific performance and damages) and a pleading under which Virginia law alleges that we and Virginia Power have failed to state a claim. A procedural schedule in the proceeding has not been set. We continue to work together with Virginia Power to prevent Norfolk Southern from depriving us of the economic benefits of the Agreement. If it is ultimately determined that we owe any amounts to Norfolk Southern, such amounts are not expected to have a material impact on our financial position, results of operations, or cash flow due to our ability to collect such amounts through rates.

Other than the FERC proceeding and related litigation regarding PSE&G transmission charges, the proceedings with Norfolk Southern, and 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, financial condition, or cash flows, there is no other litigation pending or threatened against us.

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, 2003, are derived from our audited consolidated financial statements. You should read the information contained in this table together with our consolidated financial statements, the related notes to the consolidated financial statements, and the discussion of this information in “Management’s Discussion and Analysis of Financial Condition and Results of Operations” in Item 7.

Our Indenture obligates us to establish and collect rates for service to our member distribution cooperatives, which are reasonably expected to yield a margin for interest ratio for each fiscal year equal to at least 1.10, subject to any necessary regulatory or judicial approvals. The Indenture requires that these amounts, together with other moneys available to us, provide us moneys sufficient to remain in compliance with our obligations under the Indenture. We calculate the margins for interest ratio by dividing our margins for interest by our interest charges.

In calculating margins for interest under the 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 Indenture for the year the refund is paid.

Interest charges under the Indenture equal our total interest charges (other than capitalized interest) related to (1) all obligations under the Indenture, (2) indebtedness secured by a lien equal or prior to the lien of the Indenture, and (3) 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.

In 2002, we amended the Indenture to modify the provisions for calculating margins for interest and interest charges. If we had calculated our margins for interest ratio under the prior provisions for each of the periods in which they were in effect, the ratio would have been 1.20 for each of those periods. In addition, if the prior provisions currently were in effect, our margins for interest ratio still would be 1.20 for 2003.

ITEM 7. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS

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

The preparation of our financial statements in conformity with generally accepted accounting principles requires that our management make estimates and assumptions that affect the amounts reported in our financial statements. We base these estimates and assumptions on information available as of the date of the financial statements and they are not necessarily indicative of the results to be expected for the year. We consider the following accounting policies to be critical accounting policies due to the estimation involved in each.

We are a rate-regulated entity and as a result are subject to the accounting requirements of Statement of Financial Accounting Standards (“SFAS”) No. 71, “Accounting for Certain Types of Regulation.” In accordance with SFAS No. 71, some of our revenues and expenses can be deferred at the discretion of our board of directors, which has budgetary and rate setting authority, if it is probable that these amounts will be refunded or recovered through our formulary rate in future years. Regulatory assets on our Consolidated Balance Sheet are costs that we expect to recover from our member distribution cooperatives based on rates approved by our board of directors in accordance with our formulary rate. Regulatory liabilities on our Consolidated Balance Sheet represent probable future reductions in our revenues associated with amounts that we expect to refund to our member distribution cooperatives based on rates approved by our board of directors in accordance with our formulary rate. See “Factors Affecting Results—Formulary Rate.” Regulatory assets are generally included in deferred charges and regulatory liabilities are generally included in deferred credits and other liabilities. We recognize regulatory assets and liabilities as expenses or as a reduction in expenses, concurrent with their recovery through rates.

In accordance with SFAS No. 71, we use the deferral method of accounting to recognize differences between our energy expenses and our energy revenues collected from our member distribution cooperatives. Deferred energy expense on our Consolidated Statement of Revenues, Expenses and Patronage Capital represents the difference between energy revenues and energy expenses. The deferred energy balance on our Consolidated Balance Sheet represents the net accumulation of any under- or over- collection of energy costs. Under-collected energy costs appear as an asset on our Consolidated Balance Sheet and will be collected from our member distribution cooperatives in subsequent periods through our formulary rate. Conversely, over-collected energy costs appear as a liability on our Consolidated Balance Sheet and will be refunded to our member distribution cooperatives in subsequent periods through our formulary rate.

We have a Margin Stabilization Plan that allows us to review our actual capacity-related costs of service and capacity revenue as of year end and adjust revenues from our member distribution cooperatives to meet our financial coverage requirements and accumulate additional equity as required by our board of directors. 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 calendar year. Each quarter we adjust revenues and accounts payable—members or accounts receivable, as appropriate, to reflect these adjustments. In 2003 and 2002, under our Margin Stabilization Plan, we reduced operating revenues by $3.2 million and $3.6 million, respectively, and increased accounts payable—members by the same amounts. There was no adjustment to operating revenues under our Margin Stabilization Plan in 2001.

We adopted SFAS No. 143 “Accounting for Asset Retirement Obligations” effective January 1, 2003. SFAS No. 143 requires legal obligations associated with the retirement of long-lived assets to be recognized at fair value when incurred and capitalized as part of the related long-lived asset. In the absence of quoted market prices, we estimate the fair value of our asset retirement obligations using present value techniques, in which estimates of future cash flows associated with retirement activities are discounted using its credit-adjusted risk free rate. Asset retirement obligations currently reported on our Consolidated Balance Sheet were measured during a period of historically low interest rates. The impact on measurements of new asset retirement obligations using different rates in the future, may be significant.

A significant portion of our asset retirement obligations relate to the future decommissioning of North Anna. At December 31, 2003, North Anna’s nuclear decommissioning asset retirement obligation totaled $40.3 million, which represented approximately 93.8% of our total asset retirement obligations. Because of its significance, the following discussion of critical assumptions inherent in determining the fair value of asset retirement obligations relates to those associated with our nuclear decommissioning obligations.

We obtain from third-party experts periodic site-specific “base year” cost studies in order to estimate the nature, cost and timing of planned decommissioning activities for North Anna. These cost studies are based on relevant information available at the time they are performed; however, estimates of future cash flows for extended periods are by nature highly uncertain and may vary significantly from actual results. In addition, these estimates are dependent on subjective factors, including the selection of cost escalation rates, which we consider to be a critical assumption.

We determine cost escalation rates, which represent projected cost increases over time, due to both general inflation and increases in the cost of specific decommissioning activities. The weighted average cost escalation rate used was 3.27%. The use of alternative rates would have been material to the liabilities recognized. For example, had we increased the cost escalation rate by 0.5% to 3.77%, the amount recognized as of December 31, 2003, for our asset retirement obligations related to nuclear decommissioning would have been $8.9 million higher.

We primarily purchase power under both long-term and short-term forward physical delivery contracts to supply power to our member distribution cooperatives under “all requirements” wholesale power contracts. These forward purchase contracts meet the accounting definition of a derivative; however, on a majority of the forward purchase derivative contracts, we apply the normal purchases/normal sales accounting treatment. Therefore, we record a liability and purchased power expense when the power under the forward physical delivery contract is delivered.

For forward purchase contracts that do not meet the qualifying criteria for normal purchases/normal sales accounting treatment, we elect cash flow hedge accounting, where applicable. Under cash flow hedge accounting, the fair value of the contract is recorded as a current or long-term derivative asset or liability. Subsequent changes in the fair value of the derivative assets and liabilities are recorded on a net basis in other comprehensive income and subsequently reclassified as purchased power expense in our Consolidated Statements of Revenues, Expenses and Patronage Capital as the power is delivered and/or the contract settles. Changes in the fair value of derivatives that are not designated as accounting hedges are recorded in earnings.

Generally, derivatives are reported on the Consolidated Balance Sheet at fair value. The measurement of fair value is based on actively quoted market prices, if available. Otherwise, we seek indicative price information from external sources, including broker quotes and industry publications. For individual contracts, the use of differing assumptions could have a material effect on the contract’s estimated fair value.

Our power sales are comprised of two power products – energy and capacity (also referred to as demand). Energy is the physical electricity delivered through the transmission and distribution facilities to customers. We must have sufficient committed energy available to us for delivery to our member distribution cooperatives to meet their maximum energy needs at any time, with limited exceptions. This committed available energy at any time is referred to as capacity.

The rates we charge our member distribution cooperatives for sales of energy and capacity are determined by a formulary rate accepted by FERC which is intended to permit collection of revenues which will equal the sum of:

The formulary rate has three components: a demand rate, a base energy rate and a fuel factor adjustment rate. The formulary rate identifies the cost components that we can collect through rates, but not the actual amounts to be collected. With one minor exception, we can change our rates periodically to match the costs we have incurred and we expect to incur without seeking FERC approval.

Energy costs, which are primarily variable costs, such as nuclear, coal and natural gas fuel costs and the energy costs under our power purchase contracts with third parties, are recovered through the two separate rates, the base energy rate and the fuel factor adjustment rate. The base energy rate is a fixed rate that requires FERC approval prior to adjustment. However, 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 rate. We review our energy costs at least every six months to determine whether the base energy rate and the current fuel factor adjustment rate together are adequately recovering our actual and anticipated energy costs, and revise the fuel factor adjustment rate accordingly. Since the fuel factor adjustment rate can be revised without FERC approval, we can effectively change our total energy rate to recover all our energy costs without seeking the approval of FERC.

Capacity 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, transmission costs, and our margin requirements and additional amounts approved by our board of directors are recovered through our demand rate. The formulary rate allows us to change the actual demand rate we charge as our capacity related costs change, without seeking FERC approval, with the exception of decommissioning cost, which is a fixed number in the formulary rate that requires FERC approval prior to any adjustment. Our 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.

Our operating revenues on our Consolidated Statement of Revenues, Expenses and Patronage Capital reflect the actual capacity-related costs we incurred plus the energy costs that we collected during each calendar quarter and at year-end. Estimated capacity-related costs are collected during the period through the demand component of our formulary rate. In accordance with our Margin Stabilization Plan, these costs, as well as operating revenues, are adjusted at the end of each reporting period to reflect actual costs incurred during that period. See “Critical Accounting Policies—Margin Stabilization Plan.” Estimated energy costs are collected during the period through the base energy rate and the fuel factor adjustment rate. Energy costs and operating revenues are not adjusted at the end of each reporting period to reflect actual costs incurred during that period. The difference between actual energy costs incurred and energy costs collected during each period is recorded as deferred energy expense. See “Critical Accounting Policies—Deferred Energy.”

We bill energy to each of our member and non-member customers based on the total megawatt-hours (“MWh”) delivered to them each month. We bill capacity to each of our member distribution cooperatives based on its requirement for energy during the hour of the month when the need for energy among all of the consumers in mainland Virginia or the Delmarva Peninsula, as applicable, is highest, measured in megawatts (“MW”).

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.

Under the Indenture, we are required, subject to any necessary regulatory or judicial approvals, to establish and collect rates reasonably expected to yield margins for interest for each fiscal year equal to at least 1.10 times our total interest charges for the fiscal year. The Indenture requires that these amounts, together with other moneys available to us, provide us moneys sufficient to remain in compliance with our obligations under the Indenture. See Item 6, “Selected Financial Data” for a description of the calculations of margins for interest and interest charges under the Indenture, and “—Future Issues—Restated Indenture” in this Item 7 for a discussion of the effect of a possible amendment and restatement of the Indenture.

Growth in the number of consumers and growth in consumers’ requirements for power significantly affect our member distribution cooperatives’ consumers’ requirements for power. Factors affecting our member distribution cooperatives’ consumers’ requirements for power include weather, as well as, the amount, size, and usage of electronics and machinery and the expansion of operations among their commercial and industrial customers.

Weather affects the demand for electricity. Relatively higher or lower temperatures tend to increase the demand for energy to use air conditioning and heating systems. Mild weather generally reduces the demand because heating and air conditioning systems are operated less.

Market forces influence the structure of new power supply contracts into which we enter. In mainland Virginia, we satisfy the majority of our member distribution cooperatives’ capacity and energy requirements through our ownership interests in Clover, North Anna, and Louisa, and we purchase energy from the market to supply the remaining needs of our mainland Virginia member distribution cooperatives. To serve the Delmarva Peninsula, we rely on Rock Springs and power purchase agreements to provide the capacity 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 when economical, we utilize the PJM power pool or generate power from Rock Springs.

Our operating expenses are significantly affected by the extent to which we purchase power and, relatedly, the availability of our base load generating facilities, Clover and North Anna. Base load generating facilities, particularly nuclear power plants such as North Anna, generally have relatively high fixed costs. Nuclear facilities operate with relatively low variable costs due to lower fuel costs and technological efficiencies. In addition, coal-fired facilities have relatively low variable costs, as compared to combustion turbine facilities such as Rock Springs and Louisa. Owners of nuclear and other power plants incur the embedded fixed costs of these facilities whether or not the units operate. When either North Anna or Clover is off-line, we must purchase replacement energy from either Virginia Power, which is more costly, or from 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 rather than our combustion turbine facilities. Our combustion turbine facilities have relatively low fixed costs and greater operational flexibility; however, they are more expensive to operate and, as a result, we will operate them only when the market price of energy makes their operation economical. The output of North Anna and Clover for the past three years as a percentage of maximum dependable capacity rating of the facilities was as follows:

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:

If, in any given year, our member receipts are less than 85% of our gross receipts, we would become a taxable entity in that year, and the potential tax liability could be significant. Our ability to maintain a 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. A decrease in member revenues resulting from the effect of retail competition could also cause us to lose our tax-exempt status. See “—Future Issues—Competition and Changing Regulations.” We regularly monitor the level of our member and 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.

In the late 1990’s, we implemented a strategic plan, the goal of which was 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 (the “Strategic Plan Initiative”). From 1998 through 2001, we accumulated $160.3 million in cash and investments, primarily by accelerating the amortization of regulatory assets and accelerating the depreciation of our generating facilities. This cash was used to purchase and retire $151.6 million of Old Dominion’s indebtedness and to pay associated premiums. As a result of these actions, we will incur less amortization and depreciation expense in the future, and our future interest expense and the associated margins for interest requirement will be lower.

Our operating revenues are derived from power sales to our members and non-members. Our sales to members include sales to our Class A members, which are our twelve distribution cooperative members, and sales to our single Class B member, TEC . Our operating revenues by type of purchaser for the past three years were as follows:

Revenues from sales to our member distribution cooperatives are a function of our formulary rate for sales of power to our member distribution cooperatives and our member distribution cooperatives’ consumers’ requirements for power. Our formulary rate is based on our cost of service in meeting these requirements. See “Factors Affecting Results—Formulary Rate.”

Our revenues from sales to our member distribution cooperatives by formulary rate component, energy sales to our member distribution cooperatives, and average costs to our member distribution cooperatives per MWh for the past three years were as follows:

Total revenues from our member distribution cooperatives for the year ended December 31, 2003, increased $22.6 million, or 4.6% over the same period in 2002 as a result of increases in our rates that occurred in 2003 in response to actual and projected increases in capacity and energy costs. For the year ended December 31, 2003, there was no material change in the volume of energy or capacity sales. Colder than normal weather experienced during the first quarter of 2003 yielded an increase in sales volumes as compared with the first quarter of 2002; however, milder weather during the second, third, and fourth quarters of 2003 tempered these increases. The increases in costs, combined with lower sales volumes, caused our average capacity and energy costs for 2003 to be approximately 8.4% and 4.6% higher than in 2002, respectively.

Effective February 1, 2003, we increased the demand component of our formulary rate (which collects our capacity-related costs) approximately 5.0% to collect from our member distribution cooperatives transmission charges associated with our power purchase agreement with Public Service Electric & Gas Company (“PSE&G”). We anticipate that the increase in the demand component of our formulary rate will recover over 48 months $32.9 million related to a surcharge billed to us by PSE&G, and associated interest expense and margin requirement. See “Legal Proceedings” in Item 3. Additionally, we anticipate that the revised demand component of our formulary rate will recover the amount of transmission costs that we are paying to PSE&G now until the termination of the contract in December 2004. We are making these payments under protest and subject to FERC action on this issue. See “Legal Proceedings” in Item 3. The amount of revenues collected by our demand rates in 2003 and 2002 was reduced by margin stabilization adjustments of $3.2 million and $3.6 million, respectively, so that our revenues would reflect our actual capacity-related costs for the respective years. The $3.2 million and $3.6 million is included in accounts payable-members at December 31, 2003 and December 31, 2002, respectively. See “Critical Accounting Policies—Margin Stabilization.”

Effective March 31, 2003, we increased our fuel factor adjustment rate, which resulted in an increase to our total energy rate (including our base energy rate and our fuel factor adjustment rate) of approximately 21.8%. We increased the fuel factor adjustment rate to recover higher than expected actual energy costs in the first two months of 2003 and energy costs for the remainder of the year that we anticipated would be higher than the energy costs we originally budgeted. The previous change to our fuel factor adjustment rate was effective October 1, 2002, when we reduced our total energy rate approximately 9.5% because we had over-collected our energy costs incurred to date and anticipated that the lower rate would adequately recover our energy costs in the future. At December 31, 2003, our deferred energy balance represented a $13.6 million over-collection of energy costs. See “Operating Expenses” below for a discussion of factors impacting both capacity and energy costs.

Total revenues from our member distribution cooperatives for the year ended December 31, 2002, increased by $12.3 million, or 2.6%, over the same period in 2001 as a result of increased sales of both capacity and energy. Capacity sales for 2002, measured in MW, increased by 10.7% and energy sales, measured in MWh, increased by 7.8% over those realized in 2001. Sales volumes increased primarily as a result of unusually hot weather that consumers experienced in the service territories of our member distribution cooperatives during the summer of 2002. Higher than normal temperatures created a greater requirement for power to operate air conditioning systems.

The increase in total revenues attributable to a growth in sales volume was partially offset by a decrease in the average rates that we charged in 2002 for power sold. Both our average demand rate and energy rate decreased 5.9% in 2002 compared to 2001. The decrease in our average demand rate was driven primarily by a reduction in depreciation expense resulting from the discontinuation of accelerated depreciation under our Strategic Plan Initiative, and the recognition of approximately $11.4 million in capacity revenues that were collected in 2001 and deferred until 2002.

Our average energy rate (including our base energy rate and our fuel factor adjustment rate) decreased as a result of a 15.1% drop in our average fuel factor adjustment rate. We reduced our fuel factor adjustment rate effective April 1, 2002, because the fuel factor adjustment rate that had been in effect since April 1, 2001, had fully recovered our deferred energy balance at December 31, 2001 (an $18.2 million under-collection of energy costs) and had resulted in a $4.1 million over-collection of energy costs at March 31, 2002, and we anticipated that future energy costs would be adequately recovered with a lower fuel factor adjustment rate. See “Critical Accounting Policies—Deferred Energy.” We reduced our fuel factor adjustment rate again effective October 1, 2002, because our deferred energy balance at September 30, 2002, represented a $5.0 million over-collection of energy costs, and we again anticipated that future energy costs would be adequately recovered with a lower fuel factor adjustment rate. At December 31, 2002, our deferred energy balance represented a $3.0 million over-collection of energy costs.

Our sales to TEC are primarily sales of energy that we do not need to meet the actual needs of our member distribution cooperatives. We refer to this as excess energy. These sales were $11.7 million, or 450.0%, higher in 2003 than in 2002. During the first five months of 2003, we exercised a contractual option to purchase energy at then favorable market prices. We sold the portion of this energy that could not be utilized by our member distribution cooperatives to TEC for resale into the market, or to non-members. Energy sales in MWh to TEC for 2003 and 2002 were 291,653 MWh and 67,360 MWh, respectively. There were no sales to TEC in 2001.

Sales to non-members consist of sales of excess purchased energy and sales of excess generated energy from Clover. We sell excess purchased energy that is not sold to TEC to PJM under its rates for providing energy imbalance services. We sell excess energy from Clover to Virginia Power pursuant to the requirements of the Clover Operating Agreement. See “Properties—Clover” in Item 2. Non-member revenues for the year ended December 31, 2003, were higher than in 2002 by $6.7 million or 215.9% primarily because of an increase in excess energy purchased under the option contract discussed in “Sales to TEC” above.

Non-member revenues for the year ended December 31, 2002, were $7.6 million lower than 2001 because a portion of sales we previously made to PJM were made to TEC and because of a decrease in excess energy sales volume. Our non-members energy sales in MWh for 2003, 2002, and 2001 were 262,077, 93,721, and 268,609, respectively.

We supply our member distribution cooperatives’ power requirements, consisting of capacity requirements and energy requirements, through (i) our owned or leased interests in electric generating facilities which consist of a 50% interest in Clover, an 11.6% interest in North Anna, our Rock Springs and Louisa combustion turbine facilities, and distributed generation, and (ii) power purchases from third parties through power purchase contracts and forward, short-term and spot market energy purchases. See “Business—Power Supply Resources” in Item 1. Rock Springs’ two units began commercial operations in June 2003 and Louisa’s five units began commercial operations in June and July of 2003. Our energy supply for the past three years was as follows:

Clover Unit 1 was off-line 20 days in 2003, 61 days in 2002, and 13 days in 2001 for scheduled maintenance. It experienced no major unscheduled maintenance outages during these periods.

Clover Unit 2 was off-line 36 days in 2003, 13 days in 2002, and 15 days in 2001 for scheduled maintenance. Additionally in 2002, the load on Clover Unit 2 was reduced to 125 MW for 14 days due to an unscheduled maintenance outage.

North Anna Unit 1 began an outage for a scheduled refueling and to replace the reactor vessel head on the unit on February 23, 2003 and was returned to service on April 18, 2003. During 2003, North Anna Unit 1 also experienced an unscheduled ten-day outage. There were no maintenance outages at North Anna Unit 1 during 2002. During 2001, North Anna Unit 1 was off-line 30 days for a scheduled refueling outage.

North Anna Unit 2 began a scheduled refueling outage on September 8, 2002. During the outage, the reactor vessel head was replaced and the unit was returned to service on February 2, 2003. During 2001, North Anna Unit 2 was off-line 30 days for a scheduled refueling outage and 48 days for inspection and repair.

The components of our operating expenses for the years ended December 31, 2003, 2002, and 2001, were as follows:

Our operating expenses are comprised of the costs that we incur to generate and purchase power to meet the needs of our member distribution cooperatives, and the costs associated with any sales of power to TEC and non-members. Our energy costs generally are variable and include fuel expense as well as the energy portion of our purchased power expense. Our capacity or demand costs generally are fixed and include depreciation, amortization and decommissioning expenses, and interest charges (a non-operating expense), as well as the capacity portion of our purchased power expense.

Total operating expenses for 2003 increased $27.0 million, or 6.0%, over 2002 primarily due to increases in fuel expense, purchased power expense, depreciation, amortization and decommissioning, accretion and the change in the amortization of regulatory (liability)/asset, net. These increases were partially offset by the change in deferred energy expense.

Fuel expense increased $17.5 million, or 30.3%, primarily due to the purchase of natural gas and fuel oil for the operation of our Louisa and Rock Springs combustion turbine facilities. Louisa and Rock Springs began commercial operation in June of 2003. Our combustion turbine facilities have relatively low fixed costs and greater operational flexibility, but are more expensive to operate and, as a result, we operate them only when the market price of energy makes their operation economical.

Purchased power expense increased $7.4 million, or 2.6%, as a result of a 4.6% increase in the average cost of purchased power per MWh. We purchased additional energy from the market to supply our member distribution cooperatives’ requirements during unusually cold winter weather in the beginning of 2003 as well as to replace energy normally provided by, but not available from, North Anna due to the replacement of the reactor vessel heads. Purchased power expense for 2003 included $5.0 million associated with the current portion of disputed charges under the PSE&G contract. There were no amounts included in 2002 for the disputed charges under the PSE&G contract. See “Legal Proceedings” in Item 3.

Deferred energy expense decreased $10.7 million, or 50.5%, over 2002 reflecting a reduction in our over-collection of energy costs in 2003 as compared to 2002. During 2003, we collected $10.5 million in excess of energy costs incurred as compared to 2002, when we collected $21.3 million in excess of energy costs incurred. The $10.5 million we over-collected in 2003 increased our end of year deferred energy balance from $3.1 million to $13.6 million.

Depreciation, amortization and decommissioning expense increased by $3.2 million, or 13.4%, over 2002 primarily due to $6.5 million of depreciation related to our Louisa and Rock Springs combustion turbine facilities, and $0.2 million of depreciation related to asset retirement costs. These increases were partially offset by a $3.8 million reduction in depreciation for North Anna as a result of the extension of the North Anna operating licenses which was effective in 2003.

Amortization of regulatory (liability)/asset, net changed $3.7 million, or 64.0%, causing operating expenses to increase, primarily because in 2003 we recognized the $5.6 million revenue deferral that had been established in 2002, and in 2003 we recorded $3.2 million related to a charge against a regulatory liability related to the cumulative effect of change in accounting principle for the adoption SFAS No. 143. These decreases were partially offset by $6.1 million related to the amortization of the PSE&G regulatory asset and by the $0.6 million amortization of the regulatory assets related to SFAS No. 143.

Accretion of asset retirement obligations is a result of the adoption of SFAS No. 143 in 2003.

Total operating expenses for 2002 increased $8.3 million, or 1.9%, over 2001 due to increases in purchased power expense and deferred energy expense that were mitigated by a decrease in depreciation, amortization and decommissioning expense and a change in amortization of regulatory (liability)/asset, net. Purchased power expense increased $17.6 million, or 6.5%, as a result of increased sales of capacity and energy, and a greater dependence on purchased power to meet 2002’s power needs. The average cost of purchased power decreased 6.9% in 2002. Deferred energy expense increased $24.2 million in 2002 as we recovered through rates previously incurred but not fully collected energy costs. The $21.3 million of deferred energy expenses we incurred in 2002 allowed us to fully recover our deferred energy deficit balance as of December 31, 2001, of $18.3 million and resulted in a deferred energy surplus balance as of December 31, 2002, of $3.0 million.

Depreciation, amortization and decommissioning expense decreased by $17.9 million, or 43.0%, primarily because we stopped recording accelerated depreciation under our Strategic Plan Initiative effective June 1, 2001. In 2002 we recorded no accelerated depreciation compared to $18.5 million recorded in 2001. Amortization of regulatory (liability)/asset, net changed $17.2 million, or 151.1%, causing operating expenses to decline primarily because in 2002 we recognized the $11.4 million revenue deferral which had been established in 2001, and in 2002 we also established a $5.6 million revenue deferral under the revenue deferral plan to cover expenses we expected to incur in 2003 associated with the replacement of the reactor vessels heads at North Anna.

Operations and maintenance expense increased $4.9 million, or 14.2%, in 2002 as compared to 2001 due to cost incurred in 2002 associated with the replacement of the reactor vessel heads at North Anna.

The major components of our other (expense)/income, net for the years ended December 31, 2003, 2002, and 2001 were as follows:

Other (expense)/income, net changed in 2003 by $0.1 million as compared to 2002 primarily due to the donation of transmission assets to one of our member distribution cooperatives, offset by fees received for load management services. Other (expense)/income, net decreased in 2002 by $1.6 million, or 97.4%, as compared to 2001 mainly due to a reduction in gains (increase in losses) on the sale of investments and an increase in donations. The increase in donations in 2002 was the result of our donation of transmission assets to one of our member distribution cooperatives.

Investment income increased in 2003 by $0.8 million, or 31.0%, due to an increase in invested funds. Our average balance of investments-other, and cash and cash equivalents increased from 2002 to 2003 due to our December 2002 $300.0 million and July 2003 $250.0 million issuances of indebtedness under the Indenture. See “Liquidity and Capital Resources—Sources—Financings.”

Investment income decreased in 2002 by $0.6 million, or 20.6%, as compared to 2001 as a result of a significant decrease in the interest rates earned on our investments and cash equivalents. Our average balance of investments-other, and cash and cash equivalents increased from 2001 to 2002, primarily due to our issuance of $215.0 million of additional indebtedness under the Indenture in September 2001. These proceeds were used during 2002 to continue funding the development and construction of our combustion turbine facilities. We also funded a portion of 2002’s expenditures with proceeds from our December 17, 2002 issuance of $300.0 million of additional indebtedness under the Indenture. See “Liquidity and Capital Resources—Uses—Capital Expenditures.”

The primary factors affecting our interest expense are scheduled payments of principal on our indebtedness, prepayments of indebtedness, issuance of new indebtedness, and capitalized interest.

The major components of interest charges, net for the years ended December 31, 2003, 2002, and 2001, were as follows:

Interest charges, net increased in 2003 by $9.3 million, or 25.4%, as compared to 2002, due to our increased long-term indebtedness balance as a result of our July 2003 $250.0 million issuances of indebtedness and our December 2002 $300.0 million issuance of indebtedness under the Indenture (See “Liquidity and Capital Resources—Sources—Financings.”) and due to interest related to an amount in dispute with PSE&G. See “Legal Proceedings – PSE&G” in Item 3.

Interest charges, net decreased in 2002 by $4.7 million, or 11.5%, as compared to 2001 due to an increase in the amount of capitalized interest relating to our combustion turbine facilities. We began capitalizing interest on the Rock Springs and Louisa facilities in October 2001 and January 2002, respectively. Capitalized interest is computed monthly using our interest rate, which reflects our embedded cost of indebtedness, times our investment in projects under construction. Total interest charges increased in 2002 by $7.8 million, or 18.4%, as compared to 2001 due to interest charges associated with our September 2001 issuance of $215.0 million. This increase in debt was partially offset by a $28.4 million scheduled principal retirement that occurred in December 2001.

Our net margin, which is a function of our total interest charges, increased $2.1 million, or 20.6%, in 2003 as compared to 2002, due to the $10.3 million increase in our total interest charges, attributable primarily to our December 2002 and July 2003 debt issuances. Our net margin increased $1.6 million, or 18.4%, in 2002 as compared to 2001, due to the $7.8 million increase in our total interest charges, primarily attributable to our September 2001 debt issuance.

The principal changes in our financial condition during 2003 resulted from a significant increase in electric plant in service related to the completion of our Louisa and Rock Springs, combustion turbine facilities, a decrease in construction expenditures associated with these combustion turbine facilities and an increase in long-term indebtedness. See “Liquidity and Capital Resources—Sources—Financings.” A reduction in the volume of construction expenditures in connection with the combustion turbine facilities as well as the reclassification of expenditures from construction work in progress to electric plant in service was the primary reason that our construction work in progress balance decreased by approximately $210.1 million, or 56.5%, from December 31, 2002 to December 31, 2003. The unexpended proceeds from our debt issuances are included in investments-other, and cash and cash equivalents. Investments-other decreased $20.3 million, or 26.0%, and cash and cash equivalents decreased $36.1 million or, 53.2%, from December 31, 2002 to December 31, 2003, because we liquidated investments and spent cash to satisfy additional requirements to finance the combustion turbine facilities.

In July 2003, we issued $250.0 million of 2003 Series A Bonds. The proceeds from this debt issuance were used to fund construction costs associated with our combustion turbine facilities and to redeem $130.9 million of our outstanding indebtedness on December 1, 2003.

As of December 31, 2003, our accounts payable-members account balance decreased by $12.2 million, or 20.3%, over the same period in 2002 as a result of a decrease in the amount of power bill prepayments that we received from our member distribution cooperatives and an increase in amounts owed to our member distribution cooperatives under our Margin Stabilization Plan. Our deferred energy balance was a credit of $13.6 million as of December 31, 2003, representing a surplus in the collection of energy costs, as compared to a credit of $3.0 million as of December 31, 2002. This change resulted from the fact that the revenues we collected from our member distribution cooperatives, through the base energy rate and fuel adjustment factor rate in 2003, were higher than the energy costs that we incurred in 2003. In 2003, we recognized $10.3 million in revenue that was deferred in 2002. We did not defer any revenue in 2003. See “Results of Operations—2003 Compared to 2002.”

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

Historically, our operating cash flows have been sufficient to meet our short and long-term capital expenditures related to our generating facilities, our debt service requirements, and our ordinary business operations. Our operating activities provided cash flows of $17.1 million, $120.5 million, and $80.4 million, in 2003, 2002, and 2001, respectively. Cash flows provided by operating activities during 2003 decreased primarily as a result of decreases in long-term debt due within one year, deferred revenue, accounts payable and accounts payable—members. See “Financial Condition.” These decreases were partially offset by a change in regulatory assets and liabilities associated with the implementation of SFAS No. 143 and an increase in depreciation resulting from the commercial operation of two of our combustion turbine facilities in 2003.

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 $230.0 million. Of this amount, $110.0 million is available for general working capital purposes and $120.0 million is available for capital expenditures related to our generating facilities. At December 31, 2003, and 2002, 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.

Our short-term committed variable rate lines of credit are more particularly described by lender, the amount of the line of credit provided by that lender and the expiration date as follows:

In addition to our lines of credit, we also have a committed, $50.0 million three-year revolving credit facility with CoBank, ACB. The facility is available for capital expenditures and general corporate purposes. The commitment expires on March 18, 2007.

Our credit agreements relating to our lines of credit and the revolving credit facility contain customary events of default, which, if they occur, would terminate our ability to borrow amounts under those facilities and potentially accelerate any outstanding loans under those facilities at the election of the lender. Some of these customary events of default relate to:

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 primarily of the costs related to the acquisition of our interest in North Anna, our share of the costs to construct Clover, other capital improvements and additions to Clover and North Anna, and the development and construction of our three combustion turbine facilities, which accounted for a significant portion of our cash expenditures in 2003. We currently have a shelf registration effective with the Securities and Exchange Commission. Pursuant to this registration statement, as of December 31, 2003, we may issue an additional $150 million of debt securities.

In July 2003, we issued $250.0 million of 2003 Series A Bonds under the Indenture and our shelf registration. The bonds bear interest at 5.625% and mature in 2028. A portion of the proceeds was used to redeem $130.9 million of our outstanding indebtedness. The remainder of the proceeds are being used primarily to complete the construction of our combustion turbine facilities. An offering in December 2002 of $300.0 million of our 2002 Series B Bonds also was used to repay lines of credit and fund development and construction costs related to our combustion turbine facilities.

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 recently have required significant capital expenditures. We expect that cash flows from our operations, the net proceeds of our recent issuances of indebtedness and our existing lines of credit and revolving credit facility, will be sufficient to meet our operational and capital requirements.

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 2001 through 2006:

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 additions to the solid waste and emissions reduction facilities at Clover and our portion of the cost of the nuclear fuel purchased for North Anna, and a turbine upgrade project for North Anna. Other capital expenditures include the purchase of computer hardware, and the purchase and development of computer software. We intend to use our cash from operations to fund all of our capital requirements not related to the development and construction of the combustion turbine facilities through 2006.

In March 2001, we purchased an interest in Aces Power Marketing LLC (“APM”) for $750,000. 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 in exchange for all of its capital stock. We distributed the stock of TEC as a patronage distribution to our member distribution cooperatives on the same date.

In July 2003, we issued $250.0 million of 2003 Series A Bonds under our Indenture. These bonds bear interest at 5.676% and mature in 2028. The proceeds were used to redeem $130.9 million of our outstanding indebtedness and are being used to fund construction costs associated with our combustion turbine facilities.

On December 1, 2003, we redeemed $113.4 million of our 1993 Series A Bonds, due 2013, and $17.5 million of our 1993 Series A Bonds, due 2023. We paid the holders of these bonds total premiums of $9.8 million for the redemption of their bonds prior to maturity.

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 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. In 2002, we used $71.1 million, the remaining balance of funds available to us under the Strategic Plan Initiative, to partially fund the redemption of our First Mortgage Bonds, 1992 Series A, due 2022 ($176.6 million). We paid the holders of these bonds total premiums of $15.8 million for the redemption of their bonds prior to maturity.

On the date of maturity, December 2, 2002, we paid $5.0 million to fully retire our First Mortgage Bonds, 1996 Series B. These bonds bore interest at a fixed rate of 4.25%, and were issued to secure our obligation to repay a $5.0 million loan made to us by the Industrial Development Authority of Goochland County, Virginia in December 1996.

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—Power Purchase Contracts” in Item 1 and “Future Issues—Reliance on Market Purchases of Energy.” The following table summarizes our long-term contractual obligations at December 31, 2003:

We expect to fund these obligations with cash flow from operations, unused proceeds from our issuances of long-term indebtedness and the issuances of additional long-term indebtedness.

At December 31, 2003, 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. Long-term indebtedness obligations include both principal and interest on our indebtedness.

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 “Properties—Clover” in Item 2 .” Our obligations described above relate to a portion of our obligations under these leases, including periodic basic rent. We fund substantially all of our 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”).

During 2002, we had entered into an operations and maintenance agreement with CED Operating Co., L.P., for the Rock Springs facility. We also entered into an operations and maintenance agreement with PIC Energy Services, Inc. for the Louisa and Marsh Run facilities. We have only included the fixed charges under these agreements. The ongoing operating payment obligation will vary based on the operation of these facilities.

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

We entered into a number of agreements relating to the development and construction of the combustion turbine facilities, including engineering, procurement and construction agreements, interconnection agreements, and joint ownership agreements. See “Properties —Combustion Turbine Facilities” in Item 2.

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 “Properties—Clover” in Item 2.

To facilitate the ability of TEC to sell power in the market, we have agreed to guarantee up to a maximum of $42.5 million of TEC’s delivery and payment obligations associated with its energy trades if requested. See “Business—TEC” in Item 1. Our agreement to guarantee these obligations continues in effect until we elect to terminate it by providing at least 30 days prior written notice of termination or until all amounts owed to us by TEC have been paid. Our guarantee of TEC’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, 2003, we had a total of $9.5 million in guarantees outstanding on behalf of TEC and as of March 3, 2004, we had total guarantees of $14.5 million outstanding on behalf of TEC.

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 “Properties—Clover” in Item 2. 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, 2003, the maximum amount of collateral we could have been required to provide under this provision was $1.5 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 and “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, 2003, the amount of the letter of credit we would have been required to provide was $53.4 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, 2003, we were party to 26 agreements based on the EEI Form Contract and one other power purchase agreement obligating us to provide collateral if our credit ratings fell below specified thresholds. Collectively, at December 31, 2003, if the credit ratings by S&P and Moody’s of our obligations issued under the Indenture fell below “BBB” or “Baa2” or investment grade (i.e., “BBB-” or “Baa3”), respectively, we would have been obligated to provide collateral security in the amount of approximately $2.3 million and $3.5 million, respectively. This calculation is based on energy prices on December 31, 2003 and delivered power for which we have not yet paid. Depending on the difference 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.

Additionally, in accordance with the credit policy of PJM, PJM subjects each applicant, participant and member of PJM to a complete credit evaluation to determine its creditworthiness, and whether it must provide any collateral to support its obligations in connection with its PJM transactions. PJM has never required us to provide any collateral to support our obligations. A material change in our financial condition, including the downgrading of our credit rating by any rating agency, could cause PJM to re-evaluate our creditworthiness and require that we provide collateral. As of December 31, 2003, if our ratings were lowered and PJM determined that we needed to provide collateral to support our obligations, PJM could have asked us to provide up to approximately $14.4 million of collateral security.

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—Power Purchase Contracts” in Item 1.

In 1996, we entered into two lease transactions relating to our 50% undivided ownership interest in Clover. See “Properties—Clover” in Item 2. One lease relates to our undivided interest in Clover Unit 1 and the other relates to our undivided interest in Clover Unit 2 and, in each case, the common facilities. In both transactions, we leased our undivided interests in the facilities to an owner trust for the benefit of an investor for the full productive life of Unit 1 and Unit 2 in exchange for one time rental payments at the beginning of the leases of $315.0 million and $320.0 million, respectively. Each owner trust funded this payment in part through two loans from a bank. Immediately after the leases to the owner trusts, we leased the units back for terms of 21.8 years and 23.4 years, respectively, and agreed to make periodic rental payments to the owner trusts.

We used a portion of the one-time rental payments we received in each transaction to enter into payment undertaking agreements and to make deposits which provide for substantially all of:

The deposits are issued or insured by entities which have claims paying abilities or senior debt obligations which are rated “AAA” by S&P and “Aaa” by Moody’s. After entering into the payment undertaking agreements, making the deposits and paying transaction costs we had $23.7 million and $39.3 million, respectively, remaining of the one time rental payments in the Unit 1 and Unit 2 transactions. As a result, following completion of the transactions we retained possession and our initial entitlement to the output of the units, and we had funds of $63.0 million remaining.

Both leasebacks require us to make periodic basic rental payments. For 2003, our statement of cash flow reflects payments we made of basic rent to the Unit 1 and Unit 2 owner trusts of $0.6 million and $1.7 million, respectively. Of these payments, $0.7 million and $1.7 million, respectively, were funded through distributions from the deposits made with lease proceeds. In addition to these amounts, $19.5 million and $15.3 million of additional basic rent was required under the Unit 1 and Unit 2 leases, respectively, in 2003. These additional amounts of basic rent were paid by third parties, “payment undertakers,” under payment undertaking agreements made at the inception of the leases. Under each of these arrangements, Old Dominion made a payment to the payment undertaker whose debt obligations are rated “AAA” by S&P and “Aaa” by Moody’s in return for which the payment undertaker agreed to make payments directly to the lender in the related lease transaction in satisfaction of a portion of our basic rent payment obligation under the leaseback and the owner trust’s repayment obligation under the loan to it. At December 31, 2003, both the value of this portion of our lease obligations, as well as the value of our interest in the related payment undertaking agreements, totaled approximately $273.0 million and $243.9 million for Unit 1 and Unit 2, respectively. Our financial statements do not reflect the payment undertaking agreements, the payments made by the payment undertaker or the payment of this portion of basic rent. We remain liable for all rental payments under the leasebacks if the payment undertaker fails to make such payments although the owner trusts have agreed to pursue the payment undertaker before pursuing payment from us.

At the end of the term of both leasebacks, we have the option to purchase the owner trust’s interest in the applicable unit or arrange for an acceptable third party to enter into a power purchase agreement with the owner trust. If we decide to purchase the owner trust’s interest in a unit, we must pay the applicable owner trust a fixed purchase price of $430.5 million in the case of Unit 1, and $458.9 million in the case of Unit 2. Payments under the payment undertaking agreements will fund a substantial portion of these payments. Substantially all of the remainder of these payments will be funded by the deposits we made at the inception of the leaseback. If we do not elect to purchase the owner trust’s interest in either unit, Virginia Power has an option to purchase that interest. If Virginia Power elects to purchase the interest but fails to pay the purchase price when due, we are obligated to make that payment, with interest, within 30 days.

If we elect not to purchase the owner trust’s interest in either unit, we can arrange for a third party to purchase the applicable owner trust’s output of the unit at prices which will preserve each owner trust’s net economic return as if we had purchased the related unit at the purchase option price. To be an eligible power purchaser, the third party must have, among other things, a net worth of at least $500 million and minimum specified credit ratings or other acceptable credit enhancement. We would assist in transmitting power to the third party by entering into a transmission and interconnection agreement with the owner trust. We also would be obligated to assist the owner trust in arranging new financing for the lease debt which remains outstanding at the expiration of the leasebacks. We would not be obligated, however, to provide this financing. Under the leaseback for Unit 1, however, if alternate financing is not available or we otherwise fail to satisfy the conditions to arrange for a new third party purchaser, we must either exercise our purchase option or make a termination payment to the owner trust. Under the Unit 1 lease, we also must provide management services to the owner trust if power is being sold to the third party.

In the Unit 1 lease, a third option at the end of the term of the leaseback exists. We may pay to the owner trust an amount equal to the difference between a specified termination amount and the fair market value of its interest in Unit 1 and return possession of the interest in the unit back to the owner trust. The amount we are obligated to pay cannot exceed the specified termination amount minus 20% of the fair market value of the owner trust’s interest in the unit at the time the lease was entered into in 1996 or be less than the amount of the owner trust’s debt to its lenders at the expiration of the leaseback. If we do not purchase the interest and the owner trust requests, we are obligated to use our best efforts to sell the owner trust’s interest in the unit at the end of the leaseback. Any sale proceeds would be credited against the payment we are obligated to make to the owner trust. If we are not able to sell the interest by the end of the leaseback, we must pay the owner trust the full amount of the required payment but we are entitled to be reimbursed out of the proceeds of the sale in excess of 20% of the value of the owner trust’s interest at the time the lease was entered into in 1996, plus interest, if the facility is sold within the following 36 months.

In connection with the lease relating to Unit 1, we agreed to deliver a letter of credit to the institutional investor party in 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 and “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, 2003, the amount of letter of credit we would have been required to provide was $53.4 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.

The electric utility industry has gone through significant changes over the past several years. In the 1990’s new federal and state laws and regulations deregulated some portions of the industry and resulted in increased competition among wholesale electricity suppliers and increased access to transmission services by these suppliers. See “Competition and Changing Regulations” below. Recently, however, the electric utility industry has been impacted by the response of the market and federal and state governmental authorities to the California energy crisis, the bankruptcy of Enron Corporation, and significant fluctuations in the availability and cost of fuel for the generation of electricity. A number of other significant factors have affected the operations of electric utilities in recent years. These factors include the use of alternative fuel sources for space and water heating and household appliances; fluctuating rates of load growth; compliance with environmental 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 events 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. These events could be reasons for our member distribution cooperatives to restructure

their current businesses to operate more effectively in this changing environment. In part for these reasons, we currently are considering a restructuring of our relationship with our member distribution cooperatives. See “Business—Potential Restructuring” in Item 1.

Also as a result of these events, 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. In addition, 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. See “Business—Member Distribution Cooperatives—Wholesale Power Contracts” and”—Northern Virginia Electric Cooperative” in Item 1.

Virginia, Delaware and Maryland 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, Delaware and Maryland contain similar components.

The restructuring laws of Virginia, Delaware and Maryland 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 sell power to customers located in its certificated service territory. Transmission and distribution of power will remain regulated services. At March 1, 2004, 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 customers have switched to alternative providers. If customers of our member distribution cooperatives do choose alternative power suppliers in the future, this could result in a significant reduction in our revenues and cash flows. The resulting decrease in our member revenues could cause us to lose our tax-exempt status. See “Factors Affecting Results—Tax Status.”

By January 1, 2004, customers accounting for approximately 99.7% of our capacity requirements in 2003 were 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 that state accounted for approximately 0.3% of our capacity requirements in 2003.

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, Delaware and Maryland 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.

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. The member distribution cooperatives’ exposure to potentially stranded costs most likely would result from power purchase agreements that 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. Under the wholesale power contract we have with each of our member distribution cooperatives and through our formulary rate, we would continue to collect all our costs including those that may otherwise be considered stranded costs from our member distribution cooperatives. See “Business—Member Distribution Cooperatives—Wholesale Power Contracts” in Item 1. The ability of our member distribution cooperatives to collect all their costs depends upon the legislation enacted in each

of their respective jurisdictions and the individual rate structures that have been approved for them by their respective state regulators. See “Capped Rates” below. The legislation in all three jurisdictions allows the incumbent electric utilities an opportunity to recover stranded costs as defined by each state regulatory body.

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. Capped rates extend until July 1, 2007, 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. Legislation currently under consideration would extend capped rates in Virginia through December 31, 2010. These capped rates are then unbundled, or itemized, into power, transmission and distribution components and, in the case of Virginia and Maryland, a competitive transition charge. Our member distribution cooperatives located in Virginia have the ability to pass through to their consumers changes in energy costs even while under capped rates. Our ability to charge our member distribution cooperatives located in Delaware and Maryland is not impaired by these capped rates, even if there is no adjustment to the capped rates for increases in energy costs. 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.

By January 1, 2004, customers accounting for approximately 99.7% of our capacity requirements in 2003 were 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 2003.

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, Delaware and Maryland also may exclusively provide metering and most billing services to all customers located in their certificated service territories.

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 compared to the variable costs to operate these facilities. 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 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 2004. 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, we have 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” in Item 7A. 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.

In 2001, we entered into a supplemental indenture to the Indenture which contains provisions which, if they become effective, will amend and restate the Indenture to release its lien on our property. This amended and restated indenture (the “Restated Indenture”) will become effective when all obligations under the Indenture issued prior to September 1, 2001, cease to be outstanding or when the holders of those obligations consent to the effectiveness of the Restated Indenture. We have $1 million of obligations issued under the Indenture prior to September 1, 2001 the holders of which have not consented to the effectiveness of the Restated Indenture. Following December 1, 2003, we have the ability to redeem these obligations on any subsequent June 1 or December 1, following appropriate notice to the holders of those obligations. The amendment and restatement will not occur, however, if, immediately afterwards, an event of default exists under the Indenture or an event of default would occur. The release of a subordinated mortgage on our interest in Clover Unit 2 also is to be obtained prior to the amendment and restatement. After the date the Restated Indenture becomes effective, the obligations outstanding under the Restated Indenture will be unsecured general obligations, ranking equally and ratably with all of our other unsecured and unsubordinated obligations.

Just as the Indenture currently provides, the Restated Indenture would require us 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, subject to any necessary regulatory or judicial approval. Margins for interest under the Restated Indenture are calculated in the same manner as under the current Indenture. Interest charges under the Restated Indenture equal interest charges (other than capitalized interest) related to 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 expense or premium on issuance, but excluding the interest charges on indebtedness attributed to any capitalized lease or similar agreement.

In January 2003, the Financial Accounting Standards Board issued Interpretation No. 46, “Consolidation of Variable Interest Entities, an Interpretation of Accounting Research Bulletin No. 51” (the “Interpretation”). The Interpretation requires the consolidation of entities in which an enterprise absorbs a majority of the entity’s expected losses, receives a majority of the entity’s expected residual returns, or both, as a result of ownership, contractual or other financial interests in the entity. Currently, entities are generally consolidated by an enterprise when it has a controlling financial interest through ownership of a majority voting interest in the entity. For new entities created after February 1, 2003, the Interpretation is effective immediately; this new interpretation is effective for us by the end of 2004 for existing entities. We are continuing to evaluate the impact of applying this new statement and we believe that it will not have a material impact on our financial position, results of operations, or cash flow.

In May 2003, the Financial Accounting Standards Board issued SFAS No. 150, “Accounting for Certain Financial Instruments with Characteristics of both Liabilities and Equity.” SFAS No. 150 establishes standards for how an issuer classifies and measures certain financial instruments with characteristics of both liabilities and equity. SFAS No. 150 requires that an issuer classify a financial instrument that is within the scope of SFAS No. 150 as a liability (or an asset in some circumstances), which previously may have been classified as equity. This statement did not have an effect on the classification of Patronage Capital in our Consolidated Balance Sheet because any distributions of Patronage Capital are subject to the discretion of our board of directors and the restrictions contained in the Indenture.

On February 10, 2004, our board of directors approved a decrease in the demand component of our formulary rate of approximately 7.0%, effective April 1, 2004. This decrease is due primarily to lower capacity costs in our purchase power agreements. In addition, on February 10, 2004, our board of directors approved a change to our fuel factor adjustment rate, which resulted in a decrease to our total energy rate (including our base energy rate and our fuel factor adjustment rate) of approximately 8.5% effective January 1, 2004. The decrease is due to lower 2004 budgeted energy costs and the application of a portion of the over-collected amount from 2003 against the fuel factor adjustment rate.

The operation of our business exposes us to several common market risks, including changes in interest rates and equity and market prices. We are exposed to market price risk by purchasing power and natural gas in the market to supply a portion of the power requirements of our member distribution cooperatives. In addition, we are exposed to a limited amount of interest rate or equity price risk.

We are exposed to market price risk by purchasing power in the market to supply the power requirements of our member distribution cooperatives in excess of our entitlement to the output of our generating facilities. See “Management’s Discussion and Analysis of Financial Condition and Results of Operations—Future Issues—Reliance on Market Purchases of Energy” in Item 7. In addition, the purchase of fuel to operate our generating facilities also exposes us to market price risk.

As an example of our level of exposure to market price risk, a 10% increase in the purchase price of our unhedged power, natural gas and coal purchases would have increased these expenses by approximately $20.0 million or 4.0% of total operating expenses in 2003. Conversely, a 10% decrease in these purchases would have decreased expenses by approximately $20.0 million. This calculation assumes generation and purchases consistent with historical performance and applies the 10% increase or decrease only to purchases not hedged for 2003.

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

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.

We also are subject to market price risk relating to purchases of fuel for North Anna and Clover. We manage these risks indirectly through our participation in the management arrangements for these facilities. Virginia Power, as operator of these facilities, has the direct authority and responsibility to procure nuclear fuel and coal for North Anna and Clover, respectively.

We understand that Virginia Power’s procurement strategy for nuclear fuel includes both spot purchases and long-term contracts and is constantly under review by various fuel procurement personnel and Virginia Power management. Virginia Power continually evaluates worldwide market conditions to ensure a range of supply options at reasonable prices. See “Business—Fuel Supply—Nuclear” in Item 1.

Virginia Power has advised us that its Virginia Power’s coal procurement policy for the Clover facility is to secure the bulk of its requirements under long-term contracts, with specific contract target percentages fluctuating, based on prevailing market conditions. The majority of the coal supplied to Clover is delivered under long-term contracts. Generally, on a quarterly basis, Virginia Power has advised us that it evaluates the specific terms offered by various coal suppliers to determine the optimal mix of long-term and spot market purchases, and subsequently enters purchase agreements to accomplish the desired mix. See “Business—Fuel Supply—Coal” in Item 1.

In 2003, all of our outstanding long-term indebtedness accrued interest at fixed rates, except for a $6.8 million promissory note owed to Virginia Power which relates to the loan to us of a portion of the proceeds of a tax-exempt debt financing. A 2% rise in interest rates would result in our paying Virginia Power approximately $135,000 of additional interest per year.

We also have $230.0 million of committed available lines of credit and $50.0 million available under a revolving credit agreement. See Item 7, “Management’s Discussion and Analysis of Financial Condition and Results of Operations – Liquidity and Capital Resources.” Any amounts we borrow under these facilities will accrue interest at a variable rate. During 2003, no amounts were outstanding under any of these facilities.

We are exposed to price fluctuations in equity markets with respect to some of our investments. At December 31, 2003, our equity investments totaled approximately $39.0 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 have made periodic deposits to a trust fund so that the fund balance will cover the estimated cost to decommission North Anna at the time of decommissioning. At December 31, 2003, these funds were invested primarily in equity securities and corporate obligations. See “Management’s Discussion and Analysis of Financial Condition and Results of Operations—Critical Accounting Policies—Accounting for Decommissioning Costs” in Item 7. 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 a regulatory asset until realized.

Credit risk is defined as the potential loss that we could incur as a result of non-payment or non-performance by a counterparty. We attempt to measure and monitor the amount of our credit risk principally in order to maintain an acceptable level of credit risk. We are exposed to credit risk through our power and fuel purchases and sales.

In recent years, events in the energy industry have resulted in the deterioration of the credit of many industry participants. In light of these events and the evolving challenges to our industry, we actively manage our credit risk. Our internal risk management committee has the overall responsibility to review and manage our credit risk. We have adopted a Credit Risk Policy that establishes the basis for determining counterparty credit standards and processes to determine credit limits. Through our relationship with APM, we obtain information and assistance to enable us to manage our credit risk. If required by our credit standards and limits, we require counterparties to provide collateral in the form of letters of credit, parent guarantees or other collateral in the future upon the occurrence of specified events. Our risk management committee monitors our credit exposure on a regular basis. Formal counterparty credit reviews are performed at least annually and informal reviews are performed on an ongoing basis. At December 31, 2003, we did not have requirements for any collateral from counterparties involved in our power trading activities.

We have audited the accompanying consolidated balance sheets of Old Dominion Electric Cooperative as of December 31, 2003 and 2002, and the related consolidated statements of revenues, expenses and patronage capital, comprehensive income, and cash flows for each of the three years in the period ended December 31, 2003. 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, 2003, and 2002, and the consolidated results of its operations and its cash flows for each of the three years in the period ended December 31, 2003, in conformity with accounting principles generally accepted in the United States.

As discussed in Note 3 to the consolidated financial statements, the Cooperative changed its method of accounting for asset retirement obligations effective January 1, 2003, to comply with the provisions of Statement of Financial Accounting Standards No. 143.

As discussed in Note 1 to the consolidated financial statements, the Cooperative changed its method of accounting for certain power purchase contracts effective April 1, 2002.

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

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

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

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. Our Class A members are twelve customer-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”), a corporation owned by our member distribution cooperatives. Our board of directors is composed of two representatives from each of the member distribution cooperatives and one representative from TEC. 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 December 23, 2003.

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 is stated at original cost when first placed in service. Such cost includes contract work, direct labor and materials, allocable overhead, an allowance for borrowed funds used during construction and asset retirement costs. 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 is based on the straight-line method at rates that are designed to amortize the original cost of properties over their respective 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”) and the Clover Power Station (“Clover”) were approximately 1.5%, 3.0%, and 3.1% in 2003, 2002 and 2001, respectively, for North Anna and were approximately 2.7% for each of 2003, 2002, and 2001 for Clover. In 2003, the operating licenses for North Anna were extended for an additional 20 years. The license extension resulted in a reduction to depreciation expense of $3.8 million for 2003.

In accordance with our Strategic Plan Initiative, we recorded $18.5 million of accelerated depreciation on our generation assets in 2001. We ceased recording accelerated depreciation on our generation assets under our Strategic Plan Initiative effective June 1, 2001. See Note 15—Commitments and Contingencies—to the Consolidated Financial Statements.

Nuclear fuel is amortized on a unit of production basis sufficient to fully amortize the cost of fuel over the estimated service life and is recorded in fuel expense.

In accordance with 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. Virginia Power will continue to safely manage its spent nuclear fuel until the DOE begins accepting the spent nuclear fuel. In January 2004, Virginia Power filed a lawsuit seeing recovery damages for breech of the standard contract due to the DOE’s delay in accepting spent nuclear fuel for North Anna.

Allowance for borrowed funds used during construction is defined as the net cost of borrowed funds used for construction purposes during the construction period and a reasonable rate on other funds when so used. We capitalize interest on borrowings for significant construction projects. Interest capitalized in 2003, 2002, and 2001, was $14.5 million, $13.5 million, and $1.0 million, respectively.

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, no provisions for income taxes have been reflected in the accompanying consolidated financial statements.

Our operating revenues are derived from sales to our members and non-members. We sell energy to our Class A members 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. At December 31, 2003, 2002, and 2001, sales to our member distribution cooperatives were $511.5 million, $488.9 million, and $476.6 million, respectively. See Note 5—Wholesale Power Contracts—to the Consolidated Financial Statements.

We sell excess purchased energy and excess generated energy from our combustion turbine facilities, if any, to our Class B member under FERC market-based rate authority. In 2003 and 2002, sales to our Class B member were $14.3 million and $2.6 million respectively. There were no sales to our Class B member during 2001.

We also sell excess purchased energy and excess generated energy from Clover to non-members. Excess purchased energy that is not sold to our Class B member is sold to the PJM 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 (the “Clover Agreements”). At December 31, 2003, 2002, and 2001, energy sales to non-members were $9.8 million, $3.1 million, and $10.7 million, respectively.

We account for certain revenues and expenses as a rate regulated entity in accordance with SFAS No. 71, “Accounting for the Effects of Certain Types of Regulation.” SFAS No. 71 which allows certain revenues and expenses to be deferred at the discretion of our board of directors, pursuant to their budgetary and rate setting authority, if it is probable that such amounts will be refunded or recovered through our formulary rate in future years. Regulatory assets represent certain costs that are expected to be recovered from our member distribution cooperatives based on rate action by our board of directors in accordance with our formulary rate. Regulatory liabilities represent certain probable future reductions in revenues associated with amounts that are to be refunded to our member distribution cooperatives based on rate action by our board of directors in accordance with our formulary rate. Certain regulatory assets are included in deferred charges. Certain regulatory liabilities are included in deferred credits and other liabilities. Deferred energy, which can be either a regulatory asset or a regulatory liability, (see Note 1—Deferred Energy—to the Consolidated Financial Statements) and deferred revenue, a regulatory liability, are included in current assets or current liabilities. The regulatory assets and liabilities will be recognized as expenses or as a reduction in expenses, concurrent with their recovery through rates.

Capitalized costs associated with the issuance of debt totaled $13.7 million and $11.9 million at December 31, 2003 and 2002, respectively and are included in deferred charges – other. These costs are being amortized using the effective interest method over the life of the respective debt issues, and are included in interest charges, net.

Deferred credits and other liabilities—other, includes gains on long-term lease transactions (see Note 6— Long-Term Lease Transactions—to the Consolidated Financial Statements), DOE decontamination and decommissioning liability, derivative liability associated with SFAS No. 133, “Accounting For Derivative Instruments and Hedging Activities,” and liabilities associated with benefit plans for certain executives. Gains on long-term lease transactions totaled $42.1 million and $44.8 million at December 31, 2003 and 2002, respectively. These gains are being amortized into income ratably over the terms of the operating leases as a reduction to depreciation, amortization and decommissioning expense. DOE decontamination and decommissioning liability totaled $0.9 million and $1.3 million at December 31, 2003, and 2002, respectively. We did not have a derivative liability at December 31, 2003. Deferred credit derivative liability totaled $8.2 million at December 31, 2002. Liabilities associated with benefit plans for certain executives were $0.2 million at both December 31, 2003 and 2002, respectively.

We use the deferral method of accounting to recognize differences between our energy expenses and our energy revenues collected from our member distribution cooperatives. Our deferred energy balance represents the net accumulation of any previous under- or over-collection of energy costs. At December 31, 2003, and December 31, 2002, we had a deferred energy credit of $13.6 million and $3.0 million, respectively. These deferred energy credit balances represent an over-collection of costs. Deferred energy credits are refunded to our member distribution cooperatives in the succeeding year in accordance with the tariffs then in effect.

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 a regulatory liability and a regulatory asset 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. See Note 7—Investments—to the Consolidated Financial Statements. Other investments are recorded at cost, which approximates market value.

We primarily purchase power under both long-term and short-term forward physical delivery contracts to supply power to our member distribution cooperatives under “all requirements” wholesale power contracts. In 2003, 2002, and 2001, energy purchase contracts supplied approximately 51.7%, 53.9%, and 49.9%, respectively, of our energy requirements. These forward purchase contracts meet the accounting definition of a derivative; however, on a majority of the forward purchase derivative contracts, we apply the normal purchases/normal sales accounting treatment. Therefore, we record a liability and purchase power expense when the power under the forward physical delivery contract is delivered.

For forward purchase contracts that do not meet the qualifying criteria for normal purchases/normal sales accounting treatment, we elect cash flow hedge accounting, where applicable. Under cash flow hedge accounting, the fair value of the contract is recorded as a current or long-term derivative asset or liability. Subsequent changes in the fair value of the derivative assets and liabilities are recorded on a net basis in other comprehensive income and subsequently reclassified as purchase power expense in our Consolidated Statements of Revenues, Expenses and Patronage Capital as the power is delivered and/or the contract settles. Changes in the fair value of derivatives that are not designated as accounting hedges are recorded in earnings.

In December 2001, certain interpretative guidance related to SFAS No. 133 was revised. This revised interpretive guidance became effective for us beginning April 1, 2002. Under the new guidance, certain energy option contracts, which previously qualified for the normal purchases/normal sales exception under SFAS No. 133, were required to be recorded at market value. As a result, we recorded a cumulative effect of accounting change adjustment as of April 1, 2002, of $15.9 million net unrealized loss. The cumulative effect adjustment was recorded to comprehensive income as we designated these contracts as cash flow hedges of forecasted transactions. Prior to April 1, 2002, energy option premiums were included in deferred charges and expenses through purchased power as the options expired. During 2003, 2002, and 2001, we expensed option premiums totaling $2.7 million, $7.8 million, and $0.9 million, respectively, as purchased power expense. At December 31, 2002, we had a net unrealized loss in accumulated other comprehensive income of approximately $10.9 million associated with the effective portion of the change in fair value of the option contracts designated as cash flow hedges.

During 2003, we reclassified $10.9 million of net unrealized losses from accumulated other comprehensive income to operating expense. The effect of the amounts being reclassified to expense were offset by the recognition of the hedged transactions. There was no hedge ineffectiveness during the years ended December 31, 2003, or December 31, 2002.

We have established an internal Risk Management Committee to monitor the compliance with our established risk management policies.

We are exposed to market risks associated with commodity prices for energy and fuel related to our business operations. Through our relationship with Aces Power Marketing LLC (“APM”), we have formulated policies and procedures to manage the risks associated with these price fluctuations. We manage our exposure to these fluctuations in energy and fuel market prices by entering into forward purchase contracts to hedge the variability of cash flows associated with changes in market prices of energy.

We have operating procedures in place to help ensure that proper internal controls are maintained regarding the use of derivatives.

We are also exposed to credit risk in our business operations. We have adopted a Credit Risk Policy that establishes the basis for determining counterparty credit standards and processes to determine credit limits. Our risk management committee monitors credit exposure on a regular basis. Formal counterparty credit reviews are performed at least annually and informal reviews are performed on an ongoing basis. At December 31, 2003 and 2002, we did not have requirements for any collateral from counterparties involved in our power trading activities.

We are organized and operate as a cooperative. Patronage capital represents our retained net margins, which have been allocated to our members 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 seventeen supplemental indentures thereto and hereinafter referred to as the “Indenture”).

Financial instruments that potentially subject us to concentrations of credit risk consist of cash equivalents, investments, and receivables arising from sales to our members and non-members. We place our temporary cash investments with high credit quality financial institutions and invest in debt securities with high credit standards as required by our board of directors. Cash and cash equivalents balances may exceed FDIC insurance limits. Concentrations of credit risk with respect to receivables arising from sales to our member distribution cooperatives are limited due to the large member consumer base that represents our member distribution cooperatives’ accounts receivable. Receivables from our member distribution cooperatives at December 31, 2003 and 2002, were $52.9 million and $46.0 million, respectively.

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

This statement did not have an effect on the classification of Patronage Capital in our Consolidated Balance Sheet because any distributions of Patronage Capital are subject to the discretion of our board of directors and the restrictions contained in our Indenture.

Certain reclassifications have been made to the prior years’ consolidated financial statements to conform to the current year’s presentation.

We hold a 50% undivided ownership interest in Clover, a two-unit, 882 MW (net capacity rating) coal-fired electric 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 fund these items. Our portion of assets, liabilities, and operating expenses associated with Clover are included in our consolidated financial statements. At December 31, 2003 and 2002, we had an outstanding accounts payable balance of $(0.9) million and $2.0 million, respectively, due to Virginia Power for operation, maintenance, and capital investment at the Clover facility.

We have an 11.6% undivided ownership interest in North Anna, a two-unit, 1,842 MW (net capacity rating) nuclear power 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 fund these items. Our portion of assets, liabilities, and operating expenses associated with North Anna are included in our consolidated financial statements. At December 31, 2003 and 2002, we had an outstanding accounts payable balance of $2.1 million and $5.2 million, respectively, due to Virginia Power for operation, maintenance, and capital investment at the North Anna facility

Our investment in jointly owned generating facilities at December 31, 2003, excluding accelerated depreciation of $127.2 million (see Note 15—Commitments and Contingencies—to the Consolidated Financial Statements), was as follows:

Projected capital expenditures for North Anna for 2004 through 2006 are $20.4 million, $18.3 million and $17.3 million, respectively. Projected capital expenditures for Clover for 2004 through 2006 are $5.2 million, $1.1 million and $1.3 million, respectively.

We adopted SFAS No. 143 “Accounting for Asset Retirement Obligations” effective January 1, 2003. SFAS No. 143 requires legal obligations associated with the retirement of long-lived assets to be recognized at fair value when incurred and capitalized as part 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. SFAS No. 143 requires that any transition adjustment determined at adoption be recognized as a cumulative effect of change in accounting principle.

In the absence of quoted market prices, we determined fair value by using present value techniques, in which estimates of future cash flows associated with retirement activities are discounted using a credit adjusted risk free rate. Our estimated liability could change significantly if actual costs vary from assumptions or if governmental regulations change significantly.

SFAS No. 143 applies to the decommissioning of North Anna, certain asset retirement obligations at Clover, as well as certain asset retirement obligations at our Rock Springs, Louisa, and Marsh Run combustion turbine facilities and our distributed generation facilities. At December 31, 2002, we had recorded a liability for the decommissioning of North Anna of $56.7 million, which equaled the balance in our nuclear decommissioning trust fund. At January 1, 2003, our liability for the decommissioning of North Anna as well as our liabilities associated with Clover and the diesel facilities as calculated under SFAS No. 143 were $39.0 million. This liability was calculated using the present value of estimated future cash flows. We also recorded plant assets totaling $12.3 million and offsetting accumulated depreciation of $4.4 million. The majority, $28.8 million, of the difference between what was recorded prior to January 1, 2003, and the net amount of what we recorded under SFAS No. 143 has been deferred as a regulatory liability. The remainder, $3.3 million, represents the cumulative effect of change in accounting principle.

The following represents changes in our Asset Retirement Obligations for the year ended December 31, 2003:

Our net margin for the twelve months ended December 31, 2001 and 2002, would not have differed if this statement had been adopted as of January 1, 2001.

As discussed in Note 1—Depreciation—to the Consolidated Financial Statements, the cash flow estimates for North Anna’s asset retirement obligations were based upon the recent 20-year life extension. Given the life extension, the level of decommissioning trust fund currently appears to be adequate to fund North Anna’s asset retirement obligations and no additional funding is currently required. Therefore, with the approval by the Federal Energy Regulatory Commission, we ceased collection of decommissioning expense in August 2003. As we are not currently collecting decommissioning expense in our rates, we are deferring as part of our SFAS No. 143 regulatory liability (See Note 8—Regulatory Assets and Liabilities—to the Consolidated Financial Statements) the difference between the earnings on the decommissioning trust fund and the total asset retirement obligation related depreciation and accretion expense for North Anna.

In 2003, 2002, and 2001, our owned generating facilities together furnished approximately 48.3%, 46.1%, and 50.1%, respectively, of our energy requirements. The remaining needs were satisfied through purchase power agreements from other power suppliers and purchases of energy in the forward, short-term and spot markets.

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. Under the I&O Agreement, we did not purchase any of our supplemental capacity requirements from Virginia Power in 2003. We continue to purchase our peaking capacity requirements from Virginia Power through 2003.

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. Previously, the price of energy we paid for the supplemental portion of our Virginia Power purchases equaled an average price of predetermined Virginia Power owned combustion turbine and combined cycle facilities 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.

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.

We have an agreement with the Public Service Electric & Gas (“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, 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. See Note 15—Commitments and Contingencies to the Consolidated Financial Statements.

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. The capacity and energy requirements of our member distribution cooperatives in Allegheny Power Resources’ service area in mainland Virginia for 2002 and the capacity needs up to 25 MW through May 2005.

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 to supply these purchase power needs from January 1, 2003 to May 31, 2008. Transmission service, with respect to energy purchased under this agreement, is supplied under PJM’s transmission tariff for the Allegheny Power Resource’s service area power requirements, and the American Electric Power-Virginia open access transmission tariff for power requirements served in its area.

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.

Our power purchase agreements contain certain firm capacity and minimum energy requirements. As of December 31, 2003, our minimum purchase commitments under the various agreements, without regard to capacity reductions or cost adjustments, were as follows:

Due to transmission import limitations into the Delmarva Peninsula, we paid approximately $7.8 million in congestion costs in 2003. These costs were incurred under the PJM Independent System Operator rules when higher cost generation must be run due to transmission constraints. The congestion charges were partially offset by credits of our fixed transmission rights and our auction revenue rights. Net congestion costs for 2003, 2002, and 2001 were approximately $2.6 million, $8.3 million and $11.6 million, respectively.

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 and beyond 2028 unless either party gives the other at least three years notice of termination. Each such contract provides that we shall provide all of the power that the member distribution cooperative requires for the operation of its system, with limited exceptions, to the extent that we have the power and facilities available. Each member 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 which has been accepted by 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, 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 our rates to recover actual, prudently incurred costs, whether they increase or decrease, without further application to or acceptance by FERC except for the adjustment for the collection of decommissioning costs. 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. We have a Margin Stabilization Plan that allows us to review our actual capacity-related cost of service and capacity revenues as of year end and adjust revenues from our member distribution cooperatives to meet our financial coverage requirements and accumulate additional equity as required by our board of directors. 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 calendar year. Each quarter we adjust revenues and accounts payable—members to accounts receivable, as appropriate, to reflect that adjustment. In 2003 and 2002, under our Margin Stabilization Plan, we reduced operating revenues from power sales and increased accounts payable—members by $3.2 million and $3.6 million, respectively, and increased accounts payable—members by the same amounts. There was no adjustment to operating revenues from power sales under our Margin Stabilization Plan in 2001.

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

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, as a reduction to operating expenses.

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, as a reduction to operating expenses.

Unrealized gains on these long-term lease transactions totaled $42.1 million and $44.8 million at December 31, 2003 and December 31, 2002, respectively.

Contractual maturities of debt securities at December 31, 2003, were as follows:

Realized gains and losses on the sale of securities are determined on the basis of specific identification. Gross realized gains on the sale of available for sale securities in 2003 and 2002, were $0.5 million, and $0.3 million, respectively. Gross realized losses on the sale of available for sale securities in 2002 were $0.4 million. We did not have any realized losses in 2003.

In accordance with SFAS No. 71, we record assets and liabilities that result from our ratemaking. Our regulatory assets and liabilities at December 31, 2003 and 2002, were as follows:

The regulatory assets will be recognized as expenses concurrent with their recovery through rates and the regulatory liabilities will be recognized as a reduction to expenses concurrent with their refund through rates.

Regulatory liabilities included in deferred credits and other liabilities are detailed as follows:

During 2003 and 2002, we purchased and redeemed approximately $130.9 million and $229.8 million, respectively, of our First Mortgage Bonds, 1993 Series A and 1992 Series A. The transactions resulted in a net loss of approximately $10.7 million in 2003 and $21.1 million in 2002, 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, 2003, deferred gains and losses on reacquired debt totaled a net loss of approximately $41.0 million.

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

The aggregate fair value of long-term debt was $990.4 million and $881.6 million at December 31, 2003 and 2002, 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.

We maintain committed lines of credit to cover short-term funding needs. Currently, we have short-term variable rate lines of credit in the aggregate amount of $230.0 million. Of this amount, $110.0 million is available for general working capital purposes and $120.0 million is available for capital expenditures related to our generating facilities. At December 31, 2003 and 2002, we had no short-term borrowings outstanding under any of these arrangements. We had no outstanding letters of credit as of December 31, 2003, and we had outstanding letters of credit totaling $5.1 million at December 31, 2002. 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.

We maintain a policy which allows our member distribution cooperatives to pre-pay or extend payment on their monthly power bills. Under this policy, we pay interest on early payment balances at a blended investment and outside short-term borrowing rate, and we charge interest on extended payment balances at a blended prepayment and outside short-term borrowing rate. Amounts advanced by our member distribution cooperatives are included in accounts payable—members and totaled $47.8 million and $59.9 million at December 31, 2003 and 2002, respectively. Amounts extended by our member distribution cooperatives are included in receivables and totaled $4.0 million and $1.6 million at December 31, 2003 and 2002, respectively.

Substantially all of our employees participate in the National Rural Electric Cooperative Association (“NRECA”) Retirement and Security Program, a noncontributory, defined benefit multiple 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 2003, 2002, and 2001, was $644,000, $542,000, and $479,000, 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 100% or $12,000, whichever is less, of their salary withheld on a pretax 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 $96,000, $85,000, and $79,000, in 2003, 2002, and 2001, respectively.

We adopted a plan on February 12, 2002, 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 two

officers. 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 each agreement is $408,000 and vests in equal amounts on March 1, 2002, and each January 1st thereafter until 2007 for one officer and 2005 for the other officer. 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. At December 31, 2003, the total vested option value for the plan was $340,000. Neither officer can exercise his rights under the agreement unless he has attained retirement age as identified in our retirement policy (currently age 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.

We provide no other significant post-retirement 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 post-retirement benefits of Virginia Power employees whose costs are allocated to those stations. These post-retirement benefits other than pensions resulted in an increase in expense to us of approximately $0.9 million, $0.7 million, and $0.8 million in 2003, 2002, and 2001, respectively. We are recovering through our rates the expense as it is billed by Virginia Power.

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 provides the public up to $10.9 billion of protection per nuclear incident via obligations required of owners of nuclear power plants. The Price-Anderson Act Amendment of 1988 allows for an inflationary provision adjustment every five years. Virginia Power has purchased $300 million of coverage from 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 $101.0 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. The Price-Anderson expired August 1, 2002, but operating nuclear reactors continue to be covered by the law. Congress is currently holding hearings to reauthorize the legislation. The expiration of the Price Anderson Act has no impact on existing nuclear license holders.

Virginia Power’s current level of property insurance coverage, $2.55 billion for North Anna, exceeds the Nuclear Regulatory Commission (“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 nuclear property insurance is provided to Virginia Power and us, jointly, 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 $44.0 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 $30.7 million at December 31, 2003.

We own 50% of Regional Headquarters, Inc. (“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 2003, 2002, and 2001, our rent expense was $375,000, $285,000, and $296,000, respectively.

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

Cash paid for interest, net of allowance for funds used during construction, in 2003, 2002, and 2001, was $57.2 million, $50.9 million, and $40.3 million, respectively.

We have included an unrealized deferred gain of approximately $5.6 million as a regulatory liability in 2003. In 2002, we have included an unrealized deferred loss of approximately $3.5 million in the decommissioning reserve.

In December 1992, we entered into an agreement with PSE&G to purchase capacity, reserves and associated energy, through 2004. In 1997, we filed a complaint with FERC to modify the transmission charges we pay PSE&G under the agreement to reflect the restructuring of PJM into an independent system operator. In 1998, FERC directed PSE&G to remove all transmission costs from its charges to us, effective April 1, 1998, in a general order addressing several cases relating to the restructuring of PJM (the “PJM Order”). PSE&G complied with the PJM Order but appealed to the United States Court of Appeals for the District of Columbia Circuit. In July 2002, the Court of Appeals vacated the PJM Order and remanded the cases related to the PJM Order to FERC for further consideration. Later in 2002, FERC reversed the PJM Order. FERC noted that there was no evidence in the PJM Order proceedings to demonstrate any unduly discriminatory effects of our contract with PSE&G, but stated that we could present evidence specific to our contract.

In order to prevent the index change sought by Norfolk Southern, we and Virginia Power filed suit against Norfolk Southern on November 26, 2003, in the Circuit Court of Halifax County, Virginia, requesting specific

performance in the form of an injunction declaring that Norfolk Southern cannot change the initial index rate and, in the alternative, that the court enter a declaratory judgment confirming the applicability of the initial index to the Agreement. On January 15, 2004, Norfolk Southern filed an answer and counterclaim (for declaratory judgment, specific performance and damages) and a pleading under which Virginia law alleges that we and Virginia Power have failed to state a claim. A procedural schedule in the proceeding has not been set. We continue to work together with Virginia Power, to prevent Norfolk Southern from depriving us of the economic benefits of the Agreement. If it is ultimately determined that we owe any amounts to Norfolk Southern, such amounts are not expected to have a material impact on our financial position, results of operations, or cash flow due to our ability to collect such amounts through rates.

Other than the FERC proceeding, and related litigation, regarding PSE&G transmission charges, the proceedings with Norfolk Southern, and 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, financial condition, or cash flows, there is no other litigation pending or threatened against us.

The most important environmental law affecting our operations is the Clean Air Act. The Clean Air Act requires, among other things, that owners and operators of fossil fuel-fired power stations limit emissions of sulfur dioxide (“SO₂”) and nitrogen oxides (“NO_x”). Under the Clean Air Act’s Acid Rain Program, each of our fossil fuel-fired plants must obtain SO₂ allowances equal to the number of tons of SO₂ they emit into the atmosphere annually. As an existing facility, Clover receives an annual allocation of SO₂allowances at no cost based upon its baseline operations. Newer facilities, including Rock Springs, Louisa and Marsh Run, need to obtain allowances, but because they are gas-fired, the numbers of SO₂allowances they must obtain are expected to be minimal and we anticipate will be supplied from excess SO₂ allowances allocated to Clover. Future changes in the Acid Rain Program, including increases in the cost of SO₂allowances or the ratio of allowances to emissions, could increase our costs of operation.

Rock Springs, Louisa and Marsh Run will each emit significant amounts of NO_x. As new sources, they were designed with advanced technologies that reduce the formation of NO_x emissions, and will be required to meet stringent NO_x emission limits. Each will be required to obtain allowances for every ton of NO_x they emit during the ozone season (May through September) beginning in 2003 for Rock Springs and beginning in 2004 for Louisa and Marsh Run. When designing their respective programs, Maryland and Virginia both set aside a number of NO_x allowances to be allocated to new sources based on their emissions rates. NO_x emission allowances that are not received from the new source set aside pools will be purchased in the market for the operation of all three combustion turbine facilities. We project that we will be able to obtain sufficient quantities of NO_x 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 January 2004, the Environmental Protection Agency (“EPA”) issued a proposed rule intended to reduce interstate transport of fine particulate matter and ozone (Interstate Air Quality Rule – “IAQR”). If promulgated as proposed, the rule would require that the states identified in the rule, which include Maryland and Virginia, further reduce SO₂ and NO_x emissions, with Phase I of the reductions beginning in 2010 and Phase II in 2015. The proposal suggests that, in order to achieve the goals in the proposed rule, states regulate NO_x and SO₂ emissions from power plants under a cap and trade program. At this point, it is unclear whether the requirements under the new rule would be met through the installation of additional pollution control equipment or the purchase of additional allowances. This new rule will require NO_x reductions year-round not just during the ozone season. We are still evaluating the proposal and the best approach for us to meet these new requirements. The Clean Air Act also directs the EPA to limit the emissions of hazardous air pollutants (“HAPs”). In January 2004, the EPA issued two alternative proposals for the regulation of mercury emissions from coal-fired power plants. One alternative would create an allowance trading program for mercury emissions (with decreasing caps in 2010 and 2018). The other alternative would require the installation of state-of-the-art pollution control equipment known as “maximum achievable control technology” (“MACT”). At this point, the ultimate outcome of the rulemaking process is unclear. Based on the proposals, most coal-fired facilities, including Clover, would probably be subject to such regulation. Based on the proposals, however, and the type of coal used to fuel Clover, we do not anticipate installation of additional equipment will be required for mercury reduction.

expense, operations and maintenance expense, and depreciation, amortization and decommissioning expense. We anticipate expenses to be approximately $7.3 million in 2004 in connection with environmental protection and monitoring activities, including depreciation.

Under several of the nuclear insurance policies procured by Virginia Power 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 12—Insurance— to the Consolidated Financial Statements.

Our projected capital expenditures for 2004, 2005, and 2006 are $114.6 million, $20.5 million, and $19.7 million, respectively. In addition to the development and construction of our combustion turbine facilities, our future projected capital expenditures include additions to the solid waste and emissions reduction facilities at Clover and a portion of the cost of the nuclear fuel purchased for North Anna, and a turbine upgrade project for North Anna. Other capital expenditures include the purchase of computer hardware, and the purchase and development of computer software.

A summary of the quarterly results of operations for the years 2003 and 2002 follow. Amounts reflect all adjustments, consisting of only normal recurring accruals, necessary in the opinion of management for a fair statement of the results for the interim periods. Results for the interim periods may fluctuate as a result of weather conditions, changes in rates and other factors.

ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS AND FINANCIAL DISCLOSURE

Within 90 days of this report, our management, including the Chief Executive Officer and Chief Financial Officer, conducted an evaluation of the effectiveness of our disclosure controls and procedures as defined in Rules 13a-14(c) and 15d-14(c) under the Securities Exchange Act of 1934. Based upon that evaluation, the Chief Executive Officer and Chief Financial Officer concluded that our disclosure controls and procedures are effective in ensuring that all material information required to be filed in this report has been made known to them in a timely matter. We have established a Disclosure Assessment Committee comprised of members from senior and middle management to assist in this evaluation.

There have been no significant changes in our internal controls or in other factors that could significantly affect such controls.

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. Each of our twelve 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. The candidates for director are elected to our board of directors by voting delegates from each of our members elected by each member’s local board of directors. Each elected candidate is authorized to represent such member for a renewable term of one year at our annual meeting. This election process is repeated annually. 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, is listed below.

E. Paul Bienvenue (64). President and Chief Executive Officer of Delaware Electric Cooperative since 1998. Mr. Bienvenue also served as General Manager from 1981 to 1998. Mr. Bienvenue has been a Director of Old Dominion since 1981.

Dick D. Bowman (75). President of Bowman Brothers, Inc., a farm equipment retailer since 1976. 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 (58). President and Chief Executive Officer of Mecklenburg Electric Cooperative and Mecklenburg Communications Services, Inc. since 2001. Mr. Bowman also served as Executive Vice President and General Manager of Mecklenburg Electric Cooperative from 1981 to 2001. Mr. Bowman has been a Director of Old Dominion since 1974.

M Dale Bradshaw (50). Chief Executive Officer of Prince George Electric Cooperative since 1995. Mr. Bradshaw has been a Director of Old Dominion since 1995.

Vernon N. Brinkley (57). President and Chief Executive Officer of A&N Electric Cooperative since 2003. Mr. Brinkley also served as President of A&N Electric Cooperative from 1995 to 2003 and served as Executive Vice President and General Manager from 1982 to 1995. Mr. Brinkley has been a Director of Old Dominion since 1982.

Calvin P. Carter (79). Owner of Carter’s Store since 1960 and Carter Stone Co., a stone quarry since 1965. Mr. Carter has served as a member of the Campbell Board of Supervisors since 1979. Mr. Carter has been a Director of Old Dominion since 1991 and a Director of Southside Electric Cooperative since 1972.

Glenn F. Chappell (60). Self-employed farmer since 1961. Mr. Chappell has been a Director of Old Dominion since 1995 and a Director of Prince George Electric Cooperative since 1985.

Carl R. Eason (67). Retired, formerly an electrical supervisor with International Paper from 1957 to 1997. Mr. Eason has been a director of Old Dominion since 2000 and a director of Community Electric Cooperative since 1994.

Kent D. Farmer (46). Chief Executive Officer of Rappahannock Electric Cooperative since 2004. Mr. Farmer also served as Chief Operating Officer of Rappahannock Electric Cooperative from 1999 to 2004. Mr. Farmer has been a Director of Old Dominion since 2004.

Stanley C. Feuerberg (52). President and Chief Executive Officer of Northern Virginia Electric Cooperative since 1992. Mr. Feuerberg has been a Director of Old Dominion since 1992.

William C. Frazier (73). Insurance broker of Associates Insurance Agency, a general insurance company, since 1999. Mr. Frazier has been a Director of Old Dominion since 2003 and a Director of Rappahannock Electric Cooperative since 1981.

Hunter R. Greenlaw, Jr. (58). President of Greenlaw, Edwards & Leake, Inc., a real estate development and general contracting company since 1974. Mr. Greenlaw has been a Director of Old Dominion since 1991 and a Director of Northern Neck Electric Cooperative since 1979.

Bruce A. Henry (58). Owner and Secretary/Treasurer of Delmarva Builders, Inc., a building contracting company since 1981. Mr. Henry has been a Director of Old Dominion since 1993 and a Director of Delaware Electric Cooperative since 1978.

Wade C. House (51). Vice President/Branch Manager of APAC-Atlantic, Inc., a highway construction company since 1972. Mr. House has been a Director of Old Dominion since 2004, and a Director of Northern Virginia Electric Cooperative since 1993.

Frederick L. Hubbard (63). President and Chief Executive Officer of Choptank Electric Cooperative since 2001. Mr. Hubbard also served as Senior Vice President and Chief Executive Officer from 1991 to 2001. Mr. Hubbard has been a Director of Old Dominion since 1991.

David J. Jones (55). Vice President of Exchange Warehouse, Inc. since 1996 and owner/operator of Big Fork Farms since 1970. Mr. Jones has been a Director of Old Dominion since 1986 and a Director of Mecklenburg Electric Cooperative since 1982.

Bruce M. King (57). General Manager of BARC Electric Cooperative since 2003. Prior to that Mr. King was General Manager of Cherryland Electric Cooperative from 1993 to 2002. Mr. King has been a Director of Old Dominion since 2003.

William M. Leech, Jr. (76). Retired, former self-employed farmer from 1955 to 1988. Mr. Leech has been a Director of Old Dominion since 1977 and a Director of BARC Electric Cooperative since 1970.

M. Larry Longshore (62). 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 from 1973 to 1998. Mr. Longshore has been a Director of Old Dominion since 1998.

James M. Reynolds (56). President of Community Electric Cooperative since 2001. Mr. Reynolds also served as General Manager from 1977 to 2001. Mr. Reynolds has been a Director of Old Dominion since 1977.

Charles R. Rice, Jr. (62). President and Chief Executive Officer of Northern Neck Electric Cooperative since 1998. Mr. Rice also served as General Manager from 1986 to 1998. Mr. Rice 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 (75). Office manager for Tankard Nurseries since 1985. Mr. Tankard has been a Director of Old Dominion since January 1, 2002 and a Director of A&N Electric Cooperative since 1960.

Carl R. Widdowson (65). Self-employed farmer since 1956. Mr. Widdowson has been a Director of Old Dominion since 1987 and a Director of Choptank Electric Cooperative since 1980.

C. Douglas Wine (61). President and Chief Executive Officer of Shenandoah Valley Electric Cooperative since 1995 and General Manager of North River Telephone Cooperative since 1994. Mr. Wine also served as Executive Vice President of Shenandoah Valley Electric Cooperative from 1991 to 1995. Mr. Wine has been a Director of Old Dominion since 1991.

Old Dominion does not currently have an audit committee financial expert. Our board of directors has adopted a process to identify a qualified individual as soon as reasonably possible and, if necessary, change our Articles of Incorporation and Bylaws to accommodate a new outside director.

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

Jackson E. Reasor (51). President and Chief Executive Officer of Old Dominion and the Virginia, Maryland and Delaware Association of Electric Cooperatives (the “VMDA”) (an electric cooperative association which provides services to its members and certain other electric cooperatives) since 1998. 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 (58). Senior Vice President and Chief Financial Officer since March 2004. Mr. Walker also served as our Senior Vice President Accounting and Finance from 2000 to February 2004 and served as our Vice President Accounting and Finance from 1994 until 2000.

Konstantinos N. Kappatos (61). Power Supply Advisor since March 2004. Mr. Kappatos also served as our Senior Vice President Power Supply Planning from 2000 to February 2004, and as Vice President Engineering and Operations from 1994 until 2000.

Gregory W. White (51). Senior Vice President of Power Supply since March 2004. Mr. White served as Senior Vice President Engineering and Operations from April 2002 to February 2004, and served as Senior Vice President Retail and Alliance Management from 2000 to March 2002. Mr. White also served as Vice President Alliance Management in 1999 and Vice President of the VMDA from 1996 until 1999, and interim Vice President of the VMDA from 1995 until 1996.

We have a Code of Ethics which applies to our President and Chief Executive Officer, Senior Vice President and Chief Financial Officer, and Vice President and Controller. A copy of this Code of Ethics is available without charge by sending a written request for the Code of Ethics to Old Dominion Electric Cooperative, Attention Mr. Robert L. Kees, Vice President and Controller, 4201 Dominion Boulevard, Glen Allen, VA 23060.

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 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, 2003.

On November 12, 2002, the VMDA and we entered into a new employment agreement with Jackson E. Reasor, our president and chief executive officer. The agreement is effective November 23, 2002, and has an initial four-year term with a single one-year renewal unless either party gives notice of termination within 30 days prior to the fourth anniversary of the agreement. The agreement provides for an initial annual base salary of $300,000, subject to annual adjustments, eligibility to receive an annual bonus as approved by the board of directors and certain other benefits. The VMDA currently contributes $36,000 annually to us to pay a portion of Mr. Reasor’s base salary. 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 his 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 specified reasons 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.

Effective January 1, 2003, we pay our directors who are not employees of a member a monthly retainer of $1,500 plus $400 per day for any specially called meetings, and $200 per day for participating telephonically for any specially called meeting. All directors are reimbursed for out-of-pocket expenses incurred in attending meetings.

We have elected to participate in the NRECA Retirement and Security Program (the “Plan”), a noncontributory, defined benefit, multiple-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 $205,000 effective January 1, 2004.

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 or her normal retirement date is equal to the product of his or her 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, 2003, years of credited service under the Plan at “normal retirement age” for each of the Named Executives was: Mr. Reasor, 4.08 years; Mr. Walker, 18.92 years; Mr. Kappatos, 18.92 years, and Mr. White 25.22 years.

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 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.

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 each 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. At December 31, 2003, the total vested option value for the plan was $340,000.

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.

The following table presents fees for services provided by Ernst & Young LLP for fiscal 2003 and 2002. All Audit-Related, Tax and Other Fees shown below were pre-approved by the Audit Committee in accordance with its established procedures.

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.

*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 September 10, 2002 (filed as exhibit 3.1 to the Registrant’s Form 8-K, File No. 000-50039, filed on July 25, 2003).

*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 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, including the form of the First Mortgage Bonds, 1993 Series A (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).

*4.3 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).

*4.4 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 including the form of the First Mortgage Bonds, 1996 Series A and 1996 Series B (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).

*4.5 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, including the form of the 2001 Series A Bond (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).

*4.6 Thirteenth Supplemental Indenture, dated as of November 1, 2002, 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, including the form of the 2002 Series A Bond (filed as exhibit 4.14 to Amendment No. 1 to the Registrant’s Form S 3, File No. 333-100577, on November 25, 2002).

*4.7 Fourteenth Supplemental Indenture, dated as of December 1, 2002, 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, including the form of the 2002 Series B Bond (filed as exhibit 4.1 to the Registrant’s Form 8-K, File No. 000-50039, on December 27, 2002).

4.8 Fifteenth Supplemental Indenture, dated as of May 1, 2003, 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.

*4.9 Sixteenth Supplemental Indenture, dated as of July 1, 2003, 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, including the form of the 2003 Series A Bond (filed as Exhibit 4.1 to the Registrant’s Form 8-K, File No. 000-50039, on July 25, 2003).

4.10 Seventeenth Supplemental Indenture, dated as of January 1, 2004, 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.

*4.11 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).

*4.12 First Supplemental Indenture, dated as of December 1, 2002, to the 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 the Registrant’s Form 8-K, File No. 000-50039, on December 27, 2002).

*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).

*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 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).

*10.11 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).

*10.12 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).

*10.13 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).

*10.14 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).

*10.15 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).

*10.16 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).

*10.17 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).

*10.18 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).

*10.19 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).

*10.20Amended 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).

*10.21 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).

*10.22 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).

*10.23 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).

*10.24 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).

*10.25 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).

*10.26 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).

*10.27 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).

*10.28 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).

*10.29 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).

*10.30 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).

*10.31 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).

*10.32 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).

*10.33 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).

*10.34 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).

**10.35 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).

**10.36 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).

*10.37 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).

*10.38 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).

*10.39 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).

*10.40 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).

*10.41 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).

*10.42 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).

**10.43 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).

**10.44 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).

*10.45 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).

*10.46 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).

*10.47 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).

*10.48 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).

*10.49 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).

*10.50 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).

*10.51 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).

*10.52 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).

*10.53 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).

*10.54 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).

*10.55 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).

*10.56 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).

*10.57 Employment Agreement, dated November 12, 2002, between Old Dominion Electric Cooperative and Jackson E. Reasor (filed as Exhibit 10.1 to Amendment No. 2 to the Registrant’s Form 10-Q for the quarter ended September 30, 2002, File No. 000-50039, on November 25, 2002).

*10.58 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).

*10.59 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).

*10.60 Old Dominion Electric Cooperative 2002 Option Plan, dated as of February 12, 2002 (filed as Exhibit 10.63 to Amendment No. 2 to the Registrant’s Form 10-K for the year ended December 31, 2001, File No. 000-50039, on November 25, 2002).

*10.61 Option Agreement between Old Dominion Electric Cooperative and Daniel M. Walker, dated as of March 1, 2002 (filed as Exhibit 10.64 to Amendment No. 2 to the Registrant’s Form 10-K for the year ended December 31, 2001, File No. 000-50039, on November 25, 2002).

*10.62 Option Agreement between Old Dominion Electric Cooperative and Konstantinos N. Kappatos, dated as of March 1, 2002 (filed as Exhibit 10.65 to Amendment No. 2 to the Registrant’s Form 10-K for the year ended December 31, 2001, File No. 000-50039, on November 25, 2002).

*10.63 Amendment No. 1 to Participation Agreement, dated as of December 19, 2002, among Old Dominion Electric Cooperative, State Street Bank and Trust Company, the Owner Participant named therein, Utrecht America Finance Co and Cedar Hill International Corp.

*10.64 Amendment No. 1 to Equipment Operating Lease Agreement, dated as of December 19, 2002, between State Street Bank and Trust Company, as Lessor, and Old Dominion Electric Cooperative, as Lessee.

*10.65 Amendment No. 1. to Corrected Foundation Operating Lease Agreement, dated as of December 19, 2002, between State Street Bank and Trust Company, as Foundation Lessor and Old Dominion Electric Cooperative, as Foundation Lessee.

*10.66 Deposit Agreement, dated as of December 19, 2002, between Old Dominion Electric Cooperative, as Depositor and JP Morgan Chase Bank, as Depositary.

*10.67 Deposit Pledge Agreement, dated as of December 19, 2002, between Old Dominion Electric Cooperative, as Pledgor and State Street Bank and Trust Company, as Pledgee.

*10.68 First Blocked Account Control Agreement, dated as of December 19, 2002, between Old Dominion Electric Cooperative, as Pledgor and State Street Bank and Trust Company, as Pledgee.

*10.69 Second Blocked Account Control Agreement, dated as of December 19, 2002, among Old Dominion Electric Cooperative, as Pledgor and State Street Bank and Trust Company, Utrecht America Finance Co., as Agent and JP Morgan Chase Bank.

*10.70 Amendment No. 2 to Payment Undertaking Agreement, dated as of December 19, 2002 between Old Dominion Electric Cooperative and Cooperatieve Centrale Raiffeisen Boerenleenbank B.A., “Rabobank Nederland”, New York Branch.

*10.71 Amendment No. 1 to Tax Indemnity Agreement, dated as of December 19, 2002, between Old Dominion Electric Cooperative and the Owner Participant named therein.

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 102(w) of Regulation S-X).

31.1 Certification of the Principal Executive Officer pursuant to Rule 13a-14(a)

31.2 Certification of the Principal Financial Officer pursuant to Rule 13a-14(a)

32.1 Certification of the Principal Executive Officer pursuant to 18 U.S.C. § 1350

32.2 Certification of the Principal Financial Officer pursuant to 18 U.S.C. § 1350

** 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.

The registrant did not file any reports on form 8-K during the fourth quarter of 2003.

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

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 March 22, 2004.


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)


Customer Class	Percentage of MWh Sales		Percentage of Customers
Residential	65.1	%	92.5	%
Commercial and industrial	33.7		6.9
Other	1.2		0.6


Member Distribution Cooperative	Revenues		Percentage of Total Revenues
	(in millions)
Northern Virginia Electric Cooperative	$	142.0	27.8	%
Rappahannock Electric Cooperative		106.9	20.9
Delaware Electric Cooperative		56.7	11.1


	Year Ended December 31,
	2003			2002			2001
	(in MWh and percentages)
Generated:
Mainland Virginia area:
Clover	3,212,421	30.6	%	3,153,856	30.7	%	3,342,398	34.4	%
North Anna	1,598,959	15.2		1,586,188	15.4		1,519,223	15.7
Louisa	154,693	1.5		—	—		—	—
Distributed generation	222	—		—	—		—	—

Total Mainland Virginia	4,966,295	47.3		4,740,044	46.1		4,861,621	50.1

Delmarva Peninsula area:
Rock Springs	109,748	1.0		—	—		—	—
Distributed generation	372	—		528	—		—	—

Total Delmarva Peninsula	110,120	1.0		528	—		—	—

Total Generated	5,076,415	48.3		4,740,572	46.1		4,861,621	50.1

Purchased:
Mainland Virginia area	2,872,895	27.4		3,346,963	32.6		2,555,653	26.3
Delmarva Peninsula area	2,556,506	24.3		2,190,443	21.3		2,285,585	23.6

Total Purchased	5,429,401	51.7		5,537,406	53.9		4,841,238	49.9

Total Available Energy	10,505,816	100.0	%	10,277,978	100.0	%	9,702,859	100.0	%


	Year Ended December 31,
	2003		2002		2001		2000		1999
	(in thousands except ratios)
Statement of Operations Data:

Operating Revenues	$	535,576	$	494,642	$	487,287	$	422,031	$	390,060
Operating Margin		57,941		43,983		44,895		44,696		53,325
Net Margin		12,056		9,996		8,440		8,229		9,839

Margins for Interest Ratio		1.31		1.20		1.21		1.20		1.24


Item Number		Page Number
	PART I
1.	Business	1
2.	Properties	17
3.	Legal Proceedings	22
4.	Submission of Matters to a Vote of Securities Holders	23

	PART II

5.	Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities	23
6.	Selected Financial Data	24
7.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	26
7A.	Quantitative and Qualitative Disclosures About Market Risk	50
8.	Financial Statements and Supplementary Data	53
9.	Changes in and Disagreements with Accountants on Accounting and Financial Disclosure	80
9A.	Controls and Procedures	80

	PART III

10.	Directors and Executive Officers of Registrant	81
11.	Executive Compensation	84
12.	Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters	87
13.	Certain Relationships and Related Transactions	87
14.	Principal Accountant Fees and Services	87

	PART IV

15.	Exhibits, Financial Statement Schedules, and Reports on Form 8-K	87

	SIGNATURES


	December 31,
	2003			2002			2001			2000			1999
	(in thousands except ratios)
Balance Sheet Data:

Net Electric Plant	$	1,085,406		$	938,086		$	695,008		$	648,898		$	699,531
Investments		276,998			278,218			356,048			246,730			262,024
Other Assets		199,932			213,755			203,877			114,944			88,957

Total Assets	$	1,562,336		$	1,430,059		$	1,254,933		$	1,010,572		$	1,050,512

Capitalization:
Patronage capital⁽¹⁾	$	247,590		$	235,534		$	225,538		$	224,598		$	216,369
Accumulated other comprehensive income		—			(10,911	)		398			(256	)		(2,316	)
Long-term debt		873,041			750,682			625,232			449,823			509,606

Total Capitalization	$	1,120,631		$	975,305		$	851,168		$	674,165		$	723,659

Equity Ratio⁽²⁾		22.1	%		23.9	%		26.5	%		33.3	%		29.8	%


	Clover						North Anna
	Year Ended December 31,						Year Ended December 31,
	2003		2002		2001		2003		2002		2001
Unit 1	86.6	%	75.9	%	86.8	%	80.5	%	100.8	%	87.9	%
Unit 2	81.4		88.8		88.0		90.4		68.6		74.4
Combined	84.0		82.4		87.4		85.5		84.7		81.2


Lender	Amount		Use of Proceeds	Expiration Date
	(in millions)
Bank of America, N.A.	$	30.0	Working Capital	September 30, 2004
Bank of America, N.A.		30.0	Working Capital	June 28, 2004
Branch Banking and Trust Company of Virginia		25.0	Working Capital	March 31, 2004
CoBank, ACB		25.0	Working Capital	October 31, 2004
JPMorgan Chase Bank		70.0	Construction of generating facilities	May 11, 2004
National Rural Utilities Cooperative Finance Corporation		50.0	Construction of generating facilities	August 10, 2004


	Actual						Projected
	Year Ended December 31,						Year Ended December 31,
	2001		2002		2003		2004		2005		2006
	(in millions)						(in millions)
Combustion turbine facilities	$	74.7	$	253.1	$	160.0	$	87.9	$	—	$	—
Clover		1.9		8.4		2.8		5.2		1.1		1.3
North Anna		10.4		7.4		8.5		20.4		18.3		17.3
Distributed generation facilities		6.7		1.7		—		—		—		—
Other		0.9		3.0		0.5		1.1		1.1		1.1

Total	$	94.6	$	273.6	$	171.8	$	114.6	$	20.5	$	19.7


	Payments due by Period
Contractual Obligations	Total		Less than 1 year		1-3 years		3-5 years		More than 5 years
	(in millions)
Long-term indebtedness	$	1,565.0	$	49.7	$	143.8	$	212.0	$	1,159.5
Capital lease obligations⁽¹⁾		—		—		—		—		—
Operating lease obligations		390.1		4.1		7.9		10.1		368.0
Purchase obligations		1.0		0.5		0.5		—		—
Power purchase obligations		20.0		14.1		5.9		—		—
Other long-term liabilities⁽²⁾		—		—		—		—		—
Construction obligations		36.8		36.8		—		—		—

Total	$	2,012.9	$	105.2	$	158.1	$	222.1	$	1,527.5


		Page Number
Report of Independent Accountants		54
Consolidated Balance Sheets		55
Consolidated Statements of Revenues, Expenses and Patronage Capital		56
Consolidated Statements of Comprehensive Income		57
Consolidated Statements of Cash Flows		58
Notes to Consolidated Financial Statements		59


	2003			2002
	(in thousands)
ASSETS
Electric Plant:
In service	$	1,313,649		$	926,805
Less accumulated depreciation		(397,327	)		(364,653	)

		916,322			562,152
Nuclear fuel, at amortized cost		7,439			4,226
Construction work in progress		161,645			371,708

Net Electric Plant		1,085,406			938,086

Investments:
Nuclear decommissioning trust		68,780			56,684
Lease deposits		150,559			143,598
Other		57,659			77,936

Total Investments		276,998			278,218

Current Assets:
Cash and cash equivalents		31,758			67,829
Receivables		59,708			54,566
Fuel, materials and supplies, at average cost		23,523			11,467
Prepayments		2,571			2,154

Total Current Assets		117,560			136,016

Deferred Charges:
Regulatory assets		68,234			65,883
Other		14,138			11,856

Total Deferred Charges		82,372			77,739

Total Assets	$	1,562,336		$	1,430,059

CAPITALIZATION AND LIABILITIES
Capitalization:
Patronage capital	$	247,590		$	235,534
Accumulated other comprehensive (loss) income		—			(10,911	)
Long-term debt		873,041			750,682

Total Capitalization		1,120,631			975,305

Current Liabilities:
Long-term debt due within one year		—			11,913
Accounts payable		66,812			75,333
Accounts payable—members		47,788			59,944
Accrued expenses		36,439			35,249
Deferred energy		13,582			3,039
Deferred revenue		—			10,278

Total Current Liabilities		164,621			195,756

Deferred Credits and Other Liabilities:
Asset retirement obligations		42,997			—
Decommissioning reserve		—			56,684
Obligations under long-term leases		153,659			146,465
Regulatory liabilities		37,024			1,303
Other		43,404			54,546

Total Deferred Credits and Other Liabilities		277,084			258,998

Commitments and Contingencies		—			—
Total Capitalization and Liabilities	$	1,562,336		$	1,430,059


	North Anna			Clover
	(in millions, except percentages)
Ownership interest		11.6	%		50.0	%
Electric plant in service	$	270.9		$	651.2
Accumulated depreciation		(120.5	)		(138.2	)
Nuclear fuel		44.8			—
Accumulated amortization of nuclear fuel		(37.4	)		—
Plant Acquisition Adjustment		51.8			—
Accumulated amortization of plant acquisition adjustment		(51.8	)		—
Construction work in progress		5.5			0.4


	Year Ended December 31, 2003
	(in thousands)
Decommissioning reserve	$	56,684
Cumulative effect of change in accounting principle		(17,641	)

Asset retirement obligations at January 1, 2003		39,043
Additional asset retirement obligations – new facilities		1,865
Accretion expense		2,089

Asset retirement obligations at December 31, 2003	$	42,997


Year Ending December 31,	Firm Capacity Requirements		Minimum Energy Requirements		Total
	(in millions)
2004	$	14.0	$	67.2	$	81.2
2005		0.1		23.0		23.1
2006		—		—		—
2007		—		—		—
2008		—		—		—

	$	14.1	$	90.2	$	104.3


Description	Cost		Gross Unrealized Gains		Gross Unrealized Losses			Fair Value
	(in thousands)
December 31, 2003

Available for Sale:
Corporate obligations	$	52,853	$	33	$	—		$	52,886
Registered investment companies⁽¹⁾		29,302		475		—			29,777
Common stock		34,050		5,045		(91	)		39,004
Short-term investments		60,694		—		—			60,694

	$	176,899	$	5,553	$	(91	)	$	182,361

Held to Maturity:
U.S. Government obligations	$	52,992	$	17,209	$	—		$	70,201
Corporate obligations		39,896		—		—			39,896

	$	92,888	$	17,209	$	—		$	110,097

Other	$	1,749	$	—	$	—		$	1,749

December 31, 2002

Available for Sale:
Corporate obligations	$	18,110	$	—	$	—		$	18,110
Registered investment companies⁽¹⁾		27,648		—		(90	)		27,558
Common stock		32,606		—		(3,410	)		29,196
Short-term investments		59,842		—		—			59,842

	$	138,206	$	—	$	(3,500	)	$	134,706

Held to Maturity:
U.S. Government obligations	$	104,427	$	18,935	$	—		$	123,362
Corporate obligations		37,265		—		—			37,265

	$	141,692	$	18,935	$	—		$	160,627

Other	$	1,820	$	—	$	—		$	1,820


Description	Less Than One Year		One Through Five Years		More Than Five Years		Total
	(in thousands)
Available for Sale	$	—	$	—	$	52,886	$	52,886
Held to Maturity		280		1,115		91,493		92,888

	$	280	$	1,115	$	144,379	$	145,774


Year Ending December 31	(in thousands)
2004	$	413
2005		413
2006		413
2007		413
2008		413
2009 and thereafter		3,304

	$	5,369


	First Quarter		Second Quarter		Third Quarter		Fourth Quarter		Total
	(in thousands except ratios)
Statement of Operations Data:
2003:
Operating Revenue	$	143,917	$	132,120	$	136,115	$	123,424	$	535,576
Operating Margin		14,233		10,736		17,053		15,919		57,941
Net Margin		2,716		2,768		3,268		3,304		12,056

2002:
Operating Revenue	$	132,247	$	113,426	$	130,255	$	118,714	$	494,642
Operating Margin		10,679		11,841		10,747		10,716		43,983
Net Margin		2,516		2,527		2,521		2,432		9,996


	Annual Compensation
Name and Principal Position	Year	Salary⁽²⁾		Bonus		Other Annual Compensation⁽³⁾		All Other Compensation⁽⁴⁾
Jackson E. Reasor⁽¹⁾ President and Chief Executive Officer	2003 2002 2001	$	300,833 279,880 270,000	$	— — 6,000	$	3,095 2,369 2,868	$	43,221 39,691 34,661
Daniel M. Walker Sr. Vice President Accounting and Finance	2003 2002 2001	$	190,450 175,410 168,178	$	10,000 — —	$	— — —	$	96,743 93,838 24,390
Konstantinos N. Kappatos⁽⁵⁾ Sr. Vice President Power Supply Planning	2003 2002 2001	$	190,450 175,410 168,178	$	— — —	$	— — —	$	130,746 127,838 24,390
Gregory W. White Sr. Vice President Engineering and Operations	2003 2002 2001	$	151,883 141,014 135,200	$	— — —	$	— — —	$	23,106 20,237 19,651


Final Average Salary		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
	205,000		62,207		82,943		103,679		124,415		145,150


Final Average Salary		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
	205,000		52,275		69,700		87,125		104,500		121,975


	2003		2002
Audit Fees (a)	$	207,100	$	237,400
Audit-Related Fees (b)		43,100		18,500
Tax (c)		27,500		17,500

Total	$	277,700	$	273,400


Signature		Title

/s/ JACKSON E. REASOR Jackson E. Reasor		President and Chief Executive Officer (Principal executive officer)

/s/ DANIEL M. WALKER Daniel M. Walker		Sr. Vice President and Chief Financial Officer (Principal financial officer)

/s/ ROBERT L. KEES Robert L. Kees		Vice President and Controller (Principal accounting officer)

/s/ E. PAUL BIENVENUE E. Paul Bienvenue		Director

/s/ DICK D. BOWMAN Dick D. Bowman		Director

/s/ M. JOHNSON BOWMAN M. Johnson Bowman		Director

/s/ M DALE BRADSHAW M Dale Bradshaw		Director


Signature		Title
/s/ VERNON N. BRINKLEY Vernon N. Brinkley		Director

/s/ CALVIN P. CARTER Calvin P. Carter		Director

/s/ GLENN F. CHAPPELL Glenn F. Chappell		Director

/s/ CARL R. EASON Carl R. Eason		Director

/s/ KENT D. FARMER Kent D. Farmer		Director

/s/ STANLEY C. FEUERBERG Stanley C. Feuerberg		Director

/s/ WILLIAM C. FRAZIER William C. Frazier		Director

/s/ HUNTER R. GREENLAW, JR. Hunter R. Greenlaw, Jr.		Director

/s/ BRUCE A. HENRY Bruce A. Henry		Director

/s/ WADE C. HOUSE Wade C. House		Director

/s/ FREDERICK L. HUBBARD Frederick L. Hubbard		Director

/s/ DAVID J. JONES David J. Jones		Director

/s/ BRUCE M. KING Bruce M. King		Director


Signature		Title
/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

/s/ CARL R. WIDDOWSON Carl R. Widdowson		Director

/s/ C. DOUGLAS WINE C. Douglas Wine		Director