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SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549

FORM 10-K

FOR ANNUAL AND TRANSITION REPORTS
PURSUANT TO SECTIONS 13 OR 15(d) OF THE
SECURITIES EXCHANGE ACT OF 1934

Indicate by check mark whether the Registrant: (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the Registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days.

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

Indicate by check mark whether the Registrant is an accelerated filer (as defined in Exchange Act Rule 12b2).

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

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

DOCUMENTS INCORPORATED BY REFERENCE: NONE

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OLD DOMINION ELECTRIC COOPERATIVE

2002 ANNUAL REPORT ON FORM 10-K

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PART I

ITEM 1.   BUSINESS

OLD DOMINION ELECTRIC COOPERATIVE

General

          Old Dominion Electric Cooperative was incorporated under the laws of the Commonwealth of Virginia in 1948 as a not-for-profit power supply cooperative.  We were organized for the purpose of supplying the power our member distribution cooperatives require to serve their customers on a cost-effective basis.  Through our member distribution cooperatives, we served more than 464,000 retail electric consumers (meters) representing a total population of approximately 1.2 million people in 2002.  We provide this power pursuant to long-term, all-requirements wholesale power contracts.  See “Member Distribution Cooperatives—Wholesale Power Contracts” below. 

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

          In recent years, we have decreased our reliance on long-term power purchase contracts and increased our reliance on market purchases of energy to take advantage of our projections of relatively lower future market energy prices.  See “Power Supply Resources—Other Power Supply Resources—Power Purchase Contracts” and “Management’s Discussion and Analysis of Financial Condition and Results of Operations—Future Issues—Reliance on Energy Purchases” in Item 7. 

          To meet a portion of our member distribution cooperatives’ future power requirements, we are developing three combustion turbine facilities, known as “Rock Springs,” “Louisa” and “Marsh Run.” We expect Rock Springs, Louisa and Marsh Run to supply 336 MW, 504 MW, and 504 MW of capacity, respectively, to us following completion.  Rock Springs is being developed jointly with a third party.  Construction of Rock Springs and Louisa began in October 2001, and July 2002, respectively.  We expect to obtain the required construction approvals and permits and to begin construction of Marsh Run in April 2003.  See “Power Supply Resources—Combustion Turbine Facilities.”

          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 parts of West Virginia.  Our sole Class B member is TEC Trading, Inc. (“TEC Trading”), a corporation owned by our member distribution cooperatives.  TEC Trading 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 Trading does not engage in speculative trading.  See “TEC Trading.”

          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 recently enacted state restructuring legislation, nearly all customers of our member distribution cooperatives will be able to select their power suppliers by 2004.  The member distribution cooperatives will continue to be the exclusive providers of distribution services and, at least initially, the default providers of power to their customers in their service

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territories.  See “Management’s Discussion and Analysis of Financial Condition and Results of Operations—Future Issues—Competition and Changing Regulations” In Item 7. 

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

          We are not a party to any collective bargaining agreement.  We had 65 employees as of December 31, 2002, and believe that our relations with our employees are good. 

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

Cooperative Structure

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

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

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

Member Distribution Cooperatives

          General

          Our member distribution cooperatives provide electric services, consisting of power supply, transmission services, and distribution services (including metering and billing) to residential, commercial, and industrial customers in 70 counties in Virginia, 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

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

          Wholesale Power Contracts

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

          There are two principal exceptions to the “all-requirements” obligations of the parties.  First, each mainland Virginia member distribution cooperative may purchase power allocated to it from the Southeastern Power Administration (“SEPA”).  In 2002, the total allocation of power from SEPA to the member distribution cooperatives was 84 MW plus associated energy, representing approximately 4.2%of our total member distribution cooperatives’ peak capacity requirements and approximately 0.9% of our total member distribution cooperatives’ energy requirements.  Second, if pursuant to the Public Utility Regulatory Policies Act (“PURPA”) or other laws, a member distribution cooperative is required to purchase electric power from a qualifying facility, the member distribution cooperative must make the required purchases.  Any required purchases made by the member distribution cooperative will be at a rate no more than our avoided cost, as established by us.  At our option, the member distribution cooperative will sell that power to us at a price no more than that rate.  The member distribution cooperative may appoint us to act as its agent in all dealings with the owner of any of these qualifying facilities.  Purchases of power generated by qualifying facilities constituted less than 1.0% of our member distribution cooperatives’ capacity and energy requirements in 2002. 

          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:

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The rates established under the wholesale power contracts are designed to enable us to comply with our 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 costs and expenses or estimates of our sales of power.  Increases or decreases in our annual budget automatically amend the demand component of our formulary rate.  Also, the wholesale power contracts permit us to adjust the amounts to be collected from the member distribution cooperatives to equal our actual demand costs.  We make these adjustments under our Margin Stabilization Plan.  See “Management’s Discussion and Analysis of Financial Condition and Results of Operations—Factors Affecting Results—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.  See “Management’s Discussion and Analysis of Financial Condition and Results of Operations—Factors Affecting Results—Margin Stabilization Plan” in Item 7. 

          During the term of each wholesale power contract, each member distribution cooperative will not, without obtaining our written consent, take or permit to be taken any steps for reorganization or dissolution, consolidation with or merger into any corporation, or the sale, lease or transfer of all or a substantial portion of its assets.  We will not, however, unreasonably withhold our consent to any reorganization, dissolution, consolidation, merger or sale, lease or transfer of assets.  In addition, we will not withhold or condition our consent if the transaction would not (1) increase rates to our other 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:

          Northern Virginia Electric Cooperative

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

          We received a letter, dated November 19, 2002, from the President and CEO of Northern Virginia Electric Cooperative stating that the Northern Virginia Electric Cooperative board of directors took formal action on November 18, 2002, directing the Northern Virginia Electric Cooperative CEO to communicate to us that Northern Virginia Electric Cooperative would make one final attempt to reach an acceptable conclusion to the negotiations on

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amending the wholesale power contract and authorizing the CEO to pursue recourse before an appropriate decision-making body if certain milestones were not met.  These milestones have not been met; however, we are continuing to negotiate with Northern Virginia Electric Cooperative to resolve this matter and we have been advised that, in recognition of the progress that has been made, the Northern Virginia Electric Cooperative board of directors had suspended these deadlines.

          In addition, Northern Virginia Electric Cooperative has told us that if it is necessary to bring an action before the Federal Energy Regulatory Commission (“FERC”) or the Virginia State Corporation Commission (“VSCC”) regarding this contract, that action would not challenge the validity or enforceability of the contract, but rather would seek reformation of the contract along the lines being negotiated.  Northern Virginia Electric Cooperative has further advised us it would not seek to be relieved of its obligation to buy power from us equal to that which could be served by its proportionate share of North Anna, Clover and the three combustion turbine facilities under development or construction, nor would it seek to be relieved of its obligation to pay its share of the costs of those generating facilities, including debt service, lease rentals, operation and maintenance expenses, coverage and other costs and expenses related to the facilities or properly allocable to the services provided by us to it.

          We intend to continue negotiating with Northern Virginia Electric Cooperative to resolve this matter.  While we cannot predict the outcome of any proceedings relating to this matter, we continue to believe that no reformation of our wholesale power contract with Northern Virginia Electric Cooperative is justified and intend to take all actions necessary to assure that there is no change to the wholesale power contract that adversely affects our financial condition or our other member distribution cooperatives.

TEC Trading

          Changes in the electric utility industry and our development of the three combustion turbine facilities have made it more important for us to manage our activities in power-related markets.  For instance, to obtain an economical power supply to meet our projected member distribution cooperatives’ energy requirements, we sometimes purchase energy for some hours in excess of our member distribution cooperatives’ actual needs.  We also intend to purchase natural gas and related financial and hedge arrangements to limit our exposure to fluctuating natural gas prices.  In response to these changes, TEC Trading 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 to supply the combustion turbine facilities, and taking advantage of other power-related trading opportunities in the market which will help lower our member distribution cooperatives’ costs.  TEC Trading does not engage in speculative trading. 

          We initially capitalized TEC Trading in 2001 with a $7.5 million cash investment in exchange for all of its capital stock.  We then distributed all of TEC Trading’s stock as a patronage capital distribution to our member distribution cooperatives.  TEC Trading is now owned entirely by our member distribution cooperatives, and is currently our only Class B member.  As a member, TEC Trading 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.

          On December 19, 2001, TEC Trading was granted market-based rate authority by FERC, which allows it to sell power at market rates.  We have signed a power sales contract with TEC Trading, under which TEC Trading purchases our excess energy for resale to the market.  To fully participate in power-related markets, TEC Trading must maintain credit support sufficient to meet delivery and payment obligations associated with its power trades.  To assist TEC Trading in providing this credit support, we have agreed to guarantee up to $42.5 million of TEC Trading’s delivery and payment obligations associated with its power trades.  As of December 31, 2002, we have guaranteed $0.5 million of obligations of TEC Trading.  We have also entered into an agreement with TEC Trading whereby we provide certain accounting, billing, reporting and other administrative services to TEC Trading on an arm’s-length basis.

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          TEC Trading has engaged 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 2002, TEC Trading purchased from us, and subsequently sold to the market, 67,360 megawatt-hours (“MWh”) of power.  We charged TEC Trading $8,000 for services we performed under the agreements discussed above.

Members’ Service Territories and Customers

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

          Virginia, Delaware, and Maryland have enacted legislation granting retail customers the right to choose their power supplier.  This legislation maintains the exclusive right of the incumbent electric utilities, including our member distribution cooperatives, to continue to provide transmission and distribution services and, at least initially, to be the default providers of power to their customers in their service territories.  See “Management’s Discussion and Analysis of Results of Operation and Financial Condition—Future Issues—Competition and Changing Regulations” in Item 7. 

          The territories served by our member distribution cooperatives cover large portions of Virginia, Delaware, and Maryland.  One of our member distribution cooperatives also serves a small area of West Virginia.  These service territories range from the suburban metropolitan Washington, D.C. area in northern Virginia, to the Atlantic shore of 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.  Our member distribution cooperatives serve major industries, which include manufacturing, fisheries, agriculture, forestry and wood products, paper, travel, and trade. 

          Our member distribution cooperatives’ sales of energy in 2002 totaled approximately 9,368,976 MWh.  These sales were divided by type as follows:

          From 1997 through 2002, our member distribution cooperatives experienced an average annual compound growth rate of approximately 3.0% in the number of customers and an average annual compound growth rate of 4.7% in energy sales.

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          Revenues from the following member distribution cooperatives equaled or exceeded 10% of Old Dominion’s total revenues in 2002:

          The member distribution cooperatives’ average number of customers per mile of energized line has increased approximately 5.8% since 1997 to approximately 9.1 customers per mile in 2002.  System densities of our member distribution cooperatives in 2002 ranged from 6.1 customers per mile in the service territory of BARC Electric Cooperative to 20.8 customers per mile in the service territory of Northern Virginia Electric Cooperative.  In 2002, the average service density for all distribution electric cooperatives in the United States was approximately 6.6 customers per mile. 

COMPETITION AND CHANGING REGULATIONS

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

CONSERVATION AND LOAD MANAGEMENT

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

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

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POWER SUPPLY RESOURCES

General

          We provide power to our members through a combination of our interests in Clover, North Anna and other owned resources, 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 must generate or purchase power to meet the specific needs of each area separately.  For example, power generated by Clover and North Anna 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 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 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. 

          Mainland Virginia represented approximately 76.0% of our 2002 peak capacity requirements, which occurred in July.  North Anna and Clover satisfied approximately 44.0%of our capacity requirements and 58.6% of our energy requirements in mainland Virginia in 2002.  In 2002, we obtained the remainder of our mainland Virginia and all 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.  Generally, power purchase contracts allow us to meet these requirements by purchasing fixed-price firm capacity and energy at market prices.  See “Other Power Supply Resources—Power Purchase Contracts.”

          Most of our long-term power purchase contracts will expire by 2005.  We are developing 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 is planned to meet our projected capacity requirements, which are a function of expiring power purchase contracts and our member distribution cooperatives’

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capacity requirements growth projections.  In addition, we have installed ten diesel generators across our member distribution cooperatives’ service territories primarily to enhance our system’s reliability. 

North Anna

          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.  During 2002, North Anna provided approximately 15.4% of our energy requirements.  North Anna Unit 1 commenced commercial operation in June 1978, and Unit 2 commenced commercial operation in December 1980.  Virginia Electric and Power Company (“Virginia Power”), the co-owner of North Anna, operates the facility.  Virginia Power also has the authority and responsibility to procure nuclear fuel for North Anna.  See “Fuel Supply—Nuclear.”

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

          Under the I&O Agreement, 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. 

          Like other nuclear facilities, North Anna is subject to unanticipated or extended outages for repairs, replacements, or modifications of equipment or to comply with regulatory requirements.  These outages may involve significant expenditures not previously budgeted, including replacement energy costs.  In September 2002, during a scheduled refueling outage and inspection, deposits of crystallized boric acid were discovered on top of the North Anna Unit 2 reactor vessel head.  Based upon these findings, Virginia Power, as operator, determined that a new reactor vessel head would need to be installed.  The scheduled refueling outage for this unit was extended and a new reactor vessel head was installed.  North Anna Unit 2 returned to service in February 2003.  Following the inspection of North Anna Unit 1, Virginia Power has also decided to install a new reactor vessel head at Unit 1. In February 2003, North Anna Unit 1 was taken off-line for a scheduled refueling outage and to install the new reactor vessel head.  Virginia Power currently anticipates that Unit 1 will be returned to service during the second quarter of 2003.  See “Management’s Discussion and Analysis of Financial Condition and Results of Operations—Results of Operations—Operating Expenses” in Item 7 for a discussion of recent operating history of North Anna. 

          North Anna requires significant water resources to generate steam for the production of energy and for cooling purposes.  North Anna obtains its water from Lake Anna.  By August 2002, a several year drought in central Virginia had caused Lake Anna to fall four feet below its designated normal level of 250 feet above sea level and the continued operation of North Anna at full capacity could have been affected if the drought conditions persisted.  To mitigate the effect of continued drought conditions, Virginia Power, as operator of North Anna, installed intake pump shaft extensions to allow both units to continue to operate until the water level fell more than eight feet below the normal level.  Heavy precipitation in the fall and winter of 2002 have ended the drought conditions in central Virginia.  See “Regulation—Environmental.”  As of March 14, 2003, Lake Anna was 250 feet above sea level.

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Clover

          We have a 50% undivided interest in Units 1 and 2 of Clover, a coal-fired generating facility jointly owned with Virginia Power.  Clover has a net capacity rating of 882 MW, and is located near 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.” 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 are required to take half of the power produced by Clover.  During 2002, Clover provided approximately 30.7% 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. 

          Clover requires significant water resources to generate steam for the production of energy and for cooling purposes.  Clover draws water for its operations from the Roanoke River and, if necessary, an auxiliary man-made reservoir.  Because Clover and the Roanoke River are located in central Virginia, both were affected by the several year drought in that area which continued into 2002.  See “Regulation—Environmental.”  Heavy precipitation in the fall and winter of 2002 have ended the drought conditions in central Virginia.  As of March 14, 2003, the Roanoke River was at normal levels and the reservoir had had sufficient capacity to permit Clover to continue normal operations for approximately 30 days if no water was drawn from the river. 

          Lease of Pollution Control Assets

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

          Lease of Clover Unit 1

          We also have entered into separate lease and leaseback agreements of our undivided ownership interest in each Clover unit and related common facilities, including the pollution control assets at the facilities.  In March, 1996, we entered into a lease with an owner trust for the benefit of an investor in which we leased our interest in Clover Unit 1, subject to the lien of the Existing Indenture, for a term extendable by the 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 (the “leaseback”).  After the Release Date, the interest of the owner trust in Clover Unit 1 will no longer be subject and subordinate to the lien of the Existing Indenture.  See “Management’s Discussion and Analysis of

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Financial Condition and Results of Operations—Factors Affecting Results Formulary Rate—Restated Indenture” in Item 7.  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 leaseback, 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, Part II 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. 

          Lease of Clover Unit 2

          In July 1996, we entered into another lease subject to the lien of the Existing Indenture with an owner trust for the benefit of a different investor of our interest in Clover Unit 2 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 leaseback 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 Release Date unless the holders of obligations issued under the Existing Indenture are equally and ratably secured with respect to the assets subject to the lease.  After the Release Date, the interest of the owner trust will no longer be subject and subordinate to the lien of the Existing Indenture.  See “Management’s Discussion and Analysis of Financial Condition and Results of Operations—Factors Affecting Results—Formulary Rate—Restated Indenture” in Item 7.

          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.

Combustion Turbine Facilities

          Through our subsidiaries, we are developing the Rock Springs, Louisa and Marsh Run combustion turbine facilities to enable us to continue to serve our member distribution cooperatives’ power requirements.  Upon completion of the facilities, our total system capacity from facilities owned by us or our subsidiaries will increase from 675 MW to 2,019 MW.  The sites selected for Rock Springs, Louisa and Marsh Run contain the attributes required to support a combustion turbine facility such as access to electric transmission lines, natural gas pipelines, water and other required major infrastructure.

          We have decided to dissolve the subsidiaries owning the facilities and plan to take direct ownership of their interests in Rock Springs, Louisa, and Marsh Run.  On March 11, 2003, our board of directors voted to dissolve the Louisa and Marsh Run subsidiaries effective March 31, 2003, or such later date as determined by each respective president of the Louisa and Marsh Run subsidiaries.  We anticipate that the Rock Springs subsidiary will be

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dissolved by the end of 2003.  The dissolution is not expected to have an effect on the approvals, permits, development or construction of the facilities or the expected availability of the facilities by their anticipated commercial operation dates. 

          Rock Springs

          The Rock Springs facility is currently being developed by our subsidiary together with another participant, CED Rock Springs, Inc. (“ConEd”).  Rock Springs will meet a substantial portion of the capacity requirements of our member distribution cooperatives on the Delmarva Peninsula and provide power to the other participant.  Located in the community of Rock Springs, Cecil County, Maryland, the facility is currently 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 or are being installed at the facility.  We and ConEd are each responsible for funding our share of all capital expenditures, and costs and expenses.  Our portion of the cost to develop and construct Rock Springs is currently estimated to be approximately $150 million.

          In addition to ConEd and our subsidiary, 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 (depending on the number of participants in Rock Springs) of the undivided interest in the common facilities.  Our subsidiary will be responsible for all costs associated with the development, construction, additions and operating costs and administrative and general expenses relating to its two units and its proportional share of the costs relating to the common facilities for Rock Springs. 

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

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

          We are acting as construction agent on behalf of our subsidiary, ConEd, and any future participant or participants in Rock Springs to administer and supervise the development and construction of the facility.  Our subsidiary and ConEd entered into a contract with FruCon Construction Corp.  for engineering, procurement and construction services relating to Rock Springs.  Construction began on the facility in October 2001.  The two units owned by ConEd are substantially complete.  We expect that the two units that are owned by our subsidiary will begin commercial operation in mid-2003.  The power from the facility will be transmitted to our member distribution cooperatives over PJM’s transmission facilities under its open access transmission tariff.

          In July 2002, our subsidiary 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 will begin on the commissioning date of the first unit and will automatically extend for a one year period unless notice is given by either party.  CED Operating Co., L.P. will provide to the owners the services necessary for the safe transition from construction to operation of the facility and supply all services, goods and materials required to operate the facility other than natural gas.  We will arrange for the transportation of the natural gas required by the operator for all units at Rock Springs and will arrange for the supply of natural gas to our units only.

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          Louisa

          The Louisa facility is located near Gordonsville, in Louisa County, Virginia, and will consist of five combustion turbines totaling 504 MW (net capacity rating).  The facility will include four 84 MW  General Electric 7EA combustion turbines and one 168 MW General Electric 7FA combustion turbine that we have procured under fixed-price contracts with General Electric Company.  The combustion turbines are expected to be fueled by natural gas and, if necessary, No. 2 distillate fuel oil.  Our cost to develop and construct Louisa is currently estimated to be approximately $230 million.

          We will act as construction agent on behalf of our subsidiary.  Our subsidiary has entered into a contract with Kamtech, Inc.  for engineering, procurement and construction services relating to Louisa.  The construction of the facility began in July 2002 and we expect the facility to be available for commercial operation by mid-2003.  Power from Louisa will be transmitted to our member distribution cooperatives over the transmission facilities of Virginia Power under its open access transmission tariff. 

          The VSCC has issued a certificate of public convenience and necessity for the construction and operation of the facility.  All major environmental permits from the Commonwealth of Virginia have been obtained, subject to compliance with customary conditions set forth in the certificate that are required prior to the start of construction of the facility.  We are not required to purchase NO_x emissions credits with respect to the facility.  See “Regulation—Environmental.”

          In January 2003, we entered into an operation and maintenance service agreement with PIC Energy Services, Inc. (“PIC”).  Under this agreement, PIC will provide the services necessary for the transition from construction to operation of the facility and supply all services, goods and materials required to operate the 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 supply of the natural gas and No. 2 distillate fuel oil required by this facility.

          Marsh Run

          The Marsh Run facility is located near Remington in Fauquier County, Virginia, and is currently expected to consist of three 168 MW (net capacity rating) combustion turbines, for a total of 504 MW.  We have entered into a fixed-price contract with General Electric Company to purchase the three General Electric 7FA combustion turbines to be installed at Marsh Run.  The combustion turbines are expected to be fueled by natural gas and, if necessary, No. 2 distillate fuel oil.  We may construct a fourth combustion turbine unit at the facility at a later date.  Our cost to develop and construct three units at Marsh Run is currently estimated to be approximately $227 million. 

          We will act as construction agent on behalf of our subsidiary.  Our subsidiary has entered into a contract with Ragnar Benson, Inc. for engineering, procurement and construction services relating to Marsh Run.  We expect that construction of the facility will begin in April 2003 and 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 VSCC has issued a certificate of public convenience and necessity for the construction and operation of the facility.  All major environmental permits from the Commonwealth of Virginia have been obtained subject to compliance with customary conditions set forth in the certificate that are required prior to the start of construction of the facility.  We are not required to purchase NO_x emissions credits with respect to the facility.  See “Regulation—Environmental.”

          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

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date of the Louisa facility and will expire on January 15, 2006 unless notice is given by either party.  We will arrange for the supply of the natural gas and No. 2 distillate fuel oil required by this facility.

Diesel Generators

          In 2002, we installed 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.

Other Power Supply Resources

          In 2002, we purchased approximately 53.9% of our total energy requirements.  These energy requirements were in excess of our owned generation resources and were provided principally by neighboring utilities through power purchase contracts and purchases of energy in the forward, short-term and spot markets. 

          Power Purchase Contracts

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

          Virginia Power.  Under the terms of the I&O Agreement, Virginia Power sells us reserve capacity and energy for North Anna and Clover.  We plan to purchase our reserve capacity requirements for North Anna and Clover from Virginia Power for the term of the I&O Agreement, which expires on the earlier of the date on which all facilities at North Anna have been retired or decommissioned and the date we have no interest in North Anna.  In 2002, Virginia Power provided us with approximately half of our monthly supplemental and all of our 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 and Clover.  Under the I&O Agreement, we will not purchase any of our supplemental capacity requirements from Virginia Power in 2003.  We will continue to purchase our peaking capacity requirements from Virginia Power through 2003. 

          The price of energy we pay for the peaking 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 have the contractual right to elect not to purchase energy under the I&O Agreement if we can purchase more economical energy from other sources. 

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

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          PSE&G.  In December 1992, we entered into an agreement with PSE&G to purchase 150 MW of capacity, consisting of 75 MW of intermediate or peaking capacity and 75 MW of base load capacity, as well as reserves and associated energy, through 2004.  The agreement with PSE&G contains fixed capacity charges, 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. 

          In October 1997, we filed with FERC a complaint against PSE&G asserting that our agreement with PSE&G should be modified to conform to the restructuring of PJM.  Under the PJM structure, we pay for the transmission of PSE&G power through the zonal rate we currently pay Conectiv.  On May 14, 1998, FERC ruled in our favor as part of its ruling on several cases relating to the restructuring of PJM, ordering PSE&G to remove all transmission costs from its rates for capacity and associated energy sold to us, effective April 1, 1998.  PSE&G complied with the FERC order by virtue of a compliance filing submitted to FERC on June 15, 1998.  On November 30, 2000, PSE&G filed with the United States Court of Appeals for the District of Columbia Circuit a petition for review of FERC’s orders in this matter.  On July 12, 2002, the Court of Appeals vacated FERC’s May 14, 1998 ruling and remanded all of these cases relating to the restructuring of PJM to FERC for further consideration.

          On December 19, 2002, FERC issued an order on remand reversing its May 14, 1998 generic PJM restructuring ruling.  FERC noted that there was no evidence on record in the generic restructuring proceeding to demonstrate what, if any, unduly discriminatory effects could be attributable to our particular contract, but went on to state that we are free to present evidence based on the specifics of our contract with PSE&G under Section 206 of the Federal Power Act.  On January 24, 2003, we filed an amended and renewed complaint against PSE&G with FERC, requesting that FERC reopen the proceeding regarding the matters raised by our October 1997 complaint.  That initial complaint was dismissed by FERC in August 1998, based on FERC’s generic PJM restructuring ruling that ruled in our favor.  Our January 24, 2003 complaint renewal and amendment urges FERC to find that rate pancaking to us under our agreement with PSE&G is unlawful and eliminate this rate pancaking treatment effective April 1, 1998, forward.  We also requested that FERC stay any payment obligation by us to PSE&G for surcharge amounts of pancaked rates (incurring charges from multiple transmission owners due to transmission across several systems) from April 1, 1998 through December 31, 2002.  We received an invoice from PSE&G on January 22, 2003, for this surcharge amount of $26.2 million, plus $4.7 million in accumulated interest. 

          On February 10, 2003, we informed PSE&G in writing that a payment obligation for any past amount under the 1992 agreement’s surcharge authority remains unauthorized and premature, until so ordered by FERC.  On January 14, 2003, our board of directors approved the collection from our member distribution cooperatives of approximately $32.9 million including interest and related margin requirement beginning February 1, 2003, over forty-eight months, to cover this contingency.  We are paying the amount of pancaked rates on a prospective basis, subject to protest and FERC action on our renewed and amended complaint.

          Williams.  In April 2000, we executed an agreement with Williams to meet a portion of our member distribution cooperatives’ capacity and energy needs.  We began making purchases under the Williams  agreement on September 1, 2001.  We purchased 331 MW of capacity for the period January 1, 2002 through April 30, 2002, 245 MW of capacity for the period May 1, 2002 through December 31, 2002, and expect to purchase 490 MW of capacity for the period January 1, 2003 through May 31, 2003.  In addition to having the rights to this capacity, the contract grants us the option to purchase energy at fixed rates that vary over the term of the contract. 

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

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          Allegheny.  We purchase power pursuant to power purchase contracts with Allegheny Energy Supply (“Allegheny”), a subsidiary of Allegheny Power Resources.  These contracts met the capacity and energy requirements of our member distribution cooperatives in Allegheny Power Resources’ service area in mainland Virginia for 2002 and will meet the capacity needs up to 25 MW through May 2005.

          Constellation.  In October 2001, we executed an agreement with Constellation to purchase 150 MW of capacity from May 1, 2002 through May 31, 2003 to meet a portion of our Delmarva Peninsula member distribution cooperatives’ capacity requirements.  This contract is for capacity only and does not include rights to energy. 

          To replace the contracts with Allegheny and with AEP-Virginia discussed above, 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 is supplied under PJM’s transmission tariff for the Allegheny area power requirements, and the AEP-Virginia open access transmission tariff for power requirements served in its area.

          ConEd.  As a part of the construction and ownership agreement with ConEd for the Rock Springs facility, ConEd has agreed to sell us power through May 31, 2003, which coincides with the expected in-service date of our first Rock Springs unit.  On June 1, 2002 through November 30, 2002, ConEd agreed to sell to us 150 MW of capacity and a call option on the energy.  Effective December 1, 2002, and continuing through May 31, 2003, ConEd agreed to sell us 175 MW of capacity and a call option on the energy.

          Other.  We also purchase a portion of our energy requirements from the market using forward contracts, and short-term and spot purchases.  These purchasing strategies are associated with the changing contracts and the ability to forego purchasing energy under existing contracts.  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 and in 2001, we became an equity owner in APM.  See “Management’s Discussion and Analysis of Financial Condition and Results of Operations—Future Issues  Reliance on Energy Purchases.”

Transmission

          We have entered into 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.  In order to interconnect the Rock Springs facility, we undertook the construction of two 1,100 foot 500 kilovolt (“kV”) transmission lines and a 500 kV substation at the Rock Springs site.  We and ConEd became signatories to the PJM Transmission Owners Agreement effective August 2002.  As a transmission owner, we and ConEd 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.  Because these interconnection facilities are used solely to connect Rock Springs to the PJM transmission system, they do not change our focus as a power supply cooperative nor provide us with any competitive advantage in the wholesale power markets.

          Virginia Power System

          Under the operating agreements for both North Anna and Clover, Virginia Power makes available to us its transmission and distribution systems, as needed, to transmit our power from North Anna and Clover, as well as power purchased from other suppliers, to our member distribution cooperatives’ delivery points.  Pursuant to the I&O Agreement, Virginia Power supplies all transmission services to us under its open access transmission tariff.  In 2002, the terms for transmission and related services are described in our Service Agreement for Network Integration Transmission Service (“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 PJM control of Virginia Power’s transmission facilities to PJM.  See “—RTOs.”

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          PJM

          We are a member of PJM to serve our member distribution cooperatives located on the Delmarva Peninsula and a portion of the Virginia mainland near 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.  Allegheny Power Resources joined PJM during 2002 and gave PJM operational control of its transmission facilities.

          PJM continually balances its participant’s power requirements with the power resources available to supply those requirements.  Based on this evaluation of supply and demand, PJM schedules available resources to meet the demand for power in the most efficient and cost-effective manner.  When available resources cannot be dispatched due to transmission constraints, more expensive generating facilities not subject to the transmission constraints must be dispatched to meet the requested power requirements.  PJM participants whose power requirements cause the redispatch are obligated to pay those 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 2002, PJM allocated to us 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 if economical. 

          In 2002, we paid approximately $11.4 million in congestion charges to PJM.  These charges were partially offset by credits of approximately $3.1 million from our fixed transmission rights.  Net congestion costs for 2002 were approximately $8.3 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 and Conectiv have agreed to pay for transmission network upgrades in order to serve our member distribution cooperatives on the Delmarva Peninsula more reliably and economically. 

          Other Transmission Systems

          Our power purchase contract with AEP–Virginia provides for transmission service for the power we purchase under the contract.  When this contract expires, we anticipate obtaining transmission service for purchases of power to serve our member distribution cooperatives’ requirements in this 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 the PJM regional transmission organization. 

          RTOs

          In December 1999, FERC issued Order No. 2000 amending its regulations to advance the formation of regional transmission organizations (“RTOs”).  One of the major objectives of Order No. 2000 is to eliminate pancaked transmission rates.  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 transmission charge.  FERC will regulate the transmission rates established by the RTOs.  The regulations require that each public utility that owns, operates or controls facilities for the transmission of electric energy in interstate commerce make filings with respect to forming and participating in an RTO.  Because we do not own any significant jurisdictional transmission or distribution facilities, our participation in any RTO would be as a market participant and not as a transmission owner.  We are impacted by Order No. 2000 because our member distribution cooperatives have power requirements for which we have the responsibility of providing transmission

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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. 

          On July 31, 2002, FERC issued its proposed rules on Standard Market Design.  FERC proposes to amend its regulations to modify the proforma transmission tariff to remedy remaining undue discrimination against non-owners of transmission facilities.  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.  Any such transfer must be approved by the VSCC, and the application for transfer must include a study of the comparative costs and benefit of such transfer, including the effects of transmission congestion costs.  Each incumbent electric utility must file their application for transfer by July 1, 2003 and shall transfer ownership or control by January 1, 2005, subject to VSCC approval.  To our knowledge, this legislation should not affect our ability to transmit energy to our member distribution cooperatives through Virginia Power’s transmission system and PJM nor our ability to transmit energy from our combustion turbine facilities since the transmission assets we own are minimal.

Fuel Supply

          Nuclear

          Under the Purchase, Construction and Ownership Agreement for North Anna, the I&O Agreement, and the Nuclear Fuel Agreement between Virginia Power and us, Virginia Power, as operating agent, has the 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.  The various contracts that are in place 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.  In both 2002 and 2001, Virginia Power obtained substantially all of the nuclear fuel requirements of North Anna under long-term contracts.  Virginia Power obtained the remaining nuclear fuel needed for North Anna through spot 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 ensure optimum cost and inventory levels. 

          Coal

          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 market conditions are considered favorable.  The long-term contracts in place at December 31, 2002, expire over the period through December 2003.  We are not a direct party to any of these procurement contracts, and therefore cannot control their

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terms or duration.  In 2002 and 2001, Virginia Power obtained approximately 65% and 62%, 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. 

          Natural Gas

          Natural gas has become the preferred fuel for new electric generating facilities, causing an increase in competition for natural gas capacity.  Our three combustion turbine facilities 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 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 also targeted our primary natural gas suppliers and are negotiating the contracts needed for procurement of physical natural gas.  We are also putting in place strategies and mechanisms to financially hedge our delivery needs.  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.

REGULATION

General

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

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

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

Environmental

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

          We are subject to the Clean Air Act.  The Clean Air Act requires utilities owning fossil fuel fired power stations to, among other things, limit emissions of sulfur dioxide (“SO₂”) and nitrogen oxide (“NO_x”), one of the precursors of ground level ozone, or obtain allowances for these emissions.  Through the use of pollution control facilities, Clover is designed and licensed to operate at full capacity below the current limitations for SO₂ emissions levels and NO_x emissions.  Pollution control facilities at Clover include baghouses, wet limestone scrubbers, low NO_x burners, and fly ash collection facilities.  Virginia Power, as operator of North Anna and Clover, is responsible for environmental compliance and reporting for the facilities.  If, however, liabilities arise as a result of a failure of environmental compliance at North Anna or Clover, our respective responsibility for those liabilities is governed by the operating agreements for the facilities.  See “Power Supply Resources—North Anna” and “—Clover.” 

          The combustion turbines emit less pollutants compared to other fossil fuel generation.  The fuels used (natural gas and No. 2 distillate fuel oil) in the combustion turbines have low amounts of SO₂.  The combustion turbines are designed with low NO_x burners which control NO_x emissions when utilizing natural gas.  A water injection system also is used to control NO_x emissions when No. 2 distillate fuel oil is utilized.

          In 1998, the EPA issued a rule addressing regional transport of ground level ozone through reductions in NO_x.  The rule is commonly known as the NO_x State Implementation Plan (“SIP”) call.  The NO_x SIP call affects the District of Columbia and 22 states, including Virginia, Maryland, and Delaware and required those states to develop a plan by October 30, 2000, to reduce NO_x emissions.  The NO_x SIP call also required emissions reduction to be implemented by May 1, 2004.  Fossil fuel electric generating facilities greater than 250 mmBtu/hour will be required to reduce their NO_x emissions or obtain NO_x emissions allowances from another source.  We and Virginia Power evaluated options for meeting the NO_x SIP call as applicable to Clover.  These options included installing additional NO_x controls at Clover, purchasing emissions allowances or a combination of both.  The Clover Power Station is presently in the process of installing emissions reduction equipment on both units.  This equipment is expected to reduce NO_x emissions from Clover by 25%.  NO_x emissions allowances will be purchased to meet the NO_x reduction requirement that is not met by the new equipment.  We have commenced negotiations with Virginia Power for it to provide us with the option each year to purchase from it the necessary NO_x emissions allowances to compensate for any shortfall between our NO_x emissions allowance requirement for Clover and our portion of the regulatory NO_x  emissions allocation for Clover.

          North Anna is not impacted by the NO_x SIP call because it does not have significant NO_x emissions.  Louisa and Marsh Run each will be required to obtain allowances to emit one ton of NO_x for every ton of NO_x emitted from the facility during the ozone season (May through September) beginning in 2004.  Rock Springs is in an ozone non-attainment area and will be required to obtain allowances to emit one ton of NO_x emissions for every ton of NO_x emitted during the ozone season as well as 1.3 NO_x emissions reduction credits for every ton of potential NO_x emissions.  NO_x emission reduction credits were required to be obtained prior to the construction of Rocks Springs.  Maryland and Virginia both have a NO_x set aside pool for new sources.  This pool sets aside NO_x allowances to be distributed to new sources that are not part of the Maryland’s and Virginia’s respective NO_x budget.  We expect to receive all of the allowances necessary to operate the Rock Springs facility through at least the 2003 operating period and some allowances should be available for the Louisa and Marsh Run projects.  NO_x emissions allowances

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that are not received from the set aside pool 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 allowances in the future at commercially reasonable prices but increased NO_x emissions or increased restrictions could cause the price of allowances to be higher than we expect. 

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

          The EPA has promulgated a new regional haze rule, which affects any source that emits NO_x or SO₂ and that may contribute to the degradation of visibility in national parks and wilderness areas.  Currently, we do not know what controls, if any, may have to be installed at Clover and the three combustion turbine facilities to comply with this rule. 

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

          Clover has a Virginia water protection permit that regulates the amount of water allowed to be withdrawn from the Roanoke River.  Clover has approximately a 30-day on-site water supply reservoir to supply the facility during times of low flow when the Roanoke River is below the withdrawal level allowed in the permit.  Due to the severe drought over the last several years, the DEQ granted its consent for the Clover facility to draw water at lower than permitted river flows until completion of a study of the water needs of aquatic resources in the river.  We expect the study to be completed in December 2003.  Clover is working with the DEQ and the Virginia Department of Game and Inland Fisheries on studying the Roanoke River to determine the appropriate withdrawal rates that will protect the river’s resources.  Additional measures to ensure continued operation of the Clover facility at full or partial capacity are being pursued, including application for a special allotment of water from the Roanoke River under emergency powers delegated to the DEQ by the Governor of Virginia as a result of the drought conditions.  On October 22, 2002 the Virginia State Climatology Office reported that the Federal Drought Monitor, effective as of November 19, 2002, removed any official drought designations in Virginia. However, we continue to work with the DEQ and the Virginia Department of Game and Inland Fisheries in the event the drought conditions recur.

          Our direct capital expenditures for environmental control facilities at Clover and North Anna, excluding capitalized interest, were approximately $7.7 million and $0.1 million, respectively, in 2002.  Based on information provided by Virginia Power, our portion of direct capital expenditures for environmental control facilities planned for Clover and North Anna over the next three years is estimated to be approximately $1.7 million and $1.0 million, respectively.  These expenditures, which include amounts related to the above referenced NO_x emissions reduction plans, are included in our estimated capital expenditures for the years 2003 through 2005.  See “Management’s Discussion and Analysis of Financial Condition and Results of Operations—Liquidity and Capital Resources” in Item 7. 

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

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

          The Bush Administration has submitted legislation to the United States Congress that will require fossil fuel fired generating units to comply with more stringent pollution control standards for SO₂, NO_x, and mercury emissions.  This legislation also calls for a voluntary reduction of greenhouse gases by 18% over the next 10 years.  It is currently anticipated that there will be other legislation submitted to the United States Congress to reduce these pollutants.  While we cannot predict the outcome of this matter, we anticipate that it is unlikely that legislation will be passed requiring mandatory greenhouse gas reduction from power stations.  However, if more stringent pollution controls are ultimately imposed on our generating units additional capital expenditures may be required.

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

Nuclear

          North Anna is subject to regulation by the NRC.  Operating licenses issued by the NRC are subject to revocation, suspension, or modification, and the operation of a nuclear unit may be suspended if the NRC determines that the public interest, health, or safety so requires.  From time to time, new NRC regulations require changes in the design, operation, and maintenance of existing nuclear reactors.  The operating licenses for North Anna Units 1 and 2 were scheduled to terminate in 2018 and 2020, respectively.  In May 2001, Virginia Power applied to the NRC to renew the operating licenses for both North Anna units and to permit their operation for an additional 20 years. On March 20, 2003, the NRC approved the application.  See Notes 1 and 11 to the Consolidated Financial Statements for a discussion of other laws and regulations affecting us as a result of our ownership interest in North Anna. 

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

ITEM 2.   PROPERTIES

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

ITEM 3.   LEGAL PROCEEDINGS

          On May 9, 2001, we entered into a master power purchase and sales agreement with Enron Power Marketing, Inc.  (“EPMI”).  Pursuant to transactions we entered into under this agreement, EPMI was obligated to deliver power to us through December 31, 2003.  Following its filing for bankruptcy protection on December 2, 2001, EPMI ceased scheduling deliveries of power under the agreement beginning December 15, 2001.  We then terminated the agreement.  EPMI claims that a termination payment is due from us pursuant to the terms of the contract; however, we have disputed that obligation due to EPMI’s fraudulent conduct.  On December 11, 2002, EPMI filed an adversary proceeding against us in the United States Bankruptcy Court for the Southern District of New York seeking to collect the termination payment claimed.  We moved to dismiss that action and to compel arbitration.  On March 4, 2003, the Bankruptcy Court ordered the parties to take the dispute to nonbinding

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mediation.  The adversary action is stayed pending the mediation.  If it is ultimately determined that we owe any amounts to EPMI, such amounts are not expected to have a material impact on our financial position, results of operations, or cash flow due to our ability to collect such amounts through rates.

          Other than the FERC proceeding regarding PSE&G transmission charges 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 or financial condition, there is no other litigation pending or threatened against us.   See “Power Supply Resources—Other Power Supply Resources—PSE&G”.

ITEM 4.   SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS

None

PART II

ITEM 5.   MARKET FOR REGISTRANT’S COMMON EQUITY
AND RELATED STOCKHOLDER MATTERS

Not Applicable

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ITEM 6.   SELECTED FINANCIAL DATA

          The selected financial data below present selected historical information relating to our financial condition and results of operations.  The financial data for the five years ended December 31, 2002, are derived from our audited consolidated financial statements.  You should read the information contained in this table together with our financial statements, the related notes to the financial statements, and the discussion of this information in “Management’s Discussion and Analysis of Financial Condition and Results of Operations” in Item 7.

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

Caution Regarding Forward Looking Statements

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

Critical Accounting Policies

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

          Accounting for Rate Regulation.  We are a rate regulated entity and as a result are subject to the accounting requirements of Statement of Financial Accounting Standards (“SFAS”) 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 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 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.”  We include regulatory assets in deferred charges.  We include regulatory liabilities 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.

          Margin Stabilization Plan.  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 year.  Each quarter we adjust revenues and accounts payable-members, or accounts receivable-members, as appropriate, to reflect these adjustments. 

          Accounting for Decommissioning Costs.    We accrue decommissioning costs over the expected service life of North Anna and make periodic deposits in a trust fund, such that the fund balance will equal our estimated decommissioning cost of the contaminated portion of the plant at the time of decommissioning.  The present value

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of our future decommissioning cost is credited to the decommissioning reserve; increases are charged to our member distribution cooperatives through their rates.  Our decommissioning expense for 2002 was based on the 1998 Virginia Power site specific study which projected our estimated cost to decommission North Anna to be $91.3 million.  Annual decommissioning expenses, net of earnings on the fund, were $0.7 million in each of 2002, 2001 and 2000.  Under the original operating licenses, the decommissioning of North Anna would begin in 2018 and 2020 for North Anna Units 1 and 2, respectively.  In May 2001, Virginia Power filed an application with the NRC to renew the operating licenses for North Anna and the NRC approved the application on March 20, 2003.  The renewed licenses permit the operation of North Anna Units 1 and 2 to 2038 and 2040, respectively.  In late 2002, a new site specific study was completed assuming the operating licenses for North Anna Units 1 and 2 would be extended to 2038 and 2040, respectively, and projected our estimated costs to decommission North Anna to be $80.9 million.  See “Future Issues—Extensions of North Anna Licenses and Note 1—Summary of Significant Accounting Policies—New Accounting Pronouncement to the Consolidated Financial Statements.”

Factors Affecting Results

          Margins

          We operate on a not-for-profit basis and, accordingly, seek to generate revenues sufficient to recover our cost of service and produce margins sufficient to establish reasonable reserves, meet financial coverage requirements, and accumulate additional equity required by our board of directors.  Revenues in excess of expenses in any year are designated as net margins in our Consolidated Statements of Revenues, Expenses and Patronage Capital.  We designate retained net margins in our Consolidated Balance Sheets as patronage capital, which we assign to each of our members on the basis of its class of membership and business with us.  Any distributions of patronage capital are subject to the discretion of our board of directors and restrictions contained in our Indenture referred to below. 

          Formulary Rate

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

.

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

          The formulary rate identifies the costs that we can collect through the demand rate and the fuel factor adjustment rate, but not the actual amounts to be collected.  The actual amounts to be collected under the formulary rate typically change each year.  Specifically, the demand rate is revised automatically to recover the costs contained in our annual budget and any revisions made by the board of directors to our annual budget.  In addition, we review our energy costs at least every six months to determine whether the base energy rate and the fuel factor adjustment

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rate adequately recover our energy costs.  Because the base energy rate does not normally change, we revise the fuel factor adjustment rate accordingly. 

          Changes to the Existing Indenture.  In 2001, we entered into a supplemental indenture to the Existing Indenture that contained provisions which (1) amend the Existing Indenture by modifying several covenants and other provisions of the Existing Indenture described below with the consent of a majority of the holders of the obligations outstanding under the Indenture, and (2) further amend and restate the Existing Indenture to reflect the prior amendments and release the lien of the Existing Indenture on our property when all obligations under the Existing Indenture issued prior to September 1, 2001, cease to be outstanding or when the holders of those obligations consent to the release of the lien.  We refer to the Existing Indenture as amended by the first amendments as the “Amended Indenture” and the Amended Indenture as amended and restated as the “Restated Indenture.”  References to the “Indenture” mean the Existing Indenture, the Amended Indenture or the Restated Indenture whichever is in effect.  The Amended Indenture became effective on December 17, 2002 (the “Amendment Date”). 

          The Amended Indenture modifies the covenant obligating us to establish and collect rates at a specified level and the restrictions on the issuance of additional bonds and distributions to our members.  The Amended Indenture also eliminates covenants restricting our investments and short-term indebtedness and the obligation to fund reserves known as a depreciation deposits. 

          Existing Indenture.  Prior to the Amendment Date, subject to any necessary regulatory approvals, the Existing Indenture required us to establish and collect rates for the use or the sale of the output, capacity, or service of our electric generation, transmission, and distribution system which were reasonably expected to yield margins for interest for the 12-month period commencing with the effective date of the rates equal to at least 1.20 times total interest charges during that 12-month period.  Since 1992, we have always achieved a margins for interest ratio under the Existing Indenture of at least 1.20 times. 

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

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

          Amended Indenture.  Pursuant to the Amended 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 Amended 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 Amended Indenture.  We believe that our formulary rate, and the rates and charges established under the wholesale power contracts with our member distribution cooperatives, will enable us to achieve the required margins for interest.  Interest charges under the Amended Indenture are calculated in the same manner as under the Existing Indenture with the exclusion of capitalized interest.  Margins for interest under the Amended Indenture, equal the sum of:

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          Under the Amended Indenture, interest charges 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. 

          Restated Indenture.    The Restated Indenture includes all of the amendments set forth in the Amended Indenture and releases the lien of the Amended Indenture.  The Restated Indenture will become effective when all obligations under the Existing Indenture issued prior to September 1, 2001, cease to be outstanding or when the holders of those obligations consent to the release of the lien of the Amended Indenture (“Release Date”).  We do not anticipate that the Release Date will occur prior to December 2003. 

          After the Release Date, the Restated Indenture will require us, subject to any necessary regulatory or judicial approval, to establish and collect rates reasonably expected to yield margins for interest for each fiscal year equal to 1.10 times total interest charges for the fiscal year.  Interest charges under the 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.  Margins for interest under the Restated Indenture are calculated in the same manner as under the Amended Indenture. 

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

          Margin Stabilization Plan.  We have a Margin Stabilization Plan that allows us to review our actual capacity-related cost 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 year.  Each quarter we adjust revenues and accounts payable-members or accounts receivable-members, as appropriate, to reflect these adjustments.  See “Business—Member Distribution Cooperatives—Wholesale Power Contracts” in Item 1.  In 2002, under our Margin Stabilization Plan, we reduced revenues from power sales by $3.6 million and increased accounts payable—members by the same amount.  There was no adjustment to revenues from power sales to our member distribution cooperatives under our Margin Stabilization Plan in 2001 or 2000. 

          Strategic Plan Initiative.  In the late 1990’s, the possibility of retail competition and projected lower market power rates caused us to focus on reducing our costs.  Specifically, we sought to lower our costs so that our member distribution cooperatives could set rates for power at or below market rates for power by the time

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competition for retail customers began in Virginia in 2004.  See “Future Issues—Competition and Changing Regulations.” Our efforts to meet this objective became known as the “Strategic Plan Initiative.” Because our estimates of future market rates for power constantly change, we monitor and periodically re-evaluate our methods and progress in achieving the goal of the Strategic Plan Initiative to identify and implement any appropriate changes. 

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

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

          Our projections of future market prices of power are key factors in determining our progress in meeting the Strategic Plan Initiative’s objective. Beginning in 1999, our projections of market prices indicated a rise in future power costs.  In June 2001, based on then current market projections, we believed that the $160.3 million we had accumulated through the Strategic Plan Initiative since 1998 and held as cash or investments, or already applied to reduce our indebtedness, was sufficient to reduce our costs to a level which would enable the member distribution cooperatives’ rates for power to their customers to be at or below projected market rates by January 1, 2004.  As a result, we ceased recording accelerated depreciation of our generating facilities effective June 1, 2001. From 1999 through 2001, we spent $89.2 million (including premiums and discounts) of the $160.3 million accumulated through the Strategic Plan Initiative to purchase $86.2 million of indebtedness outstanding under the Indenture.  In December 2002, we used $71.1 million, the remaining balance of funds available to us under the Strategic Plan Initiative funds, to refund a portion of our First Mortgage Bonds, 1992 Series A, due 2022.  Based on our most recent financial forecast, we believe that the objective of the Strategic Plan Initiative will be met.

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

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

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

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

Results of Operations

          Operating Revenues

          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 Trading, Inc.  Our operating revenues by type of purchaser for the past three years were as follows:

          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 bill energy to each of our member and non-member customers based on the total megawatt-hours (“MWh”) delivered to them each month and, with respect to our member distribution cooperatives, charge them an amount based on the base energy rate and fuel factor adjustment rate.  Because energy cannot be stored, 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.  See “Factors Affecting Results—Formulary Rate” above, and “General—Member Distribution Cooperatives—Wholesale Power Contracts” in Item 1.  This committed available energy at any time is referred to as capacity.  We use our generating facilities and rely on power purchase contracts to satisfy substantially all of our member distribution cooperatives’ capacity requirements.  We bill capacity to each of our member distribution cooperatives monthly through our demand rate which is based on our budgeted capacity costs.  The quantity billed to each member distribution cooperative is 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”). 

          Sales to Member Distribution Cooperatives

          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.”

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          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:

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

          Weather affects the demand for electricity.  Relatively higher or lower temperatures tend to increase the demand for energy to use heating and air conditioning systems.  Mild weather generally reduces the demand because heating and air conditioning systems are operated less.  Other factors affecting our member distribution cooperatives’ consumers’ demand for energy include the amount, size, and usage of electronics and machinery and the expansion of operations among their commercial and industrial customers.

          2002 Compared to 2001.  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.  See “—2001 compared to 2000.”  We reduced our demand rate effective April 1, 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 Note 1 — “Summary of Significant Accounting Policies” in Item 8.

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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.

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

          Our average energy rate (including our base energy rate and our fuel factor adjustment rate) in 2001 increased 63.9% over 2000 as a result of changes in our fuel factor adjustment rate.  We increased our fuel factor adjustment rate effective April 1, 2001, to recover energy costs that we previously incurred but which we did not fully recover under the base energy rate and existing fuel adjustment rate (a balance of $30.8 million as of March 31, 2001), and to recover future energy costs that we expected to be higher than originally budgeted.

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

          Sales to TEC Trading.  TEC Trading was established in 2001 and is our sole Class B member.  During 2002, sales to TEC Trading were $2.6 million compared with no sales to it in 2001.  Our sales to TEC Trading in 2002 related primarily to the sales of excess purchased energy. Prior to 2002, we would have sold any excess power directly to the PJM power pool.  Energy Sales in MWh to TEC Trading for 2002 were 67,360 MWh.  There were no sales in 2001 or 2000.

          Sales to Non-Members.    Sales to non-members consist of sales of excess purchased energy and sales of excess generated energy from Clover.  We sell excess purchased energy 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 “Business—Power Supply Resources—Purchased Power” in Item 1.  Non-member revenues for the year ended December 31, 2002 were lower than in 2001 by $7.6 million or 71.0% primarily because a portion of sales we previously made to PJM were made to TEC Trading and because of a decrease in excess energy sales volume.  Our non-members energy sales in MWh for 2002, 2001 and 2000 were 93,721, 268,609, and 151,332, respectively.

          Non-member revenues for the year ended December 31, 2001, increased $3.6 million over 2000 primarily as a result of an increase in sales of energy to PJM.  During the first eight months of 2001 we purchased the majority of the energy for our member distribution cooperatives located on the Delmarva Peninsula under an energy contract that matched those members’ needs for power.  Beginning September 1, 2001, we met those needs through a combination of forward contracts and market purchases.  During 2000, we purchased fixed amounts of power to meet our peak needs and sold the amounts not needed by those members to PJM.

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          Operating Expenses

          We have an 11.6% undivided ownership interest in the North Anna and a 50% undivided ownership interest in Clover.  In addition to power generated at Clover and North Anna, we purchase power from Virginia Power, PSE&G, Williams, Constellation and others.  See “Business—Power Supply Resources—Other Power Supply Resources” in Item 1.  Our energy supply for the past three years was as follows:

          Market forces influence the structure of new power supply contracts we enter into.  To serve the Delmarva Peninsula, we rely on power purchase agreements to provide the capacity to meet our member distribution cooperatives’ capacity requirements.  See “Business—Power Supply Resources—Other Power Supply Resources” in Item 1.  To meet our member distribution cooperatives’ energy requirements on the Delmarva Peninsula, we purchase energy from the market or utilize the PJM power pool when economical.  See “Future Issues—Reliance on Energy Purchases.”  In mainland Virginia, we satisfy the majority of our member distribution cooperatives’ capacity and energy requirements through our ownership interests in Clover and North Anna.

          Generating facilities, particularly nuclear generating facilities such as North Anna, generally have relatively high fixed costs.  Nuclear facilities operate with relatively low variable costs due to lower fuel costs and technological efficiencies.  Owners of nuclear and other power plants incur the embedded fixed costs of these facilities whether or not the units operate.  When either North Anna or Clover is off-line, we must purchase replacement energy from either Virginia Power, which is more costly, or the market, which may be more or less costly.  As a result, our operating expenses, and consequently our rates to our member distribution cooperatives, are significantly affected by the operations of North Anna and Clover.  The output of North Anna and Clover for the past three years as a percentage of the maximum dependable capacity rating of the facilities was as follows:

          North Anna.  North Anna Unit 1 operated with no outages from October 10, 2001 to December 31, 2002.  On September 10, 2001, Unit 1 began a scheduled refueling outage and was returned to service on October 10, 2001.  Prior to September 10, 2001, the unit had been on–line for 487 consecutive days.  Before beginning a scheduled maintenance outage on March 12, 2000, North Anna Unit 1 ran for 522 consecutive days without outage.  The unit was returned to service on April 8, 2000.

          North Anna Unit 1 was removed from service on February 23, 2003, for a reactor vessel head replacement and scheduled refueling. We anticipate that the unit will be returned to service during the second quarter of 2003.

          North Anna Unit 2 was removed from service on September 8, 2002, for a scheduled 30-day refueling outage and inspection.  The inspection uncovered deposits of crystallized boric acid on top of the unit’s reactor

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vessel head.  The unit outage was extended and a new vessel head was installed.  The unit was returned to service on February 2, 2003. Prior to that outage the unit had been on-line for 267 consecutive days.  Before beginning a scheduled refueling outage on March 11, 2001, North Anna Unit 2 was on-line 340 days.  The unit was returned to service on April 10, 2001. The unit was brought off-line on October 28, 2001, for inspection and repair and returned to service on December 15, 2001. North Anna Unit 2 experienced only minor unscheduled outages during the year 2000.

          Clover.  During 2002, Clover Unit 1 had a scheduled maintenance outage and was off-line from March 1, 2002 to May 1, 2002.  In addition, the unit experienced minor unscheduled outages in 2002.  Clover Unit 1 was off-line from March 1, 2002 to May 1, 2002 for a scheduled maintenance outage.  During 2001, Clover Unit 1 was off-line for 13 days in March for a scheduled maintenance outage.  The unit had previously been on-line for 276 consecutive days.  At December 31, 2001, Clover Unit 1 had been on-line for 85 consecutive days following an unscheduled maintenance outage.  Clover Unit 1 was off-line for 15 days in April 2000 for a scheduled maintenance outage.

          Clover Unit 2 was removed from service on March 15, 2003, for scheduled maintenance and we anticipate that the unit will be returned to service during the second quarter of 2003.

          On February 16, 2002, the load on Clover Unit 2 was reduced to 125 MW due to a forced draft fan motor failure and Unit 2 was returned to service on March 2, 2002.  The unit was removed from service on April 20, 2002, for a scheduled maintenance outage and was returned to service on May 3, 2002.  In addition, the unit experienced minor unscheduled outages during 2002.  During 2001, Clover Unit 2 was off-line for 15 days in April 2001 for a scheduled maintenance outage and had been on-line for 241 consecutive days prior to that. Clover Unit 2 experienced only minor outages during 2000.

          The components of our operating expenses for the years ended December 31, 2002, 2001, and 2000, 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 Trading 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.

          2002 Compared to 2001.  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.  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

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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 $35.1 million, or 66.2%, 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.  In addition, depreciation, amortization and decommissioning decreased in 2002 as a result of a $17.2 million change in amortization of regulatory liabilities.  We established a revenue deferral plan in 2001 that added $11.4 million to depreciation, amortization and decommissioning expense.  We recognized this revenue in 2002, reducing depreciation, amortization and decommissioning expense by $11.4 million.  See “Results of Operations—Operating Revenues—Sales to Member Distribution Cooperatives—2002 Compared to 2001” and “—2001 Compared to 2000.”  In 2002 we also established a $5.6 million revenue deferral plan to cover expenses we expected to incur in 2003 associated with the replacement of the reactor vessels heads at North Anna. See “Factors Affecting Results—Strategic Plan Initiative.”  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.  See “Business—Power Supply Resources—North Anna” in Item 1.

          2001 Compared to 2000.  Our aggregate operating expenses in 2001 increased $65.1 million, or 17.2%, over those incurred in 2000 because of an increase in energy costs, which we recovered through our base energy rate and the fuel factor adjustment rate. Primarily as a result of rising energy prices, our average cost of purchased power rose 34.3% in 2001 as compared to 2000.  The average cost of fuel used to generate power at Clover and North Anna increased 30.8% in 2001 as compared to 2000 because of the higher price of coal and fuel inventory adjustments.  These increases were offset by a $41.2 million, or 43.7%, decrease in depreciation, amortization, and decommissioning expense because we ceased recording accelerated depreciation on our generating facilities effective June 1, 2001.  Accelerated depreciation for 2001 and 2000 was $18.5 million and $65.0 million, respectively.  Depreciation, amortization and decommissioning expense was increased $11.4 million in 2001 by the establishment of a revenue deferral plan.

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

          Other Items

          Other Income/(Expense), net.  The major components of our other income/(expense), net for the years ended December 31, 2002, 2001, and 2000, were as follows:

          Other income/(expense), 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.

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          Other income/(expense), net increased in 2001 by $1.3 million, as compared to 2000 mainly due to an increase in gains on the sale of investments.

          Investment Income.  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.”

          Investment income decreased in 2001 by $1.0 million, or 23.7%, as compared to 2000 also because of a decrease in the interest rate on our investments.  Our average balance of investments-other, and cash and cash equivalents increased from 2001 to 2002 due to our September 2001 $215.0 million issuance of additional indebtedness under the Indenture.  During the first nine months of 2001 we liquidated a considerable amount of our investments and cash equivalents to fund payments made in connection with the combustion turbine facilities.  During the fourth quarter of 2001, a portion of the proceeds from the $215.0 million issuance were utilized to fund these payments and other costs associated with the development and construction of the combustion turbines facilities.  See “Liquidity and Capital Resources—Sources—Financings.”

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

          The major components of interest charges, net for the years ended December 31, 2002, 2001, and 2000, were as follows: