Old Dominion Electric Cooperative 10-K 2006 FY Annual report

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-K

(Mark One)

x ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the fiscal year ended December 31, 2006

OR

¨ TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the transition period from            to            

Commission file number 000-50039

OLD DOMINION ELECTRIC COOPERATIVE

(Exact name of Registrant as specified in its charter)

VIRGINIA	23-7048405
(State or other jurisdiction of incorporation or organization)	(I.R.S. employer identification no.)
4201 Dominion Boulevard, Glen Allen, Virginia	23060
(Address of principal executive offices)	(Zip code)

(804) 747-0592

(Registrant’s telephone number, including area code)

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

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

6.25% 2001 Series A Bonds due 2011

Indicate by check mark if the Registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act?    Yes  ¨    No  x

Indicate by check mark if the Registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Act.    Yes  ¨    No  x

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

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

Indicate by check mark whether the Registrant is a large accelerated filer, an accelerated filer or a non-accelerated filer (as defined in Exchange Act Rule 12b-2).    Large accelerated filer  ¨    Accelerated filer  ¨    Non-accelerated filer  x

Indicate by check mark whether the Registrant is a shell company (as defined in Exchange Act Rule 12b-2).    Yes  ¨    No  x

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

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

Documents incorporated by reference: NONE

OLD DOMINION ELECTRIC COOPERATIVE

2006 ANNUAL REPORT ON FORM 10-K

Item Number		Page Number
	PART I
1.	Business	1
1A.	Risk Factors	15
1B.	Unresolved Staff Comments	18
2.	Properties	19
3.	Legal Proceedings	22
4.	Submission of Matters to a Vote of Securities Holders	25
	PART II
5.	Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities	25
6.	Selected Financial Data	26
7.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	28
7A.	Quantitative and Qualitative Disclosures About Market Risk	47
8.	Financial Statements and Supplementary Data	50
9.	Changes in and Disagreements with Accountants on Accounting and Financial Disclosure	79
9A.	Controls and Procedures	79
9B.	Other Information	79
	PART III
10.	Directors and Executive Officers of the Registrant	80
11.	Executive Compensation	83
12.	Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters	90
13.	Certain Relationships and Related Transactions, and Director Independence	90
14.	Principal Accountant Fees and Services	90
	PART IV
15.	Exhibits and Financial Statement Schedules	91
	SIGNATURES

PART I

ITEM 1. BUSINESS

General

Old Dominion Electric Cooperative (“ODEC” or “we” or “our”) was incorporated under the laws of the Commonwealth of Virginia in 1948 as a not-for-profit power supply cooperative. We were organized for the purpose of supplying the power our member distribution cooperatives require to serve their customers on a cost-effective basis. Through our member distribution cooperatives, we served more than 535,000 retail electric consumers (meters) representing a total population of approximately 1.3 million people in 2006. We provide this power pursuant to long-term, all-requirements wholesale power contracts. See “—Member Distribution Cooperatives” below.

We supply our member distribution cooperatives’ power requirements, consisting of capacity requirements and energy requirements, through a portfolio of resources including generating facilities, power purchase contracts, and forward, short-term and spot market energy purchases. Our generating facilities are fueled by a mix of coal, nuclear, natural gas, and fuel oil. See “—Power Supply Resources” below and “Properties” in Item 2 for a description of these resources.

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

Our member distribution cooperatives primarily serve suburban, rural and recreational areas. These areas predominantly reflect stable growth in residential capacity and energy requirements both in terms of power sales and number of customers. See “—Members’ Service Territories and Customers” below. Under state restructuring legislation, nearly all customers of our member distribution cooperatives are able to select their power suppliers. The member distribution cooperatives are the exclusive providers of distribution services and, at least initially, the default providers of power to their customers in their service territories. See “Regulation—Competition” below.

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

We are not a party to any collective bargaining agreement. We had 103 employees as of March 1, 2007.

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

Cooperative Structure

In general, a cooperative is a business organization owned by its members, which are also either the cooperative’s wholesale or retail customers. Cooperatives are designed to give their members the opportunity to satisfy their collective needs in a particular area of business more effectively than if the members acted independently. As not-for-profit organizations, cooperatives are intended to provide services to their members on a cost-effective basis, in part by eliminating the need to produce profits or a return on equity in excess of required

margins. Margins not distributed to members constitute patronage capital, a cooperative’s principal source of equity. Patronage capital is held for the account of the members without interest and returned when the board of directors of the cooperative deems it appropriate to do so.

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

Our Class A members are electric distribution cooperatives. Electric distribution cooperatives own and maintain nearly half of the distribution lines in the United States and serve three-quarters of the United States’ land mass. There are currently approximately 870 electric distribution cooperatives in the United States. Historically, electric distribution cooperatives have owned and operated distribution systems to supply the power requirements of their retail customers. See also “—Competition and Changing Regulations” below.

Member Distribution Cooperatives

General

Our member distribution cooperatives provide electric services, consisting of power supply, transmission services, and distribution services (including metering and billing) to residential, commercial, and industrial customers in 70 counties in Virginia, Delaware, Maryland, and West Virginia. The member distribution cooperatives’ distribution business involves the operation of substations, transformers, and electric lines that deliver power to customers. Three of our member distribution cooperatives provide electric services on the Delmarva Peninsula: A&N Electric Cooperative in Virginia, Choptank Electric Cooperative in Maryland, and Delaware Electric Cooperative in Delaware. Our remaining nine members, which serve the Virginia mainland, are: BARC Electric Cooperative, Community Electric Cooperative, Mecklenburg Electric Cooperative, Northern Neck Electric Cooperative, Northern Virginia Electric Cooperative (“NOVEC”), Prince George Electric Cooperative, Rappahannock Electric Cooperative, Shenandoah Valley Electric Cooperative, and Southside Electric Cooperative. Shenandoah Valley Electric Cooperative also serves a small portion of West Virginia. The member distribution cooperatives are not our subsidiaries, but rather our owners. We have no interest in their properties, liabilities, equity, revenues, or margins.

Wholesale Power Contracts

We sell power to our member distribution cooperatives under “all-requirements” wholesale power contracts. Each contract obligates us to sell and deliver to the member distribution cooperative, and obligates the member distribution cooperative to purchase and receive from us, all power that it requires for the operation of its system, with limited exceptions, to the extent that we have the power and facilities available to do so. Each of these wholesale power contracts is effective through 2028 and continues in effect beyond 2028 until either party gives the other at least three years notice of termination. See “—Northern Virginia Electric Cooperative” below for a description of negotiations and proceedings related to the wholesale power contract of one of our members.

There are two principal exceptions to the all-requirements obligations of the parties. First, each Virginia mainland member distribution cooperative may purchase power allocated to it from the Southeastern Power Administration (“SEPA”), which operates hydroelectric facilities in Virginia. The total allocation of power from SEPA to the member distribution cooperatives in 2006 was 76 megawatts (“MW”) plus associated energy. This power represented approximately 3.0% of our total member distribution cooperatives’ peak capacity requirements and approximately 1.3% of our total member distribution cooperatives’ energy requirements. In 2006, the energy received by our member distribution cooperatives from SEPA was comparable to that received in 2005. 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 2006.

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Each member distribution cooperative is required to pay us monthly for power furnished under its wholesale power contract in accordance with our formulary rate. The formulary rate, which has been filed with and accepted by the Federal Energy Regulatory Commission (“FERC”), is designed to recover our total cost of service and create a firm equity base. See “Management’s Discussion and Analysis of Financial Condition and Results of Operations—Factors Affecting Results—Formulary Rate” in Item 7. More specifically, the formulary rate is intended to meet all of our costs, expenses and financial obligations associated with our ownership, operation, maintenance, repair, replacement, improvement, modification, retirement and decommissioning of our generating plants, transmission system or related facilities, as well as all of our costs, expenses and financial obligations relating to the acquisition and sale of power or related services that we provide to our member distribution cooperatives under the wholesale power contracts, including:

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

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

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

• all amounts we are required to pay under any contract to which we are a party;

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

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

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

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

During the term of each wholesale power contract, each member distribution cooperative will not, without obtaining our written consent, take or permit to be taken any steps for reorganization or dissolution, consolidation

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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:

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

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

Possible Changes to Power Supply Arrangements with Member Distribution Cooperatives

We strive to supply our member distribution cooperatives’ power requirements in an efficient and cost effective manner. We consistently explore new ways to serve our member distribution cooperatives better and respond to the challenges we face. These efforts have taken several forms in recent years. In 2004, we developed a plan to reorganize our ownership and power supply arrangements with our members. In addition, we have evaluated possible modifications to our wholesale power contracts with our member distribution cooperatives to address the desire of some of our member distribution cooperatives for additional flexibility in meeting their power requirements. We also have attempted to resolve outstanding issues with our largest member distribution cooperative, NOVEC, in proceedings relating to the potential reorganization and in discussions regarding possible modifications to our wholesale power contracts.

New Dominion

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

Structurally, the reorganization contemplated by the reorganization agreement would result in all of our member distribution cooperatives exchanging their membership interests in ODEC for a membership interest in New Dominion. All of their equity in ODEC would be transferred to New Dominion in return for an equal amount of equity in New Dominion. As a result, New Dominion would become our sole member.

As part of the reorganization, the reorganization agreement requires that New Dominion enter into a take-or-pay power sales contract with us, pursuant to which New Dominion would agree to purchase and receive 100% of the output and services of our power supply resources and to pay 100% of our costs, including amounts sufficient for us to meet the rate covenant under our Indenture of Mortgage and Deed of Trust, dated as of May 1, 1992, with Crestar Bank (predecessor to SunTrust Bank), as trustee (the “Indenture”). Payments required under this contract would not be excused by any event, including our inability or failure to perform. The reorganization agreement further provides that the wholesale power contracts we have with our member distribution cooperatives would be assigned to and assumed by New Dominion. TEC would withdraw as a member in conjunction with the completion of the reorganization and our power sales relationship with TEC also would be terminated at that time.

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

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The formation of New Dominion and the consummation of the reorganization will have almost no impact on our consolidated financial statements. We currently do not anticipate transferring ownership of any of our assets as part of the reorganization, with one exception. We will transfer to New Dominion, at the direction of our members, any prepayments for electric service held by us as of the reorganization date. These prepayments totaled approximately $44.2 million at December 31, 2006. As described above, we also will continue to be responsible for all our existing indebtedness following the reorganization. The amount of our members’ equity will remain unchanged although the number of members we have will be reduced from thirteen to one.

The only change in our liquidity immediately following the reorganization will be the entry into a mutual credit agreement with New Dominion. The mutual credit agreement will permit either ODEC or New Dominion to request from the other an extension of credit in the form of loans, guarantees, or other credit support. This mutual credit agreement will not be a committed credit facility and neither ODEC nor New Dominion will be required to extend credit to the other thereunder.

If consummated, we anticipate that following the reorganization New Dominion would conduct physical and financial power and gas procurement activities and purchase, in the markets, the power needed to supply our member distribution cooperatives over and above that obtained from us. New Dominion would not engage in speculative marketing or trading activities. We would expect to continue to perform all of our other current operations, including our obligations to operate and maintain our generating facilities. Future generating resources, including purchased power agreements, could be owned by either New Dominion or ODEC, depending upon our analysis of the advantages and disadvantages at the time the resources were acquired. New Dominion would be a taxable cooperative; however, no change would occur in our status as an organization exempt from federal income tax a result of the reorganization. We would continue to be regulated by federal or state governmental authorities in the same manner as we currently are, and we expect that New Dominion would be regulated in a similar manner.

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

Several conditions must be satisfied before the reorganization will occur, including conditions relating to obtaining all necessary regulatory approvals. NOVEC has intervened in proceedings with FERC relating to approvals required for the consummation of the reorganization. See “Legal Proceedings—FERC Proceedings Relating to Potential Reorganization” in Item 3. Because several of these conditions are beyond our control, we cannot determine when or if the reorganization will occur. Even if all other conditions to the reorganization were satisfied, we would have the right to terminate the reorganization agreement because the conditions to closing were not satisfied prior to a specified date in the reorganization agreement. We currently anticipate, however, that we and our member distribution cooperatives will continue to pursue satisfaction of the conditions to the reorganization.

Possible Extensions and Modifications of Wholesale Power Contracts

Over the past several years, we have evaluated the potential of providing our member distribution cooperatives with greater flexibility in their power supply options in the future. In particular, we have had discussions with NOVEC about changing the nature of its wholesale power contract with us from an all-requirements contract to a partial-requirements contract. We have always approached discussions regarding our wholesale power contracts from the perspective that we would never amend or modify the wholesale power contracts in any way that could adversely affect our financial condition or that of any of our member distribution cooperatives. Similarly, no member distribution cooperative, including NOVEC, has ever sought to be relieved of its obligations relating to our existing generating facilities, including debt service and other costs related or allocable to these facilities.

In February 2007, our member distribution cooperatives other than NOVEC agreed on a framework for the potential extension and modification of their wholesale power contracts. The framework provides that these member distribution cooperatives would extend their contracts for a term that would end approximately 45 years

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following the date of the effectiveness of the modifications. The framework further provides that the wholesale power contracts would be modified to permit – but not obligate – these member distribution cooperatives to purchase the greater of five percent of their power requirements or five megawatts from other suppliers. These member distribution cooperatives also would be permitted to purchase power from other suppliers in limited circumstances following approval by our board of directors. This framework was agreed upon in principle but is subject to satisfactory resolution of several other matters related to the modifications, including the implementation of amendments to our bylaws to require a supermajority approval of our board of directions before we take action in some circumstances. The possible extensions and modifications of the wholesale power contracts of these member distribution cooperatives are not definitive and any final agreement relating to these matters would be subject to approvals by our board of directors and the boards of directors of the applicable member distribution cooperatives, among others.

NOVEC

Although we have discussed potential changes to its wholesale power contract for several years, NOVEC has not agreed with our other member distribution cooperatives regarding this framework for the potential extension and modification of our wholesale power contract with it. The entry into modified wholesale power contracts with our other member distribution cooperatives would not affect our current wholesale power contract with NOVEC. NOVEC’s wholesale power contract would continue in effect in accordance with its current terms and conditions described above.

In 2006, NOVEC filed an action with FERC to reform its wholesale power contract. For some time prior to the filing, NOVEC had made known that it might bring such an action before FERC or the Virginia State Corporation Commission (“VSCC”). FERC denied NOVEC’s 2006 complaint and its subsequent request for a rehearing. NOVEC has appealed these orders. See “Legal Proceedings — Northern Virginia Electric Cooperative” in Item 3 for a discussion of these proceedings.

While we cannot predict the ultimate resolution of these proceedings, we do anticipate that we will engage in discussions with NOVEC about the possible termination of its wholesale power contract and its withdrawal as a member of Old Dominion. As in the case of any modification of the wholesale power contracts, we will not consider any termination of the wholesale power contract or take any other action in connection with the resolution of our issues with NOVEC that we believe in any way could adversely affect our financial condition or that of our other member distribution cooperatives.

TEC

TEC was formed for the primary purpose of purchasing from us, to sell in the market, energy that is not needed to meet the actual needs of our member distribution cooperatives, acquiring natural gas and forward purchase contracts to hedge the price of natural gas to supply our combustion turbine facilities, and to take advantage of other power-related trading opportunities in the market which will help lower our member distribution cooperatives’ costs. TEC does not engage in speculative trading.

TEC is owned by our member distribution cooperatives, and currently is our only Class B member. As a member, TEC is entitled to receive patronage capital distributions from us based on our allocation of margins to Class B members and the amount of its business with us. We are continuing to evaluate the potential reorganization of our relationships with our members, including TEC. See “—New Dominion” above.

We have a power sales contract with TEC, under which TEC purchases power from us that we do not need to meet the actual needs of our member distribution cooperatives for resale to the market and sells this power to the market under market-based rate authority granted by FERC. To fully participate in power-related markets, TEC must maintain credit support sufficient to meet delivery and payment obligations associated with its power trades. To assist TEC in maintaining this credit support, we have agreed to guarantee up to a maximum of $60.0 million of TEC’s delivery and payment obligations associated with its power trades. As of December 31, 2006, we had issued guarantees for up to $11.0 million of TEC’s obligations and TEC has liabilities of $0.2 million to vendors related to these guarantees.

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In 2006, TEC purchased from us, and subsequently sold to the market, 585,887 megawatt-hours (“MWh”) of energy. In 2006, we purchased from TEC $43.4 million of natural gas to fuel our combustion turbine facilities. We charged TEC $12,000 for administrative services we performed for TEC in 2006.

In accordance with Financial Accounting Standards Board Interpretation No. 46R, “Consolidation of Variable Interest Entities, an Interpretation of Accounting Research Bulletin No. 51” (“FIN 46”), TEC is considered a variable interest entity for which we are the primary beneficiary. We became the primary beneficiary of TEC in 2001. We first consolidated TEC’s financial position as of December 31, 2004, and beginning January 1, 2005, TEC’s operations were also consolidated as a result of the adoption of FIN 46. For financial reporting purposes, we have eliminated all intercompany balances and transactions in consolidation. The assets and liabilities and non-controlling interest of TEC are recorded at carrying value and the net assets consolidated were $11.0 million and $25.1 million at December 31, 2006, and December 31, 2005, respectively. The decrease in the carrying value of the net assets consolidated is due to the decrease in the number of TEC’s natural gas futures contracts held by TEC, and the fair value of these contracts.

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 each grant retail customers the right to choose their power supplier. The laws of each state maintain 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 respective service territories. See “—Regulation—Competition” below.

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

Our member distribution cooperatives’ service territories are diverse and encompass primarily suburban, rural and recreational areas. These territories predominantly reflect historically stable growth in residential capacity and energy requirements both with respect to power sales and number of customers. These customers’ requirements for capacity and energy generally are seasonal and increase in winter and summer as home heating and cooling needs increase and then decline in the spring and fall as the weather becomes milder. Our member distribution cooperatives also serve major industries, which include manufacturing, fisheries, agriculture, forestry and wood products, paper, travel, and trade. Additionally, our member distribution cooperatives can expand their service territories through acquisition.

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Our member distribution cooperatives’ sales of energy in 2006 totaled approximately 10,562,609 MWh. These sales were divided by type as follows:

Customer Class	Percentage of MWh Sales		Percentage of Customers
Residential	65.0	%	92.2	%
Commercial and industrial	33.8		7.0
Other	1.2		0.8

From 2001 through 2006, our member distribution cooperatives experienced an average annual compound growth rate of approximately 3.5% in the number of customers and an average annual compound growth rate of 3.9% in energy sales measured in MWh.

Revenues from the following member distribution cooperatives equaled or exceeded 10% of our total revenues in 2006:

Member Distribution Cooperatives	Revenues		Percentage of Total Revenues
	(in millions)
Northern Virginia Electric Cooperative	$	214.5	28.7	%
Rappahannock Electric Cooperative		163.7	21.9
Delaware Electric Cooperative		80.0	10.7

The member distribution cooperatives’ average number of customers per mile of energized line has increased approximately 5.7% since 2001 to approximately 9.5 customers per mile in 2006. System densities of our member distribution cooperatives in 2006 ranged from 6.2 customers per mile in the service territory of BARC Electric Cooperative to 21.1 customers per mile in the service territory of NOVEC. In 2006, the average service density for all distribution electric cooperatives in the United States was approximately 7.0 customers per mile.

POWER SUPPLY RESOURCES

General

We provide power to our members through a combination of our interests in the Clover Power Station (“Clover”), North Anna Nuclear Power Station (“North Anna”), Louisa generating facility (“Louisa”), Marsh Run generating facility (“Marsh Run”), Rock Springs generating facility (“Rock Springs”), distributed generation facilities, long-term and short-term physically-delivered forward power purchase contracts and spot purchases of power in the open market. Our power supply resources for the past three years have been as follows:

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	Year Ended December 31,
	2006			2005			2004
	(in MWh and percentages)
Generated:
Clover	3,470,018	27.4	%	3,190,796	24.9	%	3,342,530	29.2	%
North Anna	1,752,349	13.8		1,784,512	14.0		1,718,545	15.0
Louisa	221,400	1.7		200,535	1.6		212,087	1.9
Marsh Run	232,330	1.8		243,864	1.9		25,761	0.2
Rock Springs	55,692	0.5		119,387	0.9		125,244	1.1
Distributed generation	719	—		2,312	—		354	—
Total Generated	5,732,508	45.2		5,541,406	43.3		5,424,521	47.4
Purchased:
Total Purchased	6,956,454	54.8		7,260,938	56.7		6,005,984	52.6
Total Available Energy	12,688,962	100.0	%	12,802,344	100.0	%	11,430,505	100.0	%

Typically, our member distribution cooperatives’ peak demand for energy occurs in the summer. This peak is due in large part to the summer air conditioning requirements of the member distribution cooperatives’ customers, which reflects the large residential component of our total capacity requirements. In 2006, the peak demand for the member distribution cooperatives’ customers occurred in August.

Clover and North Anna satisfied approximately 26.3% of our capacity requirements and 41.2% of our energy requirements in 2006. Louisa, Marsh Run and Rock Springs provided 18.8%, 19.2%, and 12.9% of our 2006 capacity requirements, respectively, and 1.7%, 1.8%, and 0.5%, respectively, of our 2006 energy requirements. In 2006, we obtained the remainder of our capacity and energy requirements from numerous suppliers under various long-term and short-term physically-delivered forward power purchase contracts and spot market purchases. Most of our long-term power purchase contracts will expire by the end of 2010. See “—Power Purchase Contracts” below.

Power Supply Resources

Generating Facilities

We have ownership interests in five electric generating facilities plus distributed generation facilities. For a description of these facilities see “Properties” in Item 2. In 2006, these facilities provided 45.2% of our energy requirements.

Power Purchase Contracts

In 2006, we purchased approximately 54.8% of our total energy requirements. These energy requirements were provided principally by neighboring utilities and power marketers through long-term and short-term physically-delivered power purchase contracts and purchases of energy in the spot markets.

Our most significant long-term power purchase arrangements are with Virginia Electric & Power Company (“Virginia Power”), the operator and co-owner of Clover and North Anna. We have an agreement with Virginia Power which grants us the right, but not the obligation, to purchase energy at a price determined by reference to a specified natural gas index (the Operating and Power Sales Agreement or “OPSA”). In addition, we have other contractual arrangements with Virginia Power which permit us to purchase reserve capacity and energy. We intend to purchase our reserve capacity requirements for Clover and North Anna from Virginia Power under these arrangements until either the date on which all facilities at North Anna have been retired or decommissioned, or the

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date we have no interest in North Anna, whichever is earlier. The purchase price we pay for any reserve energy purchased under these arrangements equals the natural gas-indexed price we pay for intermediate energy under our other agreements with Virginia Power. In addition to Virginia Power, we have other power purchase agreements with Mid-Atlantic utilities, which provide a small portion of our capacity and energy requirements.

The remainder of our energy requirements is provided by the market. We purchase significant amounts of power in the market through long-term and short-term physically-delivered forward power purchase contracts. We also purchase power in the spot market. This approach to meeting our member distribution cooperatives’ energy requirements is not without risks. See “Risk Factors” in Item 1A. below. To mitigate these risks, we attempt to match our energy purchases with our energy needs to reduce our spot market purchases of energy. Additionally, we utilize policies and procedures to manage the risks in the changing business environment. These procedures, developed in cooperation with ACES Power Marketing LLC (“APM”), are designed to strike the appropriate balance between minimizing costs and reducing energy cost volatility. See also “Management’s Discussion and Analysis of Financial Condition and Results of Operations—Future Issues—Reliance on Market Purchases of Energy” in Item 7.

Transmission

We rely on transmission services provided by PJM Interconnections, LLC (“PJM”) to serve our member distribution cooperatives. PJM is a regional transmission organization of transmission facilities serving all of Delaware, Maryland, West Virginia and most of Virginia, as well as other areas outside our member distribution cooperatives’ service territories.

We transmit power to our twelve member distribution cooperatives through the transmission systems of PJM – South, PJM – West Region, and PJM – Classic Region. We have agreements with PJM, which provide us with access to transmission facilities under their control as necessary to deliver energy to our member distribution cooperatives. We own a small amount of transmission facilities. See “Properties” in Item 2.

PJM continually balances its participants’ power requirements with the power resources available to supply those requirements. Based on this evaluation of supply and demand, PJM schedules available resources in a manner intended to meet the demand for power in the most reliable and cost-effective manner. When available resources cannot be dispatched due to transmission constraints, more expensive generating facilities must be dispatched to meet the requested power requirements. PJM participants whose power requirements cause the redispatch are obligated to pay the additional costs to dispatch the more expensive generating facilities. These additional costs are commonly referred to as congestion costs. PJM operates the transmission system in a manner intended to support a competitive generation marketplace. PJM has proposed additional transmission upgrades and these efforts may reduce our congestion costs in the future. Our net congestion costs for 2006 were approximately $13.4 million.

Fuel Supply

Nuclear

Virginia Power, as operating agent, has the sole authority and responsibility to procure nuclear fuel for North Anna. Virginia Power advises they use primarily long-term contracts to support North Anna’s nuclear fuel requirements and that worldwide market conditions are continuously evaluated to ensure a range of supply options at reasonable prices which are dependent upon the market environment. We are not a direct party to any of these procurement contracts, and therefore cannot control their terms or duration. Virginia Power reports that current agreements, inventories, and spot market availability are expected to support North Anna’s current and planned fuel supply needs and that additional fuel is purchased as required to attempt to ensure optimum cost and inventory levels.

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Coal

Virginia Power, as operating agent, has the sole authority and responsibility to procure sufficient coal for the operation of Clover. Historically, Virginia Power has employed both long-term contracts and spot market purchases to acquire the low sulfur bituminous coal used to fuel the facility. Virginia Power advises us that its 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. We are not a direct party to any of these procurement contracts, and therefore cannot control their terms or duration. As of December 31, 2006, and December 31, 2005, there was a 38.5 day and a 26.5 day supply of coal at Clover, respectively. We anticipate that sufficient supplies of coal will be available in the future at reasonable prices, but market prices and price volatility both may be higher than we currently anticipate. See “Quantitative and Qualitative Disclosures About Market Risk” in Item 7A.

Natural Gas

Many electric generating facilities are fueled by natural gas, causing an increase in competition for natural gas capacity. Our three operating combustion turbine facilities are powered by natural gas and are located adjacent to natural gas transmission lines. With assistance from APM, we developed and utilize a natural gas supply strategy for providing natural gas to each of the three combustion turbine facilities. We are responsible for procuring the natural gas to be used by all units at Louisa, Marsh Run and Rock Springs. The strategy includes securing transportation contracts and incorporating the ability to use No. 2 distillate fuel oil as a back up fuel for Louisa and Marsh Run, as needed, to minimize transportation costs. We have identified our primary natural gas suppliers and have negotiated the contracts needed for procurement of physical natural gas. We have put in place strategies and mechanisms to financially hedge our natural gas 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 or when their operation is required by PJM for system reliability purposes, but significant price volatility may occur. 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, state public service commissions. Some of our operations are also subject to regulation by the Virginia Department of Environmental Quality (“DEQ”), the Department of Energy (“DOE”), the Nuclear Regulatory Commission (“NRC”), and other federal, state, and local authorities. Compliance with future laws or regulations may increase our operating and capital costs by requiring, among other things, changes in the design or operation of our generating facilities.

Rates

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

FERC may review our rates upon its own initiative or upon complaint and order a reduction of any rates determined to be unjust, unreasonable, or otherwise unlawful and order a refund for amounts collected during such proceedings in excess of the just, reasonable, and lawful rates. Our charges to TEC are established under our market-based sales tariff filed with FERC.

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Because our rates and services are regulated by FERC, the VSCC, the Delaware Public Service Commission (“Delaware PSC”), and the Maryland Public Service Commission (“Maryland PSC”) do not have jurisdiction over our rates and services. The state commissions, however, do oversee the siting of our utility facilities in their respective jurisdictions. They also regulate the rates and services offered by our Virginia and Maryland member distribution cooperatives. Effective August 2006, one of our member distribution cooperatives, Delaware Electric Cooperative, is no longer regulated by the Delaware PSC.

Other FERC Regulation

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 subject to FERC jurisdiction (other than generating facilities), or any part of such facilities having a value in excess of $10.0 million without FERC approval.

Competition

Virginia, Delaware and Maryland each have laws unbundling the power component (also known as generation) of electric service to retail customers, while maintaining regulation of transmission and distribution services. All retail customers in Virginia, Delaware and Maryland, including retail customers of our member distribution cooperatives, are currently permitted to purchase power from the registered supplier of their choice. At March 1, 2007, no entity had registered to be an alternative power supplier in any of the service territories of our member distribution cooperatives and, as a result, none of their retail customers have switched to alternative providers. If customers of our member distribution cooperatives choose alternative power suppliers in the future, this could result in a reduction in our revenues and cash flows. If the resulting decrease in our member revenues is significant enough, we could lose our tax-exempt status. See “Management’s Discussion and Analysis of Financial Condition and Results of Operations—Factors Affecting Results—Tax Status” in Item 7.

To address the difference between what an electric utility would have recovered under regulated cost-of-service rates and what that electric utility would have recovered under competitive market rates, sometimes referred to as “stranded costs,” and to facilitate the implementation of retail competition, legislation was passed in Virginia, Delaware and Maryland requiring each incumbent utility to cap the rates that it charges its retail customers in its certificated service territory during a specified transition period. The transition periods for our Delaware member distribution cooperative and our Maryland member distribution cooperative expired in 2005. Capped rates extend until December 31, 2010, for our Virginia member distribution cooperatives. These capped rates are unbundled, or itemized, into power, transmission and distribution components and a competitive transition charge. Our member distribution cooperatives located in Virginia have the ability to pass through to their customers, changes in energy costs even while under capped rates. Additionally, they may request one change in their capped rates prior to July 1, 2007, and one additional change between July 1, 2007 and December 31, 2010. Currently, there is legislation pending approval in Virginia that would change the termination of the capped rates from December 31, 2010 to December 31, 2007. Beginning January 1, 2008, this legislation would allow our Virginia member distribution cooperatives to adjust their rates on a cumulative basis by a maximum net increase or decrease of 5% in any three year period without presenting a rate case to the VSCC. This new legislation would not affect our Virginia member distribution cooperatives ability to pass through to their customers, changes in energy costs. This legislation is subject to approval by the Governor of Virginia in early April 2007.

Environmental

We are subject to federal, state, and local laws and regulations and permits designed to protect human health and the environment and regulate the emission, discharge, or release of pollutants into the environment. We believe we are in material compliance with all current requirements of such environmental laws and regulations and

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permits. As with all electric utilities, the operation of our generating units could, however, be affected by future environmental regulations. Capital expenditures and increased operating costs required to comply with any future regulations could be significant. See “Risk Factors” in Item 1A. below.

Our direct capital expenditures for environmental control facilities at Clover and North Anna, excluding capitalized interest, were immaterial in 2006. Based upon information provided by Virginia Power, we anticipate that beginning in 2011, we will have an increase in our direct capital expenditures for environmental control facilities at Clover. In 2006, we did not have any direct capital expenditures for environmental control facilities at our Louisa, Marsh Run or Rock Springs combustion turbine facilities and there are currently no projected capital expenditures for environmental control facilities in 2007, 2008, or 2009. See “Management’s Discussion and Analysis of Financial Condition and Results of Operations—Capital Expenditures” in Item 7.

The most important environmental law affecting our operations is the Clean Air Act. The Clean Air Act requires, among other things, that owners and operators of fossil fuel-fired power stations limit emissions of sulfur dioxide (“SO₂”) and nitrogen oxides (“NO_x”). In addition, regulations have been issued to limit emissions of mercury, and programs are being proposed to limit emissions of carbon dioxide (“CO₂”) and other greenhouse gases.

With respect to SO₂, under the Clean Air Act’s Acid Rain Program, each of our fossil fuel-fired plants must obtain SO₂ allowances equal to the number of tons of SO₂ they emit into the atmosphere annually. The total number of allowances is capped, and allowances can be traded. As a facility that was built before the Acid Rain Program, Clover receives an annual allocation of SO₂allowances at no cost based upon its baseline operations. Newer facilities, including Louisa, Marsh Run and Rock Springs, need to obtain allowances, but because they are primarily gas-fired, the number of SO₂allowances they must obtain are expected to be minimal and will be supplied from excess SO₂ allowances allocated to Clover. On March 10, 2005, the EPA issued the Clean Air Interstate Rule (“CAIR”), requiring significant reductions of SO₂ and NO_x in the eastern United States, including Virginia and Maryland. During its 2006 session, the Virginia General Assembly adopted legislation setting the framework for the implementation of CAIR in Virginia. The DEQ adopted the final CAIR regulation and it is expected to be published in the Virginia Register in the spring. With respect to SO₂, emissions it is expected that Virginia will participate in the federal SO₂ cap and trade program established by CAIR. That program is similar, but is in addition to the Acid Rain Program and would require all of our facilities in Virginia (including Clover) to acquire additional allowances for each ton of SO₂ they emit beginning in 2009, and additional allowances per ton starting in 2015. We are entitled to sufficient SO₂allowances because of our interest in Clover so that we do not anticipate needing to purchase additional SO₂allowances for the Louisa, Marsh Run and Rock Springs generating facilities through both phases of CAIR.

Pursuant to the Clean Air Act, both Virginia and Maryland have enacted regulations to reduce the emissions of NO_x by establishing NO_x cap and trade programs similar to the federal SO₂allowance programs. Both of these programs are being revised to meet the more stringent NO_x emission caps established under CAIR and with respect to the facilities in Virginia, additional NO_x emission reductions mandated by the Virginia General Assembly. Under the current system, Clover is allocated a certain number of NO_x allowances. If Clover, even with use of conventional and advanced pollution control equipment emits more, then additional NO_x emissions allowances will have to be purchased. We have an agreement with Virginia Power to provide us with the option each year to purchase from it the NO_x emissions allowances necessary to compensate for any shortfall between our NO_x emissions allowance requirement for Clover and our portion of the regulatory NO_xemissions allocation for Clover.

Louisa, Marsh Run and Rock Springs will each emit significant amounts of NO_x. In 2006, NO_x allowances were allocated and we anticipate receiving NO_x allowances through 2008. All three sites will be allocated NO_x emission allowances under CAIR. NO_x emission allowances that are not received from the new source set aside pools will be purchased in the market for the operation of all three combustion turbine facilities. We project that we will be able to obtain sufficient quantities of NO_x allowances in the future at commercially reasonable prices, but increased NO_x emissions or increased restrictions could cause the price of allowances to be higher than we expect.

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In December 2000, the EPA determined that it was appropriate and necessary to regulate mercury emissions from oil and coal-fired power plants as a hazardous air pollutant under the Clean Air Act. In March 2005, the EPA reversed that earlier decision and instead issued the Clean Air Mercury Rule (“CAMR”) which establishes caps for overall mercury emissions that would be implemented in two phases, with the first phase becoming effective in 2010 and the second phase in 2018, and allows the individual states to regulate mercury emissions through a market-based cap and trade program. In response to a request for reconsideration, the EPA confirmed its approach in May 2006. In June 2006, 16 states and several environmental groups filed law suits challenging CAMR and the law suits are currently pending. We cannot predict the outcome of the ongoing challenges of CAMR or what effects any decision may have that would require the EPA to regulate mercury as a hazardous air pollutant. In 2006, the Virginia General Assembly decided to adopt the cap and trade program foreseen in CAMR, subject to certain limitations. If the EPA’s decisions are upheld and CAMR is implemented we do not anticipate that any additional measures will be required at Clover due to Clover’s existing pollution control requirement which already removes greater than 90% of the mercury.

In addition to traditional air pollutants, the question of climate change has been the focus of much public attention. Several bills have been introduced in Congress to limit emissions of CO₂ and other greenhouse gases believed to contribute to climate change. Also, there are numerous actions at the state and regional level, including the Regional Greenhouse Gas Initiative (“RGGI”) established in December 2005 by the governors of seven Northeastern and Mid-Atlantic states. The RGGI provides for a cap and trade system for CO₂ among those states, capping emissions at current levels in 2009, and then reducing emissions 10% by 2019. In 2006, Maryland decided to join the RGGI. Climate change issues are also the subject of several lawsuits, although we were not party to any of those lawsuits. In November 2006, the U.S. Supreme Court heard a case concerning the EPA’s authority to regulate CO₂ emissions under the Clear Air Act. The case concerns CO₂ emissions from the transportation sector, but the Court’s decision will also influence the regulation of other sectors. We cannot exclude the possibility that future CO₂ emission regulations could have a significant effect on our operations, especially at Clover; however, at this stage we are not able to predict the final form of any such regulation.

The Clean Water Act and applicable state laws regulate water intake structures, discharges of cooling water, storm water run-off and other wastewater discharges at our generating facilities. We are in material compliance with these requirements and with permits that must be obtained with respect to such discharges. Our permits are subject to periodic review and renewal proceedings, and can be made more restrictive over time. Limitations on the thermal discharges in cooling water, or withdrawal of cooling water during low flow conditions, can restrict our operations. During 2006, we experienced no such restrictions; however, such restrictions can arise during drought conditions. Clover has two consent orders with the DEQ. One consent order is to study the impact of withdrawing water to support Clover during low river flow conditions and the other is to relocate one of the landfill discharge pipes from Black Walnut Creek to the Roanoke River. The low flow study has been conducted and the results are being finalized. One of the landfill discharge pipes has been relocated to the Roanoke River.

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

We incurred approximately $5.7 million, $9.4 million, and $11.0 million, of expenses, including depreciation, during 2006, 2005, and 2004, respectively, in connection with environmental protection and monitoring activities, such as costs related to the disposal of solid waste, operation of landfills, operation of air emissions reduction equipment, and disposal of hazardous waste material. These expenses were included in fuel expense, operations and maintenance expense, and depreciation, amortization and decommissioning expense. We anticipate expenses to be approximately $5.0 million in 2007 in connection with environmental protection and monitoring activities, including depreciation.

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Nuclear

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

ITEM 1A. – RISK FACTORS

RISK FACTORS

The following risk factors and all other information contained in this report should be considered carefully when evaluating Old Dominion. These risk factors could affect our actual results and cause these results to differ materially from those expressed in any forward-looking statements of Old Dominion. Other risks and uncertainties, in addition to those that are described below may also impair our business operations. We consider the risks listed below to be material, but you may view risks differently than we do and we may omit a risk that we consider immaterial but you consider important. An adverse outcome of any of the following risks could materially affect our business or financial condition. These risk factors should be read in conjunction with the other detailed information set forth in the notes to Consolidated Financial Statements and in “Management’s Discussion and Analysis of Financial Condition and Results of Operations” in Item 7 below, including “Caution Regarding Forward Looking Statements.”

We rely substantially on purchases of energy from other power suppliers.

We supply our member distribution cooperatives with all of their power, that is capacity and energy, requirements, with limited exceptions. Our costs to provide this capacity and energy are passed through to our member distribution cooperatives under our wholesale power contracts. We obtain the power to serve their requirements from generating facilities in which we have an interest and purchases of power from other power suppliers.

Historically, our power supply strategy has relied substantially on purchases of energy from other power suppliers. In 2006, we purchased approximately 54.8% of our energy resources. These purchases consisted of a combination of purchases under long-term and short-term physically-delivered forward contracts and purchases of energy in the spot markets. Our reliance on energy purchases may continue well into the future and may increase as our member distribution cooperatives’ requirements for power increase. Our reliance on energy purchases also could increase because the operation of our generation facilities is subject to many risks, including the shutdown of our facilities or breakdown or failure of equipment.

Purchasing power helps us mitigate high fixed costs relating to the ownership of generating facilities but exposes us, and consequently our member distribution cooperatives, to significant market price risk because energy prices can fluctuate substantially. When we enter into long-term power purchase contracts or agree to purchase energy at a date in the future, we rely on models based on our judgments and assumptions. These judgements and assumptions relate to factors such as future demand for power and market prices of energy and the price of commodities, such as natural gas used to generate electricity. Our models cannot exactly predict what will actually occur and our results may vary from what our models predict, which may in turn impact our resulting costs to our members. Our models become less reliable the further into the future that the estimates are made. Although we have engaged APM, an energy trading and risk management company, to assist us in developing strategies to meet our power requirements in the most economical manner and we have implemented a hedging strategy to limit our exposure to variability in the market, we still may purchase energy at a price which is higher than our member distribution cooperatives’ competitors’ costs of generating energy or future market prices of energy. For further discussion of our market price risk, see Item 7A “Quantitative and Qualitative Disclosures About Market Risk.”

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Changes in fuel and purchased power costs could increase our generating costs.

We are subject to changes in fuel costs, which could increase the cost of generating power and thus increase the cost to our member distribution cooperatives. The market prices for fuel may fluctuate over relatively short periods of time. Factors that could influence fuel costs are:

• Weather;

• Supply and demand;

• The availability of competitively priced alternative energy sources;

• The transportation of fuels;

• Price competition among fuels used to produce electricity, including natural gas, coal and crude oil;

• Energy transmission or natural gas transportation capacity constraints;

• Federal, state and local energy and environmental regulation and legislation; and

• Natural disasters, war, terrorism, and other catastrophic events.

Adverse changes in our credit ratings could negatively impact our ability to access capital and may require us to provide credit support for some of our obligations.

Changes in our credit ratings could affect our ability to access capital. Standard & Poor’s Ratings Services (“S&P”), Moody’s Investors Service (“Moody’s”), and Fitch Inc., currently rate our outstanding obligations issued under the Indenture at “A”, “A3”, and “A”, respectively. If these agencies were to downgrade our ratings, particularly below investment grade, we may be required to pay higher interest rates on financings, which we may decide to undertake in the future, and our potential pool of investors and funding sources could decrease. In addition, in limited circumstances, we have obligations to provide credit support if our obligations issued under the Indenture are rated below specified thresholds by S&P and Moody’s. These circumstances relate to lease and leaseback of our undivided interest in Clover Unit 1 and some of our purchases of power in the market. See also “Management’s Discussion and Analysis of Financial Condition and Results of Operations—Significant Contingent Obligations” in Item 7.

To the extent that we would have to provide additional credit support as a result of a downgrade in our credit ratings, our ability to access additional credit may be limited and our liquidity, including our ability to service our outstanding indebtedness, may be materially impaired.

We are subject to risks associated with owning an interest in a nuclear generation facility.

We have an 11.6% undivided ownership interest in North Anna which provided approximately 13.8% of our energy requirements in 2006. Ownership of an interest in a nuclear generating facility involves risks, including:

• potential liabilities relating to harmful effects on the environment and human health resulting from the operation of the facility and the storage, handling and disposal of radioactive materials;

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• significant capital expenditures relating to maintenance, operation and repair of the facility, including repairs required by the NRC;

• limitations on the amounts and types of insurance commercially available to cover losses that might arise in connection with operation of the facility; and

• uncertainties regarding the technological and financial aspects of decommissioning a nuclear plant at the end of its licensed life.

The NRC has broad authority under federal law to impose licensing and safety-related requirements for the operation of North Anna. If the facility is not in compliance, the NRC may impose fines or shut down one or both units until compliance is achieved or both depending upon its assessment of the situation. Revised safety requirements issued by the NRC have, in the past, necessitated substantial capital expenditures at other nuclear generating facilities. In addition, although we have no reason to anticipate a serious nuclear incident at North Anna, if an incident did occur, it could have a material but presently undeterminable adverse effect on our operations or financial condition. Further, any unexpected shut down at North Anna as a result of regulatory non-compliance or unexpected maintenance will require us to purchase replacement energy. We can buy this replacement power either from Virginia Power under the OPSA or the market. See “Power Supply Resources—Power Purchase Contracts.”

Environmental regulation may limit our operations or increase our costs or both.

We are required to comply with numerous federal, state and local laws and regulations relating to the protection of the environment. While we believe that we have obtained all material environmental-related approvals currently required to own and operate our facilities or that these approvals have been applied for and will be issued in a timely manner, we may incur significant additional costs because of compliance with these requirements. Failure to comply with environmental laws and regulations could have a material effect on us, including potential civil or criminal liability and the imposition of fines or expenditures of funds to bring our facilities into compliance. Delay in obtaining, or failure to obtain and maintain in effect any environmental approvals, or the delay or failure to satisfy any applicable environmental regulatory requirements related to the operation of our existing facilities or the sale of energy from these facilities could result in significant additional cost to us.

Our financial condition is largely dependent upon our members.

Our financial condition is largely dependent upon our member distribution cooperatives satisfying their obligations under the “all-requirements” wholesale power contract that each has executed with us. The wholesale power contracts require our member distribution cooperatives pay us for power furnished to them in accordance with our FERC formulary rate, which is designed to permit us to recover our total cost of service and create a firm equity base. Our board of directors, which is composed of representatives of our members, can approve changes in the rates we charge to our member distribution cooperatives without seeking FERC approval with limited exceptions. In 2006, 61.3% of our revenues were received from our three largest members, NOVEC, Rappahannock Electric Cooperative and Delaware Electric Cooperative.

Since January 2005, we have been involved in litigation with NOVEC, our largest member, regarding our potential reorganization and NOVEC’s desire to change the nature of its wholesale power contract to a partial-requirements contract. While we cannot predict the ultimate resolution of these matters, we will not amend or modify our wholesale power contracts in any way that could adversely affect our financial condition or that of our member distribution cooperatives.

The use of hedging instruments could impact our liquidity.

We use hedging instruments, including forwards, futures, financial transmission rights, and options, to manage our power market price risks. These hedging instruments generally include collateral requirements that require us to deposit funds or post letters of credit with counterparties when a counterparty’s credit exposure to us is

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in excess of agreed upon credit limits. When commodity prices decrease to levels below the levels where we have hedged future costs, we may be required to use a material portion of our cash or liquidity facilities to cover these collateral requirements. See also “Management’s Discussion and Analysis of Financial Condition and Results of Operations—Market Price Risk” in Item 7A.

Counterparties under power purchase arrangements may fail to perform their obligations to us.

Because we rely substantially on the purchase of energy from other power suppliers, we are exposed to the risk that counterparties will default in performance of their obligations to us. While we utilize APM to assist us in analyzing default risks of counterparties and other credit issues related to these purchases, and we may require our counterparties to post collateral with us, defaults may still occur. Defaults may take the form of failure to physically deliver the purchased energy. If this occurs, we may be forced to enter into alternative contractual arrangements or purchase energy in the forward, short-term or spot markets at then-current market prices that may exceed the prices previously agreed upon with the defaulting counterparty.

Our member distribution cooperatives are subject to market competition.

Virginia, Delaware and Maryland each permit our member distribution cooperatives’ customers to purchase electricity from an alternate supplier while our member distribution cooperatives continue to provide distribution services to all consumers of electricity located in their certificated service territories. Substantially all of our member distribution cooperatives’ customers are free to choose an alternate power supplier; however, to date, no customer of our member distribution cooperatives has selected an alternate supplier of power. The competitive retail market has been slow to develop and therefore it is difficult to predict the pace at which a competitive environment will evolve and the impact on us or our member distribution cooperatives. See “Business—Regulation—Competition” in Item 1 above.

ITEM 1B. UNRESOLVED STAFF COMMENTS

None

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ITEM 2. PROPERTIES

Our principal properties consist of our interest in five electric generating facilities, additional distributed generation facilities across our member distribution cooperatives’ service territories and a small amount of transmission facilities. All of our physical properties are subject to the lien of our Indenture. See “Restated Indenture” below. Our generating facilities consist of the following:

Name of Facility	Ownership Interest	Location	Primary Fuel	Commercial Operation Date	Net Capacity Entitlement(3)
Clover	50.0%(1)	Halifax County, Virginia	Coal	Unit 1 – 10/1995 Unit 2 – 03/1996	215 MW 215 MW 430 MW
North Anna	11.6%	Louisa County, Virginia	Nuclear	Unit 1 –06/1978(4) Unit 2 –12/1980(4)	107 MW 107 MW 214 MW
Louisa	100.0%	Louisa County, Virginia	Natural Gas	Unit 1 – 06/2003 Unit 2 – 06/2003 Unit 3 – 06/2003 Unit 4 – 06/2003 Unit 5 – 06/2003	84 MW 84 MW 84 MW 84 MW 168 MW 504 MW
Marsh Run	100.0%	Fauquier County, Virginia	Natural Gas	Unit 1 – 09/2004 Unit 2 – 09/2004 Unit 3 – 09/2004	168 MW 168 MW 168 MW 504 MW
Rock Springs	50.0%(2)	Cecil County, Maryland	Natural Gas	Unit 1 – 06/2003 Unit 2 – 06/2003	168 MW 168 MW 336 MW
Distributed generation	100.0%	Multiple	Diesel	10 units –07/2002	20 MW
				Total	2,008 MW

⁽¹⁾ Our interest in Clover is subject to long-term leases. See “Clover” below.

⁽²⁾ We own 100% of two units, each with a net capacity rating of 168 MW, and 50% of the common facilities for the facility. See “Combustion Turbine Facilities—Rock Springs” below.

⁽³⁾ Represents an approximation of our entitlement to the maximum dependable capacity, which does not represent actual usage.

⁽⁴⁾ We purchased our 11.6% undivided ownership interest in North Anna in December 1983.

Clover

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 “Power Supply Resources—Fuel Supply—Coal” in Item 1. We are responsible for and must fund half of all additions and operating costs associated with Clover, as well as half of Virginia Power’s administrative and general expenses for Clover. Under the terms of the Clover operating agreement, Old Dominion and Virginia Power each take half of the power produced by Clover.

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Lease of Clover Unit 1

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 and related common facilities, subject to the lien of the Indenture, for a term extendable by the owner trust up to the full productive life of Clover Unit 1, and simultaneously entered into an approximately 21.8 year lease of the interest back to us. If the lien of the Indenture is ever released, the interest of the owner trust in Clover Unit 1 would no longer be subject and subordinate to the lien of the Indenture in the future. See “Restated Indenture” below. 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 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 Indenture with an owner trust for the benefit of a different investor of our interest in Clover Unit 2 and related common facilities for a term extendable by the owner trust up to the full productive life of Clover Unit 2. We simultaneously entered into an approximately 23.4 year lease back of the interest. If the lien of the Indenture is ever released , the interest of the owner trust in Clover Unit 2 would no longer be subject and subordinate to the lien of the Indenture in the future. See “Restated Indenture” below. We have provided for all of our periodic basic rent payments under the lease by investing in obligations issued or insured by entities, the claims paying ability or senior debt obligations of which are rated “AAA” by S&P and “Aaa” by Moody’s. As with the Clover Unit 1 lease, the leaseback of Clover Unit 2 contains events of default, which could result in termination of the lease and loss of possession and right to the output of the unit.

In connection with this lease, we granted a subordinated lien and security interest in Clover Unit 2 to secure our obligations under the lease and our reimbursement obligation to an insurer for its payments under a surety bond securing some of our payment obligations under the lease. This subordinated lien and security interest will be required to be released prior to the date of the release of the lien of the Indenture in connection with its amendment and restatement unless the holders of obligations issued under the Indenture are equally and ratably secured with respect to the assets subject to the lease. After that date, the interest of the owner trust would no longer be subject and subordinate to the lien of the Indenture. See “Management’s Discussion and Analysis of Financial Condition and Results of Operations—Future Issues—Restated Indenture” in Item 7 for a discussion of the possible amendment and restatement of the Indenture.

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

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North Anna

Virginia Power, as the co-owner of North Anna, is responsible for operating North Anna. Virginia Power also has the authority and responsibility to procure nuclear fuel for North Anna. See “Fuel Supply—Nuclear” in Item 1. We are entitled to 11.6% of the power generated by North Anna. Additionally, we are responsible for and must fund 11.6% of all post-acquisition date additions and operating costs associated with North Anna, as well as a pro-rata portion of Virginia Power’s administrative and general expenses directly attributable to North Anna. We are obligated to fund these items. In addition, we separately fund our pro-rata portion of the decommissioning costs of North Anna. Old Dominion 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.

Combustion Turbine Facilities

Louisa

We undertook responsibility for the operation and maintenance of the Louisa facility beginning in 2006. We supply all services, goods and materials required to operate the facility, including arranging for the transportation and supply of the natural gas and No. 2 distillate fuel oil required by the facility.

Marsh Run

We also operate and maintain the Marsh Run facility. We supply all services, goods and materials required to operate the facility, including arrangement for the transportation and supply of the natural gas and No. 2 distillate fuel oil required by the facility.

Rock Springs

The Rock Springs facility was developed together with another participant, CED Rock Springs, LLC (“ConEd”). ODEC and ConEd each individually own two units (a total of 336 MWs each) and 50% of the common facilities. Additionally, ODEC and ConEd each individually dispatch their respective units as it determines to be necessary and prudent. The facility is currently permitted to allow two additional 168 MW combustion turbines to be installed at the site for a total site capacity of 1,008 MW.

The Rock Springs facility is operated and maintained by CED Operating Co., LLP, an affiliate of ConEd, pursuant to a service agreement under which CED Operating Co., LLP, supplies all services, goods and materials, other than natural gas, required to operate the facility. We are responsible for all costs associated with the development, construction, additions and operating costs and administrative and general expenses relating to our two units and the proportional share of the costs relating to the common facilities for Rock Springs.

We arrange for the transportation of the natural gas required by the operator for all units at Rock Springs and arrange for the supply of natural gas to our units only.

Distributed Generation Facilities

We have distributed generation facilities in our member distribution cooperatives’ service territory primarily to enhance our system’s reliability. Four diesel generators service our member distributions cooperatives’ in the Virginia mainland territory and six diesel generators service our member distribution cooperatives’ in the Delmarva Peninsula territory.

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Transmission

We own two 1,100 foot 500 kilovolt (“kV”) transmission lines and a 500 kV substation at the Rock Springs site jointly with ConEd. As a transmission owner in PJM, we have relinquished control of these transmission facilities to PJM and contracted with third parties to operate and maintain the transmission facilities.

Restated Indenture

In 2001, we entered into a supplemental indenture to the Indenture that contains provisions, which, if they become effective, will amend and restate the Indenture to release its lien on our property. This amended and restated indenture (the “Restated Indenture”) will become effective when all obligations under the Indenture issued prior to September 1, 2001, cease to be outstanding or when the holders of those obligations consent to the effectiveness of the Restated Indenture. We have $1.0 million of obligations issued under the Indenture prior to September 1, 2001, the holders of which have not consented to the effectiveness of the Restated Indenture. We have the ability to redeem these obligations on any June 1 or December 1, following appropriate notice to the holders of those obligations. The amendment and restatement may not occur, however, if, immediately afterwards, an event of default exists under the Indenture or an event of default would occur. The release of a subordinated mortgage on our interest in Clover Unit 2 also is to be obtained prior to the amendment and restatement. After the date the Restated Indenture becomes effective, the obligations outstanding under the Restated Indenture will be unsecured general obligations, ranking equally and ratably with all of our other unsecured and unsubordinated obligations.

ITEM 3. LEGAL PROCEEDINGS

NOVEC

Over the past several years, we have had discussions and negotiations with NOVEC about changing the nature of its wholesale power contract from an all-requirements contract to a partial-requirements contract. Our board of directors is composed of representatives of our member distribution cooperatives and we must reach consensus among our member distribution cooperatives before any change to any of our wholesale power contracts can be made. Building a consensus for any change is difficult because any change in our rate setting methodology or provisions of service affects our various member distribution cooperatives differently.

On January 5, 2006, NOVEC filed a complaint with FERC pursuant to Section 206 of the Federal Power Act seeking reformation of its wholesale power contract. Specifically, NOVEC sought “to modify its wholesale power contract to allow NOVEC the flexibility to acquire power and energy over and above that available from NOVEC’s share of Old Dominion’s existing resources.” NOVEC claimed that the wholesale power contract’s terms were no longer just and reasonable or in the public interest because the contract was entered into in 1983, and amended and restated in 1992, prior to an allegedly different era of open transmission access and wholesale power markets. NOVEC stated in the complaint that it would not seek to be relieved of its obligations pertaining to its share of our existing power supply resources. Obligations pertaining to our existing resources include debt service, lease rentals, operation and maintenance expenses, interest coverage requirements and other costs and expenses related to our electric generating facilities and existing power purchase arrangements. On March 2, 2006, FERC denied NOVEC’s complaint. On April 3, 2006, NOVEC filed a request for rehearing and on May 1, 2006, FERC issued a tolling order to allow additional time to consider the issues. On August 24, 2006, FERC issued it final order denying NOVEC’s request for rehearing. On October 20, 2006, NOVEC appealed FERC’s denial in the United States Court of Appeals for the District of Columbia. We have intervened in this proceeding. On March 5, 2007, the court issued the procedural schedule and NOVEC’s brief is scheduled to be filed on or before May 7, 2007.

We intend to continue to vigorously contest NOVEC’s claim and we will not amend or modify the wholesale power contract in any way that could adversely affect our financial condition or that of our other member distribution cooperatives.

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Norfolk Southern

In April 1989, we entered into a coal transportation agreement with Norfolk Southern Railway Company (“Norfolk Southern”) for delivery of coal to Clover. The agreement, which was later assigned to Virginia Power as operator of Clover, had an initial 20-year term and provides that the amounts payable for coal transportation services are subject to adjustment based on a reference index. In October 2003, Norfolk Southern claimed that it had been using an incorrect reference index to calculate amounts due to it since the inception of the agreement, and that it would begin to escalate prices for these services in the future based on an alternate reference index. On November 26, 2003, together with Virginia Power, we filed suit against Norfolk Southern in the Circuit Court of Halifax County, Virginia, seeking an order to clarify the price escalation provisions in the coal transportation agreement. In its reply to our suit, Norfolk Southern filed a counter-claim and sought (1) recovery from Virginia Power and us for additional amounts resulting from its use of the alternate reference index since December 1, 2003, and (2) an order requiring the parties to calculate the amounts Norfolk Southern claims it was underpaid since the inception of the agreement by using the alternate reference index.

On December 22, 2004, the court found in favor of Norfolk Southern on the issue of ambiguity and held that the price escalation provisions in the agreement were clear and unambiguous. The court later denied Virginia Power’s and our motion to file an amended complaint based on additional evidence that was not considered by the court in the original proceedings. The court permitted Virginia Power and us to file an amended answer to Norfolk Southern’s counter-claims and our amended answer was filed on March 4, 2005.

On September 1, 2006, the court granted Norfolk Southern’s request to substantially dispose of the issues in the case. On September 23, 2006, we, along with Virginia Power, appealed the court’s order to the Supreme Court of Virginia. On December 13, 2006, Norfolk Southern filed a motion to dismiss for lack of jurisdiction, contending that we and Virginia Power failed to timely appeal. We intend to vigorously prosecute the appeal, if the Supreme Court of Virginia determines we are able to appeal.

We recorded a liability related to the Norfolk Southern dispute and created the related regulatory asset. The regulatory asset was amortized over 21 months (April 1, 2005 through December 31, 2006) and was fully amortized and collected through rates as of December 31, 2006. The current period charges are being collected through rates. If it is ultimately determined that we owe any such amounts to Norfolk Southern, the amounts are not expected to have a material impact on our financial position or results of operations due to our ability to collect such amounts through rates charged to our member distribution cooperatives.

Ragnar Benson

In December 2002, we entered into a contract with Ragnar Benson, Inc. (“RBI”) for engineering, procurement and construction services relating to the construction of our Marsh Run combustion turbine facility. Construction of the facility began in April 2003 and the facility was required to be substantially complete in the second quarter of 2004. The facility ultimately became available for commercial operation on September 15, 2004, but is still not substantially complete according to the terms of the contract. On December 23, 2004, we terminated the contract with RBI for default and filed suit in the U.S. District Court for the Eastern District of Virginia, Richmond Division, against RBI seeking liquidated damages for delay in completion of the project up to $15.0 million and damages for breach of contract up to $5.0 million. RBI counterclaimed for damages exceeding $15.0 million related to conditions they claim to have encountered during construction. We filed an answer to RBI’s counterclaim denying any liability to RBI. During the discovery phase of the legal proceeding, RBI revised its claim from $15.0 million to $33.0 million.

On September 27, 2005, the U.S. District Court for the Eastern District of Virginia, Richmond Division, ruled on motions for partial summary judgment in our claims against RBI. Specifically, the court granted our motion for partial summary judgment pertaining to claims of entitlement to a change order and fraud allegations, it dismissed six of RBI’s counterclaims, including all counterclaims pertaining to fraud, and it limited our possible recovery of liquidated damages to the liquidated damages cap of approximately $4.7 million. The trial began October 11, 2005 and concluded October 26, 2005. During the trial, RBI revised its claim from $33.0 million to $36.0 million.

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RBI and its parent companies, The Austin Company and Austin Holdings, Inc., filed for bankruptcy under Chapter 11 of the bankruptcy code on October 14, 2005. The automatic litigation stay was lifted for our litigation with RBI.

On June 13, 2005, we executed an agreement with RBI’s surety, Seaboard Surety Company (“Seaboard”), under which it assumed all responsibilities for the final completion of the Marsh Run facility in accordance with the terms of the original agreement with RBI. Because RBI declared bankruptcy during the legal proceeding, we served a lawsuit against Seaboard on February 10, 2006, in order to enforce the eventual outcome of the suit with RBI.

On August 4, 2006, the court ruled in our favor on all remaining issues in the case and awarded us damages of $5.2 million plus expenses. On January 22, 2007, the court entered its final order awarding us an additional $2.5 million for attorneys’ fees and certain other costs and expenses. On February 1, 2007, we filed a motion to amend the final order to address our claim for expert witness fees and interest from the date of the trial, totaling approximately $0.8 million. This motion is still pending before the court. After the court rules on this motion, the judgment is final and the appeals process may begin. RBI will have 30 days to appeal any of the court’s rulings. We intend to enforce the court’s rulings against RBI, to the extent permitted by its bankruptcy proceeding, and against Seaboard.

FERC Proceedings Related to Potential Reorganization

On October 5, 2004, we, together with New Dominion, filed an application at FERC requesting that FERC approve the assignment of our existing wholesale power contracts with our twelve member distribution cooperatives to New Dominion and accept certain changes to our cost-of-service formula to conform it for use by New Dominion for the billing of its sales to the member distribution cooperatives. On December 7, 2004, we filed an application for approval of a new tariff for sales to New Dominion, with charges determined under a cost allocation formula.

On January 14, 2005, NOVEC intervened in the FERC proceedings related to the proposed reorganization. See “Member Distribution Cooperatives—New Dominion” and “—NOVEC” in Item 1 and “NOVEC” in Legal Proceedings above. Other interveners in these proceedings included Bear Island Paper Company, LLP and the VSCC.

On March 8, 2005, FERC issued an order that set the proposed assignment of the wholesale power contracts for hearing on the limited issue of whether an Old Dominion credit downgrade could raise rates, and, if so, whether the downgrade is due to the proposed transaction. The hearing was conducted on October 18 through 20, 2005, and concluded on November 2, 2005. The initial decision was issued on February 2, 2006, and the judge ruled in our favor on all material issues. On December 21, 2006, FERC issued an order affirming the initial decision indicating that it had not been shown that the credit downgrade experienced by ODEC could raise rates. On January 22, 2007, NOVEC filed a request for rehearing and on February 21, 2007, FERC issued a tolling order to allow for additional time for consideration of the matters.

Also on March 8, 2005, FERC consolidated the October 5, 2004, and December 7, 2004, rate applications and set hearing and settlement procedures. On June 10, 2005, formal settlement procedures were terminated and a judge was assigned to hear the case. Informal settlement talks continued, and on October 13, 2005, we joined with New Dominion in filing a proposed settlement agreement that resolved all issues in dispute in these proceedings among us, Bear Island Paper Company, LLP, and the Virginia VSCC. On December 23, 2005, the judge certified the partial settlement to FERC with a recommendation that it be approved. FERC issued an order approving the partial settlement on April 7, 2006, leaving NOVEC, FERC staff and us as participants in the proceeding. The hearing was conducted on October 17 through 19, 2006, and the initial decision was issued on February 5, 2007, when the judge ruled in our favor on all material matters. NOVEC and FERC staff filed exceptions to the ruling on March 7, 2007 and we have 20 days to respond.

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Other

Other than the issues discussed above and certain other legal proceedings arising out of the ordinary course of business that management believes will not have a material adverse impact on our results of operations or financial condition, there is no other litigation pending or threatened against us.

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

None

PART II

ITEM 5. MARKET FOR REGISTRANT’S COMMON EQUITY, RELATED STOCKHOLDER MATTERS AND ISSUER PURCHASES OF EQUITY SECURITIES

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, 2006, are derived from our audited consolidated financial statements. You should read the information contained in this table together with our consolidated financial statements, the related notes to the consolidated financial statements, and the discussion of this information in “Management’s Discussion and Analysis of Financial Condition and Results of Operations” in Item 7.

	Year Ended December 31,
	2006			2005			2004			2003			2002
	(in thousands, except ratios)
Statement of Operations Data:
Operating Revenues	$	817,515		$	737,679		$	588,451		$	535,576		$	494,642
Operating Margin		73,461			68,196			61,615			57,941			43,983
Net Margin(1)		21,244			12,109			12,134			12,056			9,996
Margins for Interest Ratio		1.39			1.22			1.25			1.31			1.20
	December 31,
	2006			2005			2004			2003			2002
	(in thousands, except ratios)
Balance Sheet Data:
Net Electric Plant	$	1,047,089		$	1,074,226		$	1,101,495		$	1,085,406		$	938,086
Investments		286,956			254,813			250,520			276,998			278,218
Other Assets		293,364			383,327			198,323			199,932			213,755
Total Assets	$	1,627,409		$	1,712,366		$	1,550,338		$	1,562,336		$	1,430,059
Capitalization:
Patronage Capital	$	293,077		$	271,833		$	259,724		$	247,590		$	235,534
Accumulated Other
Comprehensive (Loss)/Income		—			—			—			—			(10,911	)
Non-controlling Interest		10,993			25,062			8,225			—			—
Long-term Debt		813,264			832,980			852,910			873,041			750,682
Total Capitalization	$	1,117,334		$	1,129,875		$	1,120,859		$	1,120,631		$	975,305
Equity Ratio(2)		26.5	%		24.6	%		23.3	%		22.1	%		23.9	%

⁽¹⁾ Net Margin for 2006 includes an additional equity contribution of $9.0 million.

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

Our Indenture obligates us to establish and collect rates for service to our member distribution cooperatives, which are reasonably expected to yield a margin for interest ratio for each fiscal year equal to at least 1.10, subject to any necessary regulatory or judicial approvals. The Indenture requires that these amounts, together

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with other moneys available to us, provide us moneys sufficient to remain in compliance with our obligations under the Indenture. We calculate the margins for interest ratio by dividing our margins for interest by our interest charges.

Margins for interest under the Indenture equal:

• our net margins;

• plus revenues that are subject to refund at a later date which were deducted in the determination of net margins;

• plus non-recurring charges that may have been deducted in determining net margins;

• plus total interest charges (calculated as described below);

• plus income tax accruals imposed on income after deduction of total interest for the applicable period.

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

Interest charges under the Indenture equal our total interest charges (other than capitalized interest) related to (1) all obligations under the Indenture, (2) indebtedness secured by a lien equal or prior to the lien of the Indenture, and (3) obligations secured by liens created or assumed in connection with a tax-exempt financing for the acquisition or construction of property used by us, in each case including amortization of debt discount and expense or premium.

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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, 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.

Basis of Presentation

The accompanying financial statements reflect the consolidated accounts of Old Dominion Electric Cooperative (“ODEC” or “we” or “our”), its subsidiaries and TEC Trading, Inc. (“TEC”). See Note 1—Summary of Significant Accounting Policies in Note 1 in the Notes to the Consolidated Financial Statements in Item 8.

Overview

ODEC is a not-for-profit power supply cooperative owned entirely by its twelve member distribution cooperatives and a thirteenth member, TEC. We supply our member distribution cooperatives’ power requirements, consisting of capacity requirements and energy requirements, through a portfolio of resources including generating facilities, long-term and short-term physically-delivered forward power purchase contracts, and spot market purchases.

Our financial results for the year ended December 31, 2006, were significantly impacted by changing conditions in the power markets. As prices for energy and natural gas fell in 2006, the fair value of our forward purchase power contracts and natural gas futures, which we use to mitigate market price risk, decreased. This was the primary reason for the decrease in our regulatory liabilities, and the corresponding reduction in our net cash provided by operating activities. Although spot market prices for energy and natural gas were generally lower in 2006 as compared to 2005, our purchased power and fuel expense increased because we acquired or hedged the majority of our 2006 power needs in prior years, and our reliance on the spot market was minimal.

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.

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

Deferred Energy

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

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 approved by our board of directors. Our formulary rate allows us to recover and refund amounts under the Margin Stabilization Plan. We record all adjustments, whether increases or decreases, in the year affected and allocate any adjustments to our member distribution cooperatives based on power sales during that year. We collect these increases from our member distribution cooperatives, or offset decreases against amounts owed by our member distribution cooperatives to us, in the succeeding calendar year. Each quarter we adjust revenues and accounts payable—members or accounts receivable, as appropriate, to reflect these adjustments. In 2006 and 2005, under our Margin Stabilization Plan, we reduced operating revenues by $2.8 million and $13.3 million, respectively, and increased accounts payable—members by the same amounts. There was no adjustment to operating revenues under our Margin Stabilization Plan in 2004.

Accounting for Asset Retirement Obligations

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

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In March 2005, the FASB issued Interpretation No. 47 “Accounting for Conditional Asset Retirement Obligations, an Interpretation of Financial Accounting Standards Board (“FASB”) Statement No. 143” (“FIN 47”). FIN 47 is a further clarification of SFAS No. 143 and requires the establishment of a liability for conditional asset retirement obligations. A conditional asset retirement obligation is a legal obligation to perform an asset retirement activity in which the timing and/or method of settlement are conditional on a future event that may or may not be within the control of the entity. Uncertainty about the timing and/or method of settlement is required to be considered in the measurement of the liability when sufficient information exists. FIN 47 also clarifies when an entity would have sufficient information to reasonably estimate the fair value of an asset retirement obligation. We adopted FIN 47 as of December 31, 2005, and the impact on our results of operations and financial condition was immaterial.

A significant portion of our asset retirement obligations relates to our share of the future decommissioning of the North Anna Nuclear Power Station (“North Anna”). At December 31, 2006, North Anna’s nuclear decommissioning asset retirement obligation totaled $51.5 million, which represented approximately 92.3% of our total asset retirement obligations. Because of its significance, the following discussion of critical assumptions inherent in determining the fair value of asset retirement obligations relates to those associated with our nuclear decommissioning obligations.

We obtain from third-party experts periodic site-specific “base year” cost studies in order to estimate the nature, cost and timing of planned decommissioning activities for North Anna. These cost studies are based on relevant information available at the time they are performed; however, estimates of future cash flows for extended periods are by nature highly uncertain and may vary significantly from actual results. In addition, these estimates are dependent on subjective factors, including the selection of cost escalation rates, which we consider to be a critical assumption. These studies were last performed in 2005 and received in 2006.

We determine cost escalation rates, which represent projected cost increases over time, due to both general inflation and increases in the cost of specific decommissioning activities. The weighted average cost escalation rate used for the study performed in 2002 was 3.27%. The weighted average cost escalation rate used for the study performed in 2005 was 2.42% and this rate was applied when the cash flows increased as compared to the cash flows in the 2002 study. If the cash flows decreased, the 2002 rate of 3.27% was applied. The use of alternative rates would have been material to the liabilities recognized. For example, had we increased the cost escalation rates by 0.5% to 3.77% and 2.92%, the amount recognized as of December 31, 2006, for our asset retirement obligations related to nuclear decommissioning would have been $10.4 million higher.

Accounting for Derivative Contracts

We primarily purchase power under both long-term and short-term physically-delivered forward contracts to supply power to our member distribution cooperatives under our wholesale power contracts with them. See “Member Distribution Cooperatives — Wholesale Power Contracts” in Item 1. These forward purchase contracts meet the accounting definition of a derivative; however, a majority of the forward purchase derivative contracts qualify for the normal purchases/normal sales accounting exception under SFAS No. 133 “Accounting for Derivative Instruments and Hedging Activities.” As a result, these contracts are not recorded at fair value. We record a liability and purchased power expense when the power under the forward physical delivery contract is delivered. We also purchase natural gas futures generally for three years or less to hedge the price of natural gas for the operation of our combustion turbine facilities and for use as a basis in determining the price of power in certain forward power purchase agreements. These derivatives do not qualify for the normal purchases/normal sales accounting exception.

For all derivative contracts that do not qualify for the normal purchases/normal sales accounting exception, we may elect cash flow hedge accounting in accordance with SFAS No. 133. Accordingly, gains and losses on derivative contracts are deferred into Other Comprehensive Income until the hedged underlying transaction occurs or is no longer likely to occur. For derivative contracts where hedge accounting is not utilized, or for which ineffectiveness exists, we defer all remaining gains and losses on a net basis as a regulatory asset or liability in accordance with SFAS No. 71. These amounts are subsequently reclassified as purchased power or fuel expense in our Consolidated Statements of Revenues, Expenses, and Patronage Capital as the power or fuel is delivered and/or the contract settles.

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

Factors Affecting Results

Formulary Rate

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

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

• all of our costs and expenses;

• 20% of our total interest charges; and

• additional equity contributions approved by our board of directors.

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

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

Capacity costs, which are primarily fixed costs, such as depreciation expense, interest expense, administrative and general expenses, capacity costs under power purchase contracts with third parties, transmission costs, and our margin requirements and additional amounts approved by our board of directors are recovered through our demand rate. The formulary rate allows us to change the actual demand rate we charge as our capacity related costs change, without seeking FERC approval, with the exception of decommissioning cost, which is a fixed number in the formulary rate that requires FERC approval prior to any adjustment. FERC approval is also needed to change account classifications currently in the formula or to add accounts not otherwise included in the current formula. Additionally, future depreciation studies are to be filed with FERC for their approval if it would result in a change in our depreciation rates. Our demand rate is revised automatically to recover the costs contained in our budget and any revisions made by our board of directors to our budget.

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Recognition of Revenue

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

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

Consumers’ Requirements for Power

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

Weather

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

Power Supply Resources

Market forces influence the structure of new power supply contracts into which we enter. When we enter into long-term power purchase contracts or agree to purchase energy at a date in the future, we rely on models based on our judgments and assumptions of factors such as future demand for power and market prices of energy and the price of commodities, such as natural gas used to generate electricity. Our actual results may vary from what our models predict, which may in turn impact our resulting costs to our members. Additionally, our models become less reliable the further into the future that the estimates are made.

We satisfy the majority of our member distribution cooperatives’ capacity requirements and slightly less than half of their energy requirements through our ownership interests in the Clover Power Station (“Clover”), North Anna, the Louisa Generating Facility (“Louisa”), the Marsh Run Generating Facility (“Marsh Run”), and the Rock Springs Generating Facility (“Rock Springs”), and we purchase power under long-term and short-term physically-delivered forward contracts and in the spot market to supply the remaining needs of our member distribution cooperatives.

Our operating expenses are significantly affected by the extent to which we purchase power and, relatedly, the availability of our base load generating facilities, Clover and North Anna. Base load generating facilities,

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particularly nuclear power plants such as North Anna, generally have relatively high fixed costs. Nuclear facilities operate with relatively low variable costs due to lower fuel costs and technological efficiencies. In addition, coal-fired facilities have relatively low variable costs, as compared to combustion turbine facilities such as Louisa, Marsh Run and Rock Springs. Owners of power plants incur the fixed costs of these facilities whether or not the units operate. When either Clover or North Anna is off-line, we must purchase replacement energy from either Virginia Electric & Power Company (“Virginia Power”) or from the market. As a result, our operating expenses, and consequently our rates to our member distribution cooperatives, are significantly affected by the operations of Clover and North Anna but not our combustion turbine facilities. Our combustion turbine facilities have relatively low fixed costs and greater operational flexibility; however, they are more expensive to operate and, as a result, we will operate them only when the market price of energy makes their operation economical or when their operation is required by PJM for system reliability purposes. The output of Clover and North Anna for the past three years as a percentage of maximum dependable capacity rating of the facilities was as follows:

	Clover						North Anna
	Year Ended December 31,						Year Ended December 31,
	2006		2005		2004		2006		2005		2004
Unit 1	90.8	%	86.7	%	82.2	%	88.2	%	99.9	%	91.3	%
Unit 2	91.3		80.7		92.2		99.7		91.3		91.7
Combined	91.1		83.7		87.2		94.0		95.6		91.5

Clover

Clover Unit 1 was off-line five days in 2006, nine days in 2005, and 37 days in 2004 for scheduled maintenance. Clover Unit 1 was off-line approximately two days in 2006 and eight days in 2005 for minor unscheduled outages.

Clover Unit 2 was off-line five days in 2006, 34 days in 2005, and five days in 2004 for scheduled maintenance. Clover Unit 2 was off-line approximately two days in 2006 and nine days in 2005 for minor unscheduled outages.

On May 1, 2005, operational control of Virginia Power’s transmission facilities was transferred to PJM Interconnection, LLC (“PJM”). With that transfer, all of our member distribution cooperatives’ capacity and energy requirements are now within the PJM control area and our generating facilities are now under dispatch control of PJM. Accordingly, Clover Units 1 and 2 are operated pursuant to PJM dispatching requirements. During 2005, Clover Units 1 and 2 were dispatched less by PJM than they were by Virginia Power in prior years. When our generating facilities are dispatched less, we purchase more power to meet the needs of our member distribution cooperatives.

North Anna

North Anna Unit 1 was off-line for 29 days for a scheduled refueling and maintenance outage during 2006. North Anna Unit 1 experienced minor unscheduled outages during 2005 and was off-line 24 days in 2004 for a scheduled refueling outage.

North Anna Unit 2 experienced minor unscheduled outages during 2006 and 2005. North Anna Unit 2 was off-line for 28 days in 2005 and 28 days in 2004 for a scheduled refueling outage.

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Combustion turbine facilities

During 2006, 2005, and 2004, the operational availability of our Louisa, Marsh Run, and Rock Springs combustion turbine facilities was as follows:

	Year Ended December 31,
	2006		2005		2004
Louisa	99.2	%	98.2	%	96.8	%
Marsh Run	93.6		97.4		90.5
Rock Springs	91.2		95.8		96.5

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 approved 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.

Indenture Rate Covenant

Under the Indenture, we are required, subject to any necessary regulatory or judicial approvals, to establish and collect rates reasonably expected to yield margins for interest for each fiscal year equal to at least 1.10 times our total interest charges for the fiscal year. The Indenture requires that these amounts, together with other moneys available to us, provide us moneys sufficient to remain in compliance with our obligations under the Indenture. See Item 6, “Selected Financial Data” for a description of the calculations of margins for interest and interest charges under the Indenture, and “—Restated Indenture” in Item 2 for a discussion of the effect of a possible amendment and restatement of the Indenture.

Results of Operations

Operating Revenues

Operating revenues are derived from power sales to our members and non-members. Sales to members include sales to our Class A members, which are our twelve distribution cooperative members, and, for 2004, sales to our single Class B member, TEC. Our operating revenues by type of purchaser for the past three years were as follows:

	Year Ended December 31,
	2006		2005		2004
	(in thousands)
Revenues from sales to members:
Member distribution cooperatives	$	746,506	$	657,022	$	564,624
TEC		—		—		18,890
Total revenues from sales to members		746,506		657,022		583,514
Revenues from sales to non-members		71,009		80,657		4,937
Total revenues	$	817,515	$	737,679	$	588,451

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In accordance with Financial Accounting Standards Board Interpretation No. 46R, “Consolidation of Variable Interest Entities, an Interpretation of Accounting Research Bulletin No. 51” (“FIN 46”), TEC is considered a variable interest entity for which Old Dominion was the primary beneficiary. Beginning in 2005, the income statement of TEC is consolidated and the inter-company revenues and expenses are eliminated in consolidation. Beginning January 1, 2005, we reported no sales to TEC because TEC is now consolidated as a result of the adoption of FIN 46. TEC’s sales to third parties are reflected as non-member revenues.

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.”

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:

	Year Ended December 31,
	2006		2005		2004
	(in thousands)
Revenues from sales to member distribution cooperatives:
Base energy revenues	$	198,376	$	200,993	$	189,897
Fuel factor adjustment revenues		317,652		232,345		141,795
Total energy revenues		516,028		433,338		331,692
Demand (capacity) revenues		230,478		223,684		232,932
Total revenues from sales to member distribution cooperatives	$	746,506	$	657,022	$	564,624
Energy sales to member distribution cooperations (in MWh)		11,026,284		11,191,729		10,518,241
Average costs to member distribution cooperatives (per MWh)(1)	$	67.70	$	58.71	$	53.68

⁽¹⁾ Our average costs to our member distribution cooperatives is based on the blended cost of power from all of our power supply resources.

2006 Compared to 2005

Total revenues from sales to our member distribution cooperatives for the year ended December 31, 2006, increased $89.5 million, or 13.6%, as compared to the same period in 2005, primarily as a result of higher energy rates.

Our total energy rate (including our base energy rate and our fuel factor adjustment rate) was 20.9% higher, on a per MWh basis, for the year ended December 31, 2006, as compared to the same period in 2005. Due to continued increases in our energy costs and the need to collect revenues to reduce our deferred energy balance, we increased our fuel factor adjustment rate effective April 1, 2006, and again on October 1, 2006, resulting in an increase to our total energy rate of approximately 11.9% and 5.2%, respectively. Energy sales volumes were essentially flat, decreasing approximately 1.5% in 2006 as compared to 2005.

The capacity costs we incurred, and thus the capacity-related revenues we reflected, increased $6.8 million, or 3.0% for the year ended December 31, 2006, as compared to the same period in 2005, as a result of the collection of $9.0 million in additional equity contribution partially offset by decreases in our transmission and general and administrative costs.

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Our average costs per MWh to member distribution cooperatives increased $8.99 per MWh, or 15.3%, for the year ended December 31, 2006, as compared to the same period in 2005, as a result of the increase in our total energy rate.

2005 Compared to 2004

Total revenues from sales to our member distribution cooperatives for the year ended December 31, 2005, increased $92.4 million, or 16.4%, as compared to the same period in 2004, primarily as a result of higher energy rates and increased sales of energy.

Our total energy rate (including our base energy rate and our fuel factor adjustment rate) was 22.8% higher, on a per MWh basis, for the year ended December 31, 2005, as compared to the same period in 2004. Due to continued higher energy costs in 2005, we increased our fuel factor adjustment rate effective April 1, 2005, resulting in an increase to our total energy rate of approximately 14.6%. During 2005, energy costs continued to rise and we increased our fuel factor adjustment rate effective October 1, 2005, resulting in an increase to our total energy rate of approximately 8.1%.

Sales volumes increased approximately 6.4% as a result of colder weather experienced by customers of our member distribution cooperatives in March of 2005 as compared to the same period in 2004, and warmer weather in June through September 2005 as compared to the same period in 2004, which created a greater requirement for power to operate heating and air conditioning systems.

The capacity costs we incurred, and thus the capacity-related revenues we reflected, for the year ended December 31, 2005, as compared to the same period in 2004, decreased $9.2 million, or 4.0%, primarily as a result of lower demand costs incurred in 2005.

Our average costs per MWh to member distribution cooperatives increased $5.03 per MWh, or 9.4%, for the year ended December 31, 2005, as compared to the same period in 2004, as a result of the increase in our total energy rate, partially offset by the increase in sales volumes.

Sales to TEC

In accordance with Financial Accounting Standards Board Interpretation No. 46R, “Consolidation of Variable Interest Entities, an Interpretation of Accounting Research Bulletin No. 51” (“FIN 46”), TEC is considered a variable interest entity for which Old Dominion was the primary beneficiary. Beginning in 2005, the income statement of TEC was consolidated and the inter-company revenues and expenses were eliminated in consolidation. Beginning January 1, 2005, we reported no sales to TEC because TEC was consolidated as a result of the adoption of FIN 46. TEC’s sales to third parties are reflected as non-member revenues. Prior to January 1, 2005, sales to TEC consisted primarily of sales of excess energy that we did not need to meet the requirements of our member distribution cooperatives. We sold the portion of this energy that could not be utilized by our member distribution cooperatives to TEC for resale into the market, or to non-members.

Sales to Non-Members

Sales to non-members consist of sales of excess purchased energy and sales of excess generated energy. We primarily sell excess energy to PJM under its rates for providing energy imbalance services. Excess energy is sold at the prevailing market price at the time of sale and is the result of changes in our purchased power portfolio, differences between actual and forecasted needs, as well as changes in market conditions. Prior to May 1, 2005, we also sold excess energy from Clover to Virginia Power pursuant to the requirements of the Clover operating agreement. Non-member revenue decreased by $9.6 million, or 12.0%, in 2006 as compared to the same period in 2005 due to the decrease in the average price at which we sold excess energy. Beginning in 2005, TEC’s sales to third parties were reflected as sales to non-members. Our non-member energy sales in MWh for 2006, 2005, and 2004, were 1,349,473, 1,318,647, and 87,836, respectively.

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Operating Expenses

We supply our member distribution cooperatives’ power requirements, consisting of capacity requirements and energy requirements, through (1) our interests in electric generating facilities which consist of a 50% interest in Clover, an 11.6% interest in North Anna, our Louisa, Marsh Run, and Rock Springs combustion turbine facilities, and distributed generation, and (2) long-term and short-term physically-delivered forward power purchase contracts and spot purchases of power in the open market See “Power Supply Resources” in Item 1.

Components of Operating Expense

The components of our operating expenses for the years ended December 31, 2006, 2005, and 2004, were as follows:

	Year Ended December 31,
	2006		2005			2004
	(in thousands)
Fuel	$	154,931	$	143,332		$	90,635
Purchased power		464,047		434,557			314,763
Deferred energy		6,414		(26,135	)		(8,775	)
Operations and maintenance		35,551		34,221			40,595
Administrative and general		32,502		34,523			28,800
Depreciation, amortization and decommissioning		38,393		38,556			32,759
Amortization of regulatory asset/(liability), net		2,701		1,909			20,543
Accretion of asset retirement obligations		2,783		2,496			2,251
Taxes, other than income taxes		6,732		6,024			5,265
Total operating expense	$	744,054	$	669,483		$	526,836

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

2006 Compared to 2005

Total operating expenses for 2006 increased $74.6 million, or 11.1%, over 2005 primarily due to the change in deferred energy expense and increases in purchased power expense and fuel expense.

Deferred energy expense changed $32.5 million, or 124.5%, as compared to 2005 reflecting an over-collection of energy costs in 2006 as compared to 2005 when we under-collected our costs. Our deferred energy balance changed from a net under-collection of energy costs of $21.3 million to a net under-collection of energy costs of $14.9 million, reflecting the fact that our energy rate allowed us to collect all of our current year energy costs as well as $6.4 million of prior year energy costs.

Purchased power expense increased $29.5 million, or 6.8%, as a result of an 11.5% increase in the average price of purchased power, partially offset by a 4.2% decrease in the volume of purchases of additional energy from the market to supply our member distribution cooperatives’ requirement. Clover generated more energy in 2006 than in 2005 because it was dispatched by PJM more in 2006 than in 2005 and had fewer scheduled maintenance outage days, thereby reducing our need to purchase energy from the market.

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Fuel expense increased $11.6 million, or 8.1%, primarily due to the 15.8% increase in our average price of coal partially offset by the 7.1% decrease in our average price of natural gas in 2006 as compared to 2005.

2005 Compared to 2004

Total operating expenses for 2005 increased $142.6 million, or 27.1%, over 2004 primarily due to increases in purchased power expense and fuel expense. These increases were partially offset by the change in the amortization of regulatory asset/(liability), net and the change in deferred energy expense.

Purchased power expense increased $119.8 million, or 38.1%, as a result of the purchase of additional energy from the market to supply our member distribution cooperatives’ requirements and a 14.2% increase in the average price of purchased power. During 2005, Clover was dispatched less by PJM based upon economic factors, which resulted in increased purchased power.

Fuel expense increased $52.7 million, or 58.1%, primarily due to the 62.6% increase in the average price of coal and the 35.8% increase in the average price of natural gas in 2005 as compared to 2004. Marsh Run began commercial operation in September of 2004.

Amortization of regulatory asset/(liability), net changed $18.6 million, or 90.7%, resulting in decreased operating expenses primarily due to the acceleration of the amortization of a regulatory asset in 2004. This regulatory asset was established in 2002 in connection with the collection of additional amounts we collected and then paid relating to a dispute under a power purchase agreement with Public Service Gas and Electric Company (“PSE&G”).

Deferred energy expense changed $17.4 million, or 197.8%, over 2004 reflecting a greater under-collection of energy costs in 2005 as compared to 2004. The $26.1 million we under-collected in 2005 changed our deferred energy balance from a $4.8 million liability at December 31, 2004, to a $21.3 million asset at December 31, 2005.

Other Items

Investment Income

Investment income increased in 2006 by $4.0 million, or 60.0%, primarily due to income earned on our increased average balances in cash and temporary investments as a result of higher member prepayments and higher interest rates.

Investment income increased in 2005 by $3.7 million, or 128.6%, as a result of both higher yields on our cash and temporary investments and higher investable balances than in 2004. We earned higher yields on our invested funds largely as a result of increased market interest rates in 2005. Our higher investable balance occurred primarily during the last five months of the 2005 when we held cash posted from counterparties under terms of our power purchase and sale agreements.

Interest Charges, Net

The primary factors affecting our interest expense are scheduled payments of principal on our indebtedness, interest related to our potential liability associated with our dispute with Norfolk Southern, and capitalized interest.

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The major components of interest charges, net for the years ended December 31, 2006, 2005, and 2004, were as follows:

	Year Ended December 31,
	2006			2005			2004
	(in thousands)
Interest expense on long-term debt	$	(55,542	)	$	(56,700	)	$	(56,252	)
Other		(5,676	)		(3,845	)		(4,415	)
Total Interest Charges		(61,218	)		(60,545	)		(60,667	)
Allowance for borrowed funds used during construction		269			198			8,161
Interest Charges, net	$	(60,949	)	$	(60,347	)	$	(52,506	)

Interest charges, net remained relatively flat as compared to 2005. Other interest increased $1.8 million, or 47.6%, as compared to 2005, primarily as a result of accrued interest on our potential liability related to our dispute with Norfolk Southern. Interest expense on long-term debt decreased $1.2 million as a result of our declining long-term debt balance. Interest charges, net increased in 2005 by $7.8 million, or 14.9%, as compared to 2004, primarily due to the reduction of capitalized interest associated with Marsh Run. We ceased capitalizing interest on Marsh Run in September 2004 when the facility became commercially operable. Capitalized interest is computed monthly using an interest rate, which reflects our embedded cost of indebtedness, multiplied by our investment in projects under construction.

Financial Condition

The principal changes in our financial condition from December 31, 2005 to December 31, 2006, were caused by decreases in regulatory liabilities, deferred charges—other, net electric plant, deposits, accounts payable—deposits and accounts receivable, and increases in accounts receivable—deposits and patronage capital. Regulatory liabilities decreased $43.8 million primarily due to the change in the fair value of our forward purchase power contracts and natural gas futures for which cash flow hedge accounting is not utilized. Deferred charges—other decreased $39.9 million also as a result of the decrease in the fair value of our forward purchased power contracts and natural gas futures, partially offset by the resulting increase in the amount of collateral we were required to post in connection with our natural gas futures. Net electric plant decreased $27.1 million as we continued to depreciate our existing generating facilities. Deposits and accounts payable—deposits both decreased $24.7 million. As of December 31, 2005, our counterparties were required to post $24.7 million in deposits in accordance with the terms of our respective master power purchase and sales agreements with them. At December 31, 2006, due to changes in energy prices, our counterparties were not required to post deposits. Accounts receivable decreased $21.2 million as a result of decreased sales of excess power to non-members. Accounts receivable-deposits increased $23.6 million related to collateral we were required to post with our counterparties. Patronage capital increased $21.2 million as a function of our interest coverage requirement and the additional $9.0 million that our board of directors approved to be collected through rates in 2006.

Liquidity and Capital Resources

Sources

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

Operations

Historically, our operating cash flows have been sufficient to meet our short- and long-term capital expenditures related to our existing generating facilities, our debt service requirements, and our ordinary business operations. Our operating activities provided cash flows of $14.5 million, $122.6 million, and $0.9 million, in 2006, 2005, and 2004, respectively. Operating activities in 2006 were primarily impacted by the change in regulatory

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assets and liabilities, and current liabilities, partially offset by changes in deferred charges and credits, deferred energy and current assets. Regulatory assets and liabilities changed $55.8 million primarily due to the reduction in the fair value of our derivatives. Current liabilities changed $30.9 million primarily as a result of decreased accounts payable—deposits as a result of the change in the amount of deposits posted by our counterparties in accordance with the terms of our respective master power purchase and sales agreements with them and decreased accounts payable—members as a result of a lower margin stabilization adjustment in 2006 as compared to 2005 and lower member prepayment balances. Deferred charges and credits changed $14.5 million as a result of the reduction in the fair value of our derivatives which was partially offset by the resulting increase in the amount of collateral we were required to post. At December 31, 2006, we had an under-collected deferred energy balance of $14.9 million as compared to an under-collected deferred energy balance of $21.3 million at December 31, 2005, which resulted in a cash inflow of $6.4 million. Current assets changed $3.0 million related to the changes in accounts receivable and accounts receivable deposits. Deposits decreased $24.7 million as a result of changes in deposits posted by our counterparties in accordance with the terms of our respective master power purchase and sales agreements with them. Accounts receivable decreased $21.2 million as a result of decreased purchased power receivables, which was offset by an increase of $23.6 million related to collateral we were required to post with our counterparties.

Credit Facilities

In addition to liquidity from our operating activities, we maintain committed lines of credit and revolving credit facilities to cover our short- and medium-term funding needs. Currently, we have short-term committed variable rate lines of credit in an aggregate amount of $180.0 million, all of which are available for general working capital purposes. At December 31, 2006 and 2005, we had no short-term borrowings or letters of credit outstanding under any of these arrangements. We expect these working capital lines of credit to be renewed as they expire.

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

Lender	Amount		Expiration Date
	(in millions)
Bank of America, N.A.	$	30.0	September 30, 2007
Bank of America, N.A.		30.0	June 25, 2007
Branch Banking and Trust Company of Virginia		25.0	April 30, 2007
CoBank, ACB		25.0	October 30, 2007
JPMorgan Chase Bank, N.A.		70.0	May 8, 2007
	$	180.0

In addition to our lines of credit, we have two committed three-year revolving credit facilities, $50.0 million each, available for capital expenditures and general corporate purposes. Our revolving credit facility with CoBank, ACB expires on June 18, 2007. Our revolving credit facility with National Rural Utilities Cooperative Finance Corporation expires on January 30, 2009. As of December 31, 2006 and 2005, there were no borrowings or letters of credit outstanding under these facilities.

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

• our failure to timely pay any principal and interest due under that credit facility;

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• a breach by us of our representations and warranties in the credit agreement or related documents;

• a breach of a covenant contained in the credit agreement, which, in some cases we are given an opportunity to cure and, in one case, includes a debt to capitalization financial covenant;

• failure to pay, when due, other indebtedness above a specified amount;

• an unsatisfied judgment above specified amounts; and

• bankruptcy events relating to us.

Financings

We fund the portion of our capital expenditures that we are not able to supply from operations through financings in the market. Since 1983, these capital expenditures have consisted primarily of the costs related to the acquisition of our interest in North Anna, our share of the costs to construct Clover, and the development and construction of our three combustion turbine facilities. In 2006 and 2005, we did not engage in any material financing activities.

Uses

Our uses of liquidity and capital relate to funding our working capital needs, investment activities and financing activities. Substantially all of our investment activities relate to capital expenditures in connection with our generating facilities. We expect that cash flows from our operations and our existing lines of credit and revolving credit facilities will be sufficient to meet our currently anticipated operational and capital requirements.

Capital Expenditures

We regularly forecast our capital expenditures as part of our long-term business planning activities. We review these projections frequently in order to update our calculations to reflect changes in our future plans, construction costs, market factors, and other items affecting our forecasts. Our actual capital expenditures could vary significantly from these projections. The table below summarizes our actual and projected capital expenditures, including nuclear fuel and capitalized interest, for 2004 through 2009:

	Actual Year Ended December 31,						Projected Year Ended December 31,
	2004		2005		2006		2007		2008		2009
	(in millions)
Combustion turbine facilities	$	38.5	$	5.1	$	0.3	$	0.5	$	0.5	$	0.5
Clover		3.4		1.6		3.9		1.9		6.3		2.9
North Anna		11.7		13.2		14.7		15.4		15.5		15.0
Other		1.0		0.2		1.1		3.2		0.6		0.6
Total	$	54.6	$	20.1	$	20.0	$	21.0	$	22.9	$	19.0

Nearly all of our capital expenditures consist of additions to electric plant and equipment. Our future capital requirements include our portion of the cost of the nuclear fuel purchased for North Anna and other capital expenditures including generation facility improvements. We intend to use our cash from operations to fund all of our currently projected capital requirements through 2009.

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Contractual Obligations

In the normal course of business, we enter into long-term arrangements relating to the construction, operation and maintenance of our generating facilities, power purchases, the financing of our operations and other matters. See “Business—Power Supply Resources—Power Purchase Contracts” in Item 1 and “Future Issues—Reliance on Market Purchases of Energy.” The following table summarizes our long-term contractual obligations at December 31, 2006:

	Payments due by Period
Contractual Obligations	Total		Less than 1 year		1-3 years		3-5 years		More than 5 years
	(in millions)
Long-term indebtedness	$	1,371.5	$	69.8	$	142.2	$	387.5	$	772.0
Operating lease obligations		379.3		2.7		7.7		12.2		356.7
Power purchase obligations		656.4		351.4		305.0		—		—
Asset retirement obligations		249.9		—		—		—		249.9
Total	$	2,657.1	$	423.9	$	454.9	$	399.7	$	1,378.6

We have no capital lease obligations, no purchase obligations, no other long-term liabilities, and no construction obligations that are considered contractual obligations.

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

Long-Term Indebtedness

At December 31, 2006, nearly all of our long-term indebtedness was issued under the Indenture. This indebtedness includes bonds issued to the public and bonds issued to local governmental authorities in consideration for loans to us of the proceeds of tax-exempt offerings of indebtedness by those governmental authorities. Long-term indebtedness includes both the principal of and interest on long-term indebtedness, long-term indebtedness due within one year and unamortized discounts and premiums relating to long-term indebtedness.

Operating Lease Obligations

In 1996, we entered into two separate long-term lease transactions of our undivided interests in each of Clover Unit 1 and Clover Unit 2. See “Properties—Clover” in Item 2. Our obligations described above relate to a portion of our obligations under these leases, including periodic basic rent. We fund substantially all of our payment of these obligations through the application of the proceeds of investments we purchased at the time we entered into the leases. The investments are rated “AAA” by Standard & Poor’s Ratings Services (“S&P”) and “Aaa” by Moody’s Investors Service (“Moody’s”). Operating lease obligations includes (1) periodic basic rent obligations under the two separate long-term lease transactions which will not be satisfied by the payment undertakers under the payment undertaking agreements, and (2) the purchase option prices at the end of the term of the Leasebacks.

Power Purchase Obligations

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

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Asset Retirement Obligations

Effective January 1, 2003, we adopted Statement of Financial Accounting Standards No. 143 “Accounting for Asset Retirement Obligations” which requires legal obligations associated with the retirement of long-lived assets to be recognized at fair value when incurred and capitalized as part of the related long-lived asset. A significant portion of our asset retirement obligations relates to the future decommissioning of North Anna by 2059.

Significant Contingent Obligations

In addition to these existing contractual obligations, we have significant contingent obligations. These obligations primarily relate to our power purchase arrangements and leases of our interest in Clover. See “Properties—Clover” in Item 2.

To facilitate the ability of TEC, which is consolidated in our financial statements as of December 31, 2004, to sell power in the market, we have agreed to guarantee up to a maximum of $60.0 million of TEC’s delivery and payment obligations associated with its energy trades if requested. See “Business—TEC” in Item 1. Our agreement to guarantee these obligations continues in effect until we elect to terminate it by providing at least 30 days prior written notice of termination or until all amounts owed to us by TEC have been paid. Our guarantee of TEC’s obligations will enable it to maintain sufficient credit support to meet its delivery and payment obligations associated with its energy trades. At December 31, 2006, we had issued guarantees for up to $11.0 million of TEC’s obligations and $0.2 million of such obligations were outstanding.

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

In connection with the lease and leaseback of our undivided interest in Clover Unit 1, we agreed to deliver a letter of credit to the institutional investor party to the lease within 90 days after our obligations under the Indenture are either rated below “A-” by S&P or “Baa2” by Moody’s, or if such obligations are placed on negative credit watch by either S&P or Moody’s while rated “A-” by S&P or “Baa2” by Moody’s, respectively. If our ratings had been below this minimum rating at December 31, 2006, the amount of the letter of credit we would have been required to provide was $53.8 million. The amount of any letter of credit we are required to deliver in connection with the lease decreases over time to zero by December 18, 2018.

In addition, like many other utilities, we purchase power in the market pursuant to a form master power purchase and sale agreement (“EEI Form Contract”) prepared by the Edison Electric Institute, an association of U.S. investor-owned electric utilities and industry affiliates. The EEI Form Contract is intended to standardize the terms and conditions of purchases of power in the market and consequently foster trading among utilities. Under the terms of the EEI Form Contract, a utility may agree to provide collateral under certain circumstances. Under the terms of our EEI Form Contracts, the collateral we may be required to post is normally a function of the collateral thresholds we negotiate with a counterparty relative to a range of credit ratings as well as the value of our transaction(s) under the EEI Form Contract with a respective counterparty. At December 31, 2006, we had $23.6 million of collateral on deposit with counterparties pursuant to the EEI Form Contracts we have in place. Typically, collateral thresholds under our EEI Form Contracts are zero once an entity is rated below investment grade by S&P or Moody’s (i.e., “BBB-” or “Baa3”). We are also party to two other power purchase agreements with credit provisions similar to those in our EEI Form Contracts. At December 31, 2006, if the credit ratings referenced in our EEI form contracts or our two other power purchase agreements fell below investment grade we estimate we would have been obligated to post approximately $67.0 million of collateral with our counterparties, which is in addition to the $23.6 million referenced above. This calculation is based on energy prices on December 31, 2006 and delivered power for which we have not yet paid. Depending on the difference between the price of power under the contracts and the price of power in the market at the time of the calculation, this amount could increase or decrease.

Additionally, in accordance with the credit policy of PJM, PJM subjects each applicant, participant and member of PJM to a complete credit evaluation to determine its creditworthiness, and whether it must provide any

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collateral to support its obligations in connection with its PJM transactions. A material change in our financial condition, including the downgrading of our credit rating by any rating agency, could cause PJM to re-evaluate our creditworthiness and require that we provide collateral. As of December 31, 2006, if PJM determined that we needed to provide collateral to support our obligations, PJM could have asked us to provide up to approximately $16.9 million of collateral.

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

Off-Balance Sheet Arrangements

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

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

• our periodic basic rent payments under the leasebacks; and

• the fixed purchase price of the interests in the units at the end of the terms of the leasebacks if we exercise our option to purchase the interests of the owner trusts in the units at that time.

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

Both leasebacks require us to make periodic basic rental payments. For 2006, our statement of cash flow reflects payments we made of basic rent to the Unit 1 and Unit 2 owner trusts of $0.9 million and $1.9 million, respectively. Of these payments, $0.6 million and $1.9 million, respectively, were funded through distributions from the investments made with lease proceeds. In addition to these amounts, approximately $7.8 million and $17.5 million of additional basic rent was required under the Unit 1 and Unit 2 leases, respectively, in 2006. These additional amounts of basic rent were paid by third parties, “payment undertakers,” under payment undertaking agreements. As described above, we made a payment to each of the payment undertakers at the inception of the leasebacks in consideration for the payment undertakers agreeing to pay additional amounts of basic rent as they become due. We have no obligation to pay or repay additional amounts to the payment undertaker in the future. Under each of these arrangements, we made a payment to the payment undertaker in return for which the payment undertaker agreed to make payments directly to the lender in the related lease transaction in satisfaction of a portion of our basic rent payment obligation under the leaseback and the owner trust’s repayment obligation under the loan to it. At December 31, 2006, both the value of the portion of our lease obligations to be paid by the payment undertaker, as well as the value of our interest in the related payment undertaking agreements, totaled approximately $297.5 million and $242.0 million for Unit 1 and Unit 2, respectively. Our financial statements do not reflect the payment undertaking agreements, the payments made by the payment undertaker or the payment of this portion of basic rent. We remain liable for all rental payments under the leasebacks if the payment undertaker fails to make such payments, although the owner trusts have agreed to pursue the payment undertakers before pursuing payment from us.

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

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

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

In connection with the lease relating to Unit 1, we agreed to deliver a letter of credit to the institutional investor party in the lease in some instances. See “—Significant Contingent Obligations” above.

Tax Increase Prevention and Reconciliation Act of 2005

On May 17, 2006, President Bush signed into law an act entitled the “Tax Increase Prevention and Reconciliation Act of 2005” (the “2005 Tax Act”). Among other provisions, the 2005 Tax Act imposes an excise tax on certain types of leasing transactions entered into by tax-exempt entities. At this time, it is not clear whether the excise tax imposed by the 2005 Tax Act is applicable to our lease transactions. We are continuing to evaluate this legislation and the impact on us; however, specific guidance has not yet been made available. We have revised our estimate of the potential impact and have determined that we do not need to record a liability based upon the currently available information. We have determined that our potential liability for 2006 could range from zero to approximately $1.2 million and that zero represents our best estimate at this time. However, once further guidance is issued, our potential liability under the 2005 Tax Act may change.

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Future Issues

Reliance on Market Purchases of Energy

While the combustion turbine facilities provide most of our capacity requirements above those met by Clover and North Anna, they do not satisfy a significant portion of our energy requirements. Combustion turbine facilities are most economical to operate when the market price of energy is relatively high compared to the variable costs to operate these facilities. By operating the combustion turbine facilities during those times, we reduce our exposure to market energy price volatility risk but use the market to supply energy during other times.

Because we have and will rely heavily on market purchases of energy, we have taken two primary steps to reduce our exposure to future price fluctuations in the energy market. We have secured, through market purchases or energy contracts, a substantial portion of our energy requirements not supplied by our generating facilities or the combustion turbine facilities through the end of 2008. We plan to continue purchasing energy for significant periods into the future by utilizing a combination of long-term and short-term physically-delivered forward fixed price contracts and option contracts for the purchase of energy, as well as spot market purchases. In addition, we plan to use similar efforts to manage our exposure to market changes in the price of fuel, especially changes in the price of natural gas. Second, we have engaged ACES Power Marketing LLC (“APM”), an energy trading and risk management company, to assist us in executing trades to purchase energy, developing a strategy of when to operate the combustion turbine facilities or purchase energy, modeling our power requirements, and analyzing our power purchase contracts and credit risks of counterparties. See “Quantitative and Qualitative Disclosures About Market Risk” in Item 7A. We continue to review our power supply resource options and future requirements. As we have done in the past, we expect to adjust our portfolio of power supply resources to reflect our projected power requirements and changes in the market.

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ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

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

Market Price Risk

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

As an example of our level of exposure to market price risk, a 10% increase in the purchase price of our unhedged power, natural gas and coal purchases is estimated to have increased these expenses by approximately $10.5 million or 1.8% of total energy-related operating expenses in 2006. Conversely, a 10% decrease in these purchase prices is estimated to have decreased expenses by approximately the same amount. This calculation assumes generation and purchases consistent with historical performance and applies the 10% increase or decrease only to purchases not hedged at the beginning of 2006.

The fair value of the hedging instruments we use to mitigate market price risk is impacted by changes in market prices. At December 31, 2006, we estimate that the fair value of our purchase power agreements and forward purchases of energy and natural gas is between $800 million and $900 million. Approximately 75% of the fair value of this portfolio is estimable using observable market prices. The remaining 25% of the fair value of this portfolio is related to less liquid products and the fair values of these products are not directly estimable using observable market prices. In the absence of observable market prices, the valuation of the 25% of this portfolio that relates to less liquid products involves management judgment, the use of estimates, and the underlying assumptions in our portfolio model, which we have developed with the assistance of APM. As a result, changes in estimates and underlying assumptions or use of alternate valuation methods could affect the estimated fair value of this portfolio. As an example of our portfolio’s exposure to market price risk, a 10% increase in the price of the commodities hedged by the portion of this portfolio with observable market prices is estimated to have increased the fair value of this portion of the portfolio by $64.3 million at December 31, 2006. Conversely, a 10% decrease in the price of the commodities hedged by the same portion of this portfolio is estimated to have decreased the fair value of this portion of the portfolio by $64.3 million. To the extent all or portions of our portfolio are liquidated at above or below our original cost, these gains or losses are factored into the energy costs billed to our members pursuant to our formulary rate.

The hedging instruments we use to mitigate market price risk generally include collateral requirements that require us to deposit funds or post letters of credit with counterparties when a counterparty’s credit exposure to us is in excess of agreed upon credit limits. When commodity prices decrease to levels below the levels where we have hedged future costs, we may be required to use a material portion of our cash or liquidity facilities to cover these collateral requirements. For example, at December 31, 2006, we had $48.9 million of collateral on deposit with our counterparties and a further 10% decrease in the price of the commodities hedged by our portfolio would have required us to post additional collateral of approximately $21.1 million at December 31, 2006.

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

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

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

• selling power as our agent and the agent of TEC; and

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

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

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

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

Interest Rate Risk and Equity Price Risk

In 2006, all of our outstanding long-term indebtedness accrued interest at fixed rates, except for a $6.8 million promissory note owed to Virginia Power which relates to the loan to us of a portion of the proceeds of a tax-exempt debt financing. A 2% rise in interest rates would result in our paying Virginia Power approximately $135,000 of additional interest per year.

We also have $180.0 million of committed available lines of credit and $100.0 million available under revolving credit agreements. See Item 7, “Management’s Discussion and Analysis of Financial Condition and Results of Operations—Liquidity and Capital Resources.” Any amounts we borrow under these facilities will accrue interest at a variable rate. During 2006, no amounts were outstanding under any of these facilities.

At December 31, 2006, $20.0 million of our cash and cash equivalents was invested primarily in fixed-income securities. Due to the short-term nature of these investments, an increase or decrease in interest rates is unlikely to materially increase or decrease the income generated by our cash and cash equivalents.

We accrue decommissioning costs over the expected service life of North Anna and have made periodic deposits to a trust fund so that the fund balance will cover the estimated cost to decommission North Anna at the time of decommissioning. At December 31, 2006, $33.4 million of these funds were invested in fixed-income securities and $58.2 million of these funds were invested in equity securities. The value of these equity and fixed income securities will be impacted by changes in interest rates and price fluctuations in equity markets. To minimize adverse changes in the aggregate value of the trust fund, we actively monitor our portfolio by measuring the performance of our investments against market indexes and by maintaining and reviewing established target allocation percentages of assets in our trust to various investment options. We believe the trust fund’s exposure to changes in interest rates and price fluctuations in equity markets will not have a material impact on our financial results.

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Credit Risk

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

Our internal risk management committee has the overall responsibility to review and manage our credit risk and does so on a regular basis. We have adopted a Credit Risk Policy that establishes the basis for determining counterparty credit standards and processes to determine credit limits. Through our relationship with APM, we obtain information and assistance to enable us to manage our credit risk. If required by our credit standards and limits, we require counterparties to provide collateral in the form of letters of credit, cash, parent guarantees or other collateral in the future upon the occurrence of specified events. Our risk management committee monitors our credit exposure on a regular basis. At December 31, 2006, we did not hold collateral related to power and fuel purchases.

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ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA

CONSOLIDATED FINANCIAL STATEMENTS

INDEX

	Page Number
Report of Independent Registered Public Accounting Firm	51
Consolidated Balance Sheets	52
Consolidated Statements of Revenues, Expenses and Patronage Capital	53
Consolidated Statements of Comprehensive Income	54
Consolidated Statements of Cash Flows	55
Notes to Consolidated Financial Statements	56

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Report of Independent Registered Public Accounting Firm

To The Board of Directors

Old Dominion Electric Cooperative

We have audited the accompanying consolidated balance sheets of Old Dominion Electric Cooperative as of December 31, 2006 and 2005, and the related consolidated statements of revenues, expenses and patronage capital, comprehensive income, and cash flows for each of the three years in the period ended December 31, 2006. These financial statements are the responsibility of the Cooperative’s management. Our responsibility is to express an opinion on these financial statements based on our audits.

We conducted our audits in accordance with standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. We were not engaged to perform an audit of the Cooperative’s internal control over financial reporting. An audit includes consideration of internal control over financial reporting as a basis for designing audit procedures that are appropriate in the circumstances, but not for the purpose of expressing an opinion on the effectiveness of the Company’s internal control over financial reporting. Accordingly, we express no such opinion. An audit also includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, and evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.

In our opinion, the financial statements referred to above present fairly, in all material respects, the consolidated financial position of Old Dominion Electric Cooperative at December 31, 2006 and 2005, and the consolidated results of its operations and its cash flows for each of the three years in the period ended December 31, 2006, in conformity with U.S. generally accepted accounting principles.

As discussed in Note 1 to the consolidated financial statements the Cooperative changed its method of accounting for variable interest entities effective December 31, 2004, to comply with the accounting provisions of Financial Accounting Standard Interpretation No. 46R.

Richmond, Virginia

March 14, 2007

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OLD DOMINION ELECTRIC COOPERATIVE

CONSOLIDATED BALANCE SHEETS

AS OF DECEMBER 31, 2006 AND 2005

	2006			2005
	(in thousands)
ASSETS:
Electric Plant:
In service	$	1,527,672		$	1,519,578
Less accumulated depreciation		(509,306	)		(470,735	)
		1,018,366			1,048,843
Nuclear fuel, at amortized cost		8,381			9,018
Construction work in progress		20,342			16,365
Net Electric Plant		1,047,089			1,074,226
Investments:
Nuclear decommissioning trust		91,050			79,464
Lease deposits		171,585			163,156
Other		24,321			12,193
Total Investments		286,956			254,813
Current Assets:
Cash and cash equivalents		52,018			98,633
Deposits		—			24,686
Accounts receivable		4,071			25,242
Accounts receivable - deposits		23,600			—
Accounts receivable - members		94,136			80,569
Fuel, materials and supplies		30,585			25,669
Deferred energy		14,914			21,328
Prepayments		4,035			3,304
Total Current Assets		223,359			279,431
Deferred Charges:
Regulatory assets		49,738			43,753
Other		20,267			60,143
Total Deferred Charges		70,005			103,896
Total Assets	$	1,627,409		$	1,712,366
CAPITALIZATION AND LIABILITIES:
Capitalization:
Patronage capital	$	293,077		$	271,833
Non-controlling interest		10,993			25,062
Long-term debt		813,264			832,980
Total Capitalization		1,117,334			1,129,875
Current Liabilities:
Long-term debt due within one year		22,917			22,917
Accounts payable		87,844			89,854
Accounts payable - members		48,220			64,110
Accounts payable - deposits		—			24,686
Accrued expenses		35,767			33,740
Total Current Liabilities		194,748			235,307
Deferred Credits and Other Liabilities:
Asset retirement obligations		55,812			48,810
Obligations under long-term leases		174,205			166,043
Regulatory liabilities		51,497			95,271
Other		33,813			37,060
Total Deferred Credits and Other Liabilities		315,327			347,184
Commitments and Contingencies		—			—
Total Capitalization and Liabilities	$	1,627,409		$	1,712,366

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

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OLD DOMINION ELECTRIC COOPERATIVE

CONSOLIDATED STATEMENTS OF REVENUES, EXPENSES AND PATRONAGE CAPITAL

FOR THE YEARS ENDED DECEMBER 31, 2006, 2005 AND 2004

	2006			2005			2004
	(in thousands)
Operating Revenues	$	817,515		$	737,679		$	588,451
Operating Expenses:
Fuel		154,931			143,332			90,635
Purchased power		464,047			434,557			314,763
Deferred energy		6,414			(26,135	)		(8,775	)
Operations and maintenance		35,551			34,221			40,595
Administrative and general		32,502			34,523			28,800
Depreciation, amortization and decommissioning		38,393			38,556			32,759
Amortization of regulatory asset/(liability), net		2,701			1,909			20,543
Accretion of asset retirement obligations		2,783			2,496			2,251
Taxes other than income taxes		6,732			6,024			5,265
Total Operating Expenses		744,054			669,483			526,836
Operating Margin		73,461			68,196			61,615
Other (Expense)/Income, net		(45	)		(157	)		129
Investment Income		10,591			6,620			2,896
Interest Charges, net		(60,949	)		(60,347	)		(52,506	)
Net Margin before income taxes and non-controlling interest		23,058			14,312			12,134
Income taxes		(726	)		(881	)		—
Non-controlling interest		(1,088	)		(1,322	)		—
Net Margin		21,244			12,109			12,134
Patronage Capital - Beginning of Year		271,833			259,724			247,590
Patronage Capital - End of Year	$	293,077		$	271,833		$	259,724

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

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OLD DOMINION ELECTRIC COOPERATIVE

CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME

FOR THE YEARS ENDED DECEMBER 31, 2006, 2005 AND 2004

	2006			2005			2004
	(in thousands)
Net Margin	$	21,244		$	12,109		$	12,134
Other Comprehensive Income:
Unrealized (loss)/gain on derivative contracts(1)		(15,157	)		15,592			—
Other comprehensive income before non-controlling interest		6,087			27,701			12,134
Less: Non-controlling interest in comprehensive income		15,157			(15,592	)		—
							��
Comprehensive Income	$	21,244		$	12,109		$	12,134

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

⁽¹⁾ The tax effect relates to the consolidation of TEC Trading, Inc.’s, a taxable entity, results of operations beginning in 2005.

Unrealized (loss)/gain on derivative contracts net of tax benefit of $9.7 million for 2006 and net of tax expense of $10.0 million for 2005. There was no tax effect in 2004.

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OLD DOMINION ELECTRIC COOPERATIVE

CONSOLIDATED STATEMENTS OF CASH FLOW

FOR THE YEARS ENDED DECEMBER 31, 2006, 2005 AND 2004

	2006			2005			2004
	(in thousands)
Operating Activities:
Net Margin	$	21,244		$	12,109		$	12,134
Adjustments to reconcile net margins to net cash provided by operating activities:
Depreciation, amortization and decommissioning		38,393			38,556			32,759
Other noncash charges		16,192			11,555			10,779
Non-controlling interest		1,088			1,322			—
Amortization of lease obligations		10,976			10,368			9,964
Interest on lease deposits		(10,647	)		(9,953	)		(9,542	)
Change in current assets		3,043			(55,611	)		(18,111	)
Change in deferred energy		6,414			(26,135	)		(8,775	)
Change in current liabilities		(30,869	)		89,442			(39,952	)
Change in regulatory assets and liabilities		(55,833	)		63,558			15,134
Change in deferred charges and credits		14,546			(12,652	)		(3,446	)
Net Cash Provided by Operating Activities		14,547			122,559			944
Financing Activities:
Payment of long-term debt		(22,917	)		(22,917	)		—
Obligations under long-term leases		(596	)		(521	)		(529	)
Net Cash (Used for) Financing Activities		(23,513	)		(23,438	)		(529	)
Investing Activities:
Purchases of available for sale securities		(112,650	)		(101,085	)		(10,500	)
Proceeds from sale of available for sale securities		100,325			107,540			53,000
Increase in other investments		(5,316	)		(4,403	)		(3,234	)
Consolidation of TEC Trading, Inc.		—			—			2,488
Electric plant additions		(20,008	)		(20,104	)		(56,363	)
Net Cash (Used for) Investing Activities		(37,649	)		(18,052	)		(14,609	)
Net Change in Cash and Cash Equivalents		(46,615	)		81,069			(14,194	)
Cash and Cash Equivalents-Beginning of Year		98,633			17,564			31,758
Cash and Cash Equivalents-End of Year	$	52,018		$	98,633		$	17,564

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

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OLD DOMINION ELECTRIC COOPERATIVE

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

NOTE 1—Summary of Significant Accounting Policies

General

The accompanying financial statements reflect the consolidated accounts of Old Dominion Electric Cooperative (“ODEC” or “we” or “our”), its subsidiaries and TEC Trading, Inc. (“TEC”). In accordance with Financial Accounting Standards Board (“FASB”) Interpretation No. 46R, “Consolidation of Variable Interest Entities, an Interpretation of Accounting Research Bulletin No. 51” (the “Interpretation”), TEC, is considered a variable interest entity for which we are the primary beneficiary and has been consolidated as of December 31, 2004. We have eliminated all intercompany balances and transactions in consolidation. Our non-controlling, 50% or less, ownership interest in other entities is recorded using the equity method of accounting.

We are a not-for-profit wholesale power supply cooperative, incorporated under the laws of the Commonwealth of Virginia in 1948. We have two classes of members. Our Class A members are twelve customer-owned electric distribution cooperatives engaged in the retail sale of power to member consumers located in Virginia, Delaware, Maryland, and parts of West Virginia. Our sole Class B member is TEC, a taxable corporation owned by our member distribution cooperatives. Our board of directors is composed of two representatives from each of the member distribution cooperatives and one representative from TEC. Our rates are not regulated by the respective states’ public service commissions, but are set periodically by a formula that was accepted for filing by the Federal Energy Regulatory Commission (“FERC”) on December 23, 2003. An amendment to the formula was accepted for filing by FERC on February 19, 2005, subject to the outcome of other pending ODEC FERC proceedings.

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

In accordance with Financial Accounting Standards Board Interpretation No. 46R, “Consolidation of Variable Interest Entities, an Interpretation of Accounting Research Bulletin No. 51” (the “Interpretation”), TEC was considered a variable interest entity for which ODEC was the primary beneficiary and has been consolidated as of December 31, 2004. Because TEC was not consolidated until December 31, 2004, TEC’s revenues and expenses for 2004 are not included in ODEC’s consolidated statements of revenues, expenses and patronage capital and consolidated statements of cash flow for 2004. Beginning in 2005, the income statement of TEC is consolidated and the inter-company revenues and expenses are eliminated in consolidation. The balance sheet of TEC has been consolidated into the financial statements of ODEC and all inter-company balances have been eliminated in the consolidation. Because TEC is 100% owned by ODEC’s twelve member distribution cooperatives, its equity is presented as a non-controlling interest in ODEC’s consolidated financial statements.

TEC was initially capitalized by ODEC in 2001 with a $7.5 million cash investment in exchange for all of its capital stock. ODEC then distributed all of TEC’s stock as a patronage capital distribution to its member distribution cooperatives. TEC was formed for the primary purpose of purchasing from us, to sell in the market, energy that is not needed to meet the actual needs of ODEC’s member distribution cooperatives, acquiring natural gas and forward purchase contracts to hedge the price of natural gas to supply our combustion turbine facilities, and to take advantage of other power-related trading opportunities in the market which will help lower our member distribution cooperatives’ costs. TEC does not engage in speculative trading. ODEC first became the primary beneficiary upon the formation of TEC in 2001. As both ODEC and TEC were under common control at the date TEC was formed and the date ODEC became the primary beneficiary, the initial measurement of TEC’s assets and liabilities was at their carrying amounts.

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

Electric Plant

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

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

Depreciation

Beginning January 1, 2005, we conducted a depreciation study and updated our depreciation rates. Depreciation rates are as follows:

	Depreciation Rates
Generating Facility	2006		2005		2004
	(in percents)
Clover	1.8	%	1.8	%	2.1	%
North Anna	2.9		3.2		2.1
Louisa	3.5		3.6		3.4
Marsh Run	3.5		3.6		3.6
Rock Springs	3.8		3.8		3.6

Nuclear Fuel

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

In accordance with the Nuclear Waste Policy Act of 1982, the Department of Energy (“DOE”) is required to provide for the permanent disposal of spent nuclear fuel produced by nuclear facilities, such as the North Anna Nuclear Power Station (“North Anna”) in which we have an 11.6% ownership interest, in accordance with contracts executed with the Department of Energy (“DOE”). However, since the DOE did not begin accepting spent fuel in 1998 as specified in its contracts, Virginia Electric & Power Company (“Virginia Power”) is providing on-site spent nuclear fuel storage at the North Anna facility. These facilities are expected to be adequate until the DOE begins accepting the spent nuclear fuel. Virginia Power will continue to safely manage its spent nuclear fuel until the DOE begins accepting the spent nuclear fuel. In January 2004, Virginia Power filed a lawsuit seeking recovery damages for breech of the standard contract due to the DOE’s delay in accepting spent nuclear fuel for North Anna.

Fuel, Materials and Supplies

Fuel, materials and supplies is primarily comprised of spare parts for our generating assets, which are recorded at lower of cost or market, and fuel, which consists primarily of coal and #2 fuel oil, which is recorded at average cost.

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Allowance for Borrowed Funds Used During Construction

Allowance for borrowed funds used during construction is defined as the net cost of borrowed funds used for construction purposes during the construction period and a reasonable rate on other funds when so used. We capitalize interest on borrowings for significant construction projects. Interest capitalized in 2006, 2005, and 2004, was $0.3 million, $0.2 million, and $8.2 million, respectively.

Income Taxes

As a not-for-profit electric cooperative, we are currently exempt from federal income taxation under Section 501(c)(12) of the Internal Revenue Code of 1986, as amended, and we intend to continue to operate in this manner. Based on our assessment and evaluations of relevant authority, we believe we could sustain treatment as a tax-exempt utility in the event of a challenge of our tax status. Accordingly, no provisions for income taxes has been recorded based on ODEC’s operations in the accompanying consolidated financial statements.

TEC, a taxable corporation, has been consolidated in the accompanying financial statements as of December 31, 2004, and its provision for income taxes was approximately $0.1 million and $0.9 million as of December 31, 2006 and December 31, 2005, respectively.

Operating Revenues

Our operating revenues are derived from sales to our members and non-members. We sell energy to our Class A members pursuant to long-term wholesale power contracts that we maintain with each of our member distribution cooperatives. These wholesale power contracts obligate each member distribution cooperative to pay us for power furnished in accordance with our rates. Power furnished is determined based on month-end meter readings. At December 31, 2006, 2005, and 2004, sales to our member distribution cooperatives were $746.5 million, $657.0 million, and $564.6 million, respectively. See Note 5—Wholesale Power Contracts—to the Consolidated Financial Statements.

We sell excess purchased energy and excess generated energy from our combustion turbine facilities, if any, to our Class B member under FERC market-based rate authority. Beginning January 1, 2005, the income statement of TEC is consolidated and the inter-company revenues and expenses are eliminated in consolidation. Therefore, we reported no sales to TEC beginning in 2005. TEC’s sales to third parties are reflected as non-member revenues. Sales to TEC consisted primarily of sales of excess energy that we did not need to meet the actual needs of our member distribution cooperatives. We sold the portion of this energy that could not be utilized by our member distribution cooperatives to TEC for resale into the market, or to non-members. In 2004, sales to TEC were $18.9 million. Excess purchased energy that is not sold to TEC is sold to the PJM Interconnection, LLC (“PJM”) under its rates for providing energy imbalance service. Prior to May 1, 2005, excess energy from Clover was sold to Virginia Power. For the years ended December 31, 2006, 2005, and 2004, energy sales to non-members were $71.0 million, $80.7 million, and $4.9 million, respectively.

Regulatory Assets and Liabilities

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

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Debt Issuance Costs

Capitalized costs associated with the issuance of debt totaled $10.4 million and $11.3 million, at December 31, 2006 and 2005, respectively and are included in deferred charges – other. These costs are being amortized using the effective interest method over the life of the respective debt issues, and are included in interest charges, net.

Deferred Credits and Other Liabilities—Other

Deferred credits and other liabilities—other, includes gains on long-term lease transactions (see Note 6— Long-Term Lease Transactions—to the Consolidated Financial Statements), DOE decontamination and decommissioning liability, and liabilities associated with benefit plans for certain executives. Gains on long-term lease transactions totaled $33.7 million and $36.5 million at December 31, 2006 and 2005, respectively. These gains are being amortized into income ratably over the terms of the operating leases as a reduction to depreciation, amortization and decommissioning expense.

Deferred Energy

We use the deferral method of accounting to recognize differences between our energy expenses and our energy revenues collected from our member distribution cooperatives. Our deferred energy balance represents the net accumulation of any previous under- or over-collection of energy costs. At December 31, 2006 and 2005, we had an under-collected deferred energy balance of $14.9 million and $21.3 million, respectively. Under-collected deferred energy balances are collected from our members in subsequent periods.

Financial Instruments (including Derivatives)

Financial instruments included in the decommissioning fund are classified as available for sale, and accordingly, are carried at fair value. Unrealized gains and losses on investments held in the decommissioning fund are deferred as a regulatory liability or a regulatory asset until realized.

Our investments in marketable securities, which are actively managed, are classified as available for sale and are recorded at fair value. Unrealized gains or losses on these investments, if material, are reflected as a component of other comprehensive income. Investments in debt securities that we have the positive intent and ability to hold to maturity are classified as held to maturity and are recorded at amortized cost. See Note 7—Investments—to the Consolidated Financial Statements. Other investments are recorded at cost, which approximates market value.

We purchase power under both long-term and short-term physically-delivered forward contracts to supply power to our member distribution cooperatives under “all requirements” wholesale power contracts. These forward purchase contracts meet the accounting definition of a derivative; however, a majority of the forward purchase derivative contracts qualify for the normal purchases/normal sales exception under SFAS No. 133 “Accounting for Derivative Instruments and Hedging Activities.” As a result, these contracts are not recorded at fair value. We record a liability and purchased power expense when the power under the forward contract is delivered.

We also purchase natural gas futures generally for three years or less to hedge the price of natural gas for the operation of our combustion turbine facilities and for use as a basis in determining the price of power in certain forward power purchase agreements. These derivatives do not qualify for the normal purchases/normal sales exception. For all derivative contracts that do not qualify for the normal purchases/normal sales accounting exception, we may elect cash flow hedge accounting in accordance with SFAS No. 133. Accordingly, gains and losses on derivative contracts are deferred into Other Comprehensive Income until the hedged underlying transaction occurs or is no longer likely to occur. For derivative contracts where hedge accounting is not utilized, or

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for which ineffectiveness exists, we defer all remaining gains and losses on a net basis as a regulatory asset or liability in accordance with SFAS No. 71 “Accounting for Certain Types of Regulation.” These amounts are subsequently reclassified as purchased power or fuel expense in our Consolidated Statements of Revenues, Expenses, and Patronage Capital as the power or fuel is delivered and/or the contract settles.

Generally, derivatives are reported on the Consolidated Balance Sheet at fair value. The measurement of fair value is based on actively quoted market prices, if available. Otherwise, we seek indicative price information from external sources, including broker quotes and industry publications. For individual contracts, the use of differing assumptions could have a material effect on the contract’s estimated fair value. During 2006, 2005, and 2004, we expensed option premiums totaling $3.0 million, $0.8 million, and $1.4 million, respectively, as purchased power expense.

Hedge ineffectiveness during the years ended December 31, 2006 and 2005, was $0.1 million and $0.2, respectively. There was no hedge ineffectiveness during the year ended December 31, 2004.

Risk Management Policy

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

We are exposed to market risks associated with commodity prices for energy and fuel related to our business operations. Through our relationship with ACES Power Marketing LLC (“APM”), we have formulated policies and procedures to manage the risks associated with these price fluctuations. We manage our exposure to these fluctuations in energy and fuel market prices by entering into forward purchase contracts to hedge the variability of cash flows associated with changes in market prices of energy. We have operating procedures in place to help ensure that proper internal controls are maintained regarding the use of derivatives.

We are also exposed to credit risk in our business operations. We have adopted a Credit Risk Policy that establishes the basis for determining counterparty credit standards and processes to determine credit limits. Our risk management committee monitors credit exposure on a regular basis. Formal counterparty credit reviews are performed at least annually and informal reviews are performed on an ongoing basis. At December 31, 2006, none of our counterparties were required to post collateral for power and fuel purchases and sales. At December 31, 2005, our counterparties for power and fuel purchases and sales had posted $24.7 million in collateral.

Patronage Capital

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

Concentrations of Credit Risk

Financial instruments that potentially subject us to concentrations of credit risk consist of cash equivalents, investments, and receivables arising from sales to our members and non-members. We place our temporary cash investments with high credit quality financial institutions and invest in debt securities with high credit standards as required by our board of directors. Cash and cash equivalents balances may exceed FDIC insurance limits on occasion. Concentrations of credit risk with respect to receivables arising from sales to our member distribution cooperatives are limited due to the large member consumer base that represents our member distribution cooperatives’ accounts receivable. Receivables from our member distribution cooperatives at December 31, 2006 and 2005, were $94.1 million and $80.6 million, respectively.

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Cash Equivalents

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

New Accounting Pronouncements

In July 2006, the Financial Accounting Standards Board (“FASB”) issued FASB Interpretation No. 48, “Accounting for Uncertainty in Income Taxes – an Interpretation of FASB Statement No. 109” (“FIN 48”). This interpretation requires that income tax positions recognized in an entity’s tax returns have a more-likely-than-not chance of being sustained prior to recording the related tax benefit in the financial statements. Tax benefits would be derecognized if information became available which indicated that it was more-likely-than-not that the position would not be sustained. We will adopt this interpretation in the first quarter of fiscal 2007. We have substantially completed our analysis of FIN 48 and we do not expect it to have a material impact on our financial statements.

In September 2006, the FASB issued Statement No. 157, “Fair Value Measurements” (“SFAS No. 157”). SFAS No. 157 clarifies that the term fair value is intended to mean a market-based measure, not an entity-specific measure and gives the highest priority to quoted prices in active markets in determining fair value. SFAS No. 157 requires disclosures about the extent to which companies measure assets and liabilities at fair value, the methods and assumptions used to measure fair value, and the effect of fair value measures on earnings. SFAS No. 157 is effective for fiscal years beginning after November 15, 2007. We are currently evaluating the impact that SFAS No. 157 may have on our financial statements.

Reclassifications

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

NOTE 2—Electric Plant

Our net electric plant is comprised of the following for 2006:

	Clover			North Anna			Combustion Turbines			Other			Total
	(in thousands, except percentages)
Ownership interest		50	%		11.6	%		100	%		100	%
Electric plant in service	$	654,128		$	281,023		$	574,885		$	17,636		$	1,527,672
Accumulated depreciation		(300,008	)		(140,533	)		(61,866	)		(6,899	)		(509,306	)
Nuclear fuel		—			49,258			—			—			49,258
Accumulated amortization of nuclear fuel		—			(40,877	)		—			—			(40,877	)
Construction work in progress		3,811			16,346			50			135			20,342
	$	357,931		$	165,217		$	513,069		$	10,872		$	1,047,089

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Our net electric plant was comprised of the following for 2005:

	Clover			North Anna			Combustion Turbines			Other			Total
				(in thousands, except percentages)
Ownership interest		50	%		11.6	%		100	%		100	%
Electric plant in service	$	655,265		$	272,225		$	575,386		$	16,702		$	1,519,578
Accumulated depreciation		(289,944	)		(132,698	)		(42,057	)		(6,036	)		(470,735	)
Nuclear fuel		—			48,218			—			—			48,218
Accumulated amortization of nuclear fuel		—			(39,200	)		—			—			(39,200	)
Construction work in progress		415			15,895			—			55			16,365
	$	365,736		$	164,440		$	533,329		$	10,721		$	1,074,226

Investment in Jointly Owned Generating Facilities

We hold a 50% undivided ownership interest in the Clover Power Station (“Clover”), a two-unit, 860 MW (net capacity entitlement) coal-fired electric generating facility operated by Virginia Power. We are responsible for 50% of all post-construction additions and operating costs associated with Clover, as well as a pro-rata portion of Virginia Power’s administrative and general expenses for Clover, and must fund these items. Our portion of assets, liabilities, and operating expenses associated with Clover are included in our consolidated financial statements. At December 31, 2006 and 2005, we had an outstanding accounts payable balance of $1.4 million and $5.1 million, respectively, due to Virginia Power for operation, maintenance, and capital investment at Clover.

We have an 11.6% undivided ownership interest in North Anna, a two-unit, 1,842 MW (net capacity entitlement) nuclear power facility, as well as nuclear fuel and common facilities at the power station, and a portion of spare parts inventory, and other support facilities. North Anna is operated by Virginia Power, which owns the balance of the plant. We are responsible for 11.6% of all post acquisition date additions and operating costs associated with the plant, as well as a pro-rata portion of Virginia Power’s administrative and general expenses for North Anna, and must fund these items. Our portion of assets, liabilities, and operating expenses associated with North Anna are included in our consolidated financial statements. At December 31, 2006, we did not have an outstanding accounts payable balance due to Virginia Power for the operation, maintenance, and capital investment at the North Anna facility and at December 31, 2005, we had an outstanding accounts payable balance of $4.2 million related to North Anna.

Projected capital expenditures for Clover for 2007 through 2009 are $1.9 million, $6.3 million and $2.9 million, respectively. Projected capital expenditures for North Anna for 2007 through 2009 are $15.4 million, $15.5 million and $15.0 million, respectively.

Property, Plant & Equipment

We own three combustion turbine facilities that are carried at cost, less accumulated depreciation. We also own distributed generation facilities, which are included in “Other” in the net electric plant table. Projected capital expenditures for our combustion turbine facilities for 2007 through 2009 are $0.5 million, $0.5 million, and $0.5 million, respectively. Projected capital expenditures for our distributed generation facilities and other for 2007 through 2009 are $3.2 million, $0.6 million and $0.6 million, respectively.

NOTE 3— Accounting for Asset Retirement Obligations

We adopted SFAS No. 143 “Accounting for Asset Retirement Obligations” effective January 1, 2003. SFAS No. 143 requires legal obligations associated with the retirement of long-lived assets to be recognized at fair value when incurred and capitalized as part of the related long-lived asset. Over time, the liability is accreted to its present value each period, and the capitalized asset is depreciated over the useful life of the long-lived asset. SFAS No. 143 requires that any transition adjustment determined at adoption be recognized as a cumulative effect of change in accounting principle.

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

Approximately every four years, a new decommissioning study for North Anna is performed. In 2006, we received the new study and adopted it effective January 1, 2006, which resulted in an additional layer related to the asset retirement obligation associated with North Anna. The additional layer resulted in an increase to our asset retirement cost and our asset retirement obligation of $4.2 million.

The following represents changes in our asset retirement obligations for the years ended December 31, 2006 and 2005 (in thousands):

Asset retirement obligations at December 31, 2004	$	46,295
Additional asset retirement obligations - FIN 47		19
Accretion expense		2,496
Asset retirement obligations at December 31, 2005	$	48,810
Accretion expense		2,783
Additional asset retirement obligations - new layer		4,219
Asset retirement obligations at December 31, 2006	$	55,812

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

NOTE 4—Power Purchase Agreements

In 2006, 2005, and 2004, our owned generating facilities together furnished approximately 45.2%, 43.3%, and 47.4%, respectively, of our energy requirements. The remaining needs were satisfied through long-term and short-term physically-delivered forward purchase power contracts with other power suppliers and purchases of energy in the spot markets.

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

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

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The remainder of our energy requirements are provided by the market. We purchase significant amounts of power in the market through long-term and short-term physically-delivered forward power purchase contracts. We also purchase power in the spot market. This approach to meeting our member distribution cooperatives’ energy requirements is not without risks. To mitigate these risks, we attempt to match our energy purchases with our energy needs to reduce our spot market purchases of energy. Additionally, we have developed policies and procedures to manage the risks in the changing business environment. These procedures, developed in cooperation with APM, are designed to strike the appropriate balance between minimizing costs and reducing energy cost volatility. As of December 31, 2005, our counterparties were required to post $24.7 million in deposits in accordance with the terms of our respective master power purchase and sales agreements with them. At December 31, 2006, due to changes in energy prices, we were required to post $23.6 million with our counterparties.

Our purchased power costs for 2006, 2005, and 2004 were $464.0 million, $434.6 million, and $314.8 million, respectively.

Our power purchase agreements contain certain firm capacity and minimum energy requirements. As of December 31, 2006, our minimum purchase commitments under the various agreements, without regard to capacity reductions or cost adjustments, were as follows:

Year Ending December 31,	Firm Capacity Requirements		Minimum Energy Requirements		Total
	(in millions)
2007	$	0.9	$	343.9	$	344.8
2008		—		191.8		191.8
2009		—		113.2		113.2
	$	0.9	$	648.9	$	649.8

Congestion

Primarily due to transmission import limitations into the Delmarva Peninsula, our net congestion costs for 2006, 2005, and 2004, were approximately $13.4 million, $14.1 million, and $7.0 million, respectively. These costs were incurred under our transmission agreements with PJM when higher cost generation was run due to transmission constraints.

NOTE 5—Wholesale Power Contracts

We have a wholesale power contract with each of our member distribution cooperatives whereby each member distribution cooperative is obligated to purchase substantially all of its power requirements from us through the year 2028 and beyond 2028 unless either party gives the other at least three years notice of termination. Each such contract provides that we shall provide all of the power that the member distribution cooperative requires for the operation of its system, with limited exceptions, to the extent that we have the power and facilities available. Each member distribution cooperative is required to pay us monthly for power furnished under its wholesale power contract in accordance with rates and charges established by us pursuant to our formulary rate, which has been accepted by the Federal Energy Regulatory Commission (“FERC”.) Under the accepted formulary rate, our rates are developed using a rate methodology under which all categories of costs are specifically separated as components of the formula to determine our revenue requirements. The formula is intended to permit collection of revenues, which, together with revenues from all other sources, are equal to all costs and expenses, plus an additional 20% of total interest charges, plus additional equity contributions as approved by our board of directors. It also provides for the periodic adjustment of our rates to recover actual, prudently incurred costs, whether they increase or decrease, without further application to or acceptance by FERC with limited minor exceptions. In accordance with the formula, the board of directors can authorize accelerating the recovery of costs in the establishment of rates.

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The formulary rate allows us to recover and refund amounts under our Margin Stabilization Plan. We have a Margin Stabilization Plan that allows us to review our actual capacity-related cost of service and capacity revenues as of year end and adjust revenues from our member distribution cooperatives to meet our financial coverage requirements and accumulate additional equity as approved by our board of directors. We record all adjustments, whether increases or decreases, in the year affected and allocate any adjustments to our member distribution cooperatives based on power sales during that year. We collect these increases from our member distribution cooperatives, or offset decreases against amounts owed by our member distribution cooperatives to us, in the succeeding calendar year. Each quarter we adjust revenues and accounts payable—members or accounts receivable, as appropriate, to reflect that adjustment. In 2006 and 2005, under our Margin Stabilization Plan, we reduced operating revenues by $2.8 million and $13.3 million, respectively, and increased accounts payable—members by the same amounts. There was no adjustment to operating revenues under our Margin Stabilization Plan in 2004. On November 14, 2006, our board approved an additional equity contribution of $9.0 million in accordance with our wholesale power contracts and our formulary rate.

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

	Year Ended December 31,
	2006		2005		2004
	(in millions)
Northern Virginia Electric Cooperative	$	214.5	$	186.5	$	159.7
Rappahannock Electric Cooperative		163.7		142.0		120.8
Delaware Electric Cooperative		80.0		72.2		61.0

NOTE 6—Long-term Lease Transactions

On March 1, 1996, we entered into a long-term lease transaction with an owner trust for the benefit of an institutional equity investor. Under the terms of the transaction, we entered into a 48.8 year lease of our interest in Clover Unit 1 (valued at $315.0 million) to such owner trust, and simultaneously entered into a 21.8 year lease of the interest back from such owner trust. As a result of the transaction, we recorded a deferred gain of $23.7 million, which is being amortized into income ratably over the 21.8 year operating lease term, as a reduction to operating expenses.

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 Standard & Poor’s Ratings Services (“S&P”) and “Aaa” by Moody’s Investors Service (“Moody’s”). 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.

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

At December 31, 2006, and December 31, 2005, the unamortized portion of the deferred gains was $33.7 million and $36.5 million, respectively.

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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. At the end of the term of the leaseback, we have two options: (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.

Immediately after the leases to the owner trusts, we leased the units back for terms of 21.8 years and 23.4 years, respectively, and agreed to make periodic rental payments to the owner trusts. We used a portion of the one-time rental payments we received in each transaction to enter into payment undertaking agreements and to purchase investments, which provide for substantially all of our periodic basic rent payments under the leasebacks; and the fixed purchase price of the interests in the units at the end of the terms of the leasebacks if we exercise our option to purchase the interests of the owner trusts in the units at that time. At December 31, 2006 and December 31, 2005, the amount of debt considered to be extinguished by in substance defeasance was $539.5 million and $519.9 million, respectively.

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NOTE 7—Investments

Investments were as follows at December 31, 2006 and 2005:

Description	Cost		Gross Unrealized Gains		Gross Unrealized Losses			Fair Value
	(in thousands)
December 31, 2006
Available for Sale
Corporate obligations	$	20,000	$	—	$	—		$	20,000
Registered investment companies(1)		33,514		—		(140	)		33,374
Common stock		41,703		15,677		—			57,380
Short-term investments		61,034		—		—			61,034
	$	156,251	$	15,677	$	(140	)	$	171,788
Held to Maturity
U.S. Government obligations	$	64,584	$	21,430	$	—		$	86,014
Corporate obligations		48,956		—		—			48,956
	$	113,540	$	21,430	$	—		$	134,970
Other	$	1,628	$	—	$	—		$	1,628
December 31, 2005
Available for Sale
Corporate obligations	$	7,675	$	—	$	—		$	7,675
Registered investment companies(1)		32,004		—		(532	)		31,472
Common stock		37,628		9,996		—			47,624
Short-term investments		60,143		—		—			60,143
	$	137,450	$	9,996	$	(532	)	$	146,914
Held to Maturity
U.S. Government obligations	$	60,447	$	24,957	$	—		$	85,404
Corporate obligations		45,728		—		—			45,728
	$	106,175	$	24,957	$	—		$	131,132
Other	$	1,724	$	—	$	—		$	1,724

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

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Contractual maturities of debt securities at December 31, 2006, were as follows:

Description	Less Than One Year		One Through Five Years		More Than Five Years		Total
	(in thousands)
Available for Sale	$	20,000	$	—	$	—	$	20,000
Held to Maturity		279		1,412		111,849		113,540
	$	20,279	$	1,412	$	111,849	$	133,540

As discussed in Note 3, realized and unrealized gains and losses related to assets held in the decommissioning trust are deferred as a regulatory liability. Realized and unrealized gains and losses for all other available-for-sale securities were not significant for any period presented.

NOTE 8—Regulatory Assets and Liabilities

In accordance with SFAS No. 71, we record regulatory assets and liabilities that result from our ratemaking. Our regulatory assets and liabilities at December 31, 2006 and 2005, were as follows:

	2006		2005
	(in thousands)
Regulatory Assets:
Unamortized losses on reacquired debt	$	34,289	$	36,887
Deferred transportation costs		—		5,919
Deferred asset retirement costs		480		496
DOE decontamination and decommissioning		—		451
Deferred net unrealized losses on derivative instruments		14,969		—
Total Regulatory Assets	$	49,738	$	43,753
Regulatory Liabilities:
Deferred net unrealized gains on derivative instruments	$	—	$	52,466
North Anna SFAS No. 143 deferral		34,918		32,234
North Anna decommissioning fund market value adjustment		15,537		9,464
Unamortized gains on reacquired debt		1,042		1,107
Total Regulatory Liabilities	$	51,497	$	95,271
Regulatory Assets included in Current Assets:
Deferred energy	$	14,914	$	21,328

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

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Regulatory assets included in deferred charges are detailed as follows:

• Unamortized losses on reacquired debt are the costs we incurred to purchase our outstanding indebtedness prior to its scheduled retirement. These losses are amortized over the life of the original indebtedness and will be fully amortized in 2023.

• Deferred transportation costs. We began amortizing these costs April 1, 2005, and they were recovered through rates over 21 months and were fully amortized as of December 31, 2006.

• Deferred asset retirement costs for the cumulative effect of change in accounting principle for the Clover and distributed generation facilities as a result of the adoption of SFAS No. 143.

• DOE decontamination and decommissioning represents our share of the costs for decontamination and decommissioning levied under the Atomic Energy Act of 1954, as amended by Title XI of the Energy Policy Act of 1992. These costs were fully amortized as of December 31, 2006.

• Deferred net unrealized losses on derivative instruments. These losses will be matched and recognized in the same period the expense is incurred for the hedged item.

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

• Deferred net unrealized gains on derivative instruments. These gains will be matched and recognized in the same period the expense is incurred for the hedged item.

• North Anna SFAS No. 143 deferral is the cumulative effect of change in accounting principle as a result of the adoption of SFAS No. 143.

• North Anna decommissioning fund market value adjustment is the market value adjustment on the decommissioning trust fund.

• Unamortized gains on reacquired debt are the gains we recognized when we purchased our outstanding indebtedness prior to its scheduled retirement. These gains are amortized over the life of the original indebtedness and will be fully amortized in 2023.

Regulatory assets included in current assets are detailed as follows:

• Deferred energy—see Note 1—Deferred Energy—to the Consolidated Financial Statements for our method of accounting for deferred energy.

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NOTE 9—Long-term Debt

Long-term debt consists of the following:

	December 31,
	2006			2005
	(in thousands)
$250,000,000 principal amount of 2003 Series A Bonds due 2028 at an interest rate of 5.676%	$	229,167		$	239,583
$27,755,000 principal amount of 2002 Series A Bonds due 2028 at an interest rate of 5.00%		27,755			27,755
$32,455,000 principal amount of 2002 Series A Bonds due 2028 at an interest rate of 5.625%		32,455			32,455
$300,000,000 principal amount of 2002 Series B Bonds due 2028 at an interest rate of 6.21%		275,000			287,500
$215,000,000 principal amount of 2001 Series A Bonds due 2011 at an interest rate of 6.25%		215,000			215,000
$109,182,937 principal amount of First Mortgage Bonds, 1996 Series B, due 2018 at an effective interest rate of 7.06%		108,601			108,601
$120,000,000 principal amount of First Mortgage Bonds, 1993 Series A, due 2023 at an interest rate of 7.78%		1,000			1,000
Virginia Electric and Power Company Promissory Note (North Anna), due 2008 with variable interest rates (averaging 6.35% in 2006, and 4.18% in 2005)		6,750			6,750
		895,728			918,644
Less unamortized discounts and premiums		(59,547	)		(62,747	)
Less current maturities		(22,917	)		(22,917	)
Total Long-term Debt	$	813,264		$	832,980

At December 31, 2006, and December 31, 2005, deferred gains and losses on reacquired debt totaled a net loss of approximately $33.2 million and $35.8 million, respectively. Deferred gains and losses on reacquired debt are deferred under regulatory accounting – see Note 8 – Regulatory Assets and Liabilities in Notes to the Consolidated Financial Statements.

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

Year Ending December 31,	(in thousands)
2007	$	22,917
2008		29,667
2009		22,917
2010		22,917
2011		237,917
2012 and thereafter		559,393
	$	895,728

The aggregate fair value of long-term debt was $862.9 million and $894.3 million at December 31, 2006 and 2005, respectively, based on current market prices. For debt issues that are not quoted on an exchange, interest rates currently available to us for issuance of debt with similar terms and remaining maturities are used to estimate fair value. We believe that the carrying amount of debt issues with variable rates is a reasonable estimate of fair value.

Substantially all of our assets are pledged as collateral under the Indenture. Under the Indenture, we may not make any distribution, including a dividend or payment or retirement of patronage capital, to our members if an event of default exists under the Indenture. Otherwise, we may make a distribution to our members if (1) after the distribution, our patronage capital as of the end of the most recent fiscal quarter would be equal to or greater than 20% of our total long-term debt and patronage capital, or (2) all of our distributions for the year in which the distribution is to be made do not exceed 5% of the patronage capital as of the end of the most recent fiscal year. For this purpose, patronage capital and total long-term debt and patronage capital do not include any earnings retained in any of our subsidiaries or affiliates or the debt of any of our subsidiaries or affiliates.

NOTE 10—Short-term Borrowing Arrangements

We maintain committed lines of credit and revolving credit facilities to cover short- and intermediate- term funding needs. Currently, we have short-term committed variable rate lines of credit in the aggregate amount of $180.0 million, all of which are available for general working capital purposes. Additionally, we have two committed three-year revolving credit facilities, $50.0 million each, that are available for capital expenditures and general corporate purposes. These facilities expire on June 18, 2007, and January 30, 2009. At December 31, 2006 and 2005, we had no borrowings or letters of credit outstanding under any of these arrangements. We expect the working capital lines of credit and revolving credit facilities to be renewed as they expire.

We maintain a policy which allows our member distribution cooperatives to pre-pay or extend payment on their monthly power bills. Under this policy, we pay interest on early payment balances at a blended investment and outside short-term borrowing rate, and we charge interest on extended payment balances at a blended prepayment and outside short-term borrowing rate. Amounts advanced by our member distribution cooperatives are included in accounts payable—members and totaled $44.2 million and $49.8 million at December 31, 2006 and 2005, respectively. Amounts extended by our member distribution cooperatives are included in accounts receivable—members and totaled $23.5 million and $12.0 million at December 31, 2006 and 2005, respectively.

NOTE 11—Employee Benefits

Substantially all of our employees participate in the National Rural Electric Cooperative Association (“NRECA”) Retirement and Security Program, a noncontributory, defined benefit multiple employer master pension plan. We participate in a pension restoration plan, which is intended to provide a supplemental benefit for employees who would have a reduction in their pension benefit from the Retirement and Security Program because of the Internal Revenue Code limitations. The cost of these plans is funded annually by payments to NRECA to ensure that annuities in amounts established by the plan will be available to individual participants upon their retirement. Pension expense was $1.0 million for 2006 and 2005, and was $0.8 million for 2004.

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We have also elected to participate in a defined contribution 401(k) retirement plan administered by Diversified Investment Advisors. Under the plan, employees may elect to have up to 100% or $15,000, whichever is less, of their salary withheld on a pretax basis, subject to Internal Revenue Service limitations, and invested on their behalf. We match up to the first 2% of each participant’s base salary. Our matching contributions were $126,000, $118,000, and $110,000, in 2006, 2005, and 2004, respectively.

NOTE 12—Insurance

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

The Price-Anderson Act provides the public up to $10.8 billion of protection per nuclear incident via obligations required of owners of nuclear power plants. The Price-Anderson Act Amendment of 1988 allows for an inflationary provision adjustment every five years. Virginia Power has purchased $300 million of coverage from commercial insurance pools with the remainder provided through a mandatory industry risk-sharing program. In the event of a nuclear incident at any licensed nuclear reactor in the United States, we, jointly with Virginia Power, could be assessed up to $100.6 million for each licensed reactor not to exceed $15.0 million per year per reactor. There is no limit to the number of incidents for which this retrospective premium can be assessed. The Price-Anderson Act was first enacted in 1957 and was renewed again in 2005.

Virginia Power’s current level of property insurance coverage, $2.55 billion for North Anna, exceeds the Nuclear Regulatory Commission (“NRC”) minimum requirement for nuclear power plant licensees of $1.06 billion for each reactor site and includes coverage for premature decommissioning and functional total loss. The NRC requires that the proceeds from this insurance be used first to return the reactor to and maintain it in a safe and stable condition and second to decontaminate the reactor and station site in accordance with a plan approved by the NRC. The nuclear property insurance is provided to Virginia Power and us, jointly, by Nuclear Electric Insurance Limited (“NEIL”), a mutual insurance company, and is subject to retrospective premium assessments in any policy year in which losses exceed the funds available to the insurance company. The maximum assessment for the current policy period is $50.0 million. Based on the severity of the incident, the board of directors of the nuclear insurer has the discretion to lower or eliminate the maximum retrospective premium assessment. We, jointly with Virginia Power, have the financial responsibility for any losses that exceed the limits or for which insurance proceeds are not available because they must first be used for stabilization and decontamination.

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

Our share of the contingent liability for the coverage assessments described above is a maximum of $31.3 million at December 31, 2006.

NOTE 13—Regional Headquarters, Inc.

We own 50% of Regional Headquarters, Inc. (“RHI”), which holds title to the office building that is being partially leased to us, which we account for under the equity method. We are obligated to make lease payments equal to one half of RHI’s annual operating expenses, net of rental income from third party lessees, through the year 2016. During 2006 and 2005, our rent expense was $0.4 million and during 2004 our rent expense was $0.3 million.

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

Year Ending December 31,	(in thousands)
2007	$	448
2008		448
2009		448
2010		448
2011		448
2012 and thereafter		2,240
	$	4,480

NOTE 14—Supplemental Cash Flows Information

Cash paid for interest in 2006, 2005, and 2004, was $54.3 million, $53.8 million, and $54.0 million, respectively.

NOTE 15—Commitments and Contingencies

Legal

Northern Virginia Electric Cooperative (“NOVEC”)

Over the past several years, we have had discussions and negotiations with NOVEC about changing the nature of its wholesale power contract from an all-requirements contract to a partial-requirements contract. Our board of directors is composed of representatives of our member distribution cooperatives and we must reach consensus among our member distribution cooperatives before any change to any of our wholesale power contracts can be made. Building a consensus for any change is difficult because any change in our rate setting methodology or provisions of service affects our various member distribution cooperatives differently.

On January 5, 2006, NOVEC filed a complaint with FERC pursuant to Section 206 of the Federal Power Act seeking reformation of its wholesale power contract. Specifically, NOVEC sought “to modify its wholesale power contract to allow NOVEC the flexibility to acquire power and energy over and above that available from NOVEC’s share of Old Dominion’s existing resources.” NOVEC claimed that the wholesale power contract’s terms were no longer just and reasonable or in the public interest because the contract was entered into in 1983, and amended and restated in 1992, prior to an allegedly different era of open transmission access and wholesale power markets. NOVEC stated in the complaint that it would not seek to be relieved of its obligations pertaining to its share of our existing power supply resources. Obligations pertaining to our existing resources include debt service, lease rentals, operation and maintenance expenses, interest coverage requirements and other costs and expenses related to our electric generating facilities and existing power purchase arrangements. On March 2, 2006, FERC denied NOVEC’s complaint. On April 3, 2006, NOVEC filed a request for rehearing and on May 1, 2006, FERC issued a tolling order to allow additional time to consider the issues. On August 24, 2006, FERC issued it final order denying NOVEC’s request for rehearing. On October 20, 2006, NOVEC appealed FERC’s denial in the United States Court of Appeals for the District of Columbia. We have intervened in this proceeding. On March 5, 2007, the court issued the procedural schedule and NOVEC’s brief is scheduled to be filed on or before May 7, 2007.

We intend to continue to vigorously contest NOVEC’s claim and we will not amend or modify the wholesale power contract in any way that could adversely affect our financial condition or that of our other member distribution cooperatives.

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Norfolk Southern Railway Company (“Norfolk Southern”)

In April 1989, we entered into a coal transportation agreement with Norfolk Southern for delivery of coal to Clover. The agreement, which was later assigned to Virginia Power as operator of Clover, had an initial 20-year term and provides that the amounts payable for coal transportation services are subject to adjustment based on a reference index. In October 2003, Norfolk Southern claimed that it had been using an incorrect reference index to calculate amounts due to it since the inception of the agreement, and that it would begin to escalate prices for these services in the future based on an alternate reference index. On November 26, 2003, together with Virginia Power, we filed suit against Norfolk Southern in the Circuit Court of Halifax County, Virginia, seeking an order to clarify the price escalation provisions in the coal transportation agreement. In its reply to our suit, Norfolk Southern filed a counter-claim and sought (1) recovery from Virginia Power and us for additional amounts resulting from its use of the alternate reference index since December 1, 2003, and (2) an order requiring the parties to calculate the amounts Norfolk Southern claims it was underpaid since the inception of the agreement by using the alternate reference index.

On December 22, 2004, the court found in favor of Norfolk Southern on the issue of ambiguity and held that the price escalation provisions in the agreement were clear and unambiguous. The court later denied Virginia Power’s and our motion to file an amended complaint based on additional evidence that was not considered by the court in the original proceedings. The court permitted Virginia Power and us to file an amended answer to Norfolk Southern’s counter-claims and our amended answer was filed on March 4, 2005.

On September 1, 2006, the court granted Norfolk Southern’s request to substantially dispose of the issues in the case. On September 23, 2006, we, along with Virginia Power, appealed the court’s order to the Supreme Court of Virginia. On December 13, 2006, Norfolk Southern filed a motion to dismiss for lack of jurisdiction, contending that we and Virginia Power failed to timely appeal. We intend to vigorously prosecute the appeal, if the Supreme Court of Virginia determines we are able to appeal.

We recorded a liability related to the Norfolk Southern dispute and created the related regulatory asset. The regulatory asset was amortized over 21 months (April 1, 2005 through December 31, 2006) and was fully amortized and collected through rates as of December 31, 2006. The current period charges are being collected through rates. If it is ultimately determined that we owe any such amounts to Norfolk Southern, the amounts are not expected to have a material impact on our financial position or results of operations due to our ability to collect such amounts through rates charged to our member distribution cooperatives.

Ragnar Benson, Inc. (“RBI”)

In December 2002, we entered into a contract with RBI for engineering, procurement and construction services relating to the construction of our Marsh Run combustion turbine facility. Construction of the facility began in April 2003 and the facility was required to be substantially complete in the second quarter of 2004. The facility ultimately became available for commercial operation on September 15, 2004, but is still not substantially complete according to the terms of the contract. On December 23, 2004, we terminated the contract with RBI for default and filed suit in the U.S. District Court for the Eastern District of Virginia, Richmond Division, against RBI seeking liquidated damages for delay in completion of the project up to $15.0 million and damages for breach of contract up to $5.0 million. RBI counterclaimed for damages exceeding $15.0 million related to conditions they claim to have encountered during construction. We filed an answer to RBI’s counterclaim denying any liability to RBI. During the discovery phase of the legal proceeding, RBI revised its claim from $15.0 million to $33.0 million.

On September 27, 2005, the U.S. District Court for the Eastern District of Virginia, Richmond Division, ruled on motions for partial summary judgment in our claims against RBI. Specifically, the court granted our motion for partial summary judgment pertaining to claims of entitlement to a change order and fraud allegations, it dismissed six of RBI’s counterclaims, including all counterclaims pertaining to fraud, and it limited our possible recovery of liquidated damages to the liquidated damages cap of approximately $4.7 million. The trial began October 11, 2005 and concluded October 26, 2005. During the trial, RBI revised its claim from $33.0 million to $36.0 million.

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RBI and its parent companies, The Austin Company and Austin Holdings, Inc., filed for bankruptcy under Chapter 11 of the bankruptcy code on October 14, 2005. The automatic litigation stay was lifted for our litigation with RBI.

On June 13, 2005, we executed an agreement with RBI’s surety, Seaboard Surety Company (“Seaboard”), under which it assumed all responsibilities for the final completion of the Marsh Run facility in accordance with the terms of the original agreement with RBI. Because RBI declared bankruptcy during the legal proceeding, we served a lawsuit against Seaboard on February 10, 2006, in order to enforce the eventual outcome of the suit with RBI.

On August 4, 2006, the court ruled in our favor on all remaining issues in the case and awarded us damages of $5.2 million plus expenses. On January 22, 2007, the court entered its final order awarding us an additional $2.5 million for attorneys’ fees and certain other costs and expenses. On February 1, 2007, we filed a motion to amend the final order to address our claim for expert witness fees and interest from the date of the trial, totaling approximately $0.8 million. This motion is still pending before the court. After the court rules on this motion, the judgment is final and the appeals process may begin. RBI will have 30 days to appeal any of the court’s rulings. We intend to enforce the court’s rulings against RBI, to the extent permitted by its bankruptcy proceeding, and against Seaboard.

FERC Proceedings Related to Potential Reorganization

On October 5, 2004, we, together with New Dominion, filed an application at FERC requesting that FERC approve the assignment of our existing wholesale power contracts with our twelve member distribution cooperatives to New Dominion and accept certain changes to our cost-of-service formula to conform it for use by New Dominion for the billing of its sales to the member distribution cooperatives. On December 7, 2004, we filed an application for approval of a new tariff for sales to New Dominion, with charges determined under a cost allocation formula.

On January 14, 2005, NOVEC intervened in the FERC proceedings related to the proposed reorganization. Other interveners in these proceedings included Bear Island Paper Company, LLP and the Virginia State Corporation Commission (“VSCC”).

On March 8, 2005, FERC issued an order that set the proposed assignment of the wholesale power contracts for hearing on the limited issue of whether an Old Dominion credit downgrade could raise rates, and, if so, whether the downgrade is due to the proposed transaction. The hearing was conducted on October 18 through 20, 2005, and concluded on November 2, 2005. The initial decision was issued on February 2, 2006, and the judge ruled in our favor on all material issues. On December 21, 2006, FERC issued an order affirming the initial decision indicating that it had not been shown that the credit downgrade experienced by ODEC could raise rates. On January 22, 2007, NOVEC filed a request for rehearing and on February 21, 2007, FERC issued a tolling order to allow for additional time for consideration of the matters.

Also on March 8, 2005, FERC consolidated the October 5, 2004, and December 7, 2004, rate applications and set hearing and settlement procedures. On June 10, 2005, formal settlement procedures were terminated and a judge was assigned to hear the case. Informal settlement talks continued, and on October 13, 2005, we joined with New Dominion in filing a proposed settlement agreement that resolved all issues in dispute in these proceedings among us, Bear Island Paper Company, LLP, and the VSCC. On December 23, 2005, the judge certified the partial settlement to FERC with a recommendation that it be approved. FERC issued an order approving the partial settlement on April 7, 2006, leaving NOVEC, FERC staff and us as participants in the proceeding. The hearing was conducted on October 17 through 19, 2006, and the initial decision was issued on February 5, 2007, when the judge ruled in our favor on all material matters. NOVEC and FERC staff filed exceptions to the ruling on March 7, 2007 and we have 20 days to respond.

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Environmental

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

Our direct capital expenditures for environmental control facilities at Clover and North Anna, excluding capitalized interest, were immaterial in 2006. Based upon information provided by Virginia Power, we anticipate that beginning in 2011, we will have an increase in our direct capital expenditures for environmental control facilities at Clover. In 2006, we did not have any direct capital expenditures for environmental control facilities at our Louisa, Marsh Run or Rock Springs combustion turbine facilities and there are currently no projected capital expenditures for environmental control facilities in 2007, 2008, or 2009.

The most important environmental law affecting our operations is the Clean Air Act. The Clean Air Act requires, among other things, that owners and operators of fossil fuel-fired power stations limit emissions of sulfur dioxide (“SO₂”) and nitrogen oxides (“NO_x”). In addition, regulations have been issued to limit emissions of mercury, and programs are being proposed to limit emissions of carbon dioxide (“CO₂”) and other greenhouse gases.

With respect to SO₂, under the Clean Air Act’s Acid Rain Program, each of our fossil fuel-fired plants must obtain SO₂ allowances equal to the number of tons of SO₂ they emit into the atmosphere annually. The total number of allowances is capped, and allowances can be traded. As a facility that was built before the Acid Rain Program, Clover receives an annual allocation of SO₂allowances at no cost based upon its baseline operations. Newer facilities, including Louisa, Marsh Run and Rock Springs, need to obtain allowances, but because they are primarily gas-fired, the number of SO₂allowances they must obtain are expected to be minimal and will be supplied from excess SO₂ allowances allocated to Clover. On March 10, 2005, the EPA issued the Clean Air Interstate Rule (“CAIR”), requiring significant reductions of SO₂ and NO_x in the eastern United States, including Virginia and Maryland. During its 2006 session, the Virginia General Assembly adopted legislation setting the framework for the implementation of CAIR in Virginia. The Virginia Department of Environmental Quality (“DEQ”) adopted the final CAIR regulation and it is expected to be published in the Virginia Register in the spring. With respect to SO₂, emissions it is expected that Virginia will participate in the federal SO₂ cap and trade program established by CAIR. That program is similar, but is in addition to the Acid Rain Program and would require all of our facilities in Virginia (including Clover) to acquire additional allowances for each ton of SO₂ they emit beginning in 2009, and additional allowances per ton starting in 2015. We are entitled to sufficient SO₂allowances because of our interest in Clover so that we do not anticipate needing to purchase additional SO₂allowances for the Louisa, Marsh Run and Rock Springs generating facilities through both phases of CAIR.

Pursuant to the Clean Air Act, both Virginia and Maryland have enacted regulations to reduce the emissions of NO_x by establishing NO_x cap and trade programs similar to the federal SO₂allowance programs. Both of these programs are being revised to meet the more stringent NO_x emission caps established under CAIR and with respect to the facilities in Virginia, additional NO_x emission reductions mandated by the Virginia General Assembly. Under the current system, Clover is allocated a certain number of NO_x allowances. If Clover, even with use of conventional and advanced pollution control equipment emits more, then additional NO_x emissions allowances will have to be purchased. We have an agreement with Virginia Power to provide us with the option each year to purchase from it the NO_x emissions allowances necessary to compensate for any shortfall between our NO_x emissions allowance requirement for Clover and our portion of the regulatory NO_xemissions allocation for Clover.

Louisa, Marsh Run and Rock Springs will each emit significant amounts of NO_x. In 2006, NO_x allowances were allocated and we anticipate receiving NO_x allowances through 2008. All three sites will be allocated NO_x emission allowances under CAIR. NO_x emission allowances that are not received from the new source set aside pools will be purchased in the market for the operation of all three combustion turbine facilities. We project that we will be able to obtain sufficient quantities of NO_x allowances in the future at commercially reasonable prices, but increased NO_x emissions or increased restrictions could cause the price of allowances to be higher than we expect.

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In December 2000, the EPA determined that it was appropriate and necessary to regulate mercury emissions from oil and coal-fired power plants as a hazardous air pollutant under the Clean Air Act. In March 2005, the EPA reversed that earlier decision and instead issued the Clean Air Mercury Rule (“CAMR”) which establishes caps for overall mercury emissions that would be implemented in two phases, with the first phase becoming effective in 2010 and the second phase in 2018, and allows the individual states to regulate mercury emissions through a market-based cap and trade program. In response to a request for reconsideration, the EPA confirmed its approach in May 2006. In June 2006, 16 states and several environmental groups filed law suits challenging CAMR and the law suits are currently pending. We cannot predict the outcome of the ongoing challenges of CAMR or what effects any decision may have that would require the EPA to regulate mercury as a hazardous air pollutant. In 2006, the Virginia General Assembly decided to adopt the cap and trade program foreseen in CAMR, subject to certain limitations. If the EPA’s decisions are upheld and CAMR is implemented we do not anticipate that any additional measures will be required at Clover due to Clover’s existing pollution control requirement which already removes greater than 90% of the mercury.

In addition to traditional air pollutants, the question of climate change has been the focus of much public attention. Several bills have been introduced in Congress to limit emissions of CO₂ and other greenhouse gases believed to contribute to climate change. Also, there are numerous actions at the state and regional level, including the Regional Greenhouse Gas Initiative (“RGGI”) established in December 2005 by the governors of seven Northeastern and Mid-Atlantic states. The RGGI provides for a cap and trade system for CO₂ among those states, capping emissions at current levels in 2009, and then reducing emissions 10% by 2019. In 2006, Maryland decided to join the RGGI. Climate change issues are also the subject of several lawsuits, although we were not party to any of those lawsuits. In November 2006, the U.S. Supreme Court heard a case concerning the EPA’s authority to regulate CO₂ emissions under the Clear Air Act. The case concerns CO₂ emissions from the transportation sector, but the Court’s decision will also influence the regulation of other sectors. We cannot exclude the possibility that future CO₂ emission regulations could have a significant effect on our operations, especially at Clover; however, at this stage we are not able to predict the final form of any such regulation.

The Clean Water Act and applicable state laws regulate water intake structures, discharges of cooling water, storm water run-off and other wastewater discharges at our generating facilities. We are in material compliance with these requirements and with permits that must be obtained with respect to such discharges. Our permits are subject to periodic review and renewal proceedings, and can be made more restrictive over time. Limitations on the thermal discharges in cooling water, or withdrawal of cooling water during low flow conditions, can restrict our operations. During 2006, we experienced no such restrictions; however, such restrictions can arise during drought conditions. Clover has two consent orders with the DEQ. One consent order is to study the impact of withdrawing water to support Clover during low river flow conditions and the other is to relocate one of the landfill discharge pipes from Black Walnut Creek to the Roanoke River. The low flow study has been conducted and the results are being finalized. One of the landfill discharge pipes has been relocated to the Roanoke River.

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

We incurred approximately $5.7 million, $9.4 million, and $11.0 million, of expenses, including depreciation, during 2006, 2005, and 2004, respectively, in connection with environmental protection and monitoring activities, such as costs related to the disposal of solid waste, operation of landfills, operation of air emissions reduction equipment, and disposal of hazardous waste material. These expenses were included in fuel expense, operations and maintenance expense, and depreciation, amortization and decommissioning expense. We anticipate expenses to be approximately $5.0 million in 2007 in connection with environmental protection and monitoring activities, including depreciation.

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Tax Increase Prevention and Reconciliation Act of 2005

On May 17, 2006, President Bush signed into law an act entitled the “Tax Increase Prevention and Reconciliation Act of 2005” (the “2005 Tax Act”). Among other provisions, the 2005 Tax Act imposes an excise tax on certain types of leasing transactions entered into by tax-exempt entities. At this time, it is not clear whether the excise tax imposed by the 2005 Tax Act is applicable to our lease transactions. We are continuing to evaluate this legislation and the impact on us; however, specific guidance has not yet been made available. We have revised our estimate of the potential impact and have determined that we do not need to record a liability based upon the currently available information. We have determined that our potential liability for 2006 could range from zero to approximately $1.2 million and that zero represents our best estimate at this time. However, once further guidance is issued, our potential liability under the 2005 Tax Act may change.

Insurance

Under several of the nuclear insurance policies procured by Virginia Power to which we are a party, we are subject to retrospective premium assessments in any policy year in which losses exceed the funds available to the insurance companies. See Note 12—Insurance— to the Consolidated Financial Statements.

Projected Capital Expenditures

Our projected capital expenditures for 2007, 2008 and 2009 are $21.0 million, $22.9 million, and $19.0 million, respectively. Our future projected capital expenditures include a portion of the cost of the nuclear fuel purchased for North Anna and other capital expenditures including generating facility improvements.

NOTE 16—Selected Quarterly Financial Data (Unaudited)

A summary of the quarterly results of operations for the years 2006 and 2005 follow. Amounts reflect all adjustments, consisting of only normal recurring accruals, necessary in the opinion of management for a fair statement of the results for the interim periods. Results for the interim periods may fluctuate as a result of weather conditions, changes in rates and other factors.

	First		Second		Third		Fourth
	Quarter		Quarter		Quarter		Quarter		Total
	(in thousands except ratios)
Statement of Operations Data:
2006:
Operating Revenue	$	203,461	$	185,952	$	221,231	$	206,871	$	817,515
Operating Margin		16,901		16,436		16,624		23,500		73,461
Net Margin		2,990		3,035		3,089		12,130		21,244
2005:
Operating Revenue	$	171,591	$	160,457	$	207,491	$	198,140	$	737,679
Operating Margin		17,238		16,690		17,192		17,076		68,196
Net Margin		2,939		2,946		2,956		3,268		12,109

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

None

ITEM 9A. CONTROLS AND PROCEDURES

As of the end of the period covered by this report, our management, including the President and Chief Executive Officer and Senior Vice President and Chief Financial Officer conducted an evaluation of the effectiveness of our disclosure controls and procedures. Based upon that evaluation, the President and Chief Executive Officer and Senior Vice President and Chief Financial Officer concluded that our disclosure controls and procedures are effective in ensuring that all material information required to be filed in this report has been made known to them in a timely matter. We have established a Disclosure Assessment Committee comprised of members from senior and middle management to assist in this evaluation. There have been no significant changes in our internal controls over financial reporting or in other factors that could significantly affect such controls during the previous fiscal quarter.

ITEM 9B. OTHER INFORMATION

None

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PART III

ITEM 10. DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANT

Directors

We are governed by a board of 25 directors, consisting of two representatives from each of our member distribution cooperatives and one representative from TEC. Each of our twelve member distribution cooperatives nominates two directors at least one of whom must be a director of that member in good standing. One director currently serves as a director on behalf of a member distribution cooperative and TEC. The candidates for director are elected to our board of directors by voting delegates from each of our member distribution cooperatives elected by each member distribution cooperatives’ board of directors. Each elected candidate is authorized to represent that member for a renewable term of one year at our annual meeting. This election process occurs annually. Our board of directors sets policy and provides direction to our President and Chief Executive Officer. Beginning in 2007, the board of directors generally meets every other month.

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

John William Andrew, Jr. (53). President and Chief Executive Officer of Delaware Electric Cooperative since January 2005. Mr. Andrew also served as Vice President, Engineering and Operations from 1998 to 2004. Mr. Andrew has been a Director of ODEC since 2005.

M. Johnson Bowman (61). President and Chief Executive Officer of Mecklenburg Electric Cooperative since 2001. Mr. Bowman also served as Executive Vice President and General Manager of Mecklenburg Electric Cooperative from 1981 to 2001. Mr. Bowman has been a Director of ODEC since 1974.

M Dale Bradshaw (53). Chief Executive Officer of Prince George Electric Cooperative since 1995. Mr. Bradshaw has been a Director of ODEC since 1995.

Vernon N. Brinkley (60). President and Chief Executive Officer of A&N Electric Cooperative since 2003. Mr. Brinkley also served as President of A&N Electric Cooperative from 1995 to 2003 and as Executive Vice President and General Manager from 1982 to 1995. Mr. Brinkley has been a Director of ODEC since 1982.

Calvin P. Carter (82). Owner of Carter’s Store since 1960 and Carter Stone Co., a stone quarry since 1965. Mr. Carter has served as a member of the Campbell County Board of Supervisors since 1979. Mr. Carter has been a Director of ODEC since 1991 and a Director of Southside Electric Cooperative since 1972.

Glenn F. Chappell (63). Self-employed farmer since 1961. Mr. Chappell has been a Director of ODEC since 1995 and a Director of Prince George Electric Cooperative since 1985.

Kent D. Farmer (49). President and Chief Executive Officer of Rappahannock Electric Cooperative since 2004. Mr. Farmer also served as Chief Operating Officer of Rappahannock Electric Cooperative from 1999 to 2004. Mr. Farmer has been a Director of ODEC since 2004.

Stanley C. Feuerberg (55). President and Chief Executive Officer of Northern Virginia Electric Cooperative since 1992. Mr. Feuerberg has been a Director of ODEC since 1992.

William C. Frazier (76). Insurance broker of Associates Insurance Agency, a general insurance company, since 1999. Mr. Frazier has been a Director of ODEC since 2003 and a Director of Rappahannock Electric Cooperative since 1981.

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Fred C. Garber (62). Retired, formerly President of Mt. Jackson Farm Service, a retail farm supply company, from 1973 to 2003. Mr. Garber has been a Director of ODEC since 2005 and a Director of Shenandoah Valley Electric Cooperative since 1984.

Hunter R. Greenlaw, Jr.(61). President of Greenlaw, Edwards & Leake, Inc., a real estate development and general contracting company since 1974. Mr. Greenlaw has been a Director of ODEC since 1991 and a Director of Northern Neck Electric Cooperative since 1979.

Bruce A. Henry (61). Owner and Secretary/Treasurer of Delmarva Builders, Inc., a building contracting company since 1981. Mr. Henry has been a Director of ODEC since 1993 and a Director of Delaware Electric Cooperative since 1978.

Wade C. House (60). Vice President/Branch Manager of APAC-Atlantic, Inc., a highway construction company since 1972. Mr. House has been a Director of ODEC since 2004 and a Director of Northern Virginia Electric Cooperative since 1993.

Frederick L. Hubbard (66). President and Chief Executive Officer of Choptank Electric Cooperative since 2001. Mr. Hubbard also served as Senior Vice President and Chief Executive Officer of Choptank Electric Cooperative from 1991 to 2001. Mr. Hubbard has been a Director of ODEC since 1991.

David J. Jones (58). Owner/operator of Big Fork Farms since 1970 and Vice President of Exchange Warehouse, Inc. from 1996 to 2006. Mr. Jones has been a Director of ODEC since 1986 and a Director of Mecklenburg Electric Cooperative since 1982.

Bruce M. King (60). General Manager of BARC Electric Cooperative since 2003. Prior to that Mr. King was General Manager of Cherryland Electric Cooperative from 1993 to 2002. Mr. King has been a Director of ODEC since 2003.

William M. Leech, Jr.(79). Retired, former self-employed farmer from 1955 to 1988. Mr. Leech has been a Director of ODEC since 1977 and a Director of BARC Electric Cooperative since 1970.

M. Larry Longshore(65). President and Chief Executive Officer of Southside Electric Cooperative since 1998. Prior to that Mr. Longshore was President and Chief Executive Officer of Newberry Electric Cooperative from 1973 to 1998. Mr. Longshore has been a Director of ODEC since 1998.

Paul E.Owen (56). Director of Business Management with Smithfield Deli Group since 1974. Mr. Owen has been a Director of ODEC since 2007 and a Director of Community Electric Cooperative since 2000.

James M. Reynolds (59). President of Community Electric Cooperative since 2001. Mr. Reynolds also served as General Manager of Community Electric Cooperative from 1977 to 2001. Mr. Reynolds has been a Director of ODEC since 1977.

Myron D. Rummel (54). President and Chief Executive Officer of Shenandoah Valley Electric Cooperative since 2005. Mr. Rummel also served as Vice President, Engineering and Operations of Shenandoah Valley Electric Cooperative from 1993 to 2005. Mr. Rummel has been a Director of ODEC since 2005.

Philip B. Tankard(78). Office manager for Tankard Nurseries since 1985. Mr. Tankard has been a Director of ODEC since 2002 and a Director of A&N Electric Cooperative since 1960.

Gregory W. White (54). President and Chief Executive Officer of Northern Neck Electric Cooperative since 2005. Mr. White served as Senior Vice President of Power Supply of ODEC from 2004 to 2005, Senior Vice President Engineering and Operations of ODEC from 2002 to 2004 and Senior Vice President Retail and Alliance Management of ODEC from 2000 to 2002. Mr. White has been a Director of ODEC since 2005.

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Carl R. Widdowson (68). Self-employed farmer since 1956. Mr. Widdowson has been a Director of ODEC since 1987 and a Director of Choptank Electric Cooperative since 1980.

Audit Committee Financial Expert

We presently do not have an audit committee financial expert because of our cooperative governance structure and the resulting experience all of our directors have with matters affecting electric cooperatives in their roles as a chief executive officer or director of one of our member distribution cooperatives. In addition, the audit committee employs the services of accounting and financial consultants as it deems necessary.

Executive Officers

Our President and Chief Executive Officer administers our day-to-day business and affairs. Our executive officers, their respective ages, positions and recent business experience are listed below.

Jackson E. Reasor (54). President and Chief Executive Officer of ODEC and the Virginia, Maryland and Delaware Association of Electric Cooperatives (the “VMDA”), an electric cooperative association which provides services to its members and certain other electric cooperatives, since 1998. Mr. Reasor served as Vice President of First Virginia Bank from 1997 until 1998; President and Chief Executive Officer of Premier Trust Company from 1995 until 1997; a Virginia State Senator from 1992 until 1998; and an attorney with Galumbeck, Simmons & Reasor from 1992 until 1995.

Robert L. Kees (54). Senior Vice President and Chief Financial Officer since January 1, 2006. Mr. Kees also served as our Vice President and Controller from March 2004 to December 2005, as Assistant Vice President and Controller from March 2000 to February 2004 and as Controller from January 1994 to February 2000.

Lisa M. Johnson (41). Senior Vice President of Power Supply since May 2006. Prior to joining ODEC, Ms. Johnson served as Vice President at Mirant Corporation from 2001 to 2006.

John C. Lee, Jr.(46). Vice President of Member and External Relations since April 2004. Mr. Lee served as our Vice President Cooperative Affairs/Assistant to the President from March 2000 to March 2004; and as our Manager of Administration from February 1995 to February 2000.

Elissa M. Ecker (47). Vice President of Human Resources since November 2004. Prior to joining ODEC, Ms. Ecker served as Director of Human Resources of Xperts, Inc. from 2003 to 2004; as Director of Human Resources of Securicor New Century, L.L.C. from 2002 to 2003; and as Director of Human Resources of Manorhouse Retirement Centers, Inc. from 1997 to 2002.

Code of Ethics

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

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ITEM 11. EXECUTIVE COMPENSATION

Compensation Discussion and Analysis

General Philosophy

Our compensation philosophy has four objectives:

• attract and retain a qualified, diverse workforce through a competitive compensation program;

• provide equitable and fair compensation;

• support our business strategy; and

• ensure compliance with applicable laws and regulations.

Total Compensation Package

We compensate our senior management through the use of a total compensation package to include base salary, competitive benefits, and the potential of a bonus. The compensation of the chief executive officer (“CEO”) of ODEC is reviewed by the executive committee of our board of directors and a recommendation is then provided to our entire board of directors. The entire board of directors approves our CEO’s compensation. Our board of directors determines an annual salary derived from third party market data from the relevant labor market for positions of similar responsibilities. Our compensation structure is aligned with the external market through the use of a market pricing approach.

Targeted Overall Compensation

We engaged a consulting firm to assist us in establishing a market-based compensation program and to provide an annual review of our market analysis for all of our employees, including senior management. Our compensation program utilizes the creation and maintenance of accurate, detailed job descriptions as an instrument to establish benchmarked positions. The market compensation information includes salary data for positions within the determined competitive labor market. Our job descriptions are reviewed annually and include essential and non-essential responsibilities, required knowledge, skills and abilities, formal education and experience necessary to accomplish the requirements of the position which in turn helps us achieve operational goals. Utilizing this information, our human resources department determines a market-based salary for each position. A third-party consultant, Burton Fuller Management, Inc., reviews the market-based salary data we compiled for reasonableness and fairness annually. Our board of directors has defined market-based salary as approximately 95% to 100% of the 50^th percentile of the market, excluding new hires that may be hired at 90% of the 50^th percentile of market until a learning period is complete.

Process

We do not have a standing compensation committee because our board of directors has delegated to our President and CEO the authority to establish and adjust compensation for all other employees other than himself. We have a sub-committee of our board of directors, the executive committee, which recommends compensation for our CEO to the entire board of directors and the entire board of directors approves the compensation. The compensation for all other employees, including members of senior management other than the CEO, is determined by our CEO based upon market-based salary data. On an annual basis our board of directors reviews the performance and compensation of our CEO and our CEO reviews the performance and compensation of the remaining senior management.

Our CEO is also the CEO of the Virginia, Maryland and Delaware Association of Electric Cooperatives (“VMDA”) and their board of directors also approves the compensation of the CEO. The VMDA contributed $36,000 to our CEO’s salary for 2006 and will contribute $40,000 in 2007.

Base Salaries

We are an electric cooperative and do not have any stock and as a result, we do not have equity-based compensation programs. For this reason, substantially all of our compensation to our executive officers is provided

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in the form of base salary. We want to provide our senior management with a level of assured cash compensation in the form of base salary that is commensurate with the duties and responsibilities of their positions. These salaries were determined based on market data and internal structure for positions with similar responsibilities.

Bonuses

Our practice has been to, on infrequent occasions, award cash bonuses related to a specific event, such as the consummation of a significant transaction. On an annual basis, our board of directors determines the bonus criteria for our CEO and our CEO determines bonus criteria for all other executive officers. At the discretion of our board of directors, our CEO may be awarded an annual bonus; and, at the discretion of our CEO, other senior management may be awarded an annual bonus. We have not had any significant transactions in recent years and accordingly, our CEO and other members of our senior management were not awarded a bonus in any of the last three years. Our chief financial officer was awarded a $2,000 bonus when he was in his position as Vice President and Controller in 2004 under a bonus program generally available to all employees other than the CEO. Typically, senior management does not participate in this program.

Severance Benefits

We believe that companies should provide reasonable severance benefits to the CEO. With respect to our CEO, these severance benefits reflect the fact that it may be difficult to find comparable employment within a short period of time. In addition, while it is possible to provide salary continuation to a CEO during the job search process, which in some cases may be less expensive than a lump-sum severance payment, we prefer to pay a lump-sum severance payment to sever the relationship as soon as practicable if the severance is for cause. Our CEO’s contractual rights to amounts following severance are set forth in his employment agreement. None of our other members of senior management have any contractual severance benefits.

Plans

Retirement Plans

ODEC maintains a defined benefit pension plan which is available to all employees, with limited exceptions, who work at least 1,000 hours per year. This plan is a qualified pension plan under Section 401(a) of the Internal Revenue Code. Benefits, which accrue under the plan, are based upon the base annual salary as of November of the previous year.

We also have a 401(k) plan which is available to all employees in regular positions. Under the 401(k) plan for 2006, employees may elect to have up to 100% or $15,000, whichever is less, of their salary withheld on a pre-tax basis, subject to Internal Revenue Service limitations, and invested on their behalf. We match up to the first 2% of each participant’s base salary. Also, a catch-up contribution is available for participants in the plan once they attain age 50. The maximum catch-up contribution for 2006 was $5,000.

In addition, in 2006 ODEC entered into a non-qualified executive deferred compensation plan (the “Deferred Compensation Plan”). Our board of directors, at its discretion, determines who may participate in the plan as well as an annual contribution, if any, up to the maximum amount allowed by regulations. Currently, our board of directors has determined that our CEO is the only participant in this plan and in 2006 and we made a $15,000 contribution to the plan for his benefit.

Pension Restoration Plan

We participate in a pension restoration plan, which is intended to provide a supplemental benefit for employees who would have a reduction in their pension benefit from the Retirement and Security Plan because of the Internal Revenue Code limitations. Currently, our CEO is the only participant in this plan. Other executive officers may participate in this plan in the future.

Perquisites and Other Benefits

Our board of directors reviews the perquisites that our CEO receives during contract discussions with our CEO. The perquisite for Mr. Reasor is expenses for personal use of a company automobile amounted to $2,602 in 2006 and $2,406 in 2005.

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Senior management also participates in ODEC’s other benefit plans on the same terms as other employees. These plans include the defined benefit pension plan, the 401(k) plan, medical and dental insurance, vision insurance, life insurance & accidental death and dismemberment, long-term disability, long-term care insurance, medical reimbursement and dependent care flexible spending accounts, health club membership, vacation and sick leave. Relocation benefits are reimbursed for all employees who transfer to another location at the request or convenience of ODEC in accordance with ODEC’s relocation policy. We believe these benefits are customary for similar employers.

Change in Control

There is no provision in our CEO’s employment agreement or any other arrangements with any senior management that increases or decreases any amounts payable to him or her as a result of a change in control.

Summary Compensation Table

The following table sets forth information concerning compensation awarded to, earned by or paid to our CEO, our chief financial officer and three other senior executive officers for services rendered to us in all capacities during each of the last three fiscal years. The table also identifies the principal capacity in which each of these executives serves or served.

SUMMARY COMPENSATION TABLE

Name and Principal Position	Year	Salary		Bonus		Change in Pension Value and Non-Qualified Deferred Compensation		All Other Compensation(1)		Total
Jackson E. Reasor President and Chief Executive Officer	2006 2005 2004	$	351,667 330,833 311,667	$	—   —   —	$	96,656 85,571 58,614	$	62,625 55,400 51,672	$	510,948 471,804 421,953
Robert L. Kees Senior Vice President and Chief Financial Officer	2006 2005 2004		214,569 140,535 133,843		—   —   2,000		60,029 55,429 36,341		28,228 24,071 21,490		302,826 220,035 193,674
Lisa M. Johnson Senior Vice President Power Supply	2006 2005 2004		147,384 —   —		—   —   —		—   —   —		1,008 —   —		148,392 —   —
John C. Lee, Jr. Vice President of Member and External Relations	2006 2005 2004		157,516 141,148 128,447		—   —   —		41,309 35,637 25,010		27,424 23,836 19,396		226,249 200,621 172,853
Elissa M. Ecker Vice President of Human Resources	2006 2005 2004		141,765 134,750 17,088		—   —   —		5,483 269 —		25,882 3,098 92		173,130 138,117 17,180

⁽¹⁾ The items included in All Other Compensation are identified in the All Other Compensation table below.

Employment Agreement

On December 18, 2006, ODEC entered into an employment agreement with Jackson E. Reasor, our President and CEO. The agreement is for the term of five years, with an automatic one-year extension unless Mr. Reasor or the Employer gives written notice 30 days prior to the expiration of the agreement. The agreement provides that he will receive an annual salary of $360,000, effective as of June 1, 2006, subject to annual adjustment

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by the boards of directors of the ODEC and the VMDA (collectively, the “Employer”). The boards of directors of the Employer also may grant Mr. Reasor an annual bonus at their discretion. Mr. Reasor will also be entitled to participate in all benefit plans available to the employees of the Employer. Virginia, Maryland and Delaware Association of Electric Cooperatives is expected to contribute $36,000 of Mr. Reasor’s salary in 2006.

Under the agreement, if Mr. Reasor voluntarily terminates his employment following material breach by the Employer or the Employer terminates him without specified cause, the Employer will pay Mr. Reasor a salary at the rate in effect on the date of termination for one year, plus medical insurance benefits, with limited exceptions. If the agreement is not continued at the end of the stated term, the Employer will pay Mr. Reasor a salary at the rate in effect on the date of termination for six months.

Where the termination is without “cause” or the CEO terminates employment for “good reason” the employment agreement provides for benefits equal to one year of base salary and medical insurance. However, the medical insurance will cease if he becomes eligible for medical insurance coverage by virtue of his employment with another company. In addition, a terminated CEO is entitled to receive any benefits that he otherwise would have been entitled to receive under our 401(k) plan, frozen pension plan and supplemental retirement plans, although those benefits are not increased or accelerated. We believe that these levels are consistent with the general practice among generation and transmission cooperatives, although we have not conducted a study to confirm this.

Based upon a hypothetical termination date of December 31, 2007, the severance benefits for our CEO would have been entitled to would be as follows:

Base Salary(1)	$	360,000
Targeted bonus		—
Healthcare and other insurance benefits		13,619
Total	$	373,619

⁽¹⁾This calculation is based upon Mr. Reasor’s current salary. Mr. Reasor is scheduled for a salary review in June 2007.

Under our employment contract with our CEO, “cause” is (1) gross incompetence, insubordination, gross negligence, willful misconduct in office or breach of a material fiduciary duty, which includes a breach of confidentiality; (2) conviction of a felony, a crime of moral turpitude or commission of an act of embezzlement or fraud against ODEC or the VMDA (collectively, the “Employer”) or any subsidiary or affiliate thereof; (3) the CEO’s material failure to perform a substantial portion of his duties and responsibilities hereunder; but only after Employer provides the CEO written notice of such failure and gives him 30 days to remedy the situation; (4) deliberate dishonesty of the CEO with respect to ODEC or any of its subsidiaries or affiliates.

The CEO may terminate his employment with or without good reason by written notice to the board of directors effective 60 days after receipt of such notice by the board of directors. If the CEO terminates his employment for good reason, then the CEO is entitled to the salary specified above in the “without cause” paragraph. The CEO will not be required to render any further services. Upon termination of employment by the CEO without good reason, then the CEO is not entitled to further compensation. “Good reason” is our failure to maintain compensation and benefits or our material breach of any provision of the employment contract, which failure or breach continued for more than 30 days after the date on which our board of directors received such notice.

Defined Benefit Plan

We have elected to participate in the National Rural Electric Cooperatives Association (“NRECA”) Retirement and Security Program (the “Plan”), a noncontributory, defined benefit, multiple-employer, master pension plan maintained and administered by the NRECA for the benefit of its member systems and their employees. The Plan is a qualified pension plan under Section 401(a) of the Internal Revenue Code of 1986. The following table lists the estimated current annual pension benefit payable at “normal retirement age,” age 62, for

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participants in the specified final average salary and years of benefit service categories for the given current multiplier of 1.7%. Benefits, which accrue under the Plan, are based upon the base annual salary as of November of the previous year. As a result of changes in Internal Revenue Service regulations, the base annual salary used in determining benefits is limited to $225,000 effective January 1, 2007.

PENSION BENEFITS TABLE

Name	Plan Name	Number of Years Credited Service	Present Value of Accumulated Benefit		Payments During Last Year
Jackson E. Reasor	NRECA Retirement and	7.08	$	272,194	—
	Security Plan
	Pension Restoration Plan			119,003
Robert L.Kees	NRECA Retirement and	14.00		320,200	—
	Security Plan
Lisa M. Johnson	NRECA Retirement and	—		—	—
	Security Plan
John C. Lee, Jr.	NRECA Retirement and	13.58		204,822	—
	Security Plan
Elissa M. Ecker	NRECA Retirement and	1.83		5,752	—
	Security Plan

The pension benefits indicated above are the estimated amounts payable by the Plan, and they are not subject to any deduction for Social Security or other offset amounts. The participant’s annual pension at his or her normal retirement date is equal to the product of his or her years of benefit service times final average salary times the multiplier in effect during years of benefit service. The multiplier was 1.7% commencing January 1, 1992. The number of years of credited service is as of the “normal retirement age” for each of the named executives. The present value of accumulated benefit is calculated assuming that the executive retires at the normal retirement age per the plan and that they receive lump sums. The lump sum amounts are calculated using the 30-year Treasury rate (4.73% for 2006 and 4.89% for 2005) and the required Internal Revenue Service mortality table for lump sum payments (1994 GAS, projected to 2002, blended 50%/50% for unisex mortality.)

We participate in a pension restoration plan, which is intended to provide a supplemental benefit for employees who would have a reduction in their pension benefit from the Retirement and Security Plan because of the Internal Revenue Code limitations.

Deferred Compensation Plan

On December 18, 2006, in connection with the execution of the employment agreement with our CEO, ODEC adopted the Deferred Compensation Plan for the purpose of providing supplemental deferred compensation to Mr. Reasor in an amount within the statutory maximums permitted under Section 457 of the Internal Revenue Code. The Deferred Compensation Plan is restricted to those executive employees designated by the board of directors of ODEC who are generally responsible for ongoing operations, responsible for and have general supervision over the overall financial condition, setting and executing overall corporate policies and practices, and supervising large numbers of employees and who elect to participate in the Deferred Compensation Plan by agreeing to a deferral of a portion of their current compensation. Currently, Mr. Reasor is the only participant in the Deferred Compensation Plan. Under the Deferred Compensation Plan, annual deferrals cannot exceed 100% of Mr. Reasor’s annual compensation or $15,000 (for 2006), adjusted by and subject to specified tax laws (the “deferral limit”), during any year in which ODEC is exempt from federal income taxation. During the last three years before Mr. Reasor attains the normal retirement age under ODEC’s primary pension plan, currently age 62, the deferral limit is

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increased to the lesser of two times the deferral limit or the deferral limit plus the amount Mr. Reasor was eligible to but did not defer under the Deferred Compensation Plan. Amounts credited to him under the Plan will be credited with earnings or losses equal to those made by an investment in one or more funds of a specified regulated investment company designated by him. Distributions under the Deferred Compensation Plan generally commence upon severance of employment, whether upon termination, retirement or death.

The following table sets forth the non-qualified deferred compensation paid to our executive officers in 2006:

NON-QUALIFIED DEFERRED COMPENSATION BENEFITS TABLE

Name	Executive Contributions in Last Fiscal Year(1)	Registrant Contributions in Last Fiscal year(1)		Aggregate Earnings in Last Fiscal Year(1)		Aggregate Withdrawals/ Distributions	Aggregate Balance at Last Fiscal Year End
Jackson E. Reasor	—	$	15,000	$	74	—	$	15,074
Robert L. Kees	n/a		n/a		n/a	n/a		n/a
Lisa M. Johnson	n/a		n/a		n/a	n/a		n/a
John C. Lee, Jr.	n/a		n/a		n/a	n/a		n/a
Elissa M. Ecker	n/a		n/a		n/a	n/a		n/a

(1) These amounts are not included in summary compensation table.

The following table sets forth information concerning all other compensation awarded to, earned by or paid to these executives during the last completed fiscal year.

ALL OTHER COMPENSATION

Name	Perquisites and Other Personal Benefits(1)		Company Contributions to Defined Benefit Plans		Company-paid Insurance Premiums		All Other Compensation
Jackson E. Reasor(2)	$	7,002	$	53,823	$	1,800	$	62,625
Robert L. Kees		4,292		22,921		1,015		28,228
Lisa M. Johnson		—		—		1,008		1,008
John C. Lee, Jr.		3,150		23,244		1,030		27,424
Elissa M. Ecker		2,835		22,068		979		25,882

⁽¹⁾ Perquisites and other personal benefits is composed of contributions made by ODEC to the 401(K) plan.

⁽²⁾ Perquisites and other personal benefits includes $2,602 for personal use of a company automobile.

Board of Directors Compensation

It is our policy to compensate the members of our board of directors who are not employed by one of our member distribution cooperatives (“outside directors”). Our outside directors were compensated by a monthly retainer of $1,700 in 2006. Beginning in 2007, the monthly retainer is $2,000. They are also paid for meetings at a

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rate of $400 per in person meeting and $200 per teleconference, if the meeting date falls outside the normal board of directors meeting dates. All directors are reimbursed for out-of-pocket expenses incurred in attending meetings. Our directors receive no other compensation. Our directors do not have pension benefits, non-equity incentive plan compensation, or other perquisites and because we are a cooperative, we do not have stock or other equity options. The following table sets forth the compensation we paid to our directors in 2006:

DIRECTOR COMPENSATION TABLE

	Fees Earned
Name	or Paid in Cash(1)
Calvin P. Carter	$	28,000
Glenn F. Chappell		24,200
Carl R. Eason		23,000
William C. Frazier		23,400
Fred C. Garber		25,600
Hunter R. Greenlaw, Jr.		27,600
Bruce A. Henry		26,600
Wade C. House		21,400
David J. Jones		26,200
William M. Leech, Jr.		22,400
Philip B. Tankard		24,200
Carl R. Widdowson		32,200

⁽¹⁾ Our directors received no compensation other than as set forth in this column.

Compensation Committee Interlocks and Insider Participation

As described above, we do not have a compensation committee but the executive committee of our board of directors establishes and the full board of directors approves all compensation and awards to the CEO. Our board of directors has delegated to our CEO the authority to establish and adjust compensation for all other employees other than himself. No member of our board of directors is or previously was an officer or employee of ODEC or is or has engaged in transactions with ODEC, with one exception. Gregory W. White was an employee of ODEC from 1995 to 2005 when he left his position as Senior Vice President of Power Supply to be the President and Chief Executive Officer of Northern Neck Electric Cooperative, one of our twelve member distribution cooperatives. As the President and Chief Executive Officer of one of our member distribution cooperatives, he serves on our board of directors. Our directors are, however, members or directors of our member distribution cooperatives. See “Cooperative Status” in Item 1 and “Directors and Officers of the Registrant” in Item 10.

Compensation Committee Report

The board of directors, including the Executive Committee of the board of directors, has reviewed and discussed with the management of ODEC the contents of the section entitled “Compensation Discussion and Analysis” and based on such review and discussion has recommended and approved to the board of directors its inclusion in this annual report.

John William Andrew, Jr.

M. Johnson Bowman*

M Dale Bradshaw

Vernon N. Brinkley

Calvin P. Carter

Glenn F. Chappell

Kent D. Farmer

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Stanley C. Feuerberg

William C. Frazier

Fred C. Garber

Hunter R. Greenlaw, Jr.*

Bruce A. Henry*

Wade C. House*

Frederick L. Hubbard*

David J. Jones

Bruce M. King

William M. Leech, Jr.

M. Larry Longshore

Paul E. Owen

James M. Reynolds*

Myron D. Rummel

Philip B. Tankard

Gregory W. White

Carl R. Widdowson

* Denotes member of the Executive Committee of the board of directors

ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND RELATED STOCKHOLDER MATTERS

Not Applicable.

ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS AND DIRECTOR INDEPENDENCE

Because we are a cooperative, all of our directors are representatives of our member distribution cooperatives, which are our principal customers. Due to the extent of the payments by each member distribution cooperative to us, our directors are not independent based on the definition of “independence” of the New York Stock Exchange.

ITEM 14. PRINCIPAL ACCOUNTANT FEES AND SERVICES

The following table presents fees for services provided by Ernst & Young LLP for fiscal 2006 and 2005. All Audit, Audit-Related, and Tax Fees shown below were pre-approved by the Audit Committee in accordance with its established procedures.

	2006		2005
Audit Fees (a)	$	267,831	$	285,850
Audit-Related Fees (b)		45,725		151,480
Tax Fees (c)		60,180		3,960
Total	$	373,736	$	441,290

a) Fees for professional services provided for the audit of the Company’s annual financial statements as well as reviews of the Company’s quarterly reports on Form 10-Q, accounting consultations on matters addressed during the audit or interim reviews, and SEC filings and offering memorandums including comfort letters, consents, and comment letters.

b) Fees for professional services which principally include accounting consultations and services in connection with internal control matters.

c) Fees for professional services for tax-related advice and compliance

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PART IV

ITEM 15. EXHIBITS, FINANCIAL STATEMENT SCHEDULES

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

1. Financial Statements

See Index on page 50

2. Financial Statement Schedules

Not applicable.

3. Exhibits

Exhibits

*3.1 Amended and Restated Articles of Incorporation of Old Dominion Electric Cooperative (filed as exhibit 3.1 to the Registrant’s Form 10-Q, File No. 33-46795, filed on August 11, 2000).

*3.2 Bylaws of Old Dominion Electric Cooperative, Amended and Restated as of September 10, 2002, as amended on September 14, 2004 (filed as exhibit 3.1 to the Registrant’s Form 10-Q, File No. 000-50039, filed on November 15, 2004).

*4.1 Indenture of Mortgage and Deed of Trust, dated as of May 1, 1992, between Old Dominion Electric Cooperative and Crestar Bank, as Trustee (filed as exhibit 4.1 to the Registrant’s Form 10-K for the year ended December 31, 1992, File No. 33-46795, filed on March 30, 1993).

*4.2 Third Supplemental Indenture, dated as of May 1, 1993, to the Indenture of Mortgage and Deed of Trust, dated as of May 1, 1992, between Old Dominion Electric Cooperative and Crestar Bank, as Trustee, including the form of the First Mortgage Bonds, 1993 Series A (filed as exhibit 4.1 to the Registrant’s Form 10-Q for the quarter ended June 30, 1993, File No. 33-46795, filed on August 10, 1993).

*4.3 Fourth Supplemental Indenture, dated as of December 15, 1994, to the Indenture of Mortgage and Deed of Trust dated as of May 1, 1992, between Old Dominion Electric Cooperative and Crestar Bank, as Trustee (filed as exhibit 4.5 to the Registrant’s Form 10-K for the year ended December 31, 1996, File No. 33-46795, on March 20, 1997).

*4.4 Fifth Supplemental Indenture, dated as of February 29, 1996, to the Indenture of Mortgage and Deed of Trust dated as of May 1, 1992, between Old Dominion Electric Cooperative and Crestar Bank, as Trustee including the form of the First Mortgage Bonds, 1996 Series A and 1996 Series B (filed as exhibit 4.6 to the Registrant’s Form 10-K for the year ended December 31, 1996, File No. 33-46795, on March 20, 1997).

*4.5 Eleventh Supplemental Indenture, dated as of September 1, 2001, to the Indenture of Mortgage and Deed of Trust dated as of May 1, 1992, between Old Dominion Electric Cooperative and SunTrust Bank (formerly Crestar Bank), as Trustee, including the form of the 2001 Series A Bond (filed as exhibit 4.1 to the Registrant’s Form 10-Q/A for the quarter ended September 30, 2001, File No. 33-46795, filed on November 20, 2001).

*4.6 Thirteenth Supplemental Indenture, dated as of November 1, 2002, to the Indenture of Mortgage and Deed of Trust dated as of May 1, 1992, between Old Dominion Electric Cooperative and SunTrust Bank (Formerly Crestar Bank), as Trustee, including the form of the 2002 Series A Bond (filed as exhibit 4.14 to Amendment No. 1 to the Registrant’s Form S 3, File No. 333-100577, on November 25, 2002).

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*4.7 Fourteenth Supplemental Indenture, dated as of December 1, 2002, to the Indenture of Mortgage and Deed of Trust dated as of May 1, 1992, between Old Dominion Electric Cooperative and SunTrust Bank (Formerly Crestar Bank), as Trustee, including the form of the 2002 Series B Bond (filed as exhibit 4.1 to the Registrant’s Form 8-K, File No. 000-50039, on December 27, 2002).

*4.8 Fifteenth Supplemental Indenture, dated as of May 1, 2003, to the Indenture of Mortgage and Deed of Trust dated as of May 1, 1992, between Old Dominion Electric Cooperative and SunTrust Bank (Formerly Crestar Bank), as Trustee (filed as Exhibit 4.A to the Registrant’s Form 10-K for the year ended December 31, 2003, File No. 000-50039, on March 22, 2004).

*4.9 Sixteenth Supplemental Indenture, dated as of July 1, 2003, to the Indenture of Mortgage and Deed of Trust dated as of May 1, 1992, between Old Dominion Electric Cooperative and SunTrust Bank (Formerly Crestar Bank), as Trustee, including the form of the 2003 Series A Bond (filed as Exhibit 4.1 to the Registrant’s Form 8-K, File No. 000-50039, on July 25, 2003).

*4.10 Seventeenth Supplemental Indenture, dated as of January 1, 2004, to the Indenture of Mortgage and Deed of Trust dated as of May 1, 1992, between Old Dominion Electric Cooperative and SunTrust Bank (formerly Crestar Bank), as Trustee (filed as Exhibit 4.B to the Registrant’s Form 10-K for the year ended December 31, 2003, File No 000-50039, on March 22, 2004).

*4.11 Amended and Restated Indenture, dated as of September 1, 2001, between Old Dominion Electric Cooperative and SunTrust Bank, as Trustee (filed as exhibit 4.2 to Registrant’s Form 10-Q/A for the quarter ended September 30, 2001, File No. 33-46795, filed on November 20, 2001).

*4.12 First Supplemental Indenture, dated as of December 1, 2002, to the Amended and Restated Indenture, dated as of September 1, 2001, between Old Dominion Electric Cooperative and SunTrust Bank, as Trustee (filed as Exhibit 4.2 to the Registrant’s Form 8-K, File No. 000-50039, on December 27, 2002).

*10.1 Nuclear Fuel Agreement between Virginia Electric and Power Company and Old Dominion Electric Cooperative, dated as of December 28, 1982, amended and restated October 17, 1983 (filed as exhibit 10.1 to the Registrant’s Form S-1 Registration Statement, File No. 33-46795, filed on March 27, 1992).

*10.2 Purchase, Construction and Ownership Agreement between Virginia Electric and Power Company and Old Dominion Electric Cooperative, dated as of December 28, 1982, amended and restated October 17, 1983 (filed as exhibit 10.2 to the Registrant’s Form S-1 Registration Statement, File No. 33-46795, filed on March 27, 1992).

*10.3 Operating and Power Sales Agreement, dated as of October 12, 2004, among Virginia Electric and Power Company, Old Dominion Electric Cooperative, and New Dominion Energy Cooperative (filed as exhibit 10.1 to the Registrant’s Form 10-Q, File No. 000-50039, on November 15, 2004). Amended and Restated Interconnection and Operating Agreement between Virginia Electric and Power Company and Old Dominion Electric Cooperative, dated as of July 29, 1997 (filed as exhibit 10.5 to the Registrant’s Form 10-K for the year ended December 31, 1998, File No. 33-46795, on March 25, 1999).

*10.4 Clover Purchase, Construction and Ownership Agreement between Old Dominion Electric Cooperative and Virginia Electric and Power Company, dated as of May 31, 1990 (filed as exhibit 10.4 to the Registrant’s Form S-1 Registration Statement, File No. 33-46795, filed on March 27, 1992).

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*10.5 Amendment No. 1 to the Clover Purchase, Construction and Ownership Agreement between Old Dominion Electric Cooperative and Virginia Electric and Power Company, effective March 12, 1993 (filed as exhibit 10.34 to the Registrant’s Form S-1 Registration Statement, File No. 33-61326, filed on April 19, 1993).

*10.6 Clover Operating Agreement between Virginia Electric and Power Company and Old Dominion Electric Cooperative, dated as of May 31, 1990 (filed as exhibit 10.6 to the Registrant’s Form S-1 Registration Statement, File No. 33-46795, filed on March 27, 1992).

*10.7 Amendment to the Clover Operating Agreement between Virginia Electric and Power Company and Old Dominion Electric Cooperative, effective January 17, 1995 (filed as exhibit 10.8 to the Registrant’s Form 10-K for the year ended December 31, 1994, File No. 33-46795, on March 15, 1995).

*10.8 Lease Agreement between Old Dominion Electric Cooperative and Regional Headquarters, Inc., dated July 29, 1986 (filed as exhibit 10.27 to the Registrant’s Form S-1 Registration Statement, File No. 33-46795, filed on March 27, 1992).

*10.9 Nuclear Decommissioning Trust Agreement between Old Dominion Electric Cooperative and Bankers Trust Company, dated March 1, 1991 (filed as exhibit 10.29 to the Registrant’s Form S-1 Registration Statement, File No. 33-46795, filed on March 27, 1992).

*10.10 Form of Salary Continuation Plan (filed as exhibit 10.31 to the Registrant’s Form S-1 Registration Statement, File No. 33-46795, filed on March 27, 1992).

*10.11 Amended and Restated Wholesale Power Contract between Old Dominion Electric Cooperative and A&N Electric Cooperative, dated April 24, 1992 (filed as exhibit 10.34 to Amendment No. 2 to the Registrant’s Form S-1 Registration Statement, File No. 33-46795, filed on May 27, 1992).

*10.12 Amended and Restated Wholesale Power Contract between Old Dominion Electric Cooperative and BARC Electric Cooperative, dated April 22, 1992 (filed as exhibit 10.35 to Amendment No. 1 to the Registrant’s Form S-1 Registration Statement, File No. 33-46795, filed on May 6, 1992).

*10.13 Amended and Restated Wholesale Power Contract between Old Dominion Electric Cooperative and Choptank Electric Cooperative, dated April 20, 1992 (filed as exhibit 10.36 to Amendment No. 1 to the Registrant’s Form S-1 Registration Statement, File No. 33-46795, filed on May 6, 1992).

*10.14 Amended and Restated Wholesale Power Contract between Old Dominion Electric Cooperative and Community Electric Cooperative, dated April 28, 1992 (filed as exhibit 10.37 to Amendment No. 1 to the Registrant’s Form S-1 Registration Statement, File No. 33-46795, filed on May 6, 1992).

*10.15 Amended and Restated Wholesale Power Contract between Old Dominion Electric Cooperative and Delaware Electric Cooperative, dated April 22, 1992 (filed as exhibit 10.38 to Amendment No. 1 to the Registrant’s Form S-1 Registration Statement, File No. 33-46795, filed on May 6, 1992).

*10.16 Amended and Restated Wholesale Power Contract between Old Dominion Electric Cooperative and Mecklenburg Electric Cooperative, dated April 15, 1992 (filed as exhibit 10.39 to Amendment No. 1 to the Registrant’s Form S-1 Registration Statement, File No. 33-46795, filed on May 6, 1992).

*10.17 Amended and Restated Wholesale Power Contract between Old Dominion Electric Cooperative and Northern Neck Electric Cooperative, dated April 21, 1992 (filed as exhibit 10.40 to Amendment No. 1 to the Registrant’s Form S-1 Registration Statement, File No. 33-46795, filed on May 6, 1992).

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*10.18 Amended and Restated Wholesale Power Contract between Old Dominion Electric Cooperative and Northern Virginia Electric Cooperative, dated April 17, 1992 (filed as exhibit 10.41 to Amendment No. 1 to the Registrant’s Form S-1 Registration Statement, File No. 33-46795, filed on May 6, 1992).

*10.19 Amended and Restated Wholesale Power Contract between Old Dominion Electric Cooperative and Community Electric Cooperative, dated April 28, 1992 (filed as exhibit 10.37 to Amendment No. 1 to the Registrant’s Form S-1 Registration Statement, File No. 33-46795, filed on May 6, 1992).

*10.20 Amended and Restated Wholesale Power Contract between Old Dominion Electric Cooperative and Delaware Electric Cooperative, dated April 22, 1992 (filed as exhibit 10.38 to Amendment No. 1 to the Registrant’s Form S-1 Registration Statement, File No. 33-46795, filed on May 6, 1992).

*10.21 Amended and Restated Wholesale Power Contract between Old Dominion Electric Cooperative and Mecklenburg Electric Cooperative, dated April 15, 1992 (filed as exhibit 10.39 to Amendment No. 1 to the Registrant’s Form S-1 Registration Statement, File No. 33-46795, filed on May 6, 1992).

*10.22 Amended and Restated Wholesale Power Contract between Old Dominion Electric Cooperative and Northern Neck Electric Cooperative, dated April 21, 1992 (filed as exhibit 10.40 to Amendment No. 1 to the Registrant’s Form S-1 Registration Statement, File No. 33-46795, filed on May 6, 1992).

*10.23 Amended and Restated Wholesale Power Contract between Old Dominion Electric Cooperative and Northern Virginia Electric Cooperative, dated April 17, 1992 (filed as exhibit 10.41 to Amendment No. 1 to the Registrant’s Form S-1 Registration Statement, File No. 33-46795, filed on May 6, 1992).

*10.24 Amended and Restated Wholesale Power Contract between Old Dominion Electric Cooperative and Prince George Electric Cooperative, dated May 6, 1992 (filed as exhibit 10.42 to Amendment No. 2 to the Registrant’s Form S-1 Registration Statement, File No. 33-46795, filed on May 27, 1992).

*10.25 Amended and Restated Wholesale Power Contract between Old Dominion Electric Cooperative and Rappahannock Electric Cooperative, dated April 17, 1992 (filed as exhibit 10.43 to Amendment No. 1 to the Registrant’s Form S-1 Registration Statement, File No. 33-46795, filed on May 6, 1992).

*10.26 Amended and Restated Wholesale Power Contract between Old Dominion Electric Cooperative and Shenandoah Valley Electric Cooperative, dated April 23, 1992 (filed as exhibit 10.44 to Amendment No. 1 to the Registrant’s Form S-1 Registration Statement, File No. 33-46795, filed on May 6, 1992).

*10.27 Amended and Restated Wholesale Power Contract between Old Dominion Electric Cooperative and Southside Electric Cooperative, dated April 22, 1992 (filed as exhibit 10.45 to Amendment No. 1 to the Registrant’s Form S-1 Registration Statement, File No. 33-46795, filed on May 6, 1992).

*10.28 Interconnection Agreement between Delmarva Power & Light Company and Old Dominion Electric Cooperative, dated November 30, 1999 (filed as exhibit 10.33 to the Registrant’s Form 10-K for the year ended December 31, 2000, File No. 33-46795, on March 19, 2001).

*10.29 Participation Agreement, dated as of February 29, 1996, among Old Dominion Electric Cooperative, State Street Bank and Trust Company, the Owner Participant named therein and Utrecht America Finance Co (filed as exhibit 10.35 to the Registrant’s Form 10-K for the year ended December 31, 1996, File No. 33-46795, on March 20, 1997).

*10.30 Clover Unit 1 Equipment Interest Lease Agreement, dated as of February 29, 1996, between Old Dominion Electric Cooperative, as Equipment Head Lessor, and State Street Bank and Trust Company, as Equipment Head Lessee (filed as exhibit 10.36 to the Registrant’s Form 10-K for the year ended December 31, 1996, File No. 33-46795, on March 20, 1997).

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**10.31 Equipment Operating Lease Agreement, dated as of February 29, 1996, between State Street Bank and Trust Company, as Lessor, and Old Dominion Electric Cooperative, as Lessee (filed as exhibit 10.37 to the Registrant’s Form 10-K for the year ended December 31, 1996, File No. 33-46795, on March 20, 1997).

**10.32 Corrected Option Agreement to Lease, dated as of February 29, 1996, among Old Dominion Electric Cooperative and State Street Bank and Trust Company (filed as exhibit 10.38 to the Registrant’s Form 10-K for the year ended December 31, 1996, File No. 33-46795, on March 20, 1997).

*10.33 Clover Agreements Assignment and Assumption Agreement, dated as of February 29, 1996, between Old Dominion Electric Cooperative, as Assignor, and State Street Bank and Trust Company, as Assignee (filed as exhibit 10.39 to the Registrant’s Form 10-K for the year ended December 31, 1996, File No. 33-46795, on March 20, 1997).

*10.34 Payment Undertaking Agreement, dated as of February 29, 1996, between Old Dominion Electric Cooperative and Cooperatieve Centrale Raiffeisen Boerenleenbank B.A., “Rabobank Nederland”, New York Branch (filed as exhibit 10.42 to the Registrant’s Form 10-K for the year ended December 31, 1996, File No. 33-46795, on March 20, 1997).

*10.35 Payment Undertaking Pledge Agreement, dated as of February 29, 1996, between Old Dominion Electric Cooperative, as Payment Undertaking Pledgor, and State Street Bank and Trust Company, as Payment Undertaking Pledgee (filed as exhibit 10.43 to the Registrant’s Form 10-K for the year ended December 31, 1996, File No. 33-46795, on March 20, 1997).

*10.36 Pledge Agreement, dated as of February 29, 1996, between Old Dominion Electric Cooperative, as Pledgor, and State Street Bank and Trust Company, as Pledgee (filed as exhibit 10.44 to the Registrant’s Form 10-K for the year ended December 31, 1996, File No. 33-46795, on March 20, 1997).

*10.37 Tax Indemnity Agreement, dated as of February 29, 1996, among Old Dominion Electric Cooperative, State Street Bank and Trust Company, the Owner Participant named therein and Utrecht America Finance Co. (filed as exhibit 10.45 to the Registrant’s Form 10-K for the year ended December 31, 1996, File No. 33-46795, on March 20, 1997).

*10.38 Participation Agreement, dated as of July 1, 1996, among Old Dominion Electric Cooperative, Clover Unit 2 Generating Trust, Wilmington Trust Company, the Owner Participant named therein and Utrecht America Finance Co. (filed as exhibit 10.46 to the Registrant’s Form 10-K for the year ended December 31, 1996, File No. 33-46795, on March 20, 1997).

**10.39 Clover Unit 2 Equipment Interest Agreement, dated as of July 1, 1996, between Old Dominion Electric Cooperative and Clover Unit 2 Generating Trust (filed as exhibit 10.47 to the Registrant’s Form 10-K for the year ended December 31, 1996, File No. 33-46795, on March 20, 1997).

**10.40 Operating Equipment Agreement, dated as of July 1, 1996, between Clover Unit 2 Generating Trust and Old Dominion Electric Cooperative (filed as exhibit 10.48 to the Registrant’s Form 10-K for the year ended December 31, 1996, File No. 33-46795, on March 20, 1997).

*10.41 Clover Agreements Assignment and Assumption Agreement, dated as of July 1, 1996, between Old Dominion Electric Cooperative, as Assignor, and Clover Unit 2 Generating Trust, as Assignee (filed as exhibit 10.49 to the Registrant’s Form 10-K for the year ended December 31, 1996, File No. 33-46795, on March 20, 1997).

*10.42 Deed of Ground Lease and Sublease Agreement, dated as of July 1, 1996, between Old Dominion Electric Cooperative, as Ground Lessor, and Clover Unit 2 Generating Trust, as Ground Lessee (filed as exhibit 10.50 to the Registrant’s Form 10-K for the year ended December 31, 1996, File No. 33-46795, on March 20, 1997).

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*10.43 Guaranty Agreement, dated as of July 1, 1996, between Old Dominion Electric Cooperative and AMBAC Indemnity Corporation (filed as exhibit 10.51 to the Registrant’s Form 10-K for the year ended December 31, 1996, File No. 33-46795, on March 20, 1997).

*10.44 Investment Agreement, dated as of July 31, 1996, among AMBAC Capital Funding, Inc., Old Dominion Electric Cooperative and AMBAC Indemnity Corporation (filed as exhibit 10.52 to the Registrant’s Form 10-K for the year ended December 31, 1996, File No. 33-46795, on March 20, 1997).

*10.45 Investment Agreement Pledge Agreement, dated as of July 1, 1996, among Old Dominion Electric Cooperative, as Investment Agreement Pledgor, AMBAC Indemnity Corporation, the Owner Participant named therein and Clover Unit 2 Generating Trust (filed as exhibit 10.53 to the Registrant’s Form 10-K for the year ended December 31, 1996, File No. 33-46795, on March 20, 1997).

*10.46 Equity Security Pledge Agreement, dated as of July 1, 1996, between Old Dominion Electric Cooperative, as Pledgor, and Wilmington Trust Company, as Collateral Agent (filed as exhibit 10.54 to the Registrant’s Form 10-K for the year ended December 31, 1996, File No. 33-46795, on March 20, 1997).

*10.47 Payment Undertaking Agreement, dated as of July 1, 1996, between Old Dominion Electric Cooperative and Cooperatieve Centrale Raiffeisen Boerenleenbank B.A., “Rabobank Nederland”, New York Branch (filed as exhibit 10.55 to the Registrant’s Form 10-K for the year ended December 31, 1996, File No. 33-46795, on March 20, 1997).

*10.48 Payment Undertaking Pledge Agreement, dated as of July 1, 1996, between Old Dominion Electric Cooperative, as Payment Undertaking Pledgor, and Clover Unit 2 Generating Trust, as Payment Undertaking Pledgee (filed as exhibit 10.56 to the Registrant’s Form 10-K for the year ended December 31, 1996, File No. 33-46795, on March 20, 1997).

*10.49 Subordinated Deed of Trust and Security Agreement, dated as of July 1, 1996, among Old Dominion Electric Cooperative, Richard W. Gregory, Trustee, and Michael P. Drzal, Trustee (filed as exhibit 10.57 to the Registrant’s Form 10-K for the year ended December 31, 1996, File No. 33-46795, on March 20, 1997).

*10.50 Subordinated Security Agreement, dated as of July 1, 1996, among Old Dominion Electric Cooperative, the Owner Participant named therein, AMBAC Indemnity Corporation and Clover Unit 2 Generating Trust (filed as exhibit 10.58 to the Registrant’s Form 10-K for the year ended December 31, 1996, File No. 33-46795, on March 20, 1997).

*10.51 Tax Indemnity Agreement, dated as of July 1 1996, between Old Dominion Electric Cooperative and the Owner Participant named therein (filed as exhibit 10.59 to the Registrant’s Form 10-K for the year ended December 31, 1996, File No. 33-46795, on March 20, 1997).

*10.52 Amendment No. 3 to Participation Agreement (filed as Exhibit 10.1 to the Registrant’s Form 10-Q for the quarter ended March 31, 2006, File No. 000-50039, on May 12, 2006).

*10.53 Amendment No. 2 to Equipment Operating Lease Agreement (filed as Exhibit 10.2 to the Registrant’s Form 10-Q for the quarter ended March 31, 2006, File No. 000-50039, on May 12, 2006).

*10.54 Amendment No. 2 to Corrected Foundation Operating Lease Agreement (filed as Exhibit 10.3 to the Registrant’s Form 10-Q for the quarter ended March 31, 2006, File No. 000-50039, on May 12, 2006).

*10.55 Investment Agreement (filed as Exhibit 10.4 to the Registrant’s Form 10-Q for the quarter ended March 31, 2006, File No. 000-50039, on May 12, 2006).

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*10.56 Investment Pledge Agreement (filed as Exhibit 10.5 to the Registrant’s Form 10-Q for the quarter ended March 31, 2006, File No. 000-50039, on May 12, 2006).

*10.57 Amendment No. 3 to Payment Undertaking Agreement (filed as Exhibit 10.6 to the Registrant’s Form 10-Q for the quarter ended March 31, 2006, File No. 000-50039, on May 12, 2006).

*10.58 Amendment No. 2 to Tax Indemnity Agreement (filed as Exhibit 10.7 to the Registrant’s Form 10-Q for the quarter ended March 31, 2006, File No. 000-50039, on May 12, 2006).

*10.59 Employment Agreement, dated June 1, 2006, between Old Dominion Electric Cooperative and Jackson E. Reasor and accepted by Jackson E. Reasor on December 18, 2006 (filed as Exhibit 10.1 to the Registrant’s Form 8-K, File No. 000-50039, on December 21, 2006).

*10.60 Executive Deferred Compensation Plan, dated June 30, 2006, adopted on December 18, 2006 (filed as Exhibit 10.2 to the Registrant’s Form 8-K File No. 000-50039, on December 21, 2006).

*10.61 Employment letter, dated November 28, 2005, of Old Dominion Electric Cooperative and agreed and accepted by Robert L. Kees (filed as exhibit 10.1 to the Registrant’s Form 8-K, No. 000-50039, on November 28, 2005).

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

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

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

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

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

*10.67 Amendment No. 2 to Participation Agreement, dated as of December 31, 2004, between and among Old Dominion Electric Cooperative, U.S. Bank National Association, Wachovia Bank, National Association, Utrecht-America Finance Co., and Cedar Hill International Corp. (filed as exhibit 10.1 to the Registrant’s Form 8-K, File No. 000-50039, on January 13, 2005).

*10.68 Mutual Operating Agreement, dated as of May 18, 2005, between Virginia Electric and Power Company and Old Dominion Electric Cooperative.

21 Subsidiaries of Old Dominion Electric Cooperative (not included because Old Dominion Electric Cooperative’s subsidiaries, considered in the aggregate as a single subsidiary, would not constitute a “significant subsidiary” under Rule 102(w) of Regulation S-X).

23.1 Consent of Ernst & Young LLP

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

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

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

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

* Incorporated herein by reference.

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

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

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

Old Dominion does not solicit proxies from its cooperative members and thus is not required to provide an annual report to its security holders and will not prepare such a report after filing this Form 10-K for fiscal year 2006. Accordingly, Old Dominion will not file an annual report with the Securities and Exchange Commission.

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SIGNATURES

Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the Registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.

OLD DOMINION ELECTRIC COOPERATIVE
Registrant
By:	/s/ JACKSON E. REASOR
	Jackson E. Reasor
	President and Chief Executive Officer

Date: March 20, 2007

Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the Registrant and in the following capacities on March 20, 2007.

Signature	Title
/s/ JACKSON E. REASOR	President and Chief Executive Officer (Principal executive officer)
Jackson E. Reasor
/s/ ROBERT L. KEES	Senior Vice President and Chief Financial Officer (Principal financial officer and Principal accounting officer)
Robert L. Kees
/s/ J. WILLIAM ANDREW, JR.	Director
J. William Andrew, Jr.
/s/ M. JOHNSON BOWMAN	Director
M. Johnson Bowman
/s/ M DALE BRADSHAW	Director
M Dale Bradshaw
/s/ VERNON N. BRINKLEY	Director
Vernon N. Brinkley
/s/ CALVIN P. CARTER	Director
Calvin P. Carter
/s/ GLENN F. CHAPPELL	Director
Glenn F. Chappell

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/s/ KENT D. FARMER	Director
Kent D. Farmer
/s/ STANLEY C. FEUERBERG	Director
Stanley C. Feuerberg
/s/ WILLIAM C. FRAZIER	Director
William C. Frazier
/s/ FRED C. GARBER	Director
Fred C. Garber
/s/ HUNTER R. GREENLAW, JR.	Director
Hunter R. Greenlaw, Jr.
/s/ BRUCE A. HENRY	Director
Bruce A. Henry
/s/ WADE C. HOUSE	Director
Wade C. House
/s/ FREDERICK L. HUBBARD	Director
Frederick L. Hubbard
/s/ DAVID J. JONES	Director
David J. Jones
/s/ BRUCE M. KING	Director
Bruce M. King
/s/ WILLIAM M. LEECH, JR.	Director
William M. Leech, Jr.
/s/ M. LARRY LONGSHORE	Director
M. Larry Longshore
/s/ PAUL E. OWEN	Director
Paul E. Owen

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/s/ JAMES M. REYNOLDS	Director
James M. Reynolds
/s/ MYRON D. RUMMEL	Director
Myron D. Rummel
/s/ PHILIP B. TANKARD	Director
Philip B. Tankard
/s/ GREGORY W. WHITE	Director
Gregory W. White
/s/ CARL R. WIDDOWSON	Director
Carl R. Widdowson

101