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Table of Contents

 

 

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, 2010

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

Note – Checking the box above will not relieve any registrant required to file reports pursuant to Section 13 of 15(d) of the Exchange Act from their obligations under those Sections.

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 whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files).    Yes  ¨    No  ¨

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

Indicate by check mark whether the Registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, or a smaller reporting company. See the definitions of “large accelerated filer,” “accelerated filer” and “smaller reporting company” in Rule 12b-2 of the Exchange Act.

 

Large accelerated filer   ¨    Accelerated filer   ¨
Non-accelerated filer   x    Smaller reporting company   ¨

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

 

 

 


Table of Contents

OLD DOMINION ELECTRIC COOPERATIVE

2010 ANNUAL REPORT ON FORM 10-K

 

Item

Number

   Page
Number
 
     PART I       

   1.

   Business      1   

1A.

   Risk Factors      14   

1B.

   Unresolved Staff Comments      18   

   2.

   Properties      19   

   3.

   Legal Proceedings      21   

   4.

   Reserved      21   
   PART II   

   5.

   Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities      22   

   6.

   Selected Financial Data      22   

   7.

   Management’s Discussion and Analysis of Financial Condition and Results of Operations      24   

7A.

   Quantitative and Qualitative Disclosures About Market Risk      43   

   8.

   Financial Statements and Supplementary Data      46   

   9.

   Changes in and Disagreements with Accountants on Accounting and Financial Disclosure      72   

9A.

   Controls and Procedures      73   

9B.

   Other Information      73   
   PART III   

 10.

   Directors, Executive Officers and Corporate Governance      74   

 11.

   Executive Compensation      77   

 12.

   Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters      84   

 13.

   Certain Relationships and Related Transactions, and Director Independence      84   

 14.

   Principal Accountant Fees and Services      84   
   PART IV   

 15.

   Exhibits and Financial Statement Schedules      85   
   SIGNATURES   


Table of Contents

PART I

ITEM 1. BUSINESS

OVERVIEW

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 are organized for the purpose of supplying the power our member distribution cooperatives require to serve their customers on a cost-effective basis. We serve their power requirements pursuant to long-term, all-requirements wholesale power contracts. Through our member distribution cooperatives, we served more than 540,000 retail electric consumers (meters), representing a total population of approximately 1.2 million people in 2010.

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 customer-owned electric distribution cooperatives that are engaged in the retail sale of power to their member-consumers. Our sole Class B member is TEC Trading, Inc. (“TEC”), a taxable corporation owned by our member distribution cooperatives. 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.

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.

We are not a party to any collective bargaining agreement. We had 107 employees as of March 3, 2011.

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.

We are a power supply cooperative. 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.

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. Electric distribution cooperatives own and operate electric distribution systems to supply the power requirements of their retail customers.


Table of Contents

MEMBERS

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. We have eleven member distribution cooperatives that serve customers in 69 counties in Virginia, Delaware, and Maryland. The member distribution cooperatives’ distribution business involves the operation of substations, transformers, and electric lines that deliver power to customers.

Eight of our member distribution cooperatives provide electric services on the Virginia mainland:

BARC Electric Cooperative

Community Electric Cooperative

Mecklenburg Electric Cooperative

Northern Neck Electric Cooperative

Prince George Electric Cooperative

Rappahannock Electric Cooperative

Shenandoah Valley Electric Cooperative

Southside Electric Cooperative

Three of our member distribution cooperatives provide electric services on the Delmarva Peninsula:

A&N Electric Cooperative in Virginia

Choptank Electric Cooperative, Inc. in Maryland

Delaware Electric Cooperative, Inc. in Delaware

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

Revenues from our member distribution cooperatives and the percentage each contributed to total member distribution cooperative revenues in 2010 are as follows:

 

Member Distribution Cooperatives

   Revenues      Total
Revenues
 
     (in millions)      (%)  

Rappahannock Electric Cooperative

   $ 245.4         31.5

Shenandoah Valley Electric Cooperative

     123.2         15.8   

Delaware Electric Cooperative, Inc.

     100.0         12.8   

Choptank Electric Cooperative, Inc.

     77.5         10.0   

Southside Electric Cooperative

     68.7         8.8   

A&N Electric Cooperative

     51.0         6.5   

Mecklenburg Electric Cooperative

     42.0         5.4   

Prince George Electric Cooperative

     22.7         2.9   

Northern Neck Electric Cooperative

     20.9         2.7   

Community Electric Cooperative

     15.4         2.0   

BARC Electric Cooperative

     12.3         1.6   
                 

Total

   $ 779.1         100.0
                 

 

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Service Territories and Customers

The territories served by our member distribution cooperatives cover large portions of Virginia, Delaware, and Maryland. These service territories range from the extended suburbs of Washington, D.C. to the Atlantic shores of Virginia, Delaware and Maryland, and to the Appalachian Mountains and the North Carolina border.

Our member distribution cooperatives’ service territories are diverse and encompass primarily suburban, rural and recreational areas. 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, telecommunications, poultry, fisheries, agriculture, forestry and wood products, paper, travel, and trade.

On June 1, 2010, two of our member distribution cooperatives, Rappahannock Electric Cooperative (“REC”) and Shenandoah Valley Electric Cooperative (“SVEC”), acquired the distribution assets and right to provide electric distribution services to approximately 102,000 customers (meters) previously owned by The Potomac Edison Company in Virginia (“Potomac Edison”). On December 31, 2010, SVEC sold the distribution assets and right to provide electric distribution services to approximately 2,500 customers (meters) in West Virginia. We estimate that in the aggregate REC’s and SVEC’s acquisitions net of the disposition discussed above will increase our megawatt hour (“MWh”) and megawatt (“MW”) sales to our member distribution cooperatives by approximately 35% to 40% on an annualized basis. In accordance with the wholesale power contracts between ODEC and its member distribution cooperatives, ODEC will serve the additional power requirements resulting from REC’s and SVEC’s acquisitions.

Our member distribution cooperatives’ sales of energy in 2010 totaled approximately 11,487,834 MWh. These sales were divided by type as follows:

 

Customer Class

   Percentage of
MWh Sales
    Percentage of
Customers
 

Residential

     58.9     90.2

Commercial and industrial

     39.8        8.7   

Other

     1.3        1.1   

From 2005 through 2010, our eleven member distribution cooperatives experienced an average annual compound growth rate of approximately 5.1% in the number of customers and an average annual compound growth rate of 8.3% in energy sales measured in MWh. Our member distribution cooperatives’ service territories continue to experience modest 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; however recent economic trends could affect the level of growth. Additionally, our member distribution cooperatives can expand their service territories through acquisition. Excluding our member distribution cooperatives’ acquisitions and disposition discussed above, we estimate that our eleven member distribution cooperatives experienced an average annual compound grown rate of approximately 3.0% in the number of customers as well as energy sales measured in MWh.

Our eleven member distribution cooperatives’ average number of customers per mile of energized line has increased approximately 12.2% since 2005 to approximately 9.0 customers per mile in 2010. System densities of our member distribution cooperatives in 2010 ranged from 6.2 customers per mile in the service territory of BARC Electric Cooperative to 14.5 customers per mile in the service territory of A&N. Excluding our member distribution cooperatives’ acquisitions and disposition discussed above, we estimate the average number of customers per mile of energized line would have increased approximately 6.4% since 2005 to approximately 8.5 customers per mile in 2010. In 2010, the average service density for all distribution electric cooperatives in the United States was approximately 7.0 customers per mile.

 

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Delaware and Maryland each currently grant all retail customers the right to choose their power supplier. Virginia currently grants only a limited number of very large retail customers the right to choose their power suppliers and only in very limited circumstances. The laws of each state grant utilities, including our member distribution cooperatives, the exclusive right to provide transmission and distribution (including metering and billing) services and to be the default providers of power to their customers in service territories certified by their respective state public service commissions. See “—Regulation” and “—Competition” below.

Wholesale Power Contracts

Our financial relationships with our member distribution cooperatives are based primarily on our contractual arrangements for the supply of power and related transmission and ancillary services. These arrangements are set forth in our wholesale power contracts with our member distribution cooperatives which are effective until January 1, 2054 and beyond this date unless either party gives the other at least three years notice of termination. The wholesale power contracts are “all-requirements” 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.

The two principal exceptions to the all-requirements obligations of the member distribution cooperatives relate to the ability of our mainland Virginia member distribution cooperatives to purchase hydroelectric power allocated to them from the Southeastern Power Administration (“SEPA”), and the ability of all member distribution cooperatives to purchase energy from specified qualifying facilities under the Public Utility Regulatory Policies Act or similar laws. Purchases under these exceptions constituted approximately 2.0% of our member distribution cooperatives’ total energy requirements and approximately 2.7% of our member distribution cooperatives total capacity requirements in 2010.

Two additional limited exceptions to the all-requirements nature of the contract permit the member distribution cooperatives to receive up to the greater of five percent of their power requirements or five megawatts from owned generation or other suppliers, and to purchase additional power from other suppliers in limited circumstances following approval by our board of directors. Currently, none of our member distribution cooperatives have received any of their power requirements under these exceptions.

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, services provided to the member distribution cooperatives, and the acquisition and transmission of power or related services, 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);

 

   

any additional cost or expense, imposed or permitted by any regulatory agency; and

 

   

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.

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.

 

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Regulation

Of our 11 member distribution cooperatives, ten member distribution cooperatives participate in the U.S. Department of Agriculture Rural Utilities Service (“RUS”) loan or guarantee programs. Through provisions in the loan documents securing loans to these member distribution cooperatives, RUS exercises control and supervision over these member distribution cooperatives, including areas such as accounting, issuances of securities, rates and charges for the sale of power, construction or acquisition of facilities and the purchase and sale of power. Financial covenants in these member distribution cooperatives’ loan documents require them to design rates to achieve a specified times interest earned ratio and debt service coverage ratio.

Our member distribution cooperatives in Virginia are subject to rate regulation by the Virginia State Corporation Commission (“VSCC”) in the provision of electric services to their customers but they have the ability to pass through changes in wholesale power costs – what we charge our member distribution cooperatives – to their customers. Our Virginia member distribution cooperatives also may adjust their distribution rates by a maximum net increase or decrease of 5%, on a cumulative basis, in any three year period without filing a rate case with the VSCC.

The Maryland Public Service Commission (“Maryland PSC”) regulates the rates and services offered by our Maryland member distribution cooperative. Our Delaware member distribution cooperative is not regulated by the Delaware Public Service Commission (“Delaware PSC”). Our Maryland and Delaware member distribution cooperatives have the ability to pass through changes in wholesale power costs – what we charge our member distribution cooperatives – to their customers.

Competition

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 Delaware and Maryland, including retail customers of our member distribution cooperatives located in those states, are currently permitted to purchase power from the registered supplier of their choice. In Virginia, certain large retail customers have very limited rights to choose their energy suppliers. As of March 1, 2011, 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.

In Virginia, retail choice in the selection of a power supplier is only available to customers that consume at least five megawatts of power individually or in the aggregate (with aggregation subject to the approval of the VSCC), but that do not account for more than 1% of the incumbent utility’s peak load during the past year. Retail choice is also available to any customer whose 2006, or any subsequent year’s, noncoincident peak demand exceeded 90 megawatts. Additionally, all customers are permitted to select a supplier that provides 100% green or renewable power if their incumbent utility does not offer this same option. Currently, we do not anticipate that these conditions related to retail choice will have a material impact on our financial results.

TEC

TEC is owned by our member distribution cooperatives, and currently is our only Class B member. 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 and sells this power to the market under market-based rate authority granted by FERC. TEC also acquires natural gas and forward purchase contracts to hedge the price of natural gas to supply our combustion turbine facilities, and takes advantage of other power-related trading opportunities in the market which may help lower our member distribution cooperatives’ costs. TEC does not engage in speculative trading. To facilitate TEC’s participation in the power related markets, we have agreed to provide a maximum of $100.0 million in credit support to TEC. See “Item 7 Management’s Discussion and Analysis of Financial Condition and Results of Operations—Significant Contingent Obligations—TEC Guarantees.”

 

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New Dominion

In 2004, we entered into a reorganization agreement with our member distribution cooperatives, TEC and a newly formed taxable power supply cooperative, New Dominion Energy Cooperative (“New Dominion”). Structurally, the reorganization would result in all of our member distribution cooperatives exchanging their membership interests in ODEC for a membership interest in New Dominion. We received all necessary regulatory approvals for the reorganization contemplated by the reorganization agreement in 2008. We have evaluated whether the reorganization previously contemplated is in our best interests and the best interests of our member distribution cooperatives based on current conditions. Based on our current evaluation, we have decided not to actively pursue implementation of the reorganization at this time. As conditions change, we may reconsider this decision.

POWER SUPPLY RESOURCES

General

We provide power to our members through a combination of our interests in the Clover Power Station (“Clover”), a coal-fired generating facility; the North Anna Nuclear Power Station (“North Anna”); our three combustion turbine facilities - Louisa, Marsh Run, and Rock Springs; distributed generation facilities; and 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:

 

     Year Ended December 31,  
     2010     2009     2008  
     (in MWh and percentages)  

Generated:

               

Clover

     3,092,662         24.3     2,787,184         28.4     2,901,401         21.5

North Anna

     1,554,338         12.2        1,763,502         18.0        1,674,278         12.4   

Louisa

     382,211         3.0        93,125         0.9        153,170         1.1   

Marsh Run

     624,951         4.9        99,842         1.0        152,258         1.1   

Rock Springs

     193,498         1.5        29,906         0.3        55,045         0.4   

Distributed Generation

     897         —          457         —          286         —     
                                                   

Total Generated

     5,848,557         45.9        4,774,016         48.6        4,936,438         36.5   

Purchased:

               

Other than renewable

     6,692,647         52.5        5,019,808         51.2        8,565,802         63.4   

Renewable

     210,702         1.6        21,393         0.2        14,308         0.1   
                                                   

Total Purchased

     6,903,349         54.1        5,041,201         51.4        8,580,110         63.5   
                                                   

Total Available Energy

     12,751,906         100.0     9,815,217         100.0     13,516,548         100.0
                                                   

In 2010, our member distribution cooperatives’ peak demand occurred in July and was 2,635 MW, excluding power supplied by SEPA which is not an ODEC resource. See “—Wholesale Power Contracts.” We anticipate that our member distribution cooperatives’ peak demand will occur during the winter in future years due to the consumption patterns of the customers served by our member distribution cooperatives.

Clover and North Anna, our baseload generating facilities, satisfied approximately 27.1% of our capacity obligations and 36.5% of our energy requirements in 2010. Louisa, Marsh Run and Rock Springs, our peaking generating facilities, collectively provided 49.6% of our 2010 capacity obligations, and 9.4% of our 2010 energy requirements. For a description of our generating facilities, see “Properties” in Item 2. In 2010, we obtained the remainder of our capacity obligations through the PJM Interconnection, LLC (“PJM”) reliability pricing model (“RPM”) capacity auction process. See “—PJM” below. The energy requirements not met by our owned generation facilities were obtained from various suppliers under various long-term and short-term physically-delivered forward power purchase contracts and spot market purchases. See “—Power Purchase Contracts” below.

We plan to continue purchasing energy for significant periods into the future by utilizing a combination of physically-delivered forward power purchase contracts for the purchase of energy, as well as spot market purchases. 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. To assist us in these efforts, we continue to engage the Alliance for Cooperative Energy Services Power Marketing LLC (“ACES”), an energy trading and risk management company.

 

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Specifically, ACES assists us in negotiating power purchase contracts, evaluating the credit risk of counterparties, modeling our power requirements, bidding and dispatch of our combustion turbine facilities, and executing energy transactions. See “Quantitative and Qualitative Disclosures About Market Risk” in Item 7A.

Power Supply Planning

We continually evaluate power supply options available to us to meet the needs of our member distribution cooperatives. We have policies that establish goals for how our projected power needs will be met and one of the ways we manage these goals is the utilization of hedging. We use hedging instruments, including forwards, futures, financial transmission rights, and options, to manage our power market price risks. These hedging instruments have varying time periods ranging from one month to multiple years in advance. Additionally, we evaluate other power supply options including the acquisition or development of additional facilities.

In 2007, we filed a joint application with Virginia Electric and Power Company (“Virginia Power”) at the Nuclear Regulatory Commission (“NRC”) for a license to construct and operate a new reactor at North Anna. In October 2010, Virginia Power announced that it will slow down its pursuit of an additional nuclear-powered generating unit at North Anna and plans to reassess the schedule for construction of the unit in 2013. We have evaluated our continued participation in this project and on February 28, 2011, we announced that we have decided not to participate in the development or ownership of an additional nuclear-powered generating unit at North Anna. We are currently working with Virginia Power on the logistics of our withdrawal as a participant in the project.

In addition, we continue to separately evaluate the possibility of constructing a new baseload generation facility. In 2010, we purchased two tracts of land in Virginia for potential development; one tract is in the town of Dendron in Surry County and the other is in Sussex County. In February 2010, we received the necessary zoning approvals for both tracts for siting of a power plant and approval to proceed with the attainment of required air and other environmental permits. In the fall of 2010, we announced that due to the economy and uncertainty related to energy and environmental policies, we have extended the timeline for securing the necessary air permits to begin construction. In March 2010, several residents of Surry County filed a Complaint for Declaratory and Injunctive Relief with the Surry County Circuit Court, requesting that the court void the zoning approvals granted based on their claim of inadequate notice of a public hearing. We are currently awaiting a hearing schedule.

We anticipate that the power station would be fueled by a mixture of coal and biomass, a form of renewable energy. We have not selected the technology, the final site or determined the size of any facility that may be built. We have not made final commitments to proceed with the construction of a facility. See “—Regulation—Environmental—Proposed Construction of Generation Facility”.

PJM

PJM is a regional transmission organization (“RTO”) that coordinates the movement of wholesale electricity in all or parts of 13 states and the District of Columbia. As a federally regulated RTO, PJM must act independently and impartially in managing the regional transmission system and the wholesale electricity market. PJM ensures the reliability of the largest centrally dispatched grid in North America. PJM coordinates the continuous buying, selling and delivery of wholesale electricity over its service territory. PJM system operators continuously conduct dispatch operations and monitor the status of the grid. PJM also oversees a regional planning process for transmission expansion to ensure the continued reliability of the electric system.

PJM serves all of Delaware, Maryland, and most of Virginia, as well as other areas outside our member distribution cooperatives’ service territories. We are a member of PJM and are therefore subject to the operations of PJM. PJM also coordinates and establishes policies for the generation, purchase and sale of capacity and energy in the control areas of its members, including all of the service territories of our member distribution cooperatives. As a result, our generating facilities are under dispatch control of PJM.

We transmit power to our member distribution cooperatives through the transmission systems of PJM–South Region, PJM–West Region, and PJM–East 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 limited amount of transmission facilities. See “Properties—Transmission” in Item 2.

 

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PJM 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 generation facilities in a manner intended to meet the demand for energy in the most reliable and cost-effective manner. Thus, PJM directs the dispatch of these facilities even though it does not own them. When PJM cannot dispatch available generating facilities due to transmission constraints, PJM will dispatch more expensive generating facilities to meet the required 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 conducts the auction of financial transmission rights for future periods to provide market participants an opportunity to hedge these congestion costs.

The PJM energy market consists of day-ahead and real-time markets. PJM’s day-ahead market is a forward market in which hourly locational marginal prices are calculated for the following day based on the prices at which the owners of generating facilities, including ODEC, offer to run their facilities and the requirements of energy consumers. PJM’s real-time market is a spot market in which current locational marginal prices are calculated at five-minute intervals.

PJM rules require that load serving entities meet certain minimum generating capacity obligations. Additional capacity must be purchased for capacity obligations that are not met by an entity’s owned generation resources. Participants can procure capacity through self-supply, bilateral agreements or forward capacity auctions under PJM’s RPM. The purpose of RPM is to develop a longer-term pricing program for capacity resources, as well as provide localized pricing for capacity, and to reduce capacity price volatility and the resulting investment risk to generators thus encouraging new investment in generation facilities. The value of capacity resources varies by location and RPM provides for the recognition of the locational value. To date, PJM has conducted RPM auctions for capacity to be supplied through May 31, 2014. Each annual auction will be held 36 months before each subsequent delivery year, and up to three incremental auctions may be held at prescribed dates after the base residual auction for each delivery year to adjust for capacity market dynamics.

Power Purchase Contracts

Our purchased power is provided principally by investor-owned utilities and power marketers through physically-delivered power purchase contracts and purchases of energy in the spot markets.

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 and various hedging instruments to manage the risks in the changing business environment. These policies and procedures, developed in cooperation with ACES, are designed to strike an appropriate balance between minimizing costs and reducing energy cost volatility.

We have contractual arrangements with Virginia Power, the operator and co-owner of Clover and North Anna, which permit us to purchase reserve capacity and energy. These arrangements allow for the purchase of our reserve capacity requirements for Clover and North Anna from Virginia Power under these arrangements until 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.

In October 2009, we signed a long-term power purchase agreement with Exelon Generation Company, LLC (“Exelon”). Under the terms of this agreement, Exelon is supplying 200 MW of energy and capacity to us for ten years beginning in June 2010.

 

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Renewable Energy

Our power supply resources include renewable energy resources through power purchase contracts. We have three long-term agreements for wind generated power under which we purchase power and renewable energy credits. Two of these wind generated power projects are located in Pennsylvania and one is in Maryland. Additionally, we have renewable resources through energy purchase contracts from three landfill gas-to-energy projects. Two are currently operational; one is located in Worchester County, Maryland and the other is located in Sussex County, Delaware. The third landfill gas-to-energy project is scheduled to be operational in 2011 and is located near Richmond, Virginia. We also purchase renewable resources through an energy purchase contract for a hydroelectric facility located in Alleghany County, Virginia. These contracts allow us to buy output from the renewable facilities at a predetermined price. We do not operate these facilities and are not responsible for the operational costs.

Fuel Supply

Coal

Virginia Power, as operating agent of Clover, has the sole authority and responsibility to procure sufficient coal for the operation of the facility. Virginia Power advises us they use both long-term contracts and short-term spot agreements from both domestic and international suppliers to acquire the low sulfur bituminous coal used to fuel the facility. We are not a direct party to any of these procurement contracts, and do not control their terms or duration. As of December 31, 2010, and December 31, 2009, there was a 38.0 day and a 92.0 day supply of coal at Clover, respectively. In 2009, both units at Clover were scheduled for longer outages resulting in reduced consumption of coal and an increase in the inventory balance. We anticipate that sufficient supplies of coal will be available in the future. See “Quantitative and Qualitative Disclosures About Market Risk” in Item 7A.

Nuclear

Virginia Power, as operating agent of North Anna, has the sole authority and responsibility to procure nuclear fuel for the facility. Virginia Power advises us they primarily use 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 do not control their terms or duration. Virginia Power advises us that current agreements, inventories, and spot market availability are expected to support North Anna’s current and planned fuel supply needs for the near term and that additional fuel is purchased as required to attempt to ensure optimal cost and inventory levels.

Under the Nuclear Waste Policy Act of 1982, the Department of Energy (“DOE”) is required to provide for the permanent disposal of spent nuclear fuel produced by nuclear facilities, such as North Anna, in accordance with contracts executed with the DOE. The DOE did not begin accepting spent fuel in 1998 as specified in its contract. Virginia Power is providing on-site spent nuclear fuel storage at the North Anna facility. Virginia Power will continue to manage North Anna’s spent nuclear fuel until the DOE begins accepting the spent nuclear fuel. In 2004, Virginia Power filed a lawsuit seeking recovery of damages in connection with the DOE’s failure to commence accepting spent nuclear fuel from North Anna. A subsequent trial held in 2008 ruled in favor of Virginia Power and the DOE filed an appeal. In March 2009, the U.S. Court of Appeals for the Federal Circuit granted the DOE’s request to stay the appeal. In November 2009, Virginia Power filed a motion to lift the stay and the DOE has opposed this motion. In May 2010, the stay was lifted, and the government’s initial brief in the appeal was filed in June 2010. Briefing on the appeal was concluded in September 2010 and oral arguments took place before the U.S. Court of Appeals for the Federal Circuit in January 2011.

Natural Gas

Our three combustion turbine facilities are powered by natural gas and are located adjacent to natural gas transmission lines. With assistance from ACES, 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

 

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gas to be used by all of our 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 natural gas pipeline 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 anticipate that sufficient supplies of natural gas will be available in the future to support the operation of our combustion turbine facilities 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 Maryland Department of the Environment, the DOE, the 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.

Rate Regulation

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.

Because our rates and services are regulated by FERC, the VSCC, the Delaware PSC, and the Maryland PSC do not have jurisdiction over our rates and services.

Other 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 under FERC jurisdiction. Under FERC regulations, we are prohibited from selling, leasing, or otherwise disposing of the whole of our facilities subject to FERC jurisdiction, or any part of such facilities having a value in excess of $10.0 million without FERC approval. We are also required to seek FERC approval prior to merging or consolidating our facilities with those of any other entity having a value in excess of $10.0 million.

The VSCC, the Delaware PSC, and the Maryland PSC oversee the siting of our utility facilities in their respective jurisdictions.

Environmental

We are subject to federal, state, and local laws and regulations and permits designed to both protect human health and the environment and to 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. However, as with all electric utilities, the operation of our generating units could be affected by future environmental regulations. Capital expenditures and increased operating costs required to comply with any future regulations could be significant. See “Risk Factors” in Item 1A. below. Our direct capital expenditures for environmental control equipment at our generating facilities were immaterial in 2010.

 

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Clean Air Regulations

The most pertinent 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”), particulate matter (“PM”), mercury (“Hg”), and nitrogen oxides (“NOx”). Additionally, regulatory programs and/or taxes are being proposed to limit emissions of carbon dioxide (“CO2”) and other greenhouse gases (“GHG”.)

The Clean Air Interstate Rule (“CAIR”) requires significant reductions of SO2 and NOx in the eastern United States, including Virginia and Maryland. In 2008, the U.S. Court of Appeals for the District of Columbia Circuit vacated CAIR and later remanded CAIR for correction instead. The court did not set a deadline for the Environmental Protection Agency (“EPA”) to make the corrections.

On July 6, 2010, the EPA proposed the “Transport Rule” that would require 31 states and the District of Columbia to significantly improve air quality by reducing power plant SO2 and NOx emissions that contribute to ozone and fine particle pollution in other states. Emissions reductions would begin to take effect in 2012. By 2014, the Transport Rule and other state and EPA actions would reduce power plant SO2 emissions by 71% over 2005 levels. Based upon the revised ozone standards that are expected to be issued in 2011, the EPA has stated that there will be revisions to the Transport Rule in 2012. There is still much continuing comment and debate about the allocation methodologies and we cannot quantify the full impact that this regulation will have on existing operations or new generation.

The DEQ adopted the CAIR implementation regulations in 2007. Virginia and Maryland participate in the federal SO2 cap and trade program established by CAIR for SO2 emissions. This program is similar, but is in addition to the Acid Rain Program. There are two phases and Phase I requires all of our facilities in Virginia to acquire adequate allowances for each ton of SO2 they emit beginning in 2010. Phase II begins in 2014 and will also require adequate allowances for each ton of SO2 emissions due to the increase in the ratio between what is emitted and the number of allowances required to cover the emissions in Phase II. We are entitled to sufficient SO2 allowances because of our interest in Clover and we do not anticipate needing to purchase additional SO2 allowances for our Louisa, Marsh Run and Rock Springs generating facilities through both phases of CAIR.

Pursuant to the Clean Air Act and CAIR, both Virginia and Maryland have enacted regulations to reduce the emissions of NOx by establishing NOx cap and trade programs similar to the federal SO2 allowance programs. Both the Clean Air Act and CAIR will meet the more stringent NOx emission caps established under CAIR, and with respect to the facilities in Virginia, additional NOx emission reductions mandated by Virginia. Under CAIR, allowances are required for annual NOx emissions (“CAIRNOx” allowances) and ozone season NOx emissions (“CAIROS” allowances). Clover is allocated a certain number of CAIRNOx and CAIROS allowances. If Clover emits more NOx emissions than the allotted allowances cover then additional CAIRNOx and CAIROS emissions allowances will have to be purchased. We can purchase CAIROS allowances from Virginia Power under an existing agreement or purchase them from the market.

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 is included in the Acid Rain Program budget and receives an annual allocation of SO2 allowances at no cost based upon its baseline operations. Newer facilities, including Louisa, Marsh Run and Rock Springs, need to obtain allowances; however, because they are primarily gas-fired, the number of SO2 allowances they must obtain is typically minimal and can be supplied from excess SO2 allowances allocated to Clover.

Louisa, Marsh Run, and Rock Springs each produce NOx emissions and all three sites have been allocated CAIRNOx and CAIROS allowances under CAIR. The CAIRNOx and CAIROS allowances currently received are expected to cover the facilities emissions. If these allowances are not sufficient to cover the NOx emissions produced at these facilities, additional allowances will be purchased in the market for the operation of these facilities.

 

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Clear Air Mercury Rule

Clover is currently our only generating facility impacted by the EPA’s Clean Air Mercury Rule (“CAMR”). In 2005, the EPA issued the CAMR which establishes caps for overall mercury emissions from coal-fired power plants. In 2008, the U.S. Court of Appeals for the District of Columbia Circuit vacated the CAMR. The EPA, consistent with the court’s decisions, will be implementing emissions standards based upon the Information Collection Request information, as outlined in the subsequent section.

In 2006, Virginia adopted the cap and trade program proposed in CAMR, subject to certain limitations. The DEQ adopted the Mercury Budget Trading regulations in 2007 which are currently in effect. The 2009 U.S. Court of Appeals decision vacating CAMR does not affect the DEQ’s adoption of the Mercury Budget Trading regulations; however, there will not be a cap and trade program if the CAMR ultimately does not go into effect. We do not anticipate that any additional measures will be required at Clover to comply with the DEQ’s Mercury Budget Trading regulations due to Clover’s existing pollution control requirement, which already removes greater than 90% of the mercury emitted from the facility.

Greenhouse Gas Initiative

In late 2009, the EPA finalized the Endangerment Finding, which obligated the agency to issue GHG standards for motor vehicles. The implementation of vehicle standards made GHG emissions subject to regulation under the Clean Air Act for the first time. Subsequently, any air pollutants subject to regulation under the Clean Air Act must now be addressed under the New Source Review Prevention of Significant Deterioration and the Title V Operating Permit programs.

Based upon an effective date of January 2, 2011 for GHG standards for light-duty vehicles, the EPA has put forth rulemaking to implement the Clean Air Act permitting programs for affected stationary sources of GHG emissions. On May 13, 2010, the EPA issued the “Tailoring Rule” to address GHG emissions from stationary sources under the Clean Air Act permitting programs. The final rule set thresholds for GHG emissions that define when permits under the New Source Review Prevention of Significant Deterioration and Title V Operating Permit programs are required for new and existing industrial facilities. On December 23, 2010, the EPA issued a series of rules that provide the necessary regulatory framework for permitting of both new and existing large stationary sources. These rules significantly affect fossil fuel-fired electric generating facilities. This will have a significant effect on the renewal of Title V Operating Permits for Clover, Louisa, Marsh Run, and Rock Springs, as well as permitting of any new fossil generation by ODEC.

Also, there are numerous actions at the state and regional level, including the Regional Greenhouse Gas Initiative (“RGGI”). RGGI provides for a cap and trade program to regulate CO2 emissions among certain northeastern and mid-Atlantic states, including Delaware and Maryland, capping emissions at current levels in 2009, and then reducing emissions 10% by 2019. CO2 emissions from Rock Springs require us to purchase emissions allowances for the first compliance period of 2009 through 2011. The regulations require all allowances to be auctioned rather than allocated directly to utilities.

Revised National Ambient Air Quality Standards

On January 6, 2010, the EPA proposed to reconsider the eight hour primary ozone standard based upon additional scientific evidence. The current standard is 75 parts per billion, with the information suggesting that EPA would be considering lowering that standard. In December 2010, the EPA delayed the final rulemaking with the intent of continuing to review scientific information and recommendations from the Clean Air Scientific Advisory Committee and finalizing a new standard in late 2011. We have been monitoring this very closely and expect that this change should not significantly affect ODEC’s current operations, but may impact permitting of new generation depending upon location.

 

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Additionally, in June of 2010, EPA finalized the one hour SO2 standard. It is yet to be determined the full extent of this standard, however, it is expected to have an effect on the permitting of any new facility particularly fossil fuel fired generation. The EPA has also set a schedule in 2011 for revision of this standard as well. There is currently not enough information to determine the potential impact on ODEC operations.

Proposed Construction of Generation Facility

We are continuing to evaluate the feasibility of constructing a power station, which we anticipate would be fueled by a mixture of coal and biomass, a form of renewable energy, in either Surry or Sussex County, Virginia. See “—Power Supply Resources—Power Supply Planning” above. If constructed as currently contemplated, all of the environmental regulations applicable to Clover would also apply to this facility. However, no SO2 or NOx allowances would be allocated to this facility. Under the proposed Transport Rule, it is expected that we would have some excess SO2 allowances that could be used at a new facility if constructed, and if there were not sufficient allowances available in the set-aside pool, any shortfall would have to be purchased from the market. Due to the significant reductions proposed, under the Transport Rule, we have yet to determine the availability of additional NOx allowances that would be available.

Additionally, revisions to National Ambient Air Quality Standards (“NAAQS”) for certain areas of Virginia could have an impact on the overall permitting of a new fossil fuel-fired facility and we continue to monitor this issue.

In late 2010, the EPA established a total maximum daily load (“TMDL”) for the Chesapeake Bay which identifies the necessary reductions of nitrogen, phosphorus and sediment from Delaware, Maryland, New York, Pennsylvania, Virginia, West Virginia and the District of Columbia. Process water for the proposed facility would be withdrawn from the James River, and would be treated and discharged into the James River, which is covered under the requirements of the TMDL. Though we do not anticipate a great effect from direct discharge of our treated process water into the James, there is concern that the EPA may eventually target nitrogen deposition from air emissions sources within the context of this TMDL.

Clean Water Act

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. EPA has decided to revise the federal effluent guidelines for water discharges at power plants. In doing so, the agency is increasing its data-gathering efforts to better characterize steam-electric generating facilities.

On June 21, 2010, the EPA formally proposed to regulate coal combustion residuals (“CCRs”) under the Resource Conservation and Recovery Act (“RCRA”) to address the risks from disposals of CCRs generated by coal combustion at electric generating facilities. CCR, also commonly referred to as “coal ash,” is currently considered an exempt waste under an amendment to RCRA. The EPA is currently considering two options for regulating CCRs. Under Option 1, the EPA would list CCR’s as a special waste under Subtitle C of RCRA when destined for disposal in landfills or impoundments which would effectively result in CCRs being treated as a listed “hazardous” waste. Under Option 2, CCR’s would be regulated under subtitle D of RCRA as solid waste. Under Option 1 the difficulty in obtaining hazardous treatment, storage, and disposal permits and the lack of current access to, and availability of, properly permitted off-site landfills could cause ODEC to incur significant additional costs.

Information Collection Request

In 2009, the EPA sent Clover an information collection request for hazardous air pollutants. This information is being collected by the EPA’s Office of Air and Radiation to assist the EPA Administrator in developing Maximum Achievable Control Technology emission standards for fossil fuel-fired power plants of 25 megawatts or greater. Clover conducted stack testing and fuel analyses and submitted the information to the EPA during 2010. It is currently anticipated that the EPA will announce the emission standards in 2011.

 

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Future Regulation

New legislative and regulatory proposals are frequently introduced on both a federal and state level that would modify the environmental regulatory programs applicable to our facilities. An example is the control of CO2 and other GHGs 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.

ITEM 1A. – RISK FACTORS

RISK FACTORS

The following risk factors and all other information contained in this report should be considered carefully when evaluating ODEC. These risk factors could affect our actual results and cause these results to differ materially from those expressed in any forward-looking statements of ODEC. 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, including “Caution Regarding Forward Looking Statements.”

We rely substantially on purchases of energy from other power suppliers which exposes us to market price risk and credit risk.

We supply our member distribution cooperatives with all of their power (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 2010, we purchased approximately 54.1% of our energy resources. These purchases consisted of a combination of purchases under physically-delivered forward contracts and purchases of energy in the spot market. Our reliance on purchases of energy from other suppliers will continue well into the future and likely will increase after 2010 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 utilize our judgment and assumptions in our models. These judgments 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 ACES 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 other utilities’ 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 operating costs.

We are subject to changes in fuel costs, which could increase the cost of generating power, as well as changes in purchased power costs. Increases in fuel costs and purchased power costs 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 and purchased power 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;

 

   

Impact of implementation of new technologies in the power industry;

 

   

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

 

   

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

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

We currently 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 in addition to costs related to any costs of compliance with laws or regulations relating to CO2 and other GHG emissions. 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 member distribution cooperatives.

Our financial condition is largely dependent upon our member distribution cooperatives satisfying their obligations under the wholesale power contract that each has executed with us. The wholesale power contracts require our member distribution cooperatives to pay us for power furnished to them in accordance with our FERC formulary rate. 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 2010, 60.1% of our revenues from sales to our member distribution cooperatives were received from our three largest members, Rappahannock Electric Cooperative, Shenandoah Valley Electric Cooperative and Delaware Electric Cooperative, Inc.

 

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Our member distribution cooperatives’ ability to collect their costs from their members may have an impact on our financial condition. Economic conditions may make it difficult for some consumers of our member distribution cooperatives to pay their power bills in a timely manner which may in turn affect the timeliness of our member distribution cooperatives’ payments to us. Although the magnitude or duration of any economic downturn cannot be predicted, the occurrence may negatively affect our results of operations and financial position.

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 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.

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. On an on-going basis we analyze and monitor the default risks of counterparties and other credit issues related to these purchases, and we may require our counterparties to post collateral with us; however, defaults may still occur. Defaults may take the form of failure to physically deliver the purchased energy. If a default 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.

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 our principal security instrument, our Second Amended and Restated Indenture of Mortgage and Deed of Trust, dated as of January 1, 2011, with Branch Banking and Trust Company, as trustee (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 need 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 the lease and leaseback of our undivided interest in Clover Unit 1 and some of our power purchase contracts. See “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 may be materially impaired.

Failure of an investment in a lease of our interest in Clover Unit 1 could reduce investment income currently used to fund the majority of our rental payment obligations.

In conjunction with our 1996 lease and subsequent leaseback of our interest in Clover Unit 1, we purchased an investment that provides for a substantial portion of our periodic rent payments under the leaseback and the fixed purchase price of our interest in Unit 1 at the end of the term of the leaseback, if we exercise our option to purchase the interest at that time. The investment, which had a balance of $311.5 million at December 31, 2010, was issued by Cooperative Centrale Raiffeisen Boerenleenbank B.A., “Rabobank Nederland” (“Rabobank”), which has senior debt obligations which are currently rated “AAA” by S&P and “Aaa” by Moody’s. If this entity fails to make disbursements from the investment, we remain liable for all rental payments under the leaseback and the fixed purchase price if we choose to exercise that option. At December 31, 2010, the total balance of our remaining lease obligation was $346.1 million. See “Significant Contingent Obligations – Clover Lease” in Item 7.

 

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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 12.2% of our energy requirements in 2010. 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;

 

   

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 the 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. North Anna’s operating and safety procedures may be subject to additional federal or state regulatory scrutiny as a result of current world-wide events related to nuclear 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 energy either from Virginia Power or the market. See “Power Supply Resources—Power Purchase Contracts.”

NERC Compliance.

As a result of the Energy Policy Act 2005 (“EPACT”), owners, operators and users of bulk electric systems, including ODEC, are subject to mandatory reliability standards enacted by the North American Electric Reliability Corporation (“NERC”) and its regional entities and enforced by FERC. We must follow these standards, which are in place to require that proper functions are performed to ensure the reliability of the bulk power system. Although the standards are developed by the NERC Standards Committee, which includes representatives of various electric energy sectors, and must be just and reasonable, the standards are legally binding and compliance may require increased capital expenditures and costs to provide electricity to our member distribution cooperatives under our wholesale power contracts. If we are found to be in non-compliance with any mandatory reliability standards we would be subject to sanctions, including potentially substantial monetary penalties.

Regulation of CO2, other GHG and other climate change related costs may significantly increase our costs and may result in our purchasing additional energy in the market.

Federal and state governmental authorities, prompted by growing concerns relating to the impact of global climate change, have begun to actively pursue legislation that calls for the reduction of emissions of GHG. Recently, legislative proposals have focused on regulation of CO2 emissions. Often, these proposals either tax the emission of CO2 or institute a cap and trade program requiring allowances to emit CO2 in the operation of coal-fired and other fossil fuel generating facilities. Cap and trade proposals vary regarding the extent to which existing generation facilities would be allocated allowances without cost, similar to the regulation of other emissions under the Clean Air Act. Some proposals do not allocate any allowances to existing facilities. Proposals requiring the taxing of CO2 emissions vary widely as to the amount of the tax.

The additional costs related to a tax on CO2 emissions or a cap and trade program could affect the relative cost of the energy generated by our facilities that burn coal and other fossil fuels. Because PJM dispatches facilities from lowest to highest cost, these additional costs may cause our CO2 emitting generating facilities to be dispatched

 

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less often than they are currently. Lower levels of dispatch of these facilities by PJM likely would result in our purchasing more energy, potentially significantly more energy, from the market. The price of the additional energy purchased from the market in the future could be substantially higher than the current cost of the energy generated from our facilities emitting CO2.

Because no federal laws or state laws applicable to us regulating CO2 emissions have become effective, other than the RGGI (see “Business—Regulation—Greenhouse Gas Initiative”), we cannot predict the cost or the effect of any future legislation or regulation. We do believe, however, that some form of federal or state law or regulation in this area is likely to be enacted in the future and could have a material adverse effect on the cost of energy we supply our member distribution cooperatives. The Obama Administration has stated that it is going to pursue regulation of CO2, including a cap and trade program aimed at GHG emissions. The Administration has also proposed a federal renewable portfolio standard (“RPS”) that may require us to produce or procure a significant portion of our energy needs from renewable resources, which may include sources that are more expensive than the costs associated with our existing generating units and market purchases. Because the details of this plan are not fully available, it is difficult for us to predict with any degree of certainty the magnitude of the impact a federal RPS would have on our costs and capital expenditures should this be enacted. Also, there are numerous actions at the state and regional level. New laws or regulations, the revision or reinterpretation of existing laws or regulations, or penalties imposed for non-compliance with existing laws or regulations may require us to incur additional expenses.

Poor market performance will affect our nuclear decommissioning trust asset values and our defined benefit retirement plans, which may increase our costs.

We are required to maintain a funded trust to satisfy our future obligation to decommission the North Anna facility. A decline in the market value of those assets due to poor investment performance or other factors may increase our funding requirements for these obligations which may increase our costs.

We participate in the National Rural Electric Cooperatives Association (“NRECA”) Retirement Security Plan and the pension restoration plan. The cost of these plans is funded by our payments to NRECA. Poor performance of investments in these benefit plans may increase our costs.

Potential changes in accounting practices may adversely affect our financial results.

We cannot predict the impact that future changes in accounting standards or practices may have on public companies in general, the energy industry or our operations specifically. New accounting standards could be issued that could change the way we record revenues, expenses, assets and liabilities. These changes in accounting standards could adversely affect our reported earnings or could increase reported liabilities.

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 limited amount of transmission facilities. All of our physical properties are subject to the lien of our Indenture. Our generating facilities consist of the following:

 

Generating 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 (5)

    
 
 
 
 
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 (5)

    

 

 

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 Unit 1 is subject to a long-term lease. 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.

(5)

The units at this facility also operate on No. 2 distillate fuel oil.

Clover

Virginia Power, 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. ODEC and Virginia Power are each entitled to half of the power produced by Clover. 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 directly attributable to Clover.

Clover Lease

In 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 leaseback of the interest. The interest of the owner trust in Clover Unit 1 is subject and subordinate to the lien of the Indenture. The lease contains events of default, which, if they occur, could result in termination of the lease,

 

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and, consequently, our loss of possession and right to the output of Clover Unit 1. See “Management’s Discussion and Analysis of Financial Condition and Results of Operations—Significant Contingent Obligations—Clover Lease” in Item 7 for a discussion of our options and obligations at the end of the term of the leaseback of Clover Unit 1 and sources of funding for these obligations.

North Anna

Virginia Power, 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. In addition, we separately fund our pro-rata portion of the decommissioning costs of North Anna. ODEC 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 are responsible for the operation and maintenance of Louisa and we supply all services, goods and materials required to operate and maintain 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 are also responsible for the operation and maintenance of Marsh Run and we supply all services, goods and materials required to operate and maintain 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

ODEC and North American Energy Alliance, LLC (“NAEA”) each individually own two units (a total of 336 MWs each) and 50% of the common facilities at Rock Springs. Additionally, ODEC and NAEA each individually bid its respective units into PJM as determined to be necessary and prudent.

Rock Springs is currently operated and maintained by North American Energy Alliance Operating Co., LLC, an affiliate of NAEA, pursuant to a service agreement under which North American Energy Alliance Operating Co., LLC, 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 and supply of the natural gas required by the operator for our units at Rock Springs.

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 approximately 100 miles of transmission lines on the Virginia portion of the Delmarva Peninsula. We also own two 1,100 foot 500 kilovolt (“kV”) transmission lines and a 500 kV substation at Rock Springs jointly with NAEA. As a transmission owner in PJM, we have relinquished control of all of these transmission facilities to PJM and contracted with third parties to operate and maintain them.

Indenture

Following the redemption of $1.0 million of our First Mortgage Bonds, 1993 Series A on January 24, 2011, the Amended and Restated Indenture, dated as of September 1, 2001, became effective and amended and restated our Indenture of Mortgage and Deed of Trust, dated as of May 1, 1992, as previously amended. This previous form of the Indenture, among other things, released the lien of the 1992 Indenture. On January 26, 2011, the previous form of the Indenture again was amended and restated in the form of the Second Amended and Restated Indenture of Mortgage and Deed of Trust, dated as of January 1, 2011, which is referred to herein as “Indenture.” This form of the Indenture reinstated the lien on substantially all of our real property and tangible personal property and some of our intangible personal property in favor of the trustee, with limited exceptions. The obligations outstanding under the Indenture, regardless of the form of the Indenture in effect at the time of the issuance of the obligations, are secured equally and ratably.

ITEM 3. LEGAL PROCEEDINGS

Norfolk Southern

In 2008, we, along with Virginia Power, filed suit against Norfolk Southern Railway Company (“Norfolk Southern”) in the Circuit Court of the City of Richmond, Virginia, seeking to recover approximately $4.9 million, plus interest, for unauthorized fuel surcharges improperly collected by Norfolk Southern under our coal transportation agreement. Our portion of this claim is approximately $2.5 million, excluding interest. We believe that the fuel surcharge conflicts with the payment provisions specified in the agreement. A hearing was held on February 10, 2011, and on March 9, 2011, the court found that the fuel surcharge does not conflict with the payment provisions in the specified agreement. We currently plan to file a motion for reconsideration.

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. RESERVED

 

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PART II

ITEM 5. MARKET FOR REGISTRANT’S COMMON EQUITY,

RELATED STOCKHOLDER MATTERS AND ISSUER PURCHASES OF EQUITY SECURITIES

Not Applicable

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, 2010, 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,  
     2010     2009     2008     2007     2006  
     (in thousands, except ratios)  

Statement of Operations Data

          

Operating Revenues

   $ 844,470      $ 713,169      $ 1,040,751      $ 963,094      $ 817,515   

Operating Margin

     53,671        57,736        61,417        62,085        73,461   

Net Margin attributable to ODEC(1)

     10,158        9,687        11,784        16,035        21,244   

Margins for Interest Ratio

     1.23        1.21        1.23        1.30        1.39   
     December 31,  
     2010     2009     2008     2007     2006  
     (in thousands, except ratios)  

Balance Sheet Data

          

Net Electric Plant

   $ 1,037,404      $ 1,008,373      $ 1,016,579      $ 1,031,727      $ 1,059,745   

Total Investments

     196,597        176,076        199,129        334,269        286,956   

Other Assets

     278,434        255,463        290,037        305,751        280,708   
                                        

Total Assets

   $ 1,512,435      $ 1,439,912      $ 1,505,745      $ 1,671,747      $ 1,627,409   
                                        

Patronage capital

   $ 339,678      $ 329,520      $ 319,833      $ 309,112      $ 293,077   

Non-controlling interest

     13,166        13,178        12,787        11,431        10,993   

Long-term debt

     449,798        688,736        711,675        787,028        813,264   

Long-term debt due within one year(2)

     238,917        22,917        22,917        29,667        22,917   

Notes payable

     7,043        26,954        62,000        —          —     
                                        

Total Capitalization

   $ 1,048,602      $ 1,081,305      $ 1,129,212      $ 1,137,238      $ 1,140,251   
                                        

Equity Ratio(3)

     32.8     30.9     28.6     27.5     26.0

 

(1)

Net Margin for 2010, 2007 and 2006 includes an additional equity contribution of $1.3 million, $4.0 million and $9.0 million, respectively.

(2)

Long-term debt due within one year includes $215.0 million 2001 Series A Bonds which are due on June 1, 2011. We plan to refinance this debt in the second quarter of 2011.

(3)

Equity ratio equals patronage capital divided by the sum of our long-term debt, long-term debt due within one year, notes payable, 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 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.

 

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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, demand for energy, federal and state legislative and regulatory actions and legal and administrative proceedings, changes in and compliance with environmental laws and policies, general credit and capital market conditions, 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 ODEC, its subsidiaries and TEC. See “Note 1—Summary of Significant Accounting Policies in the Notes to the Consolidated Financial Statements in Item 8.”

Overview

We are a not-for-profit power supply cooperative owned entirely by our eleven Class A member distribution cooperatives and a Class B 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, 2010, were significantly impacted by:

 

   

Acquisition of additional service territory by two of our member distribution cooperatives,

 

   

Unseasonably warm weather in May, June, July and September and unseasonably cold weather in November and December which increased our member distribution cooperatives’ requirements for power and increased the dispatch of our combustion turbine facilities,

 

   

Reduction in our total energy rate,

 

   

Scheduled and unscheduled maintenance outages for both units at North Anna; and

 

   

An interest rate hedge transaction.

Member Distribution Cooperatives—Events

On June 1, 2010, two of our member distribution cooperatives, REC and SVEC, acquired the distribution assets and right to provide electric distribution services to approximately 102,000 customers (meters) of Potomac Edison. On December 31, 2010, SVEC sold the distribution assets and right to provide electric distribution services to approximately 2,500 customers (meters) in West Virginia. We estimate that in the aggregate REC’s and SVEC’s acquisitions net of the disposition noted above will increase our megawatt hour (“MWh”) and megawatt (“MW”) sales to our member distribution cooperatives by approximately 35% to 40% on an annualized basis.

 

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In accordance with the wholesale power contracts between ODEC and its member distribution cooperatives, ODEC is serving the additional power requirements resulting from REC’s and SVEC’s acquisitions. We were not a party to this transaction; however, we assumed power supply contracts previously entered into by Potomac Edison for the service territory to serve the load of these customers. These contracts expire on June 30, 2011. A valuation of these contracts was performed as of June 1, 2010, and the value of the contracts approximated a fair value of zero.

In accordance with our load acquisition policy, we are paying a transition fee to REC and to SVEC that represents a portion of the projected power cost savings related to these acquisitions. The aggregate transition fee is approximately $66.7 million; of which approximately $7.4 million was recorded in 2010. The transition fee is reflected as a credit on the monthly power invoices to REC and SVEC over 48 months as a reduction in sales and is being collected from our member distribution cooperatives through our formulary rate.

In an unrelated transaction Northern Virginia Electric Cooperative (“NOVEC”) withdrew as a Class A member of ODEC effective December 31, 2008. In connection with the withdrawal, we entered into a settlement, release and withdrawal agreement with NOVEC to end our power supply arrangement and to resolve all of our outstanding disputes with NOVEC. The agreement resulted in the termination of NOVEC’s wholesale power contract with us and the payment by us to NOVEC of $50.0 million.

Critical Accounting Policies

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

Accounting for Rate Regulation

We are a rate-regulated entity and, as a result, are subject to the accounting requirements of Accounting for Regulated Operations. In accordance with Accounting for Regulated Operations, 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 Accounting for Regulated Operations, 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.

 

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Margin Stabilization Plan

We have a Margin Stabilization Plan that allows us to review our actual capacity-related costs of service and capacity revenue 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, generally in the succeeding calendar year. Each quarter we adjust operating revenues and accounts receivable—members or accounts payable—members, as appropriate, to reflect these adjustments. In 2010, 2009, and 2008, under our Margin Stabilization Plan, we reduced operating revenues by $22.5 million, $2.4 million, and $11.3 million, respectively, and increased accounts payable—members by the same amount.

Accounting for Asset Retirement Obligations

Accounting for Asset Retirement and Environmental Obligations 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.

Accounting for Asset Retirement and Environmental Obligations also 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.

A significant portion of our asset retirement obligations relates to our share of the future cost to decommission North Anna. At December 31, 2010, North Anna’s nuclear decommissioning asset retirement obligation totaled $62.0 million, which represented approximately 91.3% 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.

Approximately every four years, a new decommissioning study for North Anna is performed by third-party experts. The third party experts provide us with 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. Our current estimate is based upon studies that were performed in 2009 and adopted effective July 1, 2009.

 

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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 following table details the weighted average cost escalation rates used by the study:

 

Year

Study

Performed

   Weighted
Average Cost
Escalation Rate
 
2002      3.27
2005      2.42   
2009      2.30   

The weighted average cost escalation rate was applied if the cash flows increased as compared to the previous study. The original weighted average cost escalation rate was applied if the cash flows decreased as compared to the previous study. 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%, the amount recognized as of December 31, 2010, for our asset retirement obligations related to nuclear decommissioning would have been $13.3 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. 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 Accounting for Derivatives and Hedging. As a result, these contracts are not recorded at fair value. We record a liability and purchased power expense when the power under the physically-delivered 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 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 Accounting for Derivatives and Hedging. 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 Accounting for Regulated Operations. 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 at fair value on the Consolidated Balance Sheet in the regulatory assets or regulatory liabilities account and deferred charges–other and deferred credits and other liabilities–other. 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.

 

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

 

   

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 base energy rate, a fuel factor adjustment rate, and a demand 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 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 equity contributions 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, depreciation studies are required to be filed with FERC for their approval if they would result in a change in our depreciation rates.

We may revise our budget at any time to the extent that our current budget does not accurately reflect our costs and expenses or estimates of our sales of power. Increases or decreases in our budget automatically amend the fuel factor adjustment rate and/or the demand component of our formulary rate, as necessary. The formulary rate also permits 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 “—Critical Accounting Policies—Margin Stabilization Plan.” These adjustments are treated as due, owed, incurred and accrued for the year to which the increase or decrease relates. The member distribution cooperatives generally 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.

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.

 

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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 capacity-related 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. 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 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, as measured in MW. We bill energy to each of our member and non-member customers based on the total MWh delivered to them each month.

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 – 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, respectively. Mild weather generally reduces the demand because heating and air conditioning systems are operated less. Weather also plays a role in the price of market energy through its effects on the market price for fuel, particularly natural gas. For example, hurricanes in the Gulf of Mexico can affect the supply of natural gas and its market price.

 

   

Economy – General economic conditions have an impact on the rate of growth of our member distribution cooperatives’ energy requirements.

 

   

Residential growth – The increase in the rate of residential growth in our member distribution cooperatives’ service territories increases the requirements for power.

 

   

Commercial growth – The amount, size and usage of electronics and machinery and the expansion of operations among our member distribution cooperatives’ commercial and industrial customers impacts the requirements for power.

Power Supply Resources

In an attempt to provide stable power costs to our member distribution cooperatives, we utilize a combination of our owned generating resources and purchases from the market. We also regularly review options for future power sources, including additional owned generation and power purchase contracts.

Market forces influence the structure and price 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.

 

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In 2010, we satisfied the majority of our member distribution cooperatives’ capacity requirements and slightly less than half of their energy requirements through our ownership interests in Clover, North Anna, Louisa, Marsh Run, and Rock Springs, and we purchased power under physically-delivered forward contracts and in the spot market to supply the remaining needs of our member distribution cooperatives. See “Power Supply Resources” in Item 1 and “Properties” in Item 2.

PJM

PJM is a RTO that serves all of Delaware, Maryland, and most of Virginia, as well as other areas outside our member distribution cooperatives’ service territories. We are a member of PJM and are subject to the operations of PJM. PJM also coordinates and establishes policies for the generation, purchase and sale of capacity and energy in the control areas of its members, including all of the service territories of our member distribution cooperatives. As a result, our generating facilities are under dispatch control of PJM.

PJM 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 generation facilities in a manner intended to meet the demand for energy in the most reliable and cost-effective manner. Thus, PJM directs the dispatch of these facilities even though it does not own them. When PJM cannot dispatch available generating facilities due to transmission constraints, PJM will dispatch more expensive generating facilities to meet the required power requirements. For these reasons, actions by PJM affect our operating results. For further discussion related to PJM – see “PJM” in Part 1.

Generating Facilities

Our operating expenses, and consequently our rates to our member distribution cooperatives, are significantly affected by the operations of our baseload generating facilities, Clover and North Anna. Baseload generating facilities, particularly nuclear power plants such as North Anna, generally have relatively high fixed costs. Nuclear facilities operate with relatively low variable costs due to lower fuel costs and technological efficiencies. In addition, coal-fired facilities have relatively low variable costs, as compared to combustion turbine facilities such as Louisa, Marsh Run and Rock Springs. 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 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. Owners of power plants incur the fixed costs of these facilities whether or not the units operate.

As previously mentioned, our generating facilities are under dispatch control of PJM. See “PJM” above. Typically, nuclear facilities are almost always dispatched and coal-fired facilities are dispatched based upon economic factors including the market price of energy. The operational availability of Clover for the past three years was as follows:

 

     Clover
Year Ended  December 31,
 
     2010     2009     2008  

Unit 1

     95.2     83.8     93.8

Unit 2

     95.5        82.5        94.2   

Combined

     95.4        83.2        94.0   

 

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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
Year Ended  December 31,
    North Anna
Year Ended December 31,
 
   2010     2009     2008     2010     2009     2008  

Unit 1

     80.6     74.6     76.9     85.7     92.3     100.7

Unit 2

     82.5        72.2        76.0        79.6        99.9        81.3   

Combined

     81.6        73.4        76.5        82.7        96.1        91.0   

The scheduled and unscheduled outages for Clover for the past three years were as follows:

 

     Scheduled Outages
Year Ended December 31,
     Unscheduled Outages
Year Ended December 31,
 
     2010      2009      2008      2010      2009      2008  
     (in days)      (in days)  

Unit 1

     8.0         54.8         18.5         9.5         4.3         4.3   

Unit 2

     13.1         53.1         14.5         3.4         10.9         6.8   
                                                     

Combined

     21.1         107.9         33.0         12.9         15.2         11.1   
                                                     

Also, the production for Clover Unit 1 was curtailed approximately 9.5 days in 2010 and Clover Unit 2 was curtailed approximately 1.0 day in 2009 due to equipment issues.

The scheduled and unscheduled outages for North Anna for the past three years were as follows:

 

     Scheduled Outages
Year Ended December 31,
     Unscheduled Outages
Year Ended December 31,
 
     2010      2009      2008      2010      2009      2008  
     (in days)      (in days)  

Unit 1

     31.0         25.1         —           21.6         5.8         —     

Unit 2

     36.3         —           31.0         32.9         3.0         37.8   
                                                     

Combined

     67.3         25.1         31.0         54.5         8.8         37.8   
                                                     

The majority of the unscheduled outages for both units at North Anna during 2010 relate to the inspection and replacement of non-accident qualified insulation. The majority of the unscheduled outages at North Anna Unit 2 during 2008 relate to a transformer replacement and the removal of hydrogen system contamination in the main generator.

The operational availability of our Louisa, Marsh Run and Rock Springs combustion turbine facilities for the past three years was as follows:

 

     Operational Availability
Year Ended December 31,
 
   2010     2009     2008  

Louisa

     98.4     98.2     98.2

Marsh Run

     97.3        97.3        97.9   

Rock Springs

     94.2        94.6        98.3   

Increasing Environmental Regulation

We are subject to extensive federal and state regulation regarding environmental matters. This regulation is becoming increasingly stringent through amendments to federal and state statutes and the development of regulations authorized by existing law, including regulation related to CO2 and other GHGs. Future federal and state legislation and regulations, particularly with respect to GHGs, present the potential for even greater obligations to limit the impact on the environment from the operation of our generation and transmission facilities. See “Risk Factors” in Item 1A.

 

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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.”

Sales to TEC

In accordance with Consolidation Accounting, TEC is considered a variable interest entity for which ODEC is the primary beneficiary. The financial statements of TEC are consolidated and the inter-company balances are eliminated in consolidation. TEC’s sales to third parties are reflected as non-member revenues.

Sales to Non-Members

Sales to non-members consist of sales of excess purchased and generated energy. We primarily sell excess energy to PJM at the prevailing market price at the time of sale. Excess energy is the result of changes in our purchased power portfolio, differences between actual and forecasted needs, as well as changes in market conditions.

Results of Operations

Operating Revenues

Our operating revenues are derived from power sales to our member distribution cooperatives and non-members. Our operating revenues by type of purchaser for the past three years were as follows:

 

     Operating Revenues
Year Ended December 31,
 
     2010      2009      2008  
     (in thousands)  

Revenues from sales to:

  

Member distribution cooperatives

        

Base energy revenues

   $ 199,955       $ 154,780       $ 219,713   

Fuel factor adjustment revenues

     298,464         287,904         481,274   
                          

Total energy revenues

     498,419         442,684         700,987   

Demand (capacity) revenues

     280,651         236,391         264,488   
                          

Total revenues from sales to member distribution cooperatives

     779,070         679,075         965,475   

Non-members

     65,400         34,094         75,276   
                          

Total operating revenues

   $ 844,470       $ 713,169       $ 1,040,751   
                          

Average cost to member distribution cooperatives (per MWh)

   $ 69.22       $ 78.34       $ 79.08   

 

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Our energy sales in MWh to our member distribution cooperatives and non-members and demand sales in MW to our member distribution cooperatives for the past three years were as follows:

 

     Energy and Demand Sales Volume
Year Ended December 31,
 
     2010      2009      2008  
     (in MWh)  

Energy sales to:

  

Member distribution cooperatives

     11,254,269         8,667,917         12,208,886   

Non-members

     1,356,542         1,060,656         1,228,503   
                          

Total energy sales

     12,610,811         9,728,573         13,437,389   
                          
     (in MW)  

Demand sales to Member distribution cooperatives

     21,960         16,910         24,390   
                          

In 2010, our energy sales in MWh and demand sales in MW to our member distribution cooperatives were 29.8% and 29.9% higher, respectively, as compared to 2009, primarily as a result of the service territory acquisition by two of our member distribution cooperatives as of June 1, 2010 and changes in weather. The additional service territory increased our energy and demand sales to our member distribution cooperatives approximately 21.8% in 2010. During May, June, July and September of 2010, we experienced unseasonably warm weather; and in November and December of 2010 we experienced unseasonably cold weather. These changes in weather were partially offset by milder weather experienced in the first quarter of 2010.

In 2010, our energy sales in MWh to non-members were 27.9% higher as compared to 2009. Sales to non-members consist of sales of excess purchased and generated energy.

In 2010, total revenues from sales to our member distribution cooperatives increased $100.0 million, or 14.7%, as compared to 2009. The increase in total revenues is related to the additional service territory and weather-related increases in our energy sales volumes, partially offset by a 13.3% decrease in our total energy rate (our total energy rate includes our base energy rate and our fuel factor adjustment rate). In 2009, total revenues from sales to our member distribution cooperatives decreased $286.4 million, or 29.7 %, as compared to 2008, primarily as a result of the NOVEC withdrawal as of December 31, 2008. See “Member Distribution Cooperatives—Events.” Excluding NOVEC’s sales in 2008, total 2009 revenues from sales to member distribution cooperatives decreased approximately 2.1%. Additionally, our total energy rate decreased 11.1% on a per MWh basis.

The following table summarizes the changes to our total energy rate as a result of changes to our fuel factor adjustment rate due to the continued reduction in our realized as well as projected energy costs:

 

Effective Date of Rate Change:

   % Change
(Decrease)

January 1, 2009

   (8.2)

April 1, 2009

   (3.7)

August 1, 2009

   (5.7)

October 1, 2009

   (8.0)

April 1, 2010

   (3.8)

In 2010, the capacity costs we incurred, and thus the capacity-related revenues we reflected, were 18.7% higher as compared to 2009, primarily due an increase in the amount of capacity we purchased, which was primarily related to the additional service territory. This increase was partially offset by lower operations and maintenance expense and interest charges, net. In 2009, the capacity costs we incurred, and thus the capacity-related revenues we reflected, were 10.6% lower as compared to 2008, primarily due to the reduction in the amount of capacity we purchased due to the NOVEC withdrawal. See “Member Distribution Cooperatives—Events.”

 

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In 2010 and 2009, our average cost per MWh to member distribution cooperatives decreased $9.12 per MWh, or 11.6%, and $0.74 per MWh, or 0.9%, respectively, as compared to the prior year, primarily as a result of the decreases in our total energy rate.

Non-member revenue increased $31.3 million, or 91.8%, in 2010 as compared to 2009 due to an increase in the average price and a 27.9% increase in the volume of excess energy sales. In 2009, non-member revenue decreased $41.2 million, or 54.7%, as compared to 2008 due to a decrease in the average price and a 13.7% decrease in the volume of excess energy sales.

Operating Expenses

The following is a summary of the components of our operating expenses for the past three years.

 

      Year Ended December 31,  
      2010      2009      2008  
     (in thousands)  

Fuel

   $ 185,202       $ 111,863       $ 151,577   

Purchased power

     462,871         368,270         677,341   

Deferred energy

     6,637         36,300         23,531   

Operations and maintenance

     39,467         48,232         38,028   

Administrative and general

     39,895         37,485         38,175   

Depreciation, amortization and decommissioning

     41,535         41,061         39,637   

Amortization of regulatory asset/(liability), net

     3,352         915         120   

Accretion of asset retirement obligations

     3,333         3,273         3,181   

Taxes, other than income taxes

     8,507         8,034         7,744   
                          

Total Operating Expenses

   $ 790,799       $ 655,433       $ 979,334   
                          

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, as well as the capacity portion of our purchased power expense. Additionally, all non-operating expenses and income items, including interest charges and investment income, are components of our capacity costs. See “Factors Affecting Results—Formulary Rate.”

In 2010, total operating expenses increased $135.4 million, or 20.7%, as compared to 2009, primarily due to increases in purchased power and fuel expenses partially offset by decreases in deferred energy and operations and maintenance expenses.

 

   

Purchased power expense, which includes the cost of purchased energy and capacity, increased $94.6 million, or 25.7%, due to a 36.9% increase in the volume of purchased power primarily due to the acquisition of the additional service territory partially offset by an 8.2% decrease in the average cost of purchased power.

 

   

Fuel expense increased $73.3 million, or 65.6%, primarily due to the increase in the dispatch of our combustion turbine facilities.

 

   

Deferred energy expense decreased $29.7 million, or 81.7%. During 2010, we over-collected $6.6 million in energy costs; whereas in 2009, we over-collected $36.3 million in energy costs. Our deferred energy balance was a net over-collection of energy costs of $38.7 million at December 31, 2009, as compared to a net over-collection of energy costs of $45.4 million at December 31, 2010, reflecting the fact that our energy rate allowed us to collect our current year’s energy costs plus an additional $6.6 million to be used to offset future energy costs.

 

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Operations and maintenance expense decreased $8.8 million, or 18.2%, as the result of less scheduled maintenance in 2010 as compared to 2009.

In 2009, total operating expenses decreased $323.9 million, or 33.1%, as compared to 2008, primarily due to decreases in purchased power and fuel expense partially offset by increases in deferred energy expense and operations and maintenance expenses.

 

   

Purchased power expense decreased $309.1 million, or 45.6%, primarily due to decreased purchased power needs resulting from the NOVEC withdrawal as of December 31, 2008. Additionally, our average price of purchased power decreased 7.5%, reflecting declining costs in the power markets.

 

   

Fuel expense decreased $39.7 million, or 26.2%, primarily due to the decrease in the dispatch of our combustion turbine facilities and the reversal of previously accrued fuel transportation costs.

 

   

Deferred energy expense increased $12.8 million, or 54.3%, reflecting a $36.3 million over-collection of energy costs in 2009 as compared to a $23.5 million over-collection of energy costs in 2008. Our deferred energy balance was a net over-collection of energy costs of $2.4 million at December 31, 2008, as compared to a net over-collection of energy costs of $38.7 million at December 31, 2009, reflecting the fact that our energy rate allowed us to collect our current year’s energy costs plus an additional $36.3 million to be used to offset future energy costs.

 

   

Operations and maintenance expense increased $10.2 million, or 26.8%, due to additional scheduled maintenance and refueling outages at our operating facilities in 2009 as compared to 2008.

Other Items

Loss on Investment

In 2010 and 2009, we recognized a loss of $3.6 million and $1.4 million, respectively, related to our auction rate securities. See “Liquidity and Capital Resources—Auction Rate Securities and Related Preferred Stock” below.

Investment Income

Investment income increased in 2010 by $1.6 million, or 56.1%, primarily due to higher investment balances. Investment income decreased in 2009 by $6.4 million, or 68.7%, primarily due to lower investment balances as well as lower interest rates on our investments.

 

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Interest Charges, Net

The primary factors affecting our interest charges, net are scheduled payments of principal on our indebtedness, interest related to our dispute with Norfolk Southern, interest charges related to our credit facilities, and capitalized interest. We settled our dispute with Norfolk Southern in 2009. The major components of interest charges, net for the past three years were as follows:

 

     Year Ended December 31,  
     2010     2009     2008  
     (in thousands)  

Interest expense on long-term debt

   $ (46,270   $ (47,606   $ (52,953

Interest charges related to Norfolk Southern

     5,046        1,916        (2,459

Other

     (3,050     (2,747     (3,510
                        
     (44,274     (48,437     (58,922

Allowance for borrowed funds used during construction

     1,450        1,127        653   
                        

Interest Charges, net

   $ (42,824   $ (47,310   $ (58,269
                        

In 2010, interest charges, net decreased $4.5 million, or 9.5%, as compared to 2009 primarily as a result of the amortization of the regulatory liability related to the settlement of our dispute with Norfolk Southern. In 2009, interest charges, net decreased $11.0 million, or 18.8%, as compared to 2008 primarily as a result of decreased interest expense on long-term debt due to the early retirement of a bond originally issued in connection with the Clover Unit 1 lease and decreased interest related to the settlement of our dispute with Norfolk Southern.

Net Margin

In 2010, our net margin, which is a function of our total interest charges plus any additional equity contributions approved by our board of directors, increased $0.5 million, or 4.9%, as compared to 2009 due to an equity contribution of $1.3 million during 2010 partially offset by lower interest charges. On June 29, 2010, our board of directors approved an equity contribution of $1.3 million for 2010 to be collected June 1, 2010 to December 31, 2010. In 2009, our net margin decreased $2.1 million, or 17.8%, as compared to 2008 due to lower interest charges.

Financial Condition

The principal changes in our financial condition from December 31, 2009 to December 31, 2010, were caused by increases in long-term debt due within one year, accounts payable–members, accounts payable, accounts receivable–members, accounts receivable, investments–nuclear decommissioning trust, and interest rate hedge, partially offset by decreases in long-term debt, notes payable and fuel, materials and supplies.

 

   

Long-term debt due within one year increased $216.0 million primarily due to the $215.0 million maturity of our 2001 Series A Bonds on June 1, 2011.

 

   

Accounts payable–members increased $47.5 million due to the $27.3 million increase in member prepayments and the $20.1 million increase in the margin stabilization adjustment as compared to December 2009.

 

   

Accounts payable increased $42.7 million due to increased natural gas and purchased power requirement in December 2010 as compared to December 2009.

 

   

Accounts receivable–members increased $25.7 million as a result of higher sales to members in December 2010 as compared to December 2009 related to the acquisition of the additional service territory and a $6.8 million decrease in member extension balances.

 

   

Accounts receivable increased $23.2 million related to sales of excess power to non-members.

 

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Investments–nuclear decommissioning trust increased $12.1 million as a result of the increase in the fair value of the funds.

 

   

Interest rate hedge increased $10.9 million. To mitigate a portion of our exposure to fluctuations in long-term interest rates we entered into an interest rate hedge on May 14, 2010. The liability is due to the interest rate on U.S. Treasury bonds decreasing after we executed the transaction. See “Liquidity and Capital Resources—Interest Rate Hedge” below.

 

   

Long-term debt decreased $238.9 million primarily due to the maturity of our $215.0 million 2001 Series A Bonds on June 1, 2011 and the resulting reclassification of this debt to long-term debt due within one year and scheduled principal payments of $22.9 million on December 1, 2010.

 

   

Amounts outstanding under our notes payable decreased $19.9 million reflecting our repayment of amounts outstanding under our credit facilities.

 

   

Fuel, materials and supplies decreased $13.5 million related to the reduction in our inventory of coal. In 2009, both units at Clover were scheduled for longer outages resulting in reduced consumption of coal and an increase in the inventory balance.

Liquidity and Capital Resources

Sources

Cash generated by our operations and periodically, borrowings under our credit facilities provide our sources of liquidity and capital. In the past, we have also issued long-term indebtedness in the capital markets.

Operations

Historically, our operating cash flows generally 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. In 2010 and 2009, our operating activities provided cash flows of $119.2 million and $91.2 million, respectively. In 2008, our cash needs exceeded our cash flows from operating activities by $18.7 million. Operating activities in 2010 were primarily impacted by changes in:

 

   

Current liabilities changed $90.1 million primarily due to the $47.5 million increase in accounts payable–members and the $42.7 million increase in accounts payable.

 

   

Current assets changed by $34.6 million primarily due to the $25.7 million increase in accounts receivable–members and the $23.2 million increase in accounts receivable partially offset by the decrease $13.5 million in fuel, materials and supplies.

Auction Rate Securities and Related Preferred Stock

As of December 31, 2010, we had $16.8 million of principal invested in five securities, all of which were originally issued as auction rate securities and one of which has converted to preferred stock (“ARS”). The estimated fair value of our ARS was $7.9 million as of December 31, 2010. During 2010, we recognized a loss of $0.2 million related to an ARS which had a principal balance of $0.5 million and which we sold in December 2010 for $0.3 million. Additionally, we amortized $3.4 million of the regulatory asset which was established to record the deferred loss on the ARS. As of December 31, 2009, we had $17.3 million of principal invested in six ARS, two of which had converted to preferred stock, and the estimated fair value was $1.8 million.

ARS pay variable rates of interest which reset periodically in connection with the auction to purchase or sell the securities. Generally, the periodic auctions provide owners of ARS the opportunity to liquidate their investment at par value. In the event auctions are not fully subscribed, which auction agents describe as failed auctions, these securities are typically illiquid.

 

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In the absence of liquidity provided by auctions, we rely on a third party to establish the estimated fair values of our ARS. The estimated fair values of our ARS are determined with a valuation model that utilizes expected cash flow streams, assessments of credit quality, discount rates, and overall credit market liquidity, among other things.

The following represents changes in our ARS principal, fair value, and unrealized loss for the year ended December 31, 2010:

 

     Principal     Fair
Value
    Regulatory
Asset (3)(4)
    Realized
Loss
 
     (in thousands)  

ARS at December 31, 2009 (1)

   $ 17,320      $ 1,813      $ 15,507      $ —     

Sale of ARS (2)

     (500     (5     (495     175   

Change in market value

     —          6,054        (6,054     —     

Amortization of regulatory asset (4)

     —          —          (3,383     3,383   
                                

ARS at December 31, 2010 (1)(3)

   $ 16,820      $ 7,862      $ 5,575      $ 3,558   
                                

 

(1)

Recorded on our Consolidated Balance Sheet in investments–unrestricted investments and other, and classified as available for sale.

(2)

Sale of ARS in 2010 with a principal value of $0.5 million, sold for $0.3 million.

(3)

Recorded as unrealized loss on our Consolidated Balance Sheet in deferred charges–regulatory assets.

(4)

Amortization of regulatory asset began in 2010 and the remaining balance of the regulatory asset will be amortized and recorded as a realized loss in 2011.

We accounted for the difference between the principal of our ARS and the estimated fair value of our ARS as a regulatory asset in accordance with Accounting for Regulated Operations. In 2010, we began amortizing the regulatory asset which resulted in a recognized loss of $3.4 million. The remaining balance in the regulatory asset, $5.6 million, will be amortized in 2011. The estimated fair value of our ARS are included in investments–unrestricted investments and other on our Consolidated Balance Sheet and are classified as available for sale.

Clover Lease

In 1996, we entered into a lease and leaseback of our undivided interest in Clover Unit 1. In connection with this transaction, we invested a portion of the lease proceeds in a payment undertaking agreement. Distributions from the payment undertaking agreement fund a majority of our annual rent obligations under the leaseback and would fund a majority of the fixed purchase price we would need to pay if we choose to exercise the option to terminate the lease at the end of the leaseback term in 2018. The payment undertaking agreement is issued by Rabobank which has senior debt obligations that are currently rated “AAA” by S&P and “Aaa” by Moody’s. See “Significant Contingent Obligations—Clover Lease” below.

If Rabobank fails to provide funds from the payment undertaking agreement to fund rent payments under the lease, we remain liable for the payment of all rent and if we choose to exercise the option, the fixed purchase price. For 2010, distributions from the payment undertaking agreement provided $12.6 million, to fund rent payments under the lease.

Credit Facilities

In addition to liquidity from our operating activities, we currently maintain a total of $410.0 million in unsecured committed credit facilities to cover our short-term and medium-term funding needs. At December 31, 2010, we had $7.0 million of short-term borrowings outstanding at an interest rate of 1.8%. See “Financial Condition.” At December 31, 2009, we had a total of $365.0 million in committed credit facilities and we had $27.0 million of short-term borrowings outstanding which had a weighted average interest rate of 1.9%. We expect that we will renew the majority of these credit facilities as they expire.

 

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As of December 31, 2010, our credit facilities were as follows:

 

Lender

   Amount      Expiration Date  
     (in millions)         

Branch Banking and Trust Company

   $ 25.0         April 30, 2011   

National Rural Utilities Cooperative Finance Corp.

     75.0         April 15, 2012   

JPMorgan Chase Bank, National Association

     70.0         June 1, 2012   

Wells Fargo Bank, N.A.

     70.0         August 31, 2012   

CoBank, ACB

     100.0         June 18, 2013   

Bank of America, N.A.

     70.0         November 5, 2013   
           
   $ 410.0      
           

Our credit agreements relating to our committed 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;

 

   

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, which in certain cases 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 debt capital 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 the second quarter of 2011, we expect to issue $350.0 million of long-term debt to refinance the $215.0 million of Series A Bonds due June 1, 2011 and to replenish our working capital.

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, our existing credit facilities, and potential long-term borrowings will be sufficient to meet our currently anticipated operational and capital requirements.

Interest Rate Hedge

We are exposed to fluctuations in long-term interest rates related to the issuance of long-term debt and the refinancing of our $215.0 million 2001 Series A Bonds. To mitigate a portion of this exposure, on May 14, 2010, we entered into an interest rate hedge. At December 31, 2010, the fair value of this interest rate hedge was a $10.9 million liability, which is recorded as a current liability on our balance sheet. On January 21, 2011, we terminated the interest rate hedge in accordance with the terms of the transaction, resulting in a settlement payment of $3.4 million, the fair value of the hedge as of that date.

 

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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 2008 through 2013:

 

     Actual
Year Ended  December 31,
     Projected
Year Ended  December 31,
 
     2008      2009      2010      2011      2012      2013  
     (in millions)  

Combustion turbine facilities

   $ 0.8       $ 0.6       $ 0.9       $ 3.3       $ 1.2       $ 1.5   

Clover

     2.9         10.2         9.6         11.0         56.1         113.2   

North Anna

     19.8         30.1         36.4         23.8         12.4         17.4   

Other

     3.0         1.4         31.6         3.2         5.0         5.0   
                                                     

Total

   $ 26.5       $ 42.3       $ 78.5       $ 41.3       $ 74.7       $ 137.1   
                                                     

Nearly all of our capital expenditures consist of additions to electric plant and equipment. Actual capital expenditures for a potential additional unit at North Anna were $5.1 million, $2.6 million, and $13.6 million in 2008, 2009, and 2010, respectively. 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. Projected capital expenditures for Clover for years 2012 and 2013 include additional emissions reduction equipment. Projected capital expenditures for “Other” includes costs related to our transmission assets, administrative and general assets, and distributed generation facilities, and for 2010, actual capital expenditures includes $30.0 million related to the purchase of two tracts of land for a potential base load power generation facility. We intend to use our cash from operations and borrowings to fund all of our currently projected capital requirements through 2013.

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.” The following table summarizes our long-term contractual obligations at December 31, 2010:

 

     Payments due by Period  
     Total      Less
than

1 year
     1-3
years
     3-5
years
     More
than 5
years
 
     (in millions)  

Long-term indebtedness

   $ 984.6       $ 273.4       $ 97.3       $ 114.7       $ 499.2   

Operating lease obligations

     111.9         0.4         0.9         1.3         109.3   

Power purchase obligations

     1,707.2         231.2         341.2         353.7         781.1   

Asset retirement obligations

     389.4         —           —           —           389.4   
                                            

Total

   $ 3,193.1       $ 505.0       $ 439.4       $ 469.7       $ 1,779.0   
                                            

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, 2010, all of our long-term indebtedness was issued under the Indenture. This indebtedness includes bonds issued to the public and bonds issued to a local governmental authority in consideration for loans to us of the proceeds of tax-exempt offerings of indebtedness by this governmental authority. 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.

 

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Operating Lease Obligations

Our obligation described above primarily relates to our portion of the Clover Unit 1 purchase option price at the end of the term of the leaseback that will be satisfied by our investment in United States Treasury securities. See “Significant Contingent Obligations—Clover Lease.”

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.

Asset Retirement Obligations

We account for our asset retirement obligations in accordance with Accounting for Asset Retirement and Environmental 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. See “Critical Accounting Policies—Accounting for Asset Retirement Obligations” above.

Significant Contingent Obligations

In addition to these existing contractual obligations, we have significant contingent obligations. These obligations primarily relate to power purchase arrangements, our arrangement with TEC and our lease of our interest in Clover Unit 1.

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 Clover Unit 1 lease and some of our purchases of power in the market.

Power Purchase Arrangements

Under the terms of most of our power purchase contracts, we typically agree to provide collateral under certain circumstances and we require comparable terms from our counterparties. The collateral we may be required to post with a counterparty, and vice versa, 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 a contract with a respective counterparty. At December 31, 2010 we posted $3.0 million of collateral with counterparties pursuant to the contracts we have in place. Typically, collateral thresholds under our contracts are zero once an entity is rated below investment grade by S&P or Moody’s (i.e., “BBB-” or “Baa3”, respectively). At December 31, 2010, if our credit ratings had been below investment grade we estimate we would have been obligated to post between $400.0 million and $500.0 million of collateral with our counterparties. This calculation is based on energy prices on December 31, 2010, and delivered power for which we have not yet paid. Depending on the difference between the price of power under our 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 its credit policy, PJM subjects each applicant, participant and member of PJM to a credit evaluation to determine its creditworthiness, and whether it must provide any 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. At December 31, 2010, if PJM had determined that we needed to provide collateral to support our obligations, PJM could have asked us to provide up to approximately $4.0 million.

 

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TEC Guarantees

To facilitate the ability of TEC to sell power in the market, we have agreed to guarantee up to a maximum of $100.0 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, 2010, we had issued guarantees for up to $47.6 million of TEC’s obligations and TEC had accounts payable of $28.1 million related to these guarantees.

Clover Lease

In 1996, we entered into a lease transaction relating to our 50% undivided ownership interest in Clover Unit 1 and related common facilities. In this transaction, we leased our undivided interest in the facility to an owner trust for the benefit of an investor for the full productive life of the unit in exchange for a one-time rental payment of $315.0 million at the beginning of the lease. Immediately after the lease to the owner trust, we leased the unit and common facilities back for a term of 21.8 years and agreed to make periodic rental payments to the owner trust.

We used a portion of the one-time rental payment we received to enter into a payment undertaking agreement and to purchase an investment, which provide for substantially all of:

 

   

our periodic rent payments under the leaseback; and

 

   

the fixed purchase price of the interest in Unit 1 at the end of the term of the leaseback if we were to exercise our option to purchase the interest of the owner trust in Unit 1 and the common facilities at that time. The fixed purchase price is $430.5 million.

After entering into the payment undertaking agreement, making the investment and paying transaction costs, we had $23.7 million remaining (the gain on the transaction) and we retained possession and our initial entitlement to the output of Unit 1.

The payment undertaking agreement was issued by Rabobank which has senior debt obligations which are currently rated “AAA” by S&P and “Aaa” by Moody’s. Under this agreement, we made a payment to Rabobank, in return Rabobank agreed to make payments directly to the lender in the related lease transaction in satisfaction of a portion of our rent payment obligation under the leaseback and a portion of the fixed purchase price if we choose to exercise that option. We remain liable for all rental payments under the leaseback if Rabobank fails to make such payments, although the owner trust has agreed to pursue Rabobank before pursuing payment from us. For 2010, Rabobank paid $12.6 million of rent. At December 31, 2010, both the value of the portion of our lease obligations to be paid by Rabobank to the owner trust, as well as the value of our interest in the related payment undertaking agreement, totaled approximately $311.5 million.

In connection with the lease and leaseback, we also agreed to deliver a letter of credit to the investor 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, 2010, the estimated amount of the letter of credit we would have been required to provide was $21.6 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.

At the end of the term of the Clover Unit 1 leaseback, we have the option to purchase the owner trust’s interest in the 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 the unit, we must pay the owner trust a fixed purchase price of $430.5 million. Payments under the payment undertaking agreement are expected to fund approximately

 

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$289.7 million of these payments. These payments also will be funded by United States Treasury securities with a maturity value of $108.6 million. The remaining $32.2 million will be provided by us, but will in turn be paid to us as the holder of a loan to the owner trust. If we do not elect to purchase the owner trust’s interest in Clover Unit 1, 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 Clover Unit 1, we can arrange for a third party to purchase the owner trust’s output of the unit at prices which will preserve the 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 leaseback. We would not be obligated, however, to provide this financing. 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. We also must provide management services to the owner trust if power is being sold to the third party.

As a third option, at the end of the term of the leaseback, 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.

Off-Balance Sheet Arrangements

Clover Unit 1

See “Significant Contingent Obligations—Clover Lease.”

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 “Business—Power Supply Resources” in Item 1. In addition, the purchase of fuel to operate our generating facilities also exposes us to market price risk.

The fair value of the hedging instruments we use to mitigate market price risk is impacted by changes in market prices. At December 31, 2010, we estimate that the fair value of our purchased power agreements and forward purchases of energy and natural gas was between $2.2 billion and $2.4 billion. Approximately 45% of the fair value of this portfolio is estimable using observable market prices. The remaining 55% of the fair value of this

 

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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 55% of this portfolio that relates to less liquid products involves management judgment, the use of estimates, and the underlying assumptions in our portfolio model. 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 approximately $100.0 million at December 31, 2010. 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 approximately $100.0 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. See “Management’s Discussion and Analysis of Financial Condition and Results of Operations—Factors Affecting Results—Formulary Rate” in Item 7.

Through our relationship with ACES, we have formulated policies and procedures to manage the risks associated with these market price fluctuations. We use various hedging instruments, such as futures, forwards and options, to reduce our risk exposure. ACES 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;

 

   

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 sole 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 advises us that they regularly evaluate 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 they use both long-term contracts and short-term spot agreements to acquire the low sulfur bituminous coal used to fuel the Clover facility. See “Business—Fuel Supply—Coal” in Item 1.

Interest Rate Risk and Equity Price Risk

In 2010, all of our outstanding long-term indebtedness accrued interest at fixed rates.

We also have $410.0 million of committed credit facilities. 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. At December 31, 2010, we had $7.0 million outstanding under these facilities.

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

 

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time of decommissioning. At December 31, 2010, $41.9 million of these funds were invested in fixed-income securities and $55.4 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.

We are exposed to fluctuations in long-term interest rates related to the issuance of long-term debt and the refinancing of $215.0 million principal amount of our 2001 Series A Bonds that mature on June 1, 2011. To mitigate a portion of this exposure, on May 14, 2010, we entered into an interest rate hedge. At December 31, 2010, the fair value of this interest rate hedge was a $10.9 million liability, which is recorded as a current liability on our balance sheet. On January 21, 2011, we terminated the interest rate hedge in accordance with the terms of the transaction, resulting in a settlement payment by us of $3.4 million.

Credit Risk

As of December 31, 2010, we had $16.8 million of principal invested in five securities, all of which were originally issued as auction rate securities and one of which has converted to preferred stock (“ARS”). The estimated fair value of our ARS was $7.9 million as of December 31, 2010. During 2010, we recognized a loss of $0.2 million related to an ARS which had a principal balance of $0.5 million and which we sold in December 2010 for $0.3 million. Additionally, we amortized $3.4 million of the regulatory asset which was established to record the deferred loss on the ARS. As of December 31, 2009, we had $17.3 million of principal invested in six ARS and the estimated fair value was $1.8 million.

ARS pay variable rates of interest which reset periodically in connection with the auction to purchase or sell the securities. Generally, the periodic auctions provide owners of ARS the opportunity to liquidate their investment at par value. In the event auctions are not fully subscribed, which auction agents describe as failed auctions, these securities are typically illiquid.

In the absence of liquidity provided by auctions, we rely on a third party to establish the estimated fair values of our ARS. The estimated fair values of our ARS are determined with a valuation model that utilizes expected cash flow streams, assessments of credit quality, discount rates, and overall credit market liquidity, among other things.

We accounted for the difference between the principal of our ARS and the estimated fair value of our ARS as a regulatory asset in accordance with Accounting for Regulated Operations. In 2010, we began amortizing the regulatory asset which resulted in a recognized loss of $3.4 million. The remaining balance in the regulatory asset, $5.6 million, will be amortized in 2011. The estimated fair value of our ARS are included in investments–unrestricted investments and other on our Consolidated Balance Sheet and are classified as available for sale.

 

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ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA

CONSOLIDATED FINANCIAL STATEMENTS

INDEX

 

     Page
Number

Report of Management on ODEC’s Internal Control over Financial Reporting

   47

Report of Independent Registered Public Accounting Firm

   48

Consolidated Balance Sheets

   49

Consolidated Statements of Revenues, Expenses and Patronage Capital

   50

Consolidated Statements of Cash Flows

   51

Notes to Consolidated Financial Statements

   52

 

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Report of Management on ODEC’s Internal Control over Financial Reporting

Management of Old Dominion Electric Cooperative (“ODEC”) has assessed ODEC’s internal control over financial reporting as of December 31, 2010, based on criteria for effective internal control over financial reporting described in “Internal Control – Integrated Framework” issued by the Committee of Sponsoring Organizations of the Treadway Commission. Based on this assessment, management believes that as of December 31, 2010, our system of internal control over financial reporting was properly designed and operating effectively based upon the specified criteria.

Management of ODEC is responsible for establishing and maintaining adequate internal control over financial reporting. ODEC’s internal control over financial reporting is comprised of policies, procedures, and reports designed to provide reasonable assurance to ODEC’s management and board of directors that the financial reporting and the preparation of the financial statements for external reporting purposes has been handled in accordance with accounting principles generally accepted in the United States. Internal control over financial reporting includes those policies and procedures that (1) govern records to accurately and fairly reflect the transactions and dispositions of assets of ODEC; (2) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles and that receipts and expenditures of ODEC are being made only in accordance with authorizations of the management and directors of ODEC; and (3) provide reasonable safeguards against or timely detection of material unauthorized acquisition, use or disposition of ODEC’s assets.

Internal controls over financial reporting may not prevent or detect all misstatements. Accordingly, even effective internal control can provide only reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with GAAP.

March 16, 2011

 

/s/ JACKSON E. REASOR

   

/s/ ROBERT L. KEES

Jackson E. Reasor     Robert L. Kees
President and Chief Executive Officer     Senior Vice President and Chief Financial Officer

 

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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, 2010 and 2009, and the related consolidated statements of revenues, expenses and patronage capital, and cash flows for each of the three years in the period ended December 31, 2010. 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 the 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 Company’s internal control over financial reporting. Our audits included 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, 2010 and 2009, and the consolidated results of its operations and its cash flows for each of the three years in the period ended December 31, 2010, in conformity with U.S. generally accepted accounting principles.

Richmond, Virginia

 

March 16, 2011

 

/s/ Ernst & Young LLP

 

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OLD DOMINION ELECTRIC COOPERATIVE

CONSOLIDATED BALANCE SHEETS

AS OF DECEMBER 31, 2010 AND 2009

 

     2010     2009  
     (in thousands)  

ASSETS:

    

Electric Plant:

    

Property, plant, and equipment

   $ 1,627,643      $ 1,578,459   

Less accumulated depreciation

     (663,871     (630,600
                
     963,772        947,859   

Nuclear fuel, at amortized cost

     20,872        13,519   

Construction work in progress

     52,760        46,995   
                

Net Electric Plant

     1,037,404        1,008,373   
                

Investments:

    

Nuclear decommissioning trust

     97,531        85,437   

Lease deposits

     89,355        87,052   

Unrestricted investments and other

     9,711        3,587   
                

Total Investments

     196,597        176,076   
                

Current Assets:

    

Cash and cash equivalents

     4,391        6,278   

Accounts receivable

     23,495        264   

Accounts receivable–deposits

     3,000        3,800   

Accounts receivable–members

     98,423        72,716   

Fuel, materials and supplies

     35,798        49,290   

Prepayments and other

     3,438        3,521   
                

Total Current Assets

     168,545        135,869   
                

Deferred Charges:

    

Regulatory assets

     93,199        97,864   

Other

     16,690        21,730   
                

Total Deferred Charges

     109,889        119,594   
                

Total Assets

   $ 1,512,435      $ 1,439,912   
                

CAPITALIZATION AND LIABILITIES:

    

Capitalization:

    

Patronage capital

   $ 339,678      $ 329,520   

Non-controlling interest

     13,166        13,178   
                

Total Patronage capital and Non-controlling interest

     352,844        342,698   

Long-term debt

     449,798        688,736   
                

Total Capitalization

     802,642        1,031,434   
                

Current Liabilities:

    

Long-term debt due within one year

     238,917        22,917   

Notes payable

     7,043        26,954   

Accounts payable

     91,686        48,966   

Accounts payable–members

     76,458        29,004   

Interest rate hedge

     10,944        —     

Accrued expenses

     4,606        4,659   

Deferred energy

     45,377        38,740   
                

Total Current Liabilities

     475,031        171,240   
                

Deferred Credits and Other Liabilities:

    

Asset retirement obligations

     67,876        64,543   

Obligations under long-term leases

     64,801        60,612   

Regulatory liabilities

     87,406        96,456   

Other

     14,679        15,627   
                

Total Deferred Credits and Other Liabilities

     234,762        237,238   
                

Commitments and Contingencies

     —          —     
                

Total Capitalization and Liabilities

   $ 1,512,435      $ 1,439,912   
                

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, 2010, 2009 AND 2008

 

     2010     2009     2008  
     (in thousands)  

Operating Revenues

   $ 844,470      $ 713,169      $ 1,040,751   
                        

Operating Expenses:

      

Fuel

     185,202        111,863        151,577   

Purchased power

     462,871        368,270        677,341   

Deferred energy

     6,637        36,300        23,531   

Operations and maintenance

     39,467        48,232        38,028   

Administrative and general

     39,895        37,485        38,175   

Depreciation, amortization and decommissioning

     41,535        41,061        39,637   

Amortization of regulatory asset/(liability), net

     3,352        915        120   

Accretion of asset retirement obligations

     3,333        3,273        3,181   

Taxes, other than income taxes

     8,507        8,034        7,744   
                        

Total Operating Expenses

     790,799        655,433        979,334   
                        

Operating Margin

     53,671        57,736        61,417   

Other expense, net

     (1,723     (1,598     (200

Net gain on Clover Unit 2 lease transaction

     —          —          13,121   

Loss on investments

     (3,558     (1,440     (11,480

Investment income

     4,576        2,931        9,377   

Interest charges, net

     (42,824     (47,310     (58,269

Income taxes

     3        (240     (826
                        

Net Margin including Non-controlling interest

     10,145        10,079        13,140   

Non-controlling interest

     13        (392     (1,356
                        

Net Margin attributable to ODEC

     10,158        9,687        11,784   

Patronage Capital - Beginning of Year

     329,520        319,833        309,112   

Capital adjustment

     —          —          (1,063
                        

Patronage Capital - End of Year

   $ 339,678      $ 329,520      $ 319,833   
                        

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

 

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OLD DOMINION ELECTRIC COOPERATIVE

CONSOLIDATED STATEMENTS OF CASH FLOWS

FOR THE YEARS ENDED DECEMBER 31, 2010, 2009 AND 2008

 

     2010     2009     2008  
     (in thousands)  

Operating Activities:

      

Net Margin attributable to ODEC

   $ 10,158      $ 9,687      $ 11,784   

Adjustments to reconcile net margins to net cash provided by operating activities:

      

Depreciation, amortization and decommissioning

     41,535        41,061        39,637   

Other non-cash charges

     10,149        10,603        13,311   

Non-controlling interest

     (13     392        1,356   

Amortization of lease obligations

     4,189        4,695        10,466   

Interest on lease deposits

     (2,586     (3,196     (11,827

Change in current assets

     (34,563     17,011        (14,063

Change in deferred energy

     6,637        36,300        23,531   

Change in current liabilities

     90,121        (26,284     (35,104

Change in regulatory assets and liabilities

     (11,596     411        (8,843

Change in deferred charges and credits

     5,176        538        1,085   

Contract termination fee

     —          —          (50,000
                        

Net Cash Provided by (Used for) Operating Activities

     119,207        91,218        (18,667
                        

Financing Activities:

      

Payment of long-term debt

     (22,917     (22,917     (29,667

Obligations under long-term leases

     —          (237     (423

Draws on revolving credit facilities

     110,304        545,367        62,000   

Repayments on revolving credit facilities

     (130,215     (580,413     —     

Retirement of bond, net of unamortized discount

     —          —          (56,113

Gain on Clover Unit 2 lease transaction

     —          —          (20,121
                        

Net Cash (Used for) Financing Activities

     (42,828     (58,200     (44,324
                        

Investing Activities:

      

Purchases of held to maturity securities

     —          —          (178,202

Proceeds from held to maturity securities

     —          —          118,550   

Proceeds from sale of available for sale securities

     325        3,560        —     

Decrease in other investments

     (3,663     (1,506     (2,908

Electric plant additions

     (78,486     (42,259     (26,524

Liquidation of equity deposit

     —          —          56,113   

Loss on investments

     3,558        1,440        11,480   

Acquisition of transmission assets

     —          —          (5,306
                        

Net Cash (Used for) Investing Activities

     (78,266     (38,765     (26,797
                        

Net Change in Cash and Cash Equivalents

     (1,887     (5,747     (89,788

Cash and Cash Equivalents - Beginning of Year

     6,278        12,025        101,813   
                        

Cash and Cash Equivalents - End of Year

   $ 4,391      $ 6,278      $ 12,025   
                        

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”) and TEC Trading, Inc. (“TEC”). In accordance with Consolidation Accounting, TEC is considered a variable interest entity for which we are the primary beneficiary. 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 consolidated assets were $13.2 at December 31, 2010 and December 31, 2009. The income taxes reported on our Consolidated Statements of Revenues, Expenses and Patronage Capital relate to the tax provision for TEC. As TEC is 100% owned by our Class A members, its equity is presented as a non-controlling interest in our consolidated financial statements. Our non-controlling, 50% or less, ownership interest in other entities for which we have significant influence is recorded using the equity method of accounting. 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 and sells this power to the market under market-based rate authority granted by FERC. TEC also acquires natural gas and forward purchase contracts to hedge the price of natural gas to supply our combustion turbine facilities, and takes advantage of other power-related trading opportunities in the market which may help lower our member distribution cooperatives’ costs. TEC does not engage in speculative trading.

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 customer-owned electric distribution cooperatives engaged in the retail sale of power to member consumers located in Virginia, Delaware, and Maryland. During 2010 and 2009, we had eleven member distribution cooperatives as our Class A members. During 2008, we had twelve member distribution cooperatives and one of these entities withdrew as a member on December 31, 2008. Our sole Class B member TEC, a taxable corporation, is 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”). Our most recent filing was accepted by FERC on November 4, 2008, and became effective January 1, 2009.

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

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

We do not have any other comprehensive income for the periods presented.

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.

 

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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. Our next depreciation study was completed in 2010 and will be implemented in 2011 and no material change is expected.

Depreciation rates are as follows:

 

     Depreciation Rates  

Generating Facility

   2010     2009     2008  

Clover

     1.8     1.8     1.8

North Anna

     2.9        2.9        2.9   

Louisa

     3.3        3.3        3.3   

Marsh Run

     3.4        3.4        3.4   

Rock Springs

     3.5        3.5        3.5   

Nuclear Fuel

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

Under 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 DOE. The DOE did not begin accepting spent fuel in 1998 as specified in its contracts. Virginia Electric and Power Company (“Virginia Power”) is providing on-site spent nuclear fuel storage at the North Anna facility. Virginia Power will continue to manage North Anna’s spent nuclear fuel until the DOE begins accepting the spent nuclear fuel. In January 2004, Virginia Power filed a lawsuit seeking recovery of damages in connection with the DOE’s failure to commence accepting spent nuclear fuel from North Anna. A subsequent trial held in 2008 ruled in favor of Virginia Power and the DOE filed an appeal. In March 2009, the U.S. Court of Appeals to the Federal Circuit granted the DOE’s request to stay the appeal. In November 2009, Virginia Power filed a motion to lift the stay and the DOE has opposed this motion. In May 2010, the stay was lifted, and the government’s initial brief in the appeal was filed in June 2010. Briefing on the appeal was concluded in September 2010 and oral arguments took place before the U.S. Court of Appeals for the Federal Circuit in January 2011.

Fuel, Materials and Supplies

Fuel, materials and supplies is 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 No. 2 fuel oil, which is recorded at average cost.

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 2010, 2009, and 2008, was $1.4 million, $1.1 million, and $0.7 million, respectively.

 

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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 provision for income taxes has been recorded based on ODEC’s operations in the accompanying consolidated financial statements.

TEC is a taxable corporation and its provision for income taxes was immaterial for the year ended December 31, 2010 and was approximately $0.2 million and $0.8 million for the years ended December 31, 2009 and 2008, 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. For the years ended December 31, 2010, 2009, and 2008, revenue from sales to our member distribution cooperatives was $779.1 million, $679.1 million, and $965.5 million, respectively. See Note 5—Wholesale Power Contracts.

We sell excess purchased and generated energy, if any, to TEC, our Class B member, or to third parties under FERC market-based rate authority. 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. TEC’s sales to third parties are reflected as non-member revenues. Excess purchased and generated energy that is not sold to TEC is sold to the PJM Interconnection, LLC (“PJM”) under its rates for providing energy imbalance service or to third parties. For the years ended December 31, 2010, 2009, and 2008, energy sales to non-members were $65.4 million, $34.1 million, and $75.3 million, respectively.

Regulatory Assets and Liabilities

We account for certain revenues and expenses as a rate-regulated entity in accordance with Accounting for Regulated Operations. This 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, is included in current assets or current liabilities. See—Deferred Energy below. Regulatory assets and liabilities will be recognized as expenses or as a reduction in expenses, concurrent with their recovery through rates.

Debt Issuance Costs

Capitalized costs associated with the issuance of debt totaled $8.6 million and $9.2 million, at December 31, 2010 and 2009, 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.

 

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Deferred Credits and Other Liabilities – Other

Deferred credits and other liabilities – other, includes gain on long-term lease transactions (see Note 8— Long-Term Lease Transactions), DOE decontamination and decommissioning liability, and liabilities associated with benefit plans for certain executives. The unamortized portion of the deferred gain was $7.6 million and $8.7 million at December 31, 2010 and 2009, respectively. This gain is being amortized into income ratably over the term of the operating leases as a reduction to depreciation, amortization and decommissioning expense. In December 2008, we terminated the lease on Unit 2 of the Clover Power Station (“Clover”) which resulted in recognition of a $20.1 million gain.

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 under- or over-collection of energy costs. At December 31, 2010 and 2009, we had an over-collected deferred energy balance of $45.4 million and $38.7 million, respectively. Over-collected deferred energy balances are refunded to our members in subsequent periods.

Financial Instruments (including Derivatives)

Financial instruments included in the nuclear decommissioning trust are classified as available for sale, and accordingly, are carried at fair value. Unrealized gains and losses on investments held in the nuclear decommissioning trust 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. Unrealized losses on our auction rate security investments and preferred stock (“ARS”) are deferred as a regulatory asset until realized. 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. Other investments are recorded at cost, which approximates market value. See Note 9—Investments.

We primarily purchase power under both long-term and short-term physically-delivered forward contracts to supply power to our member distribution cooperatives. 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 provided for under Accounting for Derivatives and Hedging. As a result, these contracts are not recorded at fair value. We record 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 Accounting for Derivatives and Hedging. 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 Accounting for Regulated Operations. 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. There was no hedge ineffectiveness during the years ended December 31, 2010, 2009 or 2008.

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.

 

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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 Second Amended and Restated Indenture of Mortgage and Deed of Trust, dated as of January 1, 2011, with Branch Banking and Trust Company, as trustee (the “Indenture”).

Concentrations of Credit Risk

Financial instruments that potentially subject us to concentrations of credit risk consist of cash equivalents, investments, derivatives, and receivables arising from sales to our members and non-members. Concentrations of credit risk with respect to receivables arising from sales to our member distribution cooperatives as reflected by accounts receivable–members were $98.4 million and $72.7 million, at December 31, 2010 and 2009, respectively.

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.

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 2010:

 

     Clover     North
Anna
    Combustion
Turbine
Facilities
    Other     Total  
     (in thousands)  

Property, plant, and equipment(1)

   $ 664,783      $ 317,095      $ 580,878      $ 64,887      $ 1,627,643   

Accumulated depreciation

     (338,500     (166,610     (140,260     (18,501     (663,871

Nuclear fuel

     —          60,193        —          —          60,193   

Accumulated amortization of nuclear fuel

     —          (39,321     —          —          (39,321

Construction work in progress(2)

     8,991        43,374        —          395        52,760   
                                        
   $ 335,274      $ 214,731      $ 440,618      $ 46,781      $ 1,037,404   
                                        

 

(1)

Other includes $30.0 million related to land held for future use.

(2)

North Anna includes $21.3 million related to a potential additional unit at North Anna. See Note 19—Subsequent Events.

Our net electric plant is comprised of the following for 2009:

 

     Clover     North
Anna
    Combustion
Turbine
Facilities
    Other     Total  
     (in thousands)  

Property, plant, and equipment

   $ 668,478      $ 295,614      $ 580,014      $ 34,353      $ 1,578,459   

Accumulated depreciation

     (331,617     (161,260     (120,527     (17,196     (630,600

Nuclear fuel

     —          51,371        —          —          51,371   

Accumulated amortization of nuclear fuel

     —          (37,852     —          —          (37,852

Construction work in progress(1)

     992        45,957        —          46        46,995   
                                        
   $ 337,853      $ 193,830      $ 459,487      $ 17,203      $ 1,008,373   
                                        

 

(1)

North Anna includes $7.7 million related to a potential additional unit at North Anna. See Note 19—Subsequent Events.

 

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We hold a 50% undivided ownership interest in 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 we 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, 2010 and 2009, we had an outstanding accounts payable balance of $8.1 million and $7.1 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 we 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, 2010 and 2009, we had an outstanding accounts payable balance due to Virginia Power for the operation, maintenance, and capital investment at the North Anna facility of $7.7 million and $6.6 million, respectively.

In 2007, we filed a joint application with Virginia Power at the Nuclear Regulatory Commission (“NRC”) for a license to construct and operate a new reactor at North Anna. In October 2010, Virginia Power announced that it will slow down its pursuit of an additional nuclear-powered generating unit at North Anna and plans to reassess the schedule for construction of the unit in 2013. We have evaluated our continued participation in this project and on February 28, 2011, we announced that we have decided not to participate in the development or ownership of an additional nuclear-powered generating unit at North Anna. We are currently working with Virginia Power on the logistics of our withdrawal as a participant in the project. See Note 19—Subsequent Events.

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. Additionally, we own approximately 100 miles of transmission lines on the Virginia portion of the Delmarva Peninsula, as well as two 1,100 foot 500 kilovolt (“kV”) transmission lines and a 500kV substation at our combustion turbine site in Maryland. These assets are also included in “Other”.

In May 2010, we acquired a tract of land in Surry County, Virginia, and in July 2010, we acquired a tract of land in Sussex County, Virginia, for approximately $15.0 million each for a total of $30.0 million, as possible sites for a future generation facility.

The table below summarizes our projected capital expenditures, including nuclear fuel and capitalized interest, for 2011 through 2013:

 

     Projected
Year Ended December 31,
 
     2011      2012      2013  
     (in millions)  

Combustion turbine facilities

   $ 3.3       $ 1.2       $ 1.5   

Clover

     11.0         56.1         113.2   

North Anna

     23.8         12.4         17.4   

Other

     3.2         5.0         5.0   
                          

Total

   $ 41.3       $ 74.7       $ 137.1   
                          

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. Projected capital expenditures for Clover for years 2012 and 2013 include additional emissions reduction equipment. Projected capital expenditures for “Other” include costs related to our transmission assets, administrative and general assets, and distributed generation facilities.

 

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NOTE 3—Accounting for Asset Retirement Obligations

We account for our asset retirement obligations in accordance with Accounting for Asset Retirement and Environmental Obligations. This requires that legal obligations associated with the retirement of long-lived assets 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.

In the absence of quoted market prices, we determine 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.

A significant portion of our asset retirement obligations relate to our share of the future decommissioning of North Anna. At December 31, 2010 and 2009, North Anna’s nuclear decommissioning asset retirement obligation totaled $62.0 million and $59.0 million, respectively. Approximately every four years, a new decommissioning study for North Anna is performed. In 2009, we received the new study and adopted it effective July 1, 2009, which resulted in an additional layer related to the asset retirement obligation associated with North Anna. The additional layer resulted in a decrease to our asset retirement cost and our asset retirement obligation of $1.0 million.

The following represents changes in our asset retirement obligations for the years ended December 31, 2010 and 2009 (in thousands):

 

Asset retirement obligations at December 31, 2008

   $ 62,238   

Accretion expense

     3,273   

Asset retirement obligations settled

     (968
        

Asset retirement obligations at December 31, 2009

   $ 64,543   

Accretion expense

     3,333   
        

Asset retirement obligations at December 31, 2010

   $ 67,876   
        

The cash flow estimates for North Anna’s asset retirement obligations are based upon the 20-year life extension which was granted in 2003 and extends the life of Unit 1 to 2038 and Unit 2 to 2040. Given the life extension, the level of the nuclear decommissioning trust 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 the difference between the earnings on the nuclear decommissioning trust and the total asset retirement obligation related depreciation and accretion expense for North Anna as part of our asset retirement obligation regulatory liability. See Note 10—Regulatory Assets and Liabilities.

NOTE 4—Power Purchase Agreements

In 2010, 2009, and 2008, our owned generating facilities together furnished approximately 45.9%, 48.6%, and 36.5%, respectively, of our energy requirements. The remaining needs were satisfied through physically-delivered forward purchase power contracts and spot market purchases.

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 utilize policies, procedures, and hedging instruments to manage the risks in the changing business environment. These policies and procedures, developed in cooperation with the Alliance for Cooperative Energy Services Power Marketing LLC (“ACES”), an energy trading and risk management company, are designed to strike an appropriate balance between minimizing costs and reducing energy cost volatility. At December 31, 2010, due to changes in energy prices, we were required to post $3.0 million with our counterparties in accordance with the terms of our respective master power purchase and sales agreements with them.

 

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We have contractual arrangements with Virginia Power, the operator and co-owner of Clover and North Anna, which permit us to purchase reserve capacity and energy. We have the right 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.

In October 2009, we signed a long-term power purchase agreement with Exelon Generation Company, LLC (“Exelon”) in connection with our request for power supply proposal process. Under the terms of this agreement, Exelon is supplying 200 MW of energy and capacity to us for ten years beginning in June 2010.

Our purchased power costs for 2010, 2009, and 2008 were $462.9 million, $368.3 million, and $677.3 million, respectively.

As of December 31, 2010, our energy purchase commitments under the various agreements were as follows:

 

Year Ending December 31,

   Energy
Commitments
 
     (in millions)  

2011

   $ 216.6   

2012

     168.5   

2013

     150.9   
        
   $ 536.0   
        

NOTE 5—Wholesale Power Contracts

We currently have a wholesale power contract with each of our eleven member distribution cooperatives. The wholesale power contracts are “all-requirements” 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. These contracts were amended and restated in 2008, effective January 1 2009, and extend until January 1, 2054 and beyond this date unless either party gives the other at least three years notice of termination.

The two principal exceptions to the all-requirements obligations of the member distribution cooperatives relate to the ability of our mainland Virginia member distribution cooperatives to purchase hydroelectric power allocated to them from the Southeastern Power Administration, and the ability of all member distribution cooperatives to purchase energy from specified qualifying facilities under the Public Utility Regulatory Policies Act or similar laws. Purchases under these exceptions constituted approximately 2.0% of our member distribution cooperatives’ total energy requirements and approximately 2.7% of our member distribution cooperatives total capacity requirements in 2010.

Two additional limited exceptions to the all-requirements nature of the contract permit the member distribution cooperatives to receive up to the greater of five percent of their power requirements or five megawatts from owned generation or other suppliers, and to purchase additional power from other suppliers in limited circumstances following approval by our board of directors. Currently, none of our member distribution cooperatives have received any of their power requirements under these exceptions.

Each member distribution cooperative is required to pay us monthly for power furnished under its wholesale power contract in accordance with our formulary rate. The formulary rate, which has been filed with and accepted by FERC, is designed to recover our total cost of service and create a firm equity base. More specifically, the formulary rate is intended to meet all of our costs, expenses and financial obligations associated with our

 

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ownership, operation, maintenance, repair, replacement, improvement, modification, retirement and decommissioning of our generating plants, transmission system or related facilities, services provided to the member distribution cooperatives, and the acquisition and transmission of power or related services, 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);

 

   

any additional cost or expense, imposed or permitted by any regulatory agency; and

 

   

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.

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.

The formulary rate allows us to recover and refund amounts under our Margin Stabilization Plan. The Margin Stabilization Plan allows us to review our actual capacity-related cost of service and capacity revenues 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, generally in the succeeding calendar year. Each quarter we adjust operating revenues and accounts receivable—members or accounts payable—members, as appropriate, to reflect these adjustments. In 2010, 2009, and 2008, under our Margin Stabilization Plan, we reduced operating revenues by $22.5 million, $2.4 million, and $11.3 million, respectively, and increased accounts payable—members by the same amount. In 2010, our board of directors approved an additional equity contribution of $1.3 million that was collected during 2010 in accordance with our wholesale power contracts and our formulary rate.

Revenues from the following member distribution cooperatives for the past three years were as follows:

 

     Year Ended December 31,  
     2010      2009      2008  
     (in millions)  

Rappahannock Electric Cooperative (1)

   $ 245.4       $ 191.4       $ 201.4   

Shenandoah Valley Electric Cooperative (1)

     123.2         64.5         66.3   

Delaware Electric Cooperative, Inc.

     100.0         101.5         100.1   

Choptank Electric Cooperative, Inc.

     77.5         80.2         80.6   

Southside Electric Cooperative

     68.7         70.6         72.3   

A&N Electric Cooperative (2)

     51.0         53.3         52.9   

Mecklenburg Electric Cooperative

     42.0         43.4         44.2   

Prince George Electric Cooperative

     22.7         23.7         24.3   

Northern Neck Electric Cooperative

     20.9         21.7         21.6   

Community Electric Cooperative

     15.4         15.8         15.8   

BARC Electric Cooperative

     12.3         13.0         13.9   

Northern Virginia Electric Cooperative (3)

     —           —           272.1   
                          
   $ 779.1       $ 679.1       $ 965.5   
                          

 

(1)

Rappahannock Electric Cooperative and Shenandoah Valley Electric Cooperative acquired additional service territory in 2010.

(2)

A&N Electric Cooperative acquired additional service territory in 2008.

(3)

Northern Virginia Electric Cooperative (“NOVEC”) ceased to be a member of ODEC effective December 31, 2008.

 

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NOTE 6Fair Value Measurements

The fair value hierarchy gives the highest priority to quoted prices in active markets (Level 1) and the lowest priority to unobservable data (Level 3). In some cases, the inputs used to measure fair value might fall in different levels of the fair value hierarchy. The lowest level input that is significant to a fair value measurement in its entirety determines the applicable level in the fair value hierarchy. Assessing the significance of a particular input to the fair value measurement in its entirety requires judgment, considering factors specific to the asset or liability.

The following table summarizes our financial assets and liabilities measured at fair value on a recurring basis (at least annually) as of December 31, 2010 and December 31, 2009:

 

     December 31,
2010
     Quoted Prices
in Active
Markets for
Identical
Assets

(Level 1)
     Significant
Other
Observable
Inputs
(Level 2)
     Significant
Unobservable
Inputs

(Level 3)
 
     (in thousands)  

Nuclear decommissioning trust (1)

   $ 97,531       $ 97,531       $ —         $ —     

Unrestricted investments and other (2)(3)

     7,942         80         —           7,862   

Derivatives – renewable energy credit sales

     257         —           257         —     
                                   

Total Financial Assets

   $ 105,730       $ 97,611       $ 257       $ 7,862   
                                   

Derivatives–gas and power (4)

   $ 6,904       $ 6,831       $ 73       $ —     

Derivative–interest rate hedge (5)

     10,944         —           10,944         —     
                                   

Total Financial Liabilities

   $ 17,848       $ 6,831       $ 11,017       $ —     
                                   

 

     December 31,
2009
     Quoted Prices
in Active
Markets for
Identical
Assets

(Level 1)
     Significant
Other
Observable
Inputs

(Level 2)
     Significant
Unobservable
Inputs
(Level 3)
 
     (in thousands)  

Nuclear decommissioning trust (1)

   $ 85,437       $ 85,437       $ —         $ —     

Unrestricted investments and other (2)(3)

     1,869         56         —           1,813   
                                   

Total Financial Assets

   $ 87,306       $ 85,493       $ —         $ 1,813   
                                   

Derivatives–gas and power (4)

   $ 6,904       $ 6,152       $ 752       $ —     
                                   

Total Financial Liabilities

   $ 6,904       $ 6,152       $ 752       $ —     
                                   

 

(1)

For additional information about our nuclear decommissioning trust see Note 9—Investments.

(2)

Unrestricted investments and other includes investments that were available for sale and classified as level 1 related to equity securities.

(3)

Unrestricted investments and other includes investments that were available for sale and classified as level 3. As of December 31, 2010, we had $16.8 million of principal invested in five auction rate securities and preferred stock (“ARS”) and as of December 31, 2009, we had $17.3 million of principal invested in six ARS. As of December 31, 2010 and December 31, 2009, we had an unrealized loss of $5.6 million and $15.5 million, respectively, related to these ARS which was recorded as a regulatory asset in accordance with Accounting for Regulated Operations. For additional information, see Notes 9—Investments and Note 10—Regulatory Assets and Liabilities.

(4)

Derivatives–gas and power represent natural gas futures contracts and purchased power contracts, which are recorded on our balance sheet in deferred credits and other liabilities–other. For additional information about our derivative financial instruments, see Note 1—Summary of Significant Accounting Policies and Note 4—Power Purchase Agreements.

(5)

Derivative–interest rate hedge represents the fair value of the interest rate hedge. On May 14, 2010, we entered into an interest rate hedge with an initial notional amount of $300.0 million and a settlement rate tied to the 30-year U.S. Treasury bond. At December 31, 2010, the fair value of this interest rate hedge was a liability of $10.9 million, which is recorded on our balance sheet as a current liability.

 

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The following table presents the net change in our financial assets and liabilities measured at fair value on a recurring basis and included in the Level 3 fair value category for the year ended December 31, 2010:

 

     Year Ended
December 31, 2010
 
     (in thousands)  

Balance at January 1, 2010

   $ 1,813   

Total realized and unrealized gain/(loss):

  

Included in regulatory and other assets/liabilities

     9,932   

Included in earnings

     (3,558

Purchases, issuances and settlements

     (325

Transfers out of Level 3

     —     
        

Balance at December 31, 2010

   $ 7,862   
        

The unrealized gain (change in market value) was reported in regulatory assets in our Consolidated Balance Sheet as of December 31, 2010.

NOTE 7Derivatives and Hedging

We are exposed to market purchases of power and natural gas to meet the power supply needs of our member distribution cooperatives that are not met by our owned generation. In addition, we are exposed to fluctuations in long-term interest rates related to our issuance and refinancing of long-term debt. To manage this exposure, we utilize derivative instruments.

Changes in the fair value of our derivative instruments are recorded as a regulatory asset or regulatory liability. The change in these accounts is included in the operating activities section of our statement of cash flows.

Excluding contracts accounted for as normal purchase/normal sale, we had the following outstanding derivative instruments:

 

Commodity

   Unit of Measure    As of
December 31, 2010
Quantity
     As of
December 31, 2009
Quantity
 

Natural gas

   MMBTU      4,610,000         4,910,000   

Purchased power

   MWh      161,632         108,935   

Renewable energy credits

   REC      40,000         —     

Interest rate hedge

   US Dollars      300,000,000         —     

 

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The fair value of our derivative instruments, excluding contracts accounted for as normal purchase/normal sale, was as follows:

Fair Value of Derivative Instruments

 

         Fair Value  
   

Balance Sheet Location

   As of
December 31,
2010
     As of
December 31,
2009
 
         (in thousands)  

Derivatives in an asset position designated as hedging instruments:

     
Renewable energy credit sales   Prepayments and other    $ 257       $ —     
                   

Total derivatives in an asset position designated as hedging instruments

   $ 257       $ —     
                   
Derivatives in a liability position designated as hedging instruments:      
Natural gas futures contracts   Deferred credits and other liabilities-other    $ 6,831       $ 6,152   
Purchased power contracts   Deferred credits and other liabilities-other      73         752   
Interest rate hedge   Interest rate hedge      10,944         —     
                   

Total derivatives in a liability position designated as hedging instruments

   $ 17,848       $ 6,904   
                   

The Effect of Derivative Instruments on the Statement of Revenues, Expenses and Patronage Capital

for the Years Ended December 31, 2010 and 2009

 

Derivatives Accounted for Utilizing Regulatory
Accounting

   Amount of
Gain (Loss)
Recognized within
Regulatory

Asset/Liability for
Derivatives as of
December 31,
    

Location of Gain

(Loss) Reclassified

from Regulatory

Asset/Liability into

Income

   Amount of Gain
(Loss) Reclassified
from Regulatory
Asset/Liability into
Income for the

Year Ended
December 31,
 
   2010      2009         2010      2009  
     (in thousands)           (in thousands)  

Natural gas futures contracts (1)

   $ (7,256)       $  (6,152)       Fuel/Purchased power    $ (4,612)       $ (23,738)   

Purchased power contracts

     (73)         (752)       Purchased power      (365)         —     

Renewable energy credit sales

     257         —         Operating revenue      —           —     

Purchased power–excess sales

     —           —         Operating revenue      (669)         —     

Interest rate hedge

     (10,944)         —         Interest charges, net      —           —     
                                      

Total

   $ (18,016)       $ (6,904)          $ (5,646)       $ (23,738)   
                                      

 

(1)

Gain (loss) related to natural gas futures contracts is recorded in fuel and purchased power. Includes $424,860 of loss on contracts designated for January 2011 that were physically sold in December 2010 and the impact on the Consolidated Statement of Revenues, Expenses and Patronage Capital has been deferred until January 2011.

Our hedging activities expose us to credit-related risks. We use hedging instruments, including forwards, futures, financial transmission rights, and options, to manage our market price risks. Because we rely substantially on the use of hedging instruments, we are exposed to the risk that counterparties will default in performance of their obligations to us. Although we assess the creditworthiness 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 or failure to pay. 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 be more or less than the prices previously agreed upon with the defaulting counterparty.

 

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NOTE 8—Long-term Lease Transaction

On March 1, 1996, we entered into a long-term lease transaction with an owner trust for the benefit of an 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 immediately after we 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. At December 31, 2010, and December 31, 2009, the unamortized portion of the deferred gain was $7.6 million and $8.7 million, respectively.

We used a portion of the one-time rental payment of $315.0 million we received to enter into a payment undertaking agreement that would provide for substantially all of our periodic rent payments under the leaseback, and the fixed purchase price of the interest in the unit at the end of the term of the leaseback if we were to exercise our option to purchase the interest of the owner trust in the unit at that time. The payment undertaking agreement, which had a balance of $311.5 million at December 31, 2010, is issued by Cooperative Centrale Raiffeisen Boerenleenbank B.A., “Rabobank Nederland”, which has senior debt obligations which are currently rated “AAA” by S&P and “Aaa” by Moody’s, respectively. The amount of debt considered to be extinguished by in substance defeasance was $311.5 million and $309.8 million, at December 31, 2010 and December 31, 2009, respectively.

At the end of the term of the Unit 1 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.

 

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NOTE 9—Investments

Investments were as follows at December 31, 2010 and 2009:

 

                  Gross
Unrealized
Gains
     Gross
Unrealized
Losses
    Fair
Value
     Carrying
Value
 
                        

Description

  

Designation

   Cost             
                        (in thousands)               

December 31, 2010

                

Nuclear decommissioning trust (1)

                

Debt securities

   Available for sale    $ 41,049       $ 839       $ —        $ 41,888       $ 41,888   

Equity securities

   Available for sale      48 522         9,095         (2,211     55,406         55,406   

Cash and other

   Available for sale      237         —           —          237         237   
                                              

Total Nuclear Decommissioning Trust

      $ 89 808       $ 9,934       $ (2,211   $ 97 531       $ 97,531   
                                              

Lease deposits (2)

                

Government obligations

   Held to maturity    $ 89,355       $ 185       $ (405   $ 89,135       $ 89,355   
                                              

Total Lease Deposits

      $ 89,355       $ 185       $ (405   $ 89,135       $ 89,355   
                                              

Unrestricted investments (3)

                

Debt securities

   Available for sale    $ 7,723       $ —         $ —        $ 7,723       $ 7,723   

Equity securities

   Available for sale      139         —           —          139         139   
                                              

Total Unrestricted Investments

      $ 7,862       $ —         $ —        $ 7,862       $ 7,862   
                                              

Other

                

Equity securities

   Available for sale    $ 78       $ 2       $ —        $ 80       $ 80   

Non-marketable equity investments (4)

   Equity      1,769         —           —          1,769         1,769   
                                              

Total Other

      $ 1,847       $ 2       $ —        $ 1,849       $ 1,849   
                                              
              Total Carrying Value       $ 196,597   
                      

December 31, 2009

                

Nuclear decommissioning trust (1)

                

Debt securities

   Available for sale    $ 39,289       $ —         $ (2,020   $ 37,269       $ 37,269   

Equity securities

   Available for sale      46,577         3,661         (2,142     48,096         48,096   

Cash and other

   Available for sale      72         —           —          72         72   
                                              

Total Nuclear Decommissioning Trust

      $ 85,938       $ 3,661       $ (4,162   $ 85,437       $ 85,437   
                                              

Lease deposits (2)

                

Government obligations

   Held to maturity    $ 87,052       $ 138       $ (7,213   $ 79,977   <