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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, 2011

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:

NONE

 

 

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 Securities Exchange Act (the “Exchange Act”).    Yes  x    No  ¨

Indicate by check mark whether the Registrant: (1) has filed all reports required to be filed by Section 13 or 15(d) of the Exchange Act 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  ¨    No  x

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  x    No  ¨

Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K (§ 229.405) 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. The Registrant is a membership corporation and has no authorized or outstanding equity securities.

 

 

Documents incorporated by reference:

NONE

 

 

 

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OLD DOMINION ELECTRIC COOPERATIVE

2011 ANNUAL REPORT ON FORM 10-K

 

Item Number				Page Number
		Glossary of Terms			1
		PART I
1.		Business			3
1A.		Risk Factors			15
1B.		Unresolved Staff Comments			21
2.		Properties			21
3.		Legal Proceedings			23
4.		Reserved			23
		PART II
5.		Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities			24
6.		Selected Financial Data			24
7.		Management’s Discussion and Analysis of Financial Condition and Results of Operations			26
7A.		Quantitative and Qualitative Disclosures About Market Risk			44
8.		Financial Statements and Supplementary Data			47
9.		Changes in and Disagreements with Accountants on Accounting and Financial Disclosure			73
9A.		Controls and Procedures			73
9B.		Other Information			74
		PART III
10.		Directors, Executive Officers and Corporate Governance			75
11.		Executive Compensation			78
12.		Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters			85
13.		Certain Relationships and Related Transactions, and Director Independence			85
14.		Principal Accountant Fees and Services			85
		PART IV
15.		Exhibits and Financial Statement Schedules			86
		SIGNATURES

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GLOSSARY OF TERMS

The following abbreviations or acronyms used in this Form 10-K are defined below:

 

 

Abbreviation or Acronym		Definition
ACES		Alliance for Cooperative Energy Services Power Marketing, LLC
ARS		Securities originally issued as auction rate securities, including those that converted to preferred stock
CAA		Clean Air Act
CAIR		Clean Air Interstate Rule
CAIRNOXAllowances		Annual NOx emissions allowances under CAIR
CAIROS Allowances		Annual ozone season NOx emissions allowances under CAIR
CAMR		Clean Air Mercury Rule
CCRs		Coal combustion residuals
CEO		Chief Executive Officer
CFO		Chief Financial Officer
CI		Compression ignition
COO		Chief Operating Officer
Clover		Clover Power Station
CO2		Carbon dioxide
CSAPR		Cross State Air Pollution Rule
DPSC		Delaware Public Service Commission
DOE		U.S. Department of Energy
EP		Essential Power, LLC, formerly known as North American Energy Alliance, LLC
EPA		Environmental Protection Agency
EPACT		Energy Policy Act of 2005, as amended
Exelon		Exelon Generation Company, LLC
FERC		Federal Energy Regulatory Commission
GAAP		Accounting principles generally accepted in the United States
GHG		Greenhouse gases
Hg		Mercury
Indenture		Second Amended and Restated Indenture of Mortgage and Deed of Trust, dated January 1, 2011, with Branch Banking and Trust Company, as trustee, as amended and supplemented
IRC		Internal Revenue Code of 1986, as amended
kV		Kilovolt
MACT		Maximum Achievable Control Technology
MATS		Mercury and Air Toxics Standards
Moody’s		Moody’s Investors Services
MPSC		Maryland Public Service Commission
MW		Megawatt(s)
MWh		Megawatt hour(s)
NAAQS		National Ambient Air Quality Standards
NEIL		Nuclear Electric Insurance Limited
NERC		North American Electric Reliability Corporation
Norfolk Southern		Norfolk Southern Railway Company
North Anna		North Anna Nuclear Power Station
North Anna Unit 3		A potential additional nuclear-powered generating unit at North Anna
NOVEC		Northern Virginia Electric Cooperative
NOx		Nitrogen oxide
NRC		U.S. Nuclear Regulatory Commission
NRECA		National Rural Electric Cooperatives Association
ODEC, We, Our		Old Dominion Electric Cooperative
Outside Directors		Members of our board of directors who are not employed by our member distribution cooperatives

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Potomac Edison		Potomac Edison Company of Virginia
PJM		PJM, Interconnection, LLC
PM		Particulate matter
PPA		Pension Protection Act
Rabobank		Cooperative Centrale Raiffeisen Boerenleenbank B.A., “Rabobank Nederland”
RCRA		Resource Conservation and Recovery Act, as amended
REC		Rappahannock Electric Cooperative
RGGI		Regional Greenhouse Gas Initiative
RHI		Regional Headquarters, Inc.
RPM		Reliability Pricing Model
RPS		Renewable portfolio standard
RTO		Regional transmission organization
RUS		U.S. Department of Agriculture Rural Utilities Service
S&P		Standard & Poor’s Ratings Services
SEPA		Southeastern Power Administration
SO2		Sulfur dioxide
SVEC		Shenandoah Valley Electric Cooperative
TEC		TEC Trading, Inc.
TMDL		Total maximum daily load
VDEQ		Virginia Department of Environmental Quality
Virginia Power		Virginia Electric and Power Company
VMDA		Virginia, Maryland, and Delaware Association of Electric Cooperatives
VSCC		Virginia State Corporation Commission
XBRL		Extensible Business Reporting Language

 

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PART I

ITEM 1. BUSINESS

OVERVIEW

Old Dominion Electric Cooperative was incorporated under the laws of the Commonwealth of Virginia in 1948 as a not-for-profit power supply cooperative. We 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 550,000 retail electric consumers (meters), representing a total population of approximately 1.2 million people in 2011.

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, 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 IRC Section 501(c)(12).

We are not a party to any collective bargaining agreement. We had 109 employees as of March 2, 2012.

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.

 

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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 70 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 2011 are as follows:

 

Member Distribution Cooperatives		Revenues				Total Revenues
		(in millions)				(%)
Rappahannock Electric Cooperative		$	290.4				34.0	%
Shenandoah Valley Electric Cooperative			159.8				18.7
Delaware Electric Cooperative, Inc.			97.6				11.4
Choptank Electric Cooperative, Inc.			76.6				9.0
Southside Electric Cooperative			67.5				7.9
A&N Electric Cooperative			50.1				5.9
Mecklenburg Electric Cooperative			41.8				4.9
Prince George Electric Cooperative			22.5				2.6
Northern Neck Electric Cooperative			20.5				2.4
Community Electric Cooperative			14.7				1.7
BARC Electric Cooperative			12.4				1.5
Total		$	853.9				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 rural, suburban, 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.

Our member distribution cooperatives’ sales of energy in 2011 totaled approximately 11,847,449 MWh. These sales were divided by customer class as follows:

 

Customer Class		Percentage of MWh Sales				Percentage of Customers
Residential			59.6	%			89.6	%
Commercial and industrial			39.1				9.4
Other			1.3				1.0

From 2006 through 2011, our eleven member distribution cooperatives experienced an average annual compound growth rate of approximately 6.4% in the number of customers and an average annual compound growth rate of 9.3% 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. Additionally, our member distribution cooperatives can expand their service territories through acquisition. Excluding the Potomac Edison Acquisition and the SVEC disposition, we estimate that our eleven member distribution cooperatives experienced an average annual compound growth rate of approximately 2.0% in the number of customers and an average annual compound growth rate of approximately 3.1% in energy sales measured in MWh. See “Management’s Discussion and Analysis of Financial Condition and Results of Operations—Member Distribution Cooperatives – Potomac Edison Acquisition” in Item 7.

Our eleven member distribution cooperatives’ average number of customers per mile of energized line has increased approximately 16.0% since 2006 to approximately 9.4 customers per mile in 2011. System densities of our member distribution cooperatives in 2011 ranged from 6.4 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 the Potomac Edison Acquisition and the SVEC disposition, we estimate the average number of customers per mile of energized line increased approximately 4.7% since 2006 to approximately 8.5 customers per mile in 2011. In 2011, the average service density for all distribution electric cooperatives in the United States was approximately 7.0 customers per mile.

Delaware and Maryland each currently grant all retail customers the right to choose their power supplier. Virginia currently grants only a limited number of 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.

 

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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 SEPA, and the ability of all member distribution cooperatives to purchase energy from specified qualifying facilities under the Public Utility Regulatory Policies Act, as amended, or similar laws. Purchases under these exceptions constituted approximately 1.0% of our member distribution cooperatives’ total energy requirements and approximately 2.8% of our member distribution cooperatives’ total capacity requirements in 2011.

Two additional limited exceptions to the all-requirements nature of the contract permit the member distribution cooperatives to receive up to the greater of 5.0% of their power requirements or 5 MW from owned generation or other suppliers, and to purchase additional power from other suppliers in limited circumstances following approval by our board of directors. To date, 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. 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.

Regulation

Of our 11 member distribution cooperatives, 10 participate in the RUS loan or guarantee programs. These member distribution cooperatives have entered into loan documents with RUS with affirmative and negative covenants, including with respect to matters 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. We understand that the principal loan documentation of our member distribution cooperative which does not participate in RUS loan or guarantee programs contains similar covenants.

 

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Our member distribution cooperatives in Virginia are subject to rate regulation by the 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 rates for distribution service by a maximum net increase or decrease of 5%, on a cumulative basis, in any three year period without approval by the VSCC.

The MPSC regulates the rates and services offered by our Maryland member distribution cooperative, other than wholesale power costs which are a pass through to the member distribution cooperative’s customers. Our Delaware member distribution cooperative is not regulated by the DPSC, including with respect to wholesale power costs which are a pass through to its 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, 2012, 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 an alternative power supplier.

In Virginia, retail choice in the selection of a power supplier is available to customers that consume at least 5 MW of power individually or in the aggregate (with aggregation subject to the approval of the VSCC), and 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 noncoincident peak demand exceeded 90 MW. Additionally, all customers are permitted to select an alternative power supplier that provides 100% green or renewable power if their incumbent utility, such as one of our member distribution cooperatives, does not offer this same option. As of March 2, 2012, seven of our nine Virginia member distribution cooperatives provided this option. Currently, we do not anticipate that these conditions related to retail choice will have a material impact on our financial condition or results of operations.

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 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 $200.0 million in credit support to TEC. See “Management’s Discussion and Analysis of Financial Condition and Results of Operations—Liquidity and Capital Resources—Significant Contingent Obligations—TEC Guarantees” in Item 7.

 

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POWER SUPPLY RESOURCES

General

We provide power to our members through a combination of our interests in Clover, a coal-fired generating facility; North Anna, a nuclear power station; 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 energy in the open market. Our power supply resources for the past three years were as follows:

 

		Year Ended December 31,
		2011								2010								2009
		(in MWh and percentages)
Generated:
Clover			2,583,593				19.5	%			3,092,662				24.3	%			2,787,184				28.4	%
North Anna			1,452,147				10.9				1,554,338				12.2				1,763,502				18.0
Louisa			111,835				0.8				382,211				3.0				93,125				0.9
Marsh Run			149,396				1.1				624,951				4.9				99,842				1.0
Rock Springs			125,119				1.0				193,498				1.5				29,906				0.3
Distributed Generation			863				—				897				—				457				—
Total Generated			4,422,953				33.3				5,848,557				45.9				4,774,016				48.6
Purchased:
Other than renewable			8,423,465				63.5				6,692,647				52.5				5,019,808				51.2
Renewable(1)			429,166				3.2				210,702				1.6				21,393				0.2
Total Purchased			8,852,631				66.7				6,903,349				54.1				5,041,201				51.4
Total Available Energy			13,275,584				100.0	%			12,751,906				100.0	%			9,815,217				100.0	%

 

(1)	Related to our contracts from renewable facilities from which we purchase renewable energy credits. We sell these renewable energy credits to our member distribution cooperatives and any remaining renewable energy credits are sold to non-members.

In 2011, our member distribution cooperatives’ peak demand occurred in January and was 2,566 MW, excluding power supplied by SEPA which is not an ODEC resource. See “Members—Member Distribution Cooperatives—Wholesale Power Contracts. “Under normal weather conditions, 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 23.4% of our capacity obligations and 30.4% of our energy requirements in 2011. Louisa, Marsh Run and Rock Springs, our peaking generating facilities, collectively provided 43.8% of our 2011 capacity obligations, and 2.9% of our 2011 energy requirements. For a description of our generating facilities, see “Properties” in Item 2. In 2011, we obtained the remainder of our capacity obligations through the PJM RPM capacity auction process and purchased capacity contracts. 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 ACES, an energy trading and risk management company. 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.

On August 23, 2011, a magnitude 5.8 earthquake near Mineral, Virginia caused the two reactors at North Anna to shut down immediately, as designed. Virginia Power, the co-owner and operator of North Anna, informed us that some of the earthquake’s vibrations briefly exceeded North Anna’s licensing design basis at certain

 

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frequencies; however, Virginia Power’s inspections showed no significant damage to equipment at the station from the earthquake. The reactors were placed in cold shutdown condition pending completion of an NRC inspection and review. On November 11, 2011, the NRC approved the restart of the two reactors: later that day, North Anna Unit 1 was restarted and began generating electricity on November 15, 2011; on November 20, 2011, North Anna Unit 2 was restarted and began generating electricity on November 22, 2011.

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 targets for how our projected power needs will be met, and one of the ways we manage these targets 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 Power at the NRC for a license to construct and operate a new reactor at North Anna, North Anna Unit 3. In October 2010, Virginia Power announced that it would slow its pursuit of North Anna Unit 3 and planned to reassess the schedule for construction of the unit in 2013. We evaluated our continued participation in this project and on February 28, 2011, we announced our decision not to participate in the development or ownership of North Anna Unit 3. We formally withdrew as a participant in the project and transferred our rights relating to North Anna Unit 3 to Virginia Power on December 16, 2011.

We are continuing 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. 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. 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 the residents’ allegation of inadequate notice of a public hearing. During 2011, the Surry County Circuit Court voided the zoning approvals. We repeated the application process and on March 5, 2012, we received the necessary zoning approvals for the tract located in Surry County.

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.

PJM

PJM is an 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 is primarily responsible for ensuring 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 transmission grid of its participants. 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 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 PJM transmission system. We have agreements with PJM which provide us with access to transmission facilities under its 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 the most economical 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 capacity obligations. These obligations can be met through a combination of owned generation resources, and purchases under bilateral agreements and forward capacity auctions under PJM’s RPM. The purpose of PJM’s RPM is to develop a longer-term pricing program for capacity resources, to provide localized pricing for capacity, and to reduce the resulting investment risk to owners of generating resources 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, 2015. Each annual auction is 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 consultation with ACES, are designed to strike an appropriate balance between minimizing costs and reducing energy cost volatility. See “Quantitative and Qualitative Disclosures About Market Risk” in Item 7A.

We have contractual arrangements with Virginia Power, the operator and co-owner of Clover and North Anna, under which we purchase reserve capacity. The purchase of reserve capacity allows for the purchase of reserve energy. These arrangements remain in effect 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 2009, we signed a long-term power purchase agreement with 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.

Renewable Energy

Our power supply resources include renewable energy resources through power purchase contracts. We have four long-term agreements for wind generated power under which we have contracted to purchase power and renewable energy credits. Three of these wind generated power projects are operational, two are located in Pennsylvania and one is in Maryland. The fourth project is located in Pennsylvania and is scheduled to be operational in 2013. Additionally, we have renewable resources through energy purchase contracts from three

 

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landfill gas-to-energy projects, one each in Maryland, Delaware, and Virginia. We also purchase renewable resources through an energy purchase contract for a hydroelectric facility located in 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 responsibility to procure sufficient coal for the operation of the facility. Virginia Power advises us it uses 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 we do not control their terms or duration. As of December 31, 2011, and December 31, 2010, there was a 73 day and a 38 day supply of coal at Clover, respectively. 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 it primarily uses 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 we 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 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. 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. The government’s initial brief in the appeal was filed in June 2010. In the second quarter of 2011, the Federal Appeals Court issued a decision affirming the trial court’s damages award. The government did not seek rehearing of the Federal Appeals Court decision or seek review by the U.S. Supreme Court. During the third quarter of 2011, Virginia Power received a settlement amount for spent fuel costs representing certain spent nuclear fuel-related costs incurred through June 30, 2006. Virginia Power then paid us our proportionate share of the payment, $7.8 million, which we recorded as a $6.7 million reduction to fuel expense and a $1.1 million reduction to operations and maintenance expense. We currently anticipate that Virginia Power will seek reimbursement for certain spent nuclear fuel-related costs incurred subsequent to June 30, 2006; however, due to the uncertainty of future collection, we have not recorded a receivable.

Natural Gas

Our three combustion turbine facilities are powered by natural gas and are located adjacent to natural gas transmission pipelines. We are responsible for procuring the natural gas to be used by all of our units at Louisa, Marsh Run, and Rock Springs. We have developed and utilize a natural gas supply strategy for providing natural gas to each of the three combustion turbine facilities. The strategy includes securing transportation contracts and incorporating the ability to use No. 2 distillate fuel oil as a backup 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.

 

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REGULATION

General

We are subject to regulation by FERC and, to a limited extent, state public service commissions. Some of our operations also are subject to regulation by the VDEQ, 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 an energy adjustment rate (previously referred to as 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 DPSC, and the MPSC do not have jurisdiction over our rates, charges, and services.

Other Regulation

In addition to its jurisdiction over rates, FERC also 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 DPSC, and the MPSC 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. Our direct capital expenditures for environmental control equipment at our generating facilities were immaterial in 2011.

Clean Air Act

Currently, the most pertinent environmental law affecting our operations is the CAA. The CAA requires, among other things, that owners and operators of fossil fuel-fired power stations limit emissions of SO₂, PM, Hg, and NO_x. Discussed below are certain standards and regulations under the CAA. Additionally, regulatory programs and/or taxes are being proposed to limit emissions of CO₂ and other GHG.

 

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CAIR, a rule under the CAA, requires significant reductions of SO₂ and NO_x 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 EPA to make the corrections.

In response to the Court’s remanding of CAIR, the EPA proposed CSAPR, also known as the “Transport Rule,” that would require 27 states and the District of Columbia to significantly improve air quality by reducing power plant SO₂ and NO_x emissions that contribute to ozone and fine particle pollution in other states. Emissions reductions were scheduled to take effect in 2012. However, on December 30, 2011, the U.S. Court of Appeals for the District of Columbia Circuit issued its ruling to stay implementation of CSAPR pending judicial review. Because of this action, CAIR will stay in effect until the court decision is made.

The VDEQ adopted 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 required 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.

With respect to SO₂, under the CAA’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.

Pursuant to the CAA and CAIR, both Virginia and Maryland have enacted regulations to reduce the emissions of NO_x by establishing NO_x cap and trade programs similar to the federal SO₂ allowance programs. Under CAIR, allowances are required for annual CAIRNO_x Allowances and CAIROS Allowances. Clover is allocated a certain number of CAIRNO_x Allowances and CAIROS Allowances. If Clover emits more NO_x emissions than the allotted allowances cover, then additional CAIRNO_x Allowances and CAIROS Allowances will have to be purchased. We can purchase CAIROS Allowances from Virginia Power under an existing agreement or purchase them from the market.

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

Clear Air Mercury Rule

Clover is currently our only generating facility impacted by the EPA’s CAMR. In 2005, the EPA issued 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 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 VDEQ 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 VDEQ’s adoption of the Mercury Budget Trading regulations; however, there will not be a cap and trade program if CAMR ultimately does not go into effect.

 

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On December 16, 2011, the EPA signed MATS for utility boilers that will regulate mercury, acid gases, and other air toxic organic compounds from coal-fired power plants. Coal and oil-fired power plants will need to meet MACT standards to control the pollutants in MATS within three years of publication in the Federal Register. It is anticipated that MATS regulation will be published in the Federal Register in March 2012 making the compliance date March 2015. We do not anticipate that any additional measures will be required at Clover to comply with MATS 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 2009, the EPA finalized an “Endangerment Finding” under the CAA that obligated the agency to issue GHG standards for motor vehicles. The implementation of vehicle standards made GHG emissions subject to regulation under the CAA for the first time. Subsequently, any air pollutants subject to regulation under the CAA 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 CAA permitting programs for affected stationary sources of GHG emissions. In 2010, the EPA issued the “Tailoring Rule” to address GHG emissions from stationary sources under the CAA 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. In late 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, and 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 fuel-fired generation by ODEC.

Also, there are numerous actions at the state and regional level, including 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 2009 levels, and then reducing emissions 10% by 2019. Since Rock Springs is located within Maryland, we are required to purchase RGGI CO₂ emissions allowances for each ton of CO₂ emitted by our Rock Springs units. The regulations require all allowances to be auctioned rather than allocated directly to utilities.

Reciprocating Internal Combustion Engine National Emissions Standards for Hazardous Air Pollutants

In March 2010, the Reciprocating Internal Combustion Engine National Emissions Standards for Hazardous Air Pollutants were promulgated for existing CI diesel engines. Under these standards, diesel engines used for emergency/black start power or for firewater pumping at the power stations will only have to maintain records of the hours of operation and document regular preventive maintenance. Our five distributed generation facilities that are operated at various remote substations have the capability to operate for peak shaving purposes in addition to supplying power during emergency situations. Based upon continuing this capability, we are preparing to install required control equipment and monitoring systems. In addition to the capital improvements, we must comply with ongoing semi-annual reporting and triennial compliance testing requirements. The compliance date for these engines is May 3, 2013.

Revised National Ambient Air Quality Standards

Under the CAA, the EPA is required to issue national ambient air quality standards. Enforcement of the national ambient air quality standards is the responsibility of the states. The current standard for ozone is 75 parts per billion. ODEC continues to monitor the progress of this standard and the states’ nonattainment area designation

 

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submittals. This continues to be an issue that may impact permitting of new generation depending upon location. Additionally, in June of 2010, the EPA finalized the one hour SO₂ standard and the current standard is 75 parts per billion. There is currently not enough information to determine the potential impact on ODEC operations.

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

In 2010, the EPA formally proposed to regulate CCRs under the RCRA to address the risks from disposal 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 the first option, 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. 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 us to incur significant additional costs under this option. Under the second option, CCR’s would be regulated under subtitle D of RCRA as solid waste.

Future Regulation

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

 

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Historically, our power supply strategy has relied substantially on purchases of energy from other power suppliers. In 2011, we purchased approximately 66.7% 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 2011 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 related 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 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 developed strategies to attempt to meet our power requirements in an 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 “Quantitative and Qualitative Disclosures About Market Risk” in Item 7A.

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:

 

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Weather;

 

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Supply and demand;

 

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The availability of competitively priced alternative energy sources;

 

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The transportation of fuels;

 

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

 

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Energy transmission or natural gas transportation capacity constraints;

 

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Impact of implementation of new technologies in the power industry;

 

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

 

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

 

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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 2011,64.1% of our revenues from sales to our member distribution cooperatives were received from our three largest members, REC, SVEC, and Delaware Electric Cooperative, Inc.

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.

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

We have an 11.6% undivided ownership interest in North Anna which provided approximately 10.9% of our energy requirements in 2011. Ownership of an interest in a nuclear generating facility involves risks, including:

 

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

 

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

 

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

 

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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 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” in Item 1.

 

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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.

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.

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. S&P, Moody’s, and Fitch Inc., currently rate our outstanding obligations issued under our 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—Liquidity and Capital Resources—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 $311.8 million at December 31, 2011, was issued by Rabobank, which has senior debt obligations which are currently rated “AA” by S&P and “Aaa” by Moody’s. If Rabobank 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, 2011, the total balance of our remaining lease obligation was $346.5 million. See “Management’s Discussion and Analysis of Financial Condition and Results of Operations—Liquidity and Capital Resources—Significant Contingent Obligations—Clover Lease” in Item7.

Failure to comply with reliability standards could subject us to substantial monetary penalties.

As a result of EPACT, owners, operators and users of bulk electric systems, including ODEC, are subject to mandatory reliability standards enacted by 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 NERC Standards Committee, which includes

 

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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 pursued legislation that calls for the reduction of emissions of GHG. Legislative proposals have focused on regulation of CO₂ emissions and have included either taxing the emission of CO₂ or instituting a capandtrade program requiring allowances to emit CO₂ in the operation of coal-fired and other fossil fuel-firedgenerating facilities. The additional costs related to a tax on CO₂ emissions or a capandtrade 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 less often than they are currently and 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—Clean Air Act—Greenhouse Gas Initiative” in Item 1), 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 also proposed a federal 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. However, to date no legislation has been passed and the details of this plan are not fully available; therefore, 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. 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 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 to make up our allocable portion of any under funding.

Implementation of the Dodd-Frank Wall Street Reform and Consumer Protection Act could increase our costs.

The Dodd-Frank Wall Street Reform and Consumer Protection Act enacted in July 2010 could impact our use of over-the-counter derivatives. Regulations to implement the Dodd-Frank Act could impose additional requirements on the use of over-the-counter derivatives, such as margin and reporting requirements, which could affect both the use and cost of over-the-counter derivatives. The impact, if any, cannot be determined until regulations are finalized.

 

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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.

War, acts and threats of terrorism, sabotage, natural disaster, and other significant events could adversely affect our operations.

We cannot predict the impact that any future terrorist attacks, sabotage, or natural disaster may have on the energy industry in general, or on our business in particular. Any retaliatory military strikes or sustained military campaign may affect our operations in unpredictable ways, such as changes in insurance markets and disruptions of fuel supplies and energy markets. In addition, infrastructure facilities, such as electric generation and electric transmission and distribution facilities could be direct targets of, or indirect casualties of, an act of terror or sabotage. Furthermore, the physical or cyber security compromise of our facilities could adversely affect our ability to manage these facilities effectively. Instability in financial markets as a result of terrorism, war, sabotage, natural disasters, pandemic, credit crises, recession or other factors could result in a significant decline in the U.S. economy, and the increased cost of insurance coverage, any of which could negatively impact our results of operations and financial condition.

 

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ITEM 1B. UNRESOLVED STAFF COMMENTS

None

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(1)

Clover

50.0

%(2)

Halifax County, Virginia

Coal

Unit 1 – 10/1995 Unit 2 – 03/1996

(3)

215 MW 218 MW

433 MW

North Anna

11.6

%

Louisa County, Virginia

Nuclear

Unit 1 – 06/1978 Unit 2 – 12/1980

(4)  (4)(5)

107 MW 109 MW

216 MW

Louisa

100.0

%

Louisa County, Virginia

Natural Gas(6)

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(6)

Unit 1 – 09/2004 Unit 2 – 09/2004 Unit 3 – 09/2004

168 MW 168 MW 168 MW

504 MW

Rock Springs

50.0

%(7)

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

2,013 MW

 

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

(2)	Our interest in Clover Unit 1 is subject to a long-term lease. See “Clover—Clover Lease” below.

(3)	In 2011, a major turbine maintenance project was completed on Clover Unit 2 resulting in a revised net capacity entitlement.

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

(5)	In 2011, an upgrade to the main steam turbines was completed on North Anna Unit 2 resulting in a revised net capacity entitlement.

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

(7)	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.

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 “Business—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.

 

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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, 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—Liquidity and Capital Resources—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 “Business—Power Supply Resources—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. See “Business—Power Supply Resources—General” in Item 1 for a discussion of the 2011 earthquake which caused the two reactors at North Anna to shut down.

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

Rock Springs is currently operated and maintained by Essential Power Operating Co., LLC, an affiliate of EP, pursuant to a service agreement under which Essential Power 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.

 

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Distributed Generation Facilities

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

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 kV transmission lines and a 500 kV substation at Rock Springs jointly with EP. 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

The Indenture grants a 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, including all of our long-term indebtedness, are secured equally and ratably by the trust estate under the Indenture.

ITEM 3. LEGAL PROCEEDINGS

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, 2011, 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,
		2011				2010				2009				2008				2007
		(in thousands, except ratios)
Statement of Operations Data
Operating Revenues		$	891,539			$	844,470			$	713,169			$	1,040,751			$	963,094
Operating Margin			62,590				53,671				57,736				61,417				62,085
Net Margin attributable to ODEC(1)			10,807				10,158				9,687				11,784				16,035
Margins for Interest Ratio			1.22				1.23				1.21				1.23				1.30

 

		December 31,
		2011				2010				2009				2008				2007
		(in thousands, except ratios)
Balance Sheet Data
Net Electric Plant		$	1,012,905			$	1,037,404			$	1,008,373			$	1,016,579			$	1,031,727
Total Investments			235,199				196,597				176,076				199,129				334,269
Other Assets			325,876				278,434				255,463				290,037				305,751
Total Assets		$	1,573,980			$	1,512,435			$	1,439,912			$	1,505,745			$	1,671,747
Patronage capital		$	350,485			$	339,678			$	329,520			$	319,833			$	309,112
Non-controlling interest			13,093				13,166				13,178				12,787				11,431
Long-term debt			766,128				449,798				688,736				711,675				787,028
Long-term debt due within one year(2)			28,292				238,917				22,917				22,917				29,667
Revolving credit facilities			—				7,043				26,954				62,000				—
Total Capitalization		$	1,157,998			$	1,048,602			$	1,081,305			$	1,129,212			$	1,137,238
Equity Ratio(3)			30.6	%			32.8	%			30.9	%			28.6	%			27.5	%

 

(1)	Net Margin for 2010 and 2007 includes an additional equity contribution of $1.3 million and $4.0 million, respectively.

(2)	For 2010, long-term debt due within one year includes our $215.0 million 2001 Series A Bonds which were repaid on June 1, 2011.

(3)	Equity ratio equals patronage capital divided by the sum of our long-term debt, long-term debt due within one year, revolving credit facilities, 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.

In 2011, two natural disasters occurred. On August 23, 2011, a magnitude 5.8 earthquake near Mineral, Virginia caused the two reactors at North Anna to shut down immediately, as designed. This event resulted in the need for additional purchased power and operations and maintenance expense during the quarter, although the impact was not material to our financial results. The reactors were placed in cold shutdown condition pending completion of the NRC inspection and review. On November 11, 2011, the NRC approved the restart of the two reactors: on November 11, 2011, North Anna Unit 1 was restarted and began generating electricity on November 15, 2011; on November 20, 2011, North Anna Unit 2 was restarted and began generating electricity on November 22, 2011. Additionally, on August 27, 2011, our member distribution cooperatives’ service territories were impacted by Hurricane Irene, causing the loss of power for a significant number of our member distribution cooperatives’ customers for up to seven days. This resulted in decreased power requirements during this timeframe.

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) in western Virginia (the “Potomac Edison Acquisition”). This resulted in an increase in sales to our member distribution cooperatives and additional purchased power expense for 2011 as compared to 2010.

Fuel expense and purchased power expense are significantly affected by the operations of our owned generation. PJM’s economic dispatch of our combustion turbine facilities and Clover, and the availability of North Anna resulted in decreased fuel expense and increased purchased power volume for 2011 as compared to 2010.

 

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In February 2011, we made the determination not to participate in North Anna Unit 3 and on December 16, 2011, we finalized our withdrawal as a participant in the project and transferred our interest to Virginia Power. Related to this decision, in 2011, we reclassified the corresponding construction work in progress as of February 2011 to a regulatory asset. See “Decision Not to Participate in North Anna Unit 3” below.

In the second quarter of 2011, we issued $350.0 million of first mortgage bonds under the Indenture. A portion of the proceeds of the issuance was used to repay our $215.0 million 2001 Series A Bonds due June 1, 2011.

Weather affects the demand for electricity. We experienced milder weather during the year ended December 31, 2011, especially during the fourth quarter, as compared to the same period in 2010, which resulted in a reduction in our member distribution cooperatives’ customers’ requirements for power.

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 our Margin Stabilization Plan. In accordance with our Margin Stabilization Plan, during 2011 we reduced operating revenues by $14.9 million. During the third quarter of 2011, we refunded $10.0 million and as of December 31, 2011, we had $4.9 million recorded as accounts payable-members. See “Critical Accounting Policies—Margin Stabilization Plan” below.

Member Distribution Cooperatives – Potomac Edison Acquisition

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 the Potomac Edison Acquisition, net of SVEC’s disposition, will increase our MWh and 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 is serving the additional power requirements resulting from the Potomac Edison Acquisition. 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 expired on June 30, 2011.

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 the Potomac Edison Acquisition. The aggregate transition fee is approximately $66.7 million; of which approximately $16.6 million and $7.4 million was recorded in 2011 and 2010, respectively. 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.

Decision Not to Participate in North Anna Unit 3

In February 2011, we made the determination not to participate in North Anna Unit 3. As of December 31, 2010, we had $21.3 million of construction work in progress related to North Anna Unit 3, and had incurred approximately $1.8 million in financing-related costs that were included in deferred charges–other. During 2011, we established a regulatory asset and reclassified the $21.3 million of construction work in progress costs. The $1.8 million in financing-related costs were expensed in the first quarter of 2011 as administrative and general expense. As of December 31, 2011, our regulatory asset balance was $22.7 million which includes the $21.3 million referenced above and additional costs incurred during 2011 prior to our withdrawal notice. We continued to incur costs related to North Anna Unit 3 until the finalization of our withdrawal and the transfer of our interest in the project to Virginia Power on December 16, 2011. On this date we received payment of $11.3 million from Virginia Power, which included reimbursement of $10.4 million of costs incurred from February 2011 until December 16, 2011, including interest, and $0.9 million for the sale of land related to North Anna Unit 3. Reimbursement of costs recorded in the regulatory asset to us by Virginia Power is subject to the VSCC approval. We cannot currently estimate if or when Virginia Power will seek approval from the VSCC. If these costs are not determined to be collectible from Virginia Power, we will collect them from our member distribution cooperatives through our formulary rate.

 

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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.

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 our 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 2011, 2010, and 2009, under our Margin Stabilization Plan, we reduced operating revenues by $14.9 million, $22.5 million, and $2.4 million, respectively. During the third quarter of 2011, we refunded $10.0 million of the $14.9 million.

 

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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, 2011, North Anna’s nuclear decommissioning asset retirement obligation totaled $65.2 million, which represented approximately 89.1% 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.

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, 2011, for our asset retirement obligations related to nuclear decommissioning would have been $13.8 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

 

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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.

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, an energy adjustment rate (previously referred to as 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 energy 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 an energy adjustment rate. We review our energy costs at least every six months to determine whether the base energy rate and the current energy adjustment rate together are adequately recovering our actual and anticipated energy costs, and revise the energy adjustment rate accordingly. Since the energy 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.

 

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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 its 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 energy 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” above. 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.

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” above. Estimated energy costs are collected during the period through the base energy rate and the energy 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” above.

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.

 

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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.

 

•

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.

In 2011, we satisfied the majority of our member distribution cooperatives’ capacity requirements and approximately one third 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 “Business—Power Supply Resources” in Item 1 and “Properties” in Item 2.

PJM

PJM is an 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 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 the most economical 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 “Business—Power Supply Resources—PJM” in Item 1.

 

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Generating Facilities

Our operating expenses, and consequently our rates to our member distribution cooperatives, are significantly affected by the operations of our base load generating facilities, Clover and North Anna. Base load generating facilities, particularly nuclear power plants such as North Anna, generally have relatively high fixed costs. Nuclear facilities operate with relatively low variable costs due to lower fuel costs and technological efficiencies. In addition, coal-fired facilities have relatively low variable costs, as compared to combustion turbine facilities such as 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:

 

		Year Ended December 31,
		2011				2010				2009
Unit 1			96.6	%			95.2	%			83.8	%
Unit 2			88.7				95.5				82.5
Combined			92.7				95.4				83.2

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:

 

			71.3				71.3				71.3				71.3				71.3				71.3
		Clover Year Ended  December 31,												North Anna Year Ended December 31,
		2011				2010				2009				2011				2010				2009
Unit 1			71.3	%			80.6	%			74.6	%			77.6	%			85.7	%			92.3	%
Unit 2			65.8				82.5				72.2				76.1				79.6				99.9
Combined			68.6				81.6				73.4				76.9				82.7				96.1

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

 

			71.3				71.3				71.3				71.3				71.3				71.3
		Scheduled Outages Year Ended December 31,												Unscheduled Outages Year Ended December 31,
		2011				2010				2009				2011				2010				2009
		(in days)												(in days)
Unit 1			7.9				8.0				54.8				4.6				9.5				4.3
Unit 2			29.4				13.1				53.1				11.9				3.4				10.9
Combined			37.3				21.1				107.9				16.5				12.9				15.2

Also, the production for Clover Unit 1 was curtailed approximately 1.5 days in 2011 and 9.5 days in 2010, and Clover Unit 2 was curtailed approximately 1.0 day in 2009 due to equipment issues.

 

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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,
		2011				2010				2009				2011				2010				2009
		(in days)												(in days)
Unit 1			—				31.0				25.1				83.9				21.6				5.8
Unit 2			31.8				36.3				—				59.4				32.9				3.0
Combined			31.8				67.3				25.1				143.3				54.5				8.8

The unscheduled outages for both units at North Anna during 2011 relate to a magnitude 5.8 earthquake near Mineral, Virginia on August 23, 2011, which caused the two reactors at North Anna to shut down. Both units returned to service in November 2011. See “Business—Power Supply Resources—General” in Item 1 for additional information.

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

 

		Year Ended December 31,
		2011				2010				2009
Louisa			97.8	%			98.4	%			98.2	%
Marsh Run			98.2				97.3				97.3
Rock Springs			96.2				94.2				94.6

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 GHG. Future federal and state legislation and regulations, particularly with respect to GHG, present the potential for even greater obligations to limit the impact on the environment from the operation of our generation and transmission facilities. See “Business—Regulation— Environmental” in Item 1 and “Risk Factors” in Item 1A.

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” above.

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.

 

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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:

 

		Year Ended December 31,
		2011				2010				2009
		(in thousands)
Revenues from sales to:
Member distribution cooperatives
Base energy revenues		$	213,788			$	199,955			$	154,780
Energy adjustment revenues			327,402				298,464				287,904
Total energy revenues			541,190				498,419				442,684
Demand (capacity) revenues			312,730				280,651				236,391
Total revenues from sales to member distribution cooperatives			853,920				779,070				679,075
Non-members			37,619				65,400				34,094
Total operating revenues		$	891,539			$	844,470			$	713,169
Average cost to member distribution cooperatives (per MWh)		$	69.96			$	69.22			$	78.34

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:

 

		Year Ended December 31,
		2011				2010				2009
		(in MWh)
Energy sales to:
Member distribution cooperatives			12,205,602				11,254,269				8,667,917
Non-members			941,908				1,356,542				1,060,656
Total energy sales			13,147,510				12,610,811				9,728,573
		(in MW)
Demand sales to member distribution cooperatives			24,166				21,960				16,910

In 2011, our energy sales in MWh and demand sales in MW to our member distribution cooperatives were 8.5% and 10.0% higher, respectively, as compared to 2010. The change was primarily driven by the Potomac Edison Acquisition which increased our 2011 energy and demand sales to our member distribution cooperatives approximately 10.6% and 11.2%, respectively. 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 Potomac Edison Acquisition and weather-related increases in our sales volumes. The Potomac Edison Acquisition increased our 2010 energy and demand sales to our member distribution cooperatives approximately 21.8%.

In 2011, our energy sales in MWh to non-members were 30.6% lower as compared to 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 2011, total revenues from sales to our member distribution cooperatives increased $74.9 million, or 9.6%, as compared to 2010. The increase in total revenues is primarily related to the Potomac Edison Acquisition. In 2010, total revenues from sales to our member distribution cooperatives increased $100.0 million, or 14.7%, as

 

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compared to 2009. The increase in total revenues is related to the Potomac Edison Acquisition 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 energy adjustment rate).

In 2011, the capacity costs we incurred, and thus the capacity-related revenues we reflected were 11.4% higher as compared to 2010, primarily due to an increase in the amount of capacity and transmission we purchased, which was primarily related to the Potomac Edison Acquisition. 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 to the Potomac Edison Acquisition. This increase was partially offset by lower operations and maintenance expense and interest charges, net.

In 2011, our average cost per MWh to member distribution cooperatives was relatively flat. In 2010, our average cost per MWh to member distribution cooperatives decreased $9.12 per MWh, or 11.6%, as compared to the prior year, primarily as a result of the decreases in our total energy rate.

Non-member revenue decreased $27.8 million, or 42.5%, in 2011 as compared to the prior year due to the decrease in the volume of excess energy sales and the decrease in the average price. In 2010, non-member revenue increased $31.3 million, or 91.8%, as compared to 2009 due to an increase in the average price and a 27.9% increase 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,
		2011				2010				2009
		(in thousands)
Fuel		$	112,421			$	185,202			$	111,863
Purchased power			593,030				462,871				368,270
Deferred energy			(10,665	)			6,637				36,300
Operations and maintenance			40,642				39,467				48,232
Administrative and general			36,520				39,895				37,485
Depreciation, amortization and decommissioning			41,566				41,535				41,061
Amortization of regulatory asset/(liability), net			3,808				3,352				915
Accretion of asset retirement obligations			3,572				3,333				3,273
Taxes, other than income taxes			8,055				8,507				8,034
Total Operating Expenses		$	828,949			$	790,799			$	655,433

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, net and investment income, are components of our capacity costs. See “Factors Affecting Results—Formulary Rate” above.

In 2011, total operating expenses increased $38.2 million, or 4.8%, as compared to 2010, primarily due to the increase in purchased power partially offset by decreases in fuel and deferred energy expenses.

 

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Purchased power expense, which includes the cost of purchased energy, capacity, and transmission, increased $130.2 million, or 28.1%, due to a 28.2% increase in the volume of purchased power necessitated by the decrease in energy supplied by our owned generation and the Potomac Edison Acquisition. Energy supplied by our owned generation declined in 2011 due to the economic dispatch of our combustion turbine facilities and Clover, and the availability of North Anna.

 

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•

Fuel expense decreased $72.8 million, or 39.3%, primarily due to the decrease in the economic dispatch of our combustion turbine facilities and Clover. Additionally, in 2011 we received our proportionate share of a settlement for spent nuclear fuel costs. See “Business—Power Supply Resources—Fuel Supply—Nuclear” in Item 1.

 

•

Deferred energy expense decreased $17.3 million, or 260.7%. During 2011, we under-collected $10.7 million in energy costs; whereas in 2010, we over-collected $6.6 million in energy costs. The under-collection in 2011 was the result of the decrease in our energy rate. Our board of directors approved the rate decrease so that previously over-collected energy costs would be returned to our member distribution cooperatives. See “Critical Accounting Policies—Deferred Energy” above.

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 Potomac Edison Acquisition partially offset by an 8.2% decrease in the average cost of purchased power.

 

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

 

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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.

 

•

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

Other Items

Loss on Investments, Net

In 2011, we recognized a $2.3 million net loss related to our ARS which is comprised of the amortization of the regulatory asset related to the deferred loss on ARS of $5.6 million partially offset by a gain of $3.2 million related to the sale of our ARS. In 2010, and 2009, we recognized a loss of $3.6 million and $1.4 million, respectively, related to our ARS. See “Liquidity and Capital Resources—Sources—Auction Rate Securities” below.

Investment Income

Investment income increased in 2011 by $0.4 million, or 8.6%, as compared to 2010, primarily due to income earned on our nuclear decommissioning trust. Investment income increased in 2010 by $1.6 million, or 56.1%, as compared to 2009, primarily due to higher investment balances.

 

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Interest Charges, Net

The primary factors affecting our interest charges, net are issuance of indebtedness, scheduled payments of principal on our indebtedness, interest related to our Norfolk Southern settlement, 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,
		2011				2010				2009
		(in thousands)
Interest expense on long-term debt		$	(50,984	)		$	(46,270	)		$	(47,606	)
Interest charges related to Norfolk Southern			—				5,046				1,916
Other			(3,052	)			(3,050	)			(2,747	)
			(54,036	)			(44,274	)			(48,437	)
Allowance for borrowed funds used during construction			888				1,450				1,127
Interest Charges, net		$	(53,148	)		$	(42,824	)		$	(47,310	)

In 2011, interest charges, net increased $10.3 million, or 24.1%, as compared to 2010. In 2010, we completed the amortization of the regulatory liability related to the refund of interest charges related to our Norfolk Southern settlement; thus, there was no comparable refund in 2011. Additionally, in the second quarter of 2011, we issued a total of $350.0 million of debt. See “Liquidity and Capital Resources—Sources—Financings” below. In 2010, interest charges, net decreased $4.5 million, or 9.5%, as compared to 2009, primarily as a result of our Norfolk Southern settlement.

Net Margin Attributable to ODEC

In 2011, our net margin attributable to ODEC, which is a function of our total interest charges plus any additional equity contributions approved by our board of directors, increased $0.6 million, or 6.4%, as compared to 2010, due to higher total interest charges in 2011, partially offset by the absence of an equity contribution in 2011 as compared to the $1.3 million equity contribution in 2010. In 2010, our net margin 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 total 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.

Financial Condition

The principal changes in our financial condition from December 31, 2010 to December 31, 2011, were caused by the increases in long-term debt (offset by the decrease in long-term due within one year), unrestricted investments and other, and fuel, materials, and supplies; and decreases in accounts payable, accounts receivable, accounts receivable–members, regulatory liabilities, interest rate hedge, and deferred energy.

 

•

Long-term debt increased $316.3 million. On April 7, 2011, we issued $350.0 million of debt under the Indenture which provided funding to repay the $215.0 million maturity of our 2001 Series A Bonds on June 1, 2011. Long-term debt due within one year decreased $210.6 million primarily due to the maturing debt.

 

•

Unrestricted investments and other increased $32.3 million due to excess cash related to the $350.0 million bond offering in 2011.

 

•

Fuel, materials, and supplies increased $18.0 million due to the increase in coal supply.

 

•

Accounts payable decreased $26.3 million due to decreased purchased power requirements in December 2011 as compared to December 2010 as a result of milder weather in 2011 as compared to 2010.

 

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•

Accounts receivable decreased $16.3 million as a result of lower sales to non-members in December 2011 as compared to December 2010.

 

•

Accounts receivable–members decreased $16.2 million as a result of lower sales to members in December 2011 as compared to December 2010 as a result of milder weather in 2011 as compared to 2010.

 

•

Regulatory liabilities decreased $11.8 million. The regulatory liability related to the Norfolk Southern settlement decreased $12.3 million as a result of the amortization as a reduction of fuel expense.

 

•

Interest rate hedge decreased $10.9 million. On January 21, 2011, we terminated our interest rate hedge in accordance with the terms of the transaction.

 

•

Deferred energy decreased $10.7 million as a result of the under-collection of our energy costs in 2011.

Liquidity and Capital Resources

Sources

Cash generated by our operations and periodically, borrowings under our credit facilities as well as the occasional issuance of long-term indebtedness, provide our sources of liquidity and capital.

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 2011, 2010 and 2009, our operating activities provided cash flows of $40.1 million, $119.2 million and $91.2 million, respectively. Operating activities in 2011 were primarily impacted by the following:

 

•

Current liabilities changed $21.2 million primarily due to the $26.3 million decrease in accounts payable slightly offset by the $4.8 million increase in accounts payable–members.

 

•

Current assets changed by $11.3 million primarily due to the $16.3 million decrease in accounts receivable and the $16.2 million decrease in accounts receivable–members partially offset by the $18.0 million increase in fuel, materials, and supplies.

 

•

Deferred energy decreased by $10.7 million due to the under-collection of energy costs in 2011.

Auction Rate Securities

As of December 31, 2010, we owned five ARS with an estimated fair value of $7.9 million. During 2011, we sold all five of the ARS for $11.1 million, and recognized a gain of $3.2 million.

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 through 2010. 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, was fully amortized in 2011.

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

 

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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 “AA” 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 2011, distributions from the payment undertaking agreement provided $13.9 million, to fund rent payments under the lease.

Credit Facilities

In addition to liquidity from our operating activities, we currently maintain a $500.0 million, five-year committed revolving credit facility to cover our short-term and medium-term funding needs. We did not have any outstanding borrowings under this facility at December 31, 2011; however, the interest rate would have been 1.3%. At December 31, 2010, we had $7.0 million outstanding under our existing credit facilities at an interest rate of 1.8%. See “Financial Condition” above.

On November 21, 2011, we entered into a $500.0 million, five-year revolving credit agreement with a syndicate of lenders. Commitments under the credit agreement mature on November 20, 2016, unless earlier terminated in accordance with the agreement. The syndicated credit agreement replaces seven bilateral credit agreements with an aggregate of $460.0 million of revolving loan commitments and varying expiration dates in 2012 or 2013.

Our syndicated credit agreement relating to our committed credit facility contains 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 markets. These capital expenditures consist primarily of the costs related to the development, construction, acquisition, or improvement of our owned generating facilities.

In the second quarter of 2011, we issued $350.0 million of first mortgage bonds under the Indenture. The bond issuance consisted of $90.0 million of 4.83% First Mortgage Bonds, 2011 Series A due December 1, 2040; $165.0 million of 5.54% First Mortgage Bonds, 2011 Series B due December 1, 2040; and $95.0 million of 5.54% First Mortgage Bonds, 2011 Series C due December 1, 2050. A portion of the proceeds of the issuance was used to repay our $215.0 million 2001 Series A Bonds due June 1, 2011. The remainder of the proceeds is being used for general corporate purposes.

 

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

Capital Expenditures

We regularly forecast our capital expenditures as part of our long-term business planning activities. We review these projections frequently in order to update our calculations to reflect changes in our future plans, construction costs, market factors, and other items affecting our forecasts. Our actual capital expenditures could vary significantly from these projections. The table below summarizes our actual and projected capital expenditures, including nuclear fuel and capitalized interest, for 2009 through 2014:

 

		Actual Year Ended December 31,												Projected Year Ended December 31,
		2009				2010				2011				2012				2013				2014
		(in millions)
Clover		$	10.2			$	9.6			$	9.9			$	12.2			$	12.4			$	12.7
North Anna(1)			30.1				36.4				31.9				12.4				12.7				13.4
Combustion turbine facilities			0.6				0.9				2.7				0.7				1.1				1.1
Other			1.4				31.6				1.6				7.1				6.7				6.8
Total		$	42.3			$	78.5			$	46.1			$	32.4			$	32.9			$	34.0

 

(1)	Includes expenditures for North Anna Unit 3 of $2.6 million, $13.6 million, and $1.4 million for 2009, 2010, and 2011, respectively.

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 “Other” include costs related to our transmission assets, administrative and general assets, and distributed generation facilities, and for 2010, actual capital expenditures include $30.0 million related to the purchase of two tracts of land for a potential new generating facility. We intend to use our cash from operations and borrowings to fund all of our currently projected capital requirements through 2014.

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 for capacity and energy, 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, 2011:

 

		Payments due by Period
		Total				2012				2013-2014				2015-2016				2017 and Thereafter
		(in millions)
Long-term indebtedness		$	1,138.3			$	46.8			$	92.7			$	91.6			$	907.2
Operating lease obligations			111.9				0.4				0.9				1.3				109.3
Power purchase obligations			1,524.8				214.4				340.7				383.9				585.8
Asset retirement obligations			387.0				—				—				—				387.0
Total		$	3,162.0			$	261.6			$	434.3			$	476.8			$	1,989.3

 

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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, 2011, all of our long-term indebtedness was issued under the Indenture. This indebtedness includes bonds issued privately and to the public and 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.

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” below.

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, 2011, the collateral we had posted with counterparties pursuant to the power purchase contracts we have in place was $6.5 million. 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, 2011, if our credit ratings had been below investment grade we estimate we would have been obligated to post between $450.0 million and $550.0 million of collateral with our counterparties. This calculation is based on energy prices on December 31, 2011, 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.

 

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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, 2011, if PJM had determined that we needed to provide collateral to support our obligations, PJM could have asked us to provide up to approximately $12.2 million.

TEC Guarantees

TEC is considered a variable interest entity for which we are the primary beneficiary, and we have consolidated its results and have eliminated all intercompany balances and transactions in consolidation. To facilitate the ability of TEC to sell power in the market, we have agreed to guarantee up to a maximum of $200.0 million of TEC’s delivery and payment obligations associated with its energy trades if requested. See “Business—Members—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, 2011, we had issued guarantees for up to $42.0 million of TEC’s obligations and TEC had an immaterial balance in accounts payable 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 “AA” 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 2011, Rabobank paid $13.9 million of rent. At December 31, 2011, 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 $311.8 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, 2011, the estimated amount of the letter of credit we would have been required to provide was $9.4 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.

 

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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 $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” above.

ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

The operation of our business exposes us to several common market risks, including changes in market prices for power and fuel, and interest rates and equity prices.

The Dodd-Frank Wall Street Reform and Consumer Protection Act enacted in July 2010 could impact our use of over-the-counter derivatives. Regulations to implement the Dodd-Frank Act could impose additional requirements on the use of over-the-counter derivatives, such as margin and reporting requirements, which could affect both the use and cost of over-the-counter derivatives. The impact, if any, cannot be determined until regulations are finalized.

 

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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, 2011, we estimate that the fair value of our purchased power agreements and forward purchases of energy and natural gas was between $2.3 billion and $2.4 billion. Approximately 38% of the fair value of this portfolio is estimable using observable market prices. The remaining 62% of the fair value of this portfolio is related to less liquid products and the fair values of these products are not directly estimable using observable market prices. In the absence of observable market prices, the valuation of the 62% 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, it is estimated that a 10% change in the price of the commodities hedged by the portion of this portfolio with observable market prices would have changed the fair value of this portion of the portfolio by approximately $88.0 million at December 31, 2011. To the extent all or portions of our portfolio are liquidated above or below our original cost, these gains or losses are factored into the 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.

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 Clover and North Anna. We manage these risks indirectly through our participation in the management arrangements for these facilities. However, Virginia Power, as operator of these facilities, has the sole authority and responsibility to procure coal and nuclear fuel for Clover and North Anna, respectively.

Virginia Power advises us it uses 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 Clover. See “Business—Power Supply Resources—Fuel Supply—Coal” in Item 1.

Virginia Power advises us it primarily uses 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. See “Business—Power Supply Resources—Fuel Supply—Nuclear” in Item 1.

 

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Interest Rate Risk and Equity Price Risk

In 2011, all of our outstanding long-term indebtedness accrued interest at fixed rates.

We also have a $500.0 million committed syndicated revolving credit facility. See “Management’s Discussion and Analysis of Financial Condition and Results of Operations—Liquidity and Capital Resources—Sources—Credit Facilities” in Item 7. Any amounts we borrow under this facility will accrue interest at a variable rate. At December 31, 2011, we did not have any amounts outstanding under this facility.

We accrue decommissioning costs over the expected service life of North Anna and have made periodic deposits to a trust fund so that the fund balance will cover the estimated cost to decommission North Anna at the time of decommissioning. At December 31, 2011, $45.0 million of these funds were invested in fixed-income securities and $56.3 million of these funds were invested in equity securities. The value of these equity and fixed income securities will be impacted by changes in interest rates and price fluctuations in equity markets. To minimize adverse changes in the aggregate value of the trust fund, we actively monitor our portfolio by measuring the performance of our investments against market indexes and by maintaining and reviewing established target allocation percentages of assets in our trust to various investment options. We believe the trust fund’s exposure to changes in interest rates and price fluctuations in equity markets will not have a material impact on our financial results.

 

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ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA

CONSOLIDATED FINANCIAL STATEMENTS

INDEX

 

		Page Number
Report of Management on ODEC’s Internal Control over Financial Reporting			48
Report of Independent Registered Public Accounting Firm			49
Consolidated Balance Sheets			50
Consolidated Statements of Revenues, Expenses, and Patronage Capital			51
Consolidated Statements of Cash Flows			52
Notes to Consolidated Financial Statements			53

 

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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, 2011, 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, 2011, 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 14, 2012

 

/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, 2011 and 2010, 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, 2011. 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, 2011 and 2010, and the consolidated results of its operations and its cash flows for each of the three years in the period ended December 31, 2011, in conformity with U.S. generally accepted accounting principles.

Richmond, Virginia

 

March 14, 2012				/s/ Ernst & Young LLP

 

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OLD DOMINION ELECTRIC COOPERATIVE

CONSOLIDATED BALANCE SHEETS

AS OF DECEMBER 31, 2011 AND 2010

 

		2011				2010
		(in thousands)
ASSETS:
Electric Plant:
Property, plant, and equipment		$	1,638,938			$	1,627,643
Less accumulated depreciation			(697,031	)			(663,871	)
			941,907				963,772
Nuclear fuel, at amortized cost			22,838				20,872
Construction work in progress			48,160				52,760
Net Electric Plant			1,012,905				1,037,404
Investments:
Nuclear decommissioning trust			101,474				97,531
Lease deposits			91,718				89,355
Unrestricted investments and other			42,007				9,711
Total Investments			235,199				196,597
Current Assets:
Cash and cash equivalents			63,756				4,391
Accounts receivable			7,210				23,495
Accounts receivable–deposits			6,500				3,000
Accounts receivable–members			82,236				98,423
Fuel, materials, and supplies			53,771				35,798
Prepayments and other			3,187				3,438
Total Current Assets			216,660				168,545
Deferred Charges:
Regulatory assets			98,964				93,199
Other			10,252				16,690
Total Deferred Charges			109,216				109,889
Total Assets		$	1,573,980			$	1,512,435
CAPITALIZATION AND LIABILITIES:
Capitalization:
Patronage capital		$	350,485			$	339,678
Non-controlling interest			13,093				13,166
Total Patronage capital and Non-controlling interest			363,578				352,844
Long-term debt			766,128				449,798
Total Capitalization			1,129,706				802,642
Current Liabilities:
Long-term debt due within one year			28,292				238,917
Revolving credit facilities			—				7,043
Accounts payable			65,416				91,686
Accounts payable–members			81,224				76,458
Interest rate hedge			—				10,944
Accrued expenses			4,863				4,606
Deferred energy			34,712				45,377
Total Current Liabilities			214,507				475,031
Deferred Credits and Other Liabilities:
Asset retirement obligations			73,141				67,876
Obligations under long-term lease			69,285				64,801
Regulatory liabilities			75,580				87,406
Other			11,761				14,679
Total Deferred Credits and Other Liabilities			229,767				234,762
Commitments and Contingencies			—				—
Total Capitalization and Liabilities		$	1,573,980			$	1,512,435

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, 2011, 2010, AND 2009

 

		2011				2010				2009
		(in thousands)
Operating Revenues		$	891,539			$	844,470			$	713,169
Operating Expenses:
Fuel			112,421				185,202				111,863
Purchased power			593,030				462,871				368,270
Deferred energy			(10,665	)			6,637				36,300
Operations and maintenance			40,642				39,467				48,232
Administrative and general			36,520				39,895				37,485
Depreciation and amortization			41,566				41,535				41,061
Amortization of regulatory asset/(liability), net			3,808				3,352				915
Accretion of asset retirement obligations			3,572				3,333				3,273
Taxes, other than income taxes			8,055				8,507				8,034
Total Operating Expenses			828,949				790,799				655,433
Operating Margin			62,590				53,671				57,736
Other expense, net			(1,377	)			(1,723	)			(1,598	)
Loss on investments, net			(2,348	)			(3,558	)			(1,440	)
Investment income			4,968				4,576				2,931
Interest charges, net			(53,148	)			(42,824	)			(47,310	)
Income taxes			49				3				(240	)
Net Margin including Non-controlling interest			10,734				10,145				10,079
Non-controlling interest			73				13				(392	)
Net Margin attributable to ODEC			10,807				10,158				9,687
Patronage Capital - Beginning of Year			339,678				329,520				319,833
Patronage Capital - End of Year		$	350,485			$	339,678			$	329,520

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, 2011, 2010, AND 2009

 

		2011				2010				2009
		(in thousands)
Operating Activities:
Net Margin including Non-controlling Interest		$	10,734			$	10,145			$	10,079
Adjustments to reconcile net margins to net cash provided by operating activities:
Depreciation and amortization			41,566				41,535				41,061
Other non-cash charges			10,454				10,149				10,603
Amortization of lease obligations			4,484				4,189				4,695
Interest on lease deposits			(2,646	)			(2,586	)			(3,196	)
Change in current assets			11,250				(34,563	)			17,011
Change in deferred energy			(10,665	)			6,637				36,300
Change in current liabilities			(21,247	)			90,121				(26,284	)
Change in regulatory assets and liabilities			(10,807	)			(11,596	)			411
Change in deferred charges and credits			6,951				5,176				538
Net Cash Provided by Operating Activities			40,074				119,207				91,218
Financing Activities:
Issuance of long-term debt			350,000				—				—
Debt issuance costs			(2,342	)			—				—
Payments of long-term debt			(244,292	)			(22,917	)			(22,917	)
Obligations under long-term lease			—				—				(237	)
Draws on revolving credit facilities			52,257				110,304				545,367
Repayments on revolving credit facilities			(59,300	)			(130,215	)			(580,413	)
Net Cash Provided by (Used for) Financing Activities			96,323				(42,828	)			(58,200	)
Investing Activities:
Purchases of held to maturity securities			(159,030	)			—				—
Proceeds from held to maturity securities			117,751				—				—
Proceeds from sale of trading securities			11,089				—				—
Proceeds from sale of available for sale securities			—				325				3,560
Increase in other investments			(3,100	)			(3,663	)			(1,506	)
Electric plant additions			(46,090	)			(78,486	)			(42,259	)
Loss on investments, net			2,348				3,558				1,440
Net Cash Used for Investing Activities			(77,032	)			(78,266	)			(38,765	)
Net Change in Cash and Cash Equivalents			59,365				(1,887	)			(5,747	)
Cash and Cash Equivalents-Beginning of Year			4,391				6,278				12,025
Cash and Cash Equivalents-End of Year		$	63,756			$	4,391			$	6,278

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 and 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 $13.1 million and $13.2 million at December 31, 2011 and December 31, 2010, respectively. 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. We have eleven member distribution cooperatives as our Class A members. 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 FERC. Our most recent filing became effective January 1, 2011.

We comply with the Uniform System of Accounts prescribed by FERC. In conformity with 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.

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.

 

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Depreciation

We conducted a depreciation study in 2010 and updated our depreciation rates in 2011.

Depreciation rates are as follows:

 

		Depreciation Rates
Generating Facility		2011				2010				2009
Clover			1.8	%			1.8	%			1.8	%
North Anna			3.0				2.9				2.9
Louisa			3.5				3.3				3.3
Marsh Run			3.2				3.4				3.4
Rock Springs			3.3				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 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. 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. The government’s initial brief in the appeal was filed in June 2010. In the second quarter of 2011, the Federal Appeals Court issued a decision affirming the trial court’s damages award. The government did not seek rehearing of the Federal Appeals Court decision or seek review by the U.S. Supreme Court. During the third quarter of 2011, Virginia Power received a settlement amount for spent fuel costs representing certain spent nuclear fuel-related costs incurred through June 30, 2006. Virginia Power then paid ODEC our proportionate share related to North Anna, $7.8 million, which is recorded as a $6.7 million reduction to fuel expense and a $1.1 million reduction to operations and maintenance expense. We currently anticipate that Virginia Power will seek reimbursement for certain spent nuclear fuel-related costs incurred subsequent to June 30, 2006; however, due to the uncertainty of future collection, we have not recorded a receivable.

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 2011, 2010, and 2009, was $0.9 million, $1.4 million, and $1.1 million, respectively.

Income Taxes

As a not-for-profit electric cooperative, we are currently exempt from federal income taxation under IRC Section 501(c)(12), 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.

 

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TEC is a taxable corporation and its provision for income taxes was immaterial for the years ended December 31, 2011, 2010, and 2009.

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, 2011, 2010, and 2009, revenue from sales to our member distribution cooperatives was $853.9 million, $779.1 million, and $679.1 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 consist of sales of excess energy that we do 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 PJM under its rates for providing energy imbalance service, or to third parties. For the years ended December 31, 2011, 2010, and 2009, energy sales to non-members were $37.6 million, $65.4 million, and $34.1 million, respectively.

Formulary Rate

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

The rates we charge our member distribution cooperatives for sales of energy and capacity are determined by a formulary rate accepted by 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.

For additional discussion on our formulary rate, see Note 5—Wholesale Power Contracts.

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.

 

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Debt Issuance Costs

Capitalized costs associated with the issuance of debt totaled $9.1 million and $8.6 million, at December 31, 2011 and 2010, respectively and are included in deferred charges – other. These costs are being amortized using the effective interest method over the life of the respective debt issues, and are included in interest charges, net.

Deferred Credits and Other Liabilities – Other

Deferred credits and other liabilities – other, includes a gain on a long-term lease transaction (see Note 8—Long-term Lease Transaction), DOE decontamination and decommissioning liability, and liabilities associated with benefit plans for certain executives. The unamortized portion of the deferred gain was $6.5 million and $7.6 million at December 31, 2011 and 2010, respectively. This gain is being amortized into income ratably over the term of the operating lease as a reduction to depreciation and amortization expense.

Deferred Energy

We use the deferral method of accounting to recognize differences between our energy expenses and our energy revenues collected from our member distribution cooperatives. Our deferred energy balance represents the net accumulation of any under- or over-collection of energy costs. At December 31, 2011 and 2010, we had an over-collected deferred energy balance of $34.7 million and $45.4 million, respectively. Over-collected deferred energy balances are refunded to our member distribution cooperatives 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. 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 fair 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, 2011, 2010, or 2009.

 

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

Patronage Capital

We are organized and operate as a cooperative. Patronage capital represents our retained net margins, which have been allocated to our members based upon their respective power purchases in accordance with our bylaws. Any distributions are subject to the discretion of our board of directors and the restrictions contained in the Indenture.

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 $82.2 million and $98.4 million, at December 31, 2011 and 2010, 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 2011:

 

		Clover				North Anna				Combustion Turbine Facilities				Other				Total
		(in thousands)
Property, plant, and equipment(1)		$	668,666			$	321,451			$	583,509			$	65,312			$	1,638,938
Accumulated depreciation			(342,414	)			(174,944	)			(159,648	)			(20,025	)			(697,031	)
Nuclear fuel			—				63,405				—				—				63,405
Accumulated amortization of nuclear fuel			—				(40,567	)			—				—				(40,567	)
Construction work in progress			8,707				38,324				15				1,114				48,160
		$	334,959			$	207,669			$	423,876			$	46,401			$	1,012,905

 

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

 

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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 North Anna Unit 3. On December 16, 2011, we withdrew as a participant in North Anna Unit 3.

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, 2011 and 2010, we had an outstanding accounts payable balance of $13.9 million and $8.1 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, 1,868 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, 2011 and 2010, we had an outstanding accounts payable balance due to Virginia Power for the operation, maintenance, and capital investment at the North Anna facility of $6.0 million and $7.7 million, respectively.

On August 23, 2011, a magnitude 5.8 earthquake near Mineral, Virginia caused the two reactors at North Anna to shut down immediately, as designed. Virginia Power, the co-owner and operator of North Anna, informed us that some of the earthquake’s vibrations briefly exceeded North Anna’s licensing design basis at certain frequencies; however, Virginia Power’s inspections showed no significant damage to equipment at the station from the earthquake. The reactors were placed in cold shutdown condition pending completion of the NRC inspection and review. On November 11, 2011, the NRC approved the restart of the two reactors: later that day North Anna Unit 1 was restarted and began generating electricity on November 15, 2011; on November 20, 2011, North Anna Unit 2 was restarted and began generating electricity on November 22, 2011.

In February 2011, we made the determination not to participate in North Anna Unit 3. As of December 31, 2010, we had $21.3 million of construction work in progress related to North Anna Unit 3, and had incurred approximately $1.8 million in financing-related costs that were included in deferred charges–other. During 2011, we established a regulatory asset and reclassified the $21.3 million of construction work in progress costs. The $1.8 million in financing-related costs were expensed in the first quarter of 2011 as administrative and general expense. As of December 31, 2011, our regulatory asset balance was $22.7 million which includes the $21.3 million referenced above and additional costs incurred during 2011 prior to our withdrawal notice. We continued to incur costs related to North Anna Unit 3 until the finalization of our withdrawal and the transfer of our interest in the project to Virginia Power on December 16, 2011. On this date we received payment of $11.3 million from Virginia Power, which included reimbursement of $10.4 million of costs incurred from February 2011 until December 16, 2011, including interest, and $0.9 million for the sale of land related to North Anna Unit 3. Reimbursement of costs recorded in the regulatory asset to us by Virginia Power is subject to the VSCC approval. We cannot currently estimate if or when Virginia Power will seek approval from the VCSS. If these costs are not determined to be collectible from Virginia Power, we will begin amortization of our regulatory asset and collect these costs from our member distribution cooperatives through our formulary rate.

 

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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 included in “Other,” as well as two 1,100 foot 500 kV transmission lines and a 500 kV substation at our combustion turbine site in Maryland included in “Combustion Turbine Facilities.”

In 2010, we acquired a tract of land in Surry County, Virginia, and 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 2012 through 2014:

 

		Projected Year Ended  December 31,
		2012				2013				2014
		(in millions)
Clover		$	12.2			$	12.4			$	12.7
North Anna			12.4				12.7				13.4
Combustion turbine facilities			0.7				1.1				1.1
Other			7.1				6.7				6.8
Total		$	32.4			$	32.9			$	34.0

Nearly all of our capital expenditures consist of additions to electric plant and equipment. Our future capital requirements include our portion of the cost of the nuclear fuel purchased for North Anna and other capital expenditures including generation facility improvements. Projected capital expenditures for “Other” include costs related to our transmission assets, administrative and general assets, and distributed generation facilities.

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, 2011 and 2010, North Anna’s nuclear decommissioning asset retirement obligation totaled $65.2 million and $62.0 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.

 

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The following represents changes in our asset retirement obligations for the years ended December 31, 2011 and 2010 (in thousands):

 

Asset retirement obligations at December 31, 2009		$	64,543
Accretion expense			3,333
Asset retirement obligations at December 31, 2010		$	67,876
Accretion expense			3,572
Additional asset retirement obligations			1,693
Asset retirement obligations at December 31, 2011		$	73,141

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 Annaas part of our asset retirement obligation regulatory liability. See Note 10—Regulatory Assets and Liabilities.

NOTE 4—Power Purchase Agreements

In 2011, 2010, and 2009, our owned generating facilities together furnished approximately 33.3%, 45.9%, and 48.6%, 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 through consultation with 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, 2011 and 2010, due to changes in energy prices, we were required to post $6.5 million and $3.0 million, respectively, with our counterparties pursuant to contracts we have in place with them.

We have contractual arrangements with Virginia Power, the operator and co-owner of Clover and North Anna, under which we purchase reserve capacity. The purchase of reserve capacity allows for the purchase of reserve energy. These arrangements remain in effect 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. 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 2011, 2010, and 2009 were $593.0 million, $462.9 million, and $368.3 million, respectively.

 

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As of December 31, 2011, our energy and capacity purchase commitments under the various agreements were as follows:

 

Year Ending December 31,		Energy and Capacity Commitments
		(in millions)
2012		$	214.4
2013			165.1
2014			175.6
		$	555.1

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 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 1.0% of our member distribution cooperatives’ total energy requirements and approximately 2.8% of our member distribution cooperatives’ total capacity requirements in 2011.

Two additional limited exceptions to the all-requirements nature of the contract permit the member distribution cooperatives to receive up to the greater of 5% of their power requirements or 5 MW 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 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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The formulary rate allows us to recover and refund amounts under our Margin Stabilization Plan. Our Margin Stabilization Plan allows us to review our actual capacity-related costs 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 2011, 2010, and 2009, under our Margin Stabilization Plan, we reduced operating revenues by $14.9 million, $22.5 million, and $2.4 million, respectively. During the third quarter of 2011, we refunded $10.0 million of the $14.9 million.

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

 

		Year Ended December 31,
		2011				2010				2009
		(in millions)
Rappahannock Electric Cooperative(1)		$	290.4			$	245.4			$	191.4
Shenandoah Valley Electric Cooperative(1)			159.8				123.2				64.5
Delaware Electric Cooperative, Inc.			97.6				100.0				101.5
Choptank Electric Cooperative, Inc.			76.6				77.5				80.2
Southside Electric Cooperative			67.5				68.7				70.6
A&N Electric Cooperative			50.1				51.0				53.3
Mecklenburg Electric Cooperative			41.8				42.0				43.4
Prince George Electric Cooperative			22.5				22.7				23.7
Northern Neck Electric Cooperative			20.5				20.9				21.7
Community Electric Cooperative			14.7				15.4				15.8
BARC Electric Cooperative			12.4				12.3				13.0
		$	853.9			$	779.1			$	679.1

 

(1)	REC and SVEC acquired additional service territory in 2010.

NOTE 6—Fair 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.

 

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The following table summarizes our financial assets and liabilities measured at fair value on a recurring basis as of December 31, 2011 and 2010:

 

		December 31, 2011				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)(2)		$	101,474			$	54,781			$	46,693			$	—
Unrestricted investments and other(3)			91				91				—				—
Total Financial Assets		$	101,565			$	54,872			$	46,693			$	—
Derivatives – gas and power(4)		$	5,170			$	888			$	4,282			$	—
Total Financial Liabilities		$	5,170			$	888			$	4,282			$	—

 

		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)(2)		$	97,531			$	52,156			$	45,375			$	—
Unrestricted investments and other(3)(5)			7,942				80				—				7,862
Derivatives – renewable energy credit sales			257				—				257				—
Total Financial Assets		$	105,730			$	52,236			$	45,632			$	7,862
Derivatives – gas and power(4)		$	6,904			$	6,831			$	73			$	—
Derivative – interest rate hedge(6)			10,944				—				10,944				—
Total Financial Liabilities		$	17,848			$	6,831			$	11,017			$	—

 

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

(2)

Nuclear decommissioning trust includes investments that are available for sale and classified as level 2. These level 2 assets consist of an equity fund that attempts to replicate the return of the S&P 500 and an equity fund that seeks long-term capital appreciation by investing in a portfolio of small capitalization stocks. The fair values of the investments in the nuclear decommissioning trust have been estimated using the net asset value per share.

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

(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. The level 2 derivatives – gas and power includes gas and purchased power contracts valued by ACES. The gas contracts are indexed against NYMEX and the purchased power contracts are valued using observable market inputs for similar transactions.

(5)	Unrestricted investments and other includes investments that were available for sale and classified as level 3. As of December 31, 2010, we owned five ARS; during 2011, we sold all five ARS. For additional information, see Note 9—Investments and Note 10—Regulatory Assets and Liabilities.

(6)

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. 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. The $3.4 million is recorded as a regulatory asset and will be amortized over the life of the long-term debt we issued on April 7, 2011.

 

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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:

 

		Year Ended December 31, 2011
		(in thousands)
Balance as of January 1, 2011		$	7,862
Total realized gain:
Included in loss on investments, net			3,227
Settlements			(11,089	)
Balance at December 31, 2011		$	—

The realized gain was recorded in loss on investments, net, in our Consolidated Statements of Revenues, Expenses, and Patronage Capital.

NOTE 7—Derivatives 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. To manage this exposure, we utilize derivative instruments. See Note 1—Summary of Significant Accounting Policies.

Changes in the fair value of our derivative instruments accounted for at fair value 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, 2011 Quantity				As of December 31, 2010 Quantity
Natural gas		MMBTU			3,800,000				4,610,000
Purchased power		MWh			213,120				161,632
Renewable energy credits		REC			—				40,000
Interest rate hedge		US Dollars			—				300,000,000

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

 

				Fair Value
		Balance Sheet Location		As of December 31, 2011				As of December 31, 2010
				(in thousands)
Derivatives in an asset position:
Renewable energy credit sales		Prepayments and other		$	—			$	257
Total derivatives in an asset position				$	—			$	257
Derivatives in a liability position:
Natural gas futures contracts		Deferred credits and other liabilities-other		$	3,295			$	6,831
Purchased power contracts		Deferred credits and other liabilities-other			1,875				73
Interest rate hedge		Interest rate hedge			—				10,944
Total derivatives in a liability position				$	5,170			$	17,848

 

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

for the Years Ended December 31, 2011 and 2010

 

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,
		2011				2010						2011				2010
		(in thousands)										(in thousands)
Natural gas futures contracts(1)		$	(6,826	)		$	(7,256	)		Fuel		$	(6,035	)		$	(4,612	)
Purchased power contracts			(1,875	)			(73	)		Purchased power			(517	)			(365	)
Renewable energy credit sales			—				257			Operating revenue			—				—
Purchased power – excess sales			—				—			Operating revenue			—				(669	)
Interest rate hedge			—				(10,944	)		Interest charges, net			—				—
Total		$	(8,701	)		$	(18,016	)				$	(6,552	)		$	(5,646	)

 

(1)	Includes a regulatory asset of $3.5 million to be recognized in future periods as the result of the contracts being effectively settled.

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, 2011 and 2010, the unamortized portion of the deferred gain was $6.5 million and $7.6 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 $311.8 million at December 31, 2011, is issued by Rabobank, which has senior debt obligations which are currently rated “AA” by S&P and “Aaa” by Moody’s, respectively. The amount of debt considered to be extinguished by in substance defeasance was $311.8 million and $311.5 million, at December 31, 2011 and 2010, respectively.

At the end of the term of the leaseback, we have three options: (1) retain possession of the interest in the unit by paying a fixed purchase price to the owner trust, (2) return possession of the interest to the owner trust and arrange for an acceptable third party to enter into a power purchase agreement with the owner trust, or (3) return possession of the interest and pay a termination amount to the owner trust.

 

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NOTE 9—Investments

Investments were as follows at December 31, 2011 and 2010:

 

Description		Designation		Cost				Gross Unrealized Gains				Gross Unrealized Losses				Fair Value				Carrying Value
												(in thousands)
December 31, 2011
Nuclear decommissioning trust(1)
Debt securities		Available for sale		$	42,528			$	2,475			$	—			$	45,003			$	45,003
Equity securities		Available for sale			51,654				7,689				(2,997	)			56,346				56,346
Cash and other		Available for sale			125				—				—				125				125
Total Nuclear Decommissioning Trust				$	94,307			$	10,164			$	(2,997	)		$	101,474			$	101,474
Lease deposits(2)
Government obligations		Held to maturity		$	91,718			$	9,862			$	—			$	101,580			$	91,718
Total Lease Deposits				$	91,718			$	9,862			$	—			$	101,580			$	91,718
Unrestricted investments
Government obligations		Held to maturity		$	40,111			$	5			$	—			$	40,116			$	40,111
Total Unrestricted Investments				$	40,111			$	5			$	—			$	40,116			$	40,111
Other
Equity securities		Available for sale		$	96			$	—			$	(5	)		$	91			$	91
Non-marketable equity investments(3)		Equity			1,805				—				—				1,805				1,805
Total Other				$	1,901			$	—			$	(5	)		$	1,896			$	1,896
Total Carrying Value																				$	235,199
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(4)
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(3)		Equity			1,769				—				—				1,769				1,769
Total Other				$	1,847			$	2			$	—			$	1,849			$	1,849
Total Carrying Value																				$	196,597

 

(1)

Investments in the nuclear decommissioning trust are restricted for the use of funding our share of the asset retirement obligations of the future decommissioning of North Anna. See Note 3—Accounting for Asset Retirement Obligations. Realized and unrealized gains and losses related to assets held in the nuclear decommissioning trust are deferred as a regulatory asset or liability.

(2)	Investments in lease deposits are restricted for the use of funding our future lease obligations. See Note 8—Long-term Lease Transaction.

(3)	We believe the carrying value approximates fair value for our equity investments.

(4)

The cost represents investments in ARS with a principal value of $16.8 million. The cost has been written down by $9.0 million due to the market value adjustment. During 2010 and 2011, we amortized $3.4 million and $5.6 million, respectively, of the regulatory asset as loss on investments, net. See Note 10—Regulatory Assets and Liabilities. As of December 31, 2010, we owned five ARS; during 2011, we sold all five ARS.

 

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Our investments by classification at December 31, 2011 and 2010, were as follows:

 

		December 31, 2011								December 31, 2010
Description		Cost				Carrying Value				Cost				Carrying Value
		(in thousands)
Available for Sale		$	94,403			$	101,565			$	97,748			$	105,473
Held to Maturity			131,829				131,829				89,355				89,355
Equity			1,805				1,805				1,769				1,769
		$	228,037			$	235,199			$	188,872			$	196,597

Contractual maturities of unrestricted debt securities at December 31, 2011, were as follows:

 

Description		Less than 1 year				1-5 years				5-10 years				More than 10 years				Total
		(in thousands)
Available for Sale		$	—			$	—			$	—			$	—			$	—
Held to Maturity			40,111				—				—				—				40,111
		$	40,111			$	—			$	—			$	—			$	40,111

The contractual maturities of our restricted debt securities related to our nuclear decommissioning trust have not been disclosed since all maturities are prior to the estimated decommissioning date nor have we disclosed the contractual maturities of our restricted debt securities related to our lease deposits since all maturities are concurrent with the transaction maturity date.

NOTE 10—Regulatory Assets and Liabilities

In accordance with Accounting for Regulated Operations, we record regulatory assets and liabilities that result from our ratemaking. Our regulatory assets and liabilities at December 31, 2011 and 2010, were as follows:

 

		2011				2010
		(in thousands)
Regulatory Assets:
Unamortized losses on reacquired debt		$	20,958			$	23,587
Deferred asset retirement costs			396				413
Deferred net unrealized losses on derivative instruments			8,701				7,072
Deferred loss on ARS			—				5,575
NOVEC contract termination fee			41,596				44,043
Loan acquisition fee			1,341				1,565
Interest rate hedge			3,224				10,944
North Anna Unit 3			22,748				—
Total Regulatory Assets		$	98,964			$	93,199
Regulatory Liabilities:
North Anna asset retirement obligation deferral		$	37,910			$	36,788
Norfolk Southern settlement			29,789				42,115
North Anna nuclear decommissioning trust unrealized gain			7,167				7,723
Unamortized gains on reacquired debt			714				780
Total Regulatory Liabilities		$	75,580			$	87,406
Regulatory Liabilities included in Current Liabilities:
Deferred energy		$	34,712			$	45,377

 

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

Regulatory assets included in deferred charges are detailed as follows:

 

•

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

 

•

Deferred asset retirement costs reflect the cumulative effect of change in accounting principle for the Clover and distributed generation facilities as a result of the adoption of Accounting for Asset Retirement and Environmental Obligations. These costs will be fully amortized in 2034.

 

•

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

 

•

Deferred loss on ARS reflects the write-down of the value of our ARS, which became illiquid in 2008 due to deteriorating conditions in the credit market and failed auctions. A portion of the deferred loss was amortized in 2010 and the remaining deferred loss was amortized in 2011.

 

•

NOVEC contract termination fee reflects the amount allocated to the contract value of the payment to NOVEC in 2008 as part of the termination agreement. The wholesale power contract with NOVEC was scheduled to expire in 2028, thus the contract termination fee will be amortized ratably through 2028.

 

•

Loan acquisition fee reflects the onetime fee we paid to the investor to facilitate the acquisition of the $33.0 million loan related to the lease of Clover Unit 1. This fee will be amortized ratably over the remaining life of the lease and will be fully amortized in 2018.

 

•

Interest rate hedge. 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. This will be amortized over the life of the long-term debt we issued on April 7, 2011.

 

•

North Anna Unit 3. In February 2011, we made the determination not to participate in North Anna Unit 3 and on December 16, 2011, we finalized our withdrawal as a participant in the project and transferred our interest to Virginia Power. Related to this decision, in 2011, we reclassified the corresponding construction work in progress to a regulatory asset. Reimbursement of costs recorded in the regulatory asset to us by Virginia Power is subject to the VSCC approval. We cannot currently estimate if or when Virginia Power will seek approval from the VSCC. If these costs are not determined to be collectible from Virginia Power, we will begin amortizing our regulatory asset and collect these costs from our member distribution cooperatives through our formulary rate.

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

 

•

North Anna asset retirement obligation deferral is the cumulative effect of change in accounting principle as a result of the adoption of Accounting for Asset Retirement and Environmental Obligations plus the deferral of subsequent activity primarily related to accretion expense offset by interest income on the nuclear decommissioning trust.

 

•

Norfolk Southern settlement reflects the difference in the amount previously accrued and the actual settlement amount. The remaining amounts will be amortized ratably through May 2014 as a reduction of fuel expense.

 

•

North Anna nuclear decommissioning trust unrealized gain reflects the unrealized gain on the investments in the nuclear decommissioning trust.

 

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•

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

Regulatory liabilities included in current liabilities are detailed as follows:

 

•

Deferred energy balance represents the net accumulation of over-collection of energy costs. We use the deferral method of accounting to recognize differences between our energy expenses and our energy revenues collected from our member distribution cooperatives. Over-collected deferred energy balances are refunded to our members in subsequent periods.

NOTE 11—Long-term Debt

Long-term debt consists of the following:

 

		December 31,
		2011				2010
		(in thousands)
$90,000,000 principal amount of First Mortgage Bonds, 2011 Series A due 2040 at an interest rate of 4.83%		$	87,000			$	—
$165,000,000 principal amount of First Mortgage Bonds, 2011 Series B due 2040 at an interest rate of 5.54%			165,000				—
$95,000,000 principal amount of First Mortgage Bonds, 2011 Series C due 2050 at an interest rate of 5.54%			92,625				—
$250,000,000 principal amount of 2003 Series A Bonds due 2028 at an interest rate of 5.676%			177,081				187,498
$27,755,000 principal amount of 2002 Series A Bonds due 2028 at an interest rate of 5.00%			27,755				27,755
$32,455,000 principal amount of 2002 Series A Bonds due 2028 at an interest rate of 5.625%			32,455				32,455
$300,000,000 principal amount of 2002 Series B Bonds due 2028 at an interest rate of 6.21%			212,500				225,000
$215,000,000 principal amount of 2001 Series A Bonds due 2011 at an interest rate of 6.25%			—				215,000
$120,000,000 principal amount of First Mortgage Bonds, 1993 Series A due 2023 at an interest rate of 7.78%			—				1,000
			794,416				688,708
Unamortized discounts and premiums			4				7
Current maturities			(28,292	)			(238,917	)
		$	766,128			$	449,798

At December 31, 2011 and 2010, deferred gains and losses on reacquired debt totaled a net loss of approximately $20.2 million and $22.8 million, respectively. Deferred gains and losses on reacquired debt are deferred under regulatory accounting. See Note 10—Regulatory Assets and Liabilities.

 

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

 

Year Ending December 31,		(in thousands)
2012		$	28,292
2013			28,292
2014			28,292
2015			28,292
2016			28,292
2017 and thereafter			652,956
		$	794,416

In the second quarter of 2011, we issued a total of $350.0 million of first mortgage bonds under the Indenture. The bond issuance consisted of $90.0 million of 4.83% First Mortgage Bonds, 2011 Series A due December 1, 2040; $165.0 million of 5.54% First Mortgage Bonds, 2011 Series B due December 1, 2040; and $95.0 million of 5.54% First Mortgage Bonds, 2011 Series C due December 1, 2050. A portion of the proceeds of the issuance was used to repay our $215.0 million 2001 Series A Bonds due June 1, 2011. The remainder of the proceeds is being used for general corporate purposes.

The aggregate fair value of long-term debt was $897.9 million and $753.5 million at December 31, 2011 and 2010, respectively, based on current market prices. For debt issues that are not quoted on an exchange, interest rates currently available to us for issuance of debt with similar terms and remaining maturities are used to estimate fair value.

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

NOTE 12—Short-term Borrowing Arrangements

We maintain a committed credit facility to cover short- and intermediate- term funding needs. On November 21, 2011, we entered into a $500.0 million, five-year committed revolving credit facility with a syndicate of lenders. As of December 31, 2011, we did not have any borrowings outstanding under this facility; however, if we did have borrowings outstanding, the interest rate would have been 1.3%. Commitments under the credit agreement mature on November 20, 2016, unless earlier terminated in accordance with the agreement. The syndicated credit agreement replaces seven bilateral credit agreements with an aggregate of $460.0 million of revolving loan commitments and varying expiration dates in 2012 or 2013. At December 31, 2010, we had $7.0 million in short-term borrowings outstanding under our existing credit facilities at an interest rate of 1.8%.

We maintain a policy which allows our member distribution cooperatives to prepay or extend payment on their monthly power bills. Under this policy, we pay interest on prepayment balances at a blended investment and short-term borrowing rate, and we charge interest on extended payment balances at a blended prepayment and short-term borrowing rate. Amounts prepaid by our member distribution cooperatives are included in accounts payable-members and totaled $76.2 million and $53.9 million at December 31, 2011 and 2010, respectively. Amounts extended by our member distribution cooperatives are included in accounts receivable-members and totaled $7.4 million and $3.6 million at December 31, 2011 and 2010, respectively.

 

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NOTE 13—Employee Benefits

Substantially all of our employees participate in the NRECA Retirement Security Plan, a noncontributory, defined benefit multiple employer master pension plan. The legal name of the plan is the NRECA Retirement Security Plan; the employer identification number is 53–0116145, and the plan number is 333. Plan information is available publicly through the annual Form 5500, including attachments. The plan year is January 1 through December 31. In total, the NRECA Retirement Security Plan was between 65% and 80% funded at December 31, 2010 and 2009, based on the PPA funding target and PPA actuarial value of assets on those dates. We participate in a pension restoration plan, which is intended to provide a supplemental benefit for employees who would have a reduction in their pension benefit from the Retirement Security Plan because of the IRC limitations. The cost of these plans is funded annually by payments to NRECA to ensure that annuities in amounts established by the plan will be available to individual participants upon their retirement. Our contributions were $2.7 million, $2.6 million, and $2.0 million, in 2011, 2010, and 2009, respectively. In each of these years, our contributions represented less than 5% of the total contributions made to the plan by all participating employers and there were no changes that significantly affect the comparability of the 2011, 2010, and 2009 contributions. There has been no funding improvement plan or rehabilitation plan implemented nor is one pending, and we did not pay a surcharge to the plan for 2011. Pension expense, inclusive of administrative fees, was $2.8 million, $2.7 million, and $2.0 million for 2011,2010, and 2009, respectively.

We have also elected to participate in a defined contribution 401(k) retirement plan administered by Diversified Investment Advisors. We match up to the first 2% of each participant’s base salary. Our matching contributions were $203,000, $195,000, and $190,000, in 2011, 2010, and 2009, respectively.

NOTE 14—Insurance

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

The Price-Anderson Amendments Act of 1988 provides the public up to $12.6 billion of liability protection per nuclear incident, via obligations required of owners of nuclear power plants, and allows for an inflationary provision adjustment every five years. Virginia Power has purchased $375.0 million of coverage from commercial insurance pools with the remainder provided through a mandatory industry risk-sharing program. In the event of a nuclear incident at any licensed nuclear reactor in the United States, we, jointly with Virginia Power, could be assessed up to $118.0 million for each licensed reactor not to exceed $18.0 million per year per reactor. There is no limit to the number of incidents for which this retrospective premium can be assessed.

Virginia Power’s current level of property insurance coverage, $2.55 billion for North Anna, exceeds the NRC minimum requirement for nuclear power plant licensees of $1.06 billion per reactor site and includes coverage for premature decommissioning and functional total loss. The NRC requires that the proceeds from this insurance be used first, to return the reactor to and maintain it in a safe and stable condition and second, to decontaminate the reactor and station site in accordance with a plan approved by the NRC. The nuclear property insurance is provided to Virginia Power and us, jointly, by NEIL, a mutual insurance company, and is subject to retrospective premium assessments in any policy year in which losses exceed the funds available to the insurance company. The maximum assessment for the current policy period is $40.0 million. Based on the severity of the incident, the board of directors of the nuclear insurer has the discretion to lower or eliminate the maximum retrospective premium assessment. We, jointly with Virginia Power, have the financial responsibility for any losses that exceed the limits or for which insurance proceeds are not available because they must first be used for stabilization and decontamination.

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

 

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Our share of the contingent liability for the coverage assessments described above is estimated to be a maximum of $34.2 million at December 31, 2011.

NOTE 15—Regional Headquarters, Inc.

We own 50% of RHI, which holds title to the office building that is being partially leased to us, which we account for under the equity method. We are obligated to make lease payments equal to one half of RHI’s annual operating expenses, net of rental income from third party lessees, through July 15, 2016. Our rent expense was $0.3 million, $0.4 million, and $0.3 million for 2011, 2010, and 2009, respectively.

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

 

Year Ending December 31,		(in thousands)
2012		$	448
2013			448
2014			448
2015			448
2016			243
		$	2,035

NOTE 16—Supplemental Cash Flows Information

Cash paid for interest, net of amounts capitalized, in 2011, 2010, and 2009, was $49.0 million, $44.4 million, and $45.8 million, respectively. Cash paid for income taxes was immaterial in 2011,2010, and 2009.

NOTE 17—Commitments and Contingencies

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.

Our direct capital expenditures for environmental control equipment at our generating facilities, excluding capitalized interest, were immaterial in 2011, 2010, and 2009.

Insurance

Under several of the nuclear insurance policies procured by Virginia Power to which we are a party, we are subject to retrospective premium assessments in any policy year in which losses exceed the funds available to the insurance companies. See Note 14—Insurance.

 

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NOTE 18—Selected Quarterly Financial Data (Unaudited)

A summary of the quarterly results of operations for the years 2011 and 2010 follow. Amounts reflect all adjustments, consisting of only normal recurring accruals, necessary in the opinion of management for a fair statement of the results for the interim periods. Results for the interim periods may fluctuate as a result of weather conditions, changes in rates and other factors.

 

		First Quarter				Second Quarter				Third Quarter				Fourth Quarter				Total
		(in thousands)
Statement of Operations Data
2011
Operating Revenue		$	232,095			$	219,052			$	229,909			$	210,483			$	891,539
Operating Margin			14,350				15,573				16,599				16,068				62,590
Net Margin			2,388				3,055				2,670				2,694				10,807
2010
Operating Revenue (1)		$	175,657			$	184,063			$	245,430			$	239,320			$	844,470
Operating Margin			11,945				12,328				12,959				16,439				53,671
Net Margin			2,191				2,383				2,799				2,785				10,158

 

(1)	Rappahannock Electric Cooperative and Shenandoah Valley Electric Cooperative acquired additional service territory June 1, 2010.

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

None

ITEM 9A. CONTROLS AND PROCEDURES

Evaluation of Effectiveness of Disclosure Controls and Procedures

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

Management’s Annual Report on Internal Control over Financial Reporting

Our management has assessed our internal control over financial reporting as of December 31, 2011, 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, 2011, our system of internal control over financial reporting was properly designed and operating effectively based upon the specified criteria. We have not identified any material weaknesses in our internal control over financial reporting.

 

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Our management is responsible for establishing and maintaining adequate internal control over financial reporting. Our internal control over financial reporting is comprised of policies, procedures, and reports designed to provide reasonable assurance to our 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; (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 our receipts and expenditures are being made only in accordance with authorizations of our management and directors; and (3) provide reasonable safeguards against or timely detection of material unauthorized acquisition, use or disposition of our assets.

Changes in Internal Control over Financial Reporting

There has been no change in our internal control over financial reporting that occurred during 2011 that has materially affected, or is reasonably likely to materially affect, our internal control over financial reporting.

Inherent Limitations on Internal Control

There are inherent limitations to the effectiveness of any system of internal control over financial reporting. No control system can provide absolute assurance that all control issues and instances of error or fraud, if any, have been detected. Even the best designed system can only provide reasonable assurance that the objectives of the control system have been met. Because of these inherent limitations, our internal control over financial reporting may not prevent or detect all misstatements. Additionally, projections as to the effectiveness of internal control in future periods are subject to the risk that internal control may not continue to operate at its current effectiveness levels due to changes in personnel or in our operating environment.

ITEM 9B. OTHER INFORMATION

Director

On March 13, 2012, Mr. Philip B. Tankard announced that he would be retiring as a director of ODEC effective March 31, 2012.

 

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PART III

ITEM 10. DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE

Directors

We are governed by a board of 23 directors, consisting of two representatives from each of our member distribution cooperatives and one representative from TEC. Pursuant to our bylaws, each of our eleven member distribution cooperatives, in good standing, may recommend candidates to the nominating committee of our board of directors. At the annual meeting each year, the nominating committee nominates candidates for election to our board of directors. At least one candidate from each member distribution cooperative must be a director of that member distribution cooperative. Currently and historically, the other candidate from each member distribution cooperative is the chief executive officer of that member distribution cooperative. The candidates for director are elected to our board of directors by a majority of the voting delegates from our member distribution cooperatives. Each member distribution cooperative has one voting delegate. We do not control who the member distribution cooperative recommends to the nominating committee. As a result, our board of directors has not developed criteria, such as diversity, for use in identifying nominees to our board of directors. One director currently serves as a director on behalf of a member distribution cooperative and TEC. Each elected candidate is authorized to represent that member for a renewable term of one year at our annual meeting. Our board of directors sets policy and provides direction to our President and CEO. Our board of directors meets approximately 11 times each year.

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

John William Andrew, Jr. (58). President and CEO of Delaware Electric Cooperative, Inc. since 2005. Mr. Andrew has held executive positions in the utility industry for over a decade and has been a director of ODEC since 2005.

M Dale Bradshaw (58). CEO of Prince George Electric Cooperative since 1995. Mr. Bradshaw has held executive positions in the utility industry for over a decade and has been a director of ODEC since 1995.

Vernon N. Brinkley (65). President and CEO of A&N Electric Cooperative since 2003. Mr. Brinkley has held executive positions in the utility industry for over three decades and has been a director of ODEC since 1982.

Darlene H. Carpenter (65). Realtor of Montague, Miller & Company Realtors, Inc. since 2006. Ms. Carpenter has been a director of ODEC since 2009 and a director of Rappahannock Electric Cooperative since 1984. Ms. Carpenter is a past director of National Rural Utilities Cooperative Finance Corporation where she completed two three-year terms including serving on the audit committee (as chairman), the loan committee and the corporate relations committee.

Glenn F. Chappell (68). Self-employed farmer since 1961. Mr. Chappell has been a director of ODEC since 1995 and a director of Prince George Electric Cooperative since 1985.

Earl C. Currin, Jr. (68). Retired, formerly Provost at Southside Community College where he served from 1970 to 2007. Dr. Currin taught both accounting and economics at the college level. Dr. Currin has been a director of ODEC since 2008 and a director of Southside Electric Cooperative since 1986.

Jeffrey S. Edwards (48). President and CEO of Southside Electric Cooperative since 2007. Mr. Edwards served as Executive Vice President of Albemarle Electric Membership Cooperative from 1998 to 2007. Mr. Edwards has held executive positions in the utility industry for over a decade and has been a director of ODEC since 2007.

Kent D. Farmer (54). President and CEO of Rappahannock Electric Cooperative since 2004. Mr. Farmer has held executive positions in the utility industry for over a decade and has been a director of ODEC since 2004.

 

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Fred C. Garber (67). Retired, formerly President of Mt. Jackson Farm Service from 1973 to 2003. Mr. Garber has been a director of ODEC since 2005 and a director of Shenandoah Valley Electric Cooperative since 1984.

Hunter R. Greenlaw, Jr. (66). President of Greenlaw, Edwards & Leake, Inc., a real estate development and general contracting company since 1974. Mr. Greenlaw has been a director of ODEC since 1991 and a director of Northern Neck Electric Cooperative since 1979.

Bruce A. Henry (66). Owner and Secretary/Treasurer of Delmarva Builders, Inc., since 1981. Mr. Henry has been a director of ODEC since 1993 and a director of Delaware Electric Cooperative, Inc. since 1978.

David J. Jones (63). Owner/operator of Big Fork Farms since 1970 and Vice President of Exchange Warehouse, Inc. from 1996 to 2006. Mr. Jones has been a director of ODEC since 1986 and a director of Mecklenburg Electric Cooperative since 1982.

Michael J. Keyser (35). CEO and General Manager of BARC Electric Cooperative since 2010. Mr. Keyser was CEO and General Counsel for American Samoa Power Authority from 2006 to 2010. Mr. Keyser has held executive positions in the utility industry since 2006 and has been a director of ODEC since 2010.

John C. Lee, Jr. (51). President and CEO of Mecklenburg Electric Cooperative since 2008. Mr. Lee served as Vice President of Member and External Relations of ODEC from 2004 to 2007. Mr. Lee has held executive positions in the utility industry for over a decade and has been a director of ODEC since 2008.

Paul E. Owen (61). Retired, formerly Director of Business Management with Smithfield Deli Group from 1974 to 2010. Mr. Owen has been a director of ODEC since 2006 and a director of Community Electric Cooperative since 2000.

James M. Reynolds (64). President of Community Electric Cooperative since 2001. Mr. Reynolds has held executive positions in the utility industry for over three decades and has been a director of ODEC since 1977.

Myron D. Rummel (59). President and CEO of Shenandoah Valley Electric Cooperative since 2005. Mr. Rummel has held executive positions in the utility industry for over a decade and has been a director of ODEC since 2005.

Keith L. Swisher (57). Owner/operator of Swisher Valley Farms, LLC since 1976. Mr. Swisher has been a Director of ODEC since 2008 and a director of BARC Electric Cooperative since 1981.

Philip B. Tankard (83). Retired, formerly CFO for Tankard Nurseries from 1988 to 2006. Mr. Tankard has been a director of ODEC since 2002 and a director of A&N Electric Cooperative since 1960. On March 13, 2012, Mr. Tankard announced that he would be retiring as a director of ODEC effective March 31, 2012.

Michael I. Wheatley (56). President and CEO of Choptank Electric Cooperative, Inc. since 2011. Mr. Wheatley also served as Senior Vice President Corporate Services of Choptank Electric Cooperative, Inc. from 2002 to 2011. Mr. Wheatley has held executive positions in the utility industry for over a decade and has been a director of ODEC since 2011.

Gregory W. White (59). President and CEO of Northern Neck Electric Cooperative since 2005. Mr. White has held executive positions in the utility industry for over a decade and has been a director of ODEC since 2005.

Carl R. Widdowson (74). Self-employed farmer since 1956. Mr. Widdowson has been a director of ODEC since 1987 and a director of Choptank Electric Cooperative, Inc. since 1980.

Audit Committee Financial Expert

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

 

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Executive Officers

Our President and CEO administers our day-to-day business and affairs. Our executive officers at December 31, 2011, their respective ages, positions and recent business experience are listed below.

Jackson E. Reasor (59). President and CEO of ODEC and the VMDA, an electric cooperative association which provides services to its members and certain other electric cooperatives, since 1998.

Robert L. Kees (59). Senior Vice President and CFO since 2006. Mr. Kees also served as our Vice President and Controller from 2004 to 2005.

Lisa D. Johnson (46). Senior Vice President and COO since March 15, 2011. Ms. Johnson served as Senior Vice President Power Supply from May 2006 to March 14, 2011. Prior to joining ODEC, Ms. Johnson served as Vice President of Mirant Corporation from 2001 to 2006.

Elissa M. Ecker (52). Vice President of Human Resources since 2004.

Code of Ethics

We have a code of ethics which applies to all our employees, including our President and CEO, Senior Vice President and CFO, and Vice President and Controller. A copy of our code of ethics is available without charge by sending a written request to Old Dominion Electric Cooperative, Attention Mr. Bryan S. Rogers, Vice President and Controller, 4201 Dominion Boulevard, Glen Allen, VA 23060.

 

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ITEM 11. EXECUTIVE COMPENSATION

COMPENSATION DISCUSSION AND ANALYSIS

General Philosophy

Our compensation philosophy has four objectives:

 

•

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

 

•

provide equitable and fair compensation;

 

•

support our business strategy; and

 

•

ensure compliance with applicable laws and regulations.

Total Compensation Package

We compensate our President and CEO and other senior management through the use of a total compensation package which includes base salary, competitive benefits, and the potential of a bonus. Our CEO’s base salary is derived from salary data provided by third parties through national compensation surveys. The national compensation survey data includes data from the labor market for positions of similar responsibilities.

Targeted Overall Compensation

Our compensation program utilizes detailed job descriptions for all of our employees, including senior management with the exception of the CEO, as an instrument to establish benchmarked positions. The market compensation information for each position is derived from salary data provided by third parties through national compensation surveys and includes salary data for positions within the determined competitive labor market. Our job descriptions are reviewed annually and include essential and non-essential responsibilities, required knowledge, skills and abilities, and formal education and experience necessary to accomplish the requirements of the position which in turn helps us achieve operational goals. Utilizing this information, our human resources department determines a market-based salary for each position based upon salary survey data provided by third parties. A third-party consultant reviews the market-based salary data we compiled for reasonableness and fairness annually. We have defined market-based salary as approximately the 50^th percentile of the market.

Process

We have a committee of our board of directors, the executive committee, which recommends all compensation and awards for our CEO to the entire board of directors and the entire board of directors approves the compensation. Our board of directors has delegated to our CEO the authority to establish and adjust compensation for all employees other than himself. The compensation for all other employees, including members of senior management other than the CEO, is approved by our CEO based upon market-based salary data. On an annual basis our board of directors reviews the performance and compensation of our CEO and our CEO reviews the performance and compensation of the remaining senior management.

Our CEO is also the CEO of the VMDA and their board of directors also approves the compensation of the CEO.

Base Salaries

We are an electric cooperative and do not have any stock and as a result, we do not have equity-based compensation programs. For this reason, substantially all of our compensation to our executive officers is provided in the form of base salary. We want to provide our senior management with a level of assured cash compensation in the form of base salary that is commensurate with the duties and responsibilities of their positions. These salaries were determined based on market data for positions with similar responsibilities.

 

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Bonuses

Our practice has been to, on infrequent occasions, award cash bonuses related to a specific event, such as the consummation of a significant transaction. On an annual basis, our board of directors determines the bonus criteria for our CEO and our CEO determines bonus criteria for all other members of senior management. At the discretion of our board of directors, our CEO may be awarded an annual bonus; and, at the discretion of our CEO, other members of senior management may be awarded an annual bonus.

Severance Benefits

We believe that companies should provide reasonable severance benefits to the CEO. With respect to our CEO, these severance benefits reflect the fact that it may be difficult to find comparable employment within a short period of time. Our CEO’s contractual rights to amounts following severance are set forth in his employment agreement. None of our other members of senior management have any contractual severance benefits.

Plans

Retirement Plans

We participate in the NRECA Retirement Security Plan, a noncontributory, defined benefit multiple employer master pension plan which is available to all employees, with limited exceptions, who work at least 1,000 hours per year. This plan is a qualified pension plan under IRC Section 401(a). Benefits, which accrue under the plan, are based upon the employee’s base annual salary as of November of the previous year.

We also have a 401(k) plan which is available to all employees in regular positions. Under the 401(k) plan for 2011, employees may have elected to have up to 100% or $16,500, whichever is less, of their salary withheld on a pre-tax basis, subject to Internal Revenue Service limitations, and invested on their behalf. We match up to the first 2% of each participant’s base salary. Also, a catch-up contribution is available for participants in the plan once they attain age 50. The maximum catch-up contribution for 2011 was $5,500.

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

Pension Restoration Plan

We participate in a pension restoration plan, which is intended to provide a supplemental benefit for employees who would have a reduction in their pension benefit because of IRC limitations. Currently, our CEO, Senior Vice President and CFO, and Senior Vice President and COO are the only participants in this plan. Our Vice President of Human Resources may participate in this plan in the future.

Perquisites and Other Benefits

Our board of directors reviews the perquisites that our CEO receives during contract discussions with our CEO. The perquisite for Mr. Reasor is expenses for personal use of a company automobile which amounted to $3,434 in 2011 and $3,465 in 2010.

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

 

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Change in Control

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

Summary Compensation Table

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

SUMMARY COMPENSATION

 

Name and Principal Position		Year				Salary				Bonus				Change in Pension Value and Non- Qualified  Deferred Compensation Earnings(1)				All Other Compensation(2)				Total
Jackson E. Reasor			2011			$	444,583			$	—			$	217,298			$	125,009			$	786,890
President and CEO			2010			$	430,000				—				171,693				124,073				725,766
			2009				419,583				20,000				169,505				88,957				698,045
Robert L. Kees			2011	(3)			268,446				15,000				223,356				75,751				582,553
Senior Vice President and CFO			2010				259,373				—				166,762				73,478				499,613
			2009				254,850				—				178,346				53,251				486,447
Lisa D. Johnson			2011				321,812				—				30,527				88,751				441,090
Senior Vice President and COO(4)			2010				305,182				—				72,005				84,060				461,247
			2009				294,164				—				14,896				59,418				368,478
Elissa M. Ecker			2011				186,470				—				39,903				52,000				278,373
Vice President of Human Resources			2010				176,454				—				32,336				50,002				258,792
			2009				172,698				—				27,251				36,454				236,403

 

(1)	The values disclosed here represent the change in the pension value including the change in the defined pension plan and the pension restoration plan.

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

(3)	For 2011, salary includes a lump sum salary adjustment of $4,200. Lump sum salary adjustments are not included in the calculation of pension benefits.

(4)	On March 15, 2011, Ms. Johnson was promoted to Senior Vice President and COO. Prior to March 15, 2011, Ms. Johnson held the position of Senior Vice President Power Supply.

Employment Agreement

In 2006, ODEC entered into an employment agreement with Jackson E. Reasor, our CEO. The agreement is for the term of five years, with an automatic one-year extension unless Mr. Reasor or ODEC and the VMDA (collectively, the “Employer”) give written notice 30 days prior to the expiration of the agreement. The agreement provides that he will receive an annual salary of $360,000, effective as of June 1, 2006, subject to annual adjustment by the boards of directors of the Employer. The boards of directors of the Employer also may grant Mr. Reasor an annual bonus at their discretion. Mr. Reasor will also be entitled to participate in all benefit plans available to the employees of the Employer. The VMDA contributed $45,000 of Mr. Reasor’s salary in 2011 and is expected to contribute the same amount in 2012.

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

 

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

Based upon a hypothetical termination date of December 31, 2011, the severance benefits Mr. Reasor would have been entitled to would be as follows:

 

Base Salary		$	455,000
Targeted bonus			—
Healthcare and other insurance benefits			12,677
Total		$	467,677

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

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

Our board of directors is currently in the process of negotiating an employment agreement with Mr. Reasor.

 

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Defined Benefit Plan

The following table lists the estimated values under the NRECA Retirement Security Plan and the pension restoration plan. As a result of changes in Internal Revenue Service regulations, the base annual salary used in determining benefits is limited to $250,000 effective January 1, 2012.

PENSION BENEFITS

 

Name		Plan Name		Number of Years Credited Service				Present Value of  Accumulated Benefit				Payments During Last Year
Jackson E. Reasor		NRECA Retirement Security Plan			12.08			$	709,894			$	—
		Pension Restoration Plan			12.08				486,188				—
Robert L. Kees		NRECA Retirement Security Plan			19.00				1,109,962				—
		Pension Restoration Plan			19.00				25,803				—
Lisa D. Johnson		NRECA Retirement Security Plan			4.58				112,883				—
		Pension Restoration Plan			4.58				16,790				—
Elissa M. Ecker		NRECA Retirement Security Plan			6.08				164,281				—

The pension benefits indicated above are the estimated amounts payable by the plan, and they are not subject to any deduction for Social Security or other offset amounts. The participant’s annual pension at his or her normal retirement date, currently age 62, is equal to the product of his or her years of benefit service times final average salary times the multiplier in effect during years of benefit service. The multiplier was 1.7% commencing January 1, 1992. The number of years of credited service is as of the end of the current year for each of the named executives. The present value of accumulated benefit is calculated assuming that the executive retires at the normal retirement age per the plan, but using current number of years of credited service, and that he or she receives a lump sum. The lump sum amounts are calculated using the 30-year Treasury rate (4.19% for 2011 and 4.31% for 2010) and the PPA three segment yield rates (2.16%,4.77% and 6.05% for 2011, and 3.13%, 5.07% and 5.50% for 2010) and the required Internal Revenue Service mortality table for lump sum payments (1994 GAS, projected to 2002, blended 50%/50% for unisex mortality in combination with the 30-year Treasury rates and RP 2000 PPA at 2011 combined unisex 50%/50% mortality in combination with the PPA rates.) Lump sums at normal retirement age are then discounted to the last day of the appropriate year using these same assumptions shown for the respective stated interest rates.

Deferred Compensation Plan

In 2006, in connection with the execution of the employment agreement with Mr. Reasor, we adopted the Deferred Compensation Plan for the purpose of providing supplemental deferred compensation to Mr. Reasor in an amount within the statutory maximums permitted under IRC Section 457. The Deferred Compensation Plan is restricted to those executive employees designated by our board of directors who are generally responsible for ongoing operations, responsible for and have general supervision over the overall financial condition, responsible for setting and executing overall corporate policies and practices, and responsible for supervising large numbers of employees and who elect to participate in the Deferred Compensation Plan by agreeing to a deferral of a portion of their current compensation. Currently, Mr. Reasor is the only participant in the Deferred Compensation Plan. Under the Deferred Compensation Plan, annual deferrals cannot exceed the lesser of 100% of Mr. Reasor’s annual compensation or $16, 500 (for 2011), adjusted by and subject to specified tax laws (the “deferral limit”), during any year in which we are exempt from federal income taxation. During the last three years before Mr. Reasor attains the normal retirement age under our primary pension plan, the deferral limit is increased to the lesser of two times the

 

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

The following table sets forth the non-qualified deferred compensation paid to our executive officers in 2011:

NON-QUALIFIED DEFERRED COMPENSATION

 

Name

Executive Contributions in Last Fiscal Year(1)

Registrant Contributions in Last Fiscal Year(1)

Aggregate (Losses) in Last Fiscal Year

Aggregate Withdrawals/ Distributions

Aggregate Balance at Last Fiscal Year End

Jackson E. Reasor

$

—

$

15,000

$

(3,576

)

$

—

$

91,129

Robert L. Kees

n/a

n/a

n/a

n/a

n/a

Lisa D. Johnson

n/a

n/a

n/a

n/a

n/a

Elissa M. Ecker

n/a

n/a

n/a

n/a

n/a

 

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

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

ALL OTHER COMPENSATION

 

Name		Perquisites and Other Personal Benefits(1)				Company Contributions to Defined Benefit Plans				Company- paid Insurance Premiums				All Other Compensation
Jackson E. Reasor(2)		$	8,334			$	114,343			$	2,332			$	125,009
Robert L. Kees			4,900				69,435				1,416				75,751
Lisa D. Johnson			4,900				82,175				1,676				88,751
Elissa M. Ecker			3,729				47,305				966				52,000

 

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

(2)	Perquisites and other personal benefits include $3,434 for personal use of a company automobile.

 

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Board of Directors Compensation

It is our policy to compensate the members of our board of directors who are not employed by one of our member distribution cooperatives (“outside directors”). Our outside directors were compensated by a monthly retainer of $2,500 in 2011. They were also paid for meetings at a rate of $400 per in person meeting and $200 per teleconference, if the meeting date fell outside the normal board of directors meeting dates. All directors are reimbursed for out-of-pocket expenses incurred in attending meetings. Our directors receive no other compensation. Our directors do not have pension benefits, non-equity incentive plan compensation, or other perquisites and because we are a cooperative, we do not have stock or other equity options. The following table sets forth the compensation we paid to our directors in 2011:

DIRECTOR COMPENSATION

 

Name		Fees Earned or Paid in Cash(1)
Darlene H. Carpenter		$	34,000
Glenn F. Chappell			33,800
Earl C. Currin, Jr.			32,600
Fred C. Garber			32,800
Hunter R. Greenlaw, Jr.			33,600
Bruce A. Henry			32,200
David J. Jones			33,000
Paul E. Owen			31,600
Keith L. Swisher			33,200
Philip B. Tankard			32,800
Carl R. Widdowson			33,800
		$	363,400

 

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

Compensation Committee Interlocks and Insider Participation

As described above, the executive committee of our board of directors establishes and the full board of directors approves all compensation and awards to the CEO. Our board of directors has delegated to our CEO the authority to establish and adjust compensation for all employees other than himself. No member of our board of directors is or previously was an officer or employee of ODEC or is or has engaged in transactions with ODEC, with two exceptions. Mr. Gregory W. White was an employee of ODEC from 1990 to 1996 and from 1999 to 2005 when he left his position as Senior Vice President of Power Supply to become the President and Chief Executive Officer of Northern Neck Electric Cooperative, one of our member distribution cooperatives. Mr. John C. Lee, Jr. was an employee of ODEC from 1992 to 2007 when he left his position as Vice President of Member and External Relations to become the President and Chief Executive Officer of Mecklenburg Electric Cooperative, one of our member distribution cooperatives. Our executive committee does not have a charter. Our directors are, however, employees or directors of our member distribution cooperatives.

Compensation Committee Report

The executive committee serves as the compensation committee of the board of directors and has reviewed and discussed with the management of ODEC the contents of the section entitled “Compensation Discussion and Analysis” and based on such review and discussion has recommended to the board of directors its inclusion in this annual report.

Gregory W. White, Chairman

John William Andrew, Jr.

Darlene H. Carpenter

Glenn F. Chappell

Paul E. Owen

Myron D. Rummel

 

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

Not Applicable.

ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS AND DIRECTOR INDEPENDENCE

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

ITEM 14. PRINCIPAL ACCOUNTANT FEES AND SERVICES

The following table presents fees for services provided by Ernst & Young LLP for fiscal years 2011 and 2010. All Audit, Audit-Related, and Tax Fees shown below were pre-approved by the Audit Committee in accordance with its established procedures.

 

		2011				2010
Audit Fees (a)		$	265,000			$	255,000
Audit-Related Fees (b)			117,878				—
Tax Fees (c)			5,400				5,145
Total		$	388,278			$	260,145

a)

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

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

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

For fiscal years 2011 and 2010, other than those fees listed above, we did not pay Ernst & Young LLP any fees for any other products or services.

Audit Committee Preapproval Process for the Engagement of Auditors

All audit, tax and other services to be performed by Ernst & Young LLP for us must be pre-approved by the Audit Committee. The Audit Committee reviews the description of the services and an estimate of the anticipated costs of performing those services. Pre-approval is granted usually at regularly scheduled meetings. During 2011 and 2010, all services performed by Ernst & Young LLP were pre-approved by the Audit Committee in accordance with this policy.

 

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PART IV

ITEM 15. EXHIBITS, FINANCIAL STATEMENT SCHEDULES

 

a)

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

 

1.

Financial Statements

See Index on page 47.

 

2.

Financial Statement Schedules

Not applicable.

 

3.

Exhibits

Exhibits

 

*3.1		Amended and Restated Articles of Incorporation of Old Dominion Electric Cooperative (filed as exhibit 3.1 to the Registrant’s Form 10-Q, File No. 33-46795, filed on August 11, 2000).
*3.2		Bylaws of Old Dominion Electric Cooperative, Amended and Restated as of December 31, 2008, as amended on November 11, 2008 (filed as exhibit 3 to the Registrant’s Form 8-K, File No. 000-50039, filed on November 14, 2008).
4.1		Second Amended and Restated Indenture of Mortgage and Deed of Trust, dated as of January 1, 2011, between Old Dominion Electric Cooperative and Branch Banking and Trust Company, as Trustee.
*4.2		Thirteenth Supplemental Indenture, dated as of November 1, 2002, to the Indenture of Mortgage and Deed of Trust dated as of May 1, 1992, between Old Dominion Electric Cooperative and SunTrust Bank (formerly Crestar Bank), as Trustee, including the form of the 2002 Series A Bond (filed as exhibit 4.14 to Amendment No. 1 to the Registrant’s Form S 3, File No. 333-100577, on November 25, 2002).
*4.3		Fourteenth Supplemental Indenture, dated as of December 1, 2002, to the Indenture of Mortgage and Deed of Trust dated as of May 1, 1992, between Old Dominion Electric Cooperative and SunTrust Bank (formerly Crestar Bank), as Trustee, including the form of the 2002 Series B Bond (filed as exhibit 4.1 to the Registrant’s Form 8-K, File No. 000-50039, on December 27, 2002).
*4.4		Fifteenth Supplemental Indenture, dated as of May 1, 2003, to the Indenture of Mortgage and Deed of Trust dated as of May 1, 1992, between Old Dominion Electric Cooperative and SunTrust Bank (formerly Crestar Bank), as Trustee (filed as Exhibit 4.A to the Registrant’s Form 10-K for the year ended December 31, 2003, File No. 000-50039, on March 22, 2004).
*4.5		Sixteenth Supplemental Indenture, dated as of July 1, 2003, to the Indenture of Mortgage and Deed of Trust dated as of May 1, 1992, between Old Dominion Electric Cooperative and SunTrust Bank (formerly Crestar Bank), as Trustee, including the form of the 2003 Series A Bond (filed as Exhibit 4.1 to the Registrant’s Form 8-K, File No. 000-50039, on July 25, 2003).
*4.6		Seventeenth Supplemental Indenture, dated as of January 1, 2004, to the Indenture of Mortgage and Deed of Trust dated as of May 1, 1992, between Old Dominion Electric Cooperative and SunTrust Bank (formerly Crestar Bank), as Trustee (filed as Exhibit 4.B to the Registrant’s Form 10-K for the year ended December 31, 2003, File No 000-50039, on March 22, 2004).

 

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*10.1		Nuclear Fuel Agreement between Virginia Electric and Power Company and Old Dominion Electric Cooperative, dated as of December 28, 1982, amended and restated October 17, 1983 (filed as exhibit 10.1 to the Registrant’s Form S-1 Registration Statement, File No. 33-46795, filed on March 27, 1992).
*10.2		Purchase, Construction and Ownership Agreement between Virginia Electric and Power Company and Old Dominion Electric Cooperative, dated as of December 28, 1982, amended and restated October 17, 1983 (filed as exhibit 10.2 to the Registrant’s Form S-1 Registration Statement, File No. 33-46795, filed on March 27, 1992).
*10.3		Clover Purchase, Construction and Ownership Agreement between Old Dominion Electric Cooperative and Virginia Electric and Power Company, dated as of May 31, 1990 (filed as exhibit 10.4 to the Registrant’s Form S-1 Registration Statement, File No. 33-46795, filed on March 27, 1992).
*10.4		Amendment No. 1 to the Clover Purchase, Construction and Ownership Agreement between Old Dominion Electric Cooperative and Virginia Electric and Power Company, effective March 12, 1993 (filed as exhibit 10.34 to the Registrant’s Form S-1 Registration Statement, File No. 33-61326, filed on April 19, 1993).
*10.5		Clover Operating Agreement between Virginia Electric and Power Company and Old Dominion Electric Cooperative, dated as of May 31, 1990 (filed as exhibit 10.6 to the Registrant’s Form S-1 Registration Statement, File No. 33-46795, filed on March 27, 1992).
*10.6		Amendment to the Clover Operating Agreement between Virginia Electric and Power Company and Old Dominion Electric Cooperative, effective January 17, 1995 (filed as exhibit 10.8 to the Registrant’s Form 10-K for the year ended December 31, 1994, File No. 33-46795, on March 15, 1995).
*10.7		Lease Agreement between Old Dominion Electric Cooperative and Regional Headquarters, Inc., dated July 29, 1986 (filed as exhibit 10.27 to the Registrant’s Form S-1 Registration Statement, File No. 33-46795, filed on March 27, 1992).
*10.8		Nuclear Decommissioning Trust Agreement between Old Dominion Electric Cooperative and Bankers Trust Company, dated March 1, 1991 (filed as exhibit 10.29 to the Registrant’s Form S-1 Registration Statement, File No. 33-46795, filed on March 27, 1992).
*10.9		Form of Salary Continuation Plan (filed as exhibit 10.31 to the Registrant’s Form S-1 Registration Statement, File No. 33-46795, filed on March 27, 1992).
*,****10.10		Second Amended and Restated Wholesale Power Contract between Old Dominion Electric Cooperative and A&N Electric Cooperative, dated January 1, 2009 (filed as exhibit 10.2 and 10.3 to the Registrant’s Form 10-Q for the quarterly period ended September 30, 2008, File No. 33-46795, filed on November 11, 2008).
*10.11		Interconnection Agreement between Delmarva Power & Light Company and Old Dominion Electric Cooperative, dated November 30, 1999 (filed as exhibit 10.33 to the Registrant’s Form 10-K for the year ended December 31, 2000, File No. 33-46795, on March 19, 2001).
**10.12		Participation Agreement, dated as of February 29, 1996, among Old Dominion Electric Cooperative, State Street Bank and Trust Company, the Owner Participant named therein and Utrecht America Finance Co (filed as exhibit 10.35 to the Registrant’s Form 10-K for the year ended December 31, 1996, File No. 33-46795, on March 20, 1997).
**10.13		Clover Unit 1 Equipment Interest Lease Agreement, dated as of February 29, 1996, between Old Dominion Electric Cooperative, as Equipment Head Lessor, and State Street Bank and Trust Company, as Equipment Head Lessee (filed as exhibit 10.36 to the Registrant’s Form 10-K for the year ended December 31, 1996, File No. 33-46795, on March 20, 1997).

 

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**10.14		Equipment Operating Lease Agreement, dated as of February 29, 1996, between State Street Bank and Trust Company, as Lessor, and Old Dominion Electric Cooperative, as Lessee (filed as exhibit 10.37 to the Registrant’s Form 10-K for the year ended December 31, 1996, File No. 33-46795, on March 20, 1997).
**10.15		Corrected Option Agreement to Lease, dated as of February 29, 1996, among Old Dominion Electric Cooperative and State Street Bank and Trust Company (filed as exhibit 10.38 to the Registrant’s Form 10-K for the year ended December 31, 1996, File No. 33-46795, on March 20, 1997).
**10.16		Clover Agreements Assignment and Assumption Agreement, dated as of February 29, 1996, between Old Dominion Electric Cooperative, as Assignor, and State Street Bank and Trust Company, as Assignee (filed as exhibit 10.39 to the Registrant’s Form 10-K for the year ended December 31, 1996, File No. 33-46795, on March 20, 1997).
**10.17		Payment Undertaking Agreement, dated as of February 29, 1996, between Old Dominion Electric Cooperative and Cooperative Centrale Raiffeisen Boerenleenbank B.A., “Rabobank Nederland”, New York Branch (filed as exhibit 10.42 to the Registrant’s Form 10-K for the year ended December 31, 1996, File No. 33-46795, on March 20, 1997).
**10.18		Payment Undertaking Pledge Agreement, dated as of February 29, 1996, between Old Dominion Electric Cooperative, as Payment Undertaking Pledgor, and State Street Bank and Trust Company, as Payment Undertaking Pledgee (filed as exhibit 10.43 to the Registrant’s Form 10-K for the year ended December 31, 1996, File No. 33-46795, on March 20, 1997).
**10.19		Pledge Agreement, dated as of February 29, 1996, between Old Dominion Electric Cooperative, as Pledgor, and State Street Bank and Trust Company, as Pledgee (filed as exhibit 10.44 to the Registrant’s Form 10-K for the year ended December 31, 1996, File No. 33-46795, on March 20, 1997).
**10.20		Tax Indemnity Agreement, dated as of February 29, 1996, among Old Dominion Electric Cooperative, State Street Bank and Trust Company, the Owner Participant named therein and Utrecht America Finance Co. (filed as exhibit 10.45 to the Registrant’s Form 10-K for the year ended December 31, 1996, File No. 33-46795, on March 20, 1997).
**10.21		Amendment No. 3 to Participation Agreement (filed as Exhibit 10.1 to the Registrant’s Form 10-Q for the quarter ended March 31, 2006, File No. 000-50039, on May 12, 2006).
**10.22		Amendment No. 2 to Equipment Operating Lease Agreement(filed as Exhibit 10.2 to the Registrant’s Form 10-Q for the quarter ended March 31, 2006, File No. 000-50039, on May 12, 2006).
**10.23		Amendment No. 2 to Corrected Foundation Operating Lease Agreement(filed as Exhibit 10.3 to the Registrant’s Form 10-Q for the quarter ended March 31, 2006, File No. 000-50039, on May 12, 2006).
**10.24		Investment Agreement(filed as Exhibit 10.4 to the Registrant’s Form 10-Q for the quarter ended March 31, 2006, File No. 000-50039, on May 12, 2006).
**10.25		Investment Pledge Agreement(filed as Exhibit 10.5 to the Registrant’s Form 10-Q for the quarter ended March 31, 2006, File No. 000-50039, on May 12, 2006).
**10.26		Amendment No. 3 to Payment Undertaking Agreement(filed as Exhibit 10.6 to the Registrant’s Form 10-Q for the quarter ended March 31, 2006, File No. 000-50039, on May 12, 2006).
**10.27		Amendment No. 2 to Tax Indemnity Agreement(filed as Exhibit 10.7 to the Registrant’s Form 10-Q for the quarter ended March 31, 2006, File No. 000-50039, on May 12, 2006).

 

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**10.28		Employment Agreement, dated June 1, 2006, between Old Dominion Electric Cooperative and Jackson E. Reasor and accepted by Jackson E. Reasor on December 18, 2006 (filed as Exhibit 10.1 to the Registrant’s Form 8-K, File No. 000-50039, on December 21, 2006).
**10.29		Executive Deferred Compensation Plan, dated June 30, 2006, adopted on December 18, 2006 (filed as Exhibit 10.2 to the Registrant’s Form 8-K File No. 000-50039, on December 21, 2006).
**10.30		Employment letter, dated November 28, 2005, of Old Dominion Electric Cooperative and agreed and accepted by Robert L. Kees (filed as exhibit 10.1 to the Registrant’s Form 8-K, No. 000-50039, on November 28, 2005).
**10.31		Amendment No. 1 to Participation Agreement, dated as of December 19, 2002, among Old Dominion Electric Cooperative, State Street Bank and Trust Company, the Owner Participant named therein, Utrecht America Finance Co and Cedar Hill International Corp.
**10.32		Amendment No. 1 to Equipment Operating Lease Agreement, dated as of December 19, 2002, between State Street Bank and Trust Company, as Lessor, and Old Dominion Electric Cooperative, as Lessee.
**10.33		Amendment No. 1. to Corrected Foundation Operating Lease Agreement, dated as of December 19, 2002, between State Street Bank and Trust Company, as Foundation Lessor and Old Dominion Electric Cooperative, as Foundation Lessee.
**10.34		Amendment No. 2 to Payment Undertaking Agreement, dated as of December 19, 2002 between Old Dominion Electric Cooperative and Cooperatieve Centrale Raiffeisen Boerenleenbank B.A., “Rabobank Nederland”, New York Branch.
*10.35		Amendment No. 1 to Tax Indemnity Agreement, dated as of December 19, 2002, between Old Dominion Electric Cooperative and the Owner Participant named therein.
**10.36		Amendment No. 2 to Participation Agreement, dated as of December 31, 2004, between and among Old Dominion Electric Cooperative, U.S. Bank National Association, Wachovia Bank, National Association, Utrecht-America Finance Co., and Cedar Hill International Corp. (filed as exhibit 10.1 to the Registrant’s Form 8-K, File No. 000-50039, on January 13, 2005).
*10.37		Mutual Operating Agreement, dated as of May 18, 2005, between Virginia Electric and Power Company and Old Dominion Electric Cooperative.
*10.38		Employment letter, dated March 30, 2007, of Old Dominion Electric Cooperative and agreed and accepted by Bryan S. Rogers (filed as exhibit 10.1 to the Registrant’s Form 8-K, No. 000-50039, on April 2, 2008).
10.39		Credit Agreement, dated as of November 21, 2011, among Old Dominion Electric Cooperative, the lenders, party thereto, the Issuing Lenders party thereto, and Wells Fargo Bank, National Association, as Administrative Agent and Swingline Lender.
21		Subsidiaries of Old Dominion Electric Cooperative (not included because Old Dominion Electric Cooperative’s subsidiaries, considered in the aggregate as a single subsidiary, would not constitute a “significant subsidiary” under Rule 102(w) of Regulation S-X).
23.1		Consent of Ernst & Young LLP
31.1		Certification of the Principal Executive Officer pursuant to Rule 13a-14(a)
31.2		Certification of the Principal Financial Officer pursuant to Rule 13a-14(a)
32.1		Certification of the Principal Executive Officer pursuant to 18 U.S.C. § 1350

 

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32.2		Certification of the Principal Financial Officer pursuant to 18 U.S.C. § 1350
101.INS*****		XBRL Instance Document
101.SCH*****		XBRL Taxonomy Extension Schema Document
101.CAL*****		XBRL Taxonomy Extension Calculation Linkbase Document
101.LAB*****		XBRL Taxonomy Extension Label Linkbase Document
101.PRE*****		XBRL Taxonomy Extension Presentation Linkbase Document

 

*		Incorporated herein by reference.
**		The lease relates to our interest in all of Clover Unit 1 and related common facilities, other than the foundations. At the time this lease was executed, we had entered into identical leases with respect to the foundations as part of the same transactions. We agree to furnish to the Commission, upon request, a copy of the lease of our interest in the foundations for Clover Unit 1.
****		This agreement is substantially similar in all material respects to the wholesale power contracts of our other member distribution cooperatives.
*****		XBRL (“Extensible Business Reporting Language”) information is furnished and not filed or part of a registration statement or prospectus for purposes of Sections 11 or 12 of the Securities Act of 1933, is deemed not filed for purposes of Section 18 of the Securities Exchange Act of 1934, and otherwise is not subject to liability under these sections.

 

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SIGNATURES

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

 

Date: March 14, 2012

Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the Registrant and in the following capacities on March 14, 2012.

 

Signature		Title
/s/    JACKSON E. REASOR         Jackson E. Reasor		President and Chief Executive Officer (Principal executive officer)
/s/    ROBERT L. KEES         Robert L. Kees		Senior Vice President and Chief Financial Officer (Principal financial officer)
/s/    BRYAN S. ROGERS         Bryan S. Rogers		Vice President and Controller (Principal accounting officer)
/s/    J. WILLIAM ANDREW, JR.         J. William Andrew, Jr.		Director
/s/    M DALE BRADSHAW         M Dale Bradshaw		Director
/s/    VERNON N. BRINKLEY         Vernon N. Brinkley		Director
/s/    DARLENE H. CARPENTER         Darlene H. Carpenter		Director
/s/    GLENN F. CHAPPELL         Glenn F. Chappell		Director
/s/    EARL C. CURRIN, JR.         Earl C. Currin, Jr.		Director

 

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/s/    JEFFREY S. EDWARDS         Jeffrey S. Edwards		Director
/s/    KENT D. FARMER         Kent D. Farmer		Director
/s/    FRED C. GARBER         Fred C. Garber		Director
Hunter R. Greenlaw, Jr.		Director
/s/    BRUCE A. HENRY         Bruce A. Henry		Director
/s/    DAVID J. JONES         David J. Jones		Director
/s/    MICHAEL J. KEYSER         Michael J. Keyser		Director
/s/    JOHN C. LEE, JR.         John C. Lee, Jr.		Director
/s/    Paul E. Owen         Paul E. Owen		Director
/s/    JAMES M. REYNOLDS         James M. Reynolds		Director
/s/    MYRON D. RUMMEL         Myron D. Rummel		Director
/s/    KEITH L. SWISHER         Keith L. Swisher		Director

 

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/s/    PHILIP B. TANKARD         Philip B. Tankard		Director
/s/    MICHAEL I. WHEATLEY         Michael I. Wheatley		Director
/s/    GREGORY W. WHITE         Gregory W. White		Director
/s/    CARL R. WIDDOWSON         Carl R. Widdowson		Director

 

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

ODEC does not solicit proxies from its cooperative members and thus is not required to provide an annual report to its security holders and will not prepare such a report after filing this Form 10-K for fiscal year 2011. Accordingly, ODEC will not file an annual report with the Securities and Exchange Commission.