Old Dominion Electric Cooperative 10-K 2012 FY Annual report

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-K

(Mark One)

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

For the fiscal year ended December 31, 2012

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

OLD DOMINION ELECTRIC COOPERATIVE

2012 ANNUAL REPORT ON FORM 10-K

Item Number		Page Number
	Glossary of Terms		1
	PART I
1.	Business		3
1A.	Risk Factors		17
1B.	Unresolved Staff Comments		22
2.	Properties		23
3.	Legal Proceedings		25
4.	Mine Safety Disclosures		25
	PART II
5.	Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities		26
6.	Selected Financial Data		26
7.	Management’s Discussion and Analysis of Financial Condition and Results of Operations		28
7A.	Quantitative and Qualitative Disclosures About Market Risk		47
8.	Financial Statements and Supplementary Data		49
9.	Changes in and Disagreements With Accountants on Accounting and Financial Disclosure		74
9A.	Controls and Procedures		74
	PART III
10.	Directors, Executive Officers and Corporate Governance		76
11.	Executive Compensation		79
12.	Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters		86
13.	Certain Relationships and Related Transactions, and Director Independence		86
14.	Principal Accounting Fees and Services		86
	PART IV
15.	Exhibits, Financial Statement Schedules		87
	SIGNATURES

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
DEC	Delaware Electric Cooperative, Inc.
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, of ODEC 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)
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
RPM	Reliability Pricing Model
RPS	Renewable portfolio standards
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.
VDEQ	Virginia Department of Environmental Quality
Virginia Power	Virginia Electric and Power Company
VMDAEC	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 customers (meters), representing a total population of approximately 1.2 million people in 2012.

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-customers. 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.

We are a not-for-profit electric cooperative and 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 108 employees as of March 1, 2013.

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.

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Our Class A members are electric distribution cooperatives. Electric distribution cooperatives own and operate electric distribution systems to supply the power requirements of their retail customers. 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.

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.

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Revenues from our member distribution cooperatives and the percentage each contributed to total revenues from sales to member distribution cooperatives in 2012 are as follows:

Member Distribution Cooperatives	Revenues		Total Revenues
	(in millions)
Rappahannock Electric Cooperative	$	280.4		33.9	%
Shenandoah Valley Electric Cooperative		152.1		18.4
Delaware Electric Cooperative, Inc.		95.4		11.5
Choptank Electric Cooperative, Inc.		75.9		9.2
Southside Electric Cooperative		66.0		8.0
A&N Electric Cooperative		48.4		5.8
Mecklenburg Electric Cooperative		40.6		4.9
Prince George Electric Cooperative		22.1		2.7
Northern Neck Electric Cooperative		19.7		2.4
Community Electric Cooperative		14.1		1.7
BARC Electric Cooperative		12.1		1.5
Total	$	826.8		100.0	%

No individual customer of our member distribution cooperatives constituted more than 3.6% of our revenues from our member distribution cooperatives.

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. The unemployment rate in their service territories is below that of the national average. Our member distribution cooperatives’ 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, poultry, telecommunications, agriculture, forestry and wood products, paper, travel, and trade.

Our member distribution cooperatives’ sales of energy in 2012 totaled approximately 11,542,630 MWh. These sales were divided by customer class as follows:

Customer Class	Percentage of MWh Sales			Percentage of Customers
Residential		58.4	%		89.4	%
Commercial and industrial		40.3			9.6
Other		1.3			1.0

From 2007 through 2012, our eleven member distribution cooperatives experienced a compound annual growth rate of approximately 6.0% in the number of customers and a compound annual growth rate of 7.6% 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

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distribution cooperatives can expand their service territories through acquisition. Excluding the Potomac Edison acquisition and the SVEC disposition, both which occurred in 2010, we estimate that our eleven member distribution cooperatives experienced a compound annual growth rate of approximately 1.6% in the number of customers and a compound annual growth rate of approximately 1.5% 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 14.8% since 2007 to approximately 9.4 customers per mile in 2012. System densities of our member distribution cooperatives in 2012 ranged from 6.4 customers per mile in the service territory of BARC Electric Cooperative to 14.4 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 3.8% since 2007 to approximately 8.5 customers per mile in 2012. In 2012, the average service density for all distribution electric cooperatives in the United States was approximately 7.4 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.

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 principal exception 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. Purchases under this exception constituted approximately 0.8% of our member distribution cooperatives’ total energy requirements and approximately 2.5% of our member distribution cooperatives’ total capacity requirements in 2012.

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; however, during 2013, we currently anticipate that they will receive approximately 6.5 MW under these exceptions. We do not anticipate that this will have a material impact on our financial condition, results of operations, or cash flows.

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

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“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.

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—the demand and energy costs 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. Additionally, they may make adjustments to their rates to collect fixed costs through a new or modified fixed monthly charge rather than through volumetric charges associated with energy usage so long as such adjustments are revenue neutral.

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, DEC, is not regulated by the DPSC, including with respect to wholesale power costs which are a pass through to its customers.

We are not subject to any RPS, however, beginning in 2013, DEC is subject to RPS. To meet the RPS, DEC will purchase renewable energy credits and is constructing a 4 MW solar energy farm expected to be in-service in the second quarter of 2013. In accordance with the wholesale power contract between DEC and us, DEC may receive up to the greater of 5.0% of their power requirements or 5 MW from owned generation or other suppliers. Based on an assumed capacity factor of 38%, the 4 MW solar energy farm is expected to produce approximately 1.5 MW of capacity during the times of our summer peak demands.

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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, 2013, 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 exceeds 90 MW. Additionally, all customers are permitted to select an alternative power supplier that provides 100% renewable energy if their incumbent utility, such as one of our member distribution cooperatives, does not offer this same option. As of March 1, 2013, 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, results of operations, or cash flows.

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 may acquire natural gas and forward purchase contracts to hedge the price of natural gas to supply our combustion turbine facilities, and may take 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 energy supply resources for the past three years were as follows:

	Year Ended December 31,
	2012				2011				2010
	(in MWh and percentages)
Generated:
Clover		2,188,463	17.3	%		2,583,593	19.5	%		3,092,662	24.3	%
North Anna		1,772,672	14.0			1,452,147	10.9			1,554,338	12.2
Louisa		73,058	0.6			111,835	0.8			382,211	3.0
Marsh Run		122,149	1.0			149,396	1.1			624,951	4.9
Rock Springs		66,695	0.5			125,119	1.0			193,498	1.5
Distributed Generation		650	—			863	—			897	—
Total Generated		4,223,687	33.4			4,422,953	33.3			5,848,557	45.9
Purchased:
Other than renewable		7,990,984	63.1			8,423,465	63.5			6,692,647	52.5
Renewable(1)		444,364	3.5			429,166	3.2			210,702	1.6
Total Purchased		8,435,348	66.6			8,852,631	66.7			6,903,349	54.1
Total Available Energy		12,659,035	100.0	%		13,275,584	100.0	%		12,751,906	100.0	%

⁽¹⁾  Related to our contracts from renewable facilities from which we obtain renewable energy credits. We sell these renewable energy credits to our member distribution cooperatives and non-members. The renewable energy credits sales were immaterial for the years ended December 31, 2012, 2011, and 2010.

Clover and North Anna, our baseload generating facilities, satisfied approximately 23.4% of our capacity obligations and 31.3% of our energy requirements in 2012. Louisa, Marsh Run and Rock Springs, our peaking generating facilities, collectively provided 45.1% of our 2012 capacity obligations, and 2.1% of our 2012 energy requirements. For a description of our generating facilities, see “Properties” in Item 2. In 2012, 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 generating 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.

In 2012, our member distribution cooperatives’ peak demand occurred in July and was 2,538 MW, excluding power supplied by SEPA which is not an ODEC resource. See “Members—Member Distribution Cooperatives—Wholesale Power Contracts.”

We plan to continue purchasing energy for significant periods into the future by utilizing a combination of physically-delivered forward power purchase contracts, 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 and settling energy transactions. See “Quantitative and Qualitative Disclosures About Market Risk” in Item 7A.

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Power Supply Planning

We continually evaluate power supply options available to us to meet the needs of our member distribution cooperatives. Our goal is to supply 50% to 70% of our energy needs from our owned generation and long-term contracted resources. We have policies that establish targets that define 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 generating facilities.

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. Recent EPA regulatory developments, low natural gas prices, and slower growth in demand stemming from the economic downturn have significantly changed the power supply landscape. As a result, development of either tract of land is on hold indefinitely.

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.

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 generating 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. This can result in baseload facilities being used less frequently than has historically been the case. For example, the dispatch of Clover has decreased in recent years due to the increase in the number of facilities utilizing natural gas and the decrease in the cost of natural gas. 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

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the owners of generating facilities, including ODEC, offer to run their facilities to meet the requirements of energy customers. 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 generating 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, 2016. 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.

We have a long-term power purchase agreement with Exelon to supply 200 MW of energy and capacity to us for ten years ending in May 2020.

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, one of which became operational in 2013, are located in Pennsylvania and one is in Maryland. Additionally, we have renewable resources through energy purchase contracts from three landfill gas-to-energy projects, one each in Maryland, Delaware, and Virginia. These contracts allow us to buy output from the renewable facilities at a predetermined price. We do not own or operate these facilities and are not responsible for the operational costs.

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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 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, 2012, and December 31, 2011, there was a 77 day and a 73 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 trial held in 2008 ruled in favor of Virginia Power and the DOE filed an appeal. In 2011, the Federal Appeals Court issued a decision affirming the trial court’s damages award and 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 in 2011. Virginia Power sought reimbursement for certain spent nuclear fuel-related costs incurred subsequent to June 30, 2006, and on November 1, 2012, signed a settlement agreement with the DOE. Our proportionate share of these costs from July 1, 2006 through December 31, 2012, is $8.3 million, which we recorded as a $6.2 million reduction to fuel expense and a $2.1 million reduction to property, plant, and equipment, as the settlement includes a reimbursement of costs related to fixed assets. Of the $8.3 million settlement amount, we received reimbursement of $6.2 million in the fourth quarter of 2012, and we anticipate receiving the remaining $2.1 million, which has been recorded as a receivable, in the fourth quarter of 2013.

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. 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 environmental related capital expenditures at our generating facilities were approximately $8.6 million in 2012.

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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.

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 a stay to the implementation of CSAPR pending judicial review. On August 21, 2012, the Court vacated CSAPR, ruling that the EPA had exceeded its statutory authority. On October 5, 2012, the EPA petitioned for a rehearing of the Court’s CSAPR decision. On January 24, 2013, the Court denied the EPA’s petition for rehearing. Because of these actions, CAIR currently remains in effect.

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 discussed below. 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 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 and seasonal CAIROS Allowances. Clover is allocated a certain number of CAIRNO_xAllowances and CAIROS Allowances. If Clover emits more NO_x emissions than the allotted allowances cover, then additional CAIRNO_x 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_xemissions and all three sites have been allocated CAIRNO_x and CAIROS Allowances under CAIR. The CAIRNO_x 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.

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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 2008 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.

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. The final rule was published on February 16, 2012. On July 20, 2012, the EPA issued a notice of reconsideration of the portion of the rule for new source standards and on August 2, 2012, issued a partial stay. On November 16, 2012, the EPA proposed revised emission limits on new power plants, and this proposed revision is currently in the comment process. We do not anticipate that any additional measures will be required at Clover to comply with MATS due to Clover’s existing pollution control equipment, 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 will affect fossil fuel-fired electric generating facilities, particularly permitting of any new fossil fuel-fired generation. It will also have an effect on the renewal of Title V Operating Permits for Clover, Louisa, Marsh Run, and Rock Springs, as the rules will require that existing facilities have established limits for GHGs in their operating permits.

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 in 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.

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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 have installed the required control equipment and monitoring systems prior to the May 3, 2013 compliance date. In addition to the capital improvements, we must comply with ongoing semi-annual reporting and triennial compliance testing requirements.

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 for all states is 75 parts per billion. ODEC continues to monitor the progress of this standard and the states’ nonattainment area designation 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. Initial draft implementation guidance from the EPA proposes a combination of conventional ambient monitoring as well as source modeling to demonstrate attainment. The EPA is still developing the implementation guidance related to the national ambient air quality standards and 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 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. We are awaiting the proposed rulemaking.

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. We are still awaiting a final ruling.

Renewable Portfolio Standards

We are not subject to any RPS, however, beginning in 2013, DEC is subject to RPS in Delaware.

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

Historically, our power supply strategy has relied substantially on purchases of energy from other power suppliers. In 2012, we purchased approximately 66.6% 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 2012 as our member distribution cooperatives’ requirements for power increase. Our reliance on energy purchases also could increase because the operation of our generating 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.

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

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

• Weather;

• Supply and demand;

• The availability of competitively priced alternative energy sources;

• The transportation of fuels;

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

• Energy transmission or natural gas transportation capacity constraints;

• Impact of implementation of new technologies in the power industry;

• Federal, state, and local energy and environmental regulation and legislation; including increased regulation of the extraction of natural gas and coal; and

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

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

We currently are required to comply with numerous federal, state, and local laws and regulations relating to the protection of the environment. While we believe that we have obtained all material environmental-related approvals currently required to own and operate our facilities or that these approvals have been applied for and will be issued in a timely manner, we may incur significant additional costs because of compliance with these requirements in addition to costs related to any costs of compliance with laws or regulations relating to CO₂and 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.

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 cap and trade program requiring allowances to emit CO₂ in the operation of coal-fired and other fossil fuel-fired generating facilities. The additional costs related to a tax on CO₂emissions or a cap and trade program could affect the relative cost of the energy generated by our facilities that burn coal and other fossil fuels. Because PJM dispatches facilities from lowest to highest cost, these additional costs may cause our CO₂emitting generating

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facilities to be dispatched less often than they are currently and likely would result in our purchasing 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.

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.

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 2012, 63.8% of our revenues from sales to our member distribution cooperatives were received from our three largest members, REC, SVEC, and DEC.

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 customers 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 14.0% of our energy requirements in 2012. Ownership of an interest in a nuclear generating facility involves risks, including:

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

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

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

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

The NRC has broad authority under federal law to impose licensing and safety-related requirements for the operation of North Anna. If the facility is not in compliance, the NRC may impose fines or shut down the units until compliance is achieved, or both depending upon its assessment of the situation. Revised safety requirements issued by the NRC have, in the past, necessitated substantial capital expenditures at other nuclear generating facilities. North Anna’s operating and safety procedures may be subject to additional federal or state regulatory scrutiny as a result of 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

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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.

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. Additionally, existing or new regulations related to the use of hedging instruments may impact our access to and use of hedging instruments.

We are evaluating and pursuing new power supply options.

We are in the process of evaluating and pursuing new power supply options which may result in significant capital expenditures in the future. Significant capital expenditures carry with them the risk that decisions made today can have implications well into the future. Failure to anticipate market, technology, and regulatory risks regarding particular capital assets can impact their cost to operate and value in the future. In addition, construction carries with it risks relating to timely completion and operational effectiveness.

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.

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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 and fixed purchase price.

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 $310.8 million at December 31, 2012, was issued by Rabobank, which has senior debt obligations which are currently rated “AA-” by S&P and “Aa2” 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, 2012, the total balance of our remaining lease obligation was $345.3 million. 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.

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 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.

Poor market performance will affect the asset values in our nuclear decommissioning trust 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 underfunding.

War, acts and threats of terrorism, sabotage, cyber security breach, 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, sabotage, or cyber security breach. The physical or cyber security compromise of our facilities could adversely affect our ability to manage these facilities effectively. We have not experienced any disruptions or significant costs associated with intentional attacks or unauthorized access to any of our systems. We have programs and procedures in place to safeguard our operating systems. 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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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 complete impact cannot be determined until regulations are finalized.

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

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

ITEM 1B. UNRESOLVED STAFF COMMENTS

None

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ITEM 2. PROPERTIES

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

Generating Facility	Ownership Interest			Location	Primary Fuel	Commercial Operation Date	Net Capacity Entitlement(1)
Clover		50.0	%(2)	Halifax County, Virginia	Coal	Unit 1 – 10/1995	215 MW
						Unit 2 – 03/1996	218 MW
							433 MW
North Anna		11.6	%	Louisa County, Virginia	Nuclear	Unit 1 – 06/1978(3) (4)	109 MW
						Unit 2 – 12/1980(3)	109 MW
							218 MW
Louisa		100.0	%	Louisa County, Virginia	Natural Gas(5)	Unit 1 – 06/2003 Unit 2 – 06/2003 Unit 3 – 06/2003 Unit 4 – 06/2003 Unit 5 – 06/2003	84 MW 84 MW 84 MW 84 MW 168 MW
							504 MW
Marsh Run		100.0	%	Fauquier County, Virginia	Natural Gas(5)	Unit 1 – 09/2004 Unit 2 – 09/2004 Unit 3 – 09/2004	168 MW 168 MW 168 MW
							504 MW
Rock Springs		50.0	%(6)	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	2,015 MW

⁽¹⁾  Represents an approximation of our entitlement to the maximum dependable capacity for Clover and North Anna, which does not represent actual usage. Represents a nominal average of summer and winter capacities for Louisa, Marsh Run, and Rock Springs.

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

⁽³⁾  We purchased our 11.6% undivided ownership interest in North Anna in December 1983.

⁽⁴⁾  In 2012, an upgrade to the main steam turbines was completed on North Anna Unit 1 resulting in a revised net capacity entitlement.

⁽⁵⁾  The units at this facility also operate on No. 2 distillate fuel oil.

⁽⁶⁾ We own 100.0% of two units, each with a net capacity rating of 168 MW, and 50.0% 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.

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 50.0% 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.

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

Distributed Generation Facilities

We have distributed generation facilities in our member distribution cooperatives’ service 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. MINE SAFETY DISCLOSURES

Not Applicable

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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, 2012, 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,
	2012		2011		2010		2009		2008
	(in thousands, except ratios)
Statement of Operations Data
Operating Revenues	$	842,681	$	891,539	$	844,470	$	713,169	$	1,040,751
Operating Margin		59,145		62,590		53,671		57,736		61,417
Net Margin attributable to ODEC(1)		9,939		10,807		10,158		9,687		11,784
Margins for Interest Ratio		1.21		1.22		1.23		1.21		1.23

	December 31,
	2012			2011			2010			2009			2008
	(in thousands, except ratios)
Balance Sheet Data
Net Electric Plant	$	991,340		$	1,012,905		$	1,037,404		$	1,008,373		$	1,016,579
Total Investments		263,024			235,199			196,597			176,076			199,129
Other Assets		289,157			325,876			278,434			255,463			290,037
Total Assets	$	1,543,521		$	1,573,980		$	1,512,435		$	1,439,912		$	1,505,745
Patronage capital	$	360,424		$	350,485		$	339,678		$	329,520		$	319,833
Non-controlling interest		13,257			13,093			13,166			13,178			12,787
Long-term debt		737,836			766,128			449,798			688,736			711,675
Long-term debt due within one year(2)		28,292			28,292			238,917			22,917			22,917
Revolving credit facilities		—			—			7,043			26,954			62,000
Total Capitalization and Short-term Debt	$	1,139,809		$	1,157,998		$	1,048,602		$	1,081,305		$	1,129,212
Equity Ratio(3)		32.0	%		30.6	%		32.8	%		30.9	%		28.6	%

⁽¹⁾ Net Margin for 2010 includes an additional equity contribution of $1.3 million.

⁽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.

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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.

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. 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’ energy and demand requirements through a portfolio of resources including generating facilities, long-term and short-term physically-delivered forward power purchase contracts, and spot market purchases. We also supply the transmission services necessary to deliver this power to our member distribution cooperatives.

Purchased power and fuel expenses are affected by market pricing, the output provided by our owned generation, and our member distribution cooperatives’ customers’ requirements for power. Purchased power expense decreased for 2012 as compared to 2011, due to a decrease in the average cost and volume of purchased power. Fuel expense decreased for 2012 as compared to 2011, primarily as a result of PJM’s decreased economic dispatch of our combustion turbine facilities and Clover as well as the operational availability of Clover due to outages.

Deferred energy expense represents the difference between energy revenues and energy expenses. In 2012 we over-collected energy costs from our member distribution cooperatives as compared to 2011 when we under-collected energy costs. Over-collected energy costs appear as a liability on our Condensed Consolidated Balance Sheet and will be refunded to our member distribution cooperatives in subsequent periods through our formulary rate. For further discussion on deferred energy, see “Critical Accounting Policies—Deferred Energy” 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 noted above, increased our MWh and MW sales to our member distribution cooperatives approximately 35% to 40% on an annualized basis.

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In accordance with the wholesale power contracts between ODEC and its member distribution cooperatives, ODEC is serving the additional power requirements resulting from the Potomac Edison acquisition.

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 $21.4 million, $16.6 million, and $7.4 million, was recorded in 2012, 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.

Critical Accounting Policies

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

Accounting for Rate Regulation

We are a rate-regulated entity and, as a result, are subject to the accounting requirements of Accounting for Regulated Operations. In accordance with Accounting for Regulated Operations, some of our revenues and expenses can be deferred at the discretion of our board of directors, which has budgetary and rate setting authority, if it is probable that these amounts will be refunded or recovered through our formulary rate in future years. Regulatory assets on our Consolidated Balance Sheet are costs that we expect to recover from our member distribution cooperatives based on rates approved by our board of directors in accordance with our formulary rate. Regulatory liabilities on our Consolidated Balance Sheet represent probable future reductions in our revenues associated with amounts that we expect to refund to our member distribution cooperatives based on rates approved by our board of directors in accordance with our formulary rate. See “Factors Affecting Results—Formulary Rate” below. Regulatory assets are generally included in deferred charges and regulatory liabilities are generally included in deferred credits and other liabilities. We recognize regulatory assets and liabilities as expenses or as a reduction in expenses, concurrent with their recovery through rates.

Deferred Energy

In accordance with Accounting for Regulated Operations, we use the deferral method of accounting to recognize differences between our energy expenses and our energy revenues collected from our member distribution cooperatives. Deferred energy expense on our Consolidated Statement of Revenues, Expenses, and Patronage Capital represents the difference between energy revenues and energy expenses. The deferred energy balance on our Consolidated Balance Sheet represents the net accumulation of any under- or over-collection of energy costs. Under-collected energy costs appear as an asset on our Consolidated Balance Sheet and will be collected from our member distribution cooperatives in subsequent periods through our formulary rate. Conversely, over-collected energy costs appear as a liability on our Consolidated Balance Sheet and will be refunded to our member distribution cooperatives in subsequent periods through our formulary rate.

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Margin Stabilization Plan

We have a Margin Stabilization Plan that allows us to review our actual demand-related costs of service and demand 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 2012, 2011, and 2010, under our Margin Stabilization Plan, we reduced operating revenues by $15.0 million, $14.9 million, and $22.5 million, respectively.

Accounting for Asset Retirement and Environmental 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, 2012, North Anna’s nuclear decommissioning asset retirement obligation totaled $68.5 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.

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We determine cost escalation rates, which represent projected cost increases over time, due to both general inflation and increases in the cost of specific decommissioning activities. The following table details the weighted average cost escalation rates used by the study:

Year Study Performed	Weighted Average Cost Escalation Rate
2002		3.27	%
2005		2.42
2009		2.30

The weighted average cost escalation rate was applied if the cash flows increased as compared to the previous study. The original weighted average cost escalation rate was applied if the cash flows decreased as compared to the previous study. The use of alternative rates would have been material to the liabilities recognized. For example, had we increased the cost escalation rates by 0.5%, the amount recognized as of December 31, 2012, for our asset retirement obligations related to nuclear decommissioning would have been $14.3 million higher.

Accounting for Derivatives and Hedging

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 these forward purchase derivative contracts qualify for the normal purchases/normal sales accounting exception under Accounting for Derivatives and Hedging. As a result, these contracts are not recorded at fair value. We record a liability and purchased power expense when the power under the physically-delivered forward contract is delivered. We also purchase natural gas futures generally for three years or less to hedge the price of natural gas for the operation of our combustion turbine facilities. 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 defer all unrealized 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 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 demand.

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The rates we charge our member distribution cooperatives for sales of energy and demand 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, 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.

Demand 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 demand-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 revenues 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 succeeding calendar 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

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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 Statements of Revenues, Expenses, and Patronage Capital reflect the actual demand-related costs we incurred plus the energy costs that we collected during each calendar quarter and at year-end. Estimated demand-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 demand-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 energy 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 demand 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 customers 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.

Customers’ Requirements for Power

Growth in the number of customers and growth in customers’ requirements for power significantly affect our member distribution cooperatives’ customers’ requirements for power. Factors affecting our member distribution cooperatives’ customers’ 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.

• Heating degree days are a measurement tool used to quantify the need to utilize heat for a building, and cooling degree days are a measurement tool used to quantify the need to utilize cooling for a building. The heating degree days and cooling degree days for the three years ended December 31, were as follows:

	2012		2011		2010
Heating degree days		2,880		3,188		3,730
Cooling degree days		1,363		1,427		1,787

• 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.

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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. See “Risk Factors” in Item 1A.

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 2012, 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 generating 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 may materially affect our operating results. For further discussion related to PJM, see “Business—Power Supply Resources—PJM” in Item 1.

Generating Facilities

Our operating expenses, and consequently our rates to our member distribution cooperatives, are significantly affected by the operations of our baseload generating facilities, Clover and North Anna. Baseload generating facilities, particularly nuclear power plants such as North Anna, generally have relatively high fixed costs. Nuclear facilities operate with relatively low variable costs due to lower fuel costs and technological efficiencies. In addition, coal-fired facilities have relatively low variable costs, as compared to combustion turbine facilities such as Louisa, Marsh Run, and Rock Springs. Our combustion turbine facilities have relatively low fixed costs and greater operational flexibility; however, they are more expensive to operate and, as a result, are dispatched only when the market price of energy makes their operation economical or when their operation is required by PJM for system reliability purposes.

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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 and combustion turbine facilities are dispatched based upon economic factors including the market price of energy. The operational availability of our owned generating resources for the past three years was as follows:

	Year Ended December 31,
	2012			2011			2010
Clover		85.3	%		92.7	%		95.4	%
North Anna		90.7			75.5			81.5
Louisa		97.5			97.8			98.4
Marsh Run		98.7			98.2			97.3
Rock Springs		96.8			96.2			94.2

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:

	Year Ended December 31,
	2012			2011			2010
Clover		58.1	%		68.6	%		81.6	%
North Anna		92.9			76.9			82.7

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

	Clover Year Ended December 31,						North Anna Year Ended December 31,
	2012		2011		2010		2012		2011		2010
	(in days)						(in days)
Scheduled		62.0		37.3		21.1		36.0		31.8		67.3
Unscheduled		45.7		16.5		12.9		29.0		143.3		54.5
Total		107.7		53.8		34.0		65.0		175.1		121.8

The majority of the unscheduled outages for Clover related to the extension of planned maintenance outages due to findings during the outages and other maintenance items.

Each unit at North Anna is scheduled for refueling approximately every 18 months. While only one unit is refueled at a time, this typically results in both units being down for refueling during the same calendar year once every three years.

The majority of the unscheduled outages for North Anna during 2012 related to an extension of the spring outage for Unit 1 and an unscheduled reactor coolant pump seal replacement for Unit 2. The unscheduled outages for North Anna during 2011 related 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. The majority of the unscheduled outages for both units at North Anna during 2010 related to the inspection and replacement of non-accident qualified insulation.

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

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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’ customers’ 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; however, in 2012, 2011, and 2010, TEC had no sales to third parties.

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, and changes in market conditions.

Results of Operations

Operating Revenues

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

	Year Ended December 31,
	2012		2011		2010
	(in thousands)
Revenues from sales to:
Member distribution cooperatives
Base energy revenues	$	210,633	$	213,788	$	199,955
Energy adjustment revenues		316,884		327,402		298,464
Total energy revenues		527,517		541,190		498,419
Demand revenues		299,309		312,730		280,651
Total revenues from sales to member distribution cooperatives		826,826		853,920		779,070
Non-members		15,855		37,619		65,400
Total operating revenues	$	842,681	$	891,539	$	844,470
Average cost of energy to member distribution cooperatives (per MWh)	$	43.61	$	44.34	$	44.28
Average cost of demand to member distribution cooperatives (per MWh)		24.74		25.62		24.94
Average total cost to member distribution cooperatives (per MWh)	$	68.35	$	69.96	$	69.22

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

	Year Ended December 31,
	2012		2011		2010
	(in MWh)
Energy sales to:
Member distribution cooperatives		12,096,230		12,205,602		11,254,269
Non-members		508,443		941,908		1,356,542
Total energy sales		12,604,673		13,147,510		12,610,811
	(in MW)
Demand sales to member distribution cooperatives		24,027		24,166		21,960

In 2012, our energy sales in MWh and demand sales in MW to our member distribution cooperatives were relatively flat, as compared to 2011. 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 2012, our energy sales in MWh to non-members were 46.0% lower as compared to 2011. In 2011, our energy sales in MWh to non-members were 30.6% lower as compared to 2010. Sales to non-members consist of sales of excess purchased and generated energy.

In 2012, total revenues from sales to our member distribution cooperatives decreased $27.1 million, or 3.2%, as compared to 2011 primarily due to the 1.6% decrease in the average cost of energy and the 4.3% decrease in the demand costs we incurred. 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 2011, the demand costs we incurred, and thus the demand-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.

The average cost to member distribution cooperatives is affected by changes in the revenue dollars as well as the sales volumes. In 2012, our average total cost to member distribution cooperatives per MWh was 2.3% lower as compared to 2011. In 2011, our average total cost to member distribution cooperatives per MWh was relatively flat as compared to 2010.

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

Effective Date of Rate Change:	% Change
April 1, 2011		0.6
October 1, 2011		4.8
April 1, 2012		(4.6	)
October 1, 2012		(6.8	)

Non-member revenue decreased $21.8 million, or 57.9%, in 2012 as compared to 2011 due to the 46.0% decrease in the volume of excess energy sales and the 21.9% decrease in the average price. Non-member revenue decreased $27.8 million, or 42.5%, in 2011 as compared to 2010 due to the 30.6% decrease in the volume of excess energy sales and the 17.2% decrease in the average price.

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Operating Expenses

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

	Year Ended December 31,
	2012		2011			2010
	(in thousands)
Fuel	$	90,874	$	112,421		$	185,202
Purchased power		537,746		593,030			462,871
Deferred energy		21,315		(10,665	)		6,637
Operations and maintenance		42,615		40,642			39,467
Administrative and general		35,958		36,520			39,895
Depreciation and amortization		42,012		41,566			41,535
Amortization of regulatory asset/(liability), net		735		3,808			3,352
Accretion of asset retirement obligations		3,739		3,572			3,333
Taxes, other than income taxes		8,542		8,055			8,507
Total Operating Expenses	$	783,536	$	828,949		$	790,799

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 non-members. Our energy costs generally are variable and include fuel expense as well as the energy portion of our purchased power expense. Our demand costs generally are fixed and include operations and maintenance, administrative and general, and depreciation and amortization 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 demand costs. See “Factors Affecting Results—Formulary Rate” above.

In 2012, total operating expenses decreased $45.4 million, or 5.5%, as compared to 2011, primarily due to the decrease in purchased power and fuel expenses partially offset by the increase in deferred energy expenses.

• Purchased power expense, which includes the cost of purchased energy, capacity, and transmission, decreased $55.3 million, or 9.3%, primarily due to a 5.7% decrease in the average cost of purchased energy and a 4.7% decrease in the volume of purchased energy.

• Fuel expense decreased $21.5 million, or 19.2%, primarily due to PJM’s decreased economic dispatch of our combustion turbine facilities and Clover, and the lower average cost of fuel for the combustion turbine facilities.

• Deferred energy expense increased $32.0 million. During 2012, we over-collected $21.3 million in energy costs; whereas in 2011, we under-collected $10.7 million in energy costs. The over-collection in 2012 was the result of energy costs being less than anticipated in 2012. 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 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.

• 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. 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.

Other Items

Loss on Investments, Net

In accordance with regulatory accounting, we defer the difference between asset retirement expense, and interest income and realized gains and losses on the nuclear decommissioning trust, to our regulatory liability (North Anna asset retirement obligation deferral). For additional supplemental information, see Note 10 of the Notes to Consolidated Financial Statements. In July 2012, the investments in the nuclear decommissioning trust were rebalanced resulting in a net realized loss of $2.2 million. This loss is recorded in “Loss on investments, net” on the Consolidated Statements of Revenues, Expenses, and Patronage Capital; however, the loss is deferred to the regulatory liability referred to above via “Amortization of regulatory asset/liability, net.” Therefore, there is no net impact on the Consolidated Statements of Revenues, Expenses, and Patronage Capital. The impact on the Consolidated Statements of Cash Flows is reflected in the purchases of and proceeds from sale of available for sale securities.

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. See “Liquidity and Capital Resources—Sources—Auction Rate Securities” below.

Investment Income

Investment income decreased in 2012 by $0.8 million, or 16.9%, as compared to 2011, primarily due to lower income earned on our nuclear decommissioning trust. 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.

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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. The major components of interest charges, net for the past three years were as follows:

	Year Ended December 31,
	2012			2011			2010
	(in thousands)
Interest expense on long-term debt	$	(48,449	)	$	(50,984	)	$	(46,270	)
Interest charges related to Norfolk Southern		—			—			5,046
Other		(1,245	)		(3,052	)		(3,050	)
Total interest charges		(49,694	)		(54,036	)		(44,274	)
Allowance for borrowed funds used during construction		996			888			1,450
Interest charges, net	$	(48,698	)	$	(53,148	)	$	(42,824	)

In 2012, interest expense, net decreased $4.5 million, or 8.4%, as compared to 2011. We issued $350.0 million of debt in April 2011 and repaid $215.0 million of maturing debt in June 2011, resulting in additional interest expense on long-term debt in 2011. 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.

Net Margin Attributable to ODEC

In 2012, 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, decreased $0.9 million, or 8.0%, as compared to 2011, due to lower total interest charges in 2012 as compared to 2011. In 2011, our net margin 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.

Financial Condition

The principal changes in our financial condition from December 31, 2011 to December 31, 2012, were caused by the decrease in accounts payable–members, long-term debt, and regulatory assets, substantially offset by increases in deferred energy, unrestricted investments and other, nuclear decommissioning trust, and accounts payable.

• Accounts payable–members decreased $42.6 million due to the $52.7 million decrease in member prepayments offset by the $10.1 million increase in the margin stabilization adjustment as compared to December 2011.

• Long-term debt decreased $28.3 million as a result of scheduled maturities.

• Regulatory assets decreased $12.0 million primarily as a result of the change in the fair value of derivative instruments and the amortization of regulatory assets.

• Deferred energy increased $21.3 million as a result of the over-collection of our energy costs in 2012.

• Unrestricted investments and other increased $13.6 million as a result of the investment of excess working capital.

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• Nuclear decommissioning trust increased $11.8 million primarily as a result of the unrealized gains in the fair value of the investments.

• Accounts payable increased $10.2 million primarily as a result of an increase in the amounts due to Virginia Power in connection with our ownership interests in Clover and North Anna.

Liquidity and Capital Resources

Sources

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

Operations

In 2012, 2011, and 2010, our operating activities provided cash flows of $51.3 million, $40.1 million and $119.2 million, respectively. Operating activities in 2012 were primarily impacted by the following:

• Current liabilities changed $32.4 million primarily due to the $42.6 million decrease in accounts payable–members partially offset by the $10.2 million increase in accounts payable.

• Deferred energy changed $21.3 million due to the over-collection of energy costs in 2012.

Auction Rate Securities

During 2011, we sold our remaining ARS for $11.1 million and recognized a gain of $3.2 million. In 2010, we established a regulatory asset in accordance with Accounting for Regulated Operations to account for the difference between the principal of our ARS and the estimated fair value of our ARS. 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 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 “Aa2” 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 2012, distributions from the payment undertaking agreement provided $15.3 million, to fund rent payments under the lease.

Credit Facility

We maintain a $500.0 million, five-year committed revolving credit facility to cover our short-term and medium-term funding needs. Commitments under this syndicated credit agreement mature on November 20, 2016, unless earlier terminated in accordance with the agreement. We did not have any outstanding borrowings under this facility at December 31, 2012 or December 31, 2011; however, the interest rate would have been 1.2% and 1.3%, respectively.

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Our syndicated credit agreement contains customary events of default, which, if they occur, would terminate our ability to borrow amounts under this facility and potentially accelerate any outstanding loans under this facility at the election of the lenders. Some of these customary events of default relate to:

• our failure to timely pay any principal and interest due under the 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.

Our 2002 Series A bonds, with an aggregate principal amount of $60.2 million outstanding, are subject to optional redemption by ODEC on or after June 1, 2013. We currently anticipate that we will call the 2002 Series A bonds in the second quarter of 2013.

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

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Capital Expenditures

We regularly forecast our capital expenditures as part of our long-term business planning activities. We review these projections frequently in order to update our calculations to reflect changes in our future plans, construction costs, market factors, and other items affecting our forecasts. Our actual capital expenditures could vary significantly from these projections. The table below summarizes our actual and projected capital expenditures, including nuclear fuel and capitalized interest, for 2010 through 2015:

	Actual Year Ended  December 31,						Projected Year Ended  December 31,
	2010		2011		2012		2013		2014		2015
	(in millions)
Clover	$	9.6	$	9.9	$	11.2	$	16.1	$	16.9	$	14.9
North Anna(1)		36.4		31.9		18.6		9.4		18.1		11.9
Combustion turbine facilities		0.9		2.7		0.6		1.2		1.1		1.1
Other		31.6		1.6		2.0		6.1		5.5		5.6
Total	$	78.5	$	46.1	$	32.4	$	32.8	$	41.6	$	33.5

⁽¹⁾  Includes expenditures for North Anna Unit 3 of $13.6 million and $1.4 million for 2010 and 2011, respectively. In February 2011, we made the determination not to participate in North Anna Unit 3 and on December 16, 2011, we finalized our withdrawal. These costs are a portion of the costs reclassified to a regulatory asset. See “Note 10—Regulatory Assets and Liabilities in the Notes to the Consolidated Financial Statements” in Item 8.

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 flow from operations, borrowings under our syndicated credit facility, and potential long-term borrowings to fund all of our currently projected capital requirements through 2015.

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, 2012:

	Payments due by Period
	Total		2013		2014-2015		2016-2017		2018 and Thereafter
	(in millions)
Long-term indebtedness	$	1,326.6	$	71.5	$	138.1	$	131.6	$	985.4
Operating lease obligations		111.9		0.4		0.9		1.3		109.3
Power purchase obligations		1,334.7		185.7		362.0		358.0		429.0
Asset retirement obligations		389.4		—		—		—		389.4
Total	$	3,162.6	$	257.6	$	501.0	$	490.9	$	1,913.1

We expect to fund these obligations with cash flow from operations, borrowings under our syndicated credit facility, and potential long-term borrowings.

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Long-term Indebtedness

At December 31, 2012, 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 and Environmental 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, 2012, the collateral we had posted with counterparties pursuant to the power purchase contracts we have in place was $4.4 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, 2012, if our credit ratings had been below investment grade we estimate we would have been obligated to post between $500.0 million and $600.0 million of collateral with our counterparties. This calculation is based on energy prices on December 31, 2012, 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, 2012, if PJM had determined that we needed to provide collateral to support our obligations, PJM could have asked us to provide up to approximately $11.2 million.

TEC Guarantees

TEC is considered a variable interest entity for which we are the primary beneficiary, and we have consolidated its results and 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, 2012, we had issued guarantees for up to $38.5 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 provides 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 “Aa2” 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 2012, Rabobank paid $15.3 million of rent. At December 31, 2012, 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 $310.8 million.

45

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, 2012, the estimated amount of the letter of credit we would have been required to provide was approximately $5.5 million. The amount of any letter of credit we are required to deliver in connection with the lease decreases over time to zero by December 18, 2018.

At the end of the term of the Clover Unit 1 leaseback, we have the option to purchase the owner trust’s interest in the unit or arrange for an acceptable third party to enter into a power purchase agreement with the owner trust. If we decide to purchase the owner trust’s interest in the unit, we must pay the owner trust a fixed purchase price of $430.5 million. Payments under the payment undertaking agreement are expected to fund approximately $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 a price 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.

46

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 complete impact cannot be determined until regulations are finalized.

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, 2012, we estimate that the fair value of our purchased power agreements and forward purchases of energy and natural gas was between $2.1 billion and $2.2 billion. Approximately 16% of the fair value of this portfolio is estimable using observable market prices. The remaining 84% 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 84% 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 $34.8 million at December 31, 2012. 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 member distribution cooperatives 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.

47

Virginia Power advises us it uses both long-term contracts and short-term spot agreements 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.

Interest Rate Risk and Equity Price Risk

In 2012, 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 Facility” in Item 7. Any amounts we borrow under this facility will accrue interest at a variable rate. At December 31, 2012, 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, 2012, $37.8 million of these funds were invested in fixed-income securities and $75.2 million of these funds were invested in equity securities. The value of these equity and fixed income securities will be impacted by changes in interest rates and price fluctuations in equity markets. To minimize adverse changes in the aggregate value of the trust fund, we actively monitor our portfolio by measuring the performance of our investments against market indexes and by maintaining and reviewing established target allocation percentages of assets in our trust to various investment options. We believe the trust fund’s exposure to changes in interest rates and price fluctuations in equity markets will not have a material impact on our financial results.

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ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA

CONSOLIDATED FINANCIAL STATEMENTS

INDEX

	Page Number
Report of Management on ODEC’s Internal Control over Financial Reporting		50
Report of Independent Registered Public Accounting Firm		51
Consolidated Balance Sheets		52
Consolidated Statements of Revenues, Expenses, and Patronage Capital		53
Consolidated Statements of Cash Flows		54
Notes to Consolidated Financial Statements		55

49

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, 2012, 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, 2012, 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 13, 2013

/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, 2012 and 2011, 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, 2012. 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, 2012 and 2011, and the consolidated results of its operations and its cash flows for each of the three years in the period ended December 31, 2012, in conformity with U.S. generally accepted accounting principles.

Richmond, Virginia

March 13, 2013 /s/ Ernst & Young LLP

51

OLD DOMINION ELECTRIC COOPERATIVE

CONSOLIDATED BALANCE SHEETS

AS OF DECEMBER 31, 2012 AND 2011

	2012			2011
	(in thousands)
ASSETS:
Electric Plant:
Property, plant, and equipment	$	1,655,705		$	1,638,938
Less accumulated depreciation		(721,541	)		(697,031	)
		934,164			941,907
Nuclear fuel, at amortized cost		20,379			22,838
Construction work in progress		36,797			48,160
Net Electric Plant		991,340			1,012,905
Investments:
Nuclear decommissioning trust		113,280			101,474
Lease deposits		94,145			91,718
Unrestricted investments and other		55,599			42,007
Total Investments		263,024			235,199
Current Assets:
Cash and cash equivalents		37,343			63,756
Accounts receivable		3,564			7,210
Accounts receivable–deposits		4,400			6,500
Accounts receivable–members		86,154			82,236
Fuel, materials, and supplies		59,091			53,771
Prepayments and other		2,556			3,187
Total Current Assets		193,108			216,660
Deferred Charges:
Regulatory assets		87,006			98,964
Other		9,043			10,252
Total Deferred Charges		96,049			109,216
Total Assets	$	1,543,521		$	1,573,980
CAPITALIZATION AND LIABILITIES:
Capitalization:
Patronage capital	$	360,424		$	350,485
Non-controlling interest		13,257			13,093
Total Patronage capital and Non-controlling interest		373,681			363,578
Long-term debt		737,836			766,128
Total Capitalization		1,111,517			1,129,706
Current Liabilities:
Long-term debt due within one year		28,292			28,292
Accounts payable		75,583			65,416
Accounts payable–members		38,585			81,224
Accrued expenses		4,936			4,863
Deferred energy		56,027			34,712
Total Current Liabilities		203,423			214,507
Deferred Credits and Other Liabilities:
Asset retirement obligations		76,880			73,141
Obligations under long-term lease		74,086			69,285
Regulatory liabilities		71,452			75,580
Other		6,163			11,761
Total Deferred Credits and Other Liabilities		228,581			229,767
Commitments and Contingencies		—			—
Total Capitalization and Liabilities	$	1,543,521		$	1,573,980

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

52

OLD DOMINION ELECTRIC COOPERATIVE

CONSOLIDATED STATEMENTS OF REVENUES, EXPENSES, AND PATRONAGE CAPITAL

FOR THE YEARS ENDED DECEMBER 31, 2012, 2011, AND 2010

	2012			2011			2010
	(in thousands)
Operating Revenues	$	842,681		$	891,539		$	844,470
Operating Expenses:
Fuel		90,874			112,421			185,202
Purchased power		537,746			593,030			462,871
Deferred energy		21,315			(10,665	)		6,637
Operations and maintenance		42,615			40,642			39,467
Administrative and general		35,958			36,520			39,895
Depreciation and amortization		42,012			41,566			41,535
Amortization of regulatory asset/(liability), net		735			3,808			3,352
Accretion of asset retirement obligations		3,739			3,572			3,333
Taxes, other than income taxes		8,542			8,055			8,507
Total Operating Expenses		783,536			828,949			790,799
Operating Margin		59,145			62,590			53,671
Other expense, net		(2,224	)		(1,377	)		(1,723	)
Loss on investments, net		(2,156	)		(2,348	)		(3,558	)
Investment income		4,129			4,968			4,576
Interest charges, net		(48,698	)		(53,148	)		(42,824	)
Income taxes		(93	)		49			3
Net Margin including Non-controlling interest		10,103			10,734			10,145
Non-controlling interest		(164	)		73			13
Net Margin attributable to ODEC		9,939			10,807			10,158
Patronage Capital - Beginning of Year		350,485			339,678			329,520
Patronage Capital - End of Year	$	360,424		$	350,485		$	339,678

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

53

OLD DOMINION ELECTRIC COOPERATIVE

CONSOLIDATED STATEMENTS OF CASH FLOWS

FOR THE YEARS ENDED DECEMBER 31, 2012, 2011, AND 2010

	2012			2011			2010
	(in thousands)
Operating Activities:
Net Margin including Non-controlling interest	$	10,103		$	10,734		$	10,145
Adjustments to reconcile net margin to net cash provided by operating activities:
Depreciation and amortization		42,012			41,566			41,535
Other non-cash charges		14,616			10,454			10,149
Amortization of lease obligations		4,801			4,484			4,189
Interest on lease deposits		(2,710	)		(2,646	)		(2,586	)
Change in current assets		(2,861	)		11,250			(34,563	)
Change in deferred energy		21,315			(10,665	)		6,637
Change in current liabilities		(32,399	)		(21,247	)		90,121
Change in regulatory assets and liabilities		(248	)		(10,807	)		(11,596	)
Change in deferred charges and credits		(3,319	)		6,951			5,176
Net Cash Provided by Operating Activities		51,310			40,074			119,207
Financing Activities:
Issuance of long-term debt		—			350,000			—
Debt issuance costs		—			(2,342	)		—
Payment of long-term debt		(28,292	)		(244,292	)		(22,917	)
Draws on revolving credit facilities		—			52,257			110,304
Repayments on revolving credit facilities		—			(59,300	)		(130,215	)
Net Cash (Used for) Provided by Financing Activities		(28,292	)		96,323			(42,828	)
Investing Activities:
Purchases of held to maturity securities		(103,420	)		(159,030	)		—
Proceeds from sale of held to maturity securities		91,278			117,751			—
Purchases of available for sale securities		(24,290	)		—			—
Proceeds from sale of available for sale securities		24,308			—			325
Proceeds from sale of trading securities		—			11,089			—
Increase in other investments		(4,900	)		(3,100	)		(3,663	)
Electric plant additions		(32,407	)		(46,090	)		(78,486	)
Loss on investments, net		—			2,348			3,558
Net Cash Used for Investing Activities		(49,431	)		(77,032	)		(78,266	)
Net Change in Cash and Cash Equivalents		(26,413	)		59,365			(1,887	)
Cash and Cash Equivalents - Beginning of Year		63,756			4,391			6,278
Cash and Cash Equivalents - End of Year	$	37,343		$	63,756		$	4,391

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 $13.3 million and $13.1 million at December 31, 2012 and December 31, 2011, 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 customers 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 public service commissions of the state in which our member distribution cooperatives operate, but are set periodically by a formula that was accepted for filing by FERC.

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.

55

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

Depreciation

We conduct depreciation studies approximately every five years.

	Depreciation Rates
Generating Facility	2012			2011			2010
Clover		1.8	%		1.8	%		1.8	%
North Anna		3.0			3.0			2.9
Louisa		3.5			3.5			3.3
Marsh Run		3.2			3.2			3.4
Rock Springs		3.3			3.3			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.

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 trial held in 2008 ruled in favor of Virginia Power and the DOE filed an appeal. In 2011, the Federal Appeals Court issued a decision affirming the trial court’s damages award and 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 in 2011. Virginia Power sought reimbursement for certain spent nuclear fuel-related costs incurred subsequent to June 30, 2006, and on November 1, 2012, signed a settlement agreement with the DOE. Our proportionate share of these costs from July 1, 2006 through December 31, 2012, is $8.3 million, which we recorded as a $6.2 million reduction to fuel expense and a $2.1 million reduction to property, plant, and equipment, as the settlement includes a reimbursement of costs related to fixed assets. Of the $8.3 million settlement amount, we received reimbursement of $6.2 million in the fourth quarter of 2012, and we anticipate receiving the remaining $2.1 million, which has been recorded as a receivable, in the fourth quarter of 2013.

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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 2012, 2011, and 2010, was $1.0 million, $0.9 million, and $1.4 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.

TEC is a taxable corporation and its provision for income taxes was immaterial for the years ended December 31, 2012, 2011, and 2010.

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, 2012, 2011, and 2010, revenue from sales to our member distribution cooperatives was $826.8 million, $853.9 million, and $779.1 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; however, in 2012, 2011, and 2010, TEC had no sales to third parties. 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, 2012, 2011, and 2010, energy sales to non-members were $15.9 million, $37.6 million, and $65.4 million, respectively.

Formulary Rate

Our power sales are comprised of two power products – energy and 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 demand.

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The rates we charge our member distribution cooperatives for sales of energy and demand 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.

Debt Issuance Costs

Capitalized costs associated with the issuance of debt totaled $8.3 million and $9.1 million, at December 31, 2012 and 2011, 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 $5.4 million and $6.5 million at December 31, 2012 and 2011, respectively. This gain is being amortized into income ratably over the term of the operating lease, through 2018, 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, 2012 and 2011, we had an over-collected deferred energy balance of $56.0 million and $34.7 million, respectively. Over-collected deferred energy balances are refunded to our member distribution cooperatives in subsequent periods.

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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. 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, 2012, 2011, or 2010.

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 and our syndicated credit agreement. See Note 11—Long-term Debt for discussion of 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 $86.2 million and $82.2 million, at December 31, 2012 and 2011, respectively.

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Cash Equivalents

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

Segment

We are organized for the purpose of supplying the power our member distribution cooperatives require to serve their customers on a cost-effective basis. Our CEO serves as our chief operating decision maker who manages and reviews our operating results as one operating and therefore one reportable segment. We supply our member distribution cooperatives’ energy and demand requirements through a portfolio of resources including generating facilities, power purchase contracts, and forward, short-term and spot market energy purchases.

NOTE 2—Electric Plant

Our net electric plant is comprised of the following for 2012:

	Clover			North Anna			Combustion Turbine Facilities			Other			Total
	(in thousands)
Property, plant, and equipment(1)	$	672,541		$	331,878		$	584,004		$	67,282		$	1,655,705
Accumulated depreciation		(344,428	)		(176,442	)		(179,072	)		(21,599	)		(721,541	)
Nuclear fuel		—			63,186			—			—			63,186
Accumulated amortization of nuclear fuel		—			(42,807	)		—			—			(42,807	)
Construction work in progress		6,080			29,955			105			657			36,797
	$	334,193		$	205,770		$	405,037		$	46,340		$	991,340

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

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.

We hold a 50% undivided ownership interest in Clover, a two-unit, 866 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,

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liabilities, and operating expenses associated with Clover are included in our consolidated financial statements. At December 31, 2012 and 2011, we had an outstanding accounts payable balance of $14.7 million and $13.9 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, 1,879 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, 2012 and 2011, we had an outstanding accounts payable balance of $11.2 million and $6.0 million, respectively, due to Virginia Power for the operation, maintenance, and capital investment at North Anna.

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.”

The table below summarizes our projected capital expenditures, including nuclear fuel and capitalized interest, for 2013 through 2015:

	Projected Year Ended  December 31,
	2013		2014		2015
	(in millions)
Clover	$	16.1	$	16.9	$	14.9
North Anna		9.4		18.1		11.9
Combustion turbine facilities		1.2		1.1		1.1
Other		6.1		5.5		5.6
Total	$	32.8	$	41.6	$	33.5

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.

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A significant portion of our asset retirement obligations relate to our share of the future decommissioning of North Anna. At December 31, 2012 and 2011, North Anna’s nuclear decommissioning asset retirement obligation totaled $68.5 million and $65.2 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.

The following represents changes in our asset retirement obligations for the years ended December 31, 2012 and 2011 (in thousands):

Asset retirement obligations at December 31, 2010	$	67,876
Accretion expense		3,572
Additional asset retirement obligation		1,693
Asset retirement obligations at December 31, 2011	$	73,141
Accretion expense		3,739
Asset retirement obligations at December 31, 2012	$	76,880

The cash flow estimates for North Anna’s asset retirement obligations are based upon the 20-year life extension which was granted in 2003 and extends the life of Unit 1 to 2038 and Unit 2 to 2040. Given the life extension, the level of the nuclear decommissioning trust currently appears to be adequate to fund North Anna’s asset retirement obligations and no additional funding is currently required. Therefore, with the approval by FERC, we ceased collection of decommissioning expense in August 2003. As we are not currently collecting decommissioning expense in our rates, we are deferring the difference between the earnings on the nuclear decommissioning trust and the total asset retirement obligation related depreciation and accretion expense for North Anna as part of our asset retirement obligation regulatory liability. See Note 10—Regulatory Assets and Liabilities.

NOTE 4—Power Purchase Agreements

In 2012, 2011, and 2010, our owned generating facilities together furnished approximately 33.4%, 33.3%, and 45.9%, 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, 2012 and 2011, due to changes in energy prices, we were required to post $4.4 million and $6.5 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.

We have a long-term power purchase agreement with Exelon to supply 200 MW of energy and capacity to us for ten years ending in May 2020.

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Our purchased power costs for 2012, 2011, and 2010 were $537.7 million, $593.0 million, and $462.9 million, respectively.

As of December 31, 2012, our energy and capacity purchase commitments under the various agreements were as follows:

Year Ending December 31,	Energy and Capacity Commitments
	(in millions)
2013	$	185.7
2014		175.4
2015		186.6
	$	547.7

NOTE 5—Wholesale Power Contracts

We 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 extend until January 1, 2054 and beyond this date unless either party gives the other at least three years notice of termination.

The principal exception to the all-requirements obligations of the member distribution cooperatives relates to the ability of our mainland Virginia member distribution cooperatives to purchase hydroelectric power allocated to them from SEPA. Purchases under this exception constituted approximately 0.8% of our member distribution cooperatives’ total energy requirements and approximately 2.5% of our member distribution cooperatives’ total capacity requirements in 2012.

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. To date, none of our member distribution cooperatives have received any of their power requirements under these exceptions; however, during 2013, we currently anticipate that they will receive approximately 6.5 MW 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.

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

The formulary rate allows us to recover and refund amounts under our Margin Stabilization Plan. 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. Adjustments under our Margin Stabilization Plan were $15.0 million, $14.9 million, and $22.5 million for the years ending December 31, 2012, 2011, and 2010, respectively. During the third quarter of 2011, we refunded $10.0 million of the $14.9 million.

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

	Year Ended December 31,
	2012		2011		2010
	(in millions)
Rappahannock Electric Cooperative(1)	$	280.4	$	290.4	$	245.4
Shenandoah Valley Electric Cooperative(1)		152.1		159.8		123.2
Delaware Electric Cooperative, Inc.		95.4		97.6		100.0
Choptank Electric Cooperative, Inc.		75.9		76.6		77.5
Southside Electric Cooperative		66.0		67.5		68.7
A&N Electric Cooperative		48.4		50.1		51.0
Mecklenburg Electric Cooperative		40.6		41.8		42.0
Prince George Electric Cooperative		22.1		22.5		22.7
Northern Neck Electric Cooperative		19.7		20.5		20.9
Community Electric Cooperative		14.1		14.7		15.4
BARC Electric Cooperative		12.1		12.4		12.3
	$	826.8	$	853.9	$	779.1

⁽¹⁾  REC and SVEC acquired additional service territory on June 1, 2010.

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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.

The following table summarizes our financial assets and liabilities measured at fair value on a recurring basis as of December 31, 2012 and 2011:

	December 2012		Quoted 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)	$	113,280	$	38,048	$	75,232	$	—
Unrestricted investments and other(3)		122		122		—		—
Total Financial Assets	$	113,402	$	38,170	$	75,232	$	—
Derivatives - gas and power(4)	$	624	$	624	$	—	$	—
Total Financial Liabilities	$	624	$	624	$	—	$	—
	December 2011		Quoted 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	$	—

⁽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, an equity fund that invests in small capitalization stocks, and as of the third quarter of 2012, an equity fund that invests in international 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 include 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.

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We did not have any financial assets and liabilities measured at fair value on a recurring basis and included in the Level 3 fair value category.

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 Consolidated Statements 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, 2012 Quantity		As of December 31, 2011 Quantity
Natural Gas	MMBTU		650,000		3,800,000
Purchased Power	MWh		—		213,120

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 2012		As of December 2011
		(in thousands)
Derivatives in a liability position:
Natural gas futures contracts	Deferred credits and other liabilities-other	$	624	$	3,295
Purchased power contracts	Deferred credits and other liabilities-other		—		1,875
Total derivatives in a liability position		$	624	$	5,170

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The Effect of Derivative Instruments on the Statement of Revenues, Expenses, and Patronage Capital for the Years Ended December 31, 2012 and 2011

Derivatives Accounted for Utilizing Regulatory Accounting	Amount of Gain (Loss) Recognized in 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,
	2012			2011				2012			2011
	(in thousands)							(in thousands)
Natural gas futures contracts(1)	$	(2,264	)	$	(6,826	)	Fuel	$	(6,522	)	$	(6,035	)
Purchased power contracts		—			(1,875	)	Purchased power		(2,736	)		(517	)
Total	$	(2,264	)	$	(8,701	)		$	(9,258	)	$	(6,552	)

⁽¹⁾  As of December 31, 2012 and 2011, includes a regulatory asset of $1.6 million and $3.5 million, respectively, 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, 2012 and 2011, the unamortized portion of the deferred gain was $5.4 million and $6.5 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 $310.8 million at December 31, 2012, is issued by Rabobank, which has senior debt obligations which are currently rated “AA-” by S&P and “Aa2” by Moody’s, respectively. The amount of debt considered to be extinguished by in substance defeasance was $310.8 million and $311.8 million, at December 31, 2012 and 2011, 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, 2012 and 2011:

				Gross		Gross
				Unrealized		Unrealized			Fair		Carrying
Description	Designation	Cost		Gains		Losses			Value		Value
		(in thousands)
December 31, 2012
Nuclear decommissioning trust(1)(2)
Debt securities	Available for sale	$	34,342	$	3,473	$	—		$	37,815	$	37,815
Equity securities	Available for sale		61,322		13,910		—			75,232		75,232
Cash and other	Available for sale		233		—		—			233		233
Total Nuclear Decommissioning Trust		$	95,897	$	17,383	$	—		$	113,280	$	113,280
Lease Deposits(3)
Government obligations	Held to maturity	$	94,145	$	11,063	$	—		$	105,208	$	94,145
Total Lease Deposits		$	94,145	$	11,063	$	—		$	105,208	$	94,145
Unrestricted investments
Government obligations	Held to maturity	$	51,900	$	8	$	—		$	51,908	$	51,900
Debt securities	Held to maturity		1,750		—		—			1,750		1,750
Total Unrestricted Investments		$	53,650	$	8	$	—		$	53,658	$	53,650
Other
Equity securities	Available for sale	$	113	$	9	$	—		$	122	$	122
Non-marketable equity investments(4)	Equity		1,827		—		—			1,827		1,827
Total Other		$	1,940	$	9	$	—		$	1,949	$	1,949
											$	263,024
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(3)
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(4)	Equity		1,805		—		—			1,805		1,805
Total Other		$	1,901	$	—	$	(5	)	$	1,896	$	1,896
											$	235,199

⁽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. Unrealized gains and losses related to assets held in the nuclear decommissioning trust are deferred as a regulatory asset or liability.

⁽²⁾  In the third quarter of 2012, we rebalanced our portfolio in the nuclear decommissioning trust.

⁽³⁾  Investments in lease deposits are restricted for the use of funding our future lease obligations. See Note 8—Long-term Lease Transaction.

⁽⁴⁾  We believe the carrying value approximates fair value for our equity investments.

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Our investments by classification at December 31, 2012 and 2011, were as follows:

	December 31, 2012				December 31, 2011
			Carrying				Carrying
Description	Cost		Value		Cost		Value
	(in thousands)
Available for sale	$	96,010	$	113,402	$	94,403	$	101,565
Held to maturity		147,795		147,795		131,829		131,829
Equity		1,827		1,827		1,805		1,805
	$	245,632	$	263,024	$	228,037	$	235,199

Contractual maturities of unrestricted debt securities at December 31, 2012, were as follows:

	Less than						More than
Description	1 year		1-5 years		5-10 years		10 years		Total
	(in thousands)
Available for sale	$	—	$	—	$	—	$	—	$	—
Held to maturity		53,650		—		—		—		53,650
	$	53,650	$	—	$	—	$	—	$	53,650

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, 2012 and 2011, were as follows:

	December 31,
	2012		2011
	(in thousands)
Regulatory Assets:
Unamortized losses on reacquired debt	$	18,297	$	20,958
Deferred asset retirement costs		380		396
Deferred net unrealized losses on derivative instruments		2,264		8,701
NOVEC contract termination fee		39,149		41,596
Loan acquisition fee		1,118		1,341
Interest rate hedge		3,050		3,224
North Anna Unit 3		22,748		22,748
Total Regulatory Assets	$	87,006	$	98,964
Regulatory Liabilities:
North Anna asset retirement obligation deferral	$	35,958	$	37,910
Norfolk Southern settlement		17,462		29,789
North Anna nuclear decommissioning trust unrealized gain		17,383		7,167
Unamortized gains on reacquired debt		649		714
Total Regulatory Liabilities	$	71,452	$	75,580
Regulatory Liabilities included in Current Liabilities:
Deferred energy	$	56,027	$	34,712

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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.

• 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 related to the debt we issued in 2011, we entered into an interest rate hedge. This will be amortized over the life of the 2011 debt and will be fully amortized in 2050.

• 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 amount will be amortized ratably through May 2014 as a reduction of fuel expense.

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

• 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,
	2012			2011
	(in thousands)
$90,000,000 principal amount of First Mortgage Bonds, 2011 Series A due 2040 at an interest rate of 4.83%	$	84,000		$	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			165,000
$95,000,000 principal amount of First Mortgage Bonds, 2011 Series C due 2050 at an interest rate of 5.54%		90,250			92,625
$250,000,000 principal amount of 2003 Series A Bonds due 2028 at an interest rate of 5.676%		166,664			177,081
$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%		200,000			212,500
		766,124			794,416
Unamortized discounts and premiums		4			4
Current maturities		(28,292	)		(28,292	)
	$	737,836		$	766,128

At December 31, 2012 and 2011, deferred gains and losses on reacquired debt totaled a net loss of approximately $17.6 million and $20.2 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)
2013	$	28,292
2014		28,292
2015		28,292
2016		28,292
2017		28,292
2018 and thereafter		624,664
	$	766,124

The aggregate fair value of long-term debt was $907.6 million and $897.9 million at December 31, 2012 and 2011, 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.

Our 2002 Series A bonds, with an aggregate principal amount of $60.2 million outstanding, are subject to optional redemption by ODEC on or after June 1, 2013. We currently anticipate that we will call the 2002 Series A bonds in the second quarter of 2013.

NOTE 12—Short-term Borrowing Arrangements

We maintain a $500.0 million, five-year committed revolving credit facility to cover our short-term and medium-term funding needs. Commitments under this syndicated credit agreement mature on November 20, 2016, unless earlier terminated in accordance with the agreement. We did not have any outstanding borrowings under this facility at December 31, 2012 or December 31, 2011; however, the interest rate would have been 1.2% and 1.3%, respectively.

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 $23.5 million and $76.2 million at December 31, 2012 and 2011, respectively. Amounts extended by our member distribution cooperatives are included in accounts receivable-members and totaled $13.6 million and $7.4 million at December 31, 2012 and 2011, respectively.

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

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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, 2012 and 2011, based on the PPA funding target and PPA actuarial value of assets on those dates. The cost of the plan is funded annually by payments to NRECA to ensure that annuities in amounts established by the plan will be available to individual participants upon their retirement. We also 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. Our contributions were $2.9 million, $2.7 million, and $2.6 million, in 2012, 2011, and 2010, 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 2012, 2011, and 2010 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 2012. Pension expense, inclusive of administrative fees, was $3.0 million, $2.8 million, and $2.7 million for 2012, 2011, and 2010, respectively.

We have also elected to participate in a defined contribution 401(k) retirement plan administered by Diversified, Inc. We match up to the first 2% of each participant’s base salary. Our matching contributions were $204,000, $203,000, and $195,000, in 2012, 2011, and 2010, respectively.

NOTE 14—Other

Power Supply Planning

We are in the process of evaluating and pursuing new power supply options which may result in significant capital expenditures in the future. Significant capital expenditures carry with them the risk that decisions made today can have implications well into the future. Failure to anticipate market, technology, and regulatory risks regarding particular capital assets can impact their cost to operate and value in the future. In addition, construction carries with it risks relating to timely completion and operational effectiveness.

NOTE 15—Supplemental Cash Flows Information

Cash paid for interest, net of amounts capitalized, in 2012, 2011, and 2010, was $45.4 million, $49.0 million, and $44.4 million, respectively. Cash paid for income taxes was immaterial in 2012, 2011, and 2010.

NOTE 16—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.

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.

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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.

Our share of the contingent liability for the coverage assessments described above is estimated to be a maximum of $35.3 million at December 31, 2012.

NOTE 17—Selected Quarterly Financial Data (Unaudited)

A summary of the quarterly results of operations for the years 2012 and 2011 follows. Amounts reflect all adjustments, consisting of only normal recurring accruals, necessary in the opinion of management for a fair statement of the results for the interim periods. Results for the interim periods may fluctuate as a result of weather conditions, changes in rates, and other factors.

	First		Second		Third		Fourth
	Quarter		Quarter		Quarter		Quarter		Total
	(in thousands)
Statement of Operations Data
2012
Operating Revenues	$	222,427	$	198,280	$	224,244	$	197,730	$	842,681
Operating Margin		14,365		13,848		16,386		14,546		59,145
Net Margin attributable to ODEC		2,516		2,498		2,475		2,450		9,939
2011
Operating Revenues	$	232,095	$	219,052	$	229,909	$	210,483	$	891,539
Operating Margin		14,350		15,573		16,599		16,068		62,590
Net Margin attributable to ODEC		2,388		3,055		2,670		2,694		10,807

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.

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Management’s Annual Report on Internal Control over Financial Reporting

Our management has assessed our internal control over financial reporting as of December 31, 2012, 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, 2012, 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.

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 2012 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.

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

Vernon N. Brinkley (66). 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 (66). 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 (69). 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.(69).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.

E. Garrison Drummond(61). Insurance agent of Drummond Insurance Agency, Inc. since 1984. Mr. Drummond has been a director of ODEC since 2012 and a director of A&N Electric Cooperative since 2002.

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Jeffrey S. Edwards (49). 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 (55). 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.

Fred C. Garber (68). 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.(67). 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 (67). 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 (64). 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 (36). 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.(52). 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 (62). 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 (65). 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(60). President and CEO of Shenandoah Valley Electric Cooperative since 2005. Mr. Rummel has held executive positions in the utility industry for over two decades and has been a director of ODEC since 2005.

Keith L. Swisher (58). 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.

Michael I. Wheatley (57). 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.

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Gregory W. White (60). 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 (75). 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 do not have an audit committee financial expert because of our cooperative governance structure and the resulting experience all of our directors have with matters affecting electric cooperatives in their roles as a chief executive officer or director of one of our member distribution cooperatives. In addition, the audit committee employs the services of accounting and financial consultants as it deems necessary.

Executive Officers

Our President and CEO administers our day-to-day business and affairs. Our executive officers at December 31, 2012, their respective ages, positions and relevant business experience are listed below.

Jackson E. Reasor (60). President and CEO of ODEC and the VMDAEC, an electric cooperative association which provides services to its members and certain other electric cooperatives, since 1998.

Robert L. Kees (60). Senior Vice President and CFO since 2006. Mr. Kees joined ODEC in 1991 and has held various accounting positions including Vice President and Controller.

Lisa D. Johnson (47). Senior Vice President and COO since 2011. Ms. Johnson joined ODEC in 2006 and served as Senior Vice President Power Supply from 2006 to 2011. Prior to joining ODEC, Ms. Johnson served as Vice President at Mirant Corporation from 2001 to 2006.

Elissa M. Ecker (53). Vice President of Human Resources since 2004.

Code of Ethics

We have a code of ethics which applies to all of 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 CEO and other executive officers 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 executive officers, 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, Burton~Fuller Management, Inc., reviews the market-based salary data we compiled for reasonableness annually. We have defined market-based salary as approximately the 50^th percentile of the market. In 2012, the board of directors engaged Intandem LLC to create a performance appraisal instrument for the CEO position as well as to design, distribute, and compile market valuation models and reports for the executive officers.

Process

We have a committee of our board of directors, the executive committee, which recommends all compensation 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 executive officers 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 executive officers.

Our CEO is also the CEO of the VMDAEC, 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 executive officers 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 are 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, and may award a bonus to, our CEO. On an annual basis, our CEO determines bonus criteria for, and may award a bonus to, the other executive officers.

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 executive officers 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 2012, employees may have elected to have up to 100% or $17,000, whichever is less, of their salary withheld on a pre-tax basis, subject to Internal Revenue Service limitations, and invested on their behalf. We match up to the first 2% of each participant’s base salary. Also, a catch-up contribution is available for participants in the plan once they attain age 50. The maximum catch-up contribution for 2012 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. We have made a $15,000 contribution to the plan each year for his benefit since the inception of the plan in 2006.

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, CFO, and COO are the only participants in this plan.

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 $4,933 in 2012 and $3,434 in 2011.

The executive officers participate 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 savings account, 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 executive officers 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 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		2012		$	468,708	$	—	$	363,537	$	135,590	$	967,835
President and CEO		2011			444,583		—		217,298		125,009		786,890
		2010			430,000		—		171,693		124,073		725,766
Robert L. Kees		2012	(3)		271,645		—		307,796		77,939		657,380
Senior Vice President and CFO		2011	(3)		268,446		15,000		223,356		75,751		582,553
		2010			259,373		—		166,762		73,478		499,613
Lisa D. Johnson		2012	(5)		334,935		—		79,019		94,952		508,906
Senior Vice President and COO(4)		2011			321,812		—		30,527		88,751		441,090
		2010			305,182		—		72,005		84,060		461,247
Elissa M. Ecker		2012	(6)		195,403		—		74,613		56,343		326,359
Vice President of Human Resources		2011			186,470		—		39,903		52,000		278,373
		2010			176,454		—		32,336		50,002		258,792

⁽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 below.

⁽³⁾  For 2012 and 2011, salary includes a lump sum salary adjustment of $1,729 and $4,200, respectively. 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.

⁽⁵⁾  For 2012, salary includes a lump sum salary adjustment of $9,123. Lump sum salary adjustments are not included in the calculation of pension benefits.

⁽⁶⁾  For 2012, salary includes a lump sum salary adjustment of $5,322. Lump sum salary adjustments are not included in the calculation of pension benefits.

Employment Agreement

On May 23, 2012, ODEC entered into an employment agreement with Jackson E. Reasor, our CEO. The agreement is for the term of three years, with an automatic one-year extension unless Mr. Reasor or ODEC and the VMDAEC (collectively, the “Employer”) give written notice 30 days prior to the expiration of the agreement. The agreement provides that he will receive annual compensation of $493,500, effective June 1, 2012, subject to annual adjustment by the boards of directors of the Employer. The annual compensation includes amounts paid to the deferred compensation plan, which was $15,000 in 2012. 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 VMDAEC contributed $45,000 of Mr. Reasor’s salary in 2012 and is expected to contribute the same amount in 2013.

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

Where the termination is “without cause” or Mr. Reasor terminates employment for “good reason” the employment agreement provides for benefits equal to one year of base salary and medical insurance. However, if he becomes employed in any capacity during the one year period immediately following the date of termination, the Employer’s obligation to pay the base salary shall be reduced by the amount of his salary at the new employer. Also, 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, 2012, the severance benefits Mr. Reasor would have been entitled to would be as follows:

Base salary	$	493,500
Targeted bonus		—
Healthcare and other insurance benefits		14,685
Total	$	508,185

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 VMDAEC 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 VMDAEC 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.

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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 $255,000 effective January 1, 2013.

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		13.08	$	902,351	$	—
	Pension Restoration Plan		13.08		657,268		—
Robert L. Kees	NRECA Retirement Security Plan		20.00		1,395,585		—
	Pension Restoration Plan		20.00		47,976		—
Lisa D. Johnson	NRECA Retirement Security Plan		5.58		174,531		—
	Pension Restoration Plan		5.58		34,161		—
Elissa M. Ecker	NRECA Retirement Security Plan		7.08		238,894		—

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 (3.02% for 2012, and 4.19% for 2011) and the PPA three segment yield rates (1.99%, 4.47%, and 5.26% for 2012, and 2.16%, 4.77%, and 6.05% for 2011) 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 PPA RP 2000 at 2012 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.

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Under the Deferred Compensation Plan, annual deferrals cannot exceed the lesser of 100% of Mr. Reasor’s annual compensation or $17,000 (for 2012), 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 deferral limit or the deferral limit plus the amount Mr. Reasor was eligible to but did not defer under the Deferred Compensation Plan. Mr. Reasor will attain the normal retirement age within the next two years. 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 2012:

NON-QUALIFIED DEFERRED COMPENSATION

Name	Executive Contributions in Last Fiscal Year (1)		Registrant Contributions in Last Fiscal Year (1)		Aggregate Gains in Last Fiscal Year		Aggregate Withdrawals/ Distributions		Aggregate Balance at Last Fiscal Year End
Jackson E. Reasor	$	—	$	15,000	$	15,895	$	—	$	122,024
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)	$	9,833	$	123,169	$	2,588	$	135,590
Robert L. Kees		4,900		71,532		1,507		77,939
Lisa D. Johnson		4,900		88,198		1,854		94,952
Elissa M. Ecker		3,802		51,455		1,086		56,343

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

⁽²⁾  Perquisites and other personal benefits include $4,933 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 2012. They were also paid for meetings and other official activities at a rate of $400 per day and $200 per partial day and for teleconferences, if such meetings or other official activities 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 from us. We do not provide our directors 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 2012:

DIRECTOR COMPENSATION

Name	Fees��Earned or Paid in Cash(1)
Darlene H. Carpenter	$	35,400
Glenn F. Chappell		35,600
Earl C. Currin, Jr.		33,600
E. Garrison Drummond		25,300
Fred C. Garber		33,800
Hunter R. Greenlaw, Jr.		35,000
Bruce A. Henry		34,000
David J. Jones		34,200
Paul E. Owen		33,600
Keith L. Swisher		33,800
Philip B. Tankard		8,700
Carl R. Widdowson		36,600
	$	379,600

⁽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. All of our directors are employees or directors of our member distribution cooperatives.

Under our executive committee charter, the executive committee’s duties and responsibilities include (1) recommending all compensation for ODEC’s CEO to the entire board for its approval and (2) serving as the compensation committee of the board to review and discuss with management the contents of the Compensation Discussion and Analysis section of the SEC Form 10-K and to recommend to the board inclusion of the Compensation Discussion and Analysis section in the 10-K each year.

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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 Compensation Discussion and Analysis section 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

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 ACCOUNTING FEES AND SERVICES

The following table presents fees for services provided by Ernst & Young LLP for fiscal years 2012 and 2011. All Audit, Audit-Related, and Tax Fees shown below were pre-approved by the Audit Committee in accordance with its established procedures.

	2012		2011
Audit Fees(1)	$	275,000	$	265,000
Audit-Related Fees(2)		—		117,878
Tax Fees(3)		70,675		5,400
Total	$	345,675	$	388,278

⁽¹⁾  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.

⁽²⁾  Fees for professional services which principally include accounting consultations, due diligence services, and services in connection with internal control matters.

⁽³⁾  Fees for professional services for tax-related advice and compliance.

For fiscal years 2012 and 2011, other than those fees listed above, we did not pay Ernst & Young LLP any fees for any other products or services.

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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 2012 and 2011, all services performed by Ernst & Young  LLP were pre-approved by the Audit Committee in accordance with this policy.

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 49.

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 (filed as exhibit 4.1 to the Registrant’s Form 10-K for the year ended December 31, 2010, File No. 000-50039, on March 16, 2011).

*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).

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*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).

*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).

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*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).

**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).

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**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).

*10.28 Employment Agreement, dated June 1, 2012, between Old Dominion Electric Cooperative and Jackson E. Reasor and accepted by Jackson E. Reasor on May 23, 2012 (filed as Exhibit 10.1 to the Registrant’s Form 8-K, File No. 000-50039, on May 25, 2012).

*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).

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*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. (filed as exhibit 10.39 to the Registrant’s Form 10-K for the year ended December 31, 2011, File No. 000-50039, on March 14, 2012).

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

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 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.

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

Date: March 13, 2013

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

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/s/ EARL C. CURRIN, JR. Earl C. Currin, Jr.	Director
/s/ E. GARRISON DRUMMOND E. Garrison Drummond	Director
/s/ JEFFREY S. EDWARDS	Director
Jeffrey S. Edwards
/s/ KENTD. FARMER Kent D. Farmer	Director
/s/ FRED C. GARBER Fred C. Garber	Director
/s/ HUNTER R. GREENLAW, JR. Hunter R. Greenlaw, Jr.	Director
/s/ BRUCE A. HENRY Bruce A. Henry	Director
/s/ DAVID J. JONES David J. Jones	Director
/s/ MICHAELJ. 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

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/s/ KEITH L. SWISHER Keith L. Swisher	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 2012. Accordingly, ODEC will not file an annual report with the Securities and Exchange Commission.

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