Old Dominion Electric Cooperative 10-K12 Mar 142013 FY Annual reportFinancial data

Company Profile

Document_And_Entity_Informatio

Document And Entity Information (USD $)	12 Months Ended
Document And Entity Information (USD $)	Dec. 31, 2013
Document And Entity Information [Abstract]	'
Document Type	'10-K
Amendment Flag	'false
Document Period End Date	31-Dec-13
Document Fiscal Year Focus	'2013
Document Fiscal Period Focus	'FY
Entity Registration Name	'OLD DOMINION ELECTRIC COOPERATIVE
Entity Central Index Key	'0000885568
Current Fiscal year End Date	'--12-31
Entity Filer Category	'Non-accelerated Filer
Entity Common Stock, Shares Outstanding	0
Entity Well-known Seasoned Issuer	'No
Entity Public Float	$0
Entity Current Reporting Status	'No
Entity Voluntary Filers	'Yes

Consolidated_Balance_Sheets

Consolidated Balance Sheets (USD $)	Dec. 31, 2013		Dec. 31, 2012
In Thousands, unless otherwise specified	Dec. 31, 2013		Dec. 31, 2012
ASSETS:	'		'
Property, plant, and equipment	$1,660,548		$1,655,705
Less accumulated depreciation	-755,288		-721,541
Net electric plant in service	905,260		934,164
Nuclear fuel, at amortized cost	23,636		20,379
Construction work in progress	36,482	[1]	36,797
Net Electric Plant	965,378		991,340
Investments:	'		'
Nuclear decommissioning trust	134,454		113,280
Lease deposits	96,634		94,145
Unrestricted investments and other	24,896		55,599
Total Investments	255,984		263,024
Current Assets:	'		'
Cash and cash equivalents	51,669		37,343
Accounts receivable	12,742		3,564
Accounts receivable - deposits	4,400		4,400
Accounts receivable - members	88,545		86,154
Fuel, materials, and supplies	49,246		59,091
Prepayments and other	3,892		2,556
Total Current Assets	210,494		193,108
Deferred Charges:	'		'
Regulatory assets	87,983		87,006
Other	10,758		9,043
Total Deferred Charges	98,741		96,049
Total Assets	1,530,597		1,543,521
CAPITALIZATION AND LIABILITIES:	'		'
Patronage capital	369,997		360,424
Non-controlling interest	5,691		13,257
Total Patronage capital and Non-controlling interest	375,688		373,681
Long-term debt	749,330		737,836
Total Capitalization	1,125,018		1,111,517
Current Liabilities:	'		'
Long-term debt due within one year	28,292		28,292
Accounts payable	68,560		75,583
Accounts payable - members	24,998		38,585
Accrued expenses	4,991		4,936
Deferred energy	37,193		56,027
Total Current Liabilities	164,034		203,423
Deferred Credits and Other Liabilities:	'		'
Asset retirement obligations	80,860		76,880
Obligations under long-term lease	79,227		74,086
Regulatory liabilities	76,940		71,452
Other	4,518		6,163
Total Deferred Credits and Other Liabilities	241,545		228,581
Commitments and Contingencies	'		'
Total Capitalization and Liabilities	$1,530,597		$1,543,521

[1]	Other includes $6.0 million related to Wildcat Point and $3.1 million for transmission

Consolidated_Statements_Of_Rev

Consolidated Statements Of Revenues, Expenses, And Patronage Capital (USD $)	12 Months Ended
In Thousands, unless otherwise specified	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Consolidated Statements Of Revenues, Expenses, And Patronage Capital [Abstract]	'	'	'
Operating Revenues	$842,069	$842,681	$891,539
Operating Expenses:	'	'	'
Fuel	133,592	90,874	112,421
Purchased power	529,749	537,746	593,030
Deferred energy	-18,834	21,315	-10,665
Operations and maintenance	41,546	42,615	40,642
Administrative and general	42,385	35,958	36,520
Depreciation and amortization	42,346	42,012	41,566
Amortization of regulatory asset/(liability), net	6,310	735	3,808
Accretion of asset retirement obligations	3,980	3,739	3,572
Taxes, other than income taxes	8,405	8,542	8,055
Total Operating Expenses	789,479	783,536	828,949
Operating Margin	52,590	59,145	62,590
Other expense, net	-2,562	-2,224	-1,377
Gain/(loss) on investments, net	2,269	-2,156	-2,348
Investment income	5,333	4,129	4,968
Interest charges, net	-47,680	-48,698	-53,148
Income taxes	-143	-93	49
Net Margin including Non-controlling interest	9,807	10,103	10,734
Non-controlling interest	-234	-164	73
Net Margin attributable to ODEC	9,573	9,939	10,807
Patronage Capital - Beginning of Year	360,424	350,485	339,678
Patronage Capital - End of Year	$369,997	$360,424	$350,485

Consolidated_Statements_Of_Cas

Consolidated Statements Of Cash Flows (USD $)	12 Months Ended
In Thousands, unless otherwise specified	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Operating Activities:	'	'	'
Net Margin including Non-controlling interest	$9,807	$10,103	$10,734
Adjustments to reconcile net margin to net cash provided by operating activities:	'	'	'
Depreciation and amortization	42,346	42,012	41,566
Other non-cash charges	18,604	14,616	10,454
Amortization of lease obligations	5,141	4,801	4,484
Interest on lease deposits	-2,774	-2,710	-2,646
Change in current assets	-3,060	-2,861	11,250
Change in deferred energy	-18,834	21,315	-10,665
Change in current liabilities	-20,555	-32,399	-21,247
Change in regulatory assets and liabilities	-9,004	-248	-10,807
Change in deferred charges and credits	-1,564	-3,319	6,951
Net Cash Provided by Operating Activities	20,107	51,310	40,074
Investing Activities:	'	'	'
Purchases of held to maturity securities	-112,454	-103,420	-159,030
Proceeds from sale of held to maturity securities	143,605	91,278	117,751
Purchases of available for sale securities	'	-24,290	'
Proceeds from sale of available for sale securities	'	24,308	'
Proceeds from sale of trading securities	'	'	11,089
Increase in other investments	-7,468	-4,900	-3,100
Electric plant additions	-32,093	-32,407	-46,090
Loss on investments, net	'	'	2,348
Net Cash Used for Investing Activities	-8,410	-49,431	-77,032
Financing Activities:	'	'	'
Issuance of long-term debt	100,000	'	350,000
Debt issuance costs	-744	'	-2,342
Payment of long-term debt	-88,827	-28,292	-244,292
Dividend - non-controlling interest	-7,800	'	'
Draws on revolving credit facilities	'	'	52,257
Repayments on revolving credit facilities	'	'	-59,300
Net Cash Provided by (Used for ) Financing Activities	2,629	-28,292	96,323
Net Change in Cash and Cash Equivalents	14,326	-26,413	59,365
Cash and Cash Equivalents - Beginning of Year	37,343	63,756	4,391
Cash and Cash Equivalents - End of Year	$51,669	$37,343	$63,756

Summary_Of_Significant_Account

Summary Of Significant Accounting Policies	12 Months Ended
	Dec. 31, 2013
Summary Of Significant Accounting Policies [Abstract]	'
Summary Of Significant Accounting Policies	'
	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. During 2013, TEC refunded $7.8 million of equity to its owners in the form of a cash dividend. The assets and liabilities, and non-controlling interest of TEC are recorded at carrying value and the consolidated assets were $5.7 million and $14.0 million at December 31, 2013 and December 31, 2012, 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 we may sell to TEC power that we do not need to meet the needs of our member distribution cooperatives. TEC then sells this power to the market under market-based rate authority granted by FERC. Additionally, we have a separate contract under which we may purchase natural gas from TEC. 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 eleven Class A members are customer-owned electric distribution cooperatives engaged in the retail sale of power to customers located in Virginia, Delaware, and Maryland. 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 states 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.
	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 and our depreciation rates were as follows:


			Depreciation Rates
	Generating Facility		2013		2012		2011
	Clover		1.8	%	1.8	%	1.8	%
	North Anna		3.0		3.0		3.0
	Louisa		3.5		3.5		3.5
	Marsh Run		3.2		3.2		3.2
	Rock Springs		3.3		3.3		3.3

	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. During 2013, we recorded $1.8 million as a reduction to fuel expense related to the settlement agreement. At December 31, 2013 and 2012, we had an outstanding receivable of $3.9 million and $2.1 million, respectively.
	Fuel, Materials, and Supplies

	Fuel, materials, and supplies is primarily comprised of fuel and spare parts for our generating assets. Fuel, which consists primarily of coal and No. 2 fuel oil, is recorded at average cost considering the lower of cost or market. Spare parts for our generating assets are recorded at lower of cost or market.



	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 2013, 2012, and 2011, was $0.2 million, $1.0 million, and $0.9 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, 2013, 2012, and 2011.
	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. For the years ended December 31, 2013, 2012, and 2011, revenue from sales to our member distribution cooperatives was $810.1 million, $826.8 million, and $853.9 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 2013, 2012, and 2011, 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, 2013, 2012, and 2011, energy sales to non-members, including the sale of renewable energy credits, were $31.9 million, $15.9 million, and $37.6 million, respectively.
	Formula 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.
	The rates we charge our member distribution cooperatives for sales of energy and demand are determined by a formula 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 formula 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.
	Our margin requirements and additional equity contributions approved by our board of directors are recovered through our demand rates. We establish our demand rates to produce a net margin attributable to ODEC equal to 20% of our budgeted total interest charges plus additional equity contributions approved by our board of directors. The formula rate allows us to recover and refund amounts utilizing Margin Stabilization. Margin Stabilization allows us to review our actual demand-related costs of service and demand 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. We adjust operating revenues and accounts receivable–members or accounts payable–members, as appropriate, to reflect these adjustments.
	Through December 31, 2013, we adjusted our operating revenues to reflect actual demand costs incurred, including a net margin attributable to ODEC equal to 20% of actual interest charges plus additional equity contributions approved by our board of directors. Utilizing Margin Stabilization, we reduced operating revenues by $9.8 million, $15.0 million, and $14.9 million for the years ended December 31, 2013, 2012, and 2011, respectively.
	On September 30, 2013, we filed with FERC to revise our cost-based formula rate to more closely align our cost recovery from our member distribution cooperatives with the methodologies used by PJM to allocate costs to us. On November 8, 2013, Bear Island, a customer of REC, filed a motion to intervene, protest, and request for hearing. On December 2, 2013, FERC issued its order accepting the proposed revisions for filing to become effective January 1, 2014, subject to refund, and establishing hearing and settlement procedures. We are currently in settlement discussions with Bear Island, the results of which cannot currently be determined.
	We continue to establish our demand rates to produce a net margin attributable to ODEC equal to 20% of our budgeted total interest charges plus additional equity contributions approved by our board of directors and effective January 1, 2014:
		·		If the actual net margin attributable to ODEC, excluding any budgeted additional equity contributions, equals more than 20% of our actual total interest charges, our board of directors may approve that, utilizing Margin Stabilization, revenues will be reduced by the amount of such excess margins, or that such excess margins will be retained as an additional equity contribution.

	·		If the actual net margin attributable to ODEC, excluding any budgeted additional equity contributions, equals more than 10% but less than 20% of our actual total interest charges, then no adjustment is required.

	·		If the actual net margin attributable to ODEC, excluding any budgeted additional equity contributions, equals less than 10% of our actual total interest charges, utilizing Margin Stabilization, revenues will be increased to produce a net margin attributable to ODEC, excluding any budgeted additional equity contributions, equal to 10% of our actual total interest charges.
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 recovered or refunded through our formula 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 formula 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 formula 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 $6.7 million and $8.3 million, at December 31, 2013 and 2012, 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 $4.3 million and $5.4 million at December 31, 2013 and 2012, 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, 2013 and 2012, we had an over-collected deferred energy balance of $37.2 million and $56.0 million, respectively. Over-collected deferred energy balances are refunded to our member distribution cooperatives in subsequent periods. In January 2014, the entire mid-Atlantic region experienced extremely cold weather, which increased our member distribution cooperatives’ customers’ requirements for power as well as increased our purchased power and fuel expenses. As a result, our deferred energy balance changed from an over-collection of energy costs to an under-collection of energy costs. We currently anticipate that our deferred energy balance at January 31, 2014, is an under-collection of energy costs of approximately $33.4 million.
Financial Instruments (including Derivatives)

Investments 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.
Unrestricted investments and lease deposits 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 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 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 were no contracts for which we have elected cash flow hedge accounting and therefore, there was no hedge ineffectiveness during the years ended December 31, 2013, 2012, or 2011.
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.
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 of patronage capital are subject to the discretion of our board of directors and the restrictions contained in our 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 $88.5 million and $86.2 million, at December 31, 2013 and 2012, respectively.
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 President and 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, physically-delivered forward power purchase contracts, and spot market energy purchases.
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.

Electric_Plant

Electric Plant	12 Months Ended
Electric Plant	Dec. 31, 2013
Electric Plant [Abstract]	'
Electric Plant	'




	NOTE 2—Electric Plant

	Our net electric plant is comprised of the following for 2013:



									Combustion
						North			Turbine
			Clover			Anna			Facilities		Other		Total

			(in thousands)
	Property, plant, and equipment		$	671,708		$	335,151		$	585,067	$	68,622	$	1,660,548
	Accumulated depreciation			-349,197			-184,314			-198,520		-23,257		-755,288
	Nuclear fuel			-			76,458			-		-		76,458
	Accumulated amortization of nuclear fuel			-			-52,822			-		-		-52,822
	Construction work in progress (1)			6,670			20,536			-		9,276		36,482
			$	329,181		$	195,009		$	386,547	$	54,641	$	965,378

	-1	Other includes $6.0 million related to Wildcat Point and $3.1 million for transmission.

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



									Combustion
						North			Turbine
			Clover			Anna			Facilities		Other		Total

			(in thousands)
	Property, plant, and equipment		$	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



	We hold a 50% undivided ownership interest in Clover, a two-unit, 874 MW (net capacity entitlement) coal-fired electric generating facility operated by Virginia Power. We are responsible for 50% of all post-construction additions and operating costs associated with Clover, as well as a pro-rata portion of Virginia Power’s administrative and general expenses for Clover, and we must fund these items. Our portion of assets, liabilities, and operating expenses associated with Clover are included in our consolidated financial statements in accordance with proportionate consolidation accounting. At December 31, 2013 and 2012, we had an outstanding accounts payable balance of $12.7 million and $14.7 million, respectively, due to Virginia Power for operation, maintenance, and capital investment at Clover.
	We hold an 11.6% undivided ownership interest in North Anna, a two-unit, 1,897 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 in accordance with proportionate consolidation accounting. At December 31, 2013 and 2012, we had an outstanding accounts payable balance of $4.1 million and $11.2 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.”

	Wildcat Point

	On April 23, 2013, we announced our intention to seek approval to develop and construct a 1,000 MW natural gas-fueled generation facility, named Wildcat Point, in Cecil County, Maryland. The development, construction, and operation of Wildcat Point are subject to obtainment of necessary governmental and regulatory approvals and our board’s approval of an EPC contractor. On May 20, 2013, we applied to the Maryland Public Service Commission for a Certificate of Public Convenience and Necessity, and we currently anticipate that we will receive approval mid-2014, begin construction in late 2014, and the facility will become operational in mid-2017. We continue to pursue other necessary permits and contracts related to the development and construction of the facility.

	Wildcat Point will consist of two combustion turbines, two heat recovery steam generators and one steam turbine generator. Mitsubishi will supply the combustion turbines and Alstom will supply the heat recovery steam generators and the steam turbine generator. In the fourth quarter of 2013, we issued an RFP for potential EPC contractors to construct Wildcat Point. We are currently evaluating the responses to the RFP and anticipate recommending an EPC contractor to our board of directors for approval mid-2014. In 2013, we expensed $7.7 million of preconstruction costs related to Wildcat Point, which are recorded in administrative and general expense; and we capitalized progress payments for the combustion turbines and emission reduction credits totaling $6.0 million, which are recorded in construction work in progress.

	Capital Expenditures

	The table below summarizes our projected capital expenditures, including capitalized interest, for 2014 through 2016:



		Projected
		Year Ended December 31,
		2014			2015			2016

		(in millions)
Wildcat Point (1)	$	98.7		$	455.8		$	185.4
Clover		17.5			20.3			9.2
North Anna nuclear fuel		13.1			7.9			16.0
North Anna		10.3			7.4			8.0
Transmission		7.5			7.0			3.0
Combustion turbine facilities		0.9			1.1			1.1
Other		2.6			2.8			2.9
Total	$	150.6		$	502.3		$	225.6
	-1		Wildcat Point capital expenditures are subject to necessary governmental and regulatory approvals.

Nearly all of our capital expenditures consist of additions to electric plant and equipment. Capital expenditures for “Other” include costs related to our administrative and general assets, and distributed generation facilities. We intend to use our cash flow from operations, borrowings under our syndicated credit facility, and financings in the debt capital markets to fund all of our currently projected capital requirements through 2016.

Accounting_For_Asset_Retiremen

Accounting For Asset Retirement And Environmental Obligations	12 Months Ended
	Dec. 31, 2013
Accounting For Asset Retirement And Environmental Obligations [Abstract]	'
Accounting For Asset Retirement And Environmental Obligations	'
	NOTE 3—Accounting for Asset Retirement and Environmental 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 estimate the fair value of our asset retirement obligations by using present value techniques, in which estimates of future cash flows associated with retirement activities are discounted using a credit-adjusted risk-free rate. Our estimated liability could change significantly if actual costs vary from assumptions or if governmental regulations change significantly.
	A significant portion of our asset retirement obligations relate to our share of the future costs to decommission North Anna. At December 31, 2013 and 2012, North Anna’s nuclear decommissioning asset retirement obligation totaled $72.1 million and $68.5 million, respectively. Approximately every four years, a new decommissioning study for North Anna is performed by third-party experts. In 2009, we received the new study and adopted it effective July 1, 2009. We are not aware of any events that have occurred since the 2009 study that would materially impact our estimate. The next decommissioning study for North Anna is scheduled to be performed in 2014.
	The following represents changes in our asset retirement obligations for the years ended December 31, 2013 and 2012 (in thousands):



	Asset retirement obligations at December 31, 2011	$	73,141
	Accretion expense		3,739
	Asset retirement obligations at December 31, 2012	$	76,880
	Accretion expense		3,980
	Asset retirement obligations at December 31, 2013	$	80,860

	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 April 2038 and Unit 2 to August 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 of 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.

Power_Purchase_Agreements

Power Purchase Agreements	12 Months Ended
	Dec. 31, 2013
Power Purchase Agreements [Abstract]	'
Power Purchase Agreements	'
	NOTE 4—Power Purchase Agreements

	In 2013, 2012, and 2011, our owned generating facilities together furnished approximately 39.4%, 33.4%, and 33.3%, 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 various hedging instruments to manage our power market price risks. 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, 2013 and 2012, due to changes in energy prices, we were required to post $4.4 million with our counterparties pursuant to contracts we have in place with them.
	Our purchased power costs for 2013, 2012, and 2011 were $529.7 million, $537.7 million, and $593.0 million, respectively.
	As of December 31, 2013, our energy and capacity purchase commitments under the various agreements were as follows:



		Energy and
		Capacity
	Year Ending December 31,	Commitments
		(in millions)
	2014	$	212.0
	2015		187.3
	2016		200.3
		$	599.6

Wholesale_Power_Contracts

Wholesale Power Contracts	12 Months Ended
Wholesale Power Contracts	Dec. 31, 2013
Wholesale Power Contracts [Abstract]	'
Wholesale Power Contracts	'
	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 1.5% of our member distribution cooperatives’ total energy requirements in 2013.
	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. In 2013, our member distribution cooperatives collectively received 6.7 MW under these exceptions. In 2014, we currently anticipate that our member distribution cooperatives collectively will receive approximately 74 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 formula rate. The formula 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 formula 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 necessary 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.
	Revenues from our member distribution cooperatives for the past three years were as follows:




			Year Ended December 31,
			2013		2012		2011

			(in millions)

	Rappahannock Electric Cooperative		$	275.9	$	280.4	$	290.4
	Shenandoah Valley Electric Cooperative			150.4		152.1		159.8
	Delaware Electric Cooperative, Inc.			94.7		95.4		97.6
	Choptank Electric Cooperative, Inc.			72.1		75.9		76.6
	Southside Electric Cooperative			64.5		66.0		67.5
	A&N Electric Cooperative			47.8		48.4		50.1
	Mecklenburg Electric Cooperative			39.7		40.6		41.8
	Prince George Electric Cooperative			21.6		22.1		22.5
	Northern Neck Electric Cooperative			19.5		19.7		20.5
	Community Electric Cooperative			13.9		14.1		14.7
	BARC Electric Cooperative			10.0		12.1		12.4
			$	810.1	$	826.8	$	853.9

Fair_Value_Measurements

Fair Value Measurements	12 Months Ended
Fair Value Measurements	Dec. 31, 2013
Fair Value Measurements [Abstract]	'
Fair Value Measurements	'
	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, 2013 and 2012:




				Quoted Prices
				in Active		Significant
				Markets for		Other		Significant
				Identical		Observable		Unobservable
		December 31,		Assets		Inputs		Inputs
		2013		(Level 1)		(Level 2)		(Level 3)

		(in thousands)
	Nuclear decommissioning trust (1)(2)	$	134,454	$	42,661	$	91,793	$	-
	Unrestricted investments and other (3)		173		173		-		-
	Derivatives - gas and power (4)		412		412		-		-
	Total Financial Assets	$	135,039	$	43,246	$	91,793	$	-


				Quoted Prices
				in Active		Significant
				Markets for		Other		Significant
				Identical		Observable		Unobservable
		December 31,		Assets		Inputs		Inputs
		2012		(Level 1)		(Level 2)		(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	$	-	$	-


	-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 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 are related to equity securities.
	-4	Derivatives – gas and power represent natural gas futures contracts which are recorded on our Consolidated Balance Sheet in either deferred charges-other or deferred credits and other liabilities–other, and which are indexed against NYMEX. See Note 1—Summary of Significant Accounting Policies.

	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.

Derivatives_And_Hedging

Derivatives And Hedging

12 Months Ended

Dec. 31, 2013

Derivatives And Hedging [Abstract]

Derivatives And Hedging

NOTE 7—Derivatives and Hedging

We are exposed to market price risk by purchasing power to supply the power requirements of our member distribution cooperatives that are not met by our owned generation. In addition, the purchase of fuel to operate our generating facilities also exposes us to market price risk. 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:

As of

31-Dec-13

31-Dec-12

Commodity

Unit of Measure

Quantity

Natural Gas

MMBTU

1,470,000

650,000

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

Fair Value

As of

December 31,

Balance Sheet Location

2013

2012

(in thousands)

Derivatives in an asset position:

Natural gas futures contracts

Deferred charges-other

412

Total derivatives in an asset position

412

Derivatives in a liability position:

Natural gas futures contracts

Deferred credits and other liabilities-other

624

Total derivatives in a liability position

624

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

for the Years Ended December 31, 2013 and 2012

Amount of

Amount of Gain

Gain (Loss)

(Loss) Reclassified

Recognized in

Location of Gain

from Regulatory

Regulatory

(Loss) Reclassified

Asset/Liability into

Derivatives Accounted for

Asset/Liability for

from Regulatory

Income for the

Utilizing Regulatory

Derivatives as of

Asset/Liability into

Year Ended

Accounting

December 31,

Income

December 31,

2013

2012

2013

2012

(in thousands)

Natural gas futures contracts (1)

419

-2,264

Fuel

-3,031

-6,522

Purchased power contracts

Purchased power

-2,736

Total

419

-2,264

-3,031

-9,258

-1

As of December 31, 2013 and 2012, includes a regulatory asset of $7.0 thousand and $1.6 million, respectively, to be recognized in future periods as the result of the contracts being effectively settled.

LongTerm_Lease_Transaction

Long-Term Lease Transaction	12 Months Ended
Long-Term Lease Transaction	Dec. 31, 2013
Long-Term Lease Transaction [Abstract]	'
Long-Term Lease Transaction	'
	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, 2013 and 2012, the unamortized portion of the deferred gain was $4.3 million and $5.4 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 and to purchase an investment 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 $309.7 million at December 31, 2013, 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 $309.7 million and $310.8 million, at December 31, 2013 and 2012, 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.

Investments

Investments	12 Months Ended
Investments	Dec. 31, 2013
Investments [Abstract]	'
Investments	'
	NOTE 9—Investments

	Investments were as follows at December 31, 2013 and 2012:



						Gross		Gross
						Unrealized		Unrealized		Fair		Carrying
	Description		Designation	Cost		Gains		Losses		Value		Value

				(in thousands)
	31-Dec-13

	Nuclear decommissioning trust (1)(2)
	Debt securities		Available for sale	$	40,352	$	1,719	$	-	$	42,071	$	42,071
	Equity securities		Available for sale		62,293		29,500		-		91,793		91,793
	Cash and other		Available for sale		590		-		-		590		590
	Total Nuclear Decommissioning Trust			$	103,235	$	31,219	$	-	$	134,454	$	134,454

	Lease Deposits (3)
	Government obligations		Held to maturity	$	96,634	$	5,676	$	-	$	102,310	$	96,634
	Total Lease Deposits			$	96,634	$	5,676	$	-	$	102,310	$	96,634

	Unrestricted investments
	Government obligations		Held to maturity	$	20,174	$	1	$	-	$	20,175	$	20,174
	Debt securities		Held to maturity		2,200		-		-4		2,196		2,200
	Total Unrestricted Investments			$	22,374	$	1	$	-4	$	22,371	$	22,374

	Other
	Equity securities		Trading	$	131	$	42	$	-	$	173	$	173
	Non-marketable equity investments		Equity		2,349		1,735		-		4,084		2,349
	Total Other			$	2,480	$	1,777	$	-	$	4,257	$	2,522
												$	255,984

	31-Dec-12

	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		Equity		1,827		-		-		1,827		1,827
	Total Other			$	1,940	$	9	$	-	$	1,949	$	1,949
												$	263,024


	-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 fourth quarter of 2013 and 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.
	Our investments by classification at December 31, 2013 and 2012, were as follows:



		31-Dec-13				31-Dec-12
				Carrying				Carrying
Description		Cost		Value		Cost		Value

		(in thousands)
Available for sale		$	103,235	$	134,454	$	96,010	$	113,402
Held to maturity			119,008		119,008		147,795		147,795
Equity			2,349		2,349		1,827		1,827
Trading			131		173		-		-
		$	224,723	$	255,984	$	245,632	$	263,024

Contractual maturities of debt securities at December 31, 2013, were as follows:




		Less than						More than
Description		1 year		1-5 years		5-10 years		10 years		Total

		(in thousands)
Available for sale (1)		$	-	$	-	$	42,071	$	-	$	42,071
Held to maturity			21,931		96,840		237		-		119,008
		$	21,931	$	96,840	$	42,308	$	-	$	161,079
(1) The contractual maturities of available for sale debt securities are measured using the effective duration of the bond fund within the nuclear decommissioning trust.

Regulatory_Assets_And_Liabilit

Regulatory Assets And Liabilities	12 Months Ended
Regulatory Assets And Liabilities	Dec. 31, 2013
Regulatory Assets And Liabilities [Abstract]	'
Regulatory Assets And Liabilities	'




	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, 2013 and 2012, were as follows:


		December 31,
		2013			2012

		(in thousands)
	Regulatory Assets:
	Unamortized losses on reacquired debt	$	17,435		$	18,297
	Deferred asset retirement costs		363			380
	Deferred net unrealized losses on derivative instruments		-			2,264
	NOVEC contract termination fee		36,703			39,149
	Loan acquisition fee		894			1,118
	Interest rate hedge		2,879			3,050
	North Anna Unit 3		22,748			22,748
	Voluntary prepayment to NRECA Retirement Security Plan		6,961			-
	Total Regulatory Assets	$	87,983		$	87,006

	Regulatory Liabilities:
	North Anna asset retirement obligation deferral	$	39,581		$	35,958
	Norfolk Southern settlement		5,136			17,462
	North Anna nuclear decommissioning trust unrealized gain		31,220			17,383
	Unamortized gains on reacquired debt		584			649
	Deferred net unrealized gains on derivative instruments		419			-
	Total Regulatory Liabilities	$	76,940		$	71,452

	Regulatory Liabilities included in Current Liabilities:
	Deferred energy	$	37,193		$	56,027

	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 a 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 through amortization of regulatory asset/(liability), net.
		·		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 formula rate.

		·		Voluntary prepayment to NRECA Retirement Security Plan. In April 2013, we elected to make a voluntary prepayment of $7.7 million to the NRECA Retirement Security Plan, a noncontributory, defined benefit multiple employer master pension plan. We recorded this prepayment as a regulatory asset which will be amortized over ten years beginning January 1, 2013.

	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.
		·		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.

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

LongTerm_Debt

Long-Term Debt	12 Months Ended
Long-Term Debt	Dec. 31, 2013
Long-Term Debt [Abstract]	'
Long-Term Debt	'
	NOTE 11—Long-term Debt

	Long-term debt consists of the following:



				December 31,
				2013		2012

				(in thousands)

	$50,000,000 principal amount of First Mortgage Bonds, 2013 Series A due			$	50,000	$	-
	2043 at an interest rate of 4.21%

	$50,000,000 principal amount of First Mortgage Bonds, 2013 Series B due				50,000		-
	2053 at an interest rate of 4.36%

	$90,000,000 principal amount of First Mortgage Bonds, 2011 Series A due
	2040 at an interest rate of 4.83%				81,000		84,000

	$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%				87,875		90,250

	$250,000,000 principal amount of 2003 Series A Bonds due 2028 at an
	interest rate of 5.676%				156,247		166,664

	$27,755,000 principal amount of 2002 Series A Bonds due 2028 at an
	interest rate of 5.00%				-		27,755

	$32,455,000 principal amount of 2002 Series A Bonds due 2028 at an
	interest rate of 5.625%				-		32,455

	$300,000,000 principal amount of 2002 Series B Bonds due 2028 at an
	interest rate of 6.21%				187,500		200,000
					777,622		766,124
	Unamortized discounts and premiums				-		4
	Current maturities				-28,292		-28,292
				$	749,330	$	737,836

	At December 31, 2013 and 2012, deferred gains and losses on reacquired debt totaled a net loss of approximately $16.9 million and $17.6 million, respectively. Deferred gains and losses on reacquired debt are deferred under regulatory accounting. See Note 10—Regulatory Assets and Liabilities.



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



	Year Ending December 31,	(in thousands)
	2014	$	28,292
	2015		28,292
	2016		28,292
	2017		28,292
	2018		28,292
	2019 and thereafter		636,162
		$	777,622

	The aggregate fair value of long-term debt was $846.4 million and $907.6 million at December 31, 2013 and 2012, 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.
	All of our long-term debt is issued under our Indenture. Substantially all of our real property and tangible personal property and some of our intangible personal 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, were subject to optional redemption by ODEC on or after June 1, 2013. We issued a call notice for the 2002 Series A Bonds in the second quarter of 2013 and redeemed these bonds on June 1, 2013. We paid a premium of $0.3 million and had unamortized debt issuance costs of $1.5 million related to these bonds, for a total of $1.8 million. These costs have been deferred as a regulatory asset and will be amortized over the original life of the debt to 2028.

On June 28, 2013, we issued $100.0 million of first mortgage bonds in a private placement transaction. The issuance consisted of $50.0 million of 4.21% First Mortgage Bonds, 2013 Series A due December 1, 2043 and $50.0 million of 4.36% First Mortgage Bonds, 2013 Series B due December 1, 2053.

ShortTerm_Borrowing_Arrangemen

Short-Term Borrowing Arrangements	12 Months Ended
Short-Term Borrowing Arrangements	Dec. 31, 2013
Short-Term Borrowing Arrangements [Abstract]	'
Short-Term Borrowing Arrangements	'
	NOTE 12—Short-term Borrowing Arrangements

	We currently maintain a $500.0 million, five-year committed revolving credit facility to cover our short-term and medium-term funding needs. We did not have any outstanding borrowings under this facility at December 31, 2013 or December 31, 2012; however, the interest rate on any borrowings would have been 1.1% and 1.2%, respectively.
	On March 12, 2014, we amended and extended our $500.0 million, five-year revolving credit agreement with CoBank, ACB, Wells Fargo Securities, LLC, Merrill Lynch, Pierce Fenner & Smith Incorporated, J.P. Morgan Securities LLC, and PNC Capital Markets LLC as joint lead arrangers, CoBank, ACB, as syndication agent, Wells Fargo Bank, National Association, as administrative agent and swingline lender, and Bank of America, N.A., JPMorgan Chase Bank, N.A., and PNC Bank, N.A. as documentation agents. Commitments under the credit agreement now extend until March 5, 2019, unless earlier terminated in accordance with the agreement.
	Borrowings under the credit agreement that are based on Eurodollar rates bear interest at the London Interbank Offered Rate (“LIBOR”) plus a margin ranging from 0.90% to 1.5%, depending on our credit ratings. Borrowings not based on Eurodollar rates, including swingline borrowings, bear interest at the highest of (1) the federal funds effective rate plus 0.5%, (2) the prime commercial lending rate of the administrative agent, and (3) the daily LIBOR for a one-month interest period plus 1.0%, plus in each case a margin ranging from 0.0% to 0.5%. Additionally, we are also responsible for customary unused commitment fees, an administrative agent fee and letter of credit fees.
	The credit agreement contains customary conditions to borrowing or the issuance of letters of credit, representations and warranties, and covenants. The credit agreement obligates us to maintain a debt to capitalization ratio of no more than 0.85 to 1.00 and to maintain a margins-for-interest of no less than 1.10 times interest charges (calculated in accordance with our secured indenture as currently in effect). Obligations under the credit agreement may be accelerated following, among other things, (1) the failure to pay outstanding principal when due or other amounts, including interest, within five days after the due date, (2) a material misrepresentation, (3) a cross-payment default or cross-acceleration under specified indebtedness, (4) failure by us to perform any obligation relating to the credit agreement following, in some cases, specified cure periods, (5) bankruptcy or insolvency events, (6) invalidity of the credit agreement and related loan documentation or our assertion of invalidity, and (7) a failure by our member distribution cooperatives to pay amounts in excess of an agreed threshold owing to us beyond a specified cure period.
	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 $15.2 million and $23.5 million at December 31, 2013 and 2012, respectively. Amounts extended by our member distribution cooperatives are included in accounts receivable-members and totaled $10.8 million and $13.6 million at December 31, 2013 and 2012, respectively.

Employee_Benefits

Employee Benefits	12 Months Ended
Employee Benefits	Dec. 31, 2013
Employee Benefits [Abstract]	'
Employee Benefits	'
	NOTE 13—Employee Benefits
	Substantially all of our employees participate in the NRECA Retirement Security Plan, a noncontributory, defined benefit multiple employer master pension plan. The legal name of the plan is the NRECA Retirement Security Plan; the employer identification number is 53–0116145, and the plan number is 333. Plan information is available publicly through the annual Form 5500, including attachments. The plan year is January 1 through December 31. In total, the NRECA Retirement Security Plan was over 80% funded on January 1, 2013 and was between 65% and 80% funded at January 1, 2012, 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 required contribution to the NRECA Retirement Security Plan and the pension restoration plan totaled $2.9 million, $2.9 million, and $2.7 million, in 2013, 2012, and 2011, respectively. In each of these years, our contributions represented less than 5% of the total contributions made to the plan by all participating employers. In 2013, we elected to make a voluntary prepayment of $7.7 million to the NRECA Retirement Security Plan and recorded this payment as a regulatory asset which is being amortized over ten years beginning January 1, 2013. There were no changes that significantly affect the comparability of the 2012 and 2011 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 2013. Pension expense, inclusive of administrative fees, was $3.0 million, $3.0 million, and $2.8 million for 2013, 2012, and 2011, respectively. Pension expense for 2013 includes $0.7 million related to the amortization of the voluntary prepayment.
	We have also elected to participate in a defined contribution 401(k) retirement plan administered by TransAmerica Retirement Solutions. We match up to the first 2% of each participant’s base salary. Our matching contributions were $206,000, $204,000, and $203,000, in 2013, 2012, and 2011, respectively.

Other

Other	12 Months Ended
Other	Dec. 31, 2013
Other [Abstract]	'
Other	'
	NOTE 14—Other


	Virginia Power Ancillary Service Settlement

	On January 31, 2014, we entered into a settlement agreement with Virginia Power to resolve a dispute concerning certain past and future ancillary service credits due to us related to our ownership in Clover and North Anna. We recorded an $8.1 million receivable and a corresponding reduction to purchased power expense for ancillary service credits due to us through December 31, 2013. We received a payment of $5.7 million in February 2014, and have a remaining receivable of $2.4 million.

Supplemental_Cash_Flows_Inform

Supplemental Cash Flows Information	12 Months Ended
Supplemental Cash Flows Information	Dec. 31, 2013
Supplemental Cash Flows Information [Abstract]	'
Supplemental Cash Flows Information	'
	NOTE 15—Supplemental Cash Flows Information

	Cash paid for interest, net of amounts capitalized, in 2013, 2012, and 2011, was $44.3 million, $45.4 million, and $49.0 million, respectively. Cash paid for income taxes was immaterial in 2013, 2012, and 2011.

Commitments_And_Contingencies

Commitments And Contingencies	12 Months Ended
Commitments And Contingencies	Dec. 31, 2013
Commitments And Contingencies [Abstract]	'
Commitments And Contingencies	'
	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.
	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 maximum retrospective premium assessments for the coverage assessments described above is estimated to be a maximum of $31.1 million at December 31, 2013.

Subsequent_Event

Subsequent Event	12 Months Ended
Subsequent Event	Dec. 31, 2013
Subsequent Event [Abstract]	'
Subsequent Event	'
	NOTE 17—Subsequent Events
	In accordance with our revised formula rate, we increased our total energy rate approximately 0.5%, effective January 1, 2014.
	On March 11, 2014, our board of directors approved an additional increase to our total energy rate of approximately 11.8%, effective April 1, 2014.

Selected_Quarterly_Financial_D

Selected Quarterly Financial Data	12 Months Ended
Selected Quarterly Financial Data	Dec. 31, 2013
Selected Quarterly Financial Data [Abstract]	'
Selected Quarterly Financial Data	'




	NOTE 18—Selected Quarterly Financial Data (Unaudited)

	A summary of the quarterly results of operations for the years 2013 and 2012 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
	2013
	Operating Revenues	$	220,713	$	187,623	$	220,393	$	213,340	$	842,069
	Operating Margin		14,302		13,130		14,010		11,148		52,590
	Net Margin attributable to ODEC		2,386		2,346		2,448		2,393		9,573

	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

Summary_Of_Significant_Account1

Summary Of Significant Accounting Policies (Policy)	12 Months Ended
	Dec. 31, 2013
Summary Of Significant Accounting Policies [Abstract]	'
General	'
	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. During 2013, TEC refunded $7.8 million of equity to its owners in the form of a cash dividend. The assets and liabilities, and non-controlling interest of TEC are recorded at carrying value and the consolidated assets were $5.7 million and $14.0 million at December 31, 2013 and December 31, 2012, 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 we may sell to TEC power that we do not need to meet the needs of our member distribution cooperatives. TEC then sells this power to the market under market-based rate authority granted by FERC. Additionally, we have a separate contract under which we may purchase natural gas from TEC. 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 eleven Class A members are customer-owned electric distribution cooperatives engaged in the retail sale of power to customers located in Virginia, Delaware, and Maryland. 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 states 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

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

Depreciation	'
	Depreciation

	We conduct depreciation studies approximately every five years and our depreciation rates were as follows:


			Depreciation Rates
	Generating Facility		2013		2012		2011
	Clover		1.8	%	1.8	%	1.8	%
	North Anna		3.0		3.0		3.0
	Louisa		3.5		3.5		3.5
	Marsh Run		3.2		3.2		3.2
	Rock Springs		3.3		3.3		3.3


Nuclear Fuel	'

	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. During 2013, we recorded $1.8 million as a reduction to fuel expense related to the settlement agreement. At December 31, 2013 and 2012, we had an outstanding receivable of $3.9 million and $2.1 million, respectively.

Fuel, Materials, And Supplies	'
	Fuel, Materials, and Supplies

	Fuel, materials, and supplies is primarily comprised of fuel and spare parts for our generating assets. Fuel, which consists primarily of coal and No. 2 fuel oil, is recorded at average cost considering the lower of cost or market. Spare parts for our generating assets are recorded at lower of cost or market.

Allowance For Borrowed Funds Used During Construction	'



	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 2013, 2012, and 2011, was $0.2 million, $1.0 million, and $0.9 million, respectively.

Income Taxes	'
	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, 2013, 2012, and 2011.

Operating Revenues	'
	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. For the years ended December 31, 2013, 2012, and 2011, revenue from sales to our member distribution cooperatives was $810.1 million, $826.8 million, and $853.9 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 2013, 2012, and 2011, 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, 2013, 2012, and 2011, energy sales to non-members, including the sale of renewable energy credits, were $31.9 million, $15.9 million, and $37.6 million, respectively.

Formula Rate	'
	Formula 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.
	The rates we charge our member distribution cooperatives for sales of energy and demand are determined by a formula 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 formula 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.
	Our margin requirements and additional equity contributions approved by our board of directors are recovered through our demand rates. We establish our demand rates to produce a net margin attributable to ODEC equal to 20% of our budgeted total interest charges plus additional equity contributions approved by our board of directors. The formula rate allows us to recover and refund amounts utilizing Margin Stabilization. Margin Stabilization allows us to review our actual demand-related costs of service and demand 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. We adjust operating revenues and accounts receivable–members or accounts payable–members, as appropriate, to reflect these adjustments.
	Through December 31, 2013, we adjusted our operating revenues to reflect actual demand costs incurred, including a net margin attributable to ODEC equal to 20% of actual interest charges plus additional equity contributions approved by our board of directors. Utilizing Margin Stabilization, we reduced operating revenues by $9.8 million, $15.0 million, and $14.9 million for the years ended December 31, 2013, 2012, and 2011, respectively.
	On September 30, 2013, we filed with FERC to revise our cost-based formula rate to more closely align our cost recovery from our member distribution cooperatives with the methodologies used by PJM to allocate costs to us. On November 8, 2013, Bear Island, a customer of REC, filed a motion to intervene, protest, and request for hearing. On December 2, 2013, FERC issued its order accepting the proposed revisions for filing to become effective January 1, 2014, subject to refund, and establishing hearing and settlement procedures. We are currently in settlement discussions with Bear Island, the results of which cannot currently be determined.
	We continue to establish our demand rates to produce a net margin attributable to ODEC equal to 20% of our budgeted total interest charges plus additional equity contributions approved by our board of directors and effective January 1, 2014:
		·		If the actual net margin attributable to ODEC, excluding any budgeted additional equity contributions, equals more than 20% of our actual total interest charges, our board of directors may approve that, utilizing Margin Stabilization, revenues will be reduced by the amount of such excess margins, or that such excess margins will be retained as an additional equity contribution.

		·		If the actual net margin attributable to ODEC, excluding any budgeted additional equity contributions, equals more than 10% but less than 20% of our actual total interest charges, then no adjustment is required.

		·		If the actual net margin attributable to ODEC, excluding any budgeted additional equity contributions, equals less than 10% of our actual total interest charges, utilizing Margin Stabilization, revenues will be increased to produce a net margin attributable to ODEC, excluding any budgeted additional equity contributions, equal to 10% of our actual total interest charges.

Regulatory Assets And Liabilities	'
	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 recovered or refunded through our formula 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 formula 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 formula 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	'
	Debt Issuance Costs

	Capitalized costs associated with the issuance of debt totaled $6.7 million and $8.3 million, at December 31, 2013 and 2012, 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	'
	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 $4.3 million and $5.4 million at December 31, 2013 and 2012, 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	'
	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, 2013 and 2012, we had an over-collected deferred energy balance of $37.2 million and $56.0 million, respectively. Over-collected deferred energy balances are refunded to our member distribution cooperatives in subsequent periods. In January 2014, the entire mid-Atlantic region experienced extremely cold weather, which increased our member distribution cooperatives’ customers’ requirements for power as well as increased our purchased power and fuel expenses. As a result, our deferred energy balance changed from an over-collection of energy costs to an under-collection of energy costs. We currently anticipate that our deferred energy balance at January 31, 2014, is an under-collection of energy costs of approximately $33.4 million.

Financial Instruments (Including Derivatives)	'
	Financial Instruments (including Derivatives)

	Investments 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.
	Unrestricted investments and lease deposits 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 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 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 were no contracts for which we have elected cash flow hedge accounting and therefore, there was no hedge ineffectiveness during the years ended December 31, 2013, 2012, or 2011.
	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.

Patronage Capital	'
	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 of patronage capital are subject to the discretion of our board of directors and the restrictions contained in our 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	'
	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 $88.5 million and $86.2 million, at December 31, 2013 and 2012, respectively.

Segment	'
	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 President and 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, physically-delivered forward power purchase contracts, and spot market energy purchases.

Cash Equivalents	'
	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.

Summary_Of_Significant_Account2

Summary Of Significant Accounting Policies (Tables)	12 Months Ended
Summary Of Significant Accounting Policies (Tables)	Dec. 31, 2013
Summary Of Significant Accounting Policies [Abstract]	'
Schedule Of Depreciation Rates	'


		Depreciation Rates
	Generating Facility	2013		2012		2011
	Clover	1.8	%	1.8	%	1.8	%
	North Anna	3.0		3.0		3.0
	Louisa	3.5		3.5		3.5
	Marsh Run	3.2		3.2		3.2
	Rock Springs	3.3		3.3		3.3

Electric_Plant_Tables

Electric Plant (Tables)	12 Months Ended
Electric Plant (Tables)	Dec. 31, 2013
Electric Plant [Abstract]	'
Schedule Of Public Utility Property, Plant, And Equipment	'
	Our net electric plant is comprised of the following for 2013:



									Combustion
						North			Turbine
			Clover			Anna			Facilities		Other		Total

			(in thousands)
	Property, plant, and equipment		$	671,708		$	335,151		$	585,067	$	68,622	$	1,660,548
	Accumulated depreciation			-349,197			-184,314			-198,520		-23,257		-755,288
	Nuclear fuel			-			76,458			-		-		76,458
	Accumulated amortization of nuclear fuel			-			-52,822			-		-		-52,822
	Construction work in progress (1)			6,670			20,536			-		9,276		36,482
			$	329,181		$	195,009		$	386,547	$	54,641	$	965,378

	-1	Other includes $6.0 million related to Wildcat Point and $3.1 million for transmission.

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



									Combustion
						North			Turbine
			Clover			Anna			Facilities		Other		Total

			(in thousands)
	Property, plant, and equipment		$	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




Schedule Of Projected Capital Expenditures	'


		Projected
		Year Ended December 31,
		2014			2015			2016

		(in millions)
	Wildcat Point (1)	$	98.7		$	455.8		$	185.4
	Clover		17.5			20.3			9.2
	North Anna nuclear fuel		13.1			7.9			16.0
	North Anna		10.3			7.4			8.0
	Transmission		7.5			7.0			3.0
	Combustion turbine facilities		0.9			1.1			1.1
	Other		2.6			2.8			2.9
	Total	$	150.6		$	502.3		$	225.6
		-1		Wildcat Point capital expenditures are subject to necessary governmental and regulatory approvals.

Accounting_For_Asset_Retiremen1

Accounting For Asset Retirement And Environmental Obligations (Tables)	12 Months Ended
	Dec. 31, 2013
Accounting For Asset Retirement And Environmental Obligations [Abstract]	'
Schedule Of Changes In Asset Retirement Obligations	'


	Asset retirement obligations at December 31, 2011	$	73,141
	Accretion expense		3,739
	Asset retirement obligations at December 31, 2012	$	76,880
	Accretion expense		3,980
	Asset retirement obligations at December 31, 2013	$	80,860

Power_Purchase_Agreements_Tabl

Power Purchase Agreements (Tables)	12 Months Ended
Power Purchase Agreements (Tables)	Dec. 31, 2013
Power Purchase Agreements [Abstract]	'
Schedule Of Energy And Capacity Purchase Commitments	'


		Energy and
		Capacity
	Year Ending December 31,	Commitments
		(in millions)
	2014	$	212.0
	2015		187.3
	2016		200.3
		$	599.6

Wholesale_Power_Contracts_Tabl

Wholesale Power Contracts (Tables)	12 Months Ended
Wholesale Power Contracts (Tables)	Dec. 31, 2013
Wholesale Power Contracts [Abstract]	'
Schedule Of Revenues From Member Distribution Cooperatives	'


		Year Ended December 31,
		2013		2012		2011

		(in millions)

	Rappahannock Electric Cooperative	$	275.9	$	280.4	$	290.4
	Shenandoah Valley Electric Cooperative		150.4		152.1		159.8
	Delaware Electric Cooperative, Inc.		94.7		95.4		97.6
	Choptank Electric Cooperative, Inc.		72.1		75.9		76.6
	Southside Electric Cooperative		64.5		66.0		67.5
	A&N Electric Cooperative		47.8		48.4		50.1
	Mecklenburg Electric Cooperative		39.7		40.6		41.8
	Prince George Electric Cooperative		21.6		22.1		22.5
	Northern Neck Electric Cooperative		19.5		19.7		20.5
	Community Electric Cooperative		13.9		14.1		14.7
	BARC Electric Cooperative		10.0		12.1		12.4
		$	810.1	$	826.8	$	853.9

Fair_Value_Measurements_Tables

Fair Value Measurements (Tables)	12 Months Ended
Fair Value Measurements (Tables)	Dec. 31, 2013
Fair Value Measurements [Abstract]	'
Financial Assets And Liabilities Measured At Fair Value On A Recurring Basis	'


				Quoted Prices
				in Active		Significant
				Markets for		Other		Significant
				Identical		Observable		Unobservable
		December 31,		Assets		Inputs		Inputs
		2013		(Level 1)		(Level 2)		(Level 3)

		(in thousands)
	Nuclear decommissioning trust (1)(2)	$	134,454	$	42,661	$	91,793	$	-
	Unrestricted investments and other (3)		173		173		-		-
	Derivatives - gas and power (4)		412		412		-		-
	Total Financial Assets	$	135,039	$	43,246	$	91,793	$	-


				Quoted Prices
				in Active		Significant
				Markets for		Other		Significant
				Identical		Observable		Unobservable
		December 31,		Assets		Inputs		Inputs
		2012		(Level 1)		(Level 2)		(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	$	-	$	-


	-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 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 are related to equity securities.
	-4	Derivatives – gas and power represent natural gas futures contracts which are recorded on our Consolidated Balance Sheet in either deferred charges-other or deferred credits and other liabilities–other, and which are indexed against NYMEX. See Note 1—Summary of Significant Accounting Policies.

Derivatives_And_Hedging_Tables

Derivatives And Hedging (Tables)	12 Months Ended
Derivatives And Hedging (Tables)	Dec. 31, 2013
Derivatives And Hedging [Abstract]	'
Schedule Of Outstanding Derivative Instruments	'


					As of		As of
					31-Dec-13		31-Dec-12
	Commodity		Unit of Measure		Quantity		Quantity
	Natural Gas		MMBTU		1,470,000		650,000



Fair Value Of Derivative Instruments	'


					Fair Value
					As of			As of
					December 31,			December 31,
			Balance Sheet Location		2013			2012
					(in thousands)
	Derivatives in an asset position:
	Natural gas futures contracts		Deferred charges-other		$	412		$	-
	Total derivatives in an asset position				$	412		$	-

	Derivatives in a liability position:
	Natural gas futures contracts		Deferred credits and other liabilities-other		$	-	.	$	624
	Total derivatives in a liability position				$	-		$	624


Effect Of Derivative Instruments On The Statement Of Revenues, Expenses, And Patronage Capital	'





			Amount of							Amount of Gain
			Gain (Loss)							(Loss) Reclassified
			Recognized in						Location of Gain	from Regulatory
			Regulatory						(Loss) Reclassified	Asset/Liability into
	Derivatives Accounted for		Asset/Liability for						from Regulatory	Income for the
	Utilizing Regulatory		Derivatives as of						Asset/Liability into	Year Ended
	Accounting		December 31,						Income	December 31,
			2013			2012				2013		2012

			(in thousands)							(in thousands)
	Natural gas futures contracts (1)		$	419		$	-2,264		Fuel	$	-3,031	$	-6,522
	Purchased power contracts			-			-		Purchased power		-		-2,736
	Total		$	419		$	-2,264			$	-3,031	$	-9,258

	-1	As of December 31, 2013 and 2012, includes a regulatory asset of $7.0 thousand and $1.6 million, respectively, to be recognized in future periods as the result of the contracts being effectively settled.

Investments_Tables

Investments (Tables)	12 Months Ended
Investments (Tables)	Dec. 31, 2013
Investments [Abstract]	'
Schedule Of Investments	'



								Gross			Gross
								Unrealized			Unrealized			Fair			Carrying
	Description		Designation		Cost			Gains			Losses			Value			Value

					(in thousands)
	31-Dec-13

	Nuclear decommissioning trust (1)(2)
	Debt securities		Available for sale		$	40,352		$	1,719		$	-		$	42,071		$	42,071
	Equity securities		Available for sale			62,293			29,500			-			91,793			91,793
	Cash and other		Available for sale			590			-			-			590			590
	Total Nuclear Decommissioning Trust				$	103,235		$	31,219		$	-		$	134,454		$	134,454

	Lease Deposits (3)
	Government obligations		Held to maturity		$	96,634		$	5,676		$	-		$	102,310		$	96,634
	Total Lease Deposits				$	96,634		$	5,676		$	-		$	102,310		$	96,634

	Unrestricted investments
	Government obligations		Held to maturity		$	20,174		$	1		$	-		$	20,175		$	20,174
	Debt securities		Held to maturity			2,200			-			-4			2,196			2,200
	Total Unrestricted Investments				$	22,374		$	1		$	-4		$	22,371		$	22,374

	Other
	Equity securities		Trading		$	131		$	42		$	-		$	173		$	173
	Non-marketable equity investments		Equity			2,349			1,735			-			4,084			2,349
	Total Other				$	2,480		$	1,777		$	-		$	4,257		$	2,522
																	$	255,984

	31-Dec-12

	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		Equity			1,827			-			-			1,827			1,827
	Total Other				$	1,940		$	9		$	-		$	1,949		$	1,949
																	$	263,024


	-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 fourth quarter of 2013 and 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.


Schedule Of Investments By Classification	'


			31-Dec-13						31-Dec-12
						Carrying						Carrying
	Description		Cost			Value			Cost			Value

			(in thousands)
	Available for sale		$	103,235		$	134,454		$	96,010		$	113,402
	Held to maturity			119,008			119,008			147,795			147,795
	Equity			2,349			2,349			1,827			1,827
	Trading			131			173			-			-
			$	224,723		$	255,984		$	245,632		$	263,024


Schedule Of Contractual Maturities Of Debt Securities	'



			Less than									More than
	Description		1 year			1-5 years			5-10 years			10 years			Total

			(in thousands)
	Available for sale (1)		$	-		$	-		$	42,071		$	-		$	42,071
	Held to maturity			21,931			96,840			237			-			119,008
			$	21,931		$	96,840		$	42,308		$	-		$	161,079
	(1) The contractual maturities of available for sale debt securities are measured using the effective duration of the bond fund within the nuclear decommissioning trust.

Regulatory_Assets_And_Liabilit1

Regulatory Assets And Liabilities (Tables)	12 Months Ended
Regulatory Assets And Liabilities (Tables)	Dec. 31, 2013
Regulatory Assets And Liabilities [Abstract]	'
Schedule Of Regulatory Assets And Liabilities	'


		December 31,
		2013		2012

		(in thousands)
	Regulatory Assets:
	Unamortized losses on reacquired debt	$	17,435	$	18,297
	Deferred asset retirement costs		363		380
	Deferred net unrealized losses on derivative instruments		-		2,264
	NOVEC contract termination fee		36,703		39,149
	Loan acquisition fee		894		1,118
	Interest rate hedge		2,879		3,050
	North Anna Unit 3		22,748		22,748
	Voluntary prepayment to NRECA Retirement Security Plan		6,961		-
	Total Regulatory Assets	$	87,983	$	87,006

	Regulatory Liabilities:
	North Anna asset retirement obligation deferral	$	39,581	$	35,958
	Norfolk Southern settlement		5,136		17,462
	North Anna nuclear decommissioning trust unrealized gain		31,220		17,383
	Unamortized gains on reacquired debt		584		649
	Deferred net unrealized gains on derivative instruments		419		-
	Total Regulatory Liabilities	$	76,940	$	71,452

	Regulatory Liabilities included in Current Liabilities:
	Deferred energy	$	37,193	$	56,027

LongTerm_Debt_Tables

Long-Term Debt (Tables)	12 Months Ended
Long-Term Debt (Tables)	Dec. 31, 2013
Long-Term Debt [Abstract]	'
Schedule Of Long-Term Debt	'


				December 31,
				2013		2012

				(in thousands)

	$50,000,000 principal amount of First Mortgage Bonds, 2013 Series A due			$	50,000	$	-
	2043 at an interest rate of 4.21%

	$50,000,000 principal amount of First Mortgage Bonds, 2013 Series B due				50,000		-
	2053 at an interest rate of 4.36%

	$90,000,000 principal amount of First Mortgage Bonds, 2011 Series A due
	2040 at an interest rate of 4.83%				81,000		84,000

	$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%				87,875		90,250

	$250,000,000 principal amount of 2003 Series A Bonds due 2028 at an
	interest rate of 5.676%				156,247		166,664

	$27,755,000 principal amount of 2002 Series A Bonds due 2028 at an
	interest rate of 5.00%				-		27,755

	$32,455,000 principal amount of 2002 Series A Bonds due 2028 at an
	interest rate of 5.625%				-		32,455

	$300,000,000 principal amount of 2002 Series B Bonds due 2028 at an
	interest rate of 6.21%				187,500		200,000
					777,622		766,124
	Unamortized discounts and premiums				-		4
	Current maturities				-28,292		-28,292
				$	749,330	$	737,836


Schedule Of Maturities Of Long-Term Debt	'


	Year Ending December 31,	(in thousands)
	2014	$	28,292
	2015		28,292
	2016		28,292
	2017		28,292
	2018		28,292
	2019 and thereafter		636,162
		$	777,622

Selected_Quarterly_Financial_D1

Selected Quarterly Financial Data (Tables)	12 Months Ended
Selected Quarterly Financial Data (Tables)	Dec. 31, 2013
Selected Quarterly Financial Data [Abstract]	'
Schedule Of Quarterly Financial Information	'


		First		Second		Third		Fourth
		Quarter		Quarter		Quarter		Quarter		Total

		(in thousands)
	Statement of Operations Data
	2013
	Operating Revenues	$	220,713	$	187,623	$	220,393	$	213,340	$	842,069
	Operating Margin		14,302		13,130		14,010		11,148		52,590
	Net Margin attributable to ODEC		2,386		2,346		2,448		2,393		9,573

	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

Summary_Of_Significant_Account3

Summary Of Significant Accounting Policies (Narrative) (Details) (USD $)

12 Months Ended

Dec. 31, 2013

Dec. 31, 2012

Dec. 31, 2011

Jan. 31, 2014

Dec. 31, 2012

Dec. 31, 2013

Dec. 31, 2012

Dec. 31, 2011

Dec. 31, 2013

Forecast [Member]

Property, Plant and Equipment [Member]

Fuel Expense [Member]

Operations And Maintenance Expense [Member]

Class A Members [Member]

Class B Members [Member]

Minimum [Member]

Maximum [Member]

item

Significant Accounting Policies [Line Items]

Number of members

Number of directors

Consolidated net assets

$5,700,000

$14,000,000

Percentage of interest owned in subsidiary by our Class A members

100.00%

Reimbursement of nuclear fuel costs

8,300,000

7,800,000

2,100,000

1,800,000

6,200,000

6,700,000

1,100,000

Reimbursement of nuclear fuel costs receivable

3,900,000

2,100,000

Interest Costs Capitalized

200,000

1,000,000

900,000

Member energy sales

810,100,000

826,800,000

853,900,000

Non-member energy sales

31,900,000

15,900,000

37,600,000

Margin Stabilization Plan Adjustment

9,800,000

15,000,000

14,900,000

Percentage of total interest, as part of Membership Distribution Cooperative charge rate

20.00%

10.00%

20.00%

Capitalized costs associated with the issuance of debt

6,700,000

8,300,000

Unamortized portion of the deferred gain

4,300,000

5,400,000

Deferred energy

37,193,000

56,027,000

33,400,000

Accounts receivable - members

$88,545,000

$86,154,000

Summary_Of_Significant_Account4

Summary Of Significant Accounting Policies (Schedule Of Depreciation Rates) (Details)	12 Months Ended
	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Clover [Member]	'	'	'
Segment Reporting Information [Line Items]	'	'	'
Depreciation Rates	1.80%	1.80%	1.80%
North Anna [Member]	'	'	'
Segment Reporting Information [Line Items]	'	'	'
Depreciation Rates	3.00%	3.00%	3.00%
Louisa [Member]	'	'	'
Segment Reporting Information [Line Items]	'	'	'
Depreciation Rates	3.50%	3.50%	3.50%
Marsh Run [Member]	'	'	'
Segment Reporting Information [Line Items]	'	'	'
Depreciation Rates	3.20%	3.20%	3.20%
Rock Springs [Member]	'	'	'
Segment Reporting Information [Line Items]	'	'	'
Depreciation Rates	3.30%	3.30%	3.30%

Electric_Plant_Narrative_Detai

Electric Plant (Narrative) (Details) (USD $)	12 Months Ended
Electric Plant (Narrative) (Details) (USD $)	Dec. 31, 2013		Dec. 31, 2012	Dec. 31, 2011
Segment Reporting Information [Line Items]	'		'	'
Administrative and general	$42,385,000		$35,958,000	$36,520,000
Construction work in progress	36,482,000	[1]	36,797,000	'
Clover [Member]	'		'	'
Segment Reporting Information [Line Items]	'		'	'
Undivided ownership interest	50.00%		'	'
Power facility output	874		'	'
Percent of costs	50.00%		'	'
Number of units	2		'	'
Outstanding accounts payable balance	12,700,000		14,700,000	'
Construction work in progress	6,670,000	[1]	6,080,000	'
North Anna [Member]	'		'	'
Segment Reporting Information [Line Items]	'		'	'
Decommissioning Liability, Noncurrent	72,100,000		68,500,000	'
Undivided ownership interest	11.60%		'	'
Power facility output	1,897		'	'
Percent of costs	11.60%		'	'
Number of units	2		'	'
Outstanding accounts payable balance	4,100,000		11,200,000	'
Construction work in progress	20,536,000	[1]	29,955,000	'
Combustion Turbine Facilities [Member]	'		'	'
Segment Reporting Information [Line Items]	'		'	'
Number of combustion facilities	3		'	'
Transmission lines	1,100		'	'
Transmission line capacity	500		'	'
Substation Capacity	500		'	'
Construction work in progress	'		105,000	'
Other [Member]	'		'	'
Segment Reporting Information [Line Items]	'		'	'
Transmission lines	100		'	'
Construction work in progress	9,276,000	[1]	657,000	'
Wildcat Point [Member]	'		'	'
Segment Reporting Information [Line Items]	'		'	'
Power facility output	1,000		'	'
Number of combustion turbines	2		'	'
Number of heat recovery systems	2		'	'
Number of steam turbine generators	1		'	'
Administrative and general	7,700,000		'	'
Construction work in progress	$6,000,000		'	'

[1]	Other includes $6.0 million related to Wildcat Point and $3.1 million for transmission

Electric_Plant_Schedule_Of_Pub

Electric Plant (Schedule Of Public Utility Property, Plant, And Equipment) (Details) (USD $)	Dec. 31, 2013		Dec. 31, 2012
In Thousands, unless otherwise specified	Dec. 31, 2013		Dec. 31, 2012
Segment Reporting Information [Line Items]	'		'
Property, plant, and equipment	$1,660,548		$1,655,705
Accumulated depreciation	-755,288		-721,541
Nuclear fuel	76,458		63,186
Accumulated amortization of nuclear fuel	-52,822		-42,807
Construction work in progress	36,482	[1]	36,797
Net Electric Plant	965,378		991,340
Clover [Member]	'		'
Segment Reporting Information [Line Items]	'		'
Property, plant, and equipment	671,708		672,541
Accumulated depreciation	-349,197		-344,428
Construction work in progress	6,670	[1]	6,080
Net Electric Plant	329,181		334,193
North Anna [Member]	'		'
Segment Reporting Information [Line Items]	'		'
Property, plant, and equipment	335,151		331,878
Accumulated depreciation	-184,314		-176,442
Nuclear fuel	76,458		63,186
Accumulated amortization of nuclear fuel	-52,822		-42,807
Construction work in progress	20,536	[1]	29,955
Net Electric Plant	195,009		205,770
Combustion Turbine Facilities [Member]	'		'
Segment Reporting Information [Line Items]	'		'
Property, plant, and equipment	585,067		584,004
Accumulated depreciation	-198,520		-179,072
Construction work in progress	'		105
Net Electric Plant	386,547		405,037
Other [Member]	'		'
Segment Reporting Information [Line Items]	'		'
Property, plant, and equipment	68,622		67,282
Accumulated depreciation	-23,257		-21,599
Construction work in progress	9,276	[1]	657
Net Electric Plant	54,641		46,340
Wildcat Point [Member]	'		'
Segment Reporting Information [Line Items]	'		'
Construction work in progress	6,000		'
Transmission [Member]	'		'
Segment Reporting Information [Line Items]	'		'
Construction work in progress	$3,100		'

[1]	Other includes $6.0 million related to Wildcat Point and $3.1 million for transmission

Electric_Plant_Schedule_Of_Pro

Electric Plant (Schedule Of Projected Capital Expenditures) (Details) (Forecast [Member], USD $)	12 Months Ended
In Millions, unless otherwise specified	Dec. 31, 2016		Dec. 31, 2015		Dec. 31, 2014
Segment Reporting Information [Line Items]	'		'		'
Total	$225.60		$502.30		$150.60
Wildcat Point [Member]	'		'		'
Segment Reporting Information [Line Items]	'		'		'
Total	185.4	[1]	455.8	[1]	98.7	[1]
Clover [Member]	'		'		'
Segment Reporting Information [Line Items]	'		'		'
Total	9.2		20.3		17.5
North Anna Nuclear Fuel [Member]	'		'		'
Segment Reporting Information [Line Items]	'		'		'
Total	16		7.9		13.1
North Anna [Member]	'		'		'
Segment Reporting Information [Line Items]	'		'		'
Total	8		7.4		10.3
Transmission [Member]	'		'		'
Segment Reporting Information [Line Items]	'		'		'
Total	3		7		7.5
Combustion Turbine Facilities [Member]	'		'		'
Segment Reporting Information [Line Items]	'		'		'
Total	1.1		1.1		0.9
Other [Member]	'		'		'
Segment Reporting Information [Line Items]	'		'		'
Total	$2.90		$2.80		$2.60

[1]	Wildcat Point capital expenditures are subject to necessary governmental and regulatory approvals

Accounting_For_Asset_Retiremen2

Accounting For Asset Retirement And Environmental Obligations (Narrative) (Details) (USD $)	12 Months Ended
In Millions, unless otherwise specified	Dec. 31, 2013	Dec. 31, 2012
Asset Retirement And Environmental Obligations [Line Items]	'	'
Decommission study period	'4 years	'
North Anna [Member]	'	'
Asset Retirement And Environmental Obligations [Line Items]	'	'
North Anna's nuclear decommissioning asset retirement obligation	$72.10	$68.50
Asset retirement obligations cash flow estimates useful life	'20 years	'

Accounting_For_Asset_Retiremen3

Accounting For Asset Retirement And Environmental Obligations (Schedule Of Changes In Asset Retirement Obligations) (Details) (USD $)	12 Months Ended
In Thousands, unless otherwise specified	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Accounting For Asset Retirement And Environmental Obligations [Abstract]	'	'	'
Asset retirement obligations	$76,880	$73,141	'
Accretion expense	3,980	3,739	3,572
Asset retirement obligations	$80,860	$76,880	$73,141

Power_Purchase_Agreements_Narr

Power Purchase Agreements (Narrative) (Details) (USD $)	12 Months Ended
In Thousands, unless otherwise specified	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Power Purchase Agreements [Abstract]	'	'	'
Energy requirements from owned generating facilities	39.40%	33.40%	33.30%
Deposits from counterparties pursuant to contracts	$4,400	$4,400	'
Purchased power	$529,749	$537,746	$593,030

Power_Purchase_Agreements_Sche

Power Purchase Agreements (Schedule Of Energy And Capacity Purchase Commitments) (Details) (USD $)	12 Months Ended
In Millions, unless otherwise specified	Dec. 31, 2013
Power Purchase Agreements [Abstract]	'
2014	$212
2015	187.3
2016	200.3
Energy and Capacity Purchase Commitments	$599.60

Wholesale_Power_Contracts_Narr

Wholesale Power Contracts (Narrative) (Details)	12 Months Ended
	Dec. 31, 2013	Dec. 31, 2014
	MW	Forecast [Member]
		MW
Wholesale Power Contracts [Line Items]	'	'
Wholesale power contract, expiration date	1-Jan-54	'
Purchases under principal contract exceptions, percent of energy requirements	1.50%	'
Purchases under limited contract exceptions, percent of power received from owned generation or other suppliers	5.00%	'
Purchases under limited contract exceptions, amount of power received from owned generation or other suppliers	5	'
Power received under limited exceptions to wholesale power contract	6.7	74

Wholesale_Power_Contracts_Sche

Wholesale Power Contracts (Schedule Of Revenues From Member Distribution Cooperatives) (Details) (USD $)	12 Months Ended
In Millions, unless otherwise specified	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Related Party Transaction [Line Items]	'	'	'
Member distribution revenue	$810.10	$826.80	$853.90
Rappahannock Electric Cooperative [Member]	'	'	'
Related Party Transaction [Line Items]	'	'	'
Member distribution revenue	275.9	280.4	290.4
Shenandoah Valley Electric Cooperative [Member]	'	'	'
Related Party Transaction [Line Items]	'	'	'
Member distribution revenue	150.4	152.1	159.8
Delaware Electric Cooperative, Inc. [Member]	'	'	'
Related Party Transaction [Line Items]	'	'	'
Member distribution revenue	94.7	95.4	97.6
Choptank Electric Cooperative, Inc. [Member]	'	'	'
Related Party Transaction [Line Items]	'	'	'
Member distribution revenue	72.1	75.9	76.6
Southside Electric Cooperative [Member]	'	'	'
Related Party Transaction [Line Items]	'	'	'
Member distribution revenue	64.5	66	67.5
A&N Electric Cooperative [Member]	'	'	'
Related Party Transaction [Line Items]	'	'	'
Member distribution revenue	47.8	48.4	50.1
Mecklenburg Electric Cooperative [Member]	'	'	'
Related Party Transaction [Line Items]	'	'	'
Member distribution revenue	39.7	40.6	41.8
Prince George Electric Cooperative [Member]	'	'	'
Related Party Transaction [Line Items]	'	'	'
Member distribution revenue	21.6	22.1	22.5
Northern Neck Electric Cooperative [Member]	'	'	'
Related Party Transaction [Line Items]	'	'	'
Member distribution revenue	19.5	19.7	20.5
Community Electric Cooperative [Member]	'	'	'
Related Party Transaction [Line Items]	'	'	'
Member distribution revenue	13.9	14.1	14.7
BARC Electric Cooperative [Member]	'	'	'
Related Party Transaction [Line Items]	'	'	'
Member distribution revenue	$10	$12.10	$12.40

Fair_Value_Measurements_Detail

Fair Value Measurements (Details) (USD $)	Dec. 31, 2013		Dec. 31, 2012
In Thousands, unless otherwise specified	Dec. 31, 2013		Dec. 31, 2012
Fair Value, Assets Measured on Recurring Basis, Unobservable Input Reconciliation [Line Items]	'		'
Total Financial Assets	$135,039		$113,402
Total Financial Liabilities	'		624
Derivatives - Gas And Power [Member]	'		'
Fair Value, Assets Measured on Recurring Basis, Unobservable Input Reconciliation [Line Items]	'		'
Total Financial Assets	412	[1]	'
Total Financial Liabilities	'		624	[1]
Quoted Prices In Active Markets For Identical Assets (Level 1) [Member]	'		'
Fair Value, Assets Measured on Recurring Basis, Unobservable Input Reconciliation [Line Items]	'		'
Total Financial Assets	43,246		38,170
Total Financial Liabilities	'		624
Quoted Prices In Active Markets For Identical Assets (Level 1) [Member] \| Derivatives - Gas And Power [Member]	'		'
Fair Value, Assets Measured on Recurring Basis, Unobservable Input Reconciliation [Line Items]	'		'
Total Financial Assets	412	[1]	'
Total Financial Liabilities	'		624	[1]
Significant Other Observable Inputs (Level 2) [Member]	'		'
Fair Value, Assets Measured on Recurring Basis, Unobservable Input Reconciliation [Line Items]	'		'
Total Financial Assets	91,793		75,232
Nuclear Decommissioning Trust [Member]	'		'
Fair Value, Assets Measured on Recurring Basis, Unobservable Input Reconciliation [Line Items]	'		'
Total Financial Assets	134,454	[2],[3]	113,280	[2],[3]
Nuclear Decommissioning Trust [Member] \| Quoted Prices In Active Markets For Identical Assets (Level 1) [Member]	'		'
Fair Value, Assets Measured on Recurring Basis, Unobservable Input Reconciliation [Line Items]	'		'
Total Financial Assets	42,661	[2],[3]	38,048	[2],[3]
Nuclear Decommissioning Trust [Member] \| Significant Other Observable Inputs (Level 2) [Member]	'		'
Fair Value, Assets Measured on Recurring Basis, Unobservable Input Reconciliation [Line Items]	'		'
Total Financial Assets	91,793	[2],[3]	75,232	[2],[3]
Unrestricted Investment And Other [Member]	'		'
Fair Value, Assets Measured on Recurring Basis, Unobservable Input Reconciliation [Line Items]	'		'
Total Financial Assets	173	[4]	122	[4]
Unrestricted Investment And Other [Member] \| Quoted Prices In Active Markets For Identical Assets (Level 1) [Member]	'		'
Fair Value, Assets Measured on Recurring Basis, Unobservable Input Reconciliation [Line Items]	'		'
Total Financial Assets	$173	[4]	$122	[4]

[1]	Derivatives - gas and power represent natural gas futures contracts which are recorded on our Consolidated Balance Sheet in either deferred charges-other or deferred credits and other liabilities-other, and which are indexed against NYMEX. See Note 1bSummary of Significant Accounting Policies
[2]	For additional information about our nuclear decommissioning trust see Note 9bInvestments
[3]	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 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
[4]	Unrestricted investments and other includes investments that are related to equity securities

Derivatives_And_Hedging_Schedu

Derivatives And Hedging (Schedule Of Outstanding Derivative Instruments) (Details) (Natural Gas [Member])	12 Months Ended
	Dec. 31, 2013	Dec. 31, 2012
	MMBTU	MMBTU
Natural Gas [Member]	'	'
Derivative [Line Items]	'	'
Quantity	1,470,000	650,000

Derivatives_And_Hedging_Schedu1

Derivatives And Hedging (Schedule Of Fair Value Of Derivative Instruments) (Details) (USD $)	Dec. 31, 2013	Dec. 31, 2012
In Thousands, unless otherwise specified	Dec. 31, 2013	Dec. 31, 2012
Derivatives, Fair Value [Line Items]	'	'
Total derivatives in an asset position	$412	'
Total derivatives in a liability position	'	624
Natural Gas Future Contracts [Member] \| Deferred Charges - Other [Member]	'	'
Derivatives, Fair Value [Line Items]	'	'
Total derivatives in an asset position	412	'
Natural Gas Future Contracts [Member] \| Deferred Credits And Other Liabilities - Other [Member]	'	'
Derivatives, Fair Value [Line Items]	'	'
Total derivatives in a liability position	'	$624

Derivatives_And_Hedging_Schedu2

Derivatives And Hedging (Schedule Of Derivative Instruments On The Statement Of Revenues, Expenses, And Patronage Capital) (Details) (USD $)	12 Months Ended
In Thousands, unless otherwise specified	Dec. 31, 2013		Dec. 31, 2012
Derivative [Line Items]	'		'
Amount of Gain (Loss) Recognized within Regulatory Asset/Liability for Derivatives	$419		($2,264)
Amount Of Gain (Loss) Reclassified from Regulatory Asset/Liability into Income	-3,031		-9,258
Regulatory asset to be recognized in the future	7		1,600
Natural Gas Future Contracts [Member]	'		'
Derivative [Line Items]	'		'
Amount of Gain (Loss) Recognized within Regulatory Asset/Liability for Derivatives	419	[1]	-2,264	[1]
Natural Gas Future Contracts [Member] \| Fuel [Member]	'		'
Derivative [Line Items]	'		'
Amount Of Gain (Loss) Reclassified from Regulatory Asset/Liability into Income	-3,031	[1]	-6,522	[1]
Purchased Power Contracts [Member] \| Purchased Power [Member]	'		'
Derivative [Line Items]	'		'
Amount Of Gain (Loss) Reclassified from Regulatory Asset/Liability into Income	'		($2,736)

[1]	As of December 31, 2013 and 2012, includes a regulatory asset of $7.0 thousand and $1.6 million, respectively, to be recognized in future periods as the result of the contracts being effectively settled

LongTerm_Lease_Transaction_Det

Long-Term Lease Transaction (Details) (USD $)	12 Months Ended
In Millions, unless otherwise specified	Dec. 31, 2013	Dec. 31, 2012
Long-Term Lease Transaction [Abstract]	'	'
Lease term	'48 years 9 months 18 days	'
Lease value	$315	'
Leaseback term	'21 years 9 months 18 days	'
Deferred gain	23.7	'
Unamortized portion of the deferred gain	4.3	5.4
Payment undertaking agreement	309.7	'
Debt considered to be extinguished by in substance defeasance	$309.70	$310.80

Investments_Schedule_Of_Invest

Investments (Schedule Of Investments) (Details) (USD $)	12 Months Ended
In Thousands, unless otherwise specified	Dec. 31, 2013		Dec. 31, 2012
Investment Holdings [Line Items]	'		'
Available for sale, Cost	$103,235		$96,010
Available for sale, Fair Value	134,454		113,402
Held to maturity, Cost	119,008		147,795
Equity, Cost	2,349		1,827
Trading, Cost	131		'
Trading, Fair Value	173		'
Total Nuclear Decommissioning Trust	134,454		113,280
Total Lease Deposits	96,634		94,145
Total Carrying Value	255,984		263,024
Nuclear Decommissioning Trust [Member]	'		'
Investment Holdings [Line Items]	'		'
Available for sale, Cost	103,235	[1],[2]	95,897	[1],[2]
Available for sale, Gross Unrealized Gains	31,219	[1],[2]	17,383	[1],[2]
Available for sale, Fair Value	134,454	[1],[2]	113,280	[1],[2]
Total Nuclear Decommissioning Trust	134,454	[1],[2]	113,280	[1],[2]
Nuclear Decommissioning Trust [Member] \| Debt Securities [Member]	'		'
Investment Holdings [Line Items]	'		'
Available for sale, Cost	40,352	[1],[2]	34,342	[1],[2]
Available for sale, Gross Unrealized Gains	1,719	[1],[2]	3,473	[1],[2]
Available for sale, Fair Value	42,071	[1],[2]	37,815	[1],[2]
Total Carrying Value	42,071	[1],[2]	37,815	[1],[2]
Nuclear Decommissioning Trust [Member] \| Equity Securities [Member]	'		'
Investment Holdings [Line Items]	'		'
Available for sale, Cost	62,293	[1],[2]	61,322	[1],[2]
Available for sale, Gross Unrealized Gains	29,500	[1],[2]	13,910	[1],[2]
Available for sale, Fair Value	91,793	[1],[2]	75,232	[1],[2]
Total Carrying Value	91,793	[1],[2]	75,232	[1],[2]
Nuclear Decommissioning Trust [Member] \| Cash And Other [Member]	'		'
Investment Holdings [Line Items]	'		'
Available for sale, Cost	590	[1],[2]	233	[1],[2]
Available for sale, Fair Value	590	[1],[2]	233	[1],[2]
Total Carrying Value	590	[1],[2]	233	[1],[2]
Lease Deposits [Member]	'		'
Investment Holdings [Line Items]	'		'
Held to maturity, Cost	96,634	[3]	94,145	[3]
Held to maturity, Gross Unrealized Gains	5,676	[3]	11,063	[3]
Held to maturity, Fair Value	102,310	[3]	105,208	[3]
Total Lease Deposits	96,634	[3]	94,145	[3]
Lease Deposits [Member] \| Government Obligations [Member]	'		'
Investment Holdings [Line Items]	'		'
Held to maturity, Cost	96,634	[3]	94,145	[3]
Held to maturity, Gross Unrealized Gains	5,676	[3]	11,063	[3]
Held to maturity, Fair Value	102,310	[3]	105,208	[3]
Total Carrying Value	96,634	[3]	94,145	[3]
Unrestricted Investments [Member]	'		'
Investment Holdings [Line Items]	'		'
Held to maturity, Cost	22,374		53,650
Held to maturity, Gross Unrealized Gains	1		8
Held to maturity, Gross Unrealized Losses	-4		'
Held to maturity, Fair Value	22,371		53,658
Total Unrestricted Investments	22,374		53,650
Unrestricted Investments [Member] \| Debt Securities [Member]	'		'
Investment Holdings [Line Items]	'		'
Held to maturity, Cost	2,200		1,750
Held to maturity, Gross Unrealized Losses	-4		'
Held to maturity, Fair Value	2,196		1,750
Total Carrying Value	2,200		1,750
Unrestricted Investments [Member] \| Government Obligations [Member]	'		'
Investment Holdings [Line Items]	'		'
Held to maturity, Cost	20,174		51,900
Held to maturity, Gross Unrealized Gains	1		8
Held to maturity, Fair Value	20,175		51,908
Total Carrying Value	20,174		51,900
Other Debt Securities [Member]	'		'
Investment Holdings [Line Items]	'		'
Other, Cost	2,480		1,940
Other, Gross Unrealized Gains	1,777		9
Other, Fair Value	4,257		1,949
Total Other	2,522		1,949
Other Debt Securities [Member] \| Equity Securities [Member]	'		'
Investment Holdings [Line Items]	'		'
Available for sale, Cost	'		113
Available for sale, Gross Unrealized Gains	'		9
Available for sale, Fair Value	'		122
Trading, Cost	131		'
Trading, Gross Unrealized Gains	42		'
Trading, Fair Value	173		'
Total Carrying Value	173		122
Other Debt Securities [Member] \| Non-Marketable Equity Investments [Member]	'		'
Investment Holdings [Line Items]	'		'
Equity, Cost	2,349		1,827
Equity, Gross Unrealized Gains	1,735		'
Equity, Fair Value	4,084		1,827
Total Carrying Value	$2,349		$1,827

[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 3bAccounting 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 fourth quarter of 2013 and 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 8bLong-term Lease Transaction.

Investments_Schedule_Of_Invest1

Investments (Schedule Of Investments By Classification) (Details) (USD $)	Dec. 31, 2013	Dec. 31, 2012
In Thousands, unless otherwise specified	Dec. 31, 2013	Dec. 31, 2012
Investments [Abstract]	'	'
Available for sale, Cost	$103,235	$96,010
Held to maturity, Cost	119,008	147,795
Equity, Cost	2,349	1,827
Trading, Cost	131	'
Investments, Cost	224,723	245,632
Available for sale, Carrying Value	134,454	113,402
Held to maturity, Carrying Value	119,008	147,795
Equity, Carrying Value	2,349	1,827
Trading, Carrying Value	173	'
Total Investments	$255,984	$263,024

Investments_Schedule_Of_Contra

Investments (Schedule Of Contractual Maturities Of Debt Securities) (Details) (Unrestricted Securities [Member], USD $)	Dec. 31, 2013
In Thousands, unless otherwise specified	Dec. 31, 2013
Unrestricted Securities [Member]	'
Contractual Maturities [Line Items]	'
Available for sale securities, Less than 1 year	'	[1]
Available for sale securities, 1-5 years	'	[1]
Available for sale securities, 5-10 years	42,071	[1]
Available for sale securities, More than 10 years	'	[1]
Available for sale securities, Total	42,071	[1]
Held to maturity securities, Less than 1 year	21,931
Held to maturity securities, 1-5 years	96,840
Held to maturity securities, 5-10 years	237
Held to maturity securities, More than 10 years	'
Held to maturity, carrying value	119,008
Contractual maturities of securities, Less than 1 year	21,931
Contractual maturities of securities, 1-5 years	96,840
Contractual maturities of securities, 5-10 years	42,308
Contractual maturities of securities, More than 10 years	'
Contractual maturities of securities, Total	$161,079

[1]	The contractual maturities of available for sale debt securities are measured using the effective duration of the bond fund within the nuclear decommissioning trust

Regulatory_Assets_And_Liabilit2

Regulatory Assets And Liabilities (Narrative) (Details) (USD $)	12 Months Ended
In Millions, unless otherwise specified	Dec. 31, 2013
Schedule of Regulatory Assets and Liabilities [Line Items]	'
Loan acquisition fee	$33
Multiple employer pension prepayment	$7.70
Regulatory asset amortization period	'P10Y
Norfolk Southern Settlement [Member]	'
Schedule of Regulatory Assets and Liabilities [Line Items]	'
Amortization date	'2014-05
Unamortized Gains On Reacquired Debt [Member]	'
Schedule of Regulatory Assets and Liabilities [Line Items]	'
Amortization year	'2023
Unamortized Losses On Reacquired Debt [Member]	'
Schedule of Regulatory Assets and Liabilities [Line Items]	'
Amortization year	'2023
Deferred Asset Retirement Costs [Member]	'
Schedule of Regulatory Assets and Liabilities [Line Items]	'
Amortization year	'2034
NOVEC Contract Termination Fee [Member]	'
Schedule of Regulatory Assets and Liabilities [Line Items]	'
Amortization year	'2028
Loan Acquisition Fee [Member]	'
Schedule of Regulatory Assets and Liabilities [Line Items]	'
Amortization year	'2018
Interest Rate Hedge [Member]	'
Schedule of Regulatory Assets and Liabilities [Line Items]	'
Amortization year	'2050

Regulatory_Assets_And_Liabilit3

Regulatory Assets And Liabilities (Schedule Of Regulatory Assets And Liabilities) (Details) (USD $)	Dec. 31, 2013	Dec. 31, 2012
In Thousands, unless otherwise specified	Dec. 31, 2013	Dec. 31, 2012
Schedule of Regulatory Assets and Liabilities [Line Items]	'	'
Regulatory assets	$87,983	$87,006
Regulatory liabilities	76,940	71,452
North Anna Asset Retirement Obligation Deferral [Member]	'	'
Schedule of Regulatory Assets and Liabilities [Line Items]	'	'
Regulatory liabilities	39,581	35,958
Norfolk Southern Settlement [Member]	'	'
Schedule of Regulatory Assets and Liabilities [Line Items]	'	'
Regulatory liabilities	5,136	17,462
North Anna Nuclear Decommissioning Trust Unrealized Gain [Member]	'	'
Schedule of Regulatory Assets and Liabilities [Line Items]	'	'
Regulatory liabilities	31,220	17,383
Unamortized Gains On Reacquired Debt [Member]	'	'
Schedule of Regulatory Assets and Liabilities [Line Items]	'	'
Regulatory liabilities	584	649
Deferred Energy [Member]	'	'
Schedule of Regulatory Assets and Liabilities [Line Items]	'	'
Regulatory Liabilities included in Current Liabilities	37,193	56,027
Deferred Net Unrealized Gains On Derivative Instruments [Member]	'	'
Schedule of Regulatory Assets and Liabilities [Line Items]	'	'
Regulatory liabilities	419	'
Unamortized Losses On Reacquired Debt [Member]	'	'
Schedule of Regulatory Assets and Liabilities [Line Items]	'	'
Regulatory assets	17,435	18,297
Deferred Asset Retirement Costs [Member]	'	'
Schedule of Regulatory Assets and Liabilities [Line Items]	'	'
Regulatory assets	363	380
Deferred Net Unrealized Losses On Derivative Instruments [Member]	'	'
Schedule of Regulatory Assets and Liabilities [Line Items]	'	'
Regulatory assets	'	2,264
NOVEC Contract Termination Fee [Member]	'	'
Schedule of Regulatory Assets and Liabilities [Line Items]	'	'
Regulatory assets	36,703	39,149
Loan Acquisition Fee [Member]	'	'
Schedule of Regulatory Assets and Liabilities [Line Items]	'	'
Regulatory assets	894	1,118
Interest Rate Hedge [Member]	'	'
Schedule of Regulatory Assets and Liabilities [Line Items]	'	'
Regulatory assets	2,879	3,050
North Anna Unit 3 [Member]	'	'
Schedule of Regulatory Assets and Liabilities [Line Items]	'	'
Regulatory assets	22,748	22,748
Voluntary Prepayment To NRECA Retirement Security Plan [Member]	'	'
Schedule of Regulatory Assets and Liabilities [Line Items]	'	'
Regulatory assets	$6,961	'

LongTerm_Debt_Narrative_Detail

Long-Term Debt (Narrative) (Details) (USD $)	12 Months Ended		12 Months Ended
	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2013	Jun. 28, 2013	Dec. 31, 2013	Jun. 28, 2013	Dec. 31, 2013	Jun. 28, 2013
	Dec. 31, 2013	Dec. 31, 2012	2002 Series A Bonds [Member]	2013 Series A Bonds [Member]	First Mortgage Bonds, 2013 Series A Due 2043 At 4.21% [Member]	First Mortgage Bonds, 2013 Series A Due 2043 At 4.21% [Member]	First Mortgage Bonds, 2013 Series B Due 2053 At 4.36% [Member]	First Mortgage Bonds, 2013 Series B Due 2053 At 4.36% [Member]
Debt Instrument [Line Items]	'	'	'	'	'	'	'	'
Net loss on reacquired debt	$16,900,000	$17,600,000	'	'	'	'	'	'
Fair value of long-term debt	846,400,000	907,600,000	'	'	'	'	'	'
Aggregate principle amount	'	'	60,200,000	100,000,000	50,000,000	50,000,000	50,000,000	50,000,000
Percent of patronage capital to total long-term debt and patronage capital required for distribution	20.00%	'	'	'	'	'	'	'
Maximum distribution as percent of patronage capital	5.00%	'	'	'	'	'	'	'
Bond redemption date	'	'	1-Jun-13	'	'	'	'	'
Premium	'	'	300,000	'	'	'	'	'
Unamortized debt issuance costs	'	'	1,500,000	'	'	'	'	'
Unamortized debt issuance costs and premium	'	'	$1,800,000	'	'	'	'	'
Debt instrument, interest rate	'	'	'	'	4.21%	'	4.36%	'

LongTerm_Debt_Schedule_Of_Long

Long-Term Debt (Schedule Of Long-Term Debt) (Details) (USD $)

Dec. 31, 2013

Dec. 31, 2012

Dec. 31, 2013

Jun. 28, 2013

Dec. 31, 2013

Jun. 28, 2013

Dec. 31, 2013

Dec. 31, 2012

Dec. 31, 2013

Dec. 31, 2012

Dec. 31, 2013

Dec. 31, 2012

Dec. 31, 2013

Dec. 31, 2012

Dec. 31, 2013

Dec. 31, 2012

First Mortgage Bonds, 2013 Series A Due 2043 At 4.21% [Member]

First Mortgage Bonds, 2013 Series B Due 2053 At 4.36% [Member]

First Mortgage Bonds, 2011 Series A Due 2040 At 4.83% [Member]

First Mortgage Bonds, 2011 Series B Due 2040 At 5.54% [Member]

First Mortgage Bonds, 2011 Series C Due 2050 At 5.54% [Member] [Member]

2003 Series A Bonds Due 2028 At 5.676% [Member]

2002 Series A Bonds Due 2028 At 5.00% [Member]

2002 Series A Bonds Due 2028 At 5.625% [Member]

2002 Series B Bonds Due 2028 At 6.21% [Member]

Debt Instrument [Line Items]

Long-term debt

$777,622,000

$766,124,000

$50,000,000

$81,000,000

$84,000,000

$165,000,000

$87,875,000

$90,250,000

$156,247,000

$166,664,000

$27,755,000

$32,455,000

$187,500,000

$200,000,000

Unamortized discounts and premiums

4,000

Current maturities

-28,292,000

Long-term debt, excluding current maturities

749,330,000

737,836,000

Debt instrument, face amount

$50,000,000

$90,000,000

$165,000,000

$95,000,000

$250,000,000

$27,755,000

$32,455,000

$300,000,000

Debt instrument, maturity

'2043

'2053

'2040

'2050

'2028

Debt instrument, interest rate

4.21%

4.36%

4.83%

5.54%

5.68%

5.00%

5.63%

6.21%

LongTerm_Debt_Schedule_Of_Matu

Long-Term Debt (Schedule Of Maturities Of Long-Term Debt) (Details) (USD $)	Dec. 31, 2013	Dec. 31, 2012
In Thousands, unless otherwise specified	Dec. 31, 2013	Dec. 31, 2012
Long-Term Debt [Abstract]	'	'
2014	$28,292	'
2015	28,292	'
2016	28,292	'
2017	28,292	'
2018	28,292	'
2019 and thereafter	636,162	'
Long-term debt	$777,622	$766,124

ShortTerm_Borrowing_Details

Short-Term Borrowing (Details) (USD $)	12 Months Ended
In Millions, unless otherwise specified	Dec. 31, 2013	Dec. 31, 2012
Short-term Debt [Line Items]	'	'
Member distribution cooperatives, amount prepaid	$15.20	23.5
Member distribution cooperatives, amount extended	10.8	13.6
Federal Funds Effective Rate [Member]	'	'
Short-term Debt [Line Items]	'	'
Spread on variable rate	0.50%	'
Daily LIBOR [Member]	'	'
Short-term Debt [Line Items]	'	'
Spread on variable rate	1.00%	'
Revolving Credit Facility [Member]	'	'
Short-term Debt [Line Items]	'	'
Credit facility, maximum borrowing capacity	$500	'
Credit facility, term	'5 years	'
Credit facility, interest rate	1.10%	1.20%
Minimum [Member]	'	'
Short-term Debt [Line Items]	'	'
Margins-for-interest ratio	1.1	'
Minimum [Member] \| LIBOR [Member]	'	'
Short-term Debt [Line Items]	'	'
Spread on variable rate	0.90%	'
Minimum [Member] \| Daily LIBOR [Member]	'	'
Short-term Debt [Line Items]	'	'
Spread on variable rate margin	0.00%	'
Maximum [Member]	'	'
Short-term Debt [Line Items]	'	'
Debt to capitalization ratio	0.85	'
Maximum [Member] \| LIBOR [Member]	'	'
Short-term Debt [Line Items]	'	'
Spread on variable rate	1.50%	'
Maximum [Member] \| Daily LIBOR [Member]	'	'
Short-term Debt [Line Items]	'	'
Spread on variable rate margin	0.50%	'

Employee_Benefits_Details

Employee Benefits (Details) (USD $)	12 Months Ended
Employee Benefits (Details) (USD $)	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Funded percentage	80.00%	'	'
Contributions	$2,900,000	$2,900,000	$2,700,000
Pension expense, inclusive of administrative fees	3,000,000	3,000,000	2,800,000
Matching contributions percentage	2.00%	2.00%	2.00%
Matching contributions	206,000	204,000	203,000
Companies contribution as percentage of total contributions made	5.00%	5.00%	5.00%
Multiple employer pension prepayment	7,700,000	'	'
Amortization of voluntary prepayment	$700,000	'	'
Regulatory asset amortization period	'P10Y	'	'
Minimum [Member]	'	'	'
Funded percentage	'	65.00%	'
Maximum [Member]	'	'	'
Funded percentage	'	80.00%	'

Other_Details

Other (Details) (USD $)	Dec. 31, 2013	Feb. 28, 2014
In Millions, unless otherwise specified	Dec. 31, 2013	Subsequent Event [Member]
Subsequent Event [Line Items]	'	'
Ancillary service receivable	$8.10	$2.40
Payment on ancillary service receivable	'	$5.70

Supplemental_Cash_Flows_Inform1

Supplemental Cash Flows Information (Details) (USD $)	12 Months Ended
In Millions, unless otherwise specified	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Supplemental Cash Flows Information [Abstract]	'	'	'
Cash paid for interest, net of amounts capitalized	$44.30	$45.40	$49

Commitments_And_Contingencies_

Commitments And Contingencies (Details) (USD $)	Dec. 31, 2013
In Millions, unless otherwise specified	Dec. 31, 2013
Commitments And Contingencies [Abstract]	'
Contingent liability for coverage, maximum	$31.10

Subsequent_Event_Details

Subsequent Event (Details) (Subsequent Event [Member])	0 Months Ended	1 Months Ended
Subsequent Event (Details) (Subsequent Event [Member])	Apr. 01, 2014	Jan. 31, 2014
Subsequent Event [Member]	'	'
Subsequent Event [Line Items]	'	'
Increase in total energy rate	11.80%	0.50%

Selected_Quarterly_Financial_D2

Selected Quarterly Financial Data (Details) (USD $)	3 Months Ended								12 Months Ended
In Thousands, unless otherwise specified	Dec. 31, 2013	Sep. 30, 2013	Jun. 30, 2013	Mar. 31, 2013	Dec. 31, 2012	Sep. 30, 2012	Jun. 30, 2012	Mar. 31, 2012	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Selected Quarterly Financial Data [Abstract]	'	'	'	'	'	'	'	'	'	'	'
Operating Revenue	$213,340	$220,393	$187,623	$220,713	$197,730	$224,244	$198,280	$222,427	$842,069	$842,681	$891,539
Operating Margin	11,148	14,010	13,130	14,302	14,546	16,386	13,848	14,365	52,590	59,145	62,590
Net Margin attributable to ODEC	$2,393	$2,448	$2,346	$2,386	$2,450	$2,475	$2,498	$2,516	$9,573	$9,939	$10,807