OLD DOMINION ELECTRIC COOPERATIVE - FORM 10-Q

Attached files

Attached files

OLD DOMINION ELECTRIC COOPERATIVE Reports

Also read

Table of Contents

Table of Contents

Table of Contents

Table of Contents

Table of Contents

Table of Contents

Table of Contents

Table of Contents

Table of Contents

Table of Contents

Table of Contents

Table of Contents

Table of Contents

Table of Contents

Table of Contents

Table of Contents

Table of Contents

Table of Contents

Table of Contents

Table of Contents

Table of Contents

Table of Contents

Table of Contents

file	filename
EXCEL - IDEA: XBRL DOCUMENT - OLD DOMINION ELECTRIC COOPERATIVE	Financial_Report.xls
EX-32.1 - SECTION 906 CEO CERTIFICATION - OLD DOMINION ELECTRIC COOPERATIVE	d390030dex321.htm
EX-32.2 - SECTION 906 CFO CERTIFICATION - OLD DOMINION ELECTRIC COOPERATIVE	d390030dex322.htm
EX-31.2 - SECTION 302 CFO CERTIFICATION - OLD DOMINION ELECTRIC COOPERATIVE	d390030dex312.htm
EX-31.1 - SECTION 302 CEO CERTIFICATION - OLD DOMINION ELECTRIC COOPERATIVE	d390030dex311.htm

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-Q

(Mark One)

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

For the quarterly period ended June 30, 2012

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

For the transition period from to

Commission file number 000-50039

OLD DOMINION ELECTRIC COOPERATIVE

(Exact name of registrant as specified in its charter)


VIRGINIA		23-7048405
(State or other jurisdiction of incorporation or organization)		(I.R.S. employer identification no.)

4201 Dominion Boulevard, Glen Allen, Virginia		23060
(Address of principal executive offices)		(Zip code)

(804) 747-0592

(Registrant’s telephone number, including area code)

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

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

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

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

The Registrant is a membership corporation and has no authorized or outstanding equity securities.

GLOSSARY OF TERMS

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


Abbreviation or Acronym		Definition

ACES		Alliance for Cooperative Energy Services Power Marketing, LLC
Clover		Clover Power Station
FERC		Federal Energy Regulatory Commission
GAAP		Accounting principles generally accepted in the United States
MW		Megawatt(s)
MWh		Megawatt hour(s)
North Anna		North Anna Nuclear Power Station
ODEC, We, Our		Old Dominion Electric Cooperative
PJM		PJM Interconnection, LLC
TEC		TEC Trading, Inc.
XBRL		Extensible Business Reporting Language

OLD DOMINION ELECTRIC COOPERATIVE

INDEX


		Page Number

PART I. Financial Information

Item 1.	Financial Statements

Condensed Consolidated Balance Sheets – June 30, 2012 (Unaudited) and December 31, 2011			4

Condensed Consolidated Statements of Revenues, Expenses, and Patronage Capital (Unaudited) – Three and Six months ended June 30, 2012 and 2011			5

Condensed Consolidated Statements of Cash Flows (Unaudited) – Six Months Ended June 30, 2012 and 2011			6

Notes to Condensed Consolidated Financial Statements			7

Item 2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations		12

Item 3.	Quantitative and Qualitative Disclosures About Market Risk		19

Item 4.	Controls and Procedures		19

PART II. Other Information

Item 1.	Legal Proceedings		20

Item 1A.	Risk Factors		20

Item 6.	Exhibits		21

OLD DOMINION ELECTRIC COOPERATIVE

PART 1. FINANCIAL INFORMATION

ITEM 1. FINANCIAL STATEMENTS

CONDENSED CONSOLIDATED BALANCE SHEETS


	June 30, 2012			December 31, 2011
	(in thousands)
	(unaudited)
ASSETS:
Electric Plant:
Property, plant, and equipment	$	1,643,769		$	1,638,938
Less accumulated depreciation		(717,363	)		(697,031	)

		926,406			941,907
Nuclear fuel, at amortized cost		25,859			22,838
Construction work in progress		51,794			48,160

Net Electric Plant		1,004,059			1,012,905

Investments:
Nuclear decommissioning trust		107,174			101,474
Lease deposits		93,061			91,718
Unrestricted investments and other		51,995			42,007

Total Investments		252,230			235,199

Current Assets:
Cash and cash equivalents		37,538			63,756
Accounts receivable		5,480			7,210
Accounts receivable – deposits		10,700			6,500
Accounts receivable – members		85,652			82,236
Fuel, materials, and supplies		62,225			53,771
Prepayments and other		2,116			3,187

Total Current Assets		203,711			216,660

Deferred Charges:
Regulatory assets		94,278			98,964
Other		10,116			10,252

Total Deferred Charges		104,394			109,216

Total Assets	$	1,564,394		$	1,573,980


CAPITALIZATION AND LIABILITIES:
Capitalization:
Patronage capital	$	355,499		$	350,485
Non-controlling interest		13,053			13,093

Total Patronage capital and Non-controlling interest		368,552			363,578
Long-term debt		766,128			766,128

Total Capitalization		1,134,680			1,129,706

Current Liabilities:
Long-term debt due within one year		28,292			28,292
Accounts payable		68,412			65,416
Accounts payable – members		48,132			81,224
Accrued expenses		6,482			4,863
Deferred energy		50,124			34,712

Total Current Liabilities		201,442			214,507

Deferred Credits and Other Liabilities:
Asset retirement obligations		74,999			73,141
Obligations under long-term leases		71,684			69,285
Regulatory liabilities		73,313			75,580
Other		8,276			11,761

Total Deferred Credits and Other Liabilities		228,272			229,767

Commitments and Contingencies		—			—

Total Capitalization and Liabilities	$	1,564,394		$	1,573,980

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

OLD DOMINION ELECTRIC COOPERATIVE

CONDENSED CONSOLIDATED STATEMENTS OF REVENUES,

EXPENSES, AND PATRONAGE CAPITAL (UNAUDITED)


	Three Months Ended June 30,						Six Months Ended June 30,
	2012			2011			2012			2011
	(in thousands)						(in thousands)
Operating Revenues	$	198,280		$	219,052		$	420,707		$	451,147

Operating Expenses:
Fuel		19,263			26,901			46,797			62,116
Purchased power		119,654			145,025			257,198			306,284
Deferred energy		5,989			(1,350	)		15,413			(12,912	)
Operations and maintenance		15,193			8,411			25,456			16,687
Administrative and general		9,863			9,920			18,988			19,950
Depreciation and amortization		10,468			10,369			20,844			20,700
Amortization of regulatory asset/(liability), net		973			1,127			1,717			2,211
Accretion of asset retirement obligations		940			885			1,858			1,770
Taxes, other than income taxes		2,089			2,191			4,223			4,418

Total Operating Expenses		184,432			203,479			392,494			421,224

Operating Margin		13,848			15,573			28,213			29,923
Other expense, net		(559	)		(487	)		(1,135	)		(981	)
Gain on investments, net		—			1,621			—			434
Investment income		1,319			1,428			2,331			2,813
Interest charges, net		(12,134	)		(15,101	)		(24,445	)		(26,796	)
Income taxes		5			5			10			10

Net Margin including Non-controlling interest		2,479			3,039			4,974			5,403
Non-controlling interest		19			16			40			40

Net Margin attributable to ODEC		2,498			3,055			5,014			5,443
Patronage Capital – Beginning of Period		353,001			342,066			350,485			339,678

Patronage Capital – End of Period	$	355,499		$	345,121		$	355,499		$	345,121

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

OLD DOMINION ELECTRIC COOPERATIVE

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS (UNAUDITED)


	Six Months Ended June 30,
	2012			2011
	(in thousands)
Operating Activities:
Net Margin including Non-controlling interest	$	4,974		$	5,403
Adjustments to reconcile net margin to net cash provided by operating activities:
Depreciation and amortization		20,844			20,700
Other non-cash charges		6,943			6,076
Amortization of lease obligations		2,399			2,240
Interest on lease deposits		(1,343	)		(1,311	)
Change in current assets		(13,269	)		28,081
Change in deferred energy		15,413			(12,912	)
Change in current liabilities		(28,477	)		(35,045	)
Change in regulatory assets and liabilities		(1,137	)		(3,578	)
Change in deferred charges and credits		(2,813	)		2,649

Net Cash Provided by Operating Activities		3,534			12,303


Financing Activities:
Issuance of long-term debt		—			350,000
Debt issuance costs		—			(2,342	)
Payment of long-term debt		—			(216,000	)
Draws on revolving credit facilities		—			52,257
Repayments on revolving credit facilities		—			(59,300	)

Net Cash Provided by Financing Activities		—			124,615


Investing Activities:
Purchases of held to maturity securities		(50,037	)		(65,661	)
Proceeds from held to maturity securities		41,000			56,607
Proceeds from sale of trading securities		—			418
Increase in other investments		(3,090	)		(2,560	)
Electric plant additions		(17,625	)		(19,201	)
Gain on investments, net		—			(434	)

Net Cash Used for Investing Activities		(29,752	)		(30,831	)

Net Change in Cash and Cash Equivalents		(26,218	)		106,087
Cash and Cash Equivalents – Beginning of Period		63,756			4,391

Cash and Cash Equivalents – End of Period	$	37,538		$	110,478

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

OLD DOMINION ELECTRIC COOPERATIVE

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

General

The accompanying unaudited condensed consolidated financial statements have been prepared in accordance with accounting principles generally accepted in the United States for interim financial information and with the instructions to Form 10-Q and Article 10 of Regulation S-X. In the opinion of management, the accompanying unaudited condensed consolidated financial statements contain all adjustments, which include only normal recurring adjustments, necessary for a fair statement of our consolidated financial position as of June 30, 2012, and our consolidated results of operations, and cash flows for the three and six months ended June 30, 2012 and 2011. The consolidated results of operations for the three and six months ended June 30, 2012, are not necessarily indicative of the results to be expected for the entire year. These financial statements should be read in conjunction with the financial statements and notes thereto included in our 2011 Annual Report on Form 10-K filed with the Securities and Exchange Commission.

The accompanying financial statements reflect the consolidated accounts of Old Dominion Electric Cooperative and TEC. We are a not-for-profit wholesale power supply cooperative, incorporated under the laws of the Commonwealth of Virginia in 1948. We have two classes of members. Our Class A members are eleven customer-owned electric distribution cooperatives engaged in the retail sale of power to member consumers located in Virginia, Delaware, and Maryland. Our sole Class B member is TEC, a taxable corporation owned by our member distribution cooperatives. Our board of directors is composed of two representatives from each of the member distribution cooperatives and one representative from TEC. In accordance with Consolidation Accounting, TEC is considered a variable interest entity for which we are the primary beneficiary. We have eliminated all intercompany balances and transactions in consolidation. The assets and liabilities and non-controlling interest of TEC are recorded at carrying value and the net consolidated assets were $13.1 million at June 30, 2012, and December 31, 2011. The income taxes reported on our Condensed Consolidated Statement 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 rates are set periodically by a formula that was accepted for filing by FERC, but are not regulated by the respective states’ public service commissions.

We comply with the Uniform System of Accounts as 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.

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

2.	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 June 30, 2012 and December 31, 2011:


	June 30, 2012		Quoted Prices in Active Markets for Identical Assets (Level 1)		Significant Other Observable Inputs (Level 2)		Significant Unobservable Inputs (Level 3)
	(in thousands)
Nuclear decommissioning trust ⁽¹⁾⁽²⁾	$	107,174	$	56,481	$	50,693	$	—
Unrestricted investments and other ⁽³⁾		113		113		—		—

Total Financial Assets	$	107,287	$	56,594	$	50,693	$	—


Derivatives – gas and power ⁽⁴⁾	$	2,205	$	950	$	1,255	$	—

Total Financial Liabilities	$	2,205	$	950	$	1,255	$	—


	December 31, 2011		Quoted Prices in Active Markets for Identical Assets (Level 1)		Significant Other Observable Inputs (Level 2)		Significant Unobservable Inputs (Level 3)
	(in thousands)
Nuclear decommissioning trust ⁽¹⁾⁽²⁾	$	101,474	$	54,781	$	46,693	$	—
Unrestricted investments and other⁽³⁾		91		91		—		—

Total Financial Assets	$	101,565	$	54,872	$	46,693	$	—


Derivatives – gas and power ⁽⁴⁾	$	5,170	$	888	$	4,282	$	—

Total Financial Liabilities	$	5,170	$	888	$	4,282	$	—

⁽¹⁾	For additional information about our nuclear decommissioning trust see Note 4 below.

⁽²⁾

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

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

⁽⁴⁾

Derivatives—gas and power represent natural gas futures contracts and purchased power contracts, which are recorded on our balance sheet in deferred credits and other liabilities—other. The level 2 derivatives—gas and power include gas and purchased power contracts valued by ACES. The gas contracts are indexed against NYMEX and the purchased power contracts are valued using observable market inputs for similar transactions. For additional information about our derivative financial instruments, see Notes 1 and 4 of the Notes to Consolidated Financial Statements in our 2011 Annual Report on Form 10-K.

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.

3.	Derivatives and Hedging:

We are exposed to market purchases of power and natural gas to meet the power supply needs of our member distribution cooperatives that are not met by our owned generation. To manage this exposure, we utilize derivative instruments. See Note 1 of the Notes to Consolidated Financial Statements in our 2011 Annual Report on Form 10-K.

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

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


Commodity	Unit of Measure	As of June 30, 2012 Quantity		As of December 31, 2011 Quantity
Natural gas	MMBTU		3,100,000		3,800,000
Purchased power	MWh		—		213,120

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


		Fair Value
	Balance Sheet Location	As of June 30, 2012		As of December 31, 2011
		(in thousands)
Derivatives in a liability position:

Natural gas futures contracts	Deferred credits and other liabilities – other	$	2,205	$	3,295
Purchased power contracts	Deferred credits and other liabilities – other		—		1,875

Total derivatives in a liability position		$	2,205	$	5,170

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

for the Three and Six Months Ended June 30, 2012 and 2011


Derivatives Accounted for Utilizing Regulatory Accounting	Amount of Gain (Loss) Recognized in Regulatory Asset/Liability as of June 30,						Location of Gain (Loss) Reclassified from Regulatory Asset/Liability into Income	Amount of Gain (Loss) Reclassified from Regulatory Asset/Liability into Income for the Three Months Ended June 30,						Amount of Gain (Loss) Reclassified from Regulatory Asset/Liability into Income for the Six Months Ended June 30,
	2012			2011				2012			2011			2012			2011
	(in thousands)							(in thousands)						(in thousands)
Natural gas futures contracts ⁽¹⁾	$	(6,775	)	$	(4,777	)	Fuel	$	(2,079	)	$	(249	)	$	(2,079	)	$	(3,553	)
Purchased power contracts		—			—		Purchased power		237			56			(2,736	)		539

Total	$	(6,775	)	$	(4,777	)		$	(1,842	)	$	(193	)	$	(4,815	)	$	(3,014	)

⁽¹⁾	As of June 30, 2012 and 2011, includes a regulatory asset of $4.6 million and $0.9 million, respectively, to be recognized in future periods as the result of the contracts being effectively settled.

Our hedging activities expose us to credit-related risks. We use hedging instruments, including forwards, futures, financial transmission rights, and options, to manage our power market price risks. Because we rely substantially on the use of hedging instruments, we are exposed to the risk that counterparties will default in performance of their obligations to us. Although we assess the creditworthiness of counterparties and other credit issues related to these purchases, and we may require our counterparties to post collateral with us, defaults may still occur. Defaults may take the form of failure to physically deliver the purchased energy or failure to pay. If this occurs, we may be forced to enter into alternative contractual arrangements or purchase energy in the forward, short-term or spot markets at then-current market prices that may be more or less than the prices previously agreed upon with the defaulting counterparty.

4.	Investments

Investments were as follows at June 30, 2012 and December 31, 2011:


Description	Designation	Cost		Gross Unrealized Gains		Gross Unrealized Losses			Fair Value		Carrying Value
		(in thousands)
June 30, 2012

Nuclear decommissioning trust ⁽¹⁾
Debt securities	Available for sale	$	43,202	$	3,584	$	—		$	46,786	$	46,786
Equity securities	Available for sale		53,207		10,136		(2,997	)		60,346		60,346
Cash and other	Available for sale		42		—		—			42		42

Total Nuclear Decommissioning Trust		$	96,451	$	13,720	$	(2,997	)	$	107,174	$	107,174


Lease deposits ⁽²⁾
Government obligations	Held to maturity	$	93,061	$	11,230	$	—		$	104,291	$	93,061

Total Lease Deposits		$	93,061	$	11,230	$	—		$	104,291	$	93,061


Unrestricted investments
Government obligations	Held to maturity	$	50,074	$	—	$	(8	)	$	50,066	$	50,074

Total Unrestricted Investments		$	50,074	$	—	$	(8	)	$	50,066	$	50,074

Other
Equity securities	Available for sale	$	111	$	2	$	—		$	113	$	113
Non-marketable equity investments ⁽³⁾	Equity		1,808		—		—			1,808		1,808

Total Other		$	1,919	$	2	$	—		$	1,921	$	1,921

							Total Carrying Value				$	252,230

December 31, 2011

Nuclear decommissioning trust ⁽¹⁾
Debt securities	Available for sale	$	42,528	$	2,475	$	—		$	45,003	$	45,003
Equity securities	Available for sale		51,654		7,689		(2,997	)		56,346		56,346
Cash and other	Available for sale		125		—		—			125		125

Total Nuclear Decommissioning Trust		$	94,307	$	10,164	$	(2,997	)	$	101,474	$	101,474


Lease deposits ⁽²⁾
Government obligations	Held to maturity	$	91,718	$	9,862	$	—		$	101,580	$	91,718

Total Lease Deposits		$	91,718	$	9,862	$	—		$	101,580	$	91,718


Unrestricted investments
Government obligations	Held to maturity	$	40,111	$	5	$	—		$	40,116	$	40,111

Total Unrestricted Investments		$	40,111	$	5	$	—		$	40,116	$	40,111

Other
Equity securities	Available for sale	$	96	$	—	$	(5	)	$	91	$	91
Non-marketable equity investments ⁽³⁾	Equity		1,805		—		—			1,805		1,805

Total Other		$	1,901	$	—	$	(5	)	$	1,896	$	1,896

							Total Carrying Value				$	235,199

⁽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 of the Notes to Consolidated Financial Statements in our 2011 Annual Report on Form 10-K. Realized and unrealized gains and losses related to assets held in the nuclear decommissioning trust are deferred as a regulatory asset or liability.

⁽²⁾	Investments in lease deposits are restricted for the use of funding our future lease obligations. See Note 8 of the Notes to Consolidated Financial Statements in our 2011 Annual Report on Form 10-K.

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

Our investments by classification at June 30, 2012 and December 31, 2011, were as follows:


	June 30, 2012				December 31, 2011
Description	Cost		Carrying Value		Cost		Carrying Value
	(in thousands)
Available for sale	$	96,562	$	107,287	$	94,403	$	101,565
Held to maturity		143,135		143,135		131,829		131,829
Equity		1,808		1,808		1,805		1,805

	$	241,505	$	252,230	$	228,037	$	235,199

Contractual maturities of unrestricted debt securities at June 30, 2012, were as follows:


Description	Less than 1 year		1-5 years		5-10 years		More than 10 years		Total
	(in thousands)
Available for sale	$	—	$	—	$	—	$	—	$	—
Held to maturity		50,074		—		—		—		50,074

	$	50,074	$	—	$	—	$	—	$	50,074

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

OLD DOMINION ELECTRIC COOPERATIVE

ITEM 2. MANAGEMENT’S DISCUSSION AND ANALYSIS

OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS

Caution Regarding Forward-Looking Statements

Management’s Discussion and Analysis of Financial Condition and Results of Operations contains forward looking statements regarding matters that could have an impact on our business, financial condition, and future operations. These statements, based on our expectations and estimates, are not guarantees of future performance and are subject to risks, uncertainties, and other factors that could cause actual results to differ materially from those expressed in the forward looking statements. These risks, uncertainties, and other factors include, but are not limited to, general business conditions, demand for energy, federal and state legislative and regulatory actions and legal and administrative proceedings, changes in and compliance with environmental laws and policies, general credit and capital market conditions, weather conditions, the cost of commodities used in our industry, and unanticipated changes in operating expenses and capital expenditures. Our actual results may vary materially from those discussed in the forward looking statements as a result of these and other factors. Any forward looking statement speaks only as of the date on which the statement is made, and we undertake no obligation to update any forward looking statement or statements to reflect events or circumstances after the date on which the statement is made even if new information becomes available or other events occur in the future.

Critical Accounting Policies

As of June 30, 2012, there have been no significant changes in our critical accounting policies as disclosed in our 2011 Annual Report on Form 10-K. These policies include the accounting for rate regulation, deferred energy, margin stabilization plan, accounting for asset retirement obligations, and accounting for derivative contracts.

Basis of Presentation

The accompanying financial statements reflect the consolidated accounts of Old Dominion Electric Cooperative and TEC. See Note 1—Notes to Condensed Consolidated Financial Statements in Part 1, Item 1.

Overview

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

Weather affects the demand for electricity. We experienced milder weather during the three and six months ended June 30, 2012, as compared to the same periods in 2011, which resulted in a reduction in our member distribution cooperatives’ customers’ requirements for power.

Fuel and purchased power expenses are affected by market pricing, the output provided by our owned generation, and our member distribution cooperatives’ customers’ requirements for power. Fuel expense decreased for the three months ended June 30, 2012, as compared to the same period in 2011, primarily as a result of maintenance outages at Clover. Fuel expense also decreased for the six months ended June 30, 2012, as compared to the same period in 2011. The decrease was the result of a decrease in the average cost of fuel for our combustion turbine facilities, decreased economic dispatch of our combustion turbine facilities, and the maintenance outages at Clover. Purchased power expense decreased for the three and six months ended June 30, 2012, as compared to the same periods in 2011 due to a decrease in the average cost of purchased power and the decrease in our member distribution cooperatives’ customers’ requirements for power.

Deferred energy expense represents the difference between energy revenues and energy expenses. In the three and six months ended June 30, 2012, we over-collected energy costs from our member distribution cooperatives as compared to the same periods in 2011 when we under-collected energy costs. Over-collected energy costs appear as a liability on our Condensed Consolidated Balance Sheet and will be refunded to our member distribution cooperatives in subsequent periods through our formulary rate. For further discussion on deferred energy, see Item 7 Management’s Discussion and Analysis of Financial Condition and Results of Operations—Critical Accounting Policies—Deferred Energy in our 2011 Annual Report on Form 10-K.

Operations and maintenance expense is affected by scheduled and unscheduled outages at our generating facilities. During the three and six months ended June 30, 2012, both units at Clover experienced scheduled and unscheduled outages and North Anna Unit 1 experienced scheduled and unscheduled outages. The unscheduled outages at both facilities were primarily due to extensions of original scheduled outages to address additional maintenance items.

We have a Margin Stabilization Plan that allows us to review our actual capacity-related costs of service and capacity revenue and adjust revenues from our member distribution cooperatives to meet our financial coverage requirements and accumulate additional equity as approved by our board of directors. In accordance with our Margin Stabilization Plan, as of June 30, 2012, we had $6.9 million recorded as accounts payable—members as compared to $4.9 million as of December 31, 2011. For further discussion on our margin stabilization plan, see Item 7 Management’s Discussion and Analysis of Financial Condition and Results of Operations—Critical Accounting Policies—Margin Stabilization Plan in our 2011 Annual Report on Form 10-K.

Factors Affecting Results

Formulary Rate

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

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

•

all of our costs and expenses;

•

20% of our total interest charges; and

•

additional equity contributions approved by our board of directors.

The formulary rate has three main components: a demand rate, a base energy rate and an energy adjustment rate. The formulary rate identifies the cost components that we can collect through rates, but not the actual amounts to be collected. With limited minor exceptions, we can change our rates periodically to match the costs we have incurred and we expect to incur without seeking FERC approval. For further discussion on our formulary rate, see Item 7 Management’s Discussion and Analysis of Financial Condition and Results of Operations—Factors Affecting Results—Formulary Rate in our 2011 Annual Report on Form 10-K.

Power Supply Resources

We provide power to our members through a combination of our interests in Clover, a coal-fired generating facility; North Anna, a nuclear generating facility; our three combustion turbine facilities—Louisa, Marsh Run, and Rock Springs; distributed generation facilities; and physically-delivered forward power purchase contracts and spot purchases of energy in the open market. Our power supply resources for the three and six months ended June 30, 2012 and 2011 were as follows:


	Three Months Ended June 30,								Six Months Ended June 30,
	2012				2011				2012				2011
	(in MWh and percentages)								(in MWh and percentages)
Generated:
Clover		373,838	13.4	%		600,728	18.6	%		1,081,149	17.8	%		1,389,603	20.4	%
North Anna		402,941	14.4			478,994	14.8			829,059	13.7			954,308	14.0
Louisa		18,473	0.7			34,928	1.1			31,946	0.5			46,349	0.7
Marsh Run		30,819	1.1			37,137	1.2			61,510	1.0			63,750	0.9
Rock Springs		18,574	0.7			30,216	0.9			18,574	0.3			30,216	0.4
Distributed Generation		170	—			209	—			173	—			211	—

Total Generated		844,815	30.3			1,182,212	36.6			2,022,411	33.3			2,484,437	36.4

Purchased:
Other than renewable		1,848,678	66.3			1,949,294	60.3			3,805,900	62.6			4,096,573	60.1
Renewable ⁽¹⁾		96,340	3.4			100,606	3.1			248,682	4.1			239,150	3.5

Total Purchased		1,945,018	69.7			2,049,900	63.4			4,054,582	66.7			4,335,723	63.6

Total Available Energy		2,789,833	100.0	%		3,232,112	100.0	%		6,076,993	100.0	%		6,820,160	100.0	%

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

Generating Facilities

Our operating expenses, and consequently our rates to our member distribution cooperatives, are significantly affected by the operations of our baseload generating facilities, Clover and North Anna. Baseload generating facilities, particularly nuclear power plants such as North Anna, generally have relatively high fixed costs. Nuclear facilities operate with relatively low variable costs due to lower fuel costs and technological efficiencies. In addition, coal-fired facilities have relatively low variable costs, as compared to combustion turbine facilities such as Louisa, Marsh Run, and Rock Springs. Our combustion turbine facilities have relatively low fixed costs and greater operational flexibility; however, they are more expensive to operate and, as a result, are dispatched only when the market price of energy makes their operation economical or when their operation is required by PJM for system reliability purposes. For further discussion on PJM, see Item 1 Business—Power Supply Resources—PJM in our 2011 Annual Report on Form 10-K. Owners of power plants incur the fixed costs of these facilities whether or not the units operate.

Our generating facilities are under dispatch control of PJM. Typically, nuclear facilities are almost always dispatched, and coal-fired and combustion turbine facilities are dispatched based upon economic factors including the market price of energy. The operational availability of Clover for the three and six months ended June 30, 2012 and 2011, was as follows:


	Clover
	Three Months Ended June 30,						Six Months Ended June 30,
	2012			2011			2012			2011
Unit 1		27.0	%		90.1	%		62.4	%		95.0	%
Unit 2		84.9			87.6			92.0			91.9
Combined		56.0			88.8			77.2			93.5

The output of Clover and North Anna for the three and six months ended June 30, 2012 and 2011, as a percentage of the maximum dependable capacity rating of the facilities, was as follows:


	Clover												North Anna
	Three Months Ended June 30,						Six Months Ended June 30,						Three Months Ended June 30,						Six Months Ended June 30,
	2012			2011			2012			2011			2012			2011			2012			2011
Unit 1		19.4	%		64.6	%		46.8	%		75.3	%		66.1	%		101.2	%		71.6	%		101.4	%
Unit 2		61.1			63.8			68.5			73.0			102.6			102.2			103.1			102.6
Combined		40.2			64.2			57.7			74.2			84.3			101.7			87.5			102.0

The scheduled maintenance outages and unscheduled outages for Clover for the three and six months ended June 30, 2012 and 2011, were as follows:


	Scheduled Outages								Unscheduled Outages
	Three Months Ended June 30,				Six Months Ended June 30,				Three Months Ended June 30,				Six Months Ended June 30,
	2012		2011		2012		2011		2012		2011		2012		2011
	(in days)				(in days)				(in days)				(in days)
Unit 1		53.0		7.9		54.0		7.9		13.4		1.1		15.4		1.1
Unit 2		8.0		8.1		8.0		8.1		5.7		3.1		6.6		6.5

Combined		61.0		16.0		62.0		16.0		19.1		4.2		22.0		7.6

The scheduled maintenance and refueling outages and unscheduled outages for North Anna for the three and six months ended June 30, 2012 and 2011, were as follows:


	Scheduled Outages								Unscheduled Outages
	Three Months Ended June 30,				Six Months Ended June 30,				Three Months Ended June 30,				Six Months Ended June 30,
	2012		2011		2012		2011		2012		2011		2012		2011
	(in days)				(in days)				(in days)				(in days)
Unit 1		15.0		—		36.0		—		15.2		—		15.9		—
Unit 2		—		—		—		—		—		—		—		—

Combined		15.0		—		36.0		—		15.2		—		15.9		—

During the three and six months ended June 30, 2012 and 2011, the operational availability of our Louisa, Marsh Run, and Rock Springs combustion turbine facilities was as follows:


	Three Months Ended June 30,						Six Months Ended June 30,
	2012			2011			2012			2011
Louisa		99.4	%		98.5	%		99.4	%		98.3	%
Marsh Run		99.8			99.5			99.8			97.8
Rock Springs		99.8			96.8			94.4			98.4

Sales to Member Distribution Cooperatives

Revenues from sales to our member distribution cooperatives are a function of our formulary rate for sales of power to our member distribution cooperatives and our member distribution cooperatives’ consumers’ requirements for power. Our formulary rate is based on our cost of service in meeting these requirements. See “Factors Affecting Results—Formulary Rate” above.

Sales to TEC

In accordance with Consolidation Accounting, TEC is considered a variable interest entity for which ODEC is the primary beneficiary. The financial statements of TEC are consolidated and the inter-company balances are eliminated in consolidation. TEC’s sales to third parties are reflected as non-member revenues. In 2012 and 2011, TEC had no sales to third parties.

Sales to Non-members

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

Results of Operations

Operating Revenues

Our operating revenues are derived from power sales to our member distribution cooperatives and non-members. Our operating revenues by type of purchaser for the three and six months ended June 30, 2012 and 2011, were as follows:


	Three Months Ended June 30,				Six Months Ended June 30,
	2012		2011		2012		2011
	(in thousands)				(in thousands)
Revenues from sales to:
Member distribution cooperatives
Base energy revenues	$	46,573	$	48,379	$	100,022	$	107,769
Energy adjustment revenues		70,936		72,689		158,731		160,259

Total energy revenues		117,509		121,068		258,753		268,028
Demand (capacity) revenues		77,865		79,937		153,655		158,908

Total revenues from sales to member distribution cooperatives		195,374		201,005		412,408		426,936
Non-members		2,906		18,047		8,299		24,211

Total operating revenues	$	198,280	$	219,052	$	420,707	$	451,147


Average cost to member distribution cooperatives (per MWh)	$	72.72	$	73.00	$	71.56	$	69.95

Our energy sales in MWh to our member distribution cooperatives and non-members, and demand sales in MW to our member distribution cooperatives for the three and six months ended June 30, 2012 and 2011, were as follows:


	Three Months Ended June 30,				Six Months Ended June 30,
	2012		2011		2012		2011
	(in MWh)				(in MWh)
Energy sales to:
Member distribution cooperatives		2,686,657		2,753,493		5,762,923		6,103,575
Non-members		96,392		418,763		283,491		594,664

Total energy sales		2,783,049		3,172,256		6,046,414		6,698,239


	(in MW)				(in MW)
Demand sales to Member distribution cooperatives		5,638		5,787		12,088		12,429

Our energy sales in MWh to our member distribution cooperatives for the three and six months ended June 30, 2012, were 2.4% and 5.6% lower, respectively, as compared to the same periods in 2011. Our demand sales in MW to our member distribution cooperatives for the three and six months ended June 30, 2012, were 2.6% and 2.7% lower, respectively, as compared to the same periods in 2011. These decreases were primarily a result of milder weather in 2012 as compared to 2011.

Our energy sales in MWh to non-members for the three and six months ended June 30, 2012 were 77.0% and 52.3% lower, respectively, as compared to the same periods in 2011. Sales to non-members consist of sales of excess purchased and generated energy.

Total revenues from sales to our member distribution cooperatives for the three and six months ended June 30, 2012, decreased $5.6 million, or 2.8%, and $14.5 million, or 3.4%, respectively, as compared to the same periods in 2011. The decrease in total revenues for the three months ended June 30, 2012, is primarily related to the 2.4% decrease in our energy sales volume. The decrease in total revenues for the six months ended June 30, 2012, is primarily related to the 5.6% decrease in our energy sales volume, partially offset by a 2.2% increase in our total energy rate (our total energy rate includes our base energy rate and our energy rate). Additionally, the capacity costs we incurred, and thus the capacity-related revenues we reflected, for the three and six months ended June 30, 2012, were 2.6% and 3.3% lower, respectively, as compared to the same periods in 2011, primarily due to a decrease in the cost of purchased capacity.

Our average cost per MWh to member distribution cooperatives for the three months ended June 30, 2012, was relatively flat and for the six months ended June 30, 2012, increased $1.61 per MWh, or 2.3%, as compared to the same periods in 2011. The increase for the six months ended June 30, 2012, was primarily due to the 2.2% increase in our total energy rate, and an increase in the average cost of demand (capacity) on a per MWh basis. Our capacity-related revenues for the six months ended June 30, 2012, decreased 3.3%, while our MWh volume decreased 5.6%, resulting in a higher average cost of demand on a per MWh basis, as compared to the same period in 2011.

Non-member revenue decreased $15.1 million, or 83.9%, and $15.9 million, or 65.7%, for the three and six months ended June 30, 2012, respectively, as compared to the same periods in 2011 due to the 77.0% and 52.3% decrease in the volume of excess energy sales, respectively, and a decrease in the average price.

Operating Expenses

The following is a summary of the components of our operating expenses for the three and six months ended June 30, 2012 and 2011:


	Three Months Ended June 30,					Six Months Ended June 30,
	2012		2011			2012		2011
	(in thousands)					(in thousands)
Fuel	$	19,263	$	26,901		$	46,797	$	62,116
Purchased power		119,654		145,025			257,198		306,284
Deferred energy		5,989		(1,350	)		15,413		(12,912	)
Operations and maintenance		15,193		8,411			25,456		16,687
Administrative and general		9,863		9,920			18,988		19,950
Depreciation and amortization		10,468		10,369			20,844		20,700
Amortization of regulatory asset/(liability), net		973		1,127			1,717		2,211
Accretion of asset retirement obligations		940		885			1,858		1,770
Taxes other than income taxes		2,089		2,191			4,223		4,418

Total Operating Expenses	$	184,432	$	203,479		$	392,494	$	421,224

Our operating expenses are comprised of the costs that we incur to generate and purchase power to meet the needs of our member distribution cooperatives, and the costs associated with any sales of power to non-members. Our energy costs generally are variable and include fuel expense as well as the energy portion of our purchased power expense. Our capacity or demand costs generally are fixed and include administrative and general, and depreciation and amortization expenses, as well as the capacity portion of our purchased power expense. Additionally, all non-operating expenses and income items, including interest charges, net and investment income, are components of our capacity costs. See “Factors Affecting Results—Formulary Rate.”

Total operating expenses decreased $19.0 million, or 9.4%, and $28.7 million, or 6.8%, for the three and six months ended June 30, 2012, respectively, as compared to the same periods in 2011, primarily due to decreases in purchased power and fuel expenses partially offset by increases in deferred energy and operations and maintenance expenses.

•

Purchased power expense, which includes the cost of purchased energy, capacity, and transmission, decreased $25.4 million, or 17.5%, and $49.1 million, or 16.0%, for the three and six months ended June 30, 2012, respectively. The average cost of purchased power was 13.0% and 10.2% lower for the three and six months ended June 30, 2012, respectively, as compared to the same periods in 2011. Additionally, the volume of purchased power decreased 5.1% and 6.5% for the three and six months ended June 30, 2012, respectively, as compared to the same periods in 2011, primarily due to milder weather.

•

Fuel expense decreased $7.6 million, or 28.4%, and $15.3 million, or 24.7%, for the three and six months ended June 30, 2012, respectively, as compared to the same periods in 2011. The decrease for the three months was primarily a result of the maintenance outages at Clover. The decrease for the six months was the result of a decrease in the average cost of fuel for our combustion turbine facilities, decreased economic dispatch of our combustion turbine facilities by PJM, and the maintenance outages at Clover.

•

Deferred energy expense increased $7.3 million and $28.3 million for the three and six months ended June 30, 2012, respectively, as compared to the same periods in 2011. For the three and six months ended June 30, 2012, we over-collected $6.0 million and $15.4 million, respectively, in energy costs; whereas for the same periods in 2011, we under-collected $1.4 million and $12.9 million, respectively, in energy costs. Our deferred energy balance was a net over-collection of energy costs of $34.7 million at December 31, 2011, as compared to a net over-collection of energy costs of $50.1 million at June 30, 2012.

•

Operations and maintenance expense increased $6.8 million, or 80.6%, and $8.8 million, or 52.5%, due to scheduled and unscheduled maintenance outages at Clover and North Anna during the three and six months ended June 30, 2012, as compared to the same periods in 2011.

Other Items

Investment Income

Investment income decreased for the three and six months ended June 30, 2012, by $0.1 million, or 7.6%, and $0.5 million, or 17.1%, respectively, primarily due to lower income earned on our nuclear decommissioning trust in 2012 as compared to 2011.

Interest Charges, Net

The primary factors affecting our interest charges, net are issuances of indebtedness, scheduled payments of principal on our indebtedness, interest charges related to our credit facilities, and capitalized interest. The major components of interest charges, net for the three and six months ended June 30, 2012 and 2011, were as follows:


	Three Months Ended June 30,						Six Months Ended June 30,
	2012			2011			2012			2011
	(in thousands)						(in thousands)
Interest expense on long-term debt	$	(12,151	)	$	(14,525	)	$	(24,292	)	$	(25,773	)
Other		(330	)		(750	)		(766	)		(1,442	)

Total Interest Charges		(12,481	)		(15,275	)		(25,058	)		(27,215	)
Allowance for borrowed funds used during construction		347			174			613			419

Interest Charges, net	$	(12,134	)	$	(15,101	)	$	(24,445	)	$	(26,796	)

Interest expense on long-term debt decreased $2.4 million, or 16.3%, and $1.5 million, or 5.7%, for the three and six months ended June 30, 2012, respectively, as compared to the same periods in 2011. We issued $350.0 million of debt in April 2011 and repaid $215.0 million of maturing debt in June 2011, resulting in additional interest expense on long-term debt for the three and six months ended June 30, 2011.

Net Margin Attributable to ODEC

Net margin attributable to ODEC, which is a function of our total interest charges plus any additional equity contributions approved by our board of directors, decreased $0.6 million, or 18.2%, and $0.4 million, or 7.9%, for the three and six months ended June 30, 2012, respectively, as compared to the same periods in 2011 due to lower total interest charges.

Financial Condition

The principal changes in our financial condition from December 31, 2011 to June 30, 2012, were caused by the decrease in accounts payable—members, substantially offset by increases in deferred energy, unrestricted investments and other, and fuel, materials, and supplies.

•

Accounts payable—members decreased $33.1 million due to the $35.1 million decrease in member prepayments and the $2.0 million increase in the margin stabilization adjustment as compared to December 2011.

•

Deferred energy increased $15.4 million as a result of the over-collection of our energy costs in 2012.

•

Unrestricted investments and other increased $10.0 million as a result of the investment of excess working capital.

•

Fuel, materials, and supplies increased $8.5 million primarily as a result of increased coal supply at Clover.

Liquidity and Capital Resources

Sources

Cash generated by our operations, periodic borrowings under our credit facilities, and occasional issuances of long-term indebtedness provide our sources of liquidity and capital.

Operations

During the first six months of 2012 and 2011 our operating activities provided cash flows of $3.5 million and $12.3 million, respectively. Operating activities in 2012 were primarily impacted by the following:

•

Current liabilities changed $28.5 million primarily due to the $33.1 million decrease in accounts payable—members partially offset by the $3.0 million increase in accounts payable and the $1.6 million increase in accrued expenses.

•

Deferred energy changed $15.4 million due to the over-collection of energy costs in 2012.

•

Current assets changed $13.3 million primarily due to the $8.5 million increase in fuel, materials, and supplies, the $4.2 million increase in accounts receivable—deposits and the $3.4 million increase in accounts receivable—members.

Credit Facilities

In addition to liquidity from our operating activities, we currently maintain a $500.0 million, five-year revolving credit facility to cover our short-term and medium-term funding needs. At June 30, 2012 and December 31, 2011, we did not have any borrowings outstanding under this facility.

Financings

We fund the portion of our capital expenditures that we are not able to supply from operations through financings in the debt capital markets. These capital expenditures consist primarily of the costs related to the development, construction, acquisition, or improvement of our owned generating facilities.

Uses

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

ITEM 3. QUANTITATIVE AND QUALITATIVE

DISCLOSURES ABOUT MARKET RISK

No material changes occurred in our exposure to market risk during the second quarter of 2012.

ITEM 4. CONTROLS AND PROCEDURES

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

OLD DOMINION ELECTRIC COOPERATIVE

PART II. OTHER INFORMATION

ITEM 1. LEGAL PROCEEDINGS

Other Matters

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

ITEM 1A. RISK FACTORS

In addition to the other information set forth in this report, you should carefully consider the factors discussed in “Risk Factors” in Part I, Item 1A of our 2011 Annual Report on Form 10-K, which could affect our business, financial condition or future results. The risks described in our Annual Report on Form 10-K are not the only risks facing us. Additional risks and uncertainties not currently known to us or that we currently deem to be immaterial also may materially adversely affect our business, financial condition and/or operating results.

ITEM 6.

EXHIBITS


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

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

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

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

101.INS*		XBRL Instance Document

101.SCH*		XBRL Taxonomy Extension Schema Document

101.CAL*		XBRL Taxonomy Extension Calculation Linkbase Document

101.LAB*		XBRL Taxonomy Extension Label Linkbase Document

101.PRE*		XBRL Taxonomy Extension Presentation Linkbase Document

XBRL information is furnished and not filed or part of a registration statement or prospectus for purposes of Sections 11 or 12 of the Securities Act of 1933, is deemed not filed for purposes of Section 18 of the Securities Exchange Act of 1934, and otherwise is not subject to liability under these sections.

SIGNATURE

Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized.


				OLD DOMINION ELECTRIC COOPERATIVE
				Registrant

Date: August 8, 2012				/s/ Robert L. Kees
				Robert L. Kees
				Senior Vice President and Chief Financial Officer
				(Principal financial officer)

EXHIBIT INDEX


Exhibit Number		Description of Exhibit

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

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

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

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

101.INS*		XBRL Instance Document

101.SCH*		XBRL Taxonomy Extension Schema Document

101.CAL*		XBRL Taxonomy Extension Calculation Linkbase Document

101.LAB*		XBRL Taxonomy Extension Label Linkbase Document

101.PRE*		XBRL Taxonomy Extension Presentation Linkbase Document

Larger accelerated filer

Accelerated filer

Non-accelerated filer

Smaller reporting company