Old Dominion Electric Cooperative 10-Q 2012 Q3 Quarterly report

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 September 30, 2012

or

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

For the transition period from             to             

Commission file number 000-50039

OLD DOMINION ELECTRIC COOPERATIVE

(Exact name of registrant as specified in its charter)

VIRGINIA	23-7048405
(State or other jurisdiction of incorporation or organization)	(I.R.S. employer identification no.)
4201 Dominion Boulevard, Glen Allen, Virginia	23060
(Address of principal executive offices)	(Zip code)

(804) 747-0592

(Registrant’s telephone number, including area code)

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.

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

Indicate by check mark whether the registrant is a shell company (as defined in 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
DOE	Department of Energy
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.
Virginia Power	Virginia Electric and Power Company
XBRL	Extensible Business Reporting Language

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OLD DOMINION ELECTRIC COOPERATIVE

INDEX

	Page Number
PART I. Financial Information
Item 1. Financial Statements
Condensed Consolidated Balance Sheets – September 30, 2012 (Unaudited) and December 31, 2011		4
Condensed Consolidated Statements of Revenues, Expenses, and Patronage Capital (Unaudited) – Three and Nine months ended September 30, 2012 and 2011		5
Condensed Consolidated Statements of Cash Flows (Unaudited) – Nine Months Ended September 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		13
Item 3. Quantitative and Qualitative Disclosures About Market Risk		21
Item 4. Controls and Procedures		21
PART II. Other Information
Item 1. Legal Proceedings		23
Item 1A. Risk Factors		23
Item 6. Exhibits		24

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OLD DOMINION ELECTRIC COOPERATIVE

PART 1. FINANCIAL INFORMATION

ITEM  1. FINANCIAL STATEMENTS

CONDENSED CONSOLIDATED BALANCE SHEETS

	September 30, 2012			December 31, 2011
	(in thousands)
	(unaudited)
ASSETS:
Electric Plant:
Property, plant, and equipment	$	1,648,469		$	1,638,938
Less accumulated depreciation		(720,245	)		(697,031	)
		928,224			941,907
Nuclear fuel, at amortized cost		23,191			22,838
Construction work in progress		40,282			48,160
Net Electric Plant		991,697			1,012,905
Investments:
Nuclear decommissioning trust		112,462			101,474
Lease deposits		93,459			91,718
Unrestricted investments and other		52,962			42,007
Total Investments		258,883			235,199
Current Assets:
Cash and cash equivalents		83,945			63,756
Accounts receivable		8,388			7,210
Accounts receivable - deposits		4,600			6,500
Accounts receivable - members		79,373			82,236
Fuel, materials, and supplies		63,100			53,771
Prepayments and other		1,602			3,187
Total Current Assets		241,008			216,660
Deferred Charges:
Regulatory assets		88,210			98,964
Other		9,097			10,252
Total Deferred Charges		97,307			109,216
Total Assets	$	1,588,895		$	1,573,980
CAPITALIZATION AND LIABILITIES:
Capitalization:
Patronage capital	$	357,974		$	350,485
Non-controlling interest		13,037			13,093
Total Patronage capital and Non-controlling interest		371,011			363,578
Long-term debt		766,128			766,128
Total Capitalization		1,137,139			1,129,706
Current Liabilities:
Long-term debt due within one year		28,292			28,292
Accounts payable		60,341			65,416
Accounts payable - members		54,615			81,224
Accrued expenses		19,731			4,863
Deferred energy		59,080			34,712
Total Current Liabilities		222,059			214,507
Deferred Credits and Other Liabilities:
Asset retirement obligations		75,940			73,141
Obligations under long-term leases		72,885			69,285
Regulatory liabilities		74,618			75,580
Other		6,254			11,761
Total Deferred Credits and Other Liabilities		229,697			229,767
Commitments and Contingencies		—			—
Total Capitalization and Liabilities	$	1,588,895		$	1,573,980

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

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OLD DOMINION ELECTRIC COOPERATIVE

CONDENSED CONSOLIDATED STATEMENTS OF REVENUES,

EXPENSES, AND PATRONAGE CAPITAL (UNAUDITED)

	Three Months Ended September 30,						Nine Months Ended September 30,
	2012			2011			2012			2011
	(in thousands)						(in thousands)
Operating Revenues	$	224,244		$	229,909		$	644,951		$	681,056
Operating Expenses:
Fuel		23,608			28,573			70,405			90,689
Purchased power		145,235			149,258			402,433			455,542
Deferred energy		8,955			28			24,368			(12,884	)
Operations and maintenance		8,677			12,305			34,133			28,992
Administrative and general		9,356			9,142			28,344			29,092
Depreciation and amortization		10,568			10,382			31,412			31,082
Amortization of regulatory asset/(liability), net		(1,601	)		819			116			3,030
Accretion of asset retirement obligations		941			886			2,799			2,656
Taxes, other than income taxes		2,119			1,917			6,342			6,335
Total Operating Expenses		207,858			213,310			600,352			634,534
Operating Margin		16,386			16,599			44,599			46,522
Other expense, net		(514	)		(477	)		(1,649	)		(1,458	)
Loss on investments, net		(2,156	)		(1,388	)		(2,156	)		(954	)
Investment income		872			1,060			3,203			3,873
Interest charges, net		(12,133	)		(13,132	)		(36,578	)		(39,928	)
Income taxes		4			2			14			12
Net Margin including Non-controlling interest		2,459			2,664			7,433			8,067
Non-controlling interest		16			6			56			46
Net Margin attributable to ODEC		2,475			2,670			7,489			8,113
Patronage Capital - Beginning of Period		355,499			345,121			350,485			339,678
Patronage Capital - End of Period	$	357,974		$	347,791		$	357,974		$	347,791

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

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OLD DOMINION ELECTRIC COOPERATIVE

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS (UNAUDITED)

	Nine Months Ended September 30,
	2012			2011
	(in thousands)
Operating Activities:
Net Margin including Non-controlling interest	$	7,433		$	8,067
Adjustments to reconcile net margin to net cash provided by operating activities:
Depreciation and amortization		31,412			31,082
Other non-cash charges		10,711			8,282
Amortization of lease obligations		3,600			3,363
Interest on lease deposits		(2,024	)		(1,977	)
Change in current assets		(4,159	)		37,670
Change in deferred energy		24,368			(12,884	)
Change in current liabilities		(16,816	)		(25,332	)
Change in regulatory assets and liabilities		1,698			(4,070	)
Change in deferred charges and credits		(3,553	)		3,734
Net Cash Provided by Operating Activities		52,670			47,935
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		(51,037	)		(108,121	)
Proceeds from sale of held to maturity securities		41,000			99,221
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		(3,532	)		(3,287	)
Electric plant additions		(18,930	)		(27,295	)
Loss on investments, net		—			954
Net Cash Used for Investing Activities		(32,481	)		(27,439	)
Net Change in Cash and Cash Equivalents		20,189			145,111
Cash and Cash Equivalents - Beginning of Period		63,756			4,391
Cash and Cash Equivalents - End of Period	$	83,945		$	149,502

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

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OLD DOMINION ELECTRIC COOPERATIVE

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

1. 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 September 30, 2012, and our consolidated results of operations, and cash flows for the three and nine months ended September 30, 2012 and 2011. The consolidated results of operations for the three and nine months ended September 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 $13.0 million and $13.1 million at September 30, 2012 and December 31, 2011, respectively. 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 public service commissions of the states in which our member distribution cooperatives operate.

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.

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The following table summarizes our financial assets and liabilities measured at fair value on a recurring basis as of September 30, 2012 and December 31, 2011:

	September 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)	$	112,462	$	37,885	$	74,577	$	—
Unrestricted investments and other(3)		119		119		—		—
Total Financial Assets	$	112,581	$	38,004	$	74,577	$	—
Derivatives - gas and power(4)	$	448	$	448	$	—	$	—
Total Financial Liabilities	$	448	$	448	$	—	$	—
	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, an equity fund that invests in small capitalization stocks, and during the third quarter of 2012, an equity fund that invests in international stocks. The fair values of the investments in the nuclear decommissioning trust have been estimated using the net asset value per share.

⁽³⁾  Unrestricted investments and other includes investments that are 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.

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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 September 30, 2012 Quantity		As of December 31, 2011 Quantity
Natural gas	MMBTU		650,000		3,800,000
Purchased power	MWh		—		213,120

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

		Fair Value
	Balance Sheet Location	As of September 30, 2012		As of December 31, 2011
		(in thousands)
Derivatives in a liability position:
Natural gas futures contracts	Deferred credits and other liabilities - other	$	448	$	3,295
Purchased power contracts	Deferred credits and other liabilities - other		—		1,875
Total derivatives in a liability position		$	448	$	5,170

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

for the Three and Nine Months Ended September 30, 2012 and 2011

Derivatives Accounted for Utilizing Regulatory Accounting	Amount of Gain (Loss) Recognized in Regulatory Asset/Liability as of September 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 September 30,						Amount of Gain (Loss) Reclassified from Regulatory Asset/Liability into Income for the Nine Months Ended September 30,
	2012			2011				2012			2011			2012			2011
	(in thousands)							(in thousands)						(in thousands)
Natural gas futures contracts(1)	$	(2,087	)	$	(3,574	)	Fuel	$	(4,443	)	$	(2,435	)	$	(6,522	)	$	(5,989	)
Purchased power contracts		—			—		Purchased power		—			—			(2,736	)		539
Total	$	(2,087	)	$	(3,574	)		$	(4,443	)	$	(2,435	)	$	(9,258	)	$	(5,450	)

⁽¹⁾ As of September 30, 2012 and 2011, includes a regulatory asset of $1.6 million and $44.5 thousand, 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.

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4. Investments

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

Description	Designation	Cost		Gross Unrealized Gains		Gross Unrealized Losses			Fair Value		Carrying Value
						(in thousands)
September 30, 2012
Nuclear decommissioning trust(1)(2)
Debt securities	Available for sale	$	34,105	$	3,504	$	—		$	37,609	$	37,609
Equity securities	Available for sale		60,682		13,895		—			74,577		74,577
Cash and other	Available for sale		276		—		—			276		276
Total Nuclear Decommissioning Trust		$	95,063	$	17,399	$	—		$	112,462	$	112,462
Lease deposits(3)
Government obligations	Held to maturity	$	93,459	$	11,661	$	—		$	105,120	$	93,459
Total Lease Deposits		$	93,459	$	11,661	$	—		$	105,120	$	93,459
Unrestricted investments
Government obligations	Held to maturity	$	50,030	$	2	$	—		$	50,032	$	50,030
Debt securities	Held to maturity		1,000		—		—			1,000		1,000
Total Unrestricted Investments		$	51,030	$	2	$	—		$	51,032	$	51,030
Other
Equity securities	Available for sale	$	111	$	8	$	—		$	119	$	119
Non-marketable equity investments(4)	Equity		1,813		—		—			1,813		1,813
Total Other		$	1,924	$	8	$	—		$	1,932	$	1,932
											$	258,883
December 31, 2011
Nuclear decommissioning trust(1)
Debt securities	Available for sale	$	42,528	$	2,475	$	—		$	45,003	$	45,003
Equity securities	Available for sale		51,654		7,689		(2,997	)		56,346		56,346
Cash and other	Available for sale		125		—		—			125		125
Total Nuclear Decommissioning Trust		$	94,307	$	10,164	$	(2,997	)	$	101,474	$	101,474
Lease deposits(3)
Government obligations	Held to maturity	$	91,718	$	9,862	$	—		$	101,580	$	91,718
Total Lease Deposits		$	91,718	$	9,862	$	—		$	101,580	$	91,718
Unrestricted investments
Government obligations	Held to maturity	$	40,111	$	5	$	—		$	40,116	$	40,111
Total Unrestricted Investments		$	40,111	$	5	$	—		$	40,116	$	40,111
Other
Equity securities	Available for sale	$	96	$	—	$	(5	)	$	91	$	91
Non-marketable equity investments(4)	Equity		1,805		—		—			1,805		1,805
Total Other		$	1,901	$	—	$	(5	)	$	1,896	$	1,896
											$	235,199

⁽¹⁾  Investments in the nuclear decommissioning trust are restricted for the use of funding our share of the asset retirement obligations of the future decommissioning of North Anna. See Note 3 of the Notes to Consolidated Financial Statements in our 2011 Annual Report on Form 10-K. Unrealized gains and losses related to assets held in the nuclear decommissioning trust are deferred as a regulatory asset or liability.

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

⁽³⁾  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.

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

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

	September 30, 2012				December 31, 2011
Description	Cost		Carrying Value		Cost		Carrying Value
	(in thousands)				(in thousands)
Available for sale	$	95,174	$	112,581	$	94,403	$	101,565
Held to maturity		144,489		144,489		131,829		131,829
Equity		1,813		1,813		1,805		1,805
	$	241,476	$	258,883	$	228,037	$	235,199

Contractual maturities of unrestricted debt securities at September 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		51,030		—		—		—		51,030
	$	51,030	$	—	$	—	$	—	$	51,030

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.

5. Other

Nuclear Decommissioning Trust

In accordance with regulatory accounting, we defer the difference between asset retirement expense, and interest income and realized gains and losses on the nuclear decommissioning trust, to our regulatory liability (North Anna asset retirement obligation deferral). For additional supplemental information, see Note 10 of the Notes to Consolidated Financial Statements in our 2011 Annual Report on Form 10-K. In July 2012, the investments in the nuclear decommissioning trust were rebalanced resulting in a net realized loss of $2.2 million. This loss is recorded in “Loss on investments, net” on the Condensed Consolidated Statements of Revenues, Expenses, and Patronage Capital (Unaudited); however, the loss is deferred to the regulatory liability referred to above via “Amortization of regulatory asset/liability, net.” Therefore, there is no net impact on the Condensed Consolidated Statements of Revenues, Expenses, and Patronage Capital (Unaudited). The impact on the Condensed Consolidated Statements of Cash Flows (Unaudited) is reflected in the purchases of and proceeds from sale of available for sale securities.

Spent Nuclear Fuel

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 September 30, 2012, is $8.1 million, which we recorded as a $6.0 million reduction to fuel expense, a $2.1 million reduction to property, plant, and equipment, as the settlement includes a reimbursement of costs related to fixed assets, and a receivable of $8.1 million.

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6. Subsequent Event

On October 9, 2012, our Board of Directors approved a decrease to our energy adjustment rate, resulting in a decrease to our total energy rate of approximately 6.8%, effective October 1, 2012. This decrease was implemented due to changes in our realized as well as projected energy costs.

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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 September 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 is one factor that affects the demand for electricity. We experienced slightly milder weather during the three months ended September 30, 2012, and milder weather for the nine months ended September 30, 2012, as compared to the same periods in 2011.

Heating degree days are a measurement tool used to quantify the need to utilize heat for a building, and cooling degree days are a measurement tool used to quantify the need to utilize cooling for a building. The heating degree days and cooling degree days for the three and nine months ended September 30, 2012 and 2011, were as follows:

	Three Months Ended September 30,				%			Nine Months Ended September 30,				%
	2012		2011		Change			2012		2011		Change
Heating degree days		—		—		—			1,662.9		2,130.2		(21.9	)
Cooling degree days		1,002.2		1,048.8		(4.4	)		1,362.1		1,426.7		(4.5	)

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 and nine months ended September 30, 2012, as compared to the same periods in 2011. These decreases were the result of decreases in the economic dispatch of, and average cost of fuel for, our combustion turbine facilities, as well as reduced generation due to maintenance outages and economic dispatch considerations at Clover. These decreases were partially offset by an increase in nuclear fuel expense. In 2011, there were unscheduled outages at North Anna partially attributable to an earthquake that resulted in reduced generation. Purchased power expense decreased for the three and nine months ended September 30, 2012, as compared to the same periods in 2011, due to a decrease in the average cost and volume of purchased power.

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Deferred energy expense represents the difference between energy revenues and energy expenses. In the three and nine months ended September 30, 2012, we over-collected energy costs from our member distribution cooperatives. In the nine months ended September 30, 2011, we under-collected energy costs from our member distribution cooperatives. 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 “Management’s Discussion and Analysis of Financial Condition and Results of Operations—Critical Accounting Policies—Deferred Energy” in Item 7 of 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 months ended September 30, 2012, operations and maintenance expense decreased as compared to the same period in 2011, primarily due to the outages at North Anna in 2011 related to the scheduled maintenance and refueling outage and an earthquake. During the nine months ended September 30, 2012, operations and maintenance expense increased as compared to the same period in 2011, primarily due to a scheduled outage at Clover.

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 September 30, 2012, we had $17.8 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 “Management’s Discussion and Analysis of Financial Condition and Results of Operations—Critical Accounting Policies—Margin Stabilization Plan” in Item 7 of 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 “Management’s Discussion and Analysis of Financial Condition and Results of Operations—Factors Affecting Results—Formulary Rate” in Item 7 of our 2011 Annual Report on Form 10-K.

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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 nine months ended September 30, 2012 and 2011, were as follows:

	Three Months Ended September 30,								Nine Months Ended September 30,
	2012				2011				2012				2011
	(in MWh and percentages)								(in MWh and percentages)
Generated:
Clover		553,475	16.1	%		635,812	18.5	%		1,634,624	17.2	%		2,025,415	19.8	%
North Anna		487,580	14.2			277,078	8.1			1,316,639	13.8			1,231,386	12.0
Louisa		36,041	1.0			65,486	1.9			67,987	0.7			111,835	1.1
Marsh Run		56,843	1.7			74,213	2.2			118,353	1.2			137,963	1.3
Rock Springs		46,365	1.3			83,141	2.4			64,939	0.7			113,357	1.1
Distributed Generation		410	—			652	—			583	—			863	—
Total Generated		1,180,714	34.3			1,136,382	33.1			3,203,125	33.6			3,620,819	35.3
Purchased:
Other than renewable		2,197,642	63.8			2,237,551	65.1			6,003,542	63.1			6,334,124	61.8
Renewable(1)		65,922	1.9			60,626	1.8			314,604	3.3			299,776	2.9
Total Purchased		2,263,564	65.7			2,298,177	66.9			6,318,146	66.4			6,633,900	64.7
Total Available Energy		3,444,278	100.0	%		3,434,559	100.0	%		9,521,271	100.0	%		10,254,719	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 “Business—Power Supply Resources—PJM” in Item 1 of 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 nine months ended September 30, 2012 and 2011, was as follows:

	Clover
	Three Months  Ended September 30,						Nine Months Ended September 30,
	2012			2011			2012			2011
Unit 1		96.3	%		99.7	%		73.8	%		96.6	%
Unit 2		100.0			99.4			94.7			94.5
Combined		98.1			99.6			84.2			95.6

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The output of Clover and North Anna for the three and nine months ended September 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 September 30,						Nine Months Ended September 30,						Three Months Ended September 30,						Nine Months Ended September 30,
	2012			2011			2012			2011			2012			2011			2012			2011
Unit 1		53.6	%		67.5	%		49.1	%		72.7	%		101.2	%		57.6	%		81.7	%		86.8	%
Unit 2		63.5			66.8			66.8			70.9			100.7			57.5			102.3			87.5
Combined		58.5			67.1			58.0			71.8			101.0			57.6			92.0			87.2

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

	Scheduled Outages								Unscheduled Outages
	Three Months Ended September 30,				Nine Months Ended September 30,				Three Months Ended September 30,				Nine Months Ended September 30,
	2012		2011		2012		2011		2012		2011		2012		2011
	(in days)				(in days)				(in days)				(in days)
Unit 1		—		—		54.0		7.9		3.4		0.3		18.8		1.4
Unit 2		—		—		8.0		8.1		—		1.1		6.6		7.7
Combined		—		—		62.0		16.0		3.4		1.4		25.4		9.1

Also, Clover Unit 1 and Unit 2 were placed on reserve shutdown for approximately 21.3 days and 12.4 days, respectively, for the nine months ended September 30, 2012, due to economic dispatch considerations.

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

	Scheduled Outages								Unscheduled Outages
	Three Months Ended September 30,				Nine Months Ended September 30,				Three Months Ended September 30,				Nine Months Ended September 30,
	2012		2011		2012		2011		2012		2011		2012		2011
	(in days)				(in days)				(in days)				(in days)
Unit 1		—		—		36.0		—		—		38.4		15.9		38.4
Unit 2		—		20.0		—		20.0		—		18.4		—		18.4
Combined		—		20.0		36.0		20.0		—		56.8		15.9		56.8

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

	Three Months Ended September 30,						Nine Months Ended September 30,
	2012			2011			2012			2011
Louisa		98.1	%		96.9	%		99.0	%		97.8	%
Marsh Run		96.1			97.1			98.6			97.6
Rock Springs		99.9			99.4			96.2			98.7

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.

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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 nine months ended September 30, 2012 and 2011, were as follows:

	Three Months Ended September 30,				Nine Months Ended September 30,
	2012		2011		2012		2011
	(in thousands)				(in thousands)
Revenues from sales to:
Member distribution cooperatives
Base energy revenues	$	58,027	$	57,004	$	158,049	$	164,772
Energy adjustment revenues		87,629		86,500		246,360		246,760
Total energy revenues		145,656		143,504		404,409		411,532
Demand (capacity) revenues		74,129		79,130		227,784		238,038
Total revenues from sales to member distribution cooperatives		219,785		222,634		632,193		649,570
Non-members		4,459		7,275		12,758		31,486
Total operating revenues	$	224,244	$	229,909	$	644,951	$	681,056
Average cost to member distribution cooperatives (per MWh)	$	66.22	$	67.97	$	69.61	$	69.26

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 nine months ended September 30, 2012 and 2011, were as follows:

	Three Months Ended September 30,				Nine Months Ended September 30,
	2012		2011		2012		2011
	(in MWh)				(in MWh)
Energy sales to:
Member distribution cooperatives		3,319,100		3,275,609		9,082,023		9,379,184
Non-members		113,697		158,453		397,188		753,117
Total energy sales		3,432,797		3,434,062		9,479,211		10,132,301
	(in MW)				(in MW)
Demand sales to member distribution cooperatives		6,567		6,455		18,655		18,884

Our energy sales in MWh and demand sales in MW to our member distribution cooperatives for the three months ended September 30, 2012, were 1.3% and 1.7% higher, respectively, as compared to the same period in 2011. Our energy sales in MWh and demand sales in MW to our member distribution cooperatives for the nine months ended September 30, 2012, were 3.2% and 1.2% lower, respectively, as compared to the same period in 2011, primarily as a result of milder weather in 2012 as compared to 2011.

Our energy sales in MWh to non-members for the three and nine months ended September 30, 2012 were 28.2% and 47.3% 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 nine months ended September 30, 2012, decreased $2.8 million, or 1.3%, and $17.4 million, or 2.7%, respectively, as compared to the same periods in 2011.

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The decrease in total revenues for the three months ended September 30, 2012, was due to the 6.3% decrease in the capacity costs we incurred, and thus the capacity-related revenues we reflected, primarily due to a decrease in operations and maintenance expense. The decrease in total revenues for the nine months ended September 30, 2012, was primarily related to the 4.3% decrease in the capacity costs we incurred, primarily due to a decrease in the cost of purchased capacity and the 3.2% decrease in energy sales volume.

The average cost to member distribution cooperatives is affected by changes in the revenue dollars as well as the sales volumes. Our average cost to member distribution cooperatives per MWh for the three months ended September 30, 2012, decreased $1.75 per MWh, or 2.6% as compared to the same period in 2011. Our capacity-related revenues for the three months ended September 30, 2012, decreased 6.3%, while our MWh volume increased 1.3%, resulting in a lower average cost of demand (capacity) on a per MWh basis, as compared to the same period in 2011. Our average cost to member distribution cooperatives for the nine months ended September 30, 2012, was relatively flat as compared to the same period in 2011.

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

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

Non-member revenue decreased $2.8 million, or 38.7%, and $18.7 million, or 59.5%, for the three and nine months ended September 30, 2012, respectively, as compared to the same periods in 2011 due to the 28.2% and 47.3% 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 nine months ended September 30, 2012 and 2011:

	Three Months Ended September 30,					Nine Months Ended September 30,
	2012			2011		2012		2011
	(in thousands)					(in thousands)
Fuel	$	23,608		$	28,573	$	70,405	$	90,689
Purchased power		145,235			149,258		402,433		455,542
Deferred energy		8,955			28		24,368		(12,884	)
Operations and maintenance		8,677			12,305		34,133		28,992
Administrative and general		9,356			9,142		28,344		29,092
Depreciation and amortization		10,568			10,382		31,412		31,082
Amortization of regulatory asset/(liability), net		(1,601	)		819		116		3,030
Accretion of asset retirement obligations		941			886		2,799		2,656
Taxes, other than income taxes		2,119			1,917		6,342		6,335
Total Operating Expenses	$	207,858		$	213,310	$	600,352	$	634,534

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

Total operating expenses decreased $5.5 million, or 2.6%, for the three months ended September 30, 2012, as compared to the same period in 2011, primarily due to decreases in fuel, purchased power, and operations and maintenance expenses, and amortization of regulatory asset/liability, net partially offset by an increase in deferred energy expense.

• Fuel expense decreased $5.0 million, or 17.4%, primarily as the result of a decrease in the economic dispatch of, and average cost of fuel for, our combustion turbine facilities, as well as economic dispatch considerations at Clover in 2012. These decreases were partially offset by an increase in nuclear fuel expense. In 2011, there were scheduled outages at North Anna as well as unscheduled outages, partially attributable to an earthquake, that resulted in reduced generation during the three months ended September 30, 2011. There were no comparable outages in 2012 as compared to the same period in 2011. Also, we recorded a reduction to fuel expense in 2012 and 2011 related to the DOE spent nuclear fuel refunds; however, the refund was smaller in 2012 than in 2011.

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• Purchased power expense, which includes the cost of purchased energy, capacity, and transmission, decreased $4.0 million, or 2.7%. The volume of purchased power decreased 1.5% and the average cost of purchased power was 1.2% lower for the three months ended September 30, 2012 as compared to the same period in 2011.

• Operations and maintenance expense decreased $3.6 million, or 29.5%. In 2011, there were scheduled outages at North Anna as well as unscheduled outages, partially attributable to an earthquake, during the three months ended September 30, 2011. There were no comparable outages in 2012 as compared to the same period in 2011.

• Amortization of regulatory asset/liability, net decreased $2.4 million primarily due to the reclassification of the $2.2 million realized loss to the regulatory liability. In the third quarter of 2012, the nuclear decommissioning trust was rebalanced and resulted in a $2.2 million realized loss, and in accordance with regulatory accounting, was deferred as a regulatory liability.

• Deferred energy expense increased $8.9 million. For the three months ended September 30, 2012, we over-collected $8.9 million in energy costs; whereas for the same period in 2011, we over-collected $28.0 thousand in energy costs.

Total operating expenses decreased $34.2 million, or 5.4%, for the nine months ended September 30, 2012, as compared to the same period 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 decreased $53.1 million, or 11.7%. The average cost of purchased power was 7.2% lower as compared to the same period in 2011. Additionally, the volume of purchased power decreased 4.8% primarily due to milder weather.

• Fuel expense decreased $20.3 million, or 22.4%, primarily as the result of a decrease in the economic dispatch of, and average cost of fuel for, our combustion turbine facilities, as well as reduced generation due to maintenance outages at Clover in 2012. These decreases were partially offset by an increase in nuclear fuel expense. In 2011, there were unscheduled outages at North Anna partially attributable to an earthquake that resulted in reduced generation. Also, we recorded a reduction to fuel expense in 2012 and 2011 related to the DOE spent nuclear fuel refunds; however, the refund was smaller in 2012 than in 2011.

• Deferred energy expense increased $37.3 million. For the nine months ended September 30, 2012, we over-collected $24.4 million in energy costs; whereas for the same period in 2011, we under-collected $12.9 million. 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 $59.1 million at September 30, 2012.

• Operations and maintenance expense increased $5.1 million, or 17.7%, primarily due to scheduled and unscheduled maintenance outages at Clover during the nine months ended September 30, 2012, as compared to the same period in 2011. The unscheduled outages were primarily due to the extension of original scheduled outages to address additional maintenance items.

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Other Items

Loss on Investments, net

In accordance with regulatory accounting, we defer the difference between asset retirement expense, and interest income and realized gains and losses on the nuclear decommissioning trust, to our regulatory liability (North Anna asset retirement obligation deferral). For additional supplemental information, see Note 10 of the Notes to Consolidated Financial Statements in our 2011 Annual Report on Form 10-K. In July 2012, the investments in the nuclear decommissioning trust were rebalanced resulting in a net realized loss of $2.2 million. This loss is recorded in “Loss on investments, net” on the Condensed Consolidated Statements of Revenues, Expenses, and Patronage Capital (Unaudited); however, the loss is deferred to the regulatory liability referred to above via “Amortization of regulatory asset/liability, net.” Therefore, there is no net impact on the Condensed Consolidated Statements of Revenues, Expenses, and Patronage Capital (Unaudited). The impact on the Condensed Consolidated Statements of Cash Flows (Unaudited) is reflected in the purchases of and proceeds from sale of available for sale securities.

Investment Income

Investment income decreased for the three and nine months ended September 30, 2012, by $0.2 million, or 17.7%, and $0.7 million, or 17.3%, 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 nine months ended September 30, 2012 and 2011, were as follows:

	Three Months Ended September 30,						Nine Months Ended September 30,
	2012			2011			2012			2011
	(in thousands)						(in thousands)
Interest expense on long-term debt	$	(12,146	)	$	(12,530	)	$	(36,438	)	$	(38,303	)
Other		(241	)		(819	)		(1,007	)		(2,261	)
Total Interest Charges		(12,387	)		(13,349	)		(37,445	)		(40,564	)
Allowance for borrowed funds used during construction		254			217			867			636
Interest Charges, net	$	(12,133	)	$	(13,132	)	$	(36,578	)	$	(39,928	)

Interest expense on long-term debt decreased $0.4 million, or 3.1%, and $1.9 million, or 4.9%, for the three and nine months ended September 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 nine months ended September 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 $0.2 million, or 7.3%, and $0.6 million, or 7.7%, for the three and nine months ended September 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 September 30, 2012, were caused by increases in deferred energy, accrued expenses, nuclear decommissioning trust, and unrestricted investments and other substantially offset by decreases in accounts payable–members and regulatory assets.

• Deferred energy increased $24.4 million as a result of the over-collection of our energy costs in 2012.

• Accrued expenses increased $14.9 million primarily as a result of accrued interest on long-term debt.

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• Nuclear decommissioning trust increased $11.0 million, primarily as a result of the unrealized gains in the fair value of the investments.

• Unrestricted investments and other increased $11.0 million as a result of the investment of excess working capital.

• Accounts payable–members decreased $26.6 million due to the $39.4 million decrease in member prepayments and the $12.9 million increase in the margin stabilization adjustment as compared to December 2011.

• Regulatory assets decreased $10.8 million, primarily as a result of the change in the fair value of derivative instruments and the amortization of regulatory assets.

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 nine months of 2012 and 2011 our operating activities provided cash flows of $52.7 million and $47.9 million, respectively. Operating activities in 2012 were primarily impacted by the following:

• Current liabilities changed $16.8 million primarily due to the $26.6 million decrease in accounts payable–members and the $5.1 million decrease in accounts payable partially offset by the $14.9 million increase in accrued expenses.

• Deferred energy changed $24.4 million due to the over-collection of energy costs in 2012.

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 September 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 third 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

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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.

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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.

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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.

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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: November 7, 2012	/s/    Robert L. Kees
	Robert L. Kees
	Senior Vice President and Chief Financial Officer
	(Principal financial officer)

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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

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

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