OLD DOMINION ELECTRIC COOPERATIVE - FORM 10-Q

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EXCEL - IDEA: XBRL DOCUMENT - OLD DOMINION ELECTRIC COOPERATIVE	Financial_Report.xls
EX-32.2 - SECTION 906 CFO CERTIFICATION - OLD DOMINION ELECTRIC COOPERATIVE	d350127dex322.htm
EX-31.2 - SECTION 302 CFO CERTIFICATION - OLD DOMINION ELECTRIC COOPERATIVE	d350127dex312.htm
EX-31.1 - SECTION 302 CEO CERTIFICATION - OLD DOMINION ELECTRIC COOPERATIVE	d350127dex311.htm
EX-32.1 - SECTION 906 CEO CERTIFICATION - OLD DOMINION ELECTRIC COOPERATIVE	d350127dex321.htm

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 March 31, 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		(I.R.S. employer
incorporation or organization)		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 – March 31, 2012 (Unaudited) and December 31, 2011				4

Condensed Consolidated Statements of Revenues, Expenses, and Patronage Capital (Unaudited) – Three months ended March 31, 2012 and 2011				5

Condensed Consolidated Statements of Cash Flows (Unaudited) – Three Months Ended March 31, 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


	March 31, 2012			December 31, 2011
	(in thousands)
	(unaudited)
ASSETS:
Electric Plant:
Property, plant, and equipment	$	1,641,591		$	1,638,938
Less accumulated depreciation		(707,473	)		(697,031	)

		934,118			941,907
Nuclear fuel, at amortized cost		20,659			22,838
Construction work in progress		53,337			48,160

Net Electric Plant		1,008,114			1,012,905

Investments:
Nuclear decommissioning trust		108,801			101,474
Lease deposits		92,387			91,718
Unrestricted investments and other		73,027			42,007

Total Investments		274,215			235,199

Current Assets:
Cash and cash equivalents		63,597			63,756
Accounts receivable		9,286			7,210
Accounts receivable–deposits		12,800			6,500
Accounts receivable–members		73,038			82,236
Fuel, materials, and supplies		53,151			53,771
Prepayments and other		3,167			3,187

Total Current Assets		215,039			216,660

Deferred Charges:
Regulatory assets		98,768			98,964
Other		10,839			10,252

Total Deferred Charges		109,607			109,216

Total Assets	$	1,606,975		$	1,573,980


CAPITALIZATION AND LIABILITIES:
Capitalization:
Patronage capital	$	353,001		$	350,485
Non-controlling interest		13,072			13,093

Total Patronage capital and Non-controlling interest		366,073			363,578
Long-term debt		766,128			766,128

Total Capitalization		1,132,201			1,129,706

Current Liabilities:
Long-term debt due within one year		28,292			28,292
Accounts payable		50,867			65,416
Accounts payable–members		97,556			81,224
Accrued expenses		17,857			4,863
Deferred energy		44,135			34,712

Total Current Liabilities		238,707			214,507

Deferred Credits and Other Liabilities:
Asset retirement obligations		74,059			73,141
Obligations under long-term leases		70,483			69,285
Regulatory liabilities		78,923			75,580
Other		12,602			11,761

Total Deferred Credits and Other Liabilities		236,067			229,767

Commitments and Contingencies		—			—

Total Capitalization and Liabilities	$	1,606,975		$	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 March 31,
	2012			2011
	(in thousands)

Operating Revenues	$	222,427		$	232,095


Operating Expenses:
Fuel		27,534			35,215
Purchased power		137,544			161,259
Deferred energy		9,424			(11,562	)
Operations and maintenance		10,263			8,276
Administrative and general		9,125			10,030
Depreciation and amortization		10,376			10,331
Amortization of regulatory asset/(liability), net		744			1,084
Accretion of asset retirement obligations		918			885
Taxes, other than income taxes		2,134			2,227

Total Operating Expenses		208,062			217,745

Operating Margin		14,365			14,350
Other expense, net		(576	)		(494	)
Loss on investments, net		—			(1,187	)
Investment income		1,012			1,385
Interest charges, net		(12,311	)		(11,695	)
Income taxes		5			5

Net Margin including Non-controlling interest		2,495			2,364
Non-controlling interest		21			24

Net Margin attributable to ODEC		2,516			2,388
Patronage Capital - Beginning of Period		350,485			339,678

Patronage Capital - End of Period	$	353,001		$	342,066

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

OLD DOMINION ELECTRIC COOPERATIVE

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS (UNAUDITED)


	Three Months Ended March 31,
	2012			2011
	(in thousands)

Operating Activities:
Net Margin including Non-controlling interest	$	2,495		$	2,364
Adjustments to reconcile net margin to net cash provided by operating activities:
Depreciation and amortization		10,376			10,331
Other non-cash charges		3,316			3,025
Amortization of lease obligations		1,198			1,119
Interest on lease deposits		(669	)		(651	)
Change in current assets		1,462			72,379
Change in deferred energy		9,424			(11,562	)
Change in current liabilities		14,777			(54,928	)
Change in regulatory assets and liabilities		(2,830	)		(1,617	)
Change in deferred charges and credits		511			2,338

Net Cash Provided by Operating Activities		40,060			22,798


Financing Activities:
Payment of long-term debt		—			(1,000	)
Draws on revolving credit facilities		—			51,772
Repayments on revolving credit facilities		—			(58,815	)

Net Cash Used for Financing Activities		—			(8,043	)


Investing Activities:
Purchases of held to maturity securities		(30,000	)		—
Increase in other investments		(1,965	)		(1,256	)
Electric plant additions		(8,254	)		(4,310	)
Loss on investments, net		—			1,187

Net Cash Used for Investing Activities		(40,219	)		(4,379	)

Net Change in Cash and Cash Equivalents		(159	)		10,376
Cash and Cash Equivalents - Beginning of Period		63,756			4,391

Cash and Cash Equivalents - End of Period	$	63,597		$	14,767

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

OLD DOMINION ELECTRIC COOPERATIVE

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

The accompanying unaudited consolidated condensed 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 our 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 March 31, 2012, and our consolidated results of operations, and cash flows for the three months ended March 31, 2012 and 2011. The consolidated results of operations for the three months ended March 31, 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.

2.	Presentation

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 assets consolidated were $13.1 million at March 31, 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.

3.	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 March 31, 2012 and December 31, 2011:


	March 31, 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⁾	$	108,801	$	56,208	$	52,593	$	—
Unrestricted investments and other ⁽³⁾		103		103		—		—

Total Financial Assets	$	108,904	$	56,311	$	52,593	$	—


Derivatives – gas and power ⁽⁴⁾	$	6,270	$	1,657	$	4,613	$	—

Total Financial Liabilities	$	6,270	$	1,657	$	4,613	$	—


	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 5 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.

4.	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 March 31, 2012 Quantity		As of December 31, 2011 Quantity
Natural gas	MMBTU		3,850,000		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 March 31, 2012		As of December 31, 2011
		(in thousands)
Derivatives in a liability position:

Natural gas futures contracts	Deferred credits and other liabilities - other	$	6,270	$	3,295
Purchased power contracts	Deferred credits and other liabilities - other		—		1,875

Total derivatives in a liability position		$	6,270	$	5,170

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

for the Three Months Ended March 31, 2012 and 2011


Derivatives Accounted for Utilizing Regulatory Accounting	Amount of Gain (Loss) Recognized within Regulatory Asset/Liability for Derivatives as of March 31,						Location of Gain (Loss) Reclassified from Regulatory Asset/Liability into Income	Amount of Gain (Loss) Reclassified from Regulatory Asset/ Liability into Income for the Three Months Ended March 31,
	2012			2011				2012			2011
	(in thousands)							(in thousands)
Natural gas futures contracts⁽¹⁾	$	(9,885	)	$	(4,257	)	Fuel	$	—		$	(3,304	)
Purchased power contracts		—			—		Purchased power		(2,973	)		483

Total	$	(9,885	)	$	(4,257	)		$	(2,973	)	$	(2,821	)

⁽¹⁾	Includes a regulatory asset of $3.6 million 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.

5.	Investments

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


Description	Designation	Cost		Gross Unrealized Gains		Gross Unrealized Losses			Fair Value		Carrying Value
		(in thousands)
March 31, 2012

Nuclear decommissioning trust ⁽¹⁾
Debt securities	Available for sale	$	42,868	$	2,931	$	—		$	45,799	$	45,799
Equity securities	Available for sale		52,285		12,959		(2,353	)		62,891		62,891
Cash and other	Available for sale		111		—		—			111		111

Total Nuclear Decommissioning Trust		$	95,264	$	15,890	$	(2,353	)	$	108,801	$	108,801


Lease deposits ⁽²⁾
Government obligations	Held to maturity	$	92,387	$	8,454	$	—		$	100,841	$	92,387

Total Lease Deposits		$	92,387	$	8,454	$	—		$	100,841	$	92,387


Unrestricted investments
Government obligations	Held to maturity	$	70,116	$	—	$	(13	)	$	70,103	$	70,116
Debt securities	Held to maturity		1,000		—		—			1,000		1,000

Total Unrestricted Investments		$	71,116	$	—	$	(13	)	$	71,103	$	71,116


Other
Equity securities	Available for sale	$	96	$	7	$	—		$	103	$	103
Non-marketable equity investments ⁽³⁾	Equity		1,808		—		—			1,808		1,808

Total Other		$	1,904	$	7	$	—		$	1,911	$	1,911

							Total Carrying Value				$	274,215


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 March 31, 2012 and December 31, 2011, were as follows:


	March 31, 2012				December 31, 2011
Description	Cost		Carrying Value		Cost		Carrying Value
	(in thousands)
Available for sale	$	95,360	$	108,904	$	94,403	$	101,565
Held to maturity		163,503		163,503		131,829		131,829
Equity		1,808		1,808		1,805		1,805

	$	260,671	$	274,215	$	228,037	$	235,199

Contractual maturities of unrestricted debt securities at March 31, 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		71,116		—		—		—		71,116

	$	71,116	$	—	$	—	$	—	$	71,116

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.

6.	Subsequent Event

On April 10, 2012, our board of directors approved a decrease to our energy adjustment rate, resulting in a decrease to our total energy rate of approximately 4.6%, effective April 1, 2012. This decrease was implemented due to the changes in our realized as well as projected energy costs.

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 March 31, 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 2—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 months ended March 31, 2012, as compared to the same period 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 in 2012 as compared to 2011 as a result of a decrease in the average cost of fuel for our combustion turbine facilities. Purchased power expense decreased in 2012 as compared to 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 2012, we over-collected energy costs from our member distribution cooperatives as compared to 2011 when we under-collected energy costs. Over-collected energy costs appear as a liability on our Condensed Consolidated Balance Sheet and will be refunded to our member distribution cooperatives in subsequent periods through our formulary rate. For further discussion on deferred energy, see 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.

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 March 31, 2012, we had $11.6 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 months ended March 31, 2012 and 2011 were as follows:


	Three Months Ended March 31,
	2012				2011
	(in MWh and percentages)
Generated:
Clover		707,311	21.5	%		788,875	22.0	%
North Anna		426,118	13.0			475,314	13.3
Louisa		13,473	0.4			11,421	0.3
Marsh Run		30,691	0.9			26,613	0.7
Rock Springs		—	—			—	—
Distributed Generation		3	—			2	—

Total Generated		1,177,596	35.8			1,302,225	36.3
Purchased:
Other than renewable		1,957,222	59.6			2,147,279	59.8
Renewable ⁽¹⁾		152,342	4.6			138,544	3.9

Total Purchased		2,109,564	64.2			2,285,823	63.7

Total Available Energy		3,287,160	100.0	%		3,588,048	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 months ended March 31, 2012 and 2011, was as follows:


	Three Months Ended March 31,
	2012			2011
Unit 1		97.8	%		100.0	%
Unit 2		99.1			96.3
Combined		98.4			98.2

The output of Clover and North Anna for the three months ended March 31, 2012 and 2011, as a percentage of the maximum net dependable capacity rating of the facilities, was as follows:


	Clover Three Months Ended March 31,						North Anna Three Months Ended March 31,
	2012			2011			2012			2011
Unit 1		74.3	%		86.1	%		76.7	%		101.5	%
Unit 2		76.0			82.5			103.6			102.7
Combined		75.2			84.3			90.2			102.1

The scheduled maintenance outages and unscheduled outages for Clover for the three months ended March 31, 2012 and 2011, were as follows:


	Scheduled Outages Three Months Ended March 31,				Unscheduled Outages Three Months Ended March 31,
	2012		2011		2012		2011
	(in days)				(in days)
Unit 1		1.0		—		2.0		—
Unit 2		—		—		0.9		3.4

Combined		1.0		—		2.9		3.4

The scheduled maintenance and refueling outages and unscheduled outages for North Anna for the three months ended March 31, 2012 and 2011, were as follows:


	Scheduled Outages Three Months Ended March 31,				Unscheduled Outages Three Months Ended March 31,
	2012		2011		2012		2011
	(in days)				(in days)
Unit 1		21.0		—		0.7		—
Unit 2		—		—		—		—

Combined		21.0		—		0.7		—

During the three months ended March 31, 2012 and 2011, the operational availability of our Louisa, Marsh Run, and Rock Springs combustion turbine facilities was as follows:


	Three Months Ended March 31,
	2012			2011
Louisa		99.4	%		98.2	%
Marsh Run		99.8			96.1
Rock Springs		89.0			100.0

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 months ended March 31, 2012 and 2011, were as follows:


	Three Months Ended March 31,
	2012		2011
	(in thousands)
Revenues from sales to:
Member distribution cooperatives
Base energy revenues	$	53,449	$	59,390
Energy adjustment revenues		87,795		87,570

Total energy revenues		141,244		146,960
Demand (capacity) revenues		75,790		78,971

Total revenues from sales to member distribution cooperatives		217,034		225,931
Non-members		5,393		6,164

Total operating revenues	$	222,427	$	232,095


Average cost to member distribution cooperatives (per MWh)	$	70.55	$	67.44

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 months ended March 31, 2012 and 2011, were as follows:


	Three Months Ended March 31,
	2012		2011
	(in MWh)
Energy sales to:
Member distribution cooperatives		3,076,266		3,350,082
Non-members		187,099		175,901

Total energy sales		3,263,365		3,525,983


	(in MW)
Demand sales to Member distribution cooperatives		6,450		6,642

In 2012, our energy sales in MWh and demand sales in MW to our member distribution cooperatives were 8.2% and 2.9% lower, respectively, as compared to 2011, primarily as a result of the milder weather in 2012 as compared to 2011.

In 2012, our energy sales in MWh to non-members were 6.4% higher as compared to 2011. Sales to non-members consist of sales of excess purchased and generated energy.

In 2012, total revenues from sales to our member distribution cooperatives decreased $8.9 million, or 3.9%, as compared to 2011. The decrease in total revenues is related to the 8.2% decrease in our sales volume partially offset by a 4.7% increase in our total energy rate (our total energy rate includes our base energy rate and our energy rate).

In 2012, the capacity costs we incurred, and thus the capacity-related revenues we reflected, were 4.0% lower as compared to 2011, primarily due to a decrease in the average cost of capacity we purchased.

In 2012, our average cost per MWh to member distribution cooperatives increased $3.11 per MWh, or 4.6%, as compared to 2011, primarily due to the 4.7% increase in our total energy rate and an increase in the average cost of demand (capacity) on a per MWh basis. In 2012, our capacity-related revenues decreased 4.0% while our MWh volume decreased 8.2% resulting in a higher average cost of demand on a per MWh basis.

Non-member revenue decreased $0.8 million, or 12.5%, in 2012 as compared to 2011 due to a decrease in the average price partially offset by a 6.4% increase in the volume of excess energy sales.

Operating Expenses

The following is a summary of the components of our operating expenses for the three months ended March 31, 2012 and 2011:


	Three Months Ended March 31,
	2012		2011
	(in thousands)

Fuel	$	27,534	$	35,215
Purchased power		137,544		161,259
Deferred energy		9,424		(11,562	)
Operations and maintenance		10,263		8,276
Administrative and general		9,125		10,030
Depreciation and amortization		10,376		10,331
Amortization of regulatory asset/(liability), net		744		1,084
Accretion of asset retirement obligations		918		885
Taxes, other than income taxes		2,134		2,227

Total Operating Expenses	$	208,062	$	217,745

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” above.

In 2012, total operating expenses decreased $9.7 million, or 4.4%, as compared to 2011, primarily due to decreases in purchased power and fuel expenses partially offset by the increase in deferred energy expense.

•

Purchased power expense, which includes the cost of purchased energy and capacity, decreased $23.7 million, or 14.7%, due to a 7.7% decrease in the volume of purchased power primarily due to milder weather and a 7.6% decrease in the average cost of purchased power.

•

Fuel expense decreased $7.7 million, or 21.8%, primarily due to the decrease in the average cost of fuel for our combustion turbine facilities.

•

Deferred energy expense increased $21.0 million, or 181.5%. During 2012, we over-collected $9.4 million in energy costs; whereas in 2011, we under-collected $11.6 million 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 $44.1 million at March 31, 2012.

Other Items

Investment Income

Investment income decreased in 2012 by $0.4 million, or 26.9%, 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 months ended March 31, 2012 and 2011, were as follows:


	Three Months Ended March 31,
	2012			2011
	(in thousands)
Interest expense on long-term debt	$	(12,141	)	$	(11,248	)
Other		(436	)		(692	)

Total interest charges		(12,577	)		(11,940	)
Allowance for borrowed funds used during construction		266			245

Interest charges, net	$	(12,311	)	$	(11,695	)

In 2012, interest charges, net increased $0.6 million, or 5.3%, as compared to 2011. In the second quarter of 2011, we issued $350.0 million of debt and repaid $215.0 million of maturing debt.

Net Margin Attributable to ODEC

In 2012, our net margin, which is a function of our total interest charges plus any additional equity contributions approved by our board of directors, increased $0.1 million, or 5.4%, as compared to 2011 due to higher interest charges.

Financial Condition

The principal changes in our financial condition from December 31, 2011 to March 31, 2012, were caused by increases in unrestricted investments and other, accounts payable–members, accrued expenses, and deferred energy, partially offset by decreases in accounts payable and accounts receivable–members.

•

Unrestricted investments and other increased $31.0 million as a result of the investment of excess working capital.

•

Accounts payable–members increased $16.3 million due to the $9.6 million increase in member prepayments and the $6.7 million increase in the margin stabilization adjustment as compared to December 2011.

•

Accrued expenses increased $13.0 million primarily as a result of increased interest payable related to our long-term debt.

•

Deferred energy increased $9.4 million as a result of the over-collection of our energy costs in 2012.

•

Accounts payable decreased $14.5 million due to decreased purchased power requirements in March 2012 as compared to December 2011.

•

Accounts receivable–members decreased $9.2 million as a result of lower sales to members in March 2012 as compared to December 2011 partially offset by a $3.8 million increase in member extension balances.

Liquidity and Capital Resources

Sources

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

Operations

Historically, our operating cash flows generally have been sufficient to meet our short- and long-term capital expenditures related to our existing generating facilities, our debt service requirements, and our ordinary business operations. In 2012 and 2011, our operating activities provided cash flows of $40.1 million and $22.8 million, respectively. Operating activities in 2012 were primarily impacted by the following:

•

Current liabilities changed by $14.8 million primarily due to the $16.3 million increase in accounts payable–members and the $13.0 million increase in accrued expenses partially offset by the $14.5 million decrease in accounts payable.

•

Deferred energy changed $9.4 million due to the over-collection of costs in 2012.

Credit Facilities

In addition to liquidity from our operating activities, we currently maintain a $500.0 million, five-year committed revolving credit facility to cover our short-term and medium-term funding needs. At March 31, 2012 and December 31, 2011, we did not have any short-term 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 first 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: May 10, 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