Old Dominion Electric Cooperative 10-Q 2010 Q1 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 March 31, 2010

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  x    No  ¨

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  ¨    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.

OLD DOMINION ELECTRIC COOPERATIVE

INDEX

		Page Number
PART I.	Financial Information
Item 1.	Financial Statements
	Condensed Consolidated Balance Sheets – March 31, 2010 (Unaudited) and December 31, 2009	3
	Condensed Consolidated Statements of Revenues, Expenses and Patronage Capital (Unaudited) – Three months ended March 31, 2010 and 2009	4
	Condensed Consolidated Statements of Cash Flows (Unaudited) – Three Months Ended March 31, 2010 and 2009	5
	Notes to Condensed Consolidated Financial Statements	6
Item 2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	11
Item 3.	Quantitative and Qualitative Disclosures About Market Risk	18
Item 4.	Controls and Procedures	18
PART II.	Other Information
Item 1.	Legal Proceedings	19
Item 1A.	Risk Factors	19
Item 6.	Exhibits	20

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OLD DOMINION ELECTRIC COOPERATIVE

PART 1. FINANCIAL INFORMATION

ITEM 1. FINANCIAL STATEMENTS

CONDENSED CONSOLIDATED BALANCE SHEETS

	March 31, 2010			December 31, 2009
	(in thousands)
	(unaudited)
ASSETS:
Electric Plant
In service	$	1,575,512		$	1,578,459
Less accumulated depreciation		(636,935	)		(630,600	)
		938,577			947,859
Nuclear fuel, at amortized cost		11,963			13,519
Construction work in progress		54,674			46,995
Net Electric Plant		1,005,214			1,008,373
Investments:
Nuclear decommissioning trust		89,562			85,437
Lease deposits		87,688			87,052
Unrestricted investments and other		3,804			3,587
Total Investments		181,054			176,076
Current Assets:
Cash and cash equivalents		9,739			6,278
Accounts receivable		819			264
Accounts receivable – deposits		12,150			3,800
Accounts receivable – members		59,067			72,716
Fuel, materials and supplies		42,771			49,290
Prepayments		3,071			3,521
Total Current Assets		127,617			135,869
Deferred Charges:
Regulatory assets		98,206			97,864
Other		24,191			21,730
Total Deferred Charges		122,397			119,594
Total Assets	$	1,436,282		$	1,439,912
CAPITALIZATION AND LIABILITIES:
Capitalization:
Patronage capital	$	331,711		$	329,520
Non-controlling interest		13,154			13,178
Total Patronage capital and Non-controlling interest		344,865			342,698
Long-term debt		688,730			688,736
Total Capitalization		1,033,595			1,031,434
Current Liabilities
Long-term debt due within one year		22,917			22,917
Lines of credit		—			26,954
Accounts payable		43,229			48,966
Accounts payable – members		33,147			29,004
Accrued expenses		16,958			4,659
Deferred energy		46,811			38,740
Total Current Liabilities		163,062			171,240
Deferred Credits and Other Liabilities
Asset retirement obligations		65,353			64,543
Obligations under long-term leases		61,657			60,612
Regulatory liabilities		94,943			96,456
Other		17,672			15,627
Total Deferred Credits and Other Liabilities		239,625			237,238
Commitments and Contingencies		—			—
Total Capitalization and Liabilities	$	1,436,282		$	1,439,912

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 March 31,
	2010			2009
	(in thousands)
Operating Revenues	$	175,657		$	202,722
Operating Expenses
Fuel		28,423			30,840
Purchased power		91,524			114,574
Deferred energy		8,071			5,959
Operations and maintenance		8,898			13,593
Administrative and general		12,605			9,359
Depreciation, amortization and decommissioning		10,334			10,243
Amortization of regulatory asset/(liability), net		967			(274	)
Accretion of asset retirement obligations		809			818
Taxes, other than income taxes		2,081			2,029
Total Operating Expenses		163,712			187,141
Operating Margin		11,945			15,581
Other Expense, net		(442	)		(440	)
Investment Income		1,296			350
Interest Charges, net		(10,638	)		(12,686	)
Income Taxes		6			(83	)
Net Margin Including Non-Controlling Interest		2,167			2,722
Non-Controlling Interest		24			(151	)
Net Margin Attributable to Old Dominion Electric Cooperative		2,191			2,571
Patronage Capital - Beginning of Period		329,520			319,833
Patronage Capital - End of Period	$	331,711		$	322,404

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)

	Three Months Ended March 31,
	2010			2009
	(in thousands)
Operating Activities:
Net Margin attributable to Old Dominion Electric Cooperative	$	2,191		$	2,571
Adjustments to reconcile net margin to net cash provided by operating activities:
Depreciation, amortization and decommissioning		10,334			10,243
Other noncash charges		2,499			2,336
Non-controlling interest		(24	)		151
Amortization of lease obligations		1,045			1,369
Interest on lease deposits		(636	)		(955	)
Change in current assets		11,713			7,717
Change in deferred energy		8,071			5,959
Change in current liabilities		10,705			18,905
Change in regulatory assets and liabilities		(5,119	)		(11,602	)
Change in deferred charges and credits		(144	)		(1,937	)
Net Cash Provided by Operating Activities		40,635			34,757
Financing Activities:
Obligations under long-term leases		—			(237	)
Draws on lines of credit		82,769			171,800
Repayments on lines of credit		(109,723	)		(205,365	)
Net Cash Used for Financing Activities		(26,954	)		(33,802	)
Investing Activities:
Increase in other investments		(1,078	)		(18	)
Electric plant additions		(9,142	)		(12,882	)
Net Cash Used for Investing Activities		(10,220	)		(12,900	)
Net Change in Cash and Cash Equivalents		3,461			(11,945	)
Cash and Cash Equivalents - Beginning of Period		6,278			12,025
Cash and Cash Equivalents - End of Period	$	9,739		$	80

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. 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, 2010, and our consolidated results of operations, and cash flows for the three months ended March 31, 2010 and 2009. The consolidated results of operations for the three months ended March 31, 2010, 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 2009 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 (“ODEC” or “we” or “our”) and TEC Trading, Inc. (“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, Maryland, and parts of West Virginia. 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.

We do not have any other comprehensive income for the periods presented.

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 $13.2 million at March 31, 2010, and December 31, 2009. The income taxes reported on our 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 the Federal Energy Regulatory Commission (“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 accounting principles generally accepted in the United States (“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.

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.

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The following table summarizes our financial assets and liabilities measured at fair value on a recurring basis (at least annually) as of March 31, 2010 and December 31, 2009:

	March 31, 2010		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)	$	89,562	$	89,562	$	—	$	—
Unrestricted investments and other(2)(3)		2,084		58		—		2,026
Total Financial Assets	$	91,646	$	89,620	$	—	$	2,026
Derivatives(4)	$	9,218	$	9,218	$	—	$	—
Total Financial Liabilities	$	9,218	$	9,218	$	—	$	—
	December 31, 2009		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)	$	85,437	$	85,437	$	—	$	—
Unrestricted investments and other(2)(3)		1,869		56		—		1,813
Total Financial Assets	$	87,306	$	85,493	$	—	$	1,813
Derivatives(4)	$	6,904	$	6,152	$	752	$	—
Total Financial Liabilities	$	6,904	$	6,152	$	752	$	—

⁽¹⁾ For additional information about our nuclear decommissioning trust see Note 7 of the Notes to Consolidated Financial Statements in our 2009 Annual Report on Form 10-K.

⁽²⁾ Unrestricted investments and other includes investments that were available for sale and classified as level 1 related to equity securities.

⁽³⁾ Unrestricted investments and other includes investments that were available for sale and classified as level 3. As of March 31, 2010 and December 31, 2009, we had $17.3 million of principal invested in six auction rate security investments and preferred stock (“ARS”). As of March 31, 2010, and December 31, 2009, we had an unrealized loss of $15.3 million and $15.5 million, respectively, related to these ARS which was recorded as a regulatory asset in accordance with Accounting for Regulated Operations. For additional information, see Notes 7 and 8 of the Notes to Consolidated Financial Statements in our 2009 Annual Report on Form 10-K.

⁽⁴⁾ Derivatives represent natural gas futures contracts and purchased power contracts. For additional information about our derivative financial instruments, refer to Notes 1 and 4 of the Notes to Consolidated Financial Statements in our 2009 Annual Report on Form 10-K.

The following table presents the net change in the assets and liabilities measured at fair value on a recurring basis and included in the Level 3 fair value category for the quarter ended March 31, 2010:

	Three Months Ended March 31, 2010
	(in thousands)
Balance at January 1, 2010	$	1,813
Total realized and unrealized gain:
Included in regulatory and other assets/liabilities		213
Purchases, issuances and settlements		—
Transfers out of Level 3		—
Balance at March 31, 2010	$	2,026

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The unrealized gain (change in market value) was reported in Regulatory Assets in our Consolidated Balance Sheet as of March 31, 2010.

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 contracts. See Note 1 of the Notes to Consolidated Financial Statements in our 2009 Annual Report on Form 10-K.

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

Excluding contracts accounted for as normal purchase/normal sale, we had the following outstanding natural gas futures contracts and purchased power contracts:

		As of March 31, 2010	As of December 31, 2009
Commodity	Unit of Measure	Quantity	Quantity
Natural gas	MMBTU	4,060,000	4,910,000
Purchased power	MWh	—	108,935

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

Fair Value of Derivative Instruments

		Fair Value
	Balance Sheet Location	As of March 31, 2010		As of December 31, 2009
Derivatives designated as hedging instruments
Natural gas futures contracts	Deferred credits and other liabilities-other	$	9,218	$	6,152
Purchased power contracts	Deferred credits and other liabilities-other		—		752
Total derivatives designated as hedging instruments		$	9,218	$	6,904

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

for the Quarter Ended March 31, 2010 and March 31, 2009

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 Quarter Ended March 31,
	2010			2009				2010			2009
	(in thousands)							(in thousands)
Natural gas futures contracts	$	(9,295	)	$	(21,710	)	Fuel	$	(1,049	)	$	(2	)
Other		—			—		Purchased power		(365	)		(2,884	)
Total	$	(9,295	)	$	(21,710	)		$	(1,414	)	$	(2,886	)

Our hedging activities expose us to credit-related risks. We use hedging instruments, including forwards, futures, FTRs, and options, to manage our power market price risks. Because we rely substantially on the purchase of energy from other power suppliers, we are exposed to the risk that counterparties will default in performance of their

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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, 2010 and December 31, 2009:

Description	Designation	Cost		Gross Unrealized Gains		Gross Unrealized Losses			Fair Value		Carrying Value
						(in thousands)
March 31, 2010
Nuclear decommissioning trust(1)
Debt securities	Available for sale	$	39,994	$	—	$	(740	)	$	39,254	$	39,254
Equity securities	Available for sale		46,960		5,610		(2,319	)		50,251		50,251
Cash and other	Available for sale		57		—		—			57		57
Total Nuclear Decommissioning Trust		$	87,011	$	5,610	$	(3,059	)	$	89,562	$	89,562
Lease deposits(2)
Government obligations	Held to maturity	$	87,688	$	144	$	(6,262	)	$	81,570	$	87,688
Total Lease Deposits		$	87,688	$	144	$	(6,262	)	$	81,570	$	87,688
Unrestricted investments(3)
Debt securities	Available for sale	$	1,973	$	—	$	—		$	1,973	$	1,973
Equity securities	Available for sale		53		—		—			53		53
Total Unrestricted Investments		$	2,026	$	—	$	—		$	2,026	$	2,026
Other
Equity securities	Available for sale	$	62	$	—	$	(4	)	$	58	$	58
Non-marketable equity investments	Equity		1,720		—		—			1,720		1,720
Total Other		$	1,782	$	—	$	(4	)	$	1,778	$	1,778
							Total Carrying Value				$	181,054
December 31, 2009
Nuclear decommissioning trust(1)
Debt securities	Available for sale	$	39,289	$	—	$	(2,020	)	$	37,269	$	37,269
Equity securities	Available for sale		46,577		3,661		(2,142	)		48,096		48,096
Cash and other	Available for sale		72		—		—			72		72
Total Nuclear Decommissioning Trust		$	85,938	$	3,661	$	(4,162	)	$	85,437	$	85,437
Lease deposits(2)
Government obligations	Held to maturity	$	87,052	$	138	$	(7,213	)	$	79,977	$	87,052
Total Lease Deposits		$	87,052	$	138	$	(7,213	)	$	79,977	$	87,052
Unrestricted investments(4)
Debt securities	Available for sale	$	1,761	$	—	$	—		$	1,761	$	1,761
Equity securities	Available for sale		52		—		—			52		52
Total Unrestricted Investments		$	1,813	$	—	$	—		$	1,813	$	1,813
Other
Equity securities	Available for sale	$	62	$	—	$	(6	)	$	56	$	56
Non-marketable equity investments	Equity		1,718		—		—			1,718		1,718
Total Other		$	1,780	$	—	$	(6	)	$	1,774	$	1,774
							Total Carrying Value				$	176,076

⁽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 2009 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 6 of the Notes to Consolidated Financial Statements in our 2009 Annual Report on Form 10-K.

⁽³⁾ The cost represents investments in ARS with a par value of $28.8 million, that have been written down by $26.8 million due to the $11.5 million recognition of a loss and the $15.3 million unrealized loss. We have deferred the $15.3 million as a regulatory asset in accordance with Accounting for Regulated Operations. See Note 8 of the Notes to Consolidated Financial Statements in our 2009 Annual Report on Form 10-K.

⁽⁴⁾ The cost represents investments in ARS with a par value of $28.8 million, net of a $5.0 million par value redemption in 2009 that resulted in a $1.4 million recognized loss. The cost has been written down by $27.0 million due to the $11.5 million recognition of a loss and the $15.5 million unrealized loss. We have deferred the $15.5 million as a regulatory asset in accordance with Accounting for Regulated Operations. See Note 8 of the Notes to Consolidated Financial Statements in our 2009 Annual Report on Form 10-K.

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Contractual maturities of unrestricted debt securities at March 31, 2010, were as follows:

Description	Less than 1 year		1-5 years		5-10 years		More than 10 years		Total
	(in thousands)
Available for Sale	$	—	$	—	$	—	$	1,973	$	1,973
Held to Maturity		—		—		—		—		—
	$	—	$	—	$	—	$	1,973	$	1,973

6. Subsequent Events.

On April 13, 2010, our Board of Directors approved a decrease to our fuel factor adjustment rate, resulting in a decrease to our total energy rate of approximately 3.8%, effective April 1, 2010. This decrease was implemented due to the reduction in our realized as well as projected energy costs.

In May 2010, we acquired a tract of land in Surry County, Virginia, as a possible site for a future generation facility for a purchase price of $15.4 million.

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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, increased competition in the electric utility industry, 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, 2010, there have been no significant changes in our critical accounting policies as disclosed in our Annual Report on Form 10-K for the fiscal year ended December 31, 2009. 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 (“ODEC” or “we” or “our”) and TEC Trading, Inc. (“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.

Our financial results for the quarter ended March 31, 2010, were significantly impacted by:

• Reduced need for purchased power driven by increased energy supplied by our owned generation resources and changes in our purchased power portfolio, and

• Reduction in our total energy rate.

Results of Operations

Operating Revenues

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.

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The rates we charge our member distribution cooperatives for sales of energy and capacity are determined by a formulary rate accepted by the Federal Energy Regulatory Commission (“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 a fuel factor 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 2009 Annual Report on Form 10-K.

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, 2010 and 2009, were as follows:

	Operating Revenues Three Months Ended March 31,
	2010		2009
	(in thousands)
Revenue from sales to:
Member distribution cooperatives	$	175,036	$	193,258
Non-members		621		9,464
Total revenues	$	175,657	$	202,722

Energy and Demand Sales Volumes

Our energy sales in megawatt hours (“MWh”) to our member distribution cooperatives and non-members for the three months ended March 31, 2010 and 2009, were as follows:

	Energy Sales Volume Three Months Ended March 31,
	2010	2009
	(in MWh)
Energy sales to:
Member distribution cooperatives	2,475,681	2,442,838
Non-members	19,404	223,011
Total energy sales	2,495,085	2,665,849

Our energy sales in MWh to our member distribution cooperatives were relatively flat as compared to the same period in 2009. Our energy sales in MWh to non-members were 91.3% lower as compared to the same period in 2009. Sales to non-members consist of sales of excess purchased and generated energy. 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.

Our demand sales in megawatts (“MW”) to our member distribution cooperatives for the three months ended March 31, 2010 and 2009, were as follows:

	Demand Sales Volume Three  Months Ended March 31,
	2010	2009
	(in MW)
Demand sales to Member distribution cooperatives	4,821	5,454

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Our demand sales in MW to our member distribution cooperatives were 11.6% lower for the three months ended March 31, 2010, as compared to the same period in 2009, primarily as a result of changes in weather.

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. Operating revenues on our Condensed Consolidated Statements of Revenues, Expenses and Patronage Capital reflect the actual capacity-related costs we incurred plus the energy costs that we collected during the quarter. Estimated capacity-related costs are collected during the period through the demand component of our formulary rate. Under our formulary rate, we make adjustments for the refund or recovery of amounts under our Margin Stabilization Plan. We adjust demand revenues and accounts payable–members or accounts receivable–members each quarter to reflect these adjustments. See “Critical Accounting Policies—Margin Stabilization Plan” in Part II, Item 7 of our Annual Report on Form 10-K for the fiscal year ended December 31, 2009.

Revenues from sales to our member distribution cooperatives by formulary rate component and our average costs to our member distribution cooperatives in MWh for the three months ended March 31, 2010 and 2009, were as follows:

	Three Months Ended March 31,
	2010		2009
	(in thousands)
Revenues from sales to member distribution cooperatives:
Base energy revenues	$	44,213	$	43,626
Fuel factor adjustment revenues		68,996		90,072
Total energy revenues		113,209		133,698
Demand (capacity) revenues		61,827		59,560
Total revenues from sales to member distribution cooperatives	$	175,036	$	193,258
Average costs to member distribution cooperatives (per MWh)	$	70.70	$	79.11

Growth in the number of consumers and growth in consumers’ requirements for power significantly affect our member distribution cooperatives’ requirements for power. Factors affecting our member distribution cooperatives’ consumers’ requirements for power include weather, the economy, and residential and commercial growth. See “Consumers’ Requirements for Power” in Part II, Item 7 of our Annual Report on Form 10-K for the fiscal year ended December 31, 2009.

Three Months Ended March 31, 2010 compared to Three Months ended March 31, 2009

Total revenues from sales to our member distribution cooperatives decreased $18.2 million, or 9.4%, primarily as a result of a reduction in our total energy rate. Our total energy rate (including our base energy rate and our fuel factor adjustment rate) was $9.00, or 16.4%, lower on a per MWh basis.

The following table summarizes the changes to our total energy rate as a result of changes to our fuel factor adjustment rate:

Effective Date of Rate Change:	% Change (Decrease)
January 1, 2009	(8.2	)
April 1, 2009	(3.7	)
August 1, 2009	(5.7	)
October 1, 2009	(8.0	)

These decreases are due to the continued reduction in our realized as well as projected energy costs due to overall reduced energy costs.

The capacity costs we incurred, and thus the capacity-related revenues we reflected pursuant to the formulary rate, increased $2.3 million, or 3.8%, related to higher purchased power capacity costs and administrative and general costs, offset by lower net interest expense.

Our average costs to member distribution cooperatives per MWh decreased $8.41 per MWh, or 10.6%, as a result of decreases in our total energy rate slightly offset by higher capacity costs.

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Sales to Non-Members.Sales to non-members consist of sales of excess purchased energy and sales of excess generated energy. We primarily sell excess energy to PJM under its rates for providing energy imbalance services. Non-member revenue decreased $8.8 million, or 93.4%. The decrease in non-member revenue is primarily due to a 91.3% decrease in the volume of excess energy sales and a decrease in the prices at which we sold excess energy to non-members. During 2010, our owned generation resources supplied more of our energy needs resulting in reduced need for purchased power. Excess energy is sold at the prevailing market price at the time of sale and is the result of changes in our purchased power portfolio, differences between actual and forecasted needs, as well as changes in market conditions.

Operating Expenses

We supply our member distribution cooperatives’ power requirements, consisting of capacity requirements and energy requirements, through (i) our interests in electric generating facilities which consist of a 50% interest in the Clover Power Station (“Clover”), an 11.6% interest in the North Anna Nuclear Power Station (“North Anna”), our Louisa combustion turbine facility (“Louisa”), our Marsh Run combustion turbine facility (“Marsh Run”), our Rock Springs combustion turbine facility (“Rock Springs”), and our distributed generation facilities, and (ii) power purchases from third parties through power purchase contracts and forward, short-term and spot market energy purchases. Our energy supply for the three months ended March 31, 2010 and 2009, was as follows:

	Three Months Ended March 31,
	2010			2009
	(in MWh and percentages)
Generated:
Clover	860,424	34.2	%	726,654	27.1	%
North Anna	429,729	17.1		397,543	14.8
Louisa	9,777	0.4		16,714	0.6
Marsh Run	12,792	0.5		18,786	0.7
Rock Springs	1,415	—		293	—
Distributed Generation	2	—		3	—
Total Generated	1,314,139	52.2		1,159,993	43.2
Purchased:
Total Purchased	1,201,133	47.8		1,522,853	56.8
Total Available Energy	2,515,272	100.0	%	2,682,846	100.0	%

We satisfy the majority of our member distribution cooperatives’ capacity requirements and approximately half of their energy requirements through our ownership interests in Clover, North Anna, Louisa, Marsh Run, and Rock Springs. We purchase capacity and energy from the market to supply the remaining needs of our member distribution cooperatives.

Our operating expenses are significantly affected by the extent to which we purchase power and, relatedly, the availability of our base load generating facilities, Clover and North Anna. Base load generating facilities generally have relatively high fixed costs but relatively lower variable costs. When either Clover or North Anna is off-line, we purchase replacement energy from either Virginia Power or from the market. As a result, our operating expenses, and consequently our rates to our member distribution cooperatives, are more significantly affected by the operations of Clover and North Anna than by our combustion turbine facilities. Our combustion turbine facilities have relatively low fixed costs and greater operational flexibility; however, they have relatively high variable costs; and as a result we will operate them only when the market price of energy makes their operation economical or when their operation is required by PJM for system reliability purposes.

The output of Clover and North Anna for the three months ended March 31, 2010 and 2009, as a percentage of the maximum net dependable capacity rating of the facilities was as follows:

	Clover				North Anna
	Three Months Ended March 31,				Three Months Ended March  31,
	2010		2009		2010		2009
Unit 1	91.8	%	76.4	%	101.4	%	74.4	%
Unit 2	91.6		78.7		88.6		101.4
Combined	91.7		77.6		95.0		87.9

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The scheduled maintenance outages and unscheduled outages for Clover for the three months ended March 31, 2010 and 2009, were as follows:

	Scheduled Outages Three Months Ended March 31,		Unscheduled Outages Three Months Ended March 31,
	2010	2009	2010	2009
	(in days)		(in days)
Unit 1	—	14.0	0.1	1.0
Unit 2	—	11.0	0.4	—
Combined	—	25.0	0.5	1.0

The scheduled maintenance and refueling outages and unscheduled outages for North Anna for the three months ended March 31, 2010 and 2009, were as follows:

	Scheduled Outages Three Months Ended March 31,		Unscheduled Outages Three Months Ended March 31,
	2010	2009	2010	2009
	(in days)		(in days)
Unit 1	—	23.9	—	—
Unit 2	11.0	—	—	—
Combined	11.0	23.9	—	—

Combustion turbine facilities.During the three months ended March 31, 2010 and 2009, the operational availability of our Louisa, Marsh Run and Rock Springs combustion turbine facilities was as follows:

	Three Months Ended March  31,
	2010		2009
Louisa	100.0	%	99.1	%
Marsh Run	100.0		98.7
Rock Springs	99.1		90.5

The components of our operating expenses for the three months ended March 31, 2010 and 2009, were as follows:

	Three Months Ended March 31,
	2010		2009
	(in thousands)
Fuel	$	28,423	$	30,840
Purchased power		91,524		114,574
Deferred energy		8,071		5,959
Operations and maintenance		8,898		13,593
Administrative and general		12,605		9,359
Depreciation, amortization and decommissioning		10,334		10,243
Amortization of regulatory asset/(liability), net		967		(274	)
Accretion of asset retirement obligations		809		818
Taxes, other than income taxes		2,081		2,029
Total Operating Expenses	$	163,712	$	187,141

Three Months Ended March 31, 2010 compared to Three Months Ended March 31, 2009:

Aggregate operating expenses decreased $23.4 million, or 12.5%, primarily due to the decrease in purchased power and operations and maintenance expense, partially offset by the increase in administrative and general.

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Purchased power expense decreased $23.1 million, or 20.1%, primarily due to a 21.1% decrease in the volume of purchased power. Our owned generation resources met 52.2% of our power needs versus 43.2% during the same period of 2009.

Operations and maintenance expense decreased $4.7 million, or 34.5%. In the first quarter of 2010, there was a planned refueling and maintenance outage for Unit 2 at North Anna versus the first quarter of 2009 when there were planned maintenance outages at Clover for both Units 1 and 2 and for Unit 1 at North Anna.

Administrative and general expense increased $3.2 million, or 34.7%, primarily due to a one-time charge of $2.4 million from Virginia Power related to its workforce reduction program’s impact at Clover and North Anna.

Other Items

Investment Income.Investment income increased $0.9 million, primarily due to higher investment balances.

Interest Charges, net. The primary factors affecting our interest expense are scheduled annual payments of principal on our indebtedness, interest charges related to our dispute with Norfolk Southern Railway Company (“Norfolk Southern”), and capitalized interest. We settled our dispute with Norfolk Southern in 2009. For further discussion of our dispute with Norfolk Southern, see Item 3 Legal Proceedings and Item 7 Management’s Discussion and Analysis of Financial Condition and Results of Operations see – Financial Condition in our 2009 Annual Report on Form 10-K.

The major components of interest charges, net for the three months ended March 31, 2010 and 2009, were as follows:

	Three Months Ended March 31,
	2010			2009
	(in thousands)
Interest expense on long-term debt	$	(11,579	)	$	(11,921	)
Interest charges related to Norfolk Southern(1)		1,261			(482	)
Other		(632	)		(451	)
Total Interest Charges		(10,950	)		(12,854	)
Allowance for borrowed funds used during construction		312			168
Interest Charges, net	$	(10,638	)	$	(12,686	)

⁽¹⁾ In 2010, includes amortization of the regulatory liability related to settlement of our dispute with Norfolk Southern. In 2009, includes interest charge related to potential liability associated with our dispute with Norfolk Southern.

Net Margin.Our net margin, which is a function of our total interest charges, decreased $0.4 million, or 14.8%.

Financial Condition

The principal changes in our financial condition from December 31, 2009 to March 31, 2010, were caused by decreases in lines of credit and accounts receivable–members, substantially offset by increases in accrued expenses, accounts receivable–deposits, and deferred energy.

• Amounts outstanding under our lines of credit decreased $27.0 million reflecting our repayment of all amounts outstanding under our lines of credit.

• Accounts receivable–members decreased $13.6 million as a result of lower sales in March 2010 as compared to December 2009.

• Accrued expenses increased $12.3 million primarily as a result of increased interest payable related to our long-term debt.

• Accounts receivable–deposits increased $8.4 million due to the increase in the amount of collateral we were required to post with our counterparties as a result of the decline in the market value of some of our purchased power contracts.

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• Deferred energy changed $8.1 million due to the over-collection of energy costs in 2010.

Liquidity and Capital Resources

Operations. Historically, our operating cash flows generally have been sufficient to meet our short-term and long-term capital expenditures related to our existing generating facilities, our debt service requirements, and our ordinary business operations. During the first three months of 2010 and 2009, our operating activities provided cash flow of $40.6 million and $34.8 million, respectively. Operating activities in the first three months of 2010 were primarily impacted by changes in current assets, current liabilities, deferred energy, and regulatory assets and liabilities.

• Current assets changed $11.7 million primarily related to a $13.6 million decrease in the accounts receivable–members balance, a $6.5 million decrease in fuel, materials and supplies, partially offset by an $8.4 million increase in accounts receivable–deposits.

• Current liabilities changed $10.7 million primarily related to a $12.3 million increase in accrued expenses (driven by the $10.3 million increase in accrued interest payable related to our long-term debt) and a $4.1 million increase in accounts payable–members, partially offset by a $5.7 million decrease in accounts payable.

• Deferred energy changed by $8.1 million due to the over-collection of energy costs.

• Regulatory assets and liabilities changed $5.1 primarily due to the decrease in the fair value of our natural gas futures contracts.

Financing Activities.In addition to liquidity from our operating activities, we currently maintain a total of $365.0 million in committed lines of credit and revolving credit facilities to cover short-term and medium-term funding needs. As of March 31, 2010, we had short-term committed variable rate lines of credit in an aggregate amount of $215.0 million. Additionally, we had two committed three-year revolving credit facilities totaling $150.0 million. At March 31, 2010 we had no short-term borrowings or letters of credit outstanding under any of these arrangements. At December 31, 2009, we had $27.0 million of short-term borrowings outstanding under these arrangements.

Investing Activities.Investing activities in the first three months of 2010 were primarily impacted by activity related to electric plant additions for our generating facilities, and interest earned on investments—unrestricted investments and other, and cash and cash equivalents.

Auction Rate Securities.As of March 31, 2010 and December 31, 2009, we had $17.3 million of principal invested in six securities, all of which were originally issued as auction rate securities and two of which have converted to preferred stock, (“ARS”). The estimated fair value of our ARS was $2.0 million as of March 31, 2010, and was $1.8 million as of December 31, 2009.

ARS pay variable rates of interest which reset periodically in connection with the auction to purchase or sell the securities. Generally, the periodic auctions provide owners of ARS the opportunity to liquidate their investment at par value. In the event auctions are not fully subscribed, which auction agents describe as failed auctions, these securities are typically illiquid.

In the absence of liquidity provided by auctions, we rely on a third party to establish the estimated fair values of our ARS. It is our understanding that the estimated fair values of our ARS are determined with a valuation model that utilizes expected cash flow streams, assessments of credit quality, discount rates, and overall credit market liquidity, among other things.

The following represents changes in our ARS principal, fair value, and unrealized loss for the quarter ended March 31, 2010:

	Principal		Fair Value			Unrealized Loss(2)
	(in thousands)
ARS at December 31, 2009(1)	$	17,320		$	1,813	$	15,507
ARS at March 31, 2010(1)	$	17,320		$	2,026	$	15,294

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⁽¹⁾ Recorded on Consolidated Balance Sheet in Investments–Unrestricted investments and other, and are classified as available for sale.

⁽²⁾ Recorded on Consolidated Balance Sheet in Deferred Charges–Regulatory assets.

The cumulative $15.3 million difference between the principal of our ARS and the estimated fair value of our ARS at March 31, 2010 was accounted for as a regulatory asset in accordance with Accounting for Regulated Operations. Future changes in the estimated fair value of our ARS will be accounted for in a similar manner.

ITEM 3. QUANTITATIVE AND QUALITATIVE

DISCLOSURES ABOUT MARKET RISK

No material changes occurred in our exposure to market risk during the first quarter of 2010.

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.

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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 Annual Report on Form 10-K for the year ended December 31, 2009, 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

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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:	May 12, 2010	/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

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