OLD DOMINION ELECTRIC COOPERATIVE - FORM 10-Q

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EX-3.1 - EXHIBIT 3.1 - OLD DOMINION ELECTRIC COOPERATIVE	dex31.htm
EX-32.1 - SECTION 906 CEO CERTIFICATION - OLD DOMINION ELECTRIC COOPERATIVE	dex321.htm
EX-32.2 - SECTION 906 CFO CERTIFICATION - OLD DOMINION ELECTRIC COOPERATIVE	dex322.htm
EX-31.1 - SECTION 302 CEO CERTIFICATION - OLD DOMINION ELECTRIC COOPERATIVE	dex311.htm
EX-31.2 - SECTION 302 CFO CERTIFICATION - OLD DOMINION ELECTRIC COOPERATIVE	dex312.htm

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-Q

(Mark One)

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

For the quarterly period ended September 30, 2009

¨	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.

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 – September 30, 2009 (Unaudited) and December 31, 2008	3

	Condensed Consolidated Statements of Revenues, Expenses and Patronage Capital (Unaudited) – Three and Nine Months Ended September 30, 2009 and 2008	4

	Condensed Consolidated Statements of Cash Flows (Unaudited) – Nine Months Ended September 30, 2009 and 2008	5

	Notes to Condensed Consolidated Financial Statements	6

Item 2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	13

Item 3.	Quantitative and Qualitative Disclosures About Market Risk	21

Item 4.	Controls and Procedures	21

PART II. Other Information

Item 1.	Legal Proceedings	22

Item 1A.	Risk Factors	22

Item 5.	Other Information	22

Item 6.	Exhibits	24

OLD DOMINION ELECTRIC COOPERATIVE

PART 1. FINANCIAL INFORMATION

ITEM 1. FINANCIAL STATEMENTS

CONDENSED CONSOLIDATED BALANCE SHEETS


	September 30, 2009			December 31, 2008
	(in thousands)
	(unaudited)
ASSETS:
Electric Plant
In service	$	1,570,687		$	1,565,697
Less accumulated depreciation		(621,249	)		(592,319	)

		949,438			973,378
Nuclear fuel, at amortized cost		14,327			12,774
Construction work in progress		46,117			30,427

Net Electric Plant		1,009,882			1,016,579

Investments:
Nuclear decommissioning trust		82,326			69,239
Lease deposits		86,412			118,826
Unrestricted investments and other		3,963			11,064

Total Investments		172,701			199,129

Current Assets:
Cash and cash equivalents		8,087			12,025
Accounts receivable		1,069			7,560
Accounts receivable–deposits		14,552			5,201
Accounts receivable–members		62,019			93,888
Fuel, materials and supplies		47,406			36,852
Prepayments		2,116			3,101

Total Current Assets		135,249			158,627

Deferred Charges:
Regulatory assets		105,708			116,073
Other		20,944			15,337

Total Deferred Charges		126,652			131,410

Total Assets	$	1,444,484		$	1,505,745


CAPITALIZATION AND LIABILITIES:
Capitalization:
Patronage capital	$	327,613		$	319,833
Non-controlling interest		13,220			12,787

Total Patronage capital and Non-controlling interest		340,833			332,620
Long-term debt		711,658			711,675

Total Capitalization		1,052,491			1,044,295

Current Liabilities
Long-term debt due within one year		22,917			22,917
Lines of credit		11,808			62,000
Accounts payable		41,588			87,918
Accounts payable–members		26,157			20,921
Accrued expenses		24,416			63,589
Deferred energy		25,693			2,440

Total Current Liabilities		152,579			259,785

Deferred Credits and Other Liabilities
Asset retirement obligations		64,690			62,238
Obligations under long-term leases		59,634			90,954
Regulatory liabilities		100,216			38,694
Other		14,874			9,779

Total Deferred Credits and Other Liabilities		239,414			201,665

Commitments and Contingencies		—			—

Total Capitalization and Liabilities	$	1,444,484		$	1,505,745

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 September 30,						Nine Months Ended September 30,
	2009			2008			2009			2008
	(in thousands)						(in thousands)

Operating Revenues	$	182,952		$	277,617		$	554,612		$	775,993

Operating Expenses
Fuel		38,186			51,747			96,995			123,264
Purchased power		88,466			193,105			285,243			519,528
Deferred energy		9,231			(15,126	)		23,253			(6,765	)
Operations and maintenance		9,276			10,200			35,304			27,257
Administrative and general		9,141			9,325			28,356			28,451
Depreciation, amortization and decommissioning		10,296			9,660			30,779			28,963
Amortization of regulatory asset/(liability), net		166			(254	)		(40	)		(564	)
Accretion of asset retirement obligations		817			771			2,452			2,313
Taxes, other than income taxes		2,006			1,797			6,044			5,655

Total Operating Expenses		167,585			261,225			508,386			728,102

Operating Margin		15,367			16,392			46,226			47,891

Other Expense, net		(363	)		(64	)		(1,245	)		(183	)
Investment Income		594			1,952			1,641			6,876
Interest Charges, net		(12,791	)		(14,677	)		(38,143	)		(43,892	)
Income Taxes		(69	)		(235	)		(266	)		(689	)

Net Margin Including Non-controlling Interest		2,738			3,368			8,213			10,003
Non-controlling Interest		(112	)		(391	)		(433	)		(1,132	)

Net Margin Attributable to Old Dominion Electric Cooperative		2,626			2,977			7,780			8,871
Patronage Capital—Beginning of Period		324,987			315,006			319,833			309,112

Patronage Capital—End of Period	$	327,613		$	317,983		$	327,613		$	317,983

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

OLD DOMINION ELECTRIC COOPERATIVE

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS (UNAUDITED)


	Nine Months Ended September 30,
	2009			2008
	(in thousands)

Operating Activities:
Net Margin	$	7,780		$	8,871
Adjustments to reconcile net margins to net cash provided by operating activities:
Depreciation, amortization and decommissioning		30,779			28,963
Other non-cash charges		7,332			10,021
Non-controlling interest		433			1,132
Amortization of lease obligations		3,716			9,133
Interest on lease deposits		(2,556	)		(9,016	)
Change in current assets		19,440			(12,143	)
Change in deferred energy		23,253			(6,765	)
Change in current liabilities		(80,267	)		11,452
Change in regulatory assets and liabilities		66,519			(16,467	)
Change in deferred charges and credits		301			2,054

Net Cash Provided by Operating Activities		76,730			27,235


Financing Activities:
Obligations under long-term leases		(236	)		(423	)
Repayment on lines of credit		(50,192	)		—

Net Cash Used for Financing Activities		(50,428	)		(423	)


Investing Activities:
Purchases of available for sale securities		—			(96,000	)
Proceeds from sale of available for sale securities		—			24,000
Decrease in other investments		(448	)		15,879
Electric plant additions		(29,792	)		(22,399	)
Acquisition of transmission assets		—			(5,306	)

Net Cash Used for Investing Activities		(30,240	)		(83,826	)

Net Change in Cash and Cash Equivalents		(3,938	)		(57,014	)
Cash and Cash Equivalents—Beginning of Period		12,025			101,813

Cash and Cash Equivalents—End of Period	$	8,087		$	44,799

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

OLD DOMINION ELECTRIC COOPERATIVE

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

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 September 30, 2009, and our consolidated results of operations, and cash flows for the three and nine months ended September 30, 2009 and 2008. The consolidated results of operations for the three and nine months ended September 30, 2009, 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 2008 Annual Report on Form 10-K filed with the Securities and Exchange Commission.

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. During 2008, we had twelve Class A members. Effective December 31, 2008, one of these members, Northern Virginia Electric Cooperative, withdrew as a member. For additional information, see Note 1 of the Notes to Consolidated Financial Statements in our 2008 Annual Report on Form 10-K. 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 and $12.8 million at September 30, 2009, and December 31, 2008, respectively. 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.

3.	Commitments and Contingencies.

Norfolk Southern

As previously disclosed in Note 15 of Notes to the Consolidated Financial Statements in our 2008 Annual Report on Form 10-K, we and Virginia Electric and Power Company (“Virginia Power”) have been parties to a contract dispute with a fuel transportation supplier, Norfolk Southern Railway Company (“Norfolk Southern”), in the Circuit Court of Halifax County, Virginia. The Circuit Court originally entered an order on April 17, 2008, in favor of Norfolk Southern awarding it $86.2 million in damages, which included prejudgment interest of approximately $8.5 million, for the contract period from December 1, 2003 through November 30, 2007. We, along with Virginia Power, appealed the Circuit Court’s order to the Supreme Court of Virginia. On September 18, 2009, the Supreme Court of Virginia upheld several of the Circuit Court’s rulings; however, it reversed the Circuit Court’s ruling as to the method of calculating damages.

On September 28, 2009, we filed a Notice of Intent to File Petition for Rehearing related to one of the rulings upheld by the Supreme Court of Virginia and Norfolk Southern filed a Notice of Intent to File Petition for Rehearing related to the reversal of the Circuit Court’s method of calculating damages. The petitions for rehearing were filed on October 16,

OLD DOMINION ELECTRIC COOPERATIVE

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

2009. On October 30, 2009, we and Virginia Power settled our contract dispute with Norfolk Southern. As a result of the settlement, all parties voluntarily withdrew their respective petitions for rehearing. Under the terms of the settlement, we and Virginia Power agreed to pay Norfolk Southern approximately $10.8 million in damages, representing underpayments made to Norfolk Southern from December 1, 2003 through the present. Our share of the settlement amount is approximately $5.4 million. A regulatory liability of $63.5 million was established for the difference between the amount previously accrued and collected and the settlement amount. Also, as part of the settlement, the parties agreed on the fourth quarter 2009 adjusted base rates, which will be adjusted on a quarterly basis under the terms of the parties’ coal transportation agreement.

For further description of our legal proceedings for Norfolk Southern, see Part 1, Item 3 of our 2008 Annual Report on Form 10-K and Part II, Item 1 of our 2009 Quarterly Report on Form 10-Q for the Quarterly Period Ended March 31, 2009 and June 30, 2009.

Proposed Acquisition of Additional Service Territory by two of our Member Distribution Cooperatives

On September 15, 2009, two member distribution cooperatives of ODEC, Rappahannock Electric Cooperative (“REC”) and Shenandoah Valley Electric Cooperative (“SVEC”), filed a joint petition and application with the Virginia State Corporation Commission (“VSCC”) to obtain regulatory approval for the acquisition of The Potomac Edison Company’s (“Potomac Edison”) Virginia service territory that includes approximately 102,000 customers (meters).

In accordance with the wholesale power contracts between ODEC and its member distribution cooperatives, ODEC anticipates that it will serve the additional power requirements related to REC’s and SVEC’s acquisition. As part of the acquisition transaction, we are negotiating the assumption of full requirements power supply contracts previously entered into by Potomac Edison for the service territory. These contracts have differing terms and the latest date any of these contracts expires is June 30, 2011.

We anticipate that REC’s and SVEC’s acquisition, including the assumption of the power supply contracts from Potomac Edison, will result in lowering our average cost of power to all of our member distribution cooperatives. As a result, in accordance with our load acquisition policy, we will pay a transition fee to REC and to SVEC that represents a portion of the power cost savings related to this acquisition. The aggregate transition fee is estimated to be approximately $66.7 million. Upon closing of the acquisition, the transition fee will be reflected as a credit on the monthly power invoices of REC and SVEC over a four year period. The transition fee will be collected from our member distribution cooperatives through our formulary rate.

Consummation of the acquisition by REC and SVEC is subject to the satisfaction of several conditions including obtaining all necessary regulatory approvals. The VSCC has set a hearing date of March 2, 2010. Although we anticipate that the acquisition will close in 2010, we cannot predict when, or even if, all of the conditions to the closing of the acquisition will be satisfied and whether the closing will occur.

4.	Fair Value Measurements.

Fair Value Measurements and Disclosures clarifies that the term fair value is intended to mean a market-based measure, not an entity-specific measure.

We utilize the following fair value hierarchy, which prioritizes the inputs to valuation techniques used to measure fair value, into three broad levels:

•

Level 1—Quoted prices (unadjusted) in active markets for identical assets and liabilities that we have the ability to access at the measurement date. Instruments categorized in Level 1 primarily consist of financial instruments such as the majority of exchange-traded derivatives and securities held in our nuclear decommissioning trust funds.

•

Level 2—Inputs other than quoted prices included within Level 1 that are either directly or indirectly observable for the asset or liability, including quoted prices for similar assets or liabilities in active markets, quoted prices for identical or similar assets or liabilities in inactive markets, inputs other than quoted prices that are observable for the asset or liability, and inputs that are derived from observable market data by correlation or other means. Instruments categorized in Level 2 primarily include non-exchange traded derivatives such as over-the-counter commodity forwards and swaps, and short-term debt securities held in nuclear decommissioning trust funds.

OLD DOMINION ELECTRIC COOPERATIVE

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

•

Level 3—Unobservable inputs for the asset or liability, including situations where there is little, if any, market activity for the asset or liability. Instruments categorized in Level 3 consist of long-dated commodity derivatives, financial transmission rights, and other modeled commodity derivatives.

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 September 30, 2009:


	September 30, 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⁾	$	82,326	$	82,326	$	—	$	—
Unrestricted investments and other ⁽²⁾		2,240		—		—		2,240

Total Financial Assets	$	84,566	$	82,326	$	—	$	2,240


Derivatives ⁽³⁾	$	5,883	$	5,883	$	—	$	—

Total Financial Liabilities	$	5,883	$	5,883	$	—	$	—

⁽¹⁾	For additional information about our nuclear decommissioning trust see Note 7 of the Notes to Consolidated Financial Statements in our 2008 Annual Report on Form 10-K.

⁽²⁾

Unrestricted investments and other includes investments that were available for sale. As of December 31, 2008 and September 30, 2009, we had $22.3 million of principal invested in seven auction rate securities, two of which converted to preferred stock (“ARS”). As of September 30, 2009, we have an unrealized loss of $20.1 million related to these ARS which is recorded as a regulatory asset in accordance with Regulated Operations accounting. For additional information, see Notes 7 and 8 of the Notes to Consolidated Financial Statements in our 2008 Annual Report on Form 10-K.

⁽³⁾	Derivatives represent natural gas futures contracts. For additional information about our derivative financial instruments, refer to Notes 1 and 4 of the Notes to Consolidated Financial Statements in our 2008 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 nine months ended September 30, 2009:


	Nine Months Ended September 30, 2009
	(in thousands)
Balance at January 1, 2009	$	9,467
Total realized and unrealized (losses):
Included in regulatory and other assets/liabilities		(7,227	)
Purchases, issuances and settlements		—
Transfers out of Level 3		—

Balance at September 30, 2009	$	2,240

OLD DOMINION ELECTRIC COOPERATIVE

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

5.	New Accounting Pronouncements.

We adopted the following new accounting pronouncements as of January 2009:

Consolidation Accounting:

In December 2007, the FASB issued additional guidance on Consolidation Accounting and the presentation of the non-controlling interest in our financial statements is presented as a component of equity in accordance with the requirements of this guidance.

Derivatives and Hedging:

In March 2008, the FASB issued additional guidance on Derivatives and Hedging which seeks to improve financial reporting for derivative instruments and hedging activities by requiring enhanced disclosures regarding the impact on financial position, financial performance, and cash flows. To achieve this increased transparency, the additional guidance requires (a) the disclosure of the fair value of derivative instruments and gains and losses in a tabular format; (b) the disclosure of derivative features that are credit risk-related; and (c) cross-referencing within the footnotes.

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. We purchase power under both long-term and short-term physically-delivered forward contracts to supply power to our member distribution cooperatives. These forward purchase contracts meet the accounting definition of a derivative; however, a majority of the forward purchase derivative contracts qualify for the normal purchases/normal sales exception under previously issued guidance. As a result, these contracts are not recorded at fair value and are not subject to the disclosure requirements. We record purchased power expense when the power under the forward contract is delivered.

We also purchase natural gas futures contracts to hedge the price of natural gas for the operation of our combustion turbine facilities and for use as a basis in determining the price of power in certain forward power purchase agreements. These derivatives do not qualify for the normal purchases/normal sales exception and we have not elected cash flow hedge accounting as allowed under previously issued guidance. For these derivative contracts that do not qualify for the normal purchase/normal sales exception, we defer all gains and losses on a net basis as a regulatory asset or liability in accordance with accounting for regulated operations. These amounts are subsequently reclassified as purchased power or fuel expense in our Consolidated Statements of Revenues, Expenses, and Patronage Capital as the power or fuel is delivered and/or the contract settles.

Generally, derivatives are reported on the Consolidated Balance Sheet at fair value. The measurement of fair value is based on actively quoted market prices, if available. Otherwise, we seek indicative price information from external sources, including broker quotes and industry publications. For individual contracts, the use of differing assumptions could have a material effect on the contract’s estimated fair value.

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.

As of September 30, 2009, excluding contracts accounted for as normal purchase/normal sale, we had the following outstanding natural gas futures contracts:


Commodity	Unit of Measure	Quantity
Natural Gas	MMBTU	6,520,000

OLD DOMINION ELECTRIC COOPERATIVE

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

As of September 30, 2009, the fair value of our derivative instruments, excluding contracts accounted for as normal purchase/normal sale, was as follows:


Fair Value of Derivative Instruments

	Derivatives
	as of September 30, 2009
	Balance Sheet Location	Fair Value
		(in thousands)
Derivatives designated as hedging instruments

Natural gas futures contracts	Deferred credits and other liabilities-other	$	5,883


Total derivatives designated as hedging instruments		$	5,883

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

for the Three and Nine Months Ended September 30, 2009


Derivatives Accounted for Utilizing Regulatory Accounting	Amount of Gain (Loss) Recognized within Regulatory Asset/Liability for Derivatives as of September 30, 2009			Location of Gain (Loss) Reclassified from Regulatory Asset/Liability into Income	Amount of Gain (Loss) Reclassified from Regulatory Asset/Liability into Income for the Three Months Ended September 30, 2009			Amount of Gain (Loss) Reclassified from Regulatory Asset/Liability into Income for the Nine Months Ended September 30, 2009
	(in thousands)				(in thousands)
Natural gas futures contracts ⁽¹⁾	$	(6,734	)	Purchased power	$	(4,609	)	$	(10,774	)
Other		—		Fuel		(6,139	)		(9,058	)

Total	$	(6,734	)		$	(10,748	)	$	(19,832	)

⁽¹⁾ Includes approximately $0.9 million of loss on contracts designated for October 2009 that were physically sold in September and the impact on the Statement of Financial Position has been deferred until October 2009.

Credit-risk related contingent features:

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 purchase of energy from other power suppliers, 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 exceed the prices previously agreed upon with the defaulting counterparty.

OLD DOMINION ELECTRIC COOPERATIVE

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

Investments–Debt and Equity Securities:

In April 2009, the FASB issued additional guidance related to Investments–Debt and Equity Securities which revised and expanded the guidance concerning the recognition and measurement of other-than-temporary impairments of debt securities classified as available for sale or held to maturity. We adopted this guidance in the second quarter of 2009. There was no impact on our financial statements due to our intent to dispose of the securities before the anticipated recovery; however in accordance with this additional guidance we have expanded our disclosure below.


Description	Designation	Cost		Gross Unrealized Gains		Gross Unrealized Losses			Fair Value		Carrying Value
						(in thousands)
September 30, 2009

Nuclear decommissioning trust ⁽¹⁾
Debt securities	Available for sale	$	38,885	$	—	$	(2,470	)	$	36,415	$	36,415
Equity securities	Available for sale		45,959		1,963		(2,098	)		45,824		45,824
Cash and other	Available for sale		87		—		—			87		87

Total Nuclear decommissioning trust		$	84,931	$	1,963	$	(4,568	)	$	82,326	$	82,326


Lease deposits ⁽²⁾
Government obligations	Held to maturity		86,412		184		(4,804	)		81,792		86,412

Total Lease deposits		$	86,412	$	184	$	(4,804	)	$	81,792	$	86,412


Unrestricted investments ⁽³⁾
Debt securities	Available for sale	$	2,187	$	—	$	—		$	2,187	$	2,187
Equity securities	Available for sale		53		—		—			53		53

Total Unrestricted investments		$	2,240	$	—	$	—		$	2,240	$	2,240


Other
Equity securities	Available for sale	$	62	$	—	$	(8	)	$	54	$	54
Non-marketable equity investments	Equity		1,669		—		—			1,669		1,669

Total Other		$	1,731	$	—	$	(8	)	$	1,723	$	1,723

							Total Carrying Value				$	172,701

December 31, 2008

Nuclear decommissioning trust ⁽¹⁾
Debt securities	Available for sale	$	37,227	$	—	$	(7,345	)	$	29,882	$	29,882
Equity securities	Available for sale		47,071		—		(7,855	)		39,216		39,216
Cash and other	Available for sale		141		—		—			141		141

Total Nuclear decommissioning trust		$	84,439	$	—	$	(15,200	)	$	69,239	$	69,239


Lease deposits ⁽²⁾
Debt securities	Held to maturity	$	34,021	$	—	$	—		$	34,021	$	34,021
Government obligations	Held to maturity		84,805		285		(270	)		84,820		84,805

Total Lease deposits		$	118,826	$	285	$	(270	)	$	118,841	$	118,826


Unrestricted investments ⁽³⁾
Debt securities	Available for sale	$	8,397	$	—	$	—		$	8,397	$	8,397
Equity securities	Available for sale		1,070		—		—			1,070		1,070

Total Unrestricted investments		$	9,467	$	—	$	—		$	9,467	$	9,467


Other
Equity securities	Available for sale	$	46	$	—	$	(17	)	$	29	$	29
Non-marketable equity investments	Equity		1,568		—		—			1,568		1,568

Total Other		$	1,614	$	—	$	(17	)	$	1,597	$	1,597

							Total Carrying Value				$	199,129

⁽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 Nuclear Power Station. 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.

⁽³⁾

The cost represents investments in auction rate securities and preferred stock with a par value of $33.8 million that have been written down by $24.4 million due to the $11.5 million recognition of a loss and the $12.9 million market value adjustment. We have deferred the $20.1 million and $12.9 million as of September 30, 2009 and December 31, 2008, respectively as a regulatory asset in accordance with Accounting for Regulated Operations.

OLD DOMINION ELECTRIC COOPERATIVE

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

Contractual maturities of unrestricted debt securities at September 30, 2009, were as follows:


Description	Less than 1 year		1-5 years		5-10 years		More than 10 years		Total
	(in thousands)
Available for Sale	$	—	$	—	$	—	$	2,187	$	2,187
Held to Maturity		—		—		—		—		—

	$	—	$	—	$	—	$	2,187	$	2,187

Subsequent Events:

In May 2009, the FASB issued guidance related to Subsequent Events which sets forth: 1) the period after the balance sheet date during which management of a reporting entity should evaluate events or transactions that may occur for potential recognition or disclosure in the financial statements; 2) the circumstances under which an entity should recognize events or transactions occurring after the balance sheet date in its financial statements; and 3) the disclosures that an entity should make about events or transactions that occurred after the balance sheet date. We have evaluated subsequent events through November 12, 2009 and accordingly we note the following. On October 14, 2009, our Board of Directors approved a decrease to our fuel factor adjustment rate, resulting in a decrease to our total energy rate of approximately 8.0%, effective October 1, 2009. This decrease was implemented due to the continued reduction in our realized as well as projected energy costs. On October 30, 2009, we and Virginia Power settled our contract dispute with Norfolk Southern. Under the terms of the settlement, we and Virginia Power agreed to pay Norfolk Southern approximately $10.8 million in damages, representing underpayments made to Norfolk Southern from December 1, 2003 through the present. Our share of the settlement amount is approximately $5.4 million. A regulatory liability of $63.5 million was established for the difference between the amount previously accrued and collected and the settlement amount and these amounts are reflected in our consolidated balance sheet.

Accounting Standards Codification and the Hierarchy of Generally Accepted Accounting Principles:

In June 2009, the FASB issued “The FASB Accounting Standards Codification and the Hierarchy of Generally Accepted Accounting Principles, a replacement of FASB Statement No. 162” (the “Codification”). The Codification, which was launched on July 1, 2009, became the single source of authoritative nongovernmental U.S. GAAP, superseding existing FASB, American Institute of Certified Public Accountants (AICPA), Emerging Issues Task Force (EITF) and related literature. The Codification eliminates the GAAP hierarchy contained in previously issued guidance and establishes one level of authoritative GAAP. All other literature is considered non-authoritative. This statement is effective for financial statements issued for interim and annual periods ending after September 15, 2009.

6.	Reclassifications.

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

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 September 30, 2009, 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, 2008. These policies include the accounting for rate regulation, deferred energy, margin stabilization plan, and accounting for asset retirement obligations and 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

ODEC is a not-for-profit power supply cooperative owned entirely by its 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 three and nine months ended September 30, 2009, were significantly impacted by:

•

Change in the number of members we serve;

•

Milder than usual weather resulting in reduced demand for energy;

•

Lower purchased power costs and volume;

•

Acquisition of a loan and liquidation of an investment related to the lease and leaseback of our interest in Clover Power Station (“Clover”) Unit 1 and the resulting defeasance of the loan; and

•

Establishment of a regulatory liability related to the settlement of a dispute with Norfolk Southern Railway Company (“Norfolk Southern”).

Results of Operations

Member Distribution Cooperatives

Beginning January 1, 2009, we serve eleven member distribution cooperatives and supply their power requirements. In 2008, we served these eleven member distribution cooperative plus another, Northern Virginia Electric Cooperative (“NOVEC”). On August 15, 2008, we entered into a settlement, release and withdrawal agreement (the “Withdrawal Agreement”) with NOVEC to end our power supply arrangement and to resolve all of our outstanding disputes with it. The Withdrawal Agreement resulted in the termination of NOVEC’s wholesale power contract with ODEC and the withdrawal of NOVEC as a member of ODEC effective as of December 31, 2008. For further description of NOVEC’s withdrawal as a member, see Part 1, Item 1 “Business–Member Distribution Cooperatives–NOVEC” of our 2008 Annual Report on Form 10-K.

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 at any time 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 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.

Energy costs, which are primarily variable costs, such as nuclear, coal and natural gas fuel costs and the energy costs under our power purchase contracts with third parties, are recovered through two separate rates, the base energy rate and the fuel factor adjustment rate. The base energy rate is a fixed rate that requires FERC approval prior to adjustment. However, to the extent the base energy rate over- or under-collects our energy costs, we refund or collect the difference through a fuel factor adjustment rate. We review our energy costs at least every six months to determine whether the base energy rate and the current fuel factor adjustment rate together are adequately recovering our actual and anticipated energy costs, and revise the fuel factor adjustment rate accordingly. Since the fuel factor adjustment rate can be revised without FERC approval, we can effectively change our total energy rate to recover all our energy costs without seeking the approval of FERC.

Capacity costs, which are primarily fixed costs, such as depreciation expense, interest expense, administrative and general expenses, capacity costs under power purchase contracts with third parties, transmission costs, and our margin requirements and additional equity contributions approved by our board of directors are recovered through our demand rate. The formulary rate allows us to change the actual demand rate we charge as our capacity-related costs change, without seeking FERC approval, with the exception of decommissioning cost, which is a fixed number in the formulary rate that requires FERC approval prior to any adjustment. FERC approval is also needed to change account classifications currently in the formula or to add accounts not otherwise included in the current formula. Additionally, future depreciation studies are to be filed with FERC for their approval if they would result in a change in our depreciation rates. Our demand rate is revised automatically to recover the costs contained in our budget and any revisions made by our board of directors to our budget.

Our operating revenues are derived from power sales to our member distribution cooperatives and non-members. Our operating revenues by type of purchaser for the three and nine months ended September 30, 2009 and 2008, were as follows:


	Three Months Ended September 30,				Nine Months Ended September 30,
	2009		2008		2009		2008
	(in thousands)				(in thousands)
Revenue from sales to:
Member distribution cooperatives	$	173,775	$	257,154	$	524,162	$	716,270
Non-members		9,177		20,463		30,450		59,723

Total revenues	$	182,952	$	277,617	$	554,612	$	775,993

Our energy sales in megawatt hours (“MWh”) to our member distribution cooperatives and non-members for the three and nine months ended September 30, 2009 and 2008, were as follows:


	Three Months Ended September 30,		Nine Months Ended September 30,
	2009	2008	2009	2008
	(in MWh)		(in MWh)
Energy sales to:
Member distribution cooperatives	2,267,214	3,256,775	6,553,454	9,197,324
Non-members	332,243	306,448	944,131	916,258

Total energy sales	2,599,457	3,563,223	7,497,585	10,113,582

Our energy sales in MWh to our member distribution cooperatives were 30.4% and 28.7% lower for the three and nine months ended September 30, 2009, as compared to the same periods in 2008, primarily as a result of the change in the number of member distribution cooperatives we served. See “Member Distribution Cooperatives” above. Excluding energy sales in MWh to NOVEC, our energy sales to our member distribution cooperatives were relatively flat for the three and nine months ended September 30, 2009, as compared to the same period in 2008. Our energy sales in MWh to non-members were 8.4% and 3.0% higher for the three and nine months ended September 30, 2009, as compared to the same period in 2008. Sales to non-members consist of sales of excess purchased and generated energy.

Our demand sales in megawatts (“MW”) to our member distribution cooperatives for the three and nine months ended September 30, 2009 and 2008, were as follows:


	Three Months Ended September 30,		Nine Months Ended September 30,
	2009	2008	2009	2008
	(in MW)		(in MW)

Demand sales to member distribution cooperatives	4,304	6,742	13,344	18,587

Our demand sales in MW to our member distribution cooperatives were 36.2% and 28.2% lower for the three and nine months ended September 30, 2009, respectively, as compared to the same periods in 2008, primarily as a result of the change in the number of member distribution cooperatives we served. See “Member Distribution Cooperatives” above. Excluding demand sales in MW to NOVEC, our demand sales decreased 7.0% for the three months ended September 30, 2009, as compared to the same period in 2008. This decrease is mainly due to milder weather experienced in the third quarter of 2009 as compared to the same period in 2008. Excluding demand sales in MW to NOVEC, our demand sales were relatively flat for the nine months ended September 30, 2009, as compared to the same period in 2008.

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, 2008.

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 and nine months ended September 30, 2009 and 2008, were as follows:


	Three Months Ended September 30,				Nine Months Ended September 30,
	2009		2008		2009		2008
	(in thousands)				(in thousands)

Revenue from sales to member distribution cooperatives:
Base energy revenues	$	40,483	$	58,604	$	117,021	$	165,579
Fuel factor adjustment revenues		74,624		130,072		228,974		355,870

Total energy revenues		115,107		188,676		345,995		521,449
Demand (capacity) revenues		58,668		68,478		178,167		194,821

Total Revenues from sales to member distribution cooperatives	$	173,775	$	257,154	$	524,162	$	716,270


Average costs to member distribution cooperatives (per MWh)	$	76.65	$	78.96	$	79.98	$	77.88

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, 2008.

Three and Nine Months Ended September 30, 2009 compared to Three and Nine Months Ended September 30, 2008:

Total revenues from sales to our member distribution cooperatives for the three and nine months ended September 30, 2009, decreased $83.4 million, or 32.4%, and decreased $192.1 million, or 26.8%, respectively, as compared to the same periods in 2008 primarily as a result of the change in the number of member distribution cooperatives we served. See “Member Distribution Cooperatives” above. Excluding NOVEC’s sales in 2008, total revenues from sales to member distribution cooperatives for the three months ended September 30, 2009, decreased approximately 3.8% and for nine months ended September 30, 2009, increased approximately 2.1%.

Our total energy rate (including our base energy rate and our fuel factor adjustment rate) was 12.4% and 6.9% lower during the three and nine months ended September 30, 2009, respectively, as compared to the same periods in 2008. The following table summarizes the changes to our total energy rate as a result of changes to our fuel factor adjustment rate:


Changes to Total Energy Rate as a Result of Changes to Fuel Factor Adjustment Rate
Effective Date of Rate Change:	% Change Increase (Decrease)
January 1, 2009	(8.2	)
April 1, 2009	(3.7	)
August 1, 2009	(5.7	)

These decreases are due to the continued reduction in our realized as well as projected energy costs. Since NOVEC’s departure, we are able to satisfy more of our member distribution cooperatives’ energy needs through our owned generation, which generally are lower cost resources than energy we purchase to serve our current member distribution cooperatives’ consumers.

The capacity costs we incurred, and thus the capacity-related revenues we reflected pursuant to the formulary rate, decreased $9.8 million, or 14.3%, and $16.7 million, or 8.5%, for the three and nine months ended September 30, 2009, respectively, as compared to the same period in 2008, primarily due to decreased capacity charges. The decreased capacity charges are a function of the reduction in the amount of capacity we purchased for the first nine months of 2009 as compared to the same period in 2008. Due to the departure of NOVEC, our capacity requirements declined.

Our average costs to member distribution cooperatives per MWh decreased $2.31, or 2.9%, for the three months ended September 30, 2009, as compared to the same period in 2008 and increased $2.10, or 2.7%, per MWh, for the nine months ended September 30, 2009, as compared to the same period in 2008.

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 by $11.3 million or 55.2%, and $29.3 million, or 49.0%, in the three and nine months ended September 30, 2009, respectively, as compared to the same periods in 2008. For the three and nine months ended September 30, 2009, the decrease is due to a reduction in the prices at which we sold excess energy to non-members slightly offset by an increase in the volume of excess energy sales. Excess energy is sold at the prevailing market price at the time of the 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 Clover, an 11.6% interest in 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 and nine months ended September 30, 2009 and 2008, was as follows:


	Three Months Ended September 30,						Nine Months Ended September 30,
	2009			2008			2009			2008
	(in MWh and percentages)						(in MWh and percentages)
Generated:
Clover	812,126	31.1	%	729,621	20.4	%	2,160,336	28.6	%	2,117,986	20.9	%
North Anna	464,538	17.8		420,279	11.7		1,318,249	17.5		1,320,314	13.0
Louisa	61,169	2.3		83,360	2.3		87,541	1.1		145,543	1.4
Marsh Run	54,097	2.1		71,068	2.0		80,734	1.1		144,866	1.4
Rock Springs	22,062	0.9		34,216	1.0		29,906	0.4		51,019	0.5
Distributed generation	448	—		128	—		455	—		283	—

Total generated	1,414,440	54.2		1,338,672	37.4		3,677,221	48.7		3,780,011	37.2

Purchased:
Total purchased	1,196,953	45.8		2,237,171	62.6		3,873,036	51.3		6,390,010	62.8

Total available energy	2,611,393	100.0	%	3,575,843	100.0	%	7,550,257	100.0	%	10,170,021	100.0	%

We satisfy the majority of our capacity requirements and approximately half of our 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. Clover and North Anna operate with relatively low variable costs as compared to Louisa, Marsh Run and Rock Springs. Our combustion turbine facilities have relatively low fixed costs and greater operational flexibility; however, they have relatively high variable costs. As a result, we 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. 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. The output of Clover and North Anna for the three and nine months ended September 30, 2009 and 2008, as a percentage of the maximum net dependable capacity rating of the facilities, was as follows:


	Clover								North Anna
	Three Months Ended September 30,				Nine Months Ended September 30,				Three Months Ended September 30,				Nine Months Ended September 30,
	2009		2008		2009		2008		2009		2008		2009		2008
Unit 1	85.3	%	77.1	%	83.6	%	74.2	%	100.5	%	100.2	%	91.5	%	101.0	%
Unit 2	84.2		76.3		68.5		75.1		100.3		81.0		100.7		90.8
Combined	84.8		76.7		76.1		74.7		100.4		90.6		96.1		95.9

The scheduled and unscheduled outages for Clover for the three and nine months ended September 30, 2009 and 2008, were as follows:


	Scheduled Outages				Unscheduled Outages
	Three Months Ended September 30,		Nine Months Ended September 30,		Three Months Ended September 30,		Nine Months Ended September 30,
	2009	2008	2009	2008	2009	2008	2009	2008
	(in days)		(in days)		(in days)		(in days)
Unit 1	—	—	14.0	18.5	—	1.0	2.9	4.3
Unit 2	—	—	53.1	14.5	0.9	2.1	4.4	2.7

Combined	—	—	67.1	33.0	0.9	3.1	7.3	7.0

The scheduled and unscheduled outages for North Anna for the three and nine months ended September 30, 2009 and 2008, were as follows:


	Scheduled Outages				Unscheduled Outages
	Three Months Ended September 30,		Nine Months Ended September 30,		Three Months Ended September 30,		Nine Months Ended September 30,
	2009	2008	2009	2008	2009	2008	2009	2008
	(in days)		(in days)		(in days)		(in days)
Unit 1	—	—	25.1	—	—	—	—	—
Unit 2	—	17.0	—	17.0	—	—	—	8.7

Combined	—	17.0	25.1	17.0	—	—	—	8.7

Combustion turbine facilities. During the three and nine months ended September 30, 2009, and 2008, the operational availability of our Louisa, Marsh Run and Rock Springs combustion turbine facilities was as follows:


	Three Months Ended September 30,				Nine Months Ended September 30,
	2009		2008		2009		2008
Louisa	99.3	%	96.5	%	98.7	%	97.7	%
Marsh Run	90.5		99.9		96.4		98.3
Rock Springs	99.7		99.5		96.0		99.4

The components of our operating expenses for the three and nine months ended September 30, 2009 and 2008, were as follows:


	Three Months Ended September 30,					Nine Months Ended September 30,
	2009		2008			2009			2008
	(in thousands)					(in thousands)

Fuel	$	38,186	$	51,747		$	96,995		$	123,264
Purchased power		88,466		193,105			285,243			519,528
Deferred energy		9,231		(15,126	)		23,253			(6,765	)
Operations and maintenance		9,276		10,200			35,304			27,257
Administrative and general		9,141		9,325			28,356			28,451
Depreciation, amortization and decommissioning		10,296		9,660			30,779			28,963
Amortization of regulatory asset/(liability), net		166		(254	)		(40	)		(564	)
Accretion of asset retirement obligations		817		771			2,452			2,313
Taxes, other than income taxes		2,006		1,797			6,044			5,655

Total Operating Expenses	$	167,585	$	261,225		$	508,386		$	728,102

Aggregate operating expenses decreased $93.6 million, or 35.8%, and $219.7 million, or 30.2%, for the three and nine months ended September 30, 2009, respectively, as compared to the same periods in 2008, primarily due to the decrease in purchased power expense and fuel expense slightly offset by an increase in deferred energy. Additionally, operations and maintenance expense increased for the nine months ended September 30, 2009 as compared to the same period in 2008.

Purchased power expense decreased $104.6 million, or 54.2%, and $234.3 million, or 45.1%, for the three and nine months ended September 30, 2009, respectively, as compared to the same periods in 2008, primarily due to decreased purchased

power needs resulting from NOVEC’s departure as of December 31, 2008. For the three and nine months ended September 30, 2009, our owned generation resources met 54.2% and 48.7%, respectively, of our members power needs versus 37.4% and 37.2% for the three and nine months ended September 30, 2008, respectively.

Fuel expense decreased $13.6 million, or 26.2%, and $26.3 million, or 21.3%, respectively, for the three and nine months ended September 30, 2009, as compared to the same periods in 2008, primarily due to the decrease in the dispatch of our combustion turbine facilities and decreased coal usage as a result of scheduled maintenance outages for both units at Clover during the nine months ended September 30, 2009.

Deferred energy expense increased $24.4 million and $30.0 million for the three and nine months ended September 30, 2009, respectively, as compared to the same periods in 2008. During the three months ended September 30, 2009, we over-collected $9.2 million in energy costs; whereas in the three months ended September 30, 2008, we under-collected $15.1 million in energy costs. During the nine months ended September 30, 2009, we over-collected $23.3 million in energy costs as compared to an under-collection of $6.8 million for the same period in 2008.

Operations and maintenance expense increased $8.0 million, or 29.5%, for the nine months ended September 30, 2009, due to scheduled maintenance and refueling outages at our operating facilities in 2009 as compared to 2008.

Other Items

Investment Income. Investment income decreased $1.4 million, or 69.6%, and $5.2 million, or 76.1%, for the three and nine months ended September 30, 2009, respectively, as compared to the same periods in 2008, primarily due to lower investment balances as well as lower interest rates on our investments.

Interest Charges, net. The primary factors affecting our interest expense are scheduled annual payments of principal on our indebtedness, interest related to our potential liability associated with our dispute with Norfolk Southern, and capitalized interest. See “Legal Proceedings” in Part II, Item 1. Also, in December of 2008, we retired $108.6 million of bonds and the related unamortized discount of $52.5 million, which resulted in decreased interest expense on long-term debt beginning in 2009.

The major components of interest charges, net for the three and nine months ended September 30, 2009 and 2008, were as follows:


	Three Months Ended September 30,						Nine Months Ended September 30,
	2009			2008			2009			2008
	(in thousands)						(in thousands)
Interest expense on long-term debt	$	(11,938	)	$	(13,269	)	$	(35,789	)	$	(39,789	)
Other		(1,196	)		(1,610	)		(3,114	)		(4,564	)

Total Interest Charges		(13,134	)		(14,879	)		(38,903	)		(44,353	)
Allowance for borrowed funds used during construction		343			202			760			461

Interest Charges, net	$	(12,791	)	$	(14,677	)	$	(38,143	)	$	(43,892	)

Net Margin. Our net margin, which is a function of our total interest charges, decreased $0.4 million, or 11.8% and $1.1 million, or 12.3% for the three and nine months ended September 30, 2009, as compared to the same periods in 2008.

Financial Condition

The principal changes in our financial condition from December 31, 2008 to September 30, 2009, were caused by decreases in borrowings under our lines of credit, accounts payable, accrued expenses, lease deposits and obligations under long-term leases, and accounts receivable–members, partially offset by increases in regulatory liabilities and the change in deferred energy. Amounts outstanding under our lines of credit decreased $50.2 million reflecting our decreased need to borrow funds under our existing lines of credit. Accounts payable decreased $46.3 million related to decreased purchased power requirements in September 2009 as compared to December 2008. Accrued expenses decreased $39.2 million primarily related to the $63.5 million (including approximately $9.0 million in current year activity) reduction in the liability related to the Norfolk Southern dispute (See Note 3 in the Notes to Condensed Consolidated Financial Statements), partially offset by an $11.0 million increase in accrued interest. Lease deposits and obligations under long-term leases decreased $32.4 million and $31.3 million, respectively, related to our acquisition of a loan and liquidation of an investment related to the lease and leaseback of our interest in Clover Unit 1 and the resulting defeasance of the loan. Accounts receivable–members decreased $31.9 million as a result of lower sales in September 2009 as compared to December 2008. Regulatory liabilities increased $61.5 million primarily as a result of the establishment of a regulatory liability related to a reduction in the liability we recorded as a result of the settlement of the contract dispute with Norfolk Southern. This regulatory liability will be amortized into income over a period not to exceed 54 months. The amortization period will be determined by the Board of Directors once the procedural process is complete and the court has entered its final order. Deferred energy changed $23.3 million due to the over-collection of energy costs during the first nine months of 2009.

Liquidity and Capital Resources

Operations. Historically, our operating cash flows 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. During the first nine months of 2009 and 2008, our operating activities provided cash flow of $76.7 million and $27.2 million, respectively. Operating activities in the first nine months of 2009 were primarily impacted by changes in current liabilities, regulatory assets and liabilities, deferred energy, and current assets. Current liabilities changed $82.3 million primarily related to a $46.3 million decrease in accounts payable and a $41.2 million decrease in accrued expenses. Regulatory assets and liabilities changed $66.5 million primarily as a result of the establishment of a $63.5 million regulatory liability related to the Norfolk Southern dispute. Deferred energy changed $23.3 million due to the over-collection of energy costs during the first nine months of 2009. Current assets changed by $19.4 million as a result of the $10.6 million increase in fuel, materials and supplies, and the $9.4 million increase in accounts receivable–deposits, offset by the $31.9 million decrease in accounts receivable–members and the $6.5 million decrease in accounts receivable.

Financing Activities. In addition to liquidity from our operating activities, we maintain committed lines of credit and revolving credit facilities to cover short-term and medium-term funding needs. As of September 30, 2009, 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 September 30, 2009, we had $11.8 million of short-term borrowings outstanding under these arrangements. We renewed our $70.0 million line of credit with Bank of America, N.A. and extended the maturity to September 29, 2010 and we also renewed our $50.0 million line of credit with Wachovia, N.A. and extended the maturity to September 28, 2010.

Investing Activities. Investing activities in the first nine months of 2009 were primarily impacted by activity related to electric plant additions for our generating facilities.

Auction Rate Securities. As of September 30, 2009 and December 31, 2008, we had $22.3 million of principal invested in seven 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 $2.2 million as of September 30, 2009, and was $9.5 million as of December 31, 2008.

ARS pay a variable rate of interest which resets periodically in connection with the auction to purchase or sell the securities. Generally, the periodic auctions provide owners of auction rate securities 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 2007, deteriorating conditions in the credit market resulted in our seven ARS experiencing failed auctions. These failed auctions resulted in the interest rates on these ARS resetting at a predetermined spread above LIBOR, which, depending on the security, has ranged from 100 basis points to 200 basis points. As of November 4, 2009, all of the ARS we owned were rated between “C” and “A+” by S&P, and between “Ca” and “A3” by Moody’s.

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 and fair value, for the three and nine months ended September 30, 2009:


	Principal		Fair Value
	(in thousands)
ARS at December 31, 2008 ⁽¹⁾	$	22,320	$	9,467
Decline in market value ⁽²⁾		—		(6,931	)
ARS at June 30, 2009 ⁽¹⁾	$	22,320	$	2,536
Decrease in market value ⁽²⁾		—		(296	)

ARS at September 30, 2009 ⁽¹⁾	$	22,320	$	2,240

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

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

The cumulative $20.1 million difference between the principal of our ARS and the estimated fair value of our ARS is 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 third quarter of 2009.

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 manner. We have established a Disclosure Assessment Committee comprised of members from senior and middle management to assist in this evaluation. There have been no significant 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

Norfolk Southern

We and Virginia Electric have been parties to a contract dispute with a fuel transportation supplier, Norfolk Southern, in the Circuit Court of Halifax County, Virginia. On October 30, 2009, we and Virginia Power settled our contract dispute with Norfolk Southern. As a result of the settlement, all parties voluntarily withdrew their respective petitions for rehearing which had been filed with the Supreme Court of Virginia on October 16, 2009. Under the terms of the settlement, we and Virginia Power agreed to pay Norfolk Southern approximately $10.8 million in damages, representing underpayments made to Norfolk Southern from December 1, 2003 through the present. Our share of the settlement amount is $5.4 million. Also, as part of the settlement, the parties agreed on the fourth quarter 2009 adjusted base rates, which will be adjusted on a quarterly basis under the terms of the parties’ coal transportation agreement.

On July 30, 2008, we, along with Virginia Power, filed a separate suit against Norfolk Southern in the Circuit Court of the City of Richmond, Virginia, seeking to recover $4.9 million, plus interest, for unauthorized fuel surcharges improperly collected by Norfolk Southern under our coal transportation agreement. Our portion of this claim is $2.5 million, excluding interest. We believe that the fuel surcharge conflicts with the payment provisions specified in the agreement.

On September 25, 2008, Norfolk Southern filed its brief in support of demurrer and special plea. On October 16, 2008, we and Virginia Power filed our memorandum in opposition to Norfolk Southern’s demurrer and special plea. On October 23, 2008, Norfolk Southern filed its reply brief. On February 12, 2009, the judge issued a letter opinion asserting that certain facts were omitted in our original filing. On April 9, 2009, we filed an amended complaint to address certain factual assertions that the court deemed necessary. On July 24, 2009, the judge overruled Norfolk Southern’s demurrer and the parties are currently engaged in discovery.

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. See “Legal Proceedings” in Part II, Item 1 of our Quarterly Report on Form 10-Q for the quarter ended March 31, 2009 and June 30, 2009.

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, 2008, 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 5.

OTHER INFORMATION

Proposed Acquisition of Additional Service Territory by two of our Member Distribution Cooperatives

Power Supply Planning

As part of our on-going power supply planning process, we issued a Request for Power Supply Proposals (“RFP”) this summer. In October 2009, we signed a long-term power purchase and sale agreement with Exelon Generation (“Exelon”) in connection with our RFP process. Under the terms of this agreement, Exelon will begin supplying 200 MW of energy and capacity to us for ten years beginning in June 2010. We are continuing to evaluate additional proposals received as part of the RFP process.

ITEM 6.

EXHIBITS


3.1		Bylaws of Old Dominion Electric Cooperative Amended and Restated as of November 10, 2009

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

SIGNATURE

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


		OLD DOMINION ELECTRIC COOPERATIVE
		Registrant

Date: November 12, 2009		/S/ ROBERT L. KEES
		Robert L. Kees
		Senior Vice President and Chief Financial Officer
		(Principal Financial Officer)

EXHIBIT INDEX


Exhibit Number		Description of Exhibit

3.1		Bylaws of Old Dominion Electric Cooperative Amended and Restated as of November 10, 2009

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

Large accelerated filer

Accelerated filer

Non-accelerated filer

Smaller reporting company