Old Dominion Electric Cooperative 10-Q 2008 Q3 Quarterly report

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-Q

(Mark One)

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

For the quarterly period ended September 30, 2008

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	(I.R.S. Employer
Incorporation or Organization)	Identification No.)
4201 Dominion Boulevard, Glen Allen, Virginia	23060
(Address of Principal Executive Offices)	(Zip Code)

(804) 747-0592

(Registrant’s Telephone Number, Including Area Code)

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

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

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

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

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

OLD DOMINION ELECTRIC COOPERATIVE

INDEX

		Page Number
PART I. Financial Information
Item 1.	Financial Statements
	Condensed Consolidated Balance Sheets – September 30, 2008 (Unaudited) and December 31, 2007	3
	Condensed Consolidated Statements of Revenues, Expenses and Patronage Capital (Unaudited) – Three and Nine months Ended September 30, 2008 and 2007	4
	Condensed Consolidated Statements of Comprehensive Income (Unaudited) - Three and Nine months Ended September 30, 2008 and 2007	4
	Condensed Consolidated Statements of Cash Flows (Unaudited) – Nine months Ended September 30, 2008 and 2007	5
	Notes to Condensed Consolidated Financial Statements	6
Item 2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	8
Item 3.	Quantitative and Qualitative Disclosures About Market Risk	16
Item 4.	Controls and Procedures	16
PART II. Other Information
Item 1.	Legal Proceedings	17
Item 1A.	Risk Factors	18
Item 5.	Other Information	18
Item 6.	Exhibits	20

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OLD DOMINION ELECTRIC COOPERATIVE

PART I. FINANCIAL INFORMATION

ITEM 1. FINANCIAL STATEMENTS

CONDENSED CONSOLIDATED BALANCE SHEETS

	September 30, 2008			December 31, 2007
	(in thousands)
	(unaudited)
ASSETS:
Electric Plant:
In service	$	1,556,752		$	1,541,970
Less accumulated depreciation		(583,852	)		(546,879	)
		972,900			995,091
Nuclear fuel, at amortized cost		9,759			13,869
Construction work in progress		40,787			22,767
Net Electric Plant		1,023,446			1,031,727
Investments:
Nuclear decommissioning trust		81,172			94,408
Lease deposits		189,425			183,559
Unrestricted investments and other		110,954			56,302
Total Investments		381,551			334,269
Current Assets:
Cash and cash equivalents		44,799			101,813
Accounts receivable		7,550			13,073
Accounts receivable-members		94,539			94,011
Fuel, materials and supplies		39,400			21,862
Deferred energy		27,856			21,091
Prepayments		3,193			3,593
Total Current Assets		217,337			255,443
Deferred Charges:
Regulatory assets		52,095			33,886
Other		14,980			16,422
Total Deferred Charges		67,075			50,308
Total Assets	$	1,689,409		$	1,671,747
CAPITALIZATION AND LIABILITIES:
Capitalization:
Patronage capital	$	317,983		$	309,112
Non-controlling interest		12,563			11,431
Long-term debt		789,784			787,028
Total Capitalization		1,120,330			1,107,571
Current Liabilities:
Long-term debt due within one year		29,667			29,667
Accounts payable		85,341			89,855
Accounts payable-members		59,687			68,598
Accrued expenses		73,958			49,079
Total Current Liabilities		248,653			237,199
Deferred Credits and Other Liabilities:
Asset retirement obligation		61,055			58,742
Obligations under long-term leases		189,408			183,567
Regulatory liabilities		40,410			53,653
Other		29,553			31,015
Total Deferred Credits and Other Liabilities		320,426			326,977
Commitments and Contingencies		—			—
Total Capitalization and Liabilities	$	1,689,409		$	1,671,747

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

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OLD DOMINION ELECTRIC COOPERATIVE

CONDENSED CONSOLIDATED STATEMENTS OF REVENUES,

EXPENSES AND PATRONAGE CAPITAL (UNAUDITED)

	Three Months Ended September 30,						Nine Months Ended September 30,
	2008			2007			2008			2007
	(in thousands)						(in thousands)
Operating Revenues	$	277,617		$	262,362		$	775,993		$	717,691
Operating Expenses:
Fuel		51,747			57,649			123,264			120,166
Purchased power		193,105			167,647			519,528			473,103
Deferred energy		(15,126	)		(12,951	)		(6,765	)		(19,857	)
Operations and maintenance		10,200			11,235			27,257			34,172
Administrative and general		9,325			8,811			28,451			25,424
Depreciation, amortization and decommissioning		9,660			9,365			28,963			28,189
Amortization of regulatory asset/(liability), net		(254	)		624			(564	)		1,517
Accretion of asset retirement obligations		771			732			2,313			2,197
Taxes other than income taxes		1,797			1,923			5,655			5,557
Total Operating Expenses		261,225			245,035			728,102			670,468
Operating Margin		16,392			17,327			47,891			47,223
Other (Expense)/Income, net		(64	)		(40	)		(183	)		(101	)
Investment Income		1,952			3,886			6,876			10,519
Interest Charges, net		(14,677	)		(15,496	)		(43,892	)		(45,783	)
Net Margin Before Income Taxes and Non-Controlling Interest		3,603			5,677			10,692			11,858
Income Taxes		(235	)		(132	)		(689	)		(157	)
Non-Controlling Interest		(391	)		(442	)		(1,132	)		(508	)
Net Margin		2,977			5,103			8,871			11,193
Patronage Capital - Beginning of Period		315,006			299,167			309,112			293,077
Patronage Capital - End of Period	$	317,983		$	304,270		$	317,983		$	304,270

OLD DOMINION ELECTRIC COOPERATIVE

CONDENSED CONSOLIDATED STATEMENTS

OF COMPREHENSIVE INCOME (UNAUDITED)

	Three Months Ended September 30,				Nine Months Ended September 30,
	2008		2007		2008		2007
	(in thousands)				(in thousands)
Net Margin	$	2,977	$	5,103	$	8,871	$	11,193
Other Comprehensive Income:
Unrealized (loss) on derivative contracts(1)		—		—		—		(435	)
Other Comprehensive Income Before Non-controlling interest		2,977		5,103		8,871		10,758
Less: Non-controlling interest in comprehensive income		—		—		—		435
Comprehensive income	$	2,977	$	5,103	$	8,871	$	11,193

(1) Unrealized (loss) on derivative contracts net of taxes of $0.3 million for the nine months ended September 30, 2007.

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

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OLD DOMINION ELECTRIC COOPERATIVE

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS (UNAUDITED)

	Nine Months Ended September 30,
	2008			2007
	(in thousands)
Operating Activities:
Net Margin	$	8,871		$	11,193
Adjustments to reconcile net margins to net cash provided by operating activities:
Depreciation, amortization and decommissioning		28,963			28,189
Other non-cash charges		10,021			8,997
Non-controlling interest		1,132			508
Amortization of lease obligations		9,133			8,684
Interest on lease deposits		(9,016	)		(8,460	)
Change in current assets		(12,143	)		25,486
Change in deferred energy		(6,765	)		(19,857	)
Change in current liabilities		11,452			67,279
Change in regulatory assets and liabilities		(16,467	)		17,499
Deferred charges and credits		2,054			1,763
Net Cash Provided by Operating Activities		27,235			141,281
Financing Activities:
Obligations under long-term leases		(423	)		(366	)
Net Cash Used for Financing Activities		(423	)		(366	)
Investing Activities:
Purchases of available for sale securities		(96,000	)		(266,147	)
Proceeds from sale of available for sale securities		24,000			176,779
Decrease in other investments		15,879			13,793
Electric plant additions		(22,399	)		(15,294	)
Settlement of litigation		—			3,000
Acquisition of transmission assets		(5,306	)		—
Net Cash Used for Investing Activities		(83,826	)		(87,869	)
Net Change in Cash and Cash Equivalents		(57,014	)		53,046
Cash and Cash Equivalents - Beginning of Period		101,813			52,018
Cash and Cash Equivalents - End of Period	$	44,799		$	105,064

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 September 30, 2008, and our consolidated results of operations, comprehensive income, and cash flows for the three and nine months ended September 30, 2008 and 2007. The consolidated results of operations for the three and nine months ended September 30, 2008, 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 2007 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 twelve 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.

In accordance with Financial Accounting Standards Board (“FASB”) Interpretation No. 46R, “Consolidation of Variable Interest Entities, an Interpretation of Accounting Research Bulletin No. 51” (the “Interpretation”), 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 $12.5 million and $11.4 million at September 30, 2008, and December 31, 2007, respectively. As TEC is 100% owned by our twelve member distribution cooperatives, its equity is presented as a non-controlling interest in our consolidated financial statements. Our non-controlling, 50% or less, ownership interest in other entities is recorded using the equity method of accounting.

Our rates are set periodically by a formula that was accepted for filing by the Federal Energy Regulatory Commission (“FERC”) with an effective date of February 19, 2005, 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

On January 15, 2008, ODEC, Virginia Electric and Power Company (“Virginia Power”) and Norfolk Southern Railway Company (“Norfolk Southern”) filed a stipulated calculation. A damage hearing was held on April 8, 2008, and the court took the issues presented at the hearing under advisement. On April 17, 2008, the court entered its final order in favor of Norfolk Southern. On July 8, 2008, we, along with Virginia Power filed a petition for appeal with the Supreme Court of Virginia and on July 29, 2008, Norfolk Southern filed its brief in opposition to our petition for appeal. We are pursuing an appeal with the Supreme Court of Virginia.

We recorded a liability related to the Norfolk Southern dispute and the current period charges are being collected through rates. If it is ultimately determined that we owe any such amounts to Norfolk Southern, the amounts are not expected to have a material impact on our financial position or results of operations due to our ability to collect such amounts through rates charged to our member distribution cooperatives. For further description of our legal proceedings for Norfolk Southern, see Note 15 of the Notes to Consolidated Financial Statements in our 2007 Annual Report on Form 10-K.

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4. New Accounting Pronouncements.

We adopted the provision of the Financial Accounting Standards Board (“FASB”) Statement No. 157, “Fair Value Measurements” (“SFAS No. 157”) on January 1, 2008. SFAS No. 157 clarifies that the term fair value is intended to mean a market-based measure, not an entity-specific measure and gives the highest priority to quoted prices in active markets in determining fair value. SFAS No. 157 requires disclosures about the extent to which companies measure financial assets and liabilities at fair value, the methods and assumptions used to measure fair value, and the effect of fair value measures on earnings. SFAS No. 157 is effective for fiscal years beginning after November 15, 2007.

The following table summarizes our financial assets and liabilities measured at fair value on a recurring basis (at least annually) as of September 30, 2008:

	September 30, 2008		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 (a)	$	81,172	$	81,172	$	—	$	—
Unrestricted investments and other (b)		13,573		37		—		13,536
Derivatives (c)		3,114		3,114		—		—
Total Financial Assets	$	97,859	$	84,323	$	—	$	13,536

(a) For additional information about our nuclear decommissioning trust see Note 7 of the Notes to Consolidated Financial Statements in our 2007 Annual Report on Form 10-K.

(b) Unrestricted investments and other includes investments that were available for sale. As of December 31, 2007 and September 30, 2008, we had $33.8 million of principal invested in seven auction rate securities. As of September 30, 2008, we have an unrealized loss of $20.3 million related to these auction rate securities which is recorded as a regulatory asset in accordance with SFAS No. 71. For additional information, see Notes 7 and 8 of the Notes to Consolidated Financial Statements in our 2007 Annual Report on Form 10-K.

(c) 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 2007 Annual Report on Form 10-K.

In December 2007, the FASB issued FASB Statement No. 160, “Noncontrolling Interests in Consolidated Financial Statements” (“SFAS No. 160”). SFAS No. 160 will change the presentation of non-controlling interest in our financial statements. SFAS No. 160 is effective for us on January 1, 2009. We are in the process of evaluating the new disclosure requirements under SFAS No. 160.

In March 2008, the FASB issued SFAS No. 161, “Disclosures about Derivative Instruments and Hedging Activities – An Amendment of SFAS No. 133” (“SFAS 161”). SFAS 161 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, SFAS 161 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. SFAS 161 is effective for us on January 1, 2009. We are in the process of evaluating the new disclosure requirements under SFAS 161.

5. Subsequent Event.

On October 8, 2008, our board of directors approved an increase to our fuel factor adjustment rate, resulting in an increase to our total energy rate of approximately 3.0% effective October 1, 2008. This increase was implemented due to our continued rising energy costs and differences between actual costs incurred and anticipated costs upon which our rates were based. Effective October 1, 2008, we increased the demand component of our rate approximately 13.4% in accordance with the revised 2008 budget that our Board of Directors approved. Increases or decreases in our budget automatically amend the demand component of our formulary rate.

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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 September 30, 2008, 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, 2007.

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 twelve member distribution cooperatives and a thirteenth 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, 2008, were impacted by higher energy rates and higher capacity costs. Revenues were higher due to higher energy rates, which were implemented in October of 2007 and April of 2008 to collect previously incurred but not collected costs and to provide for the collection of future anticipated costs. The increase in our energy rates was due to our continued rising fuel and purchased power costs and differences between actual costs incurred and anticipated future costs upon which our rates were based. Our capacity costs were higher due to the implementation of the reliability pricing model (“RPM”) by PJM Interconnection, LLC (“PJM)” on June 1, 2007.

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 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;

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• 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 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 energy 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 all of 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 of our energy costs without seeking FERC approval.

Capacity costs, which are primarily fixed costs, such as depreciation expense, interest expense, administrative and general expenses, capacity costs under RPM, transmission costs, and our margin requirements and additional amounts 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, 2008 and 2007, were as follows:

	Three Months Ended September 30,				Nine Months Ended September 30,
	2008		2007		2008		2007
	(in thousands)				(in thousands)
Revenues from sales to:
Member distribution cooperatives	$	257,154	$	237,855	$	716,270	$	645,910
Non-members		20,463		24,507		59,723		71,781
Total revenues	$	277,617	$	262,362	$	775,993	$	717,691
Our energy sales in megawatt hours (“MWh”) to our member distribution cooperatives and non-members for the three and nine months ended September 30, 2008 and 2007, were as follows:
	Three Months Ended September 30,				Nine Months Ended September 30,
	2008		2007		2008		2007
	(in MWh)				(in MWh)
Energy sales to:
Member distribution cooperatives		3,256,775		3,256,837		9,197,324		9,001,847
Non-members		306,448		443,453		916,258		1,377,592
Total energy sales		3,563,223		3,700,290		10,113,582		10,379,439

Our energy sales in MWh to our member distribution cooperatives were flat for the three months ended September 30, 2008, and increased 2.2% for the nine months ended September 30, 2008, as compared to the same periods in 2007. For the three months ended September 30, 2008, energy sales volume to our member distribution cooperatives was flat. Excluding the additional service territory acquired by one of our member distribution cooperatives in January of 2008, our energy sales volume decreased by 3.8%

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for the three months ended September 30, 2008, as compared to the same period in 2007. For the nine months ended September 30, 2008, our energy sales volume to our member distribution cooperatives increased 2.2%. Excluding the additional service territory acquired by one of our member distribution cooperatives in January of 2008, our energy sales volume to our member distribution cooperatives decreased by 1.5% for the nine months ended September 30, 2008, as compared to the same period in 2007.

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 period. 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, 2007.

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, 2008 and 2007, were as follows:

	Three Months Ended September 30,				Nine Months Ended September 30,
	2008		2007		2008		2007
	(in thousands)				(in thousands)
Revenues from sales to member distribution cooperatives:
Base energy revenues	$	58,604	$	58,459	$	165,579	$	161,959
Fuel factor adjustment revenues		130,072		115,835		355,870		308,784
Total energy revenues		188,676		174,294		521,449		470,743
Demand (capacity) revenues		68,478		63,561		194,821		175,167
Total revenues from sales to member distribution cooperatives	$	257,154	$	237,855	$	716,270	$	645,910
Average costs to member distribution cooperatives (per MWh)	$	78.96	$	73.03	$	77.88	$	71.75

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, 2007.

Three and Nine months Ended September 30, 2008 compared to Three and Nine months ended September 30, 2007:

Total revenues from sales to our member distribution cooperatives for the three and nine months ended September 30, 2008, increased $19.3 million, or 8.1%, and increased $70.4 million, or 10.9%, respectively, as compared to the same periods in 2007 primarily as a result of our higher energy rates and increased capacity costs (which are reflected in revenues in the period in which they are expensed).

Our total energy rate (including our base energy rate and our fuel factor adjustment rate) was 8.3% and 8.4% higher during the three and nine months ended September 30, 2008, respectively, as compared to the same periods in 2007. We increased our fuel factor adjustment rate effective October 1, 2007, and April 1, 2008 resulting in an increase to our total energy rate of approximately 1.7% and 6.4%, respectively. The fuel factor adjustment rate was increased to collect previously incurred but not collected energy costs and to collect projected increases in future energy costs.

The capacity costs we incurred, and thus the capacity-related revenues we reflected pursuant to the formulary rate, increased $4.9 million, or 7.7%, and $19.7 million, or 11.2%, for the three and nine months ended September 30, 2008, respectively, as compared to the same period in 2007, primarily due to increased purchased capacity charges related to PJM’s implementation of RPM on June 1, 2007. The purpose of RPM is to develop a longer-term pricing program for capacity resources, as well as provide localized pricing for capacity. It is designed to reduce capacity price volatility and the resulting investment risk to generators thus encouraging new investment in generation facilities. The value of capacity resources varies by location and RPM provides for the recognition of the locational value. We purchase additional capacity for capacity obligations that are not met by our owned generation resources.

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Our average costs to member distribution cooperatives per MWh increased $5.93, or 8.1%, and $6.13, or 8.5%, per MWh, for the three and nine months ended September 30, 2008, respectively, as compared to the same periods in 2007, primarily as a result of the increase in our total energy rates related to increased fuel and purchased power costs. Demand (capacity) revenues increased primarily as a result of an increase in the costs we incurred related to capacity costs.

On October 8, 2008, our board of directors approved an increase to our fuel factor adjustment rate, resulting in an increase to our total energy rate of approximately 3.0% effective October 1, 2008. This increase was implemented due to our continued rising energy costs and differences between actual costs incurred and anticipated costs upon which our rates were based. Effective October 1, 2008, we increased the demand component of our rate approximately 13.4% in accordance with the revised 2008 budget that our Board of Directors approved. Increases or decreases in our budget automatically amend the demand component of our formulary rate.

Sales to Non-Members.Sales to non-members consist of sales of excess purchased and generated energy. We primarily sell excess energy to PJM under its rates for providing energy imbalance services. Non-member revenue decreased by $4.0 million or 16.5%, and $12.1 million, or 16.8%, in the three and nine months ended September 30, 2008, respectively, as compared to the same periods in 2007. The decrease is primarily due to a decrease in the volume of excess energy sales partially offset by an increase in the prices at which we sold excess energy to non-members. The volume of excess energy sales decreased 30.9% and 33.5% for the three and nine months ended September 30, 2008, respectively, as compared to the same periods in 2007. 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 energy 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 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 spot purchases of power in the open market. Our energy supply for the three and nine months ended September 30, 2008 and 2007, was as follows:

	Three Months Ended September 30,						Nine Months Ended September 30,
	2008			2007			2008			2007
	(in MWh and percentages)						(in MWh and percentages)
Generated:
Clover	729,621	20.4	%	855,394	23.0	%	2,117,986	20.9	%	2,475,009	23.5	%
North Anna	420,279	11.7		389,675	10.5		1,320,314	13.0		1,209,251	11.4
Louisa	83,360	2.3		150,743	4.1		145,543	1.4		190,543	1.8
Marsh Run	71,068	2.0		181,723	4.9		144,866	1.4		249,212	2.4
Rock Springs	34,216	1.0		28,482	0.8		51,019	0.5		45,014	0.4
Distributed generation	128	—		489	—		283	—		646	—
Total generated	1,338,672	37.4		1,606,506	43.3		3,780,011	37.2		4,169,675	39.5
Purchased:
Total purchased	2,237,171	62.6		2,101,477	56.7		6,390,010	62.8		6,377,778	60.5
Total available energy	3,575,843	100.0	%	3,707,983	100.0	%	10,170,021	100.0	%	10,547,453	100.0	%

We satisfy the majority of our member distribution cooperatives’ capacity requirements and less than 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.

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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. When either Clover or North Anna is off-line, we must purchase replacement energy from either Virginia Electric and Power Company (“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. 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. The output of Clover and North Anna for the three and nine months ended September 30, 2008 and 2007, 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,
	2008		2007		2008		2007		2008		2007		2008		2007
Unit 1	77.1	%	88.2	%	74.2	%	86.4	%	100.2	%	74.8	%	101.0	%	91.4	%
Unit 2	76.3		93.0		75.1		87.4		81.0		90.8		90.8		82.0
Combined	76.7		90.6		74.7		86.9		90.6		82.8		95.9		86.7

The scheduled and unscheduled outages of Clover for the three and nine months ended September 30, 2008 and 2007, as measured in days was 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,
	2008	2007	2008	2007	2008	2007	2008	2007
	(in days)				(in days)
Unit 1	—	—	18.5	13.4	1.0	—	4.3	0.3
Unit 2	—	3.5	14.5	16.9	2.1	0.1	2.7	3.4
Combined	—	3.5	33.0	30.3	3.1	0.1	7.0	3.7
The scheduled and unscheduled outages of North Anna for the three and nine months ended September 30, 2008 and 2007, as measured in days was 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,
	2008	2007	2008	2007	2008	2007	2008	2007
	(in days)				(in days)
Unit 1	—	22.0	—	22.0	—	—	—	1.0
Unit 2	17.0	—	17.0	35.8	—	9.1	8.7	9.5
Combined	17.0	22.0	17.0	57.8	—	9.1	8.7	10.5

Combustion turbine facilities.During the three and nine months ended September 30, 2008, and 2007, 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,
	2008		2007		2008		2007
Louisa	96.5	%	99.0	%	97.7	%	95.7	%
Marsh Run	99.9		100.0		98.3		98.7
Rock Springs	99.5		99.9		99.4		99.2

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The components of our operating expenses for the three and nine months ended September 30, 2008 and 2007, were as follows:

	Three Months Ended September 30,						Nine Months Ended September 30,
	2008			2007			2008			2007
	(in thousands)						(in thousands)
Fuel	$	51,747		$	57,649		$	123,264		$	120,166
Purchased power		193,105			167,647			519,528			473,103
Deferred energy		(15,126	)		(12,951	)		(6,765	)		(19,857	)
Operations and maintenance		10,200			11,235			27,257			34,172
Administrative and general		9,325			8,811			28,451			25,424
Depreciation, amortization and decommissioning		9,660			9,365			28,963			28,189
Amortization of regulatory asset/(liability), net		(254	)		624			(564	)		1,517
Accretion of asset retirement obligations		771			732			2,313			2,197
Taxes other than income taxes		1,797			1,923			5,655			5,557
Total Operating Expenses	$	261,225		$	245,035		$	728,102		$	670,468

Aggregate operating expenses increased $16.2 million, or 6.6%, and $57.6 million, or 8.6%, for the three and nine months ended September 30, 2008, respectively, as compared to the same periods in 2007, primarily due to changes in purchased power expense, deferred energy, fuel expense and operations and maintenance expense.

Purchased power expense increased $25.5 million, or 15.2%, and $46.4 million, or 9.8%, for the three and nine months ended September 30, 2008, respectively, as compared to the same periods in 2007, primarily due to increased capacity charges related to PJM’s implementation of RPM on June 1, 2007, and due to an increase in the average cost of purchased power. The increase in the average cost of purchased power is reflective of the timing of our forward energy purchases relative to the prevailing market prices at the time of those purchases.

Deferred energy expense decreased $2.2 million, or 16.8%, and increased $13.1 million, or 65.9%, for the three and nine months ended September 30, 2008, respectively, as compared to the same periods in 2007. During the three months ended September 30, 2008, we under-collected $15.1 million in energy costs; whereas in the three months ended September 30, 2007, we under-collected $13.0 million in energy costs. During the nine months ended September 30, 2008, we under-collected $6.7 million in energy costs as compared to an under-collection of $19.9 million for the same period in 2007.

Fuel expense decreased $5.9 million, or 10.2%, for the three months ended September 30, 2008, as compared to the same period in 2007 primarily due to decreased generation and the resulting decreased usage of fuel partially offset by the increase in the average price of fuel. Fuel expense increased $3.1 million, or 2.6%, for the nine months ended September 30, 2008, as compared to the same period in 2007, primarily due to the increase in the average price of fuel partially offset by decreased usage of fuel due to decreased generation.

Operations and maintenance expense decreased $1.0 million, or 9.2%, and $6.9 million, or 20.2%, for the three and nine months ended September 30, 2008, respectively, as compared to the same periods in 2007. The decrease in operations and maintenance expense was primarily related to fewer scheduled maintenance and refueling outages at our operating facilities during 2008 as compared to 2007.

Other Items

Investment Income.Investment income decreased $1.9 million, or 49.7%, and $3.6 million, or 34.6%, for the three and nine months ended September 30, 2008, respectively, as compared to the same periods in 2007, primarily due to lower interest income on investments in our nuclear decommissioning trust fund.

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 Railway Company (“Norfolk Southern”), and capitalized interest. Our total interest charges remained relatively flat for the three and nine months ended September 30, 2008, as compared to the same periods in 2007.

13

The major components of interest charges, net for the three and nine months ended September 30, 2008 and 2007, were as follows:

	Three Months Ended September 30,						Nine Months Ended September 30,
	2008			2007			2008			2007
	(in thousands)						(in thousands)
Interest expense on long-term debt	$	(13,269	)	$	(13,622	)	$	(39,789	)	$	(40,858	)
Other		(1,610	)		(1,896	)		(4,564	)		(5,110	)
Total Interest Charges		(14,879	)		(15,518	)		(44,353	)		(45,968	)
Allowance for borrowed funds used during construction		202			22			461			185
Interest Charges, net	$	(14,677	)	$	(15,496	)	$	(43,892	)	$	(45,783	)

Net Margin.Our net margin, which is a function of our total interest charges plus any additional equity contributions approved by our board of directors, decreased $2.1 million, or 41.7%, and decreased $2.3 million, or 20.7 % for the three and nine months ended September 30, 2008, as compared to the same periods in 2007. Our net margin for the three and nine months ended September 30, 2007, included an equity contribution of $2.0 million.

Financial Condition

The principal changes in our financial condition from December 31, 2007 to September 30, 2008, were caused by increases in investments—unrestricted investments and other, accrued expenses, regulatory assets, fuel, materials and supplies and deferred energy. These increases were slightly offset by decreases in regulatory liabilities, investments—nuclear decommissioning trust and accounts payable—members. Investments—unrestricted investments and other increased $54.7 related to additional cash invested due to cash provided by operations. Accrued expenses increased $24.9 million as a result of the increased accrued interest, property taxes and accrued transportation costs. Regulatory assets increased $18.2 million as a result of the increase in the deferred loss on auction rate securities. See “Liquidity and Capital Resources – Auction Rate Securities” for further discussion of our auction rate securities. Fuel, materials and supplies increased $17.5 million related to an increase in our coal inventory as well as diesel fuel. Deferred energy changed $6.8 million due to the under-collection of energy costs in the first nine months of 2008. Regulatory liabilities decreased $13.2 million as a result of the decrease in the fair value of our natural gas futures contracts. Investments—nuclear decommissioning trust decreased $13.2 million as a result of the decrease in the fair value of the funds. Accounts payable—members decreased $8.9 million due to a reduction in the amount due our member distribution cooperatives under our margin stabilization plan. For additional discussion of our margin stabilization plan, see Item 7 “Management’s Discussion and Analysis of Financial Condition and Results of Operations – Critical Accounting Policies – Margin Stabilization Plan” in our Annual Report on Form 10-K for the fiscal year ended December 31, 2007.

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 2008 and 2007, our operating activities provided cash flow of $27.2 million and $141.3 million, respectively. Operating activities in the first nine months of 2008 were primarily impacted by changes in regulatory assets and liabilities, current assets and current liabilities. Changes in regulatory assets and liabilities, which caused a $16.5 million outflow, were primarily related to the increase in the deferred loss on our auction rate securities. See “Liquidity and Capital Resources – Auction Rate Securities” for further discussion of our auction rate securities. Current assets increased by $12.1 million as a result of the $17.5 million increase in fuel, materials and supplies primarily as a result of increased quantities of coal as compared to year end, partially offset by a $5.5 million decrease in accounts receivable. Current liabilities increased $11.5 million primarily related to an $11.4 million increase in accrued interest and a $10.9 million increase in accrued transportation costs, partially offset by an $8.9 million decrease in accounts payable—members.

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, 2008, 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 $125.0 million. At September 30, 2008 and 2007, we had no short-term borrowings or letters of credit outstanding under any of these arrangements. We expect that we will renew the majority of these working capital lines of credit and revolving credit facilities as they expire.

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Investing Activities.Investing activities in the first nine months of 2008 were primarily impacted by activity related to available for sale securities, electric plant additions for our generating facilities, the acquisition of approximately 100 miles of transmission lines located on the Eastern Shore of Virginia from Delmarva Power and Light, and interest earned on investments—unrestricted investments and other, and cash and cash equivalents.

Auction Rate Securities.As of December 31, 2007 and September 30, 2008, we had $33.8 million of principal invested in seven auction rate securities (“ARS’”). On these respective dates, the estimated fair value of our ARS was $31.9 million and $13.5 million. The estimated fair value of our ARS decreased significantly from June 30, 2008, primarily due to the negative credit watch placed on the monoline insurers resulting in the decrease in value of securities insured by them. Additionally, market yields for securities similar to ARS have increased by 100 to 300 basis points which has caused further declines in the value of our ARS.

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 to LIBOR, which, depending on the security, has ranged from 100 basis points to 200 basis points. All of the ARS we owned at September 30, 2008, were rated “A-”, “A”, or “AA” by Standard & Poor’s Ratings Services (“S&P”), “Baa2”,”Baa1”, “A3”, “A2”, “Aa3”, or “Aa2” by Moody’s Investors Service (“Moody’s”), or “AA” by Fitch, Inc. All of the ARS we owned at November 7, 2008, were rated “A-”, “A”, or “AA” by S&P, “Ba1”, “Baa2”,”Baa1”, “A2”, or “Aa2” by Moody’s or “AA” by Fitch, Inc.

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.

At September 30, 2008, the $20.3 million difference between the principal of our ARS and the estimated fair value of our ARS was accounted for as a regulatory asset in accordance with SFAS No. 71. Future changes in the estimated fair value of our ARS will be accounted for in a similar manner. The estimated fair value of our ARS are included in investments – unrestricted investments and other on our Condensed Consolidated Balance Sheet and are classified as available for sale.

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OLD DOMINION ELECTRIC COOPERATIVE

ITEM 3. QUANTITATIVE AND QUALITATIVE

DISCLOSURES ABOUT MARKET RISK

No material changes occurred in our exposure to market risk during the third quarter of 2008.

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.

16

OLD DOMINION ELECTRIC COOPERATIVE

PART II. OTHER INFORMATION

ITEM 1. LEGAL PROCEEDINGS

Northern Virginia Electric Cooperative (“NOVEC”)

Over the past several years, we have had discussions and negotiations with NOVEC about changing the nature of its wholesale power contract from an all-requirements contract to a partial-requirements contract. See Part 1, Item 1 of our Annual Report on Form 10-K for the fiscal year ended December 31, 2007.

On August 15, 2008, ODEC and NOVEC entered into a settlement, release and withdrawal agreement (the “Agreement”) to end their power supply arrangement and to resolve all outstanding disputes between them. The Agreement, which is subject to regulatory approval, provides for the termination of NOVEC’s wholesale power contract with ODEC and the withdrawal of NOVEC as a member of ODEC effective as of the closing date. Under the Agreement, ODEC agreed to make a payment of $50.0 million to NOVEC at the closing date. Under the agreement, both ODEC and NOVEC will release each other from all claims against the other. See Part 1, Item 3 – “Legal Proceedings” in our 2007 Annual Report on Form 10-K for further discussion of our legal proceedings with NOVEC and see Part 2, Item 1 – “Legal Proceedings” in our 2008 Form 10-Q for the Quarterly Period Ending March 31, 2008 and the Quarterly Period Ending June 30, 2008. Also, see Item 5 – “Other Information” in our 2008 Form 10-Q for the Quarterly Period Ending June 30, 2008. NOVEC further releases any right, title or interest it has in ODEC’s equity or assets, including generating facilities. We currently anticipate that the closing date of this transaction will be on or about December 31, 2008, subject to the receipt of necessary regulatory approvals.

Norfolk Southern

We are a party to a contractual dispute with a fuel transportation supplier, Norfolk Southern. See Part 1, Item 3 of our Annual Report on Form 10-K for the fiscal year ended December 31, 2007. On January 15, 2008, ODEC, Virginia Power and Norfolk Southern filed a stipulated calculation in the case. A damage hearing was held on April 8, 2008, and the court entered its final order on April 17, 2008 in favor of Norfolk Southern. On July 8, 2008, we, along with Virginia Power, filed a petition for appeal with the Supreme Court of Virginia and on July 29, 2008, Norfolk Southern filed its brief in opposition to our petition for appeal. Oral arguments on the petition for appeal are scheduled with the Supreme Court of Virginia on December 3, 2008.

We recorded a liability related to the Norfolk Southern dispute and the current period charges are being collected through rates. If it is ultimately determined that we owe any such amounts to Norfolk Southern, the amounts are not expected to have a material impact on our financial position or results of operations due to our ability to collect such amounts through rates charged to our member distribution cooperatives.

On July 30, 2008, we, along with Virginia Power, filed 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. Our portion of this amount is $2.45 million, plus interest. We believe that the fuel surcharge conflicts with the payment provisions specified in the agreement that provides for the amounts payable for coal transportation services to Clover and the fuel surcharge is therefore inapplicable.

On September 25, 2008, Norfolk Southern filed its brief in support of demurrer and special plea. On October 16, 2008, ODEC and Virginia Power filed their memorandum in opposition to Norfolk Southern’s demurrer and special plea. On October 23, 2008 Norfolk Southern filed its reply brief. We are currently awaiting the hearing schedule.

FERC Proceedings Related to Potential Reorganization

We have been engaged in proceedings at FERC relating to approvals for a potential reorganization. See Part 1, Item 3 of our Annual Report on Form 10-K for the fiscal year ended December 31, 2007. On July 1, 2008, FERC issued an order accepting the revised tariff sheets for filing, effective on the date of the consummation of ODEC’s potential reorganization and these proceedings are concluded.

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, 2008 and June 30, 2008.

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ITEM 1A. RISK FACTORS

In addition to the other information set forth in this report, careful consideration should be given to 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, 2007, 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

Lease of Clover Unit 1

In March 1996, we entered into a lease with an owner trust for the benefit of an investor in which we leased our interest in the Clover Power Station Unit 1 (“Clover Unit 1”) and related common facilities, subject to the lien of the Indenture, for a term extendable by the owner trust up to the full productive life of Clover Unit 1, and simultaneously entered into an approximately 21.8 year lease of the interest back to us. See Part II, Item 7—Management’s Discussion and Analysis of Financial Condition and Results of Operations—Liquidity and Capital Resources—Significant Contingent Obligations and Off-Balance Sheet Arrangements in the Annual Report on Form 10-K for the fiscal year ended December 31, 2007. In connection with the lease and leaseback of Clover Unit 1, we issued a zero-coupon bond which was pledged as collateral to the trust formed for the benefit of the investor. The zero-coupon bond was insured by Ambac Assurance Corporation (“Ambac”). Under the terms of the arrangements relating to the transaction, we agreed to replace this collateral if the claims paying ability of Ambac fell below “AAA” as rated by S&P or “Aaa” as rated by Moody’s. On June 5, 2008, S&P lowered its rating of Ambac to “AA.” We have been in discussions with the investor regarding the replacement or enhancement of this collateral by the date indicated by the investor in its notice to us, November 19, 2008. We are continuing discussions with the investor regarding a resolution of this matter.

Lease of Clover Unit 2

In 1996, we entered into a lease transaction with respect to our interest in Clover Unit 2 (the “Lease”) pursuant to a Participation Agreement, dated as of July 1, 1996, with Clover Unit 2 Generating Trust, Wilmington Trust Company, not in its individual capacity but solely as trustee of the Clover Unit 2 Generating Trust (the “Trust”), an investor in the Trust (the “Investor”) and Utrecht America Finance Co. (as amended, the “Participation Agreement”). See “Properties – Clover – Lease of Clover Unit 2” in Item 2 and “Management’s Discussion and Analysis of Financial Condition and Results of Operations – Off-Balance Sheet Arrangements” in Item 7 of our Annual Report on Form 10-K for the fiscal year ended December 31, 2007 for additional description of the Lease. As part of the Lease, AMBAC Indemnity Corporation, currently known as Ambac Assurance Corporation (“Ambac”), issued a surety bond supporting a portion of our obligations relating to the Lease. The amount of the obligations enhanced by this surety bond currently is approximately $91.1 million. This amount declines to zero by 2020.

We received notice from the Investor that it construed the Participation Agreement to obligate us to replace the outstanding Ambac surety bond (the “Surety Bond”) with a new surety bond issued by an entity with a claims paying ability rated “AAA” by Standard & Poor’s Ratings Services (“S&P”) and “Aaa” by Moody’s Investors Service (“Moody’s”). S&P and Moody’s rate Ambac’s claims paying ability “AA” and “Aa3”, respectively. We do not agree that the operative agreements relating to the Lease obligate us to replace the outstanding Ambac surety bond with a replacement surety bond or any other form of credit enhancement (collectively referred to as “Replacement Credit Enhancement”).

On October 10, 2008, we entered into a Waiver and Forbearance Agreement, dated as of October 9, 2008, with the Investor and the Trust (the “Waiver”). The Waiver provides that the Investor and the Trust waive compliance by us with the provision in the Participation Agreement which in the event the Surety Bond ceased to satisfy the requirements of the Participation Agreement would obligate us to provide Replacement Credit Enhancement, and agrees to forbear from delivering any notice of default with respect to, or exercising any remedies until five business days after the earliest of December 5, 2008, and the occurrence of other specified events, including a downgrade of Ambac’s claims paying ability below “A” by S&P or “A” by Moody’s. On November 5, 2008, Ambac’s claims paying ability was downgraded below “A” by Moody’s. On November 10, 2008, we entered into an amendment to the Waiver with the Investor which waived our obligation to provide Replacement Credit Enhancement as a result of a downgrade of Ambac’s claims paying ability by S&P or Moody’s. We continue to work with the Investor towards a resolution of this matter.

The Waiver does not obligate us, the Investor or the Trust to waive any of our or their positions regarding whether we are obligated to provide Replacement Credit Enhancement.

18

Wholesale Power Contracts

On September 2, 2008, ODEC entered into a Second Amended and Restated Wholesale Power Contract with eleven of our member distribution cooperatives which provides for the extension and modification of their respective existing wholesale power contracts. The eleven member distribution cooperatives are A&N Electric Cooperative, BARC Electric Cooperative, Choptank Electric Cooperative, Inc., Community Electric Cooperative, Delaware Electric Cooperative, Inc., Mecklenburg Electric Cooperative, Northern Neck Electric Cooperative, Prince George Electric Cooperative, Rappahannock Electric Cooperative, Shenandoah Valley Electric Cooperative, and Southside Electric Cooperative. The terms and conditions of the Second Amended and Restated Wholesale Power Contracts include the extension of their existing restated and amended wholesale power contracts until January 1, 2054; the ability for these member distribution cooperatives to receive up to the greater of five percent of their power requirements or five megawatts from owned generation or other suppliers; and the ability for these member distribution cooperatives to purchase additional power from other suppliers in limited circumstances following approval by our board of directors. The Second Amended and Restated Wholesale Power Contracts continue to provide for the recovery of all of ODEC’s costs under its formulary rate. See “Factors Affecting Results—Formulary Rate” in Part II, Item 7 of our Annual Report on Form 10-K for the fiscal year ended December 31, 2007 for a description of the formulary rate.

The Second Amended and Restated Wholesale Power Contract with eleven of our member distribution cooperatives has been approved by our board of directors and the boards of directors of the applicable member distribution cooperatives. We currently anticipate that the agreements will become effective on or about January 1, 2009, subject to the receipt of necessary regulatory approvals.

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ITEM 6. EXHIBITS

10.1	Settlement, Release and Withdrawal Agreement between Old Dominion Electric Cooperative and Northern Virginia Electric Cooperative dated August 15, 2008.
10.2	Second Amended and Restated Wholesale Power Contract between Old Dominion Electric Cooperative and A&N Electric Cooperative, entered into on September 2, 2008, and effective January 1, 2009.
10.3	Schedule of other Second Amended and Restated Wholesale Power Contracts omitted and the material details in which such documents differ from Exhibit 10.2 noted above.
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: November 11, 2008	/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
10.1	Settlement, Release and Withdrawal Agreement between Old Dominion Electric Cooperative and Northern Virginia Electric Cooperative dated August 15, 2008.
10.2	Second Amended and Restated Wholesale Power Contract between Old Dominion Electric Cooperative and A&N Electric Cooperative, entered into on September 2, 2008, and effective January 1, 2009.
10.3	Schedule of other Second Amended and Restated Wholesale Power Contracts omitted and the material details in which such documents differ from Exhibit 10.2 noted above.
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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