Old Dominion Electric Cooperative 10-Q 2008 Q1 Quarterly report

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-Q

(Mark One)

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

For the quarterly period ended March 31, 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 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 is a large accelerated filer, an accelerated filer, a non-accelerated filer or a smaller reporting company. See definitions of “larger accelerated filer,” “accelerated filer” and “smaller reporting company” in Rule 12b-2 of the Exchange Act.

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

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

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

OLD DOMINION ELECTRIC COOPERATIVE

INDEX

	Page Number
PART I. Financial Information
Item 1. Financial Statements
Condensed Consolidated Balance Sheets – March 31, 2008 (Unaudited) and December 31, 2007	3
Condensed Consolidated Statements of Revenues, Expenses and Patronage Capital (Unaudited) – Three months ended March 31, 2008 and 2007	4
Condensed Consolidated Statements of Comprehensive Income (Unaudited)—Three months ended March 31, 2008 and 2007	4
Condensed Consolidated Statements of Cash Flows (Unaudited) – Three Months Ended March 31, 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 6. Exhibits	19

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OLD DOMINION ELECTRIC COOPERATIVE

PART 1. FINANCIAL INFORMATION

ITEM 1. FINANCIAL STATEMENTS

CONDENSED CONSOLIDATED BALANCE SHEETS

	March 31, 2008			December 31, 2007
	(in thousands)
	(unaudited)
ASSETS:
Electric Plant:
In service	$	1,555,078		$	1,541,970
Less accumulated depreciation		(564,636	)		(546,879	)
		990,442			995,091
Nuclear fuel, at amortized cost		12,305			13,869
Construction work in progress		26,537			22,767
Net Electric Plant		1,029,284			1,031,727
Investments:
Nuclear decommissioning trust		88,593			94,408
Lease deposits		183,833			183,559
Unrestricted investments and other		97,152			56,302
Total Investments		369,578			334,269
Current Assets:
Cash and cash equivalents		99,070			101,813
Accounts receivable		6,395			13,073
Accounts receivable - members		69,309			94,011
Fuel, materials and supplies		31,266			21,862
Deferred energy		18,149			21,091
Prepayments		4,368			3,593
Total Current Assets		228,557			255,443
Deferred Charges:
Regulatory assets		39,047			33,886
Other		24,960			16,422
Total Deferred Charges		64,007			50,308
Total Assets	$	1,691,426		$	1,671,747
CAPITALIZATION AND LIABILITIES:
Capitalization:
Patronage capital	$	312,074		$	309,112
Non-controlling interest		11,815			11,431
Long-term debt		787,945			787,028
Total Capitalization		1,111,834			1,107,571
Current Liabilities
Long-term debt due within one year		29,667			29,667
Accounts payable		77,280			89,855
Accounts payable - members		64,438			68,598
Accrued expenses		66,732			49,079
Total Current Liabilities		238,117			237,199
Deferred Credits and Other Liabilities
Asset retirement obligations		59,513			58,742
Obligations under long-term leases		183,551			183,567
Regulatory liabilities		68,090			53,653
Other		30,321			31,015
Total Deferred Credits and Other Liabilities		341,475			326,977
Commitments and Contingencies		—			—
Total Capitalization and Liabilities	$	1,691,426		$	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 March 31,
	2008			2007
	(in thousands)
Operating Revenues	$	259,235		$	228,710
Operating Expenses:
Fuel		35,670			33,093
Purchased power		174,965			166,316
Deferred energy		2,942			(16,119	)
Operations and maintenance		7,715			9,976
Administrative and general		10,005			8,092
Depreciation, amortization and decommissioning		9,635			9,417
Amortization of regulatory asset/(liability), net		(450	)		181
Accretion of asset retirement obligations		771			732
Taxes, other than income taxes		1,940			1,830
Total Operating Expenses		243,193			213,518
Operating Margin		16,042			15,192
Other Expense, net		(86	)		(43	)
Investment Income		2,327			3,008
Interest Charges, net		(14,701	)		(15,086	)
Net Margin Before Income Taxes and Non-Controlling Interest		3,582			3,071
Income Taxes		(235	)		(8	)
Non-Controlling Interest		(385	)		(30	)
Net Margin		2,962			3,033
Patronage Capital - Beginning of Period		309,112			293,077
Patronage Capital - End of Period	$	312,074		$	296,110

OLD DOMINION ELECTRIC COOPERATIVE

CONDENSED CONSOLIDATED STATEMENTS

OF COMPREHENSIVE INCOME (UNAUDITED)

	Three Months Ended March 31,
	2008		2007
	(in thousands)
Net Margin	$	2,962	$	3,033
Other Comprehensive Income:
Unrealized loss on derivative contracts (1)		—		(435	)
Other Comprehensive Income before Non-controlling interest		2,962		2,598
Less: Non-controlling interest in comprehensive income		—		435
Comprehensive Income	$	2,962	$	3,033

⁽¹⁾ Unrealized loss on derivative contracts net of taxes of $0.3 million for the three months ended March 31, 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)

	Three Months Ended March 31,
	2008			2007
	(in thousands)
Operating Activities:
Net Margin	$	2,962		$	3,033
Adjustments to reconcile net margins to net cash provided by operating activities:
Depreciation, amortization and decommissioning		9,635			9,417
Other noncash charges		3,417			3,038
Non-controlling interest		385			30
Amortization of lease obligations		3,036			2,886
Interest on lease deposits		(2,997	)		(2,810	)
Change in current assets		21,201			24,075
Change in deferred energy		2,942			(16,119	)
Change in current liabilities		918			5,222
Change in regulatory assets and liabilities		15,413			18,342
Change in deferred charges and credits		(8,542	)		(1,031	)
Net Cash Provided by Operating Activities		48,370			46,083
Financing Activities:
Obligations under long-term leases		(329	)		(274	)
Net Cash Used for Financing Activities		(329	)		(274	)
Investing Activities:
Purchases of available for sale securities		(45,800	)		(117,449	)
Proceeds from sale of available for sale securities		—			57,629
Decrease in other investments		4,629			9,045
Electric plant additions		(4,307	)		(4,619	)
Acquisition of transmission assets		(5,306	)		—
Net Cash Used for Investing Activities		(50,784	)		(55,394	)
Net Change in Cash and Cash Equivalents		(2,743	)		(9,585	)
Cash and Cash Equivalents - Beginning of Period		101,813			52,018
Cash and Cash Equivalents - End of Period	$	99,070		$	42,433

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

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OLD DOMINION ELECTRIC COOPERATIVE

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

1. In the opinion of our management, the accompanying unaudited condensed consolidated financial statements contain all adjustments, which include only normal recurring adjustments, necessary for a fair statement of our consolidated financial position as of March 31, 2008, and our consolidated results of operations, comprehensive income, and cash flows for the three months ended March 31, 2008 and 2007. The consolidated results of operations for the three months ended March 31, 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 $11.8 million and $11.4 million at March 31, 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”) on December 23, 2003, but are not regulated by the respective states’ public service commissions. An amendment to the formula was accepted for filing by FERC on February 19, 2005, subject to the outcome of our other pending FERC proceedings.

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. 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 March 31, 2008:

	March 31, 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)	$	88,593	$	88,593	$	—	$	—
Unrestricted investments and other (b)		26,137		27		—		26,110
Derivatives (c)		24,697		24,697		—		—
Total Financial Assets	$	139,427	$	113,317	$	—	$	26,110

(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 March 31, 2008, we had $33.8 million of principal invested in seven auction rate securities. As of March 31, 2008, we have an unrealized loss of $7.7 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 include 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 fiscal years, and interim periods within those fiscal years, beginning on or after December 15, 2008.

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 April 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 6.4%, effective April 1, 2008. This increase was implemented due to continued increases in our energy costs and to collect a portion of our deferred energy balance.

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OLD DOMINION ELECTRIC COOPERATIVE

ITEM 2. MANAGEMENT’S DISCUSSION AND ANALYSIS

OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS

Caution Regarding Forward-Looking Statements

Management’s Discussion and Analysis of Financial Condition and Results of Operations contains forward looking statements regarding matters that could have an impact on our business, financial condition, and future operations. These statements, based on our expectations and estimates, are not guarantees of future performance and are subject to risks, uncertainties, and other factors that could cause actual results to differ materially from those expressed in the forward looking statements. These risks, uncertainties, and other factors include, but are not limited to, general business conditions, increased competition in the electric utility industry, demand for energy, federal and state legislative and regulatory actions and legal and administrative proceedings, changes in and compliance with environmental laws and policies, general credit and capital market conditions, weather conditions, the cost of commodities used in our industry, and unanticipated changes in operating expenses and capital expenditures. Our actual results may vary materially from those discussed in the forward looking statements as a result of these and other factors. Any forward looking statement speaks only as of the date on which the statement is made, and we undertake no obligation to update any forward looking statement or statements to reflect events or circumstances after the date on which the statement is made even if new information becomes available or other events occur in the future.

Critical Accounting Policies

As of March 31, 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. These policies include the accounting for rate regulation, deferred energy, margin stabilization plan, 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 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 months ended March 31, 2008, were impacted by higher energy rates, changes in the fair value of our derivative contracts and higher capacity costs. Revenues were higher due to higher energy rates which were implemented in April and October of 2007 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. Due to changing conditions in the power markets, the fair value of our natural gas futures contracts increased resulting in changes to our regulatory liabilities which increased cash provided by operating activities. 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 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.

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The rates we charge our member distribution cooperatives for sales of energy and capacity are determined by a formulary rate accepted by the Federal Energy Regulatory Commission (“FERC”), which is intended to permit collection of revenues which will equal the sum of:

• all of our costs and expenses;

• 20% of our total interest charges; and

• additional equity contributions approved by our board of directors.

The formulary rate has three main components: a demand rate, a base energy rate and a fuel factor adjustment rate. The formulary rate identifies the cost components that we can collect through rates, but not the actual amounts to be collected. With limited minor exceptions, we can change our rates periodically to match the costs we have incurred and we expect to incur without seeking FERC approval.

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 months ended March 31, 2008 and 2007, were as follows:

	Three Months Ended March 31,
	2008		2007
	(in thousands)
Revenue from sales to:
Member distribution cooperatives	$	237,986	$	208,619
Non-members		21,249		20,091
Total revenues	$	259,235	$	228,710

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Our energy sales in megawatt hours (“MWh”) to our member distribution cooperatives and non-members for the three months ended March 31, 2008 and 2007, were as follows:

	Three Months Ended March 31,
	2008	2007
	(in MWh)
Energy sales to:
Member distribution cooperatives	3,208,577	3,088,879
Non-members	316,753	416,191
Total energy sales	3,525,330	3,505,070

Our energy sales in MWh to our member distribution cooperatives was 3.9% higher for the three months ended March 31, 2008, as compared to the same period in 2007, as a result of the additional service territory acquired by one of our member distribution cooperatives in January of 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, 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 months ended March 31, 2008 and 2007, were as follows:

	Three Months Ended March 31,
	2008		2007
	(in thousands)
Revenues from sales to member distribution cooperatives:
Base energy revenues	$	57,740	$	55,625
Fuel factor adjustment revenues		116,812		98,681
Total energy revenues		174,552		154,306
Demand (capacity) revenues		63,434		54,313
Total revenues from sales to member distribution cooperatives	$	237,986	$	208,619
Average costs to member distribution cooperatives (per MWh)	$	74.17	$	67.54

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 Months Ended March 31, 2008 compared to Three Months ended March 31, 2007

Total revenues from sales to our member distribution cooperatives for the three months ended March 31, 2008, increased $29.4 million, or 14.1%, over the same period in 2007, primarily as a result 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 8.9% higher during the three months ended March 31, 2008, as compared to the same period in 2007. We increased our fuel factor adjustment rate effective April 1, 2007, and October 1, 2007, resulting in an increase to our total energy rate of approximately 7.2% and 1.7%, respectively.

The capacity costs we incurred, and thus the capacity-related revenues we reflected pursuant to the formulary rate, for the

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three months ended March 31, 2008, as compared to the same period in 2007, increased $9.1 million, or 16.8%, related to increased capacity charges, and administrative and general expense. The increased capacity charges are 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 purchased additional capacity for capacity obligations that are not met by our owned generation resources. The increased administrative and general expense is related to increased charges for an incentive program at the North Anna Power Station (“North Anna”).

Our average costs to member distribution cooperatives per MWh increased $6.63 per MWh, or 9.8%, for the three months ended March 31, 2008, as compared to the same period in 2007. Energy revenues increased primarily as a result of the increase in our total energy rates related to increased fuel and purchased power costs. Demand (capacity) revenues increased as a result of an increase in the costs we incurred related to capacity costs and administrative and general costs.

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 increased by $1.2 million, or 5.8%, in the three months ended March 31, 2008. The increase in non-member revenue for the three months ended March 31, 2008, is due to an increase in the prices at which we sold excess energy to non-members partially offset by a decrease in the volume of excess energy sales. Excess energy is sold at the prevailing market price at the time of sale and is the result of changes in our purchased power portfolio, differences between actual and forecasted needs, as well as changes in market conditions.

Operating Expenses

We supply our member distribution cooperatives’ power requirements, consisting of capacity requirements and energy requirements, through (i) our interests in electric generating facilities which consist of a 50% interest in the Clover Power Station (“Clover”), an 11.6% interest in North Anna, our Louisa combustion turbine facility (“Louisa”), our Marsh Run combustion turbine facility (“Marsh Run”), our Rock Springs combustion turbine facility (“Rock Springs”), and our distributed generation facilities, and (ii) power purchases from third parties through power purchase contracts and forward, short-term and spot market energy purchases. Our energy supply for the three months ended March 31, 2008 and 2007, was as follows:

	Three Months Ended March 31,
	2008			2007
	(in MWh and percentages)
Generated:
Clover	806,197	22.7	%	883,720	24.5	%
North Anna	438,505	12.3		420,019	11.7
Louisa	17,431	0.5		13,236	0.4
Marsh Run	22,400	0.7		32,304	0.9
Rock Springs	704	—		809	—
Distributed generation	62	—		113	—
Total Generated	1,285,299	36.2		1,350,201	37.5
Purchased:
Total Purchased	2,268,593	63.8		2,246,498	62.5
Total Available Energy	3,553,892	100.0	%	3,596,699	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.

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 & 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;

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and as a result we will operate them only when the market price of energy makes their operation economical or when their operation is required by PJM for system reliability purposes. The output of Clover and North Anna for the three months ended March 31, 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 March 31,				Three Months Ended March 31,
	2008		2007		2008		2007
Unit 1	84.8	%	94.4	%	101.4	%	99.1	%
Unit 2	85.6		93.6		90.4		83.6
Combined	85.2		94.0		95.9		91.4

Clover.During the three months ended March 31, 2008, Clover Unit 1 was off-line for three days for unscheduled maintenance outages and Clover Unit 2 was off-line for three days for a scheduled maintenance outage. During the three months ended March 31, 2007, Clover Unit 1 was off-line for one day for scheduled maintenance outage and Clover Unit 2 was off-line for one day for an unscheduled maintenance outage.

North Anna.During the three months ended March 31, 2008, North Anna Unit 2 was off-line for nine days for unscheduled maintenance outages. During the three months ended March 31, 2007, North Anna Unit 1 was off-line for one day for an unscheduled maintenance outage and North Anna Unit 2 was off-line for 14 days for a scheduled refueling and maintenance outage.

Combustion turbine facilities.During the three months ended March 31, 2008 and 2007, the operational availability of our Louisa, Marsh Run and Rock Springs combustion turbine facilities was as follows:

	Three Months Ended March 31,
	2008		2007
Louisa	99.5	%	98.8	%
Marsh Run	95.8		99.7
Rock Springs	99.8		99.7

The Rock Springs combustion turbine facility was developed together with another participant, CED Rock Springs, LLC (“ConEd”). ODEC and ConEd each individually owned two units (a total of 336 MWs each) and 50% of the common facilities. On May 8, 2008, ConEd sold its share of the Rock Springs generating facility to North American Energy Alliance, LLC (“NAEA”) and the Rock Springs facility will be operated and maintained by North American Energy Alliance Operating Co., LLC, an affiliate of NAEA.

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The components of our operating expenses for the three months ended March 31, 2008 and 2007, were as follows:

	Three Months Ended March 31,
	2008			2007
	(in thousands)
Fuel	$	35,670		$	33,093
Purchased power		174,965			166,316
Deferred energy		2,942			(16,119	)
Operations and maintenance		7,715			9,976
Administrative and general		10,005			8,092
Depreciation, amortization and decommissioning		9,635			9,417
Amortization of regulatory asset/(liability), net		(450	)		181
Accretion of asset retirement obligations		771			732
Taxes, other than income taxes		1,940			1,830
Total Operating Expenses	$	243,193		$	213,518

Three Months Ended March 31, 2008 compared to Three Months Ended March 31, 2007:

Aggregate operating expenses increased $29.7 million, or 13.9%, for the three months ended March 31, 2008, as compared to the same period in 2007, primarily due to the change in deferred energy expense and the increase in purchased power, fuel, and administrative and general expense partially offset by a decrease in operations and maintenance expense.

Deferred energy expense changed $19.1 million for the three months ended March 31, 2008, as compared to the same period in 2007. During the three months ended March 31, 2008, we over-collected $2.9 million in energy costs; whereas in the three months ended March 31, 2007, we under-collected $16.1 million in energy costs.

Purchased power expense increased $8.6 million, or 5.2%, for the three months ended March 31, 2008, as compared to the same period in 2007, primarily due to increased capacity charges related to PJM’s implementation of RPM on June 1, 2007.

Fuel expense increased $2.6 million, or 7.8%, for the three months ended March 31, 2008, as compared to the same period in 2007, primarily due to the increase in the average cost of coal and coal transportation costs.

Administrative and general expense increased $1.9 million, or 23.6%, for the three months ended March 31, 2008, as compared to the same period in 2007, primarily due to increased costs at North Anna related to an incentive program and consulting costs related to possible future power resource options.

Operations and maintenance expense decreased $2.3 million, or 22.7%, as compared to the same period in 2007. In the first quarter of 2007 there were planned maintenance outages at North Anna and accordingly expense was higher.

Other Items

Investment Income.Investment income decreased $0.7 million, or 22.6%, for the three months ended March 31, 2008, as compared to the same period in 2007, primarily due to lower interest income on investments in our nuclear decommissioning trust fund partially offset by increased investment income related to cash and cash equivalents balance.

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.

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The major components of interest charges, net for the three months ended March 31, 2008 and 2007, were as follows:

	Three Months Ended March 31,
	2008			2007
	(in thousands)
Interest expense on long-term debt	$	(13,291	)	$	(13,613	)
Other		(1,519	)		(1,553	)
Total Interest Charges		(14,810	)		(15,166	)
Allowance for borrowed funds used during construction		109			80
Interest Charges, net	$	(14,701	)	$	(15,086	)

Net Margin.Our net margin, which is a function of our total interest charges, remained relatively flat for the three months ended March 31, 2008, as compared to the same period in 2007.

Financial Condition

The principal changes in our financial condition from December 31, 2007 to March 31, 2008, were caused by increases in investments – unrestricted investments and other, accrued expenses, and regulatory liabilities, and by decreases in accounts receivable – members and accounts payable. Investments – unrestricted investments and other increased $40.9 related to additional cash invested due to our margin stabilization balance and cash provided by operations. Accrued expenses increased $17.7 million primarily as a result of increased interest payable and accrued transportation costs related to our dispute with Norfolk Southern Railway Company (“Norfolk Southern”). Regulatory liabilities increased $14.4 million primarily due to the increase in the fair value of our natural gas futures contracts. Accounts receivable – members decreased $24.7 million due to lower sales in March 2008 as compared to December 2007. Accounts payable decreased $12.6 million related to decreased purchased power requirements in March 2008 as compared to December 2007.

Liquidity and Capital Resources

Operations. Historically, our operating cash flows have been sufficient to meet our short-term and long-term capital expenditures related to our existing generating facilities, our debt service requirements, and our ordinary business operations. During the first three months of 2008 and 2007, our operating activities provided cash flow of $48.4 million and $46.1 million, respectively. Operating activities in the first three months of 2008 were primarily impacted by changes in current assets, and regulatory assets and liabilities. Current assets changed $21.2 million primarily related to a decrease in the accounts receivable – members balance partially offset by an increase in fuel, materials and supplies which was driven by an increase in the coal inventory balance. Regulatory assets and liabilities changed $15.4 primarily due to the increase in the fair value of our natural gas futures contracts.

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 March 31, 2008, we had short-term committed variable rate lines of credit in an aggregate amount of $205.0 million. Additionally, we had two committed three-year revolving credit facilities totaling $125.0 million. At March 31, 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.

Investing Activities.Investing activities in the first three 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 March 31, 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 $26.1 million.

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

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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 December 31, 2007 and March 31, 2008 were rated “AA-”, “AA” or “AAA” by S&P, “Aa3”, “Aa2” or “Aaa” 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 March 31, 2008, the $7.7 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 first 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 matter. We have established a Disclosure Assessment Committee comprised of members from senior and middle management to assist in this evaluation. There have been no significant changes in our internal controls over financial reporting or in other factors that could significantly affect such controls during the past fiscal quarter.

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OLD DOMINION ELECTRIC COOPERATIVE

PART II. OTHER INFORMATION

ITEM 1. LEGAL PROCEEDINGS

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.

On December 18, 2007, NOVEC filed a motion advising the court that NOVEC and ODEC are engaged in settlement negotiations and requested that proceedings be held in abeyance. On January 11, 2008, the court granted this motion but required NOVEC and ODEC to file status reports every 60 days. Status reports were filed on March 11, 2008 and May 12, 2008, and indicated that NOVEC and ODEC continue to be engaged in settlement negotiations. The court has also ordered that NOVEC and ODEC file motions to govern further proceedings in the case within 30 days of the end of the settlement negotiations. For further description of our legal proceedings related to NOVEC, see Part 1, Item 3 of our 2007 Annual Report on Form 10-K.

Norfolk Southern

On January 15, 2008, ODEC, Virginia Power and 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. 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 Part 1, Item 3 of our 2007 Annual Report on Form 10-K.

FERC Proceedings Related to Potential Reorganization

The hearing was conducted on October 17 through 19, 2006, and the initial decision was issued on February 5, 2007, when the judge ruled in our favor on all material matters. NOVEC and FERC staff filed exceptions to the ruling on March 7, 2007. On March 27, 2007, we filed our response to the March 7, 2007, Northern Virginia Electric Cooperative (“NOVEC”) and FERC staff exceptions to the February 5, 2007, initial decision wherein the judge ruled in our favor on all material matters. On February 25, 2008, FERC affirmed the initial decision on all issues relating to the rate formulas except one. The only issue on which FERC disagreed with the initial decision related to a single phrase in a prior period adjustment clause. FERC found that this phrase allowed our board of directors too much discretion in the annual true-up between estimated and actual demand charges. The phrase at issue had been deleted in the partial settlement discussed above and has been deleted from the prior period adjustment clause. A compliance filing was filed on March 26, 2008, that described our rates since the effective date of the settlement (April 7, 2006), and included the classification of certain accounts, the units used in certain rate formula calculations, and reasons that no adjustment of past rates was needed. No parties intervened in the compliance filing and we are currently awaiting a final order from FERC.

For further description of our legal proceedings for the FERC Proceedings Related to Potential Reorganization, see Part 1, Item 3 of our 2007 Annual Report on Form 10-K.

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Other Matters

Other than legal proceedings arising out of the ordinary course of business, which management believes will not have a material adverse impact on our results of operations or financial condition, there is no other litigation pending or threatened against us.

ITEM 1A. RISK FACTORS

In addition to the other information set forth in this report, you should carefully consider the factors discussed in “Risk Factors” in Part I, Item 1A of our Annual Report on Form 10-K for the year ended December 31, 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.

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ITEM 6. EXHIBITS

31.1	Certification of the Chief Executive Officer pursuant to Rule 13a-14(a)
31.2	Certification of the Chief Financial Officer pursuant to Rule 13a-14(a)
32.1	Certification of the Chief Executive Officer pursuant to 18 U.S.C. § 1350
32.2	Certification of the Chief Financial Officer pursuant to 18 U.S.C. § 1350

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SIGNATURE

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

	OLD DOMINION ELECTRIC COOPERATIVE
	Registrant
Date: May 13, 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
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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