Old Dominion Electric Cooperative 10-Q 2007 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, 2007

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, or a non-accelerated filer. See definition of “accelerated filer and large accelerated filer” in Rule 12b-2 of the Exchange Act.

Larger accelerated filer  ¨    Accelerated filer  ¨    Non-accelerated filer  x

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, 2007 (Unaudited) and December 31, 2006	3
Condensed Consolidated Statements of Revenues, Expenses and Patronage Capital (Unaudited) – Three months ended March 31, 2007 and 2006	4
Condensed Consolidated Statements of Comprehensive Income (Unaudited) - Three months ended March 31, 2007 and 2006	4
Condensed Consolidated Statements of Cash Flows (Unaudited) – Three Months Ended March 31, 2007 and 2006	5
Notes to Condensed Consolidated Financial Statements	6
Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations	10
Item 3. Quantitative and Qualitative Disclosures About Market Risk	17
Item 4. Controls and Procedures	17
PART II. Other Information
Item 1. Legal Proceedings	18
Item 1A. Risk Factors	18
Item 5. Other Information	18
Item 6. Exhibits	20

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OLD DOMINION ELECTRIC COOPERATIVE

PART 1. FINANCIAL INFORMATION

ITEM 1. FINANCIAL STATEMENTS

CONDENSED CONSOLIDATED BALANCE SHEETS

	March 31, 2007			December 31, 2006
	(in thousands)
	(unaudited)
ASSETS:
Electric Plant:
In service	$	1,527,774		$	1,527,672
Less accumulated depreciation		(519,067	)		(509,306	)
		1,008,707			1,018,366
Nuclear fuel, at amortized cost		7,043			8,381
Construction work in progress		24,402			20,342
Net Electric Plant		1,040,152			1,047,089
Investments:
Nuclear decommissioning trust		92,607			91,050
Lease deposits		172,681			171,585
Other		74,179			24,321
Total Investments		339,467			286,956
Current Assets:
Cash and cash equivalents		42,433			52,018
Accounts receivable		3,199			4,071
Accounts receivable - deposits		—			23,600
Accounts receivable - members		92,976			94,136
Fuel, materials and supplies		31,546			30,585
Deferred energy		31,033			14,914
Prepayments		4,631			4,035
Total Current Assets		205,818			223,359
Deferred Charges:
Regulatory assets		34,083			49,738
Other		20,535			20,267
Total Deferred Charges		54,618			70,005
Total Assets	$	1,640,055		$	1,627,409
CAPITALIZATION AND LIABILITIES:
Capitalization:
Patronage capital	$	296,110		$	293,077
Non-controlling interest		10,588			10,993
Long-term debt		814,120			813,264
Total Capitalization		1,120,818			1,117,334
Current Liabilities
Long-term debt due within one year		22,917			22,917
Accounts payable		68,911			87,844
Accounts payable-members		56,433			48,220
Accrued expenses		51,432			35,767
Total Current Liabilities		199,693			194,748
Deferred Credits and Other Liabilities
Asset retirement obligation		56,545			55,812
Obligations under long-term leases		175,103			174,205
Regulatory liabilities		54,824			51,497
Other		33,072			33,813
Total Deferred Credits and Other Liabilities		319,544			315,327
Commitments and Contingencies		—			—
Total Capitalization and Liabilities	$	1,640,055		$	1,627,409

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,
	2007			2006
	(in thousands)
Operating Revenues	$	228,710		$	203,461
Operating Expenses:
Fuel		33,093			24,465
Purchased power		166,316			161,364
Deferred energy		(16,119	)		(27,682	)
Operations and maintenance		9,976			8,060
Administrative and general		8,092			8,287
Depreciation, amortization and decommissioning		9,417			9,660
Amortization of regulatory asset/(liability), net		181			195
Accretion of asset retirement obligations		732			651
Taxes other than income taxes		1,830			1,560
Total Operating Expenses		213,518			186,560
Operating Margin		15,192			16,901
Other Expense, net		(43	)		(100	)
Investment Income		3,008			2,075
Interest Charges, net		(15,086	)		(14,922	)
Net Margin Before Income Taxes and Non-Controlling Interest		3,071			3,954
Income Taxes		(8	)		(385	)
Non-Controlling Interest		(30	)		(579	)
Net Margin		3,033			2,990
Patronage Capital - Beginning of Period		293,077			271,833
Patronage Capital - End of Period	$	296,110		$	274,823

OLD DOMINION ELECTRIC COOPERATIVE

CONDENSED CONSOLIDATED STATEMENTS

OF COMPREHENSIVE INCOME (UNAUDITED)

	Three Months Ended March 31,
	2007			2006
	(in thousands)
Net Margin	$	3,033		$	2,990
Other Comprehensive Income:
Unrealized loss on derivative contracts (1)		(435	)		(12,504	)
Other Comprehensive Income (Loss) before Non-controlling interest		2,598			(9,514	)
Less: Non-controlling interest in comprehensive income		435			12,504
Comprehensive Income	$	3,033		$	2,990

⁽¹⁾ Unrealized loss on derivative contracts net of taxes of $0.3 and $8.0 million for the three months ended March 31, 2007 and March 31, 2006, respectively.

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,
	2007			2006
	(in thousands)
Operating Activities:
Net Margin	$	3,033		$	2,990
Adjustments to reconcile net margins to net cash provided by (used for) operating activities:
Depreciation, amortization and decommissioning		9,417			9,660
Other non-cash charges		3,038			2,795
Non-controlling interest		30			579
Amortization of lease obligations		2,886			2,718
Interest on lease deposits		(2,810	)		(2,616	)
Change in current assets		24,075			55,968
Change in deferred energy		(16,119	)		(27,682	)
Change in current liabilities		5,222			(56,179	)
Change in regulatory assets and liabilities		18,342			(32,069	)
Deferred charges and credits		(1,031	)		(1,710	)
Net Cash Provided by (Used for) Operating Activities		46,083			(45,546	)
Financing Activities:
Obligations under long-term leases		(274	)		(503	)
Net Cash (Used for) Financing Activities		(274	)		(503	)
Investing Activities:
Purchases of available for sale securities		(117,449	)		(7,675	)
Proceeds from sale of available for sale securities		57,629			15,350
Increase in other investments		9,045			(869	)
Electric plant additions		(4,619	)		(3,282	)
Net Cash (Used for) Provided by Investing Activities		(55,394	)		3,524
Net Change in Cash and Cash Equivalents		(9,585	)		(42,525	)
Cash and Cash Equivalents - Beginning of Period		52,018			98,633
Cash and Cash Equivalents - End of Period	$	42,433		$	56,108

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, 2007, and our consolidated results of operations, comprehensive income, and cash flows for the three months ended March 31, 2007 and 2006. The consolidated results of operations for the three months ended March 31, 2007 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 2006 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 became the primary beneficiary of TEC in 2001. We first consolidated TEC’s financial position as of December 31, 2004, and beginning January 1, 2005, TEC’s operations were also consolidated as a result of our adoption of the Interpretation. 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 $10.6 million and $11.0 million at March 31, 2007, and December 31, 2006, 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 not regulated by the respective states’ public service commissions, but are set periodically by a formula that was accepted for filing by the Federal Energy Regulatory Commission (“FERC”) on December 23, 2003. 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. Financial Instruments (including Derivatives). Financial instruments included in the decommissioning fund are classified as available for sale, and accordingly, are carried at fair value. Unrealized gains and losses on investments held in the decommissioning fund are deferred as a regulatory liability and a regulatory asset until realized.

Our investments in marketable securities, which are actively managed, are classified as available for sale and are recorded at fair value. Unrealized gains or losses on these investments, if material, are reflected as a component of capitalization. Investments in debt securities that we have the positive intent and ability to hold to maturity are classified as held to maturity and are recorded at amortized cost. Other investments are recorded at cost, which approximates market value.

We primarily purchase power under both long-term and short-term forward physical delivery contracts to supply power to our member distribution cooperatives under “all requirements” wholesale power contracts. These forward purchase contracts meet the accounting definition of a derivative; however, a majority of the forward purchase derivative contracts qualify for the normal purchases/normal sales exception under Statement of Financial Accounting Standards (“SFAS”) No. 133 “Accounting for Derivative Instruments and Hedging Activities.” As a result, these contracts are not recorded at fair value. We record a liability and purchased power expense when the power under the forward physical delivery contract is delivered. We also purchase

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natural gas futures generally for three years or less to hedge the price of natural gas for the operation of our combustion turbine facilities and to hedge certain forward power purchase agreements that use natural gas as a basis for determining the price of power. These derivatives do not qualify for the normal purchase/normal sales exception.

For all derivative contracts that do not qualify for the normal purchases/normal sales accounting exception, we may elect cash flow hedge accounting in accordance with SFAS No. 133. Accordingly, gains and losses on derivative contracts are deferred into Other Comprehensive Income until the hedged underlying transaction occurs or is no longer likely to occur. For derivative contracts where hedge accounting is not utilized, or for which ineffectiveness exists, we defer all remaining gains and losses on a net basis as a regulatory asset or liability in accordance with SFAS No. 71 “Accounting for the Effects of Certain Types of Regulation.” These amounts are subsequently reclassified as purchased power or fuel expense in our Consolidated Statements of Revenues, Expenses, and Patronage Capital as the power or fuel is delivered and/or the contract settles.

Generally, derivatives are reported on the Consolidated Balance Sheet at fair value. The measurement of fair value is based on actively quoted market prices, if available. Otherwise, we seek indicative price information from external sources, including broker quotes and industry publications. For individual contracts, the use of differing assumptions could have a material effect on the contract’s estimated fair value. There was no hedge ineffectiveness for the three months ended March 31, 2007 and hedge ineffectiveness was immaterial for the three months ended March 31, 2006.

We are exposed to credit risk in our business operations. We have a Credit Risk Policy that establishes the basis for determining counterparty credit standards and processes to determine credit limits. Our risk management committee monitors credit exposure on a regular basis. Formal counterparty credit reviews are performed at least annually and informal reviews are performed on an ongoing basis.

4. Commitments and Contingencies.

Norfolk Southern

In April 1989, we entered into a coal transportation agreement with Norfolk Southern for delivery of coal to Clover. The agreement, which was later assigned to Virginia Power as operator of Clover, had an initial 20-year term and provides that the amounts payable for coal transportation services are subject to adjustment based on a reference index. In October 2003, Norfolk Southern claimed that it had been using an incorrect reference index to calculate amounts due to it since the inception of the agreement, and that it would begin to escalate prices for these services in the future based on an alternate reference index. On November 26, 2003, together with Virginia Power, we filed suit against Norfolk Southern in the Circuit Court of Halifax County, Virginia, seeking an order to clarify the price escalation provisions in the coal transportation agreement. In its reply to our suit, Norfolk Southern filed a counter-claim and sought (1) recovery from Virginia Power and us for additional amounts resulting from its use of the alternate reference index since December 1, 2003, and (2) an order requiring the parties to calculate the amounts Norfolk Southern claims it was underpaid since the inception of the agreement by using the alternate reference index.

On December 22, 2004, the court found in favor of Norfolk Southern on the issue of ambiguity and held that the price escalation provisions in the agreement were clear and unambiguous. The court later denied Virginia Power’s and our motion to file an amended complaint based on additional evidence that was not considered by the court in the original proceedings. The court permitted Virginia Power and us to file an amended answer to Norfolk Southern’s counter-claims and our amended answer was filed on March 4, 2005.

On September 1, 2006, the court granted Norfolk Southern’s request to substantially dispose of the issues in the case. On September 23, 2006, we, along with Virginia Power, appealed the court’s order to the Supreme Court of Virginia. On December 13, 2006, Norfolk Southern filed a motion to dismiss for lack of jurisdiction, contending that we and Virginia Power failed to timely appeal. On April 4, 2007, we along with Virginia Power, presented our arguments to a panel of three justices as to why the petition for appeal should be granted and we are currently awaiting the decision. If any one of the three justices supports granting the petition for appeal, we along with Virginia Power, intend to vigorously prosecute the appeal.

We recorded a liability related to the Norfolk Southern dispute and created the related regulatory asset for prior charges. The regulatory asset was amortized over 21 months (April 1, 2005 through December 31, 2006) and was fully amortized and collected through rates as of December 31, 2006. 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.

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Ragnar Benson

In December 2002, we entered into a contract with RBI for engineering, procurement and construction services relating to the construction of our Marsh Run combustion turbine facility. Construction of the facility began in April 2003 and the facility was required to be substantially complete in the second quarter of 2004. The facility ultimately became available for commercial operation on September 15, 2004, but is still not substantially complete according to the terms of the contract. On December 23, 2004, we terminated the contract with RBI for default and filed suit in the U.S. District Court for the Eastern District of Virginia, Richmond Division, against RBI seeking liquidated damages for delay in completion of the project up to $15.0 million and damages for breach of contract up to $5.0 million. RBI counterclaimed for damages exceeding $15.0 million related to conditions they claim to have encountered during construction. We filed an answer to RBI’s counterclaim denying any liability to RBI. During the discovery phase of the legal proceeding, RBI revised its claim from $15.0 million to $33.0 million.

On September 27, 2005, the U.S. District Court for the Eastern District of Virginia, Richmond Division, ruled on motions for partial summary judgment in our claims against RBI. Specifically, the court granted our motion for partial summary judgment pertaining to claims of entitlement to a change order and fraud allegations, it dismissed six of RBI’s counterclaims, including all counterclaims pertaining to fraud, and it limited our possible recovery of liquidated damages to the liquidated damages cap of approximately $4.7 million. The trial began October 11, 2005 and concluded October 26, 2005. During the trial, RBI revised its claim from $33.0 million to $36.0 million.

RBI and its parent companies, The Austin Company and Austin Holdings, Inc., filed for bankruptcy under Chapter 11 of the bankruptcy code on October 14, 2005. The automatic litigation stay was lifted for our litigation with RBI.

On June 13, 2005, we executed an agreement with RBI’s surety, Seaboard Surety Company (“Seaboard”), under which it assumed all responsibilities for the final completion of the Marsh Run facility in accordance with the terms of the original agreement with RBI. Because RBI declared bankruptcy during the legal proceeding, we served a lawsuit against Seaboard on February 10, 2006, in order to enforce the eventual outcome of the suit with RBI.

On August 4, 2006, the court ruled in our favor on all remaining issues in the case and awarded us damages of $5.2 million plus expenses. On January 22, 2007, the court entered its order awarding us an additional $2.5 million for attorneys’ fees and certain other costs and expenses. On February 1, 2007, we filed a motion to amend the January 22, 2007 order to address our claim for expert witness fees and interest from the date of the trial, totaling approximately $0.8 million. On April 12, 2007, the court entered its final order awarding us a total of $7.6 million plus interest on the principal judgment from October 25, 2005, and interest on attorneys’ fees from September 15, 2006. The appeals process began with the April 12, 2007 order and RBI will have 30 days to appeal any of the court’s rulings. On April 23, 2007, we filed an amended complaint against Seaboard Surety Company (“Seaboard”) to take into consideration the final order entered by the court on April 12, 2007. We intend to enforce the court’s rulings against RBI, to the extent permitted by its bankruptcy proceeding, and against Seaboard.

Tax Increase Prevention and Reconciliation Act of 2005

On May 17, 2006, President Bush signed into law an act entitled the “Tax Increase Prevention and Reconciliation Act of 2005” (the “2005 Tax Act”). Among other provisions, the 2005 Tax Act imposes an excise tax on certain types of leasing transactions entered into by tax-exempt entities. At this time, it is not clear whether the excise tax imposed by the 2005 Tax Act is applicable to our lease transactions. We are continuing to evaluate this legislation and the impact on us; however, specific guidance has not yet been made available. We have revised our estimate of the potential impact and have determined that we do not need to record a liability based upon the currently available information. We have determined that our potential liability for 2006 could range from zero to approximately $1.2 million and that zero represents our best estimate at this time. However, once further guidance is issued, our potential liability under the 2005 Tax Act may change.

5. New Accounting Pronouncements.

We adopted the provisions of the Financial Accounting Standards Board (“FASB”) Interpretation No. 48, “Accounting for Uncertainty in Income Taxes—an Interpretation of FASB Statement No. 109” (“FIN 48”) on January 1, 2007. This

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interpretation requires that income tax positions recognized in an entity’s tax returns have a more-likely-than-not chance of being sustained prior to recording the related tax benefit in the financial statements. There was no impact on our financial statements as a result of the adoption of FIN 48.

6. Subsequent Event.On April 10, 2007, our Board of Directors approved an increase to our fuel factor adjustment rate, resulting in an increase to our total energy rate of approximately 7.2%, effective April 1, 2007. This increase was implemented due to our continued rising energy costs and difference between actual costs incurred and anticipated costs upon which our rates were based.

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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, 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, 2007, 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, 2006. 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”) effective December 31, 2006. 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, 2007, were impacted by higher energy rates, weather, operation of our combustion turbine facilities, and changes in the fair value of our derivative contracts. Revenues were higher due to higher energy rates which were implemented in April and October of 2006 to collect previously incurred but not collected costs and to provide for the collection of future anticipated costs. We experienced significantly colder weather in February 2007 resulting in increased sales volume. Our combustion turbine facilities were dispatched more in accordance with the requirements of PJM Interconnection, LLC (“PJM)” resulting in increased fuel costs. Due to changing conditions in the power markets, the fair value of our forward purchase power contracts and natural gas futures increased resulting in changes to our regulatory assets and liabilities which increased cash provided by operating activities.

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 our power purchase contracts with third parties, 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 deprecation 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, 2007 and 2006, were as follows:

	Three Months Ended March 31,
	2007		2006
	(in thousands)
Revenue from sales to:
Member distribution cooperatives	$	208,619	$	176,815
Non-members		20,091		26,646
Total revenues	$	228,710	$	203,461

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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, 2007 and 2006, were as follows:

	Three Months Ended March 31,
	2007	2006
	(in MWh)
Energy sales to:
Member distribution cooperatives	3,088,879	2,793,266
Non-members	416,191	476,586
Total energy sales	3,505,070	3,269,852

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, 2006, for a discussion of our Margin Stabilization Plan.

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, 2007 and 2006, were as follows:

	Three Months Ended March 31,
	2007		2006
	(in thousands)
Revenues from sales to member distribution cooperatives:
Base energy revenues	$	55,625	$	50,229
Fuel factor adjustment revenues		98,681		68,336
Total energy revenues		154,306		118,565
Demand (capacity) revenues		54,313		58,250
Total revenues from sales to member distribution cooperatives	$	208,619	$	176,815
Average costs to member distribution cooperatives (per MWh)	$	67.54	$	63.30

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 the amount, size, and usage of electronics and machinery and the expansion of operations among their commercial and industrial customers. Weather also affects the requirement for electricity. Relatively higher or lower temperatures tend to increase the requirement for energy to use air conditioning or heating systems, respectively. Mild weather generally reduces the requirement because air conditioning and heating systems are operated less.

Three Months Ended March 31, 2007 compared to Three Months ended March 31, 2006

Total revenues from sales to our member distribution cooperatives for the three months ended March 31, 2007, increased $31.8 million, or 18.0%, over the same period in 2006, primarily as a result of higher energy rates and higher sales volumes slightly offset by lower incurred 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 17.7% higher during the three months ended March 31, 2007, as compared to the same period in 2006. We increased our fuel factor adjustment rate effective April 1, 2006, and October 1, 2006, resulting in an increase to our total energy rate of approximately 11.9% and 5.2%, respectively. These increases were implemented due to our continued rising fuel and purchased power costs and differences between actual costs incurred and anticipated costs upon which our rates were based.

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The capacity costs we incurred, and thus the capacity-related revenues we reflected pursuant to the formulary rate, for the three months ended March 31, 2007, as compared to the same period in 2006, decreased $3.9 million, or 6.8%, primarily related to decreased transmission charges. Additionally, effective April 1, 2006, we decreased the demand component of our rate approximately 1.8% in accordance with the budget that our board of directors approved in December 2005. Increases or decreases in our budget automatically amend the demand component of our formulary rate.

Our average costs to member distribution cooperatives per MWh increased $4.24 per MWh, or 6.7%, for the three months ended March 31, 2007, as compared to the same period in 2006, primarily as a result of the increase in our total energy rates related to increased fuel and purchased power 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 purchased energy to PJM under its rates for providing energy imbalance services. 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. Non-member revenue decreased by $6.6 million, or 24.6%, in the three months ended March 31, 2007, and non-member energy sales in MWh decreased 60,395 MWh, or 12.7%, as compared to the same period in 2006. The decrease in non-member revenue for the three months ended March 31, 2007, is due to a decrease in the prices at which we sold excess energy to non-members and a decrease in the volume of excess energy sales.

Operating Expenses

We supply our member distribution cooperatives’ power requirements, consisting of capacity requirements and energy requirements, through (i) our interests in electric generating facilities which consist of a 50% interest in the Clover Power Station (“Clover”), an 11.6% interest in the North Anna Nuclear Power Station (“North Anna”), our Louisa combustion turbine facility (“Louisa”), our Marsh Run combustion turbine facility (“Marsh Run”), our Rock Springs combustion turbine facility (“Rock Springs”), and our distributed generation facilities, and (ii) long-term and short-term physically-delivered forward power purchase contracts and spot purchases of power in the open market. Our energy supply for the three months ended March 31, 2007 and 2006, was as follows:

	Three Months Ended March 31,
	2007			2006
	(in MWh and percentages)
Generated:
Clover	883,720	24.5	%	906,808	27.1	%
North Anna	420,019	11.7		388,494	11.6
Louisa	13,236	0.4		775	—
Marsh Run	32,304	0.9		1,550	0.1
Rock Springs	809	—		—	—
Distributed generation	113	—		—	—
Total Generated	1,350,201	37.5		1,297,627	38.8
Purchased:
Total Purchased	2,246,498	62.5		2,045,939	61.2
Total Available Energy	3,596,699	100.0	%	3,343,566	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, particularly nuclear power plants such as North Anna, generally have relatively high fixed costs. Nuclear facilities operate with relatively low variable costs due to lower fuel costs and technological efficiencies. In addition, coal-fired facilities also have relatively low variable costs, as compared to combustion turbine facilities such as Louisa, Marsh Run and Rock Springs. Owners of power plants incur the fixed costs of these facilities whether or not the units operate. 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

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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 are more expensive to operate; 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, 2007 and 2006, 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,
	2007		2006		2007		2006
Unit 1	94.4	%	96.5	%	99.1	%	68.8	%
Unit 2	93.6		96.0		83.6		100.6
Combined	94.0		96.3		91.4		84.7

Clover.During the three months ended March 31, 2007, both Clover Units 1 and 2 were available for dispatch. Clover Unit 2 experienced minor unscheduled outages during the three months ended March 31, 2007 and 2006. On March 31, 2007, Clover Unit 1 was taken off-line for a scheduled maintenance outage and was returned to service on April 14, 2007.

North Anna.North Anna Unit 1 experienced minor unscheduled outages during the three months ended March 31, 2007 and 2006. On March 18, 2007, North Anna Unit 2 was taken off-line for a scheduled refueling and maintenance outage and was returned to service on April 22, 2007.

Combustion turbine facilities.During the three months ended March 31, 2007 and 2006, the operational availability of our Louisa, Marsh Run and Rock Springs combustion turbine facilities was as follows:

	Three Months Ended March 31,
	2007		2006
Louisa	98.8	%	99.5	%
Marsh Run	99.7		99.2
Rock Springs	99.7		92.2

The components of our operating expenses for the three months ended March 31, 2007 and 2006, were as follows:

	Three Months Ended March 31,
	2007			2006
	(in thousands)
Fuel	$	33,093		$	24,465
Purchased power		166,316			161,364
Deferred energy		(16,119	)		(27,682	)
Operations and maintenance		9,976			8,060
Administrative and general		8,092			8,287
Depreciation, amortization and decommissioning		9,417			9,660
Amortization of regulatory asset/(liability), net		181			195
Accretion of asset retirement obligations		732			651
Taxes other than income taxes		1,830			1,560
Total Operating Expenses	$	213,518		$	186,560

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Three Months Ended March 31, 2007 compared to Three Months ended March 31, 2006:

Aggregate operating expenses increased $27.0 million, or 14.5%, for the three months ended March 31, 2007, as compared to the same period in 2006, primarily due to the change in deferred energy expense and the increase in fuel expense.

Deferred energy expense changed $11.6 million, or 41.8%, for the three months ended March 31, 2007, as compared to the same period in 2006. During the three months ended March 31, 2007, we under-collected $16.1 million in energy costs; whereas in the three months ended March 31, 2006, we under-collected $27.7 million in energy costs. At March 31, 2007, we had an under-collected deferred energy balance of $31.0 million.

Fuel expense increased $8.6 million, or 35.3%, for the three months ended March 31, 2007, as compared to the same period in 2006, primarily due to the increased operation of our combustion turbine facilities.

On April 10, 2007, our Board of Directors approved an increase to our fuel factor adjustment rate, resulting in an increase to our total energy rate of approximately 7.2% effective April 1, 2007, due to our continued rising energy costs and differences between our actual and anticipated costs upon which our rates were based.

Other Items

Investment Income.Investment income increased $0.9 million, or 45.0%, for the three months ended March 31, 2007, as compared to the same period in 2006, primarily due to income earned on our increased average balance in cash and temporary investments as a result of higher member prepayments and higher interest rates.

Interest Charges, net. The primary factors affecting our interest expense are scheduled payments of principal on our indebtedness, interest related to our potential liability associated with our dispute with Norfolk Southern, and capitalized interest.

The major components of interest charges, net for the three months ended March 31, 2007 and 2006, were as follows:

	Three Months Ended March 31,
	2007			2006
	(in thousands)
Interest expense on long-term debt	$	(13,613	)	$	(13,895	)
Other		(1,553	)		(1,056	)
Total Interest Charges		(15,166	)		(14,951	)
Allowance for borrowed funds used during construction		80			29
Interest Charges, net	$	(15,086	)	$	(14,922	)

Interest charges, net remained relatively flat for the three months ended March 31, 2007, as compared to the same period in 2006. Other interest increased $0.5 million, or 47.1% for the three months ended March 31, 2007 as compared to the same period in 2006, primarily as a result of accrued interest related to our dispute with Norfolk Southern.

Net Margin.Our net margin, which is a function of our total interest charges, remained relatively flat for the three months ended March 31, 2007, as compared to the same period in 2006.

Financial Condition

The principal changes in our financial condition from December 31, 2006 to March 31, 2007, were caused by increases in investments—other, accrued expenses and the change in deferred energy partially offset by decreases in accounts receivable—deposits, accounts payable and regulatory assets. Investments—other increased $49.9 million related to the return of $23.6 in collateral we were required to post with our counterparties at December 31, 2006. Also, we had additional cash to invest due to higher member prepayment balances. Due to changes in energy prices, at March 31, 2007, we were not required to post any deposits. Accrued expenses increased $15.7 million related primarily to accrued interest. Our deferred energy balance represents the net under-

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or over-collection of energy costs as of the end of the reporting period. These amounts are recovered from or refunded to our member distribution cooperatives in subsequent periods. At December 31, 2006, we had an under-collected deferred energy balance of $14.9 million as compared to an under-collected deferred energy balance of $31.0 million at March 31, 2007. Accounts receivable—deposits decreased by $23.6 million related to the return of collateral posted due to changes in energy prices. Accounts payable decreased $18.9 million primarily as a result of decreased purchased power in March 2007 as compared to December 2006. Regulatory assets decreased $15.7 million primarily due to the change in the fair value of our derivatives.

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 2007, our operating activities provided cash flow of $46.1 million. During the first three months of 2006, our cash needs exceeded our cash inflows from operating activities by $45.5 million. Operating activities in the first three months of 2007 were primarily impacted by the change in current assets and regulatory assets and liabilities partially offset by the change in deferred energy. Current assets changed $24.1 million primarily related to the return of $23.6 million in deposits we were required to post as of December 31, 2006. As of March 31, 2007, due to market changes in energy prices, we were not required to post any deposits. Regulatory assets and liabilities changed $18.3 primarily due to the change in the fair value of our derivatives. At March 31, 2007, we had an under-collected deferred energy balance of $31.0 million as compared to an under-collected deferred energy balance of $14.9 million at December 31, 2006, which resulted in a cash outflow of $16.1 million.

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, 2007, we had short-term committed variable rate lines of credit in an aggregate amount of $180.0 million. Additionally, we had two committed three-year revolving credit facilities, $50.0 million each.

At March 31, 2007 and 2006, we had no short-term borrowings or letters of credit outstanding under any of these arrangements. We expect the working capital lines of credit and revolving credit facilities to be renewed as they expire.

Investing Activities.Investing activities in the first three months of 2007 were primarily impacted by activity related to available for sale securities, interest earned on investments—other and cash and cash equivalents, as well as electric plant additions for our generating facilities.

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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 2007.

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

On May 7, 2007, Northern Virginia Electric Cooperative (“NOVEC”) filed a brief in accordance with the procedural schedule issued on March 5, 2007, by the United States Court of Appeals for the District of Columbia. For further description of our legal proceedings related to NOVEC, see Part 1, Item 3 of our 2006 Annual Report on Form 10-K.

Norfolk Southern

In our legal proceedings against Norfolk Southern Railway Company (“Norfolk Southern”), on April 4, 2007, we along with Virginia Power, presented our arguments to a panel of three justices as to why the petition for appeal should be granted. We are currently awaiting the decision. If any one of the three justices supports granting the petition for appeal, we, along with Virginia Power, intend to vigorously prosecute the appeal. For further description of our legal proceedings for Norfolk Southern, see Part 1, Item 3 of our 2006 Annual Report on Form 10-K.

Ragnar Benson

In our legal proceedings against Ragnar Benson, Inc. (“RBI”), on April 12, 2007, the court entered its final order awarding us a total of $7.6 million plus interest on the principal judgment from October 25, 2005, and interest on attorneys’ fees from September 15, 2006. On April 23, 2007, we filed an amended complaint against Seaboard Surety Company (“Seaboard”) to take into consideration the final order entered by the court on April 12, 2007. For further description of our legal proceedings for RBI, see Part 1, Item 3 of our 2006 Annual Report on Form 10-K.

FERC Proceedings Related to Potential Reorganization

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. For further description of our legal proceedings for the FERC Proceedings Related to Potential Reorganization, See Part 1, Item 3 of our 2006 Annual Report on Form 10-K.

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, 2006, 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

On April 4, 2007, legislation was passed in Virginia that changed the electricity restructuring in Virginia. The legislation, effective July 1, 2007, changed the termination date for the capped rates our Virginia member distribution cooperatives charge their customers from December 31, 2010 to December 31, 2008. After the end of capped rates, retail choice is eliminated for all customers except those that consume at least five megawatts of power individually or in the aggregate (with aggregation subject to the approval of the Virginia State Corporation Commission (“VSCC”)), but do not account for more than 1% of the incumbent utility’s peak load during the past year. Also, retail choice will continue to be available for customers that desire to select a supplier that provides 100% green or renewable power and for any cooperative customer whose 2006, or any subsequent year’s, noncoincident peak demand exceeded 90 megawatts. Currently, we do not anticipate that these conditions related to retail choice will have a material impact on

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our financial results. Also, beginning January 1, 2009, this legislation allows our Virginia member distribution cooperatives to adjust their rates by a maximum net increase or decrease of 5%, on a cumulative basis, in any three year period without filing a rate case with the VSCC. Additionally, our Virginia member distribution cooperatives may make changes to their terms and conditions of distribution service without VSCC approval, provided the changes do not affect their revenues. This new legislation does not affect our Virginia member distribution cooperatives’ ability to pass through changes in energy costs to their customers. For further description see “Competition” in Part 1, Item 1 of our 2006 Annual Report on Form 10-K.

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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 14, 2007	/s/ Robert L. Kees
	Robert L. Kees
	Senior Vice President and Chief Financial Officer
	(Principal Financial and Accounting 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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