Edgar Filing: VIRGINIA ELECTRIC & POWER CO

VIRGINIA ELECTRIC AND POWER COMPANY

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 June 30, 2007

¨	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 001-02255

VIRGINIA ELECTRIC AND POWER COMPANY

(Exact name of registrant as specified in its charter)


VIRGINIA		54-0418825
*(State or other jurisdiction of incorporation or organization)*		*(I.R.S. Employer Identification No.)*

120 TREDEGAR STREET RICHMOND, VIRGINIA		23219
*(Address of principal executive offices)*		*(Zip Code)*

(804) 819-2000

(Registrant’s telephone number)

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.

Large 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

At June 30, 2007, the latest practicable date for determination, 198,047 shares of common stock, without par value, of the registrant were outstanding.

VIRGINIA ELECTRIC AND POWER COMPANY

INDEX


		Page Number
PART I. Financial Information

Item 1.	Consolidated Financial Statements

	Consolidated Statements of Income – Three and Six Months Ended June 30, 2007 and 2006	3

	Consolidated Balance Sheets – June 30, 2007 and December 31, 2006	4

	Consolidated Statements of Cash Flows – Six Months Ended June 30, 2007 and 2006	6

	Notes to Consolidated Financial Statements	7

Item 2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	16

Item 3.	Quantitative and Qualitative Disclosures About Market Risk	26

Item 4.	Controls and Procedures	27

PART II. Other Information

Item 1.	Legal Proceedings	27

Item 1A.	Risk Factors	27

Item 4	Submission of Matters to a Vote of Security Holders	28

Item 6.	Exhibits	29

PAGE 2

VIRGINIA ELECTRIC AND POWER COMPANY

PART I. FINANCIAL INFORMATION

ITEM 1. CONSOLIDATED FINANCIAL STATEMENTS

CONSOLIDATED STATEMENTS OF INCOME

(Unaudited)


	Three Months Ended June 30,					Six Months Ended June 30,
(millions)	2007			2006		2007			2006
Operating Revenue	$	1,424		$	1,323	$	2,867		$	2,656
Operating Expenses
Electric fuel and energy purchases		661			555		1,336			1,112
Purchased electric capacity		107			109		223			226
Other energy-related commodity purchases		8			8		16			18
Other operations and maintenance:
External suppliers		196			207		402			396
Affiliated suppliers		78			81		156			158
Depreciation and amortization		140			135		274			267
Other taxes		43			43		88			88

Total operating expenses		1,233			1,138		2,495			2,265

Income from operations		191			185		372			391

Other income		17			17		40			41

Interest and related charges:
Interest expense		75			63		129			133
Interest expense—junior subordinated notes payable to affiliated trust		7			7		15			15

Total interest and related charges		82			70		144			148

Income before income tax expense		126			132		268			284
Income tax expense		47			46		100			101

Income before extraordinary item		79			86		168			183
Extraordinary item⁽¹⁾		(158	)		—		(158	)		—

Net Income (Loss)		(79	)		86		10			183
Preferred dividends		4			4		8			8

Balance available for common stock	$	(83	)	$	82	$	2		$	175

(1)	Net of income tax benefit of $101 million for the three and six months ended June 30, 2007.

The accompanying notes are an integral part of the Consolidated Financial Statements.

PAGE 3

VIRGINIA ELECTRIC AND POWER COMPANY

CONSOLIDATED BALANCE SHEETS

(Unaudited)


(millions)	June 30, 2007			December 31, 2006⁽¹⁾
ASSETS
Current Assets
Cash and cash equivalents	$	25		$	18
Customer accounts receivable (less allowance for doubtful accounts of $8 and $7)		743			650
Other receivables (less allowance for doubtful accounts of $8 and $9)		113			98
Inventories (average cost method)		457			505
Prepayments		54			133
Other		61			51

Total current assets		1,453			1,455

Investments
Nuclear decommissioning trust funds		1,351			1,293
Other		22			22

Total investments		1,373			1,315

Property, Plant and Equipment
Property, plant and equipment		21,207			20,771
Accumulated depreciation and amortization		(8,576	)		(8,353	)

Total property, plant and equipment, net		12,631			12,418

Deferred Charges and Other Assets		452			495

Total assets	$	15,909		$	15,683

(1)	The Consolidated Balance Sheet at December 31, 2006 has been derived from the audited Consolidated Financial Statements at that date.

The accompanying notes are an integral part of the Consolidated Financial Statements.

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VIRGINIA ELECTRIC AND POWER COMPANY

CONSOLIDATED BALANCE SHEETS—(Continued)

(Unaudited)


(millions)	June 30, 2007		December 31, 2006⁽¹⁾
LIABILITIES AND SHAREHOLDER’S EQUITY
Current Liabilities
Securities due within one year	$	644	$	1,267
Short-term debt		914		618
Accounts payable		458		418
Other		505		638

Total current liabilities		2,521		2,941

Long-Term Debt
Long-term debt		3,492		2,987
Junior subordinated notes payable to affiliated trust		412		412
Notes payable—other affiliates		220		220

Total long-term debt		4,124		3,619

Deferred Credits and Other Liabilities
Deferred income taxes and investment tax credits		1,995		2,308
Asset retirement obligations		659		641
Regulatory liabilities		961		430
Other		262		95

Total deferred credits and other liabilities		3,877		3,474

Total liabilities		10,522		10,034

Commitments and Contingencies (see Note 10)

Preferred Stock Not Subject to Mandatory Redemption		257		257

Common Shareholder’s Equity
Common stock—no par, 300,000 shares authorized; 198,047 shares outstanding		3,388		3,388
Other paid-in capital		888		887
Retained earnings		821		955
Accumulated other comprehensive income		33		162

Total common shareholder’s equity		5,130		5,392

Total liabilities and shareholder’s equity	$	15,909	$	15,683

(1)	The Consolidated Balance Sheet at December 31, 2006 has been derived from the audited Consolidated Financial Statements at that date.

The accompanying notes are an integral part of the Consolidated Financial Statements.

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VIRGINIA ELECTRIC AND POWER COMPANY

CONSOLIDATED STATEMENTS OF CASH FLOWS

(Unaudited)


	Six Months Ended June 30,
(millions)	2007			2006
Operating Activities
Net income	$	10		$	183
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation and amortization		317			307
Deferred income taxes and investment tax credits, net		(2	)		(29	)
Deferred fuel expenses, net		69			56
Extraordinary item, net of income taxes		158			—
Other adjustments to net income		(23	)		(45	)
Changes in:
Accounts receivable		(99	)		37
Affiliated accounts receivable and payable		1			25
Inventories		48			(63	)
Accounts payable		61			(60	)
Accrued interest, payroll and taxes		(18	)		152
Prepayments		76			13
Other operating assets and liabilities		79			98

Net cash provided by operating activities		677			674

Investing Activities
Plant construction and other property additions		(460	)		(421	)
Purchases of nuclear fuel		(66	)		(60	)
Purchases of securities		(279	)		(267	)
Proceeds from sales of securities		263			256
Other		9			22

Net cash used in investing activities		(533	)		(470	)

Financing Activities
Issuance (repayment) of short-term debt, net		296			(655	)
Issuance (repayment) of affiliated current borrowings, net		(140	)		190
Issuance of long-term debt		600			1,000
Repayment of long-term debt		(726	)		(612	)
Common dividend payments		(142	)		(139	)
Preferred dividend payments		(8	)		(8	)
Other		(17	)		(14	)

Net cash used in financing activities		(137	)		(238	)

Increase (decrease) in cash and cash equivalents		7			(34	)
Cash and cash equivalents at beginning of period		18			54

Cash and cash equivalents at end of period	$	25		$	20

The accompanying notes are an integral part of the Consolidated Financial Statements.

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VIRGINIA ELECTRIC AND POWER COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

Note 1. Nature of Operations

Virginia Electric and Power Company (the Company), a Virginia public service company, is a wholly-owned subsidiary of Dominion Resources, Inc. (Dominion). We are a regulated public utility that generates, transmits and distributes electricity for sale in Virginia and northeastern North Carolina. As of June 30, 2007, we served approximately 2.4 million retail customer accounts, including governmental agencies and wholesale customers such as rural electric cooperatives and municipalities. We are a member of PJM Interconnection, LLC (PJM), a regional transmission organization (RTO), and our electric transmission facilities are integrated into the PJM wholesale electricity markets.

We manage our daily operations through three primary operating segments: Delivery, Energy and Generation. In addition, we report our corporate and other functions as a segment. Our assets remain wholly owned by us and our legal subsidiaries.

The terms “Virginia Power,” “we,” “our” and “us” are used throughout this report and, depending on the context of their use, may represent any of the following: the legal entity, Virginia Electric and Power Company, one of Virginia Electric and Power Company’s consolidated subsidiaries or operating segments or the entirety of Virginia Electric and Power Company, including our Virginia and North Carolina operations and our consolidated subsidiaries.

Note 2. Significant Accounting Policies

As permitted by the rules and regulations of the Securities and Exchange Commission, our accompanying unaudited Consolidated Financial Statements contain certain condensed financial information and exclude certain footnote disclosures normally included in annual audited consolidated financial statements prepared in accordance with accounting principles generally accepted in the United States of America (GAAP). These unaudited Consolidated Financial Statements should be read in conjunction with our Consolidated Financial Statements and Notes in our Annual Report on Form 10-K for the year ended December 31, 2006.

In our opinion, our accompanying unaudited Consolidated Financial Statements contain all adjustments, including normal recurring accruals, necessary to present fairly our financial position as of June 30, 2007, our results of operations for the three and six months ended June 30, 2007 and 2006, and our cash flows for the six months ended June 30, 2007 and 2006.

We make certain estimates and assumptions in preparing our Consolidated Financial Statements in accordance with GAAP. These estimates and assumptions affect the reported amounts of assets and liabilities, the disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenue and expenses for the periods presented. Actual results may differ from those estimates.

Our accompanying unaudited Consolidated Financial Statements include, after eliminating intercompany transactions and balances, our accounts and those of our majority-owned subsidiaries and those variable interest entities (VIEs) where we have been determined to be the primary beneficiary.

In accordance with GAAP, we report certain contracts and instruments at fair value. Market pricing and indicative price information from external sources are used to measure fair value when available. In the absence of this information, we estimate fair value based on near-term and historical price information and statistical methods. For individual contracts, the use of differing assumptions could have a material effect on the contract’s estimated fair value. See Note 2 to the Consolidated Financial Statements in our Annual Report on Form 10-K for the year ended December 31, 2006 for more discussion of our estimation techniques.

PAGE 7

The results of operations for the interim periods are not necessarily indicative of the results expected for the full year. Information for quarterly periods is affected by seasonal variations in sales, electric fuel and energy purchases and other factors.

Certain amounts in our 2006 Consolidated Financial Statements and Notes have been recast to conform to the 2007 presentation.

As discussed further in Note 5, we reapplied the provisions of Statement of Financial Accounting Standards (SFAS) No. 71, Accounting for the Effects of Certain Types of Regulation (SFAS No. 71), to the Virginia jurisdiction of our generation operations upon enactment of reregulation legislation in Virginia on April 4, 2007. In connection with the reapplication of SFAS No. 71 to these operations, we prospectively changed certain of our accounting policies to those used by cost-of-service rate-regulated entities.

Note 3. Newly Adopted Accounting Standards

FIN 48

We adopted the provisions of Financial Accounting Standards Board (FASB) Interpretation No. 48, Accounting for Uncertainty in Income Taxes (FIN 48), on January 1, 2007. As a result of the implementation of FIN 48, we recorded a $5 million benefit, primarily attributable to interest, to beginning retained earnings for the cumulative effect of the change in accounting principle.

Unrecognized tax benefits represent those tax benefits related to tax positions that have been taken or are expected to be taken in tax returns that are not recognized in the financial statements because, in accordance with FIN 48, management has either measured the tax benefit at an amount less than the benefit claimed or expected to be claimed or concluded that it is not more-likely-than-not that the tax position will be ultimately sustained. Unrecognized tax benefits may result in an increase in income taxes payable, a reduction of an income tax refund receivable, an increase in deferred tax liabilities, or a decrease in deferred tax assets. Noncurrent income taxes payable related to unrecognized tax benefits are classified in other deferred credits and other liabilities; current payables are included in other current liabilities, except when such amounts are presented net with amounts receivable from or amounts prepaid to taxing authorities in prepayments.

In May 2007, the FASB issued FASB Staff Position No. FIN 48-1, Definition of Settlement in FASB Interpretation No. 48 (FSP FIN 48-1), to provide guidance on how to determine whether a tax position is effectively settled for the purpose of recognizing previously unrecognized tax benefits. FSP FIN 48-1 should have been applied in the initial adoption of FIN 48. In light of its delayed issuance, if an enterprise did not implement FIN 48 in a manner consistent with the provisions of FSP FIN 48-1, it is required to retrospectively apply its provisions to the date of its initial adoption of FIN 48. The adoption of FSP FIN 48-1 did not impact the beginning balance of unrecognized tax benefits.

As of January 1, 2007, unrecognized tax benefits totaled $226 million. For the majority of these tax positions, the ultimate deductibility is highly certain, but there is uncertainty about the timing of such deductibility. For the six months ended June 30, 2007, the activity for unrecognized tax benefits for tax positions taken in prior years included gross increases of $16 million and reductions of $14 million due to settlements with taxing authorities. Unrecognized tax benefits as of January 1, 2007, included $5 million that, if recognized, would lower the effective tax rate. Through June 30, 2007, there have been no significant changes in unrecognized tax benefits that, if recognized, would lower the effective tax rate.

Consistent with our existing policies, we continue to recognize estimated interest payable on underpayments of income taxes in interest expense and estimated penalties that may result from the settlement of some uncertain tax positions in other income. As of January 1, 2007, we had accrued $17 million for interest receivable and $1 million for estimated penalties.

We file a consolidated United States (U.S.) federal income tax return and participate in an intercompany tax sharing agreement with Dominion and its subsidiaries. In addition, where applicable, we participate in combined income tax returns with Dominion and its subsidiaries in various states, and we file separate income tax returns in other states.

For Dominion and its subsidiaries, the U.S. federal statute of limitations has expired for tax years prior to 1993.

PAGE 8

The U.S. Congressional Joint Committee on Taxation has recently completed its review of our settlement for tax years 1993–1998 with the Appellate Division of the Internal Revenue Service (IRS). As a result, we will receive a tax refund of approximately $39 million. Receipt of this refund will not impact our results of operations. We are also currently engaged in settlement negotiations with the Appellate Division of the IRS regarding certain adjustments proposed during the examination of tax years 1999-2001. With settlement negotiations possibly concluding later this year, unrecognized tax benefits could be reduced by approximately $22 million. At this time, we cannot estimate the impact on unrecognized tax benefits that may result in the next twelve months from settlement negotiations with the IRS for those adjustments remaining in dispute. In addition, the examination of our 2002 and 2003 returns by the IRS was completed in June 2007. In July 2007, we filed protests for certain proposed adjustments with the Appellate Division of the IRS.

Dominion’s combined income tax returns filed with Virginia for 2003 and subsequent years remain subject to examination by taxing authorities. We are also obligated to report adjustments resulting from IRS settlements of earlier years to state taxing authorities. In addition, if state net operating losses or credits, generated by Dominion and its subsidiaries in years for which the statute of limitations has expired, are utilized, the determination of such amounts is subject to examination by state taxing authorities.

EITF 06-3

Effective January 1, 2007, Emerging Issues Task Force (EITF) Issue No. 06-3, How Taxes Collected from Customers and Remitted to Governmental Authorities Should Be Presented in the Income Statement (That Is, Gross versus Net Presentation), requires certain disclosures if an entity collects any tax assessed by a governmental authority that is both imposed on and concurrent with a specific revenue-producing transaction between the entity, as a seller, and its customers. We collect sales, consumption and consumer utility taxes but exclude such amounts from revenue.

Note 4. Recently Issued Accounting Standards

SFAS No. 157

In September 2006, the FASB issued SFAS No. 157, Fair Value Measurements (SFAS No. 157), which defines fair value, establishes a framework for measuring fair value and expands disclosures about fair value measurements. SFAS No. 157 clarifies that fair value should be based on assumptions that market participants would use when pricing an asset or liability and establishes a fair value hierarchy of three levels that prioritizes the information used to develop those assumptions. The fair value hierarchy gives the highest priority to quoted prices in active markets and the lowest priority to unobservable data. SFAS No. 157 requires fair value measurements to be separately disclosed by level within the fair value hierarchy. The provisions of SFAS No. 157 will become effective for us beginning January 1, 2008. Generally, the provisions of this statement are to be applied prospectively. Certain situations, however, require retrospective application as of the beginning of the year of adoption through the recognition of a cumulative effect of accounting change. Such retrospective application is required for financial instruments, including derivatives and certain hybrid instruments with limitations on initial gains or losses under EITF Issue No. 02-3, Issues Involved in Accounting for Derivative Contracts Held for Trading Purposes and Contracts Involved in Energy Trading and Risk Management Activities, and SFAS No. 155, Accounting for Certain Hybrid Financial Instruments. We are currently evaluating the impact that SFAS No. 157 will have on our results of operations and financial condition.

SFAS No. 159

In February 2007, the FASB issued SFAS No. 159, The Fair Value Option for Financial Assets and Financial Liabilities (SFAS No. 159). SFAS No. 159 provides an entity with the option, at specified election dates, to measure certain financial assets and liabilities and other items at fair value, with changes in fair value recognized in earnings as those changes occur. SFAS No. 159 also establishes presentation and disclosure requirements that include displaying the fair value of those assets and liabilities for which the entity elected the fair value option on the face of the balance sheet and providing management’s reasons for electing the fair value option for each eligible item. The provisions of SFAS No. 159 will become effective for us beginning January 1, 2008. We are currently evaluating the impact that SFAS No. 159 may have on our results of operations and financial condition.

PAGE 9

Note 5. Reapplication of SFAS No. 71

In March 1999, we discontinued the application of SFAS No. 71 to the majority of our generation operations upon the enactment of deregulation legislation in Virginia. Our transmission and distribution operations continued to apply the provisions of SFAS No. 71 since they remained subject to cost-of-service rate regulation.

In April 2007, the Virginia General Assembly passed legislation that returns the Virginia jurisdiction of our generation operations to cost-of-service rate regulation. As a result, we reapplied the provisions of SFAS No. 71 to those operations on April 4, 2007, the date the legislation was enacted. The accounting impacts of the reapplication of SFAS No. 71 are described below.

Extraordinary Item

The reapplication of SFAS No. 71 to the Virginia jurisdiction of our generation operations resulted in a $259 million ($158 million after tax) extraordinary charge and the reclassification of $195 million ($119 million after tax) of unrealized gains from accumulated other comprehensive income (AOCI). This was done in order to establish a $454 million long-term regulatory liability for amounts collected from Virginia jurisdictional customers and placed in external trusts (including income, losses and changes in fair value thereon) for the future decommissioning of our nuclear generation stations, in excess of amounts recorded pursuant to SFAS No. 143, Accounting for Asset Retirement Obligations.

Accounting Policy Changes

In connection with the reapplication of SFAS No. 71, we prospectively changed certain of our accounting policies for the Virginia jurisdiction of our generation operations to those used by cost-of-service rate-regulated entities. Other than the extraordinary item discussed above, the overall impact of these changes, summarized below, was not material to our results of operations or financial condition.

Nuclear Decommissioning Trust Funds

Net realized and unrealized gains and losses are now recorded to the regulatory liability established upon reapplication of SFAS No. 71 as described above. Previously, realized gains and losses and any other-than-temporary declines in fair value were included in other income and unrealized gains were reported as a component of AOCI, net of tax.

Property, Plant and Equipment

Early retirements of generation-related utility property are now recorded to accumulated depreciation rather than recognizing gains and losses upon retirement. Cost of removal incurred or salvage proceeds realized in connection with a retirement of generation property, plant and equipment are now recorded to accumulated depreciation rather than being charged to expense as incurred. We discontinued capitalizing interest on all generation construction projects since the Virginia State Corporation Commission (Virginia Commission) has historically allowed for current recovery of construction financing costs.

Asset Retirement Obligations

Accretion and depreciation associated with nuclear decommissioning asset retirement obligations, previously charged to expense, are now recorded to a regulatory liability, in order to match the recognition for rate-making purposes.

Derivative Instruments

Previously, unrealized gains and losses resulting from changes in the fair value of derivative instruments designated as cash flow or fair value hedges under SFAS No. 133, Accounting for Derivative Instruments and Hedging Activities, were recorded in AOCI, or long-term debt, respectively. Also, ineffectiveness and gains and losses excluded from the measurement of ineffectiveness were recorded through earnings as incurred. Following the reapplication of SFAS No. 71, changes in the fair value of these derivative instruments will be classified as regulatory assets or regulatory liabilities as these instruments now receive regulatory treatment. Gains or losses on the derivative instruments will be recognized when the related transactions impact net income.

PAGE 10

Note 6. Operating Revenue

Our operating revenue consists of the following:


	Three Months Ended June 30,				Six Months Ended June 30,
(millions)	2007		2006		2007		2006
Regulated electric sales	$	1,386	$	1,283	$	2,797	$	2,581
Other		38		40		70		75

Total operating revenue	$	1,424	$	1,323	$	2,867	$	2,656

Note 7. Comprehensive Income

The following table presents total comprehensive income:


	Three Months Ended June 30,						Six Months Ended June 30,
(millions)	2007			2006			2007			2006
Net income (loss)	$	(79	)	$	86		$	10		$	183
Other comprehensive loss:
Net other comprehensive loss associated with effective portion of changes in fair value of derivatives designated as cash flow hedges, net of taxes and amounts reclassified to earnings⁽¹⁾		(19	)		—			(12	)		(7	)
Other⁽²⁾		(115	)		(17	)		(117	)		(7	)

Other comprehensive loss		(134	)		(17	)		(129	)		(14	)

Total comprehensive income (loss)	$	(213	)	$	69		$	(119	)	$	169

(1)	2007 amounts reflect the impact of the reclassification of derivative-related amounts previously recorded in AOCI to regulatory liabilities, as a result of the reapplication of SFAS No. 71 to the Virginia jurisdiction of our generation operations.

(2)

For the three and six months ended June 30, 2007, the amount primarily reflects the impact of the reclassification of gross unrealized gains on investments held in nuclear decommissioning trusts associated with the Virginia jurisdiction of our generation operations previously recorded in AOCI to regulatory liabilities, as a result of the reapplication of SFAS No. 71. For the three and six months ended June 30, 2006, the amount primarily reflects net unrealized losses on investments held in nuclear decommissioning trusts.

Note 8. Variable Interest Entities

Certain variable pricing terms in some of our long-term power and capacity contracts cause them to be considered potential variable interests in the counterparties. As discussed in Note 14 to the Consolidated Financial Statements in our Annual Report on Form 10-K for the year ended December 31, 2006, two potential VIEs with which we have existing power purchase agreements (signed prior to December 31, 2003), had not provided sufficient information for us to perform our evaluation under FASB Interpretation No. 46 (revised December 2003), Consolidation of Variable Interest Entities (FIN 46R).

As of June 30, 2007, no further information has been received from the two remaining potential VIEs. We will continue our efforts to obtain information and will complete an evaluation of our relationship with each of these potential VIEs if sufficient information is ultimately obtained. We have remaining purchase commitments with these two potential VIE supplier entities of $1.2 billion at June 30, 2007. We are not subject to any risk of loss from these potential VIEs, other than the remaining purchase commitments. We paid $24 million for electric generation capacity from these entities in the three months ended June 30, 2007 and 2006. We paid $23 million and $19 million for electric energy from these entities in the three months ended June 30, 2007 and 2006, respectively. We paid $50 million and $49 million for electric generation capacity and $49 million and $37 million for electric energy from these entities in the six months ended June 30, 2007 and 2006, respectively.

PAGE 11

In 2006, we restructured three long-term power purchase contracts with two VIEs, of which we are not the primary beneficiary. The restructured contracts expire between 2015 and 2017. We have remaining purchase commitments with these two VIE supplier entities of $1 billion at June 30, 2007. We are not subject to any risk of loss from these VIEs, other than the remaining purchase commitments. We paid $30 million and $29 million for electric generation capacity from these entities in the three months ended June 30, 2007 and 2006, respectively. We paid $13 million for electric energy from these entities in the three months ended June 30, 2007 and 2006. We paid $59 million and $58 million for electric generation capacity and $27 million and $28 million for electric energy from these entities in the six months ended June 30, 2007 and 2006, respectively.

During 2005, we entered into four long-term contracts with unrelated limited liability companies (LLCs) to purchase synthetic fuel produced from coal. Certain variable pricing terms in the contracts protect the equity holders from variability in the cost of their coal purchases, and therefore, the LLCs were determined to be VIEs. After completing our FIN 46R analysis, we concluded that although our interests in the contracts, as a result of their pricing terms, represent variable interests in the LLCs, we are not the primary beneficiary. We paid $121 million and $104 million to the LLCs for coal and synthetic fuel produced from coal in the three months ended June 30, 2007 and 2006, respectively, and $221 million and $215 million to the LLCs for coal and synthetic fuel produced from coal in the six months ended June 30, 2007 and 2006, respectively. We are not subject to any risk of loss from the contractual arrangements, as our only obligation to the VIEs is to purchase the synthetic fuel that the VIEs produce according to the terms of the applicable purchase contracts. These contracts will terminate on December 31, 2007.

Our Consolidated Balance Sheets as of June 30, 2007 and December 31, 2006 reflect net property, plant and equipment of $332 million and $337 million, respectively and $370 million of debt, related to the consolidation, in accordance with FIN 46R, of a variable interest lessor entity through which we have financed and leased a power generation plant. The debt is non-recourse to us and is secured by the entity’s property, plant and equipment. The lease under which we operate the power generation facility terminates in August 2007. We intend to take legal title to the facility through repayment of the lessor’s related debt at the end of the lease term, subject to regulatory approval.

Note 9. Significant Financing Transactions

Joint Credit Facilities and Short-term Debt

We use short-term debt, primarily commercial paper, to fund working capital requirements and as a bridge to long-term debt financing. The level of our borrowings may vary significantly during the course of the year, depending upon the timing and amount of cash requirements not satisfied by cash from operations. Short-term financing is supported by a $3.0 billion five-year joint revolving credit facility dated February 2006 with Dominion, which is scheduled to terminate in February 2011. This credit facility is being used for working capital, as support for the combined commercial paper programs of Dominion and us and other general corporate purposes. This credit facility can also be used to support up to $1.5 billion of letters of credit.

At June 30, 2007, total outstanding commercial paper supported by the joint credit facility was $1.1 billion, of which our borrowings were $914 million. At June 30, 2007, total outstanding letters of credit supported by the joint credit facility were $238 million, of which approximately $4 million was issued on our behalf.

At June 30, 2007, capacity available under the joint credit facility was $1.6 billion.

Long-term Debt

In May 2007, we issued $600 million of 6% senior notes that mature in 2037. We used the proceeds for general corporate purposes, including the repayment of short-term debt.

During the six months ended June 30, 2007, we repaid $726 million of our long-term debt.

PAGE 12

Note 10. Commitments and Contingencies

Other than the following matters, there have been no significant developments regarding commitments and contingencies as disclosed in Note 21 to the Consolidated Financial Statements in our Annual Report on Form 10-K for the year ended December 31, 2006, or Note 10 to the Consolidated Financial Statements in our Quarterly Report on Form 10-Q for the quarter ended March 31, 2007, nor have any significant new matters arisen during the quarter ended June 30, 2007.

Guarantees and Surety Bonds

As of June 30, 2007, we had issued $10 million of guarantees primarily to support commodity transactions of our subsidiaries. We had also purchased $72 million of surety bonds for various purposes, including providing workers’ compensation coverage and the posting of security to suspend execution of the judgment during the appeal of the Norfolk Southern matter, as discussed in Litigation in Note 21 to the Consolidated Financial Statements in our Annual Report on Form 10-K for the year ended December 31, 2006. Under the terms of surety bonds, we are obligated to indemnify the respective surety bond company for any amounts paid.

Nuclear Operations

The Price-Anderson Act provides the public up to $10.8 billion of liability protection per nuclear incident via obligations required of owners of nuclear power plants. The Price-Anderson Act Amendment of 1988 allows for an inflationary provision adjustment every five years. We have purchased $300 million of coverage from commercial insurance pools with the remainder provided through a mandatory industry risk-sharing program. In the event of a nuclear incident at any licensed nuclear reactor in the U.S., we could be assessed up to $100.6 million for each of our four licensed reactors, not to exceed $15 million per year per reactor. There is no limit to the number of incidents for which this retrospective premium can be assessed. The Price-Anderson Act was first enacted in 1957 and was renewed again in 2005.

Our current level of property insurance coverage ($2.55 billion each for North Anna and Surry, individually) exceeds the Nuclear Regulatory Commission’s (NRC) minimum requirement for nuclear power plant licensees of $1.06 billion per reactor site and includes coverage for premature decommissioning and functional total loss. The NRC requires that the proceeds from this insurance be used first, to return the reactor to and maintain it in a safe and stable condition and second, to decontaminate the reactor and station site in accordance with a plan approved by the NRC. Our nuclear property insurance is provided by Nuclear Electric Insurance Limited (NEIL), a mutual insurance company, and is subject to retrospective premium assessments in any policy year in which losses exceed the funds available to the insurance company. The maximum assessment for the current policy period is $51 million. Based on the severity of the incident, the board of directors of our nuclear insurer has the discretion to lower or eliminate the maximum retrospective premium assessment. We have the financial responsibility for any losses that exceed the limits or for which insurance proceeds are not available because they must first be used for stabilization and decontamination.

We purchase insurance from NEIL to cover the cost of replacement power during the prolonged outage of a nuclear unit due to direct physical damage of the unit. Under this program, we are subject to a retrospective premium assessment for any policy year in which losses exceed funds available to NEIL. The current policy period’s maximum assessment is $19 million.

Old Dominion Electric Cooperative, a part owner of North Anna Power Station, is responsible to us for its share of the nuclear decommissioning obligation and insurance premiums on applicable units, including any retrospective premium assessments and any losses not covered by insurance.

PAGE 13

Note 11. Credit Risk

We maintain a provision for credit losses based on factors surrounding the credit risk of our customers, historical trends and other information. We believe, based on our credit policies and our June 30, 2007 provision for credit losses, that it is unlikely that a material adverse effect on our financial position, results of operations or cash flows would occur as a result of counterparty nonperformance.

We sell electricity and provide distribution and transmission services to customers in Virginia and northeastern North Carolina. Management believes that this geographic concentration risk is mitigated by the diversity of our customer base, which includes residential, commercial and industrial customers, as well as rural electric cooperatives and municipalities. Credit risk associated with trade accounts receivable from energy consumers is limited due to the large number of customers.

Our exposure to potential concentrations of credit risk results primarily from sales to wholesale customers. Our gross credit exposure for each counterparty is calculated as outstanding receivables plus any unrealized on or off-balance sheet exposure, taking into account contractual netting rights. Gross credit exposure is calculated prior to the application of collateral. At June 30, 2007, our gross credit exposure totaled $49 million. Of this amount, 73% related to a single counterparty; however, the entire balance is with investment grade entities. We held no collateral for these transactions at June 30, 2007.

Note 12. Related Party Transactions

We engage in related party transactions primarily with other Dominion subsidiaries (affiliates). Our receivable and payable balances with affiliates are settled based on contractual terms or on a monthly basis, depending on the nature of the underlying transactions. We are included in Dominion’s consolidated federal income tax return and participate in certain Dominion benefit plans. A discussion of significant related party transactions follows.

Transactions with Affiliates

We transact with affiliates for certain quantities of natural gas and other commodities in the ordinary course of business.

Dominion Resources Services, Inc. (Dominion Services) provides accounting, legal and certain administrative and technical services to us. In addition, we provide certain services to affiliates, including charges for facilities and equipment usage.

Presented below are significant transactions with Dominion Services and other affiliates:


	Three Months Ended June 30,				Six Months Ended June 30,
(millions)	2007		2006		2007		2006
Commodity purchases from affiliates	$	78	$	46	$	127	$	80
Services provided by affiliates		78		81		156		158

We have borrowed funds from Dominion under both short-term and long-term borrowing arrangements. At December 31, 2006, our outstanding borrowings, net of repayments, under the Dominion money pool for our nonregulated subsidiaries totaled $140 million. There were no money pool borrowings at June 30, 2007. At June 30, 2007 and December 31, 2006, our borrowings from Dominion under a long-term note totaled $220 million. Net interest charges incurred by us related to these borrowings were $1 million for each of the three months ended June 30, 2007 and 2006, respectively, and $4 million and $3 million in the six months ended June 30, 2007 and 2006, respectively.

PAGE 14

Note 13. Operating Segments

We are organized primarily on the basis of products and services sold in the U.S. The majority of our revenue is provided through tariff rates. Generally, such revenue is allocated for management reporting based on an unbundled rate methodology among our Delivery, Energy and Generation segments. We manage our operations through the following segments:

Delivery includes our regulated electric distribution and customer service businesses.

Energy includes our regulated electric transmission operations.

Generation includes our regulated generation and energy supply operations.

Corporate includes our corporate and other functions. The contribution to net income by our primary operating segments is determined based on a measure of profit that management believes represents the segments’ core earnings. As a result, certain specific items attributable to those segments have been excluded from the profit measures evaluated by management, either in assessing segment performance or in allocating resources among the segments and are instead reported in the Corporate segment. For the six months ended June 30, 2007 and 2006, we reported net expenses of $164 million and $4 million, respectively, in our Corporate segment, attributable to our operating segments.

The net expenses in 2007 related to the following items attributable to our Generation segment:

•

A $259 million ($158 million after-tax) extraordinary charge in connection with the reapplication of SFAS No. 71 to the Virginia jurisdiction of our generation operations;

•

A $6 million ($4 million after-tax) charge resulting from a contract termination settlement; and

•

A $3 million ($2 million after-tax) impairment charge related to other-than-temporary declines in the fair value of securities held as investments in our nuclear decommissioning trusts during the first quarter of 2007.

The net expenses in 2006 related to a $7 million ($4 million after-tax) charge resulting from the write-off of certain assets no longer in use at one of our electric generating facilities, attributable to our Generation segment.

The following table presents segment information pertaining to our operations:


(millions)	Delivery		Energy		Generation			Corporate			Consolidated Total
Three Months Ended June 30, 2007
Operating revenue	$	299	$	60	$	1,064		$	1		$	1,424
Extraordinary item, net of tax		—		—		—			(158	)		(158	)
Net income (loss)		68		22		(6	)		(163	)		(79	)
Three Months Ended June 30, 2006
Operating revenue	$	287	$	52	$	983		$	1		$	1,323
Net income (loss)		66		16		8			(4	)		86
Six Months Ended June 30, 2007
Operating revenue	$	606	$	116	$	2,142		$	3		$	2,867
Extraordinary item, net of tax		—		—		—			(158	)		(158	)
Net income (loss)		145		42		(8	)		(169	)		10
Six Months Ended June 30, 2006
Operating revenue	$	576	$	104	$	1,976		$	—		$	2,656
Net income (loss)		133		33		21			(4	)		183

PAGE 15

VIRGINIA ELECTRIC AND POWER COMPANY

ITEM 2. MANAGEMENT’S DISCUSSION AND ANALYSIS OF

FINANCIAL CONDITION AND RESULTS OF OPERATIONS

Management’s Discussion and Analysis of Financial Condition and Results of Operations (MD&A) discusses the results of operations and general financial condition of Virginia Electric and Power Company. MD&A should be read in conjunction with our Consolidated Financial Statements. The terms “Virginia Power,” “Company,” “we,” “our” and “us” are used throughout this report and, depending on the context of their use, may represent any of the following: the legal entity, Virginia Electric and Power Company, one of Virginia Electric and Power Company’s consolidated subsidiaries or operating segments, or the entirety of Virginia Electric and Power Company, including our Virginia and North Carolina operations and our consolidated subsidiaries. We are a wholly-owned subsidiary of Dominion.

Contents of MD&A

Our MD&A consists of the following information:

•

Forward-Looking Statements

•

Accounting Matters

•

Results of Operations

•

Segment Results of Operations

•

Liquidity and Capital Resources

•

Future Issues and Other Matters

Forward-Looking Statements

This report contains statements concerning our expectations, plans, objectives, future financial performance and other statements that are not historical facts. These statements are “forward-looking statements” within the meaning of the Private Securities Litigation Reform Act of 1995. In most cases, the reader can identify these forward-looking statements by such words as “anticipate,” “estimate,” “forecast,” “expect,” “believe,” “should,” “could,” “plan,” “may” or other similar words.

We make forward-looking statements with full knowledge that risks and uncertainties exist that may cause actual results to differ materially from predicted results. Factors that may cause actual results to differ are often presented with the forward-looking statements themselves. Additionally, other factors may cause actual results to differ materially from those indicated in any forward-looking statement. These factors include but are not limited to:

•

Unusual weather conditions and their effect on energy sales to customers and energy commodity prices;

•

Extreme weather events, including hurricanes and winter storms, that can cause outages and property damage to our facilities;

•

State and federal legislative and regulatory developments and changes to environmental and other laws and regulations, including those related to climate change, to which we are subject;

•

Cost of environmental compliance, including those costs related to climate change;

•

Risks associated with the operation of nuclear facilities;

•

Fluctuations in energy-related commodity prices and the effect these could have on our earnings, liquidity position and the underlying value of our assets;

•

Capital market conditions, including price risk due to marketable securities held as investments in nuclear decommissioning trusts;

•

Fluctuations in interest rates;

•

Changes in rating agency requirements or credit ratings and the effect on availability and cost of capital;

•

Changes in financial or regulatory accounting principles or policies imposed by governing bodies;

•

Employee workforce factors including collective bargaining agreements and labor negotiations with union employees;

•

The risks of operating businesses in regulated industries that are subject to changing regulatory structures;

•

Changes in rules for RTOs in which we participate, including changes in rate designs and new and evolving capacity models; and

•

Political and economic conditions, including the threat of domestic terrorism, inflation and deflation.

Additionally, other risks that could cause actual results to differ from predicted results are set forth in Item 1A. Risk Factors in this report, in our Quarterly Report on Form 10-Q for the quarter ended March 31, 2007, and in our Annual Report on Form 10-K for the year ended December 31, 2006.

PAGE 16

Our forward-looking statements are based on our beliefs and assumptions using information available at the time the statements are made. We caution the reader not to place undue reliance on our forward-looking statements because the assumptions, beliefs, expectations and projections about future events may, and often do, differ materially from actual results. We undertake no obligation to update any forward-looking statement to reflect developments occurring after the statement is made.

Accounting Matters

Critical Accounting Policies and Estimates

As of June 30, 2007, there have been no significant changes with regard to critical accounting policies and estimates as disclosed in MD&A in our Annual Report on Form 10-K for the year ended December 31, 2006. The policies disclosed included the accounting for: asset retirement obligations, regulated operations, unbilled revenue and income taxes.

Other

See Notes 3 and 4 to our Consolidated Financial Statements for a discussion of newly adopted and recently issued accounting standards, and Note 5 related to the reapplication of SFAS No. 71 to the Virginia jurisdiction of our generation operations.

Results of Operations

Presented below is a summary of our consolidated results for the quarter and year-to-date periods ended June 30, 2007 and 2006:


	Second Quarter								Year-To-Date
(millions)	2007			2006		$ Change			2007		2006		$ Change
Net income (loss)	$	(79	)	$	86	$	(165	)	$	10	$	183	$	(173	)

Overview

Second Quarter 2007 vs. 2006

We reported a net loss of $79 million in 2007, as compared to net income of $86 million in 2006. Unfavorable drivers include an extraordinary charge in connection with the reapplication of SFAS No. 71 to the Virginia jurisdiction of our generation operations, and an increase in electric fuel and energy purchases resulting primarily from increased consumption of fossil fuel and higher purchased power costs due to an increase in the number of heating and cooling degree days. Favorable drivers include an increase in regulated electric sales resulting from weather and customer growth.

Year-To-Date 2007 vs. 2006

Net income decreased 95% to $10 million. Unfavorable drivers include an extraordinary charge in connection with the reapplication of SFAS No. 71 to the Virginia jurisdiction of our generation operations, an increase in electric fuel and energy purchases resulting primarily from increased consumption of fossil fuel and higher purchased power costs due to an increase in the number of heating and cooling degree days, and increased outage costs due to scheduled outages at certain of our electric generating facilities. Favorable drivers include an increase in regulated electric sales resulting from weather and customer growth.

PAGE 17

Analysis of Consolidated Operations

Presented below are selected amounts related to our results of operations:


	Second Quarter								Year-To-Date
(millions)	2007			2006		$ Change			2007			2006		$ Change
Operating Revenue	$	1,424		$	1,323	$	101		$	2,867		$	2,656	$	211
Operating Expenses
Electric fuel and energy purchases		661			555		106			1,336			1,112		224
Purchased electric capacity		107			109		(2	)		223			226		(3	)
Other energy-related commodity purchases		8			8		—			16			18		(2	)
Other operations and maintenance		274			288		(14	)		558			554		4
Depreciation and amortization		140			135		5			274			267		7
Other taxes		43			43		—			88			88		—
Other income		17			17		—			40			41		(1	)
Interest and related charges		82			70		12			144			148		(4	)
Income tax expense		47			46		1			100			101		(1	)
Extraordinary item, net of tax		(158	)		—		(158	)		(158	)		—		(158	)

An analysis of our results of operations for the second quarter and year-to-date periods of 2007 compared to the second quarter and year-to-date periods of 2006 follows:

Second Quarter 2007 vs. 2006

Operating Revenue increased 8% to $1.4 billion, reflecting the combined effects of:

•

A $42 million increase in sales to retail customers due to an increase in the number of heating and cooling degree days. As compared to the prior year, we experienced a 50% increase in heating degree days and a 21% increase in cooling degree days;

•

A $36 million increase in sales to retail customers attributable to new customer connections ($16 million) primarily in our residential and commercial customer classes and variations in rates resulting from changes in sales mix and other factors ($20 million); and

•

An $18 million increase in sales to wholesale customers primarily resulting from an increase in the number of heating and cooling degree days.

Operating Expenses and Other Items

Electric fuel and energy purchases expense increased 19% to $661 million, primarily due to increased consumption of fossil fuel and higher purchased power costs, as a result of an increase in the number of heating and cooling degree days and higher commodity prices.

Other operations and maintenance expense decreased 5% to $274 million, primarily reflecting:

•

A $10 million decrease due to an increased benefit from financial transmission rights (FTRs) granted by PJM used to offset congestion costs associated with PJM spot market activity, which are included in Electric fuel and energy purchases expense;

•

An $8 million decrease in outage costs primarily due to a decrease in the number of scheduled outage days at certain of our electric generating facilities; and

•

The absence of a $7 million charge in the second quarter of 2006, resulting from the write-off of certain assets no longer in use at one of our electric generating facilities; partially offset by

•

A $12 million increase due to fewer sales of emissions allowances.

Interest and related charges increased 17% to $82 million, primarily resulting from additional commercial paper borrowings and a revised estimate of interest on income taxes payable, partially offset by a decrease resulting from the early redemption and maturity of certain debt securities.

Extraordinary item reflects a $158 million after-tax charge in connection with the reapplication of SFAS No. 71 to the Virginia jurisdiction of our generation operations.

PAGE 18

Year-To-Date 2007 vs. 2006

Operating Revenue increased 8% to $2.9 billion, reflecting the combined effects of:

•

A $95 million increase in sales to retail customers due to an increase in the number of heating and cooling degree days. As compared to the prior year, we experienced a 21% increase in cooling degree days and a 16% increase in heating degree days;

•

A $79 million increase in sales to retail customers attributable to new customer connections ($33 million) primarily in our residential and commercial customer classes and variations in rates resulting from changes in sales mix and other factors ($46 million);

•

A $27 million increase in sales to wholesale customers primarily resulting from an increase in the number of heating and cooling degree days; and

•

A $19 million increase resulting primarily from higher ancillary service revenue reflecting higher regulation and operating reserves revenue received from PJM.

Operating Expenses and Other Items

Electric fuel and energy purchases expense increased 20% to $1.3 billion, primarily due to increased consumption of fossil fuel and higher purchased power costs, as a result of an increase in the number of heating and cooling degree days and higher commodity prices.

Other operations and maintenance expense increased 1% to $558 million, primarily reflecting:

•

A $19 million increase due to fewer sales of emissions allowances;

•

A $6 million charge resulting from a contract termination settlement;

•

A $6 million increase resulting from the absence of a benefit in 2006 from a favorable change in the fair value of a forward contract for purchased power; and

•

A $3 million increase in outage costs primarily due to an increase in the number of scheduled outage days at certain of our electric generating facilities; partially offset by

•

A $22 million decrease due to an increased benefit from FTRs granted by PJM used to offset congestion costs associated with PJM spot market activity, which are included in Electric fuel and energy purchases expense; and

•

The absence of a $7 million charge in the second quarter of 2006, resulting from the write-off of certain assets no longer in use at one of our electric generating facilities.

Extraordinary item reflects a $158 million after-tax charge in connection with the reapplication of SFAS No. 71 to the Virginia jurisdiction of our generation operations.

PAGE 19

Segment Results of Operations

Presented below is a summary of contributions by our operating segments to net income (loss) for the quarter and year-to-date periods ended June 30, 2007 and 2006:


	Second Quarter									Year-To-Date
(millions)	2007			2006			$ Change			2007			2006			$ Change
Delivery	$	68		$	66		$	2		$	145		$	133		$	12
Energy		22			16			6			42			33			9
Generation		(6	)		8			(14	)		(8	)		21			(29	)

Primary operating segments		84			90			(6	)		179			187			(8	)
Corporate		(163	)		(4	)		(159	)		(169	)		(4	)		(165	)

Consolidated	$	(79	)	$	86		$	(165	)	$	10		$	183		$	(173	)

Delivery

Presented below are operating statistics related to our Delivery operations:


	Second Quarter				Year-To-Date
	2007	2006	% Change		2007	2006	% Change
Electricity delivered (million mwhrs)	20.0	18.7	7	%	41.0	38.2	7	%
Degree days (electric service area):
Cooling⁽¹⁾	481	396	21		493	409	21
Heating⁽²⁾	367	245	50		2,360	2,041	16
Average electric delivery customer accounts⁽³⁾	2,356	2,322	1		2,354	2,318	2

mwhrs

= megawatt hours

(1)	Cooling degree days (CDDs) are units measuring the extent to which the average daily temperature is greater than 65 degrees. CDDs are calculated as the difference between the average temperature for each day and 65 degrees.

(2)	Heating degree days (HDDs) are units measuring the extent to which the average daily temperature is less than 65 degrees. HDDs are calculated as the difference between the average temperature for each day and 65 degrees.

(3)	Period average, in thousands.

Presented below, on an after-tax basis, are the key factors impacting Delivery’s net income contribution:


	Second Quarter 2007 vs. 2006			Year-To-Date 2007 vs. 2006
(millions)	Increase (Decrease)			Increase (Decrease)
Regulated electric sales:
Weather	$	6		$	13
Customer growth		2			5
Interest expense		(3	)		—
Other		(3	)		(6	)

Change in net income contribution	$	2		$	12

PAGE 20

Energy

Presented below, on an after-tax basis, are the key factors impacting Energy’s net income contribution:


	Second Quarter 2007 vs. 2006		Year-To-Date 2007 vs. 2006
(millions)	Increase (Decrease)		Increase (Decrease)
Regulated electric sales:
Weather	$	1	$	2
Customer growth		—		1
Other		3		3
Other		2		3

Change in net income contribution	$	6	$	9

Generation

Presented below are operating statistics related to our Generation operations:


	Second Quarter				Year-To-Date
	2007	2006	% Change		2007	2006	% Change
Electricity supplied (million mwhrs)	20.0	18.7	7	%	41.0	38.2	7	%
Degree days (electric service area):
Cooling	481	396	21		493	409	21
Heating	367	245	50		2,360	2,041	16

Presented below, on an after-tax basis, are the key factors impacting Generation’s net income contribution:


	Second Quarter 2007 vs. 2006			Year-To-Date 2007 vs. 2006
(millions)	Increase (Decrease)			Increase (Decrease)
Unrecovered Virginia fuel expenses⁽¹⁾	$	(41	)	$	(90	)
Interest expense		(3	)		3
Regulated electric sales:
Weather		12			27
Customer growth		5			9
Other		9			12
Outage costs		5			(2	)
Ancillary service revenue		4			12
Other		(5	)		—

Change in net income contribution	$	(14	)	$	(29	)

(1)	Increase is primarily due to increased consumption of fossil fuel and higher purchased power costs due to an increase in the number of heating and cooling degree days and an increase in commodity prices.

PAGE 21

Corporate

Presented below are the Corporate segment’s after-tax results.


	Second Quarter									Year-To-Date
(millions)	2007			2006			$ Change			2007			2006			$ Change
Specific items attributable to operating segments	$	(158	)	$	(4	)	$	(154	)	$	(164	)	$	(4	)	$	(160	)
Other corporate operations		(5	)		—			(5	)		(5	)		—			(5	)

Total net expense	$	(163	)	$	(4	)	$	(159	)	$	(169	)	$	(4	)	$	(165	)

Specific Items Attributable to Operating Segments

Corporate includes specific items attributable to our primary operating segments that have been excluded from the profit measures evaluated by management, either in assessing segment performance or in allocating resources among the segments. See Note 13 to our Consolidated Financial Statements for a discussion of these items.

Other Corporate Operations

The net expenses associated with other corporate operations for the quarter and year-to-date periods ended June 30, 2007 increased by $5 million, primarily due to unallocated interest expense and income taxes.

Liquidity and Capital Resources

We depend on both internal and external sources of liquidity to provide working capital and to fund capital requirements. Short-term cash requirements not met by cash provided by operations are generally satisfied with proceeds from short-term borrowings. Long-term cash needs are met through sales of securities and additional long-term debt financings.

At June 30, 2007, we had $1.6 billion of unused capacity under our joint credit facility.

A summary of our cash flows for the six months ended June 30, 2007 and 2006 is presented below:


(millions)	2007			2006
Cash and cash equivalents at January 1,	$	18		$	54
Cash flows provided by (used in)
Operating activities		677			674
Investing activities		(533	)		(470	)
Financing activities		(137	)		(238	)

Net increase (decrease) in cash and cash equivalents		7			(34	)

Cash and cash equivalents at June 30,	$	25		$	20

Operating Cash Flows

For the six months ended June 30, 2007, net cash provided by operating activities increased by $3 million as compared to the six months ended June 30, 2006. The increase in cash flow due to favorable weather and customer growth was offset by unfavorable changes in working capital. We believe that our operations provide a stable source of cash flow sufficient to contribute to planned levels of capital expenditures and provide dividends to Dominion. However, our operations are subject to risks and uncertainties that may negatively impact the timing or amounts of operating cash flows. See discussion of such factors in Item 1A. Risk Factors in this report, in our Quarterly Report on Form 10-Q for the quarter ended March 31, 2007, and in our Annual Report on Form 10-K for the year ended December 31, 2006.

Credit Risk

Our exposure to potential concentrations of credit risk results primarily from sales to wholesale customers. Presented below is a summary of our gross exposure as of June 30, 2007 for these activities. Our gross credit exposure for each counterparty is calculated as outstanding receivables plus any unrealized on or off-balance sheet exposure, taking into account contractual netting rights. Gross credit exposure is calculated prior to the application of collateral. We held no collateral for these transactions at June 30, 2007.

PAGE 22


(millions)	Gross Credit Exposure
Investment grade⁽¹⁾	$	13
Non-investment grade		—
No external ratings:
Internally rated—investment grade⁽²⁾		36
Internally rated—non-investment grade		—

Total	$	49

(1)	Designations as investment grade are based on minimum credit ratings assigned by Moody’s Investors Service and Standard & Poor’s Ratings Services. The five largest counterparty exposures, combined, for this category represented approximately 26% of the total gross credit exposure.

(2)	The five largest counterparty exposures, combined, for this category represented approximately 74% of the total gross credit exposure.

Investing Cash Flows

Significant investing activities in the six months ended June 30, 2007 included:

•

$460 million for environmental upgrades, routine capital improvements of generation facilities and construction and improvements of electric transmission and distribution assets;

•

$279 million for purchases of securities held as investments in our nuclear decommissioning trusts; and

•

$66 million for nuclear fuel expenditures; partially offset by

•

$263 million of proceeds from sales of securities held as investments in our nuclear decommissioning trusts.

Financing Cash Flows and Liquidity

We rely on banks and capital markets as significant sources of funding for capital requirements not satisfied by the cash provided by our operations. As discussed in Credit Ratings and Debt Covenants, our ability to borrow funds or issue securities and the return demanded by investors are affected by our credit ratings. In addition, the raising of external capital is subject to meeting certain regulatory requirements, including obtaining regulatory approval from the Virginia Commission.

Significant financing activities for the six months ended June 30, 2007 included:

•

$726 million for the repayment of long-term debt;

•

$142 million of common dividend payments; and

•

$140 million for the net repayment of affiliated current borrowings; partially offset by

•

$600 million from the issuance of long-term debt; and

•

$296 million from the net issuance of short-term debt.

See Note 9 to our Consolidated Financial Statements for further information regarding our credit facilities, liquidity and significant financing transactions. Also see Note 12 to our Consolidated Financial Statements for further information regarding our borrowings from Dominion.

Credit Ratings and Debt Covenants

Credit ratings are intended to provide banks and capital market participants with a framework for comparing the credit quality of securities and are not a recommendation to buy, sell or hold securities. In Credit Ratings and Debt Covenants of MD&A in our Annual Report on Form 10-K for the year ended December 31, 2006, we discussed our use of capital markets and the impact of credit ratings on the accessibility and costs of using these markets, as well as various covenants present in the enabling agreements underlying our debt. As of June 30, 2007, there have been no changes in our credit ratings nor changes to or events of default under our debt covenants.

Future Cash Payments for Contractual Obligations

As of June 30, 2007, there have been no material changes outside the ordinary course of business to the contractual obligations disclosed in MD&A in our Annual Report on Form 10-K for the year ended December 31, 2006.

PAGE 23

Future Issues and Other Matters

The following discussion of future issues and other information includes current developments of previously disclosed matters and new issues arising during the period covered by and subsequent to our Consolidated Financial Statements. This section should be read in conjunction with Future Issues and Other Matters in MD&A in our Annual Report on Form 10-K for the year ended December 31, 2006 and in our Quarterly Report on Form 10-Q for the quarter ended March 31, 2007.

Virginia Fuel Expenses

In April 2007, we filed our Virginia fuel factor application with the Virginia Commission, requesting an increase in our Virginia fuel factor from 1.891¢ per kilowatt hour (kWh) to 2.232¢ per kWh, an increase of $219 million. The application established a need for an annual increase in fuel expense recovery for the period July 1, 2007 through June 30, 2008 of approximately $662 million. However, under the 2007 amendments to the fuel cost recovery statute, the requested increase as of July 1, 2007 was limited to an amount that results in the residential customer class not receiving an increase of more than 4% of total rates in effect as of June 30, 2007. The percentage increase for individual residential customers, and for other customer classes, depended on their current rates and respective usage. The 4% limitation to the residential class limited the fuel factor increase for Virginia jurisdictional customers to approximately $219 million, effective July 1, 2007; the balance of approximately $443 million will be deferred and subsequently recovered, without interest, during the period commencing July 1, 2008 and ending June 30, 2011. As a result of these changes, deferred fuel accounting will be applied for the over and under recovery of fuel costs. The Virginia Commission held a public hearing on June 19, 2007 and, on June 26, 2007, entered an order approving the requested increase effective July 1, 2007.

Transmission Expansion Plan

Each year, as part of PJM’s Regional Transmission Expansion Plan (RTEP) process, reliability projects are authorized. In June 2006, PJM, through the RTEP process, authorized construction of numerous electric transmission upgrades through 2011. We are involved in two of the major construction projects. The first project is an approximately 270-mile 500-kilovolt (kV) transmission line from southwestern Pennsylvania to northern Virginia, of which we will construct approximately 65 miles in Virginia and a subsidiary of Allegheny Energy, Inc. will construct the remainder. The second project is an approximately 60-mile 500 kV transmission line that we will construct in southeastern Virginia. These transmission upgrades are designed to improve the reliability of service to our customers and the region. The siting and construction of these transmission lines will be subject to applicable state and federal permits and approvals. In April 2007, we filed an application with the Virginia Commission requesting approval of the proposed construction of the 65-mile transmission line in northern Virginia. In May 2007, we filed an application with the Virginia Commission requesting approval of the proposed construction of the 60-mile transmission line in southeastern Virginia.

Generation Expansion

Based on available generation capacity and current estimates of growth in customer demand in our utility service area, we will need additional generation in the future. As a result, in April 2007, we filed an application with the Virginia Commission requesting approval to add two 150 megawatt (Mw) natural gas-fired electric generating units to our Ladysmith Power Station to supply electricity during periods of peak demand. Pending regulatory approval and necessary permits, the facility is expected to be in operation by August 2008, at an estimated cost of $135 million.

In July 2007, we filed an application with the Virginia Commission requesting approval to construct and operate a 585 Mw (nominal) carbon capture compatible, clean coal powered electric generation facility to be located in Wise County, Virginia. We also requested approval to continue to accrue allowance for funds used during construction (AFUDC) until capped rates end and, beginning January 1, 2009, current recovery of financing costs, including a return on common equity of 11.75% together with a 200 basis point enhancement, through a rate adjustment clause. Pending regulatory approval and necessary permits, the facility is expected to be in operation by 2012 at an estimated cost of approximately $1.6 billion, at that time.

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PJM Rate Design

In May 2005, the Federal Energy Regulatory Commission (FERC) issued an order finding that PJM’s existing transmission service rate design may not be just and reasonable, and ordered an investigation and hearings into the matter. In April 2007, FERC reaffirmed PJM’s existing transmission service rate design. FERC also determined that the costs of new, PJM-planned transmission facilities that operate at or above 500 kV will be allocated on a PJM region-wide basis, while the costs of new, PJM-planned transmission facilities that operate below 500 kV will be assigned to zones within the PJM region based on a new model to be developed in further proceedings. Settlement discussions among stakeholders in the PJM region are underway, which may address these cost allocations. We cannot predict how the cost of the facilities below 500 kV will be allocated, or whether the FERC decision will be modified upon rehearing or appeal.

Collective Bargaining Agreement

We have reached an agreement with the International Brotherhood of Electrical Workers, Local 50 (Local 50) for a six year collective bargaining agreement expiring March 31, 2013. Local 50 represents approximately 3,200 of our employees in Virginia, North Carolina and the Mount Storm Power Station in West Virginia.

Environmental Matters

In April 2007, the U. S. Supreme Court ruled that the Environmental Protection Agency (EPA) has the authority to regulate greenhouse gas emissions under the Clean Air Act which could result in future EPA action. In June 2007, the President announced U.S. support for an effort to develop a new post-2012 framework on climate change involving the top 10 to 15 greenhouse gas emitting countries that would focus on establishing a long-term global goal to reduce greenhouse gas emissions with each country establishing its own mid-term targets and programs. Although we expect legislative or regulatory action on the regulation of greenhouse gas emissions in the future, the outcome in terms of specific requirements and timing is uncertain, and we cannot predict the financial impact on our operations at this time.

Clean Water Act Compliance

In July 2004, the EPA published regulations that govern existing utilities that employ a cooling water intake structure, and that have flow levels exceeding a minimum threshold. The EPA’s rule presents several compliance options. We have been evaluating information from certain of our existing power stations and had expected to spend approximately $4 million over the next two years conducting studies and technical evaluations. However, in January 2007, the U.S. Court of Appeals for the Second Circuit issued a decision on an appeal of the regulations, remanding the rule to the EPA. In July 2007, the EPA suspended the regulations pending further rulemaking consistent with the decision issued by the U. S. Court of Appeals for the Second Circuit. We cannot predict the outcome of the EPA regulatory process or determine with any certainty what specific controls may be required.

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VIRGINIA ELECTRIC AND POWER COMPANY

ITEM 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES

ABOUT MARKET RISK

The matters discussed in this Item may contain “forward-looking statements” as described in the introductory paragraphs under Part I, Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations of this Form 10-Q. The reader’s attention is directed to those paragraphs for discussion of various risks and uncertainties that may affect our future.

Market Risk Sensitive Instruments and Risk Management

Our financial instruments, commodity contracts and related financial derivative instruments are exposed to potential losses due to adverse changes in commodity prices, interest rates, foreign currency exchange rates and equity security prices as described below. Commodity price risk is due to our exposure to market shifts for prices received and paid for natural gas, electricity and other commodities. Interest rate risk is generally related to our outstanding debt. We are exposed to foreign currency exchange rate risks related to our purchases of fuel and fuel services denominated in foreign currencies. In addition, we are exposed to equity price risk through various portfolios of equity securities.

The following sensitivity analysis estimates the potential loss of future earnings or fair value from market risk sensitive instruments over a selected time period due to a 10% unfavorable change in commodity prices, interest rates and foreign currency exchange rates.

Commodity Price Risk

To manage price risk, we primarily hold commodity-based financial derivative instruments for nontrading purposes associated with the purchase of electricity and natural gas.

The derivatives used to manage our commodity price risk are executed within established policies and procedures and may include instruments such as futures, forwards, swaps and options that are sensitive to changes in the related commodity prices. For sensitivity analysis purposes, the fair value of commodity-based financial derivative instruments is determined based on models that consider the market prices of commodities in future periods, the volatility of the market prices in each period, as well as the time value factors of the derivative instruments. Prices and volatility are principally determined based on actively-quoted market prices.

A hypothetical 10% unfavorable change in commodity prices would have resulted in a decrease of approximately $14 million and $3 million in the fair value of our non-trading commodity-based financial derivative instruments as of June 30, 2007 and December 31, 2006, respectively. The increase is primarily due to new power derivatives executed during 2007.

The impact of a change in energy commodity prices on our non-trading commodity-based financial derivative instruments at a point in time is not necessarily representative of the results that will be realized when such contracts are ultimately settled. For example, our expenses for purchased power when combined with the settlement of commodity derivative instruments used for hedging purposes, will generally result in a range of prices for those purchases contemplated by the risk management strategy.

Foreign Currency Exchange Risk

We manage our foreign currency exchange risk exposure associated with anticipated future purchases of nuclear fuel processing services denominated in foreign currencies by utilizing currency forward contracts. As a result of holding these contracts as hedges, our exposure to foreign currency risk is minimal. A hypothetical 10% decrease in relevant foreign exchange rates would have resulted in a decrease of approximately $1 million and $3 million in the fair value of currency forward contracts held by us at June 30, 2007 and December 31, 2006, respectively.

Interest Rate Risk

We manage our interest rate risk exposure predominantly by maintaining a portfolio of fixed and variable-rate debt. We also enter into interest rate sensitive derivatives, including interest rate swaps and interest rate lock agreements. For financial instruments outstanding at June 30, 2007, a hypothetical 10% increase in market interest rates would have resulted in a decrease in annual earnings of approximately $7 million. A hypothetical 10% increase in market interest rates, as determined at December 31, 2006, would have resulted in a decrease in annual earnings of approximately $6 million.

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Investment Price Risk

We are subject to investment price risk due to marketable securities held as investments in decommissioning trust funds. These marketable securities are managed by third-party investment managers and are reported in our Consolidated Balance Sheets at fair value. Net realized gains (including investment income) on nuclear decommissioning trust investments were $18 million and $25 million for the six months ended June 30, 2007 and 2006, respectively, and $36 million for the year ended December 31, 2006. We recorded, in AOCI, gross unrealized gains on decommissioning trust investments of $5 million and net unrealized losses on decommissioning trust investments of $11 million for the six months ended June 30, 2007 and 2006, respectively, and gross unrealized gains on decommissioning trust investments of $86 million for the year ended December 31, 2006.

Following the reapplication of SFAS No. 71 to the Virginia jurisdiction of our generation operations, gains or losses on those decommissioning trust investments are deferred as regulatory liabilities or regulatory assets, respectively.

Dominion sponsors employee pension and other postretirement benefit plans, in which our employees participate, that hold investments in trusts to fund benefit payments. To the extent that the values of investments held in these trusts decline, the effect will be reflected in our recognition of the periodic cost of such employee benefit plans and the determination of the amount of cash that we will contribute to the employee benefit plans.

ITEM 4. CONTROLS AND PROCEDURES

Senior management, including our Chief Executive Officer and Chief Financial Officer, evaluated the effectiveness of our disclosure controls and procedures as of the end of the period covered by this report. Based on this evaluation process, the Chief Executive Officer and Chief Financial Officer have concluded that our disclosure controls and procedures are effective. There were no changes in our internal control over financial reporting that occurred during the last fiscal quarter that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.

PART II. - OTHER INFORMATION

ITEM 1. LEGAL PROCEEDINGS

From time to time, we are alleged to be in violation or in default under orders, statutes, rules or regulations relating to the environment, compliance plans imposed upon or agreed to by us, or permits issued by various local, state and federal agencies for the construction or operation of facilities. Administrative proceedings may also be pending on these matters. In addition, in the ordinary course of business, we are involved in various legal proceedings. Management believes that the ultimate resolution of these proceedings will not have a material adverse effect on our financial position, liquidity or results of operations. See Future Issues and Other Matters in MD&A in our Consolidated Financial Statements for discussions on various environmental and regulatory proceedings to which we are a party.

ITEM 1A. RISK FACTORS

Our business is influenced by many factors that are difficult to predict, involve uncertainties that may materially affect actual results and are often beyond our control. We have identified a number of these risk factors in our Annual Report on Form 10-K for the year ended December 31, 2006, which factors should be taken into consideration when reviewing the information contained in this report. With the exception of the risk factor below, there have been no material changes with regard to the risk factors previously disclosed in our most recent Form 10-K or our Quarterly Report on Form 10-Q for the quarter ended March 31, 2007. For other factors that may cause actual results to differ materially from those indicated in any forward-looking statement or projection contained in this report, see Forward-Looking Statements in MD&A.

We are exposed to cost-recovery shortfalls because of capped base rates in effect in Virginia for our regulated electric utility. Under the 1999 Virginia Restructuring Act (Restructuring Act) as amended in 2007, our base rates remain capped through December 31, 2008 unless sooner modified or terminated. Although the Restructuring Act allows for the recovery of certain generation-related costs during the capped rates period, we remain exposed to numerous risks of cost-recovery shortfalls, such as costs related to hurricanes or other unanticipated events.

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ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS

On April 27, 2007, by consent in lieu of the annual meeting, Dominion Resources, Inc., the sole holder of all the voting common stock of the Company, elected the following persons to serve as Directors: Thomas F. Farrell, II and Thomas N. Chewning.

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ITEM 6. EXHIBITS

(a) Exhibits:



3.1		Restated Articles of Incorporation, as in effect on October 28, 2003 (Exhibit 3.1, Form 10-Q for the quarter ended September 30, 2003, File No. 1-2255, incorporated by reference).

3.2		Bylaws, as amended, as in effect on April 28, 2000 (Exhibit 3, Form 10-Q for the quarter ended March 31, 2000, File No. 1-2255, incorporated by reference).

4.1		Form of Senior Indenture, dated as of June 1, 1998, between Virginia Electric and Power Company and The Bank of New York (as successor trustee to JP Morgan Chase Bank (formerly The Chase Manhattan Bank)) as supplemented by the First Supplemental Indenture (Exhibit 4.2, Form 8-K, dated June 12, 1998, File No. 1-2255, incorporated by reference); Second Supplemental Indenture (Exhibit 4.2, Form 8-K, dated June 3, 1999, File No.1-2255, incorporated by reference); Third Supplemental Indenture (Exhibit 4.2, Form 8-K, dated October 27, 1999, File No. 1-2255, incorporated by reference); Form of Fourth Supplemental Indenture (Exhibit 4.2, Form 8-K, dated March 22, 2001, File No. 1-2255, incorporated by reference); and Form of Fifth Supplemental Indenture (Exhibit 4.3, Form 8-K, dated March 22, 2001, File No. 1-2255, incorporated by reference); Form of Sixth Supplemental Indenture (Exhibit 4.2, Form 8-K, dated January 24, 2002, incorporated by reference); Seventh Supplemental Indenture dated September 1, 2002 (Exhibit 4.4, Form 8-K filed September 11, 2002, File No. 1-2255, incorporated by reference); Form of Ninth Supplemental Indenture (Exhibit 4.2, Form 8-K filed December 4, 2003, File No. 1-2255, incorporated by reference); Form of Eighth Supplemental Indenture (Exhibit 4.2, Form 8-K filed February 27, 2003, File No. 1-2255, incorporated by reference); Form of Tenth Supplemental Indenture (Exhibit 4.3, Form 8-K filed December 4, 2003, File No. 1-2255, incorporated by reference); Form of Eleventh Supplemental Indenture (Exhibit 4.2, Form 8-K filed December 11, 2003, File No. 1-2255, incorporated by reference); Form of Twelfth Supplemental Indenture (Exhibit 4.2, Form 8-K filed January 12, 2006, File No. 1-2255, incorporated by reference); Form of Thirteenth Supplemental Indenture (Exhibit 4.3, Form 8-K filed January 12, 2006, File No. 1-2255, incorporated by reference); Form of Fourteenth Supplemental Indenture (Exhibit 4.2, Form 8-K filed May 16, 2007, File No. 1-2255, incorporated by reference).

4.2		Virginia Electric and Power Company agrees to furnish to the Securities and Exchange Commission upon request any other instrument with respect to long-term debt as to which the total amount of securities authorized does not exceed 10% of its total consolidated assets.

12.1		Ratio of earnings to fixed charges (filed herewith).

12.2		Ratio of earnings to fixed charges and preferred dividends (filed herewith).

31.1		Certification by Registrant’s Chief Executive Officer pursuant to Section 302 of the Sarbanes-Oxley Act of 2002 (filed herewith).

31.2		Certification by Registrant’s Principal Financial Officer pursuant to Section 302 of the Sarbanes-Oxley Act of 2002 (filed herewith).

32		Certification to the Securities and Exchange Commission by Registrant’s Chief Executive Officer and Chief Financial Officer, as required by Section 906 of the Sarbanes-Oxley Act of 2002 (filed herewith).

99		Condensed consolidated earnings statements (unaudited) (filed herewith).

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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.


				VIRGINIA ELECTRIC AND POWER COMPANY
				Registrant

August 8, 2007				/s/ Steven A. Rogers
				Steven A. Rogers
				Senior Vice President and
				Chief Accounting Officer

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