Edgar Filing: VIRGINIA ELECTRIC & POWER CO

Form 10-Q

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

¨	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 March 31, 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 Months Ended March 31, 2007 and 2006	3

	Consolidated Balance Sheets – March 31, 2007 and December 31, 2006	4

	Consolidated Statements of Cash Flows – Three Months Ended March 31, 2007 and 2006	6

	Notes to Consolidated Financial Statements	7

Item 2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	15

Item 3.	Quantitative and Qualitative Disclosures About Market Risk	24

Item 4.	Controls and Procedures	25

	PART II. Other Information

Item 1.	Legal Proceedings	26

Item 1A.	Risk Factors	26

Item 4	Submission of Matters to a Vote of Security Holders	26

Item 6.	Exhibits	27

PAGE 2

VIRGINIA ELECTRIC AND POWER COMPANY

PART I. FINANCIAL INFORMATION

ITEM 1. CONSOLIDATED FINANCIAL STATEMENTS

CONSOLIDATED STATEMENTS OF INCOME

(Unaudited)


	Three Months Ended March 31,
	2007		2006
(millions)
Operating Revenue	$	1,443	$	1,333
Operating Expenses
Electric fuel and energy purchases		675		557
Purchased electric capacity		116		117
Other energy-related commodity purchases		8		10
Other operations and maintenance:
External suppliers		206		189
Affiliated suppliers		78		77
Depreciation and amortization		134		132
Other taxes		45		45

Total operating expenses		1,262		1,127

Income from operations		181		206

Other income		23		24

Interest and related charges:
Interest expense		54		70
Interest expense—junior subordinated notes payable to affiliated trust		8		8

Total interest and related charges		62		78

Income before income tax expense		142		152
Income tax expense		53		55

Net Income		89		97
Preferred dividends		4		4

Balance available for common stock	$	85	$	93

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

PAGE 3

VIRGINIA ELECTRIC AND POWER COMPANY

CONSOLIDATED BALANCE SHEETS

(Unaudited)


	March 31, 2007			December 31, 2006⁽¹⁾
(millions)
ASSETS
Current Assets
Cash and cash equivalents	$	51		$	18
Customer accounts receivable (less allowance for doubtful accounts of $8 and $7)		652			650
Other receivables (less allowance for doubtful accounts of $9 at both dates)		77			98
Inventories (average cost method)		453			505
Prepayments		54			133
Other		40			51

Total current assets		1,327			1,455

Investments
Nuclear decommissioning trust funds		1,307			1,293
Other		22			22

Total investments		1,329			1,315

Property, Plant and Equipment
Property, plant and equipment		20,974			20,771
Accumulated depreciation and amortization		(8,464	)		(8,353	)

Total property, plant and equipment, net		12,510			12,418

Deferred Charges and Other Assets		463			495

Total assets	$	15,629		$	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.

PAGE 4

VIRGINIA ELECTRIC AND POWER COMPANY

CONSOLIDATED BALANCE SHEETS—(Continued)

(Unaudited)


	March 31, 2007		December 31, 2006⁽¹⁾
(millions)
LIABILITIES AND SHAREHOLDER’S EQUITY
Current Liabilities
Securities due within one year	$	644	$	1,267
Short-term debt		1,340		618
Accounts payable		439		418
Other		481		638

Total current liabilities		2,904		2,941

Long-Term Debt
Long-term debt		2,896		2,987
Junior subordinated notes payable to affiliated trust		412		412
Notes payable—other affiliate		220		220

Total long-term debt		3,528		3,619

Deferred Credits and Other Liabilities
Deferred income taxes and investment tax credits		2,200		2,308
Other		1,328		1,166

Total deferred credits and other liabilities		3,528		3,474

Total liabilities		9,960		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		969		955
Accumulated other comprehensive income		167		162

Total common shareholder’s equity		5,412		5,392

Total liabilities and shareholder’s equity	$	15,629	$	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.

PAGE 5

VIRGINIA ELECTRIC AND POWER COMPANY

CONSOLIDATED STATEMENTS OF CASH FLOWS

(Unaudited)


	Three Months Ended March 31,
	2007			2006
(millions)
Operating Activities
Net income	$	89		$	97
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation and amortization		156			153
Deferred income taxes and investment tax credits, net		29			(15	)
Deferred fuel expenses, net		28			31
Other adjustments to net income		(19	)		(22	)
Changes in:
Accounts receivable		20			97
Affiliated accounts receivable and payable		(20	)		12
Inventories		52			(63	)
Accounts payable		39			7
Accrued interest, payroll and taxes		(32	)		60
Prepayments		79			5
Other operating assets and liabilities		88			37

Net cash provided by operating activities		509			399

Investing Activities
Plant construction and other property additions		(220	)		(205	)
Purchases of nuclear fuel		(37	)		(38	)
Purchases of securities		(137	)		(155	)
Proceeds from sales of securities		115			156
Other		(3	)		1

Net cash used in investing activities		(282	)		(241	)

Financing Activities
Issuance (repayment) of short-term debt, net		722			(905	)
Issuance (repayment) of affiliated current borrowings, net		(117	)		414
Issuance of long-term debt		—			1,000
Repayment of long-term debt		(718	)		(607	)
Common dividend payments		(77	)		(76	)
Preferred dividend payments		(4	)		(4	)
Other		—			(11	)

Net cash used in financing activities		(194	)		(189	)

Increase (decrease) in cash and cash equivalents		33			(31	)
Cash and cash equivalents at beginning of period		18			54

Cash and cash equivalents at end of period	$	51		$	23

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

PAGE 6

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 March 31, 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 March 31, 2007, and our results of operations and cash flows for the three months ended March 31, 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.

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.

PAGE 7

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. 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. Unrecognized tax benefits as of January 1, 2007, included $5 million that, if recognized, would lower the effective tax rate. Through March 31, 2007, there have been no significant changes in our unrecognized tax benefits.

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.

We have recently reached a settlement for tax years 1993 – 1998 with the Appellate Division of the Internal Revenue Service (IRS), which is subject to a mandatory review by the U.S. Congressional Joint Committee on Taxation. We expect the settlement to be finalized later this year, resulting in a refund of approximately $39 million. 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 by applying amounts previously deposited with the IRS. In addition, the examination of our 2002 and 2003 returns by the IRS is expected to be completed by July 2007. Based on our concurrence with certain proposed adjustments and payments expected to be made later this year, unrecognized tax benefits could be reduced by approximately $9 million. Our receipt or payment of the amounts discussed above would not impact our results of operations. At this time, we cannot estimate the impact on unrecognized tax benefits that could result in the next twelve months from additional payments that may be made for adjustments remaining in dispute or any newly proposed adjustments.

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.

PAGE 8

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 Statement of Financial Accounting Standards (SFAS) No. 157, Fair Value Measurements, which defines fair value, establishes a framework for measuring fair value and expands disclosures about fair value measurements (SFAS No. 157). 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.

Note 5. Operating Revenue

Our operating revenue consists of the following:


	Three Months Ended March 31,
	2007		2006
(millions)
Regulated electric sales	$	1,411	$	1,298
Other		32		35

Total operating revenue	$	1,443	$	1,333

PAGE 9

Note 6. Comprehensive Income

The following table presents total comprehensive income:


	Three Months Ended March 31,
	2007			2006
(millions)
Net income	$	89		$	97
Other comprehensive income:
Net other comprehensive income (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		7			(7	)
Other, net of tax⁽¹⁾		(2	)		10

Other comprehensive income		5			3

Total comprehensive income	$	94		$	100

(1)

For the three months ended March 31, 2007, the amount primarily represents a reduction in gross unrealized gains on investments held in nuclear decommissioning trusts. For the three months ended March 31, 2006, the amount primarily represents net unrealized gains on investments held in nuclear decommissioning trusts.

Note 7. Hedge Accounting Activities

We are exposed to the impact of market fluctuations in the price of natural gas, electricity and other energy-related products purchased, as well as currency exchange and interest rate risks of our business operations. We use derivative instruments to manage our exposure to certain of these risks and designate derivative instruments as fair value or cash flow hedges for accounting purposes as allowed by SFAS No. 133, Accounting for Derivative Instruments and Hedging Activities. For the three months ended March 31, 2007 and 2006, hedge ineffectiveness and time value that were excluded from the measurement of effectiveness and included in net income were not material.

The following table presents selected information related to cash flow hedges included in accumulated other comprehensive income (AOCI) in our Consolidated Balance Sheet at March 31, 2007:


	AOCI After-Tax		Portion Expected to be Reclassified to Earnings During the Next 12 Months After-Tax		Maximum Term
(millions)
Natural gas	$	3	$	3	3 months
Electricity		2		2	3 months
Interest rate		1		—	103 months
Foreign currency		13		6	6 months

Total	$	19	$	11

The amounts that will be reclassified from AOCI to earnings will generally be offset by the recognition of the hedged transactions (e.g., anticipated purchases) in earnings, thereby achieving the realization of prices contemplated by the underlying risk management strategies and will vary from the expected amounts presented above as a result of changes in market prices, interest rates and foreign exchange rates.

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).

PAGE 10

As of March 31, 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 $1.3 billion at March 31, 2007. We are not subject to any risk of loss from these potential VIEs, other than the remaining purchase commitments. We paid $26 million and $25 million for electric generation capacity and $27 million and $18 million for electric energy from these entities in the three months ended March 31, 2007 and 2006, respectively.

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 March 31, 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 and $14 million and $15 million for electric energy from these entities in the three months ended March 31, 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 $99 million and $111 million to the LLCs for coal and synthetic fuel produced from coal in the three months ended March 31, 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.

Our Consolidated Balance Sheets as of March 31, 2007 and December 31, 2006 reflect net property, plant and equipment of $335 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.

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 and Consolidated Natural Gas Company (CNG), a wholly-owned subsidiary of 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, CNG 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 March 31, 2007, total outstanding commercial paper supported by the joint credit facility was $2.0 billion, of which our borrowings were $1.3 billion. At March 31, 2007, total outstanding letters of credit supported by the joint credit facility were $299 million, of which less than $1 million was issued on our behalf.

At March 31, 2007, capacity available under the credit facility was $723 million.

Long-term Debt

During the three months ended March 31, 2007, we repaid $718 million of our long-term debt.

Note 10. Commitments and Contingencies

Other than the matters discussed below, 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, nor have any significant new matters arisen during the quarter ended March 31, 2007.

PAGE 11

Status of Electric Regulation in Virginia

2007 Virginia Restructuring Act and Fuel Factor Amendments

In April 2007, the Virginia General Assembly passed legislation that significantly changes electricity restructuring in Virginia. The legislation ends capped rates two years early, on December 31, 2008. After capped rates end, retail choice will be eliminated for all but individual retail customers with a demand of more than 5 megawatts (Mw) and non-residential retail customers who obtain Virginia State Corporation Commission (Virginia Commission) approval to aggregate their load to reach the 5 Mw threshold; individual retail customers will be permitted to purchase renewable energy from competitive suppliers if the incumbent electric utility does not offer a renewable energy tariff. Also after the end of capped rates, the Virginia Commission will set our base rates under a modified cost-of-service model. Among other features, the new model provides for the Virginia Commission to:

•

Initiate a base rate case during the first six months of 2009, reviewing the 2008 test year, as a result of which the Virginia Commission:

•

shall establish a return on equity (ROE) no lower than that reported by a group of utilities within the southeastern U.S., with certain limitations, as described in the legislation;

•

may increase or decrease the ROE by up to 100 basis points based on generating plant performance, customer service and operating efficiency, if appropriate;

•

shall increase base rates if needed to allow the Company the opportunity to recover its costs and earn a fair rate of return, if we are found to have earnings more than 50 basis points below the established ROE; and

•

may reduce rates or, alternatively, order a credit to customers if we are found to have earnings more than 50 basis points above the established ROE.

•

After the initial rate case, review base rates biennially, as a result of which the Virginia Commission:

•

shall establish an ROE no lower than that reported by a group of utilities within the southeastern U.S., with certain limitations, as described in the legislation;

•

may increase or decrease the ROE by up to 100 basis points based on generating plant performance, customer service, and operating efficiency, if appropriate;

•

shall increase base rates if needed to allow the Company the opportunity to recover its costs and earn a fair rate of return if we are found to have earned, during the test period, more than 50 basis points below the then currently established ROE; and

•

may order a credit to customers if we are found to have earned, during the test period, more than 50 basis points above the then currently established ROE, and reduce rates if we are found to have had such excess earnings during two consecutive biennial review periods.

•

Authorize stand-alone rate adjustments for recovery of certain costs, including new generation projects, major generating unit modifications, environmental compliance projects, Federal Energy Regulatory Commission (FERC)-approved costs for transmission service, energy efficiency and conservation programs, and renewable energy programs;

•

Authorize an enhanced ROE on new capital expenditures as a financial incentive for construction of major generation projects; and

•

After 2010, authorize an enhanced ROE on overall rate base as a financial incentive for renewable energy portfolio standard programs.

The legislation also continues statutory provisions directing us to file annual fuel cost recovery cases with the Virginia Commission beginning in 2007 and continuing thereafter. However, our fuel factor increase as of July 1, 2007 will be limited to an amount that results in the residential customer class not receiving an increase of more than 4% of total rates as of that date, and the remainder will be deferred and collected over three years, as provided in the legislation.

We are currently evaluating the timing and impact of reapplying SFAS No. 71, Accounting for the Effects of Certain Types of Regulation, to our generation operations.

Virginia Fuel Expenses

Under amendments to the Virginia fuel cost recovery statute passed in 2004, our fuel factor provisions were frozen until July 1, 2007. Fuel prices have increased considerably since 2004, which has resulted in our fuel expenses being significantly in excess of our fuel cost recovery. Pursuant to the 2007 amendments to the fuel cost recovery statute, annual fuel rate adjustments, with deferred fuel accounting for over- or under-recoveries of fuel costs, will be instituted beginning July 1, 2007. We expect that fuel expenses will continue to exceed fuel cost recovery until our fuel factor is adjusted in July 2007. While the 2007 amendments do not allow us to collect any unrecovered fuel expenses that were incurred prior to July 1, 2007, once our fuel factor is adjusted, the risk of under-recovery of prudently incurred fuel costs is greatly diminished.

PAGE 12

In April 2007, we filed our Virginia fuel factor application with the Virginia Commission. The application shows 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, the requested increase is limited to $219 million under the 2007 amendments to the fuel cost recovery statute. Under these amendments, our fuel factor increase as of July 1, 2007 is 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, will depend on their current rates and respective usage. The 4% limitation to the residential class would limit the fuel factor increase for Virginia jurisdictional customers to approximately $219 million, effective July 1, 2007, with the balance of approximately $443 million deferred and subsequently recovered, without interest, during the period commencing July 1, 2008 and ending June 30, 2011.

Guarantees and Surety Bonds

As of March 31, 2007, we had issued $6 million of guarantees primarily to support commodity transactions of our subsidiaries. We had also purchased $70 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.

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 March 31, 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 March 31, 2007, our gross credit exposure totaled $51 million. Of this amount, 81% related to a single counterparty; however, the entire balance is with investment grade entities. We held no collateral for these transactions at March 31, 2007.

Note 12. Related Party Transactions

We engage in related-party transactions primarily with affiliates (Dominion subsidiaries). 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.

At March 31, 2007 and December 31, 2006, our Consolidated Balance Sheets include derivative assets with affiliates of $6 million and derivative liabilities with affiliates of $2 million, respectively. Unrealized gains or losses, representing the effective portion of the changes in fair value of those derivative contracts that have been designated as cash flow hedges, are included in AOCI in our Consolidated Balance Sheets.

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.

PAGE 13

The transactions with Dominion Services and other affiliates are detailed below:


	Three Months Ended March 31,
	2007		2006
(millions)
Commodity purchases from affiliates	$	49	$	34
Commodity sales to affiliates		2		3
Services provided by affiliates		78		77
Services provided to affiliates		6		6

We have borrowed funds from Dominion under both short-term and long-term borrowing arrangements. At March 31, 2007 and December 31, 2006, our outstanding borrowings, net of repayments, under the Dominion money pool for our nonregulated subsidiaries totaled $23 million and $140 million, respectively, included in other current liabilities on our Consolidated Financial Statements. At March 31, 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 $3 million and $2 million in the three months ended March 31, 2007 and 2006, respectively.

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. The Delivery segment is subject to cost-of-service rate regulation and accordingly, applies SFAS No. 71.

Energy includes our regulated electric transmission operations. The Energy segment is subject to cost-of-service rate regulation and accordingly, applies SFAS No. 71.

Generation includes our portfolio of electric generating facilities, power purchase agreements and our 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 three months ended March 31, 2007, we reported net expenses of $6 million in our Corporate segment. No such expenses were reported in the Corporate segment in the three months ended March 31, 2006.

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

•

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.

The following table presents segment information pertaining to our operations:


	Delivery		Energy		Generation			Corporate			Consolidated Total
(millions)
Three Months Ended March 31, 2007
Operating revenue	$	307	$	56	$	1,078		$	2		$	1,443
Net income (loss)		77		20		(2	)		(6	)		89

Three Months Ended March 31, 2006
Operating revenue	$	289	$	52	$	993		$	(1	)	$	1,333
Net income		67		17		13			—			97

PAGE 14

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;

•

Changes to our ability to recover investments made under traditional regulation through rates; 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 and in our Annual Report on Form 10-K for the year ended December 31, 2006.

PAGE 15

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 March 31, 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.

Results of Operations

Presented below is a summary of our consolidated results for the periods ended March 31, 2007 and 2006:


	2007		2006		$ Change
(millions)
First Quarter
Net income	$	89	$	97	$	(8	)

Overview

First Quarter 2007 vs. 2006

Net income decreased 8% to $89 million. Unfavorable drivers include an increase in electric fuel and energy purchases resulting primarily from increased consumption of fossil fuel and purchased power due to colder weather 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 colder weather and customer growth.

Analysis of Consolidated Operations

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


	First Quarter
	2007		2006		$ Change
(millions)
Operating Revenue	$	1,443	$	1,333	$	110
Operating Expenses
Electric fuel and energy purchases		675		557		118
Purchased electric capacity		116		117		(1	)
Other energy-related commodity purchases		8		10		(2	)
Other operations and maintenance		284		266		18
Depreciation and amortization		134		132		2
Other taxes		45		45		—
Other income		23		24		(1	)
Interest and related charges		62		78		(16	)
Income tax expense		53		55		(2	)

An analysis of our results of operations for the first quarter of 2007 compared to the first quarter of 2006 follows:

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

•

A $52 million increase associated with colder weather. As compared to the prior year, we experienced an 11% increase in heating degree days;

•

A $26 million increase attributable to variations in rates resulting from changes in customer usage patterns and sales mix and other factors;

PAGE 16

•

A $17 million increase due to new customer connections primarily in our residential and commercial customer classes;

•

A $15 million increase resulting primarily from higher ancillary service revenue reflecting higher regulation and operating reserves revenue received from PJM; and

•

A $9 million increase in sales to wholesale customers primarily resulting from colder weather during the current year; partially offset by

•

A $7 million decrease due to the impact of a comparatively lower fuel rate in certain customer jurisdictions that was offset by a comparable decrease in Electric fuel and energy purchases expense.

Operating Expenses and Other Items

Electric fuel and energy purchases expense increased 21% to $675 million, primarily due to increased consumption of fossil fuel and purchased power as a result of comparably colder weather during the current year.

Other operations and maintenance expense increased 7% to $284 million, primarily reflecting:

•

A $12 million increase in outage costs primarily due to an increase in the number of scheduled outage days at certain of our electric generating facilities;

•

A $7 million increase due to a reduced benefit from the sale of emissions allowances;

•

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

•

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; partially offset by

•

A $12 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.

Interest and related charges decreased 21% to $62 million, primarily attributable to a revised estimate of interest on income taxes payable.

PAGE 17

Segment Results of Operations

Presented below is a summary of contributions by our operating segments to net income for the periods ended March 31, 2007 and 2006:


	First Quarter
	2007			2006		$ Change
(millions)
Delivery	$	77		$	67	$	10
Energy		20			17		3
Generation		(2	)		13		(15	)

Primary operating segments		95			97		(2	)
Corporate		(6	)		—		(6	)

Consolidated	$	89		$	97	$	(8	)

Delivery

Presented below are operating statistics related to our Delivery operations:


	First Quarter
	2007	2006	% Change
Electricity delivered (million mwhrs)	21.0	19.5	8	%
Degree days (electric service area):
Cooling⁽¹⁾	12	13	(8	)
Heating⁽²⁾	1,993	1,796	11
Average electric delivery customer accounts⁽³⁾	2,351	2,314	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:


	First Quarter 2007 vs. 2006 Increase (Decrease)
(millions)
Regulated electric sales:
Weather	$	7
Customer growth		2
Interest expense		3
Other		(2	)

Change in net income contribution	$	10

PAGE 18

Energy

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


	First Quarter 2007 vs. 2006 Increase (Decrease)


(millions)
Regulated electric sales:
Weather	$	1
Customer growth		1
Other		1

Change in net income contribution	$	3

Generation

Presented below are operating statistics related to our Generation operations:


	First Quarter
	2007	2006	% Change
Electricity supplied (million mwhrs)	21.0	19.5	8	%
Degree days (electric service area):
Cooling	12	13	(8	)
Heating	1,993	1,796	11

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


	First Quarter 2007 vs. 2006 Increase (Decrease)


(millions)
Unrecovered Virginia fuel expenses	$	(48	)
Outage costs		(7	)
Regulated electric sales:
Weather		15
Customer growth		5
Other		7
Interest expense		6
Other		7

Change in net income contribution	$	(15	)

Corporate

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


	First Quarter
	2007			2006		$ Change
(millions)
Specific items attributable to operating segments	$	(6	)	$	—	$	(6	)

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.

PAGE 19

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 March 31, 2007, we had $723 million of unused capacity under our joint credit facility.

A summary of our cash flows for the three months ended March 31, 2007 and 2006 is presented below:


	2007			2006
(millions)
Cash and cash equivalents at January 1,	$	18		$	54
Cash flows provided by (used in)
Operating activities		509			399
Investing activities		(282	)		(241	)
Financing activities		(194	)		(189	)

Net increase (decrease) in cash and cash equivalents		33			(31	)

Cash and cash equivalents at March 31,		51			23

Operating Cash Flows

For the three months ended March 31, 2007, net cash provided by operating activities increased by $110 million as compared to the three months ended March 31, 2006. The increase is primarily attributable to higher electric sales as a result of colder weather and customer growth, as well as favorable 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 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 March 31, 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 March 31, 2007.


	Gross Credit Exposure
(millions)
Investment grade⁽¹⁾	$	9
Non-investment grade		—
No external ratings:
Internally rated—investment grade⁽²⁾		42
Internally rated—non-investment grade		—

Total	$	51

(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 19% of the total gross credit exposure.

(2)	The five largest counterparty exposures, combined, for this category represented approximately 81% of the total gross credit exposure.

Investing Cash Flows

Significant investing activities in the three months ended March 31, 2007 included:

•

$220 million for environmental upgrades, routine capital improvements of generation facilities and construction and improvements of electric transmission and distribution assets;

•

$137 million for purchases of securities held as investments in our nuclear decommissioning trusts; and

•

$37 million for nuclear fuel expenditures; partially offset by

•

$115 million of proceeds from sales of securities held as investments in our nuclear decommissioning trusts.

PAGE 20

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 three months ended March 31, 2007 included:

•

$718 million for the repayment of long-term debt;

•

$117 million for the net repayment of affiliated current borrowings; and

•

$77 million of common dividend payments; partially offset by

•

$722 million from the 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 March 31, 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 March 31, 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.

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.

Status of Electric Regulation in Virginia

2007 Virginia Restructuring Act and Fuel Factor Amendments

In April 2007, the Virginia General Assembly passed legislation that significantly changes electricity restructuring in Virginia. The legislation ends capped rates two years early, on December 31, 2008. After capped rates end, retail choice will be eliminated for all but individual retail customers with a demand of more than 5 Mw and non-residential retail customers who obtain Virginia Commission approval to aggregate their load to reach the 5 Mw threshold; individual retail customers will be permitted to purchase renewable energy from competitive suppliers if the incumbent electric utility does not offer a renewable energy tariff. Also after the end of capped rates, the Virginia Commission will set our base rates under a modified cost-of-service model. Among other features, the new model provides for the Virginia Commission to:

•

Initiate a base rate case during the first six months of 2009, reviewing the 2008 test year, as a result of which the Virginia Commission:

•

shall establish an ROE no lower than that reported by a group of utilities within the southeastern U.S., with certain limitations, as described in the legislation;

•

may increase or decrease the ROE by up to 100 basis points based on generating plant performance, customer service and operating efficiency, if appropriate;

•

may reduce rates or, alternatively, order a credit to customers if we are found to have earnings more than 50 basis points above the established ROE.

•

After the initial rate case, review base rates biennially, as a result of which the Virginia Commission:

•

shall establish an ROE no lower than that reported by a group of utilities within the southeastern U.S., with certain limitations, as described in the legislation;

PAGE 21

•

may increase or decrease the ROE by up to 100 basis points based on generating plant performance, customer service and operating efficiency, if appropriate;

•

Authorize stand-alone rate adjustments for recovery of certain costs, including new generation projects, major generating unit modifications, environmental compliance projects, FERC-approved costs for transmission service, energy efficiency and conservation programs, and renewable energy programs;

•

Authorize an enhanced ROE on new capital expenditures as a financial incentive for construction of major generation projects; and

•

After 2010, authorize an enhanced ROE on overall rate base as a financial incentive for renewable energy portfolio standard programs.

We are currently evaluating the timing and impact of reapplying SFAS No. 71 to our generation operations.

Virginia Fuel Expenses

Transmission Expansion Plan

Each year, as part of PJM’s Regional Transmission Expansion Plan (RTEP) process, reliability projects will be 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 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 56-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 Virginia.

PAGE 22

Generation Expansion

Based on available generation capacity and current estimates of growth in customer demand, 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 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. We will continue to evaluate the development of a coal plant in southwest Virginia and other new plants to meet customer demand for additional generation in the future.

PJM Rate Design

In May 2005, 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. Hearings were held in April 2006, and in July 2006, the Presiding Administrative Law Judge issued an initial decision (Initial Decision). The Initial Decision concluded that the existing PJM transmission service rate design has been shown to be unjust and unreasonable, and should be replaced with a new rate design that would allocate substantial transmission costs to the Dominion zone, effective April 2006. Our position was that the existing rate design remained just and reasonable, as supported by a broad coalition of PJM stakeholders. In April 2007, FERC overruled the Initial Decision by reaffirming 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. 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

In April 2007, we reached a tentative agreement with the International Brotherhood of Electrical Workers, Local 50 (Local 50) for a six year collective bargaining agreement to replace the current agreement that was scheduled to expire on March 31, 2007. The new agreement is subject to a ratification vote by the members of Local 50, which represents approximately 3,200 of our employees in Virginia, North Carolina and the Mount Storm Power Station in West Virginia. The current agreement remains in effect until the new agreement is ratified or, if it is not ratified, so long as the parties continue to negotiate.

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. 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.

PAGE 23

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, foreign currency exchange rates, interest 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. We are exposed to foreign currency exchange rate risks related to our purchases of fuel and fuel services denominated in foreign currencies. Interest rate risk is generally related to our outstanding debt. 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, foreign currency exchange rates and interest 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% decrease in commodity prices would have resulted in a decrease of approximately $10 million and $3 million in the fair value of our non-trading commodity-based financial derivative instruments as of March 31, 2007 and December 31, 2006, respectively.

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 power purchases 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 March 31, 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 March 31, 2007 and December 31, 2006, a hypothetical 10% increase in market interest rates would decrease annual earnings by approximately $8 million and $6 million, respectively.

PAGE 24

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. We recognized net realized gains (including investment income) on nuclear decommissioning trust investments of $15 million and $17 million for the three months ended March 31, 2007 and 2006, respectively, and $36 million for the year ended December 31, 2006. We recorded, in AOCI, a $2 million reduction in gross unrealized gains on these investments for the three months ended March 31, 2007 and net unrealized gains on these investments of $15 million for the three months ended March 31, 2006. For the year ended December 31, 2006, we recorded, in AOCI, gross unrealized gains on these investments of $86 million.

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.

PAGE 25

VIRGINIA ELECTRIC AND POWER COMPANY

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 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 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. 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 and amendments to the fuel cost recovery statute in effect in Virginia. Under the 1999 Virginia Electric Utility Restructuring Act (Restructuring Act) as amended in 2007, our base rates remain capped through December 31, 2008 unless sooner modified or terminated. Although this 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. These risks include exposure to stranded costs, future environmental compliance requirements, certain tax law changes, costs related to hurricanes or other weather events, inflation, the cost of obtaining replacement power during unplanned plant outages and increased capital costs.

In addition, our current Virginia fuel factor provisions are locked-in until July 1, 2007, with no deferred fuel accounting. As a result, until July 1, 2007 we are exposed to fuel price and other risks. These risks include exposure to increased costs of fuel, including purchased power costs, differences between our projected and actual power generation mix and generating unit performance (which affects the types and amounts of fuel we use) and differences between fuel price assumptions and actual fuel prices. Annual fuel rate adjustments, with deferred fuel accounting for over- or under-recoveries of fuel costs, will be instituted beginning July 1, 2007. Beginning July 1, 2007, our risk of under-recovering prudently incurred fuel and purchased power expenses is greatly diminished.

The 2007 amendments to the fuel cost recovery statute call for annual fuel cost recovery proceedings beginning July 1, 2007 and continuing thereafter. The first annual increase as of July 1, 2007 will be limited to an amount that results in the residential customer class not receiving an increase of more than 4% of total rates as of that date, and the remainder will be deferred, without interest, and collected during the period commencing July 1, 2008 and ending June 30, 2011. The amendments to the Restructuring Act and the fuel cost recovery statute will become effective July 1, 2007.

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		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

May 2, 2007		/s/ Steven A. Rogers
		Steven A. Rogers Senior Vice President and Chief Accounting Officer

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