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 September 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 September 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 Nine Months Ended September 30, 2007 and 2006	3

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

	Consolidated Statements of Cash Flows – Nine Months Ended September 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	17

Item 3.	Quantitative and Qualitative Disclosures About Market Risk	27

Item 4.	Controls and Procedures	28

PART II. Other Information

Item 1.	Legal Proceedings	28

Item 1A.	Risk Factors	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 September 30,				Nine Months Ended September 30,
	2007		2006		2007			2006
(millions)
Operating Revenue	$	1,833	$	1,690	$	4,700		$	4,346
Operating Expenses
Electric fuel and energy purchases		609		821		1,945			1,933
Purchased electric capacity		107		114		330			340
Other energy-related commodity purchases		8		15		24			33
Other operations and maintenance:
External suppliers		255		110		657			506
Affiliated suppliers		83		75		239			233
Depreciation and amortization		146		133		420			400
Other taxes		43		37		131			125

Total operating expenses		1,251		1,305		3,746			3,570

Income from operations		582		385		954			776

Other income		18		20		58			61

Interest and related charges:
Interest expense		77		65		206			198
Interest expense—junior subordinated notes payable to affiliated trust		8		8		23			23

Total interest and related charges		85		73		229			221

Income before income tax expense		515		332		783			616
Income tax expense		193		123		293			224

Income before extraordinary item		322		209		490			392
Extraordinary item⁽¹⁾		—		—		(158	)		—

Net Income		322		209		332			392
Preferred dividends		4		4		12			12

Balance available for common stock	$	318	$	205	$	320		$	380

(1)	Net of income tax benefit of $101 million.

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

PAGE 3

VIRGINIA ELECTRIC AND POWER COMPANY

CONSOLIDATED BALANCE SHEETS

(Unaudited)


	September 30, 2007			December 31, 2006⁽¹⁾
(millions)
ASSETS
Current Assets
Cash and cash equivalents	$	21		$	18
Customer receivables (less allowance for doubtful accounts of $8 and $7)		837			650
Other receivables (less allowance for doubtful accounts of $8 and $9)		71			98
Inventories (average cost method)		484			505
Prepayments		41			133
Other		56			51

Total current assets		1,510			1,455

Investments
Nuclear decommissioning trust funds		1,362			1,293
Other		22			22

Total investments		1,384			1,315

Property, Plant and Equipment
Property, plant and equipment		21,460			20,771
Accumulated depreciation and amortization		(8,689	)		(8,353	)

Total property, plant and equipment, net		12,771			12,418

Deferred Charges and Other Assets
Regulatory assets		409			241
Other		275			254

Total deferred charges and other assets		684			495

Total assets	$	16,349		$	15,683

(1)	Our 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 our Consolidated Financial Statements.

PAGE 4

VIRGINIA ELECTRIC AND POWER COMPANY

CONSOLIDATED BALANCE SHEETS—(Continued)

(Unaudited)


	September 30, 2007		December 31, 2006⁽¹⁾
(millions)
LIABILITIES AND SHAREHOLDER’S EQUITY
Current Liabilities
Securities due within one year	$	59	$	1,267
Short-term debt		—		618
Affiliated current borrowings		1,054		140
Payables to affiliates		90		62
Accounts payable		415		418
Other		473		436

Total current liabilities		2,091		2,941

Long-Term Debt
Long-term debt		4,088		2,987
Junior subordinated notes payable to affiliated trust		412		412
Notes payable—other affiliates		220		220

Total long-term debt		4,720		3,619

Deferred Credits and Other Liabilities
Deferred income taxes and investment tax credits		2,098		2,308
Asset retirement obligations		671		641
Regulatory liabilities		990		430
Other		271		95

Total deferred credits and other liabilities		4,030		3,474

Total liabilities		10,841		10,034

Commitments and Contingencies (see Note 11)

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		889		887
Retained earnings		943		955
Accumulated other comprehensive income		31		162

Total common shareholder’s equity		5,251		5,392

Total liabilities and shareholder’s equity	$	16,349	$	15,683

(1)	Our 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 our Consolidated Financial Statements.

PAGE 5

VIRGINIA ELECTRIC AND POWER COMPANY

CONSOLIDATED STATEMENTS OF CASH FLOWS

(Unaudited)


	Nine Months Ended September 30,
	2007			2006
(millions)
Operating Activities
Net income	$	332		$	392
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation and amortization		485			464
Deferred income taxes and investment tax credits, net		99			(23	)
Deferred fuel expenses, net		(152	)		73
Extraordinary item, net of income taxes		158			—
Other adjustments to income, net		(31	)		(79	)
Changes in:
Accounts receivable		(178	)		(5	)
Affiliated accounts receivable and payable		46			—
Inventories		21			(49	)
Accounts payable		(9	)		(21	)
Accrued interest, payroll and taxes		5			207
Other operating assets and liabilities		182			147

Net cash provided by operating activities		958			1,106

Investing Activities
Plant construction and other property additions		(680	)		(631	)
Purchases of nuclear fuel		(88	)		(92	)
Purchases of securities		(427	)		(376	)
Proceeds from sales of securities		391			358
Other		29			77

Net cash used in investing activities		(775	)		(664	)

Financing Activities
Repayment of short-term debt, net		(618	)		(905	)
Issuance of affiliated current borrowings, net		914			340
Issuance of long-term debt		1,200			1,000
Repayment of long-term debt		(1,313	)		(613	)
Common dividend payments		(338	)		(273	)
Preferred dividend payments		(12	)		(12	)
Other		(13	)		(10	)

Net cash used in financing activities		(180	)		(473	)

Increase (decrease) in cash and cash equivalents		3			(31	)
Cash and cash equivalents at beginning of period		18			54

Cash and cash equivalents at end of period	$	21		$	23

The accompanying notes are an integral part of our 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 September 30, 2007, we served approximately 2.4 million retail customer accounts, including governmental agencies, as well as 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.

In the fourth quarter of 2007, we will realign our business units and begin managing our daily operations through two primary operating segments: Dominion Virginia Power (DVP) and Generation. DVP will include our regulated electric distribution and electric transmission operations in Virginia and North Carolina, as well as our customer service operations. Generation will continue to include our regulated generation and energy supply operations.

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 and Quarterly Reports on Forms 10-Q for the quarters ended March 31, 2007 and June 30, 2007.

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 September 30, 2007, our results of operations for the three and nine months ended September 30, 2007 and 2006, and our cash flows for the nine months ended September 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, recovery of 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.

Under amendments to the Virginia fuel cost recovery statute passed in 2004, our fuel factor provisions were frozen until July 1, 2007. 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, were instituted beginning July 1, 2007.

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. 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 had no impact on the amounts recorded in connection with the adoption of FIN 48.

As of January 1, 2007, unrecognized tax benefits totaled $226 million. For the nine months ended September 30, 2007, the activity for unrecognized tax benefits for tax positions taken in prior years included gross increases of $20 million and reductions of $14 million due to settlements with taxing authorities. The activity for unrecognized tax benefits for tax positions taken in the current year included gross increases of $13 million. Unrecognized tax benefits as of January 1, 2007, included $5 million that, if recognized, would lower the effective tax rate. Through September 30, 2007, unrecognized tax benefits that, if recognized, would lower the effective tax rate have increased by $1 million.

PAGE 8

For the majority of our unrecognized tax benefits, the ultimate deductibility is highly certain, but there is uncertainty about the timing of such deductibility. When uncertainty about the deductibility of amounts is limited to the timing of such deductibility, any tax liabilities recognized for prior periods would be subject to offset with the availability of refundable amounts from later periods when such deductions could otherwise be taken. Pending resolution of these timing uncertainties, interest is being accrued from the due date of prior years’ returns until the period in which the amounts would be deductible, if not deducted in prior years. Through the nine months ended September 30, 2007, unrecognized tax benefits for prior periods have been reduced by $11 million to recognize amounts that, if not deducted in prior years, would be deductible in 2007. Over the next twelve months, unrecognized tax benefits could be reduced by an additional $13 million to recognize prior period amounts becoming otherwise deductible in the current period.

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, resulting primarily from interest income related to pending refund claims recognized in connection with the adoption of FIN 48, 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 1999, except that we have reserved the right to pursue a refund of amounts related to interest costs capitalized on plant and equipment during the years 1995 through 1998.

The U.S. Congressional Joint Committee on Taxation has recently completed its review of our settlement for tax years 1993 through 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 through 2001. 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.

We have filed appeals of assessments received from taxing authorities, and we believe that it is reasonably possible that, based on settlement negotiations, unrecognized tax benefits could decrease by up to $49 million over the next twelve months.

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 tax 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.

PAGE 9

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.

FSP FIN 39-1

In April 2007, the FASB issued FASB Staff Position No. FIN 39-1, Amendment of FASB Interpretation No. 39, Offsetting of Amounts Related to Certain Contracts (FSP FIN 39-1). FSP FIN 39-1 amends FIN 39 to permit the offsetting of amounts recognized for the right to reclaim cash collateral or the obligation to return cash collateral against amounts recognized for derivative instruments executed with the same counterparty under the same master netting arrangement that have been offset. FSP FIN 39-1 will become effective for us beginning January 1, 2008 and must be applied retroactively to all financial statements presented, unless it is impracticable to do so. We are currently evaluating the impact that FSP FIN 39-1 may have on our financial condition. We do not expect FSP FIN 39-1 to have an impact on our results of operations or cash flows.

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.

PAGE 10

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) previously 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 as a reduction to the regulatory liability for nuclear decommissioning trust funds discussed above, 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 (SFAS No. 133), 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, for jurisdictions subject to cost-based regulation, 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. Realized gains or losses on the derivative instruments will generally be recognized when the related transactions impact net income.

Note 6. Operating Revenue

Our operating revenue consists of the following:


	Three Months Ended September 30,				Nine Months Ended September 30,
	2007		2006		2007		2006
(millions)
Regulated electric sales	$	1,796	$	1,650	$	4,593	$	4,231
Other		37		40		107		115

Total operating revenue	$	1,833	$	1,690	$	4,700	$	4,346

PAGE 11

Note 7. Comprehensive Income

The following table presents total comprehensive income:


	Three Months Ended September 30,						Nine Months Ended September 30,
	2007			2006			2007			2006
(millions)
Net income	$	322		$	209		$	332		$	392
Other comprehensive income (loss):
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		6			4			(6	)		(3	)
Other		(8	)		29	⁽¹⁾		(125	)⁽²⁾		22	⁽¹⁾

Other comprehensive income (loss)		(2	)		33			(131	)		19

Total comprehensive income	$	320		$	242		$	201		$	411

(1)	Amount primarily reflects net unrealized gains on investments held in nuclear decommissioning trusts.

(2)

Amount primarily reflects the impact of the reclassification of 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.

Note 8. 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 these risks and designate derivative instruments as fair value or cash flow hedges for accounting purposes as allowed by SFAS No. 133. As discussed in Note 5, for jurisdictions subject to cost-based regulation, changes in the fair value of derivatives designated as hedges are deferred as regulatory assets or regulatory liabilities until the contracts are settled.

The following table presents selected information, for jurisdictions that are not subject to cost-based regulation, related to cash flow hedges included in AOCI in our Consolidated Balance Sheet at September 30, 2007:


	AOCI After-Tax		Amounts Expected to be Reclassified to Earnings During the Next 12 Months After-Tax		Maximum Term
(millions)
Foreign currency	$	1	$	1	42 months
Other		5		2	120 months

Total	$	6	$	3

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.

For the three months and nine months ended September 30, 2007 and 2006, hedge ineffectiveness and time value that is excluded from the measurement of effectiveness did not have a significant impact on net income.

PAGE 12

Note 9. 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 September 30, 2007, limited 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 September 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 September 30, 2007 and 2006. We paid $34 million and $31 million for electric energy from these entities in the three months ended September 30, 2007 and 2006, respectively. We paid $74 million and $72 million for electric generation capacity and $84 million and $68 million for electric energy from these entities in the nine months ended September 30, 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 September 30, 2007. We are not subject to any risk of loss from these VIEs, other than the remaining purchase commitments. We paid $27 million and $29 million for electric generation capacity and $16 million and $14 million for electric energy from these entities in the three months ended September 30, 2007 and 2006, respectively. We paid $86 million and $87 million for electric generation capacity and $44 million and $42 million for electric energy from these entities in the nine months ended September 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 $120 million and $36 million to the LLCs for coal and synthetic fuel produced from coal in the three months ended September 30, 2007 and 2006, respectively, and $333 million and $243 million to the LLCs for coal and synthetic fuel produced from coal in the nine months ended September 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 Sheet as of December 31, 2006, reflected net property, plant and equipment of $337 million, and $370 million of debt related to the consolidation, in accordance with FIN 46R, of a variable interest lessor entity through which we financed and leased a power generation plant. The debt was non-recourse to us and was secured by the entity’s property, plant and equipment. The lease under which we operated the power generation facility terminated in August 2007 and we took legal title to the facility through repayment of the lessor’s related debt.

PAGE 13

Note 10. Significant Financing Transactions

Joint Credit Facilities and Short-term Debt

We use short-term debt, including 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 September 30, 2007, there was no outstanding commercial paper supported by the joint credit facility. At September 30, 2007, total outstanding letters of credit supported by the joint credit facility were $155 million, of which approximately $4 million were issued on our behalf.

At September 30, 2007, capacity available under the joint credit facility was $2.8 billion.

Long-term Debt

In May 2007, we issued $600 million of 6.0% senior notes that mature in 2037. In September 2007, we issued $600 million of 5.95% senior notes that mature in 2017. We used the proceeds for general corporate purposes, including the repayment of short-term debt.

During the nine months ended September 30, 2007, we repaid $1.3 billion of our long-term debt.

See Note 13 for a discussion of affiliated borrowings.

Note 11. 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 Reports on Forms 10-Q for the quarters ended March 31, 2007 and June 30, 2007, respectively, nor have any significant new matters arisen during the quarter ended September 30, 2007.

Guarantees and Surety Bonds

As of September 30, 2007, we had issued $3 million of guarantees primarily to support commodity transactions of our subsidiaries. We had also purchased $26 million of surety bonds for various purposes, including providing workers’ compensation coverage. The surety bond posted for security to suspend execution of the judgment during the appeal of the Norfolk Southern Railway Company 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, was released by the Circuit Court of Halifax, Virginia in September 2007. Under the terms of surety bonds, we are obligated to indemnify the respective surety bond company for any amounts paid.

Note 12. 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 September 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 accounts receivable from energy consumers is limited due to the large number of customers.

PAGE 14

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 September 30, 2007, our gross credit exposure totaled $43 million. Of this amount, 83% related to a single counterparty; however, the entire balance is with investment grade entities, including those internally rated. We held no collateral for these transactions at September 30, 2007.

Note 13. Related Party Transactions

We engage in related party transactions 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 September 30,				Nine Months Ended September 30,
	2007		2006		2007		2006
(millions)
Commodity purchases from affiliates	$	154	$	132	$	281	$	212
Services provided by affiliates		83		75		239		233

During the third quarter of 2007, the Virginia Commission approved our application to add two 150 megawatt (Mw) natural gas-fired electric generating units (Units 3 and 4) to our Ladysmith Power Station to supply electricity during periods of peak demand. As part of that project, we will purchase two gas-fired turbines from a non-regulated affiliate for $53 million. Approximately $10 million of turbine parts have been transferred as of September 30, 2007. Approval by the North Carolina Commission for payment under this affiliate transaction is still pending.

We lease an office building from Dominion under an agreement that was to expire in 2008. In August 2007, we exercised our option to extend the lease term for five years.

We have borrowed funds from Dominion under both short-term and long-term borrowing arrangements. At September 30, 2007 and December 31, 2006, our outstanding borrowings, net of repayments, under the Dominion money pool for our nonregulated subsidiaries totaled $133 million and $140 million, respectively. Our short-term demand note borrowings from Dominion were $921 million at September 30, 2007. There were no short-term demand note borrowings at December 31, 2006. At September 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 $12 million and $4 million in the three months ended September 30, 2007 and 2006, respectively, and $16 million and $7 million in the nine months ended September 30, 2007 and 2006, respectively.

PAGE 15

Note 14. 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 nine months ended September 30, 2007 and 2006, we reported net expenses of $166 million and $4 million, respectively, in our Corporate segment, attributable to our operating segments.

The net expenses in 2007 primarily resulted from a $259 million ($158 million after-tax) extraordinary charge, attributable to our Generation segment, in connection with the reapplication of SFAS No. 71 to the Virginia jurisdiction of our generation operations.

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:


	Delivery		Energy		Generation		Corporate			Consolidated Total
(millions)
Three Months Ended September 30, 2007
Operating revenue	$	333	$	56	$	1,443	$	1		$	1,833
Net income		78		18		226		—			322

Three Months Ended September 30, 2006
Operating revenue	$	324	$	57	$	1,307	$	2		$	1,690
Net income		79		21		109		—			209

Nine Months Ended September 30, 2007
Operating revenue	$	939	$	172	$	3,585	$	4		$	4,700
Extraordinary item, net of tax		—		—		—		(158	)		(158	)
Net income (loss)		223		60		218		(169	)		332

Nine Months Ended September 30, 2006
Operating revenue	$	900	$	161	$	3,283	$	2		$	4,346
Net income (loss)		212		54		130		(4	)		392

In the fourth quarter of 2007, we will realign our business units and begin managing our daily operations through two primary operating segments: DVP and Generation. DVP will include our regulated electric distribution and electric transmission operations in Virginia and North Carolina, as well as our customer service operations. Generation will continue to include our regulated generation and energy supply operations.

PAGE 16

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 Reports on Forms 10-Q for the quarters ended March 31, 2007 and June 30, 2007, and in our Annual Report on Form 10-K for the year ended December 31, 2006.

PAGE 17

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 September 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 September 30, 2007 and 2006:


	Third Quarter						Year-To-Date
	2007		2006		$ Change		2007		2006		$ Change
(millions)
Net income	$	322	$	209	$	113	$	332	$	392	$	(60	)

Overview

Third Quarter 2007 vs. 2006

Net income increased 54% to $322 million. Favorable drivers include the reapplication of deferral accounting for Virginia jurisdiction fuel costs and an increase in regulated electric sales resulting from customer growth and other factors. Unfavorable drivers include a decrease in gains from sales of emissions allowances.

Year-To-Date 2007 vs. 2006

Net income decreased 15% to $332 million. Unfavorable drivers include an extraordinary charge in connection with the reapplication of SFAS No. 71 to the Virginia jurisdiction of our generation operations and a decrease in gains from sales of emissions allowances. Favorable drivers include an increase in regulated electric sales resulting from favorable weather, customer growth and other factors, and the reapplication of deferral accounting for Virginia jurisdiction fuel costs.

PAGE 18

Analysis of Consolidated Operations

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


	Third Quarter							Year-To-Date
	2007		2006		$ Change			2007			2006		$ Change
(millions)
Operating Revenue	$	1,833	$	1,690	$	143		$	4,700		$	4,346	$	354
Operating Expenses
Electric fuel and energy purchases		609		821		(212	)		1,945			1,933		12
Purchased electric capacity		107		114		(7	)		330			340		(10	)
Other energy-related commodity purchases		8		15		(7	)		24			33		(9	)
Other operations and maintenance		338		185		153			896			739		157
Depreciation and amortization		146		133		13			420			400		20
Other taxes		43		37		6			131			125		6
Other income		18		20		(2	)		58			61		(3	)
Interest and related charges		85		73		12			229			221		8
Income tax expense		193		123		70			293			224		69
Extraordinary item, net of tax		—		—		—			(158	)		—		(158	)

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

Third Quarter 2007 vs. 2006

Operating Revenue increased 8% to $1.8 billion, reflecting the combined effects of:

•

A $70 million increase due to the impact of a comparatively higher fuel rate in certain customer jurisdictions;

•

A $46 million increase in sales to retail customers attributable to variations in rates resulting from changes in sales mix and other factors ($25 million) and new customer connections ($21 million) primarily in our residential and commercial customer classes; and

•

A $22 million increase in sales to wholesale customers.

Operating Expenses and Other Items

Electric fuel and energy purchases expense decreased 26% to $609 million, primarily due to the reapplication of deferral accounting for Virginia jurisdiction fuel costs beginning on July 1, 2007. The underlying fuel costs, including those subject to deferral accounting, increased by approximately $26 million due to higher consumption of fossil fuel and purchased power resulting primarily from a change in generation mix. This increase was more than offset by a $238 million reduction in fuel expenses, primarily to defer fuel costs that were in excess of current period fuel rate recovery.

Other operations and maintenance expense increased 83% to $338 million, primarily reflecting:

•

A $62 million increase primarily due to the inclusion of financial transmission rights revenue, which are used to offset congestion costs associated with PJM power purchases incurred by our generation operations, in Electric fuel and energy purchases expense beginning July 1, 2007 as a result of the reapplication of deferred fuel accounting for the Virginia jurisdiction;

•

A $45 million decrease in gains from the sale of emissions allowances held for consumption; and

•

A $20 million increase in outage costs primarily due to an increase in the number of scheduled outage days at certain of our electric generating facilities.

Interest and related charges increased 16% to $85 million, primarily resulting from higher average borrowings.

Income tax expense increased 57% to $193 million, reflecting higher pre-tax income in 2007.

PAGE 19

Year-To-Date 2007 vs. 2006

Operating Revenue increased 8% to $4.7 billion, reflecting the combined effects of:

•

A $125 million increase in sales to retail customers attributable to variations in rates resulting from changes in sales mix and other factors ($71 million) and new customer connections ($54 million) primarily in our residential and commercial customer classes;

•

A $90 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 23% increase in heating and cooling degree days;

•

A $56 million increase due to the impact of a comparatively higher fuel rate in certain customer jurisdictions;

•

A $50 million increase in sales to wholesale customers; and

•

A $32 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 1% to $1.9 billion. The underlying fuel costs, including those subject to deferral accounting, increased by approximately $237 million due to higher consumption of fossil fuel and purchased power resulting from an increase in the number of heating and cooling degree days, higher commodity costs and a change in generation mix. This increase was partially offset by a $225 million reduction in fuel expenses, primarily to defer fuel costs that were in excess of current period fuel rate recovery.

Other operations and maintenance expense increased 21% to $896 million, primarily reflecting:

•

A $63 million decrease in gains from the sale of emissions allowances held for consumption;

•

A $40 million increase primarily due to the inclusion of financial transmission rights revenue, which are used to offset congestion costs associated with PJM power purchases incurred by our generation operations, in Electric fuel and energy purchases expense beginning July 1, 2007 as a result of the reapplication of deferred fuel accounting for the Virginia jurisdiction; and

•

A $24 million increase in outage costs primarily due to an increase in the number of scheduled outage days at certain of our electric generating facilities.

Income tax expense increased 31% to $293 million, reflecting higher pre-tax income in 2007.

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 20

Segment Results of Operations

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


	Third Quarter							Year-To-Date
	2007		2006		$ Change			2007			2006			$ Change
(millions)
Delivery	$	78	$	79	$	(1	)	$	223		$	212		$	11
Energy		18		21		(3	)		60			54			6
Generation		226		109		117			218			130			88

Primary operating segments		322		209		113			501			396			105
Corporate		—		—		—			(169	)		(4	)		(165	)

Consolidated	$	322	$	209	$	113		$	332		$	392		$	(60	)

Delivery

Presented below are operating statistics related to our Delivery operations:


	Third Quarter				Year-To-Date
	2007	2006	% Change		2007	2006	% Change
Electricity delivered (million mwhrs)	23.7	23.1	3	%	64.7	61.2	6	%
Degree days (electric service area):
Cooling⁽¹⁾	1,150	1,119	3		1,643	1,528	8
Heating⁽²⁾	5	15	(67	)	2,365	2,056	15
Average electric delivery customer accounts⁽³⁾	2,364	2,330	1		2,357	2,322	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:


	Third Quarter			Year-To-Date
	2007 vs. 2006			2007 vs. 2006
	Increase (Decrease)			Increase (Decrease)
(millions)
Interest expense	$	(2	)	$	(2	)
Regulated electric sales:
Weather		(1	)		13
Customer growth		3			7
Major storm damage and service restoration⁽¹⁾		7			6
Other		(8	)		(13	)

Change in net income contribution	$	(1	)	$	11

(1)	Primarily resulting from the absence in 2007 of costs associated with tropical storm Ernesto in September 2006.

PAGE 21

Energy

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


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

Change in net income contribution	$	(3	)	$	6

Generation

Presented below are operating statistics related to our Generation operations:


	Third Quarter				Year-To-Date
	2007	2006	% Change		2007	2006	% Change
Electricity supplied (million mwhrs)	23.7	23.0	3	%	64.7	61.2	6	%
Degree days (electric service area):
Cooling	1,150	1,119	3		1,643	1,528	8
Heating	5	15	(67	)	2,365	2,056	15

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


	Third Quarter			Year-To-Date
	2007 vs. 2006			2007 vs. 2006
	Increase (Decrease)			Increase (Decrease)
(millions)
Virginia fuel expenses⁽¹⁾	$	165		$	75
Ancillary service revenue		10			22
Regulated electric sales:
Customer growth		7			16
Weather		(2	)		25
Sale of emissions allowances		(28	)		(39	)
Outage costs⁽²⁾		(13	)		(15	)
Interest expense		(5	)		(2	)
Other		(17	)		6

Change in net income contribution	$	117		$	88

(1)

For the quarter and year-to-date periods, primarily reflects the reapplication of deferred fuel accounting effective July 1, 2007. For the year-to-date period, the benefit is partially offset by increased consumption of fossil fuel and higher purchased power costs during the first six months of the year.

(2)	Primarily reflects an increase in the number of scheduled outage days for certain nuclear units for the quarter and certain fossil units for the year-to-date period.

PAGE 22

Corporate

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


	Third Quarter								Year-To-Date
	2007			2006		$ Change			2007			2006			$ Change
(millions)
Specific items attributable to operating segments	$	(2	)	$	—	$	(2	)	$	(166	)	$	(4	)	$	(162	)
Other corporate operations		2			—		2			(3	)		—			(3	)

Total net expense	$	—		$	—	$	—		$	(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 14 to our Consolidated Financial Statements for a discussion of these items.

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 September 30, 2007, we had $2.8 billion of unused capacity under our joint credit facility.

A summary of our cash flows for the nine months ended September 30, 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		958			1,106
Investing activities		(775	)		(664	)
Financing activities		(180	)		(473	)

Net increase (decrease) in cash and cash equivalents		3			(31	)

Cash and cash equivalents at September 30,	$	21		$	23

Operating Cash Flows

For the nine months ended September 30, 2007, net cash provided by operating activities decreased by $148 million as compared to the nine months ended September 30, 2006. The decrease in cash flow is primarily due to higher income taxes paid in 2007 and 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 Reports on Forms 10-Q for the quarters ended March 31, 2007 and June 30, 2007, and in our Annual Report on Form 10-K for the year ended December 31, 2006.

PAGE 23

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 September 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 September 30, 2007.


	Gross Credit Exposure
(millions)
Investment grade	$	—
Non-investment grade		—
No external ratings:
Internally rated—investment grade⁽¹⁾		43
Internally rated—non-investment grade		—

Total	$	43

(1)	The five largest counterparty exposures, combined, for this category represented approximately 99% of the total gross credit exposure.

Investing Cash Flows

Significant investing activities in the nine months ended September 30, 2007 included:

•

$680 million for environmental upgrades, routine capital improvements of generation facilities and construction and improvements of electric transmission and distribution assets;

•

$427 million for purchases of securities held as investments in our nuclear decommissioning trusts; and

•

$88 million for nuclear fuel expenditures; partially offset by

•

$391 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 nine months ended September 30, 2007 included:

•

$1.3 billion for the repayment of long-term debt;

•

$618 million for the net repayment of short-term debt; and

•

$338 million of common dividend payments; partially offset by

•

$1.2 billion from the issuance of long-term debt; and

•

$914 million from the net issuance of affiliated current borrowings.

See Note 10 to our Consolidated Financial Statements for further information regarding our credit facilities, liquidity and significant financing transactions. Also see Note 13 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 September 30, 2007, there have been no changes in our credit ratings nor changes to or events of default under our debt covenants.

PAGE 24

Future Cash Payments for Contractual Obligations

As of September 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.

Planned Capital Expenditures

As of September 30, 2007, our planned capital expenditures for 2008 are expected to total approximately $2.1 billion. The increase in our capital spending program, as compared to the amounts originally forecasted in our Annual Report on Form 10-K for the year ended December 31, 2006, primarily reflects the need for additional generation in our service territory and includes capital projects that are subject to board approval. We expect to fund our capital expenditures with cash from operations and a combination of sales of securities and short-term borrowings.

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 Reports on Forms 10-Q for the quarters ended March 31, 2007 and June 30, 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. (Trans-Allegheny Interstate Line Company) 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, along with Trans-Allegheny Interstate Line Company, filed an application with the Virginia Commission requesting approval of the proposed construction of the 65-mile transmission line in northern Virginia. Evidentiary hearings on this application will be held in February 2008. 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. Evidentiary hearings will be held on this application in February 2008.

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 over the next ten years. 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 (Units 3 and 4) to our Ladysmith Power Station to supply electricity during periods of peak demand. The facility is expected to be in operation by August 2008, at an estimated cost of $135 million. The Virginia Commission approved the application on August 24, 2007, and construction has commenced. Approval by the North Carolina Commission for a related affiliate transaction is still pending.

On September 13, 2007, we filed a Petition for Reconsideration requesting that the Virginia Commission modify its order of August 24, 2007 for the limited purpose of continuing the docket generally to provide us with an opportunity to file supplemental information supporting approval of a fifth combustion turbine (Unit 5) at the existing Ladysmith generating facility. The Virginia Commission granted the petition for that limited purpose on September 14, 2007 and we plan to file for approval of Unit 5 in early November 2007.

PAGE 25

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 an allowance for funds used during construction until capped rates end and, beginning January 1, 2009, receive 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. A public hearing is scheduled for January 8, 2008.

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. Rehearing of the FERC order was sought in May 2007. We cannot predict whether the FERC decision with regard to the allocation of costs of facilities operating at or above 500 kV will be modified upon rehearing. In September 2007, a settlement proposal was filed at FERC with regard to the allocation of costs of PJM-planned facilities that operate below 500 kV. Such settlement proposal is still pending.

Depreciation Study

In October 2007, we revised the depreciation rates for our generation assets to reflect the results of a new depreciation study, which incorporates changes in service life estimates and the property, plant and equipment accounting policy changes that were made upon the reapplication of SFAS No. 71, as discussed in Note 5 to our Consolidated Financial Statements. This change is expected to increase annual depreciation expense by approximately $54 million ($33 million after-tax) prospectively.

Environmental Matters

The Virginia Energy Plan, released by the Governor of Virginia in September 2007, set a goal of reducing greenhouse gas emissions statewide back to 2000 levels by 2025, and has called for the formation of a Commission on Climate Change to develop a plan to achieve this goal. Until this goal results in legislative or regulatory action, 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 26

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 electricity, natural gas, 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 non-trading 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 derivatives as of September 30, 2007 and December 31, 2006, respectively. The increase is primarily due to an increase in electricity-related 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 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 $2 million and $3 million in the fair value of currency forward contracts held by us at September 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 September 30, 2007, a hypothetical 10% increase in market interest rates would have resulted in a decrease in annual earnings of approximately $5 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.

PAGE 27

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 $14 million and $33 million for the nine months ended September 30, 2007 and 2006, respectively, and $36 million for the year ended December 31, 2006. We recorded, in AOCI, unrealized gains on decommissioning trust investments of $6 million and net unrealized gains on decommissioning trust investments of $37 million for the nine months ended September 30, 2007 and 2006, respectively, and 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 and our Quarterly Reports on Forms 10-Q for the quarters ended March 31, 2007 and June 30, 2007, which factors should be taken into consideration when reviewing the information contained in this report. There have been no material changes with regard to the risk factors previously disclosed in our most recent Form 10-K or our Quarterly Reports on Forms 10-Q for the quarters ended March 31, 2007 and June 30, 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.

PAGE 28

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); Fifteenth Supplemental Indenture (Exhibit 4.2, Form 8-K filed September 10, 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).

PAGE 29

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

November 1, 2007				/s/ Thomas P. Wohlfarth
				Thomas P. Wohlfarth Senior Vice President and Chief Accounting Officer

PAGE 30

Table of Contents

Table of Contents

Table of Contents

Table of Contents

Table of Contents

Table of Contents

Table of Contents

Table of Contents

Table of Contents

Table of Contents

Table of Contents

Table of Contents

Table of Contents

Table of Contents

Table of Contents

Table of Contents

Table of Contents

Table of Contents

Table of Contents

Table of Contents

Table of Contents

Table of Contents

Table of Contents

Table of Contents

Table of Contents

Table of Contents

Table of Contents

Table of Contents

Table of Contents

Table of Contents